Samson Oil & Gas (SSNYY) 10-Q 2017 Q2 Quarterly report

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, 2016

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). Yesx    No¨

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes¨ Nox

There were 3,282,860,301 ordinary shares outstanding as of February 6, 2017.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED December 31, 2016

TABLE OF CONTENTS

		Page
Part I — Financial Information		4
Item 1.	Financial Statements (unaudited)	4
Consolidated Balance Sheets, December 31, 2016 and June 30, 2016		4
Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months ended December 31, 2016 and 2015 and for the six months ended December 31, 2016 and 2015		5
Consolidated Statements of Changes in Stockholders’ Equity/(Deficit) for the six months ended December 31, 2016		6
Consolidated Statements of Cash Flows for the six months ended December 31, 2016 and 2015		7
Notes to  Consolidated Financial Statements (unaudited)		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
Item 4.	Controls and Procedures	24
Part II   — Other Information		24
Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	24
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 3.	Defaults Upon Senior Securities	24
Item 4.	Mine Safety Disclosures	24
Item 5.	Other Information	25
Item 6.	Exhibits	25
Signatures		26

2

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

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

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

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

• timing, amount, and marketability of production;

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

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

• our ability to market, develop and produce new properties;

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

• effectiveness of management strategies and decisions;

• oil and natural gas prices and demand;

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

• the strength and financial resources of our competitors;

• our entrance into transactions in commodity derivative instruments; and

• climatic conditions.

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, if any, 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.

3

Part I — Financial Information

Item 1.   Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

 CONSOLIDATED BALANCE SHEETS

(Unaudited)

	31-Dec-16			30-Jun-16
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,554,452		$	2,654,812
Accounts receivable		2,589,420			1,996,415
Prepayments		320,390			183,305
Oil inventory		232,678			463,768
Oil and gas properties held for sale		-			13,768,865
Total current assets		4,696,940			19,067,165
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $15,991,616 and $15,049,015 at December 31, 2016 and June 30, 2016, respectively		31,704,435			31,522,323
Other property and equipment, net of accumulated depreciation and amortization of $647,467 and $573,995 at December 31, 2016 and June 30, 2016, respectively		322,805			308,474
Net property, plant and equipment		32,027,240			31,830,797
OTHER NON CURRENT ASSETS
Undeveloped capitalized acreage		261,103			220,703
Restricted cash - bonding		450,000			450,000
Other		336,860			474,325
TOTAL ASSETS	$	37,772,143		$	52,042,990
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,201,268		$	4,125,643
Accruals		668,161			1,629,975
Fair value of derivative instruments		1,989,336			1,671,653
Promissory Note		4,300,142			4,046,428
Credit facility		18,902,557			11,500,000
Provision for annual leave		229,575			194,497
Total current liabilities		30,291,039			23,168,196
NON CURRENT LIABILITIES
Asset retirement obligations		3,393,466			3,450,245
Fair value of derivative instruments		1,006,580			1,233,076
Credit facility		-			19,000,000
TOTAL LIABILITIES		34,691,085			46,851,517
STOCKHOLDERS’EQUITY – nil par value
3,282,860,301(equivalent to 16,414,301ADR’s) and 3,215,854,701 (equivalent to 16,079,273 ADR’s) ordinary shares issued and outstanding at December 31, 2016 and June 30, 2016, respectively		105,968,075			105,719,184
Accumulated other comprehensive income		917,442			927,718
Accumulated deficit		(103,804,459	)		(101,455,429	)
Total stockholders’ equity		3,081,058			5,191,473
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	37,772,143		$	52,042,990

See accompanying Notes to Consolidated Financial Statements.

4

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATEDSTATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three months ended						Six months ended
	31-Dec-16			31-Dec-15			31-Dec-16			31-Dec-15
REVENUES AND OTHER INCOME:
Oil sales	$	3,161,515		$	1,898,240		$	6,747,723		$	4,320,823
Gas sales		65,752			210,212			208,278			426,959
Other liquids		11,540			27,201			26,573			28,547
Interest income		161			667			276			2,202
Gain on derivative instruments		-			200,017			-			572,569
Other		1,634,174			265			1,800,117			17,902
TOTAL REVENUE AND OTHER INCOME		4,873,142			2,336,602			8,782,967			5,369,002
EXPENSES:
Lease operating expense		(2,887,532	)		(1,102,441	)		(5,060,846	)		(2,831,170	)
Depletion, depreciation and amortization		(514,049	)		(1,399,511	)		(1,033,932	)		(2,883,243	)
Impairment expense		-			(9,682,965	)		(244,480	)		(9,802,987	)
Abandonment expense		-			-			-			-
Exploration and evaluation expenditure		(18,490	)		(3,699,651	)		(24,545	)		(4,192,719	)
Accretion of asset retirement obligations		(76,841	)		(15,116	)		(156,028	)		(30,004	)
Amortization of borrowing costs		(66,849	)		(35,486	)		(133,698	)		(70,972	)
Interest expense		(343,256	)		(196,357	)		(966,649	)		(386,396	)
Loss on  derivative instruments		(1,488,504	)		-			(1,045,148	)		-
General and administrative		(1,314,104	)		(911,925	)		(2,466,671	)		(1,972,518	)
TOTAL EXPENSES		(6,709,625	)		(17,043,452	)		(11,131,997	)		(22,170,009	)
Loss from operations		(1,836,483	)		(14,706,850	)		(2,349,030	)		(16,801,007	)
Income tax benefit		-			-			-			-
Net loss		(1,836,483	)		(14,706,850	)		(2,349,030	)		(16,801,007	)
OTHER COMPREHENSIVE GAIN (LOSS)
Foreign currency translation gain/(loss)		(24,089	)		6,623			(10,276	)		(64,161	)
Total comprehensive loss for the period	$	(1,860,572	)	$	(14,700,227	)	$	(2,359,306	)	$	(16,865,168	)
Net loss per ordinary share from operations:
Basic – cents per share		(0.06	)		(0.52	)		(0.07	)		(0.59	)
Diluted – cents per share		(0.06	)		(0.52	)		(0.07	)		(0.59	)
Weighted average ordinary shares outstanding:
Basic		3,247,516,688			2,837,834,301			3,231,877,779			2,837,828,903
Diluted		3,247,516,688			2,837,834,301			3,231,877,779			2,837,828,903

See accompanying Notes to Consolidated Financial Statements.

5

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ (DEFICIT)/EQUITY

(Unaudited)

							Accumulated Other
							Other			Total
	Ordinary						Comprehensive			Stockholders
	Shares			(Accumulated Deficit)			Income			Deficit
Balance at June 30, 2016	$	105,719,184		$	(101,455,429	)	$	927,718		$	5,191,473
Net loss		-			(2,349,030	)		-			(2,349,030	)
Foreign currency translation loss, net of tax of $nil		-			-			(10,276	)		(10,276	)
Total comprehensive loss for the period		-			(2,349,030	)		(10,276	)		(2,359,306	)
Share based payments		282,895			-			-			282,895
Cost associated with issue of equity		(34,004	)		-			-			(34,004	)
Balance at December 31, 2016	$	105,968,075		$	(103,804,459	)	$	917,442		$	3,081,058

See accompanying Notes to Consolidated Financial Statements.

6

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended
	31-Dec-16			31-Dec-15
Cash flows (used in)/provided by operating activities
Receipts from customers	$	6,752,951		$	6,543,082
Payments to suppliers & employees		(6,628,656	)		(5,738,781	)
Interest received		276			2,188
(Payments on)/proceeds from derivative instruments		(699,606	)		109,684
Interest paid		(954,923	)		(398,837	)
Net cash flows (used in)/provided by operating activities		(1,529,958	)		517,336
Cash flows used in investing activities
Proceeds from sale of oil and gas properties		14,101,512			-
Payments for plant & equipment		(87,172	)		-
Payments for exploration and evaluation		(64,945	)		(314,639	)
Payments for oil and gas properties		(1,920,048	)		(1,558,976	)
Net cash flows provided by/(used in) investing activities		12,029,347			(1,873,615	)
Cash flows (used in)/provided by financing activities
Proceeds from the exercise of options		-			1,475
Proceeds from borrowings		-			301,000
Repayment of borrowings		(11,597,443	)		-
Share issuance costs		-			-
Net cash flows (used in)/provided by financing activities		(11,597,443	)		302,475
Net (decrease) in cash and cash equivalents		(1,098,054	)		(1,053,804	)
Cash and cash equivalents at the beginning of the fiscal period		2,654,812			2,062,720
Effects of exchange rate changes on cash and cash equivalents		(2,306	)		(65,627	)
Cash and cash equivalents at end of fiscal period	$	1,554,452		$	943,289

See accompanying Notes to Consolidated Financial Statements

7

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, 2016. The year-end Consolidated Balance Sheet presented herein was derived from audited Consolidated Financial Statements, but does not include all disclosures required by GAAP.

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

Accruals.   Accrued liabilities at June 30, 2016 and December 31, 2016 consist primarily of estimates for goods and services received but not yet invoiced.

Prepayments.Prepayments at December 31, 2016 and June 30, 2016 include insurance premiums and other subscription costs paid in advance for the year.

Comparatives.Changes have been made to the classification of certain prior period comparatives in order to remain consistent with the current period presentation. These changes have had no material impact on the financial statements.

Recent Accounting Standards

In August 2014, the FASB issued Accounting Standards Update No. 2014-15,Presentation of Financial Statements –Going Concern(“ASU 2014-15”). The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for fiscal years ending after December 15, 2016 and annual and interim periods thereafter. This standard is not expected to have an impact on the Company’s consolidated financial statements and we are currently assessing the expected impact on footnote disclosures.

In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting standards for revenue recognition. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017, including interim periods therein, as a result of the FASB's recent decision to defer the effective date by one year. We are currently evaluating the method of adoption and impact this standard will have on our consolidated financial statements and related disclosures.

2. Income Taxes

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

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

8

3. Earnings Per Share

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

The following table details the weighted average dilutive and anti-dilutive securities outstanding, which consist of transferable options to purchase ordinary shares which are tradeable on the ASX (“options”), for the periods presented:

	Three months ended				Six months ended
	31-Dec-16		31-Dec-15		31-Dec-16		31-Dec-15
Dilutive		-		-		-		-
Anti–dilutive		471,824,277		324,615,486		395,859,022		389,177,139

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

	Three months ended						Six months ended
	31-Dec-16			31-Dec-15			31-Dec-16			31-Dec-15
Net income (loss)	$	(1,836,483	)		(14,706,850	)	$	(2,349,030	)		(16,801,007	)
Basic weighted average ordinary shares outstanding		3,247,516,688			2,837,834,301			3,231,877,779			2,837,828,903
Basic earnings per ordinary share – cents per share		(0.06	)		(0.52	)		(0.07	)		(0.59	)
Diluted earnings per ordinary share – cents per share		(0.06	)		(0.52	)		(0.07	)		(0.59	)

4. Asset Retirement Obligations

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

Liabilities settled during the period relate to wells in our Hawk Springs project area in Goshen County, Wyoming which were plugged and abandoned during the period. Disposition of properties relates to the sale of our North Stockyard project in North Dakota, which closed during the quarter ended December 31, 2016.

The following table summarizes the activities for the Company’s asset retirement obligations for the six months ended December 31, 2016 and 2015:

	Six months ended
	31-Dec-16			31-Dec-15
Asset retirement obligations at beginning of period	$	3,750,245		$	1,810,674
Liabilities incurred or acquired		-			-
Liabilities settled		(134,688	)		(46,322	)
Disposition of properties		(378,119	)		-
Accretion expense		156,028			30,004
Asset retirement obligations at end of period		3,393,466			1,794,356
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-			-
Long-term asset retirement obligations	$	3,393,466		$	1,794,356

9

5. Fair Value Measurements

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

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

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2016 and June 30, 2016.

	Carrying value at December 31, 2016		Level 1		Level 2		Level 3		Netting(1)			Fair Value at December 31, 2016
Current Assets:
Cash and cash equivalents	$	1,554,452	$	1,554,452	$	-	$	-	$	-		$	1,554,452
Derivative Instruments		-		-		27,040		-		(27,040	)		-
Non Current Assets
Derivative Instruments		-		-		364,425				(364,425	)		-
Current Liabilities
Derivative instruments		1,989,336		-		2,016,376		-		(27,040	)		1,989,336
Non Current Liabilities
Derivative Instruments		1,006,580		-		1,371,005				(364,425	)		1,006,580

10

	Carrying value at June 30, 2016		Level 1		Level 2		Level 3		Netting (1)			Fair Value at June 30, 2016
Current Assets:
Cash and cash equivalents	$	2,654,812	$	2,654,812	$	-	$	-	$	-		$	2,654,812
Derivative Instruments		-		-		136,727		-		(136,727	)		-
Non Current Assets
Derivative Instruments		-		-		220,317		-		(220,317	)		-
Current Liabilities
Derivative instruments		1,671,653		-		1,808,380		-		(136,727	)		1,671,653
Non Current Liabilities
Derivative Instruments		1,233,076		-		1,453,393		-		(220,317	)		1,233,076

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

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

Level 1 Fair value Measurements

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

Level 2 Fair Measurements

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

Other fair value measurements

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

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

Some oil and gas properties are stated at fair value as at June 30, 2016. As a result of the significant decline in oil prices experienced in recent months, the carrying value of oil and gas properties was reviewed and subject to impairment costs of $11 million for the twelve months ended June 30, 2016, the majority of which related to our North Stockyard field due to the sustained decrease in the oil price.

Following the sale of our North Stockyard property in October 2016, we closed out 42,300 barrels of oil hedges and 220,750 mcf of natural gas hedges at a cost of $169,182 to us, including $165,003 in deferred premiums.

6. Commitments and Contingencies

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

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

7. Capitalized Exploration Expense

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

11

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

§ the period for which Samson has the right to explore;

§ planned and budgeted future exploration expenditure;

§ activities incurred during the year; and

§ activities planned for future periods.

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

As of December 31, 2016 we had capitalized exploration expenditures of $261,103. This amount primarily relates to costs incurred in connection with our Cane Creek project in Utah.

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

8.  Share Capital

Issue of Share Capital 

During the six months ended December 31, 2016 the company issued 67,005,600 ordinary shares to employees and Directors of the company. These shares were issued in lieu of cash salaries for employees and directors during the period from August 1, 2015 to August 31, 2016. The share price on the grant was US$0.0035 per ordinary share.

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

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

Issue of Warrants

During the six months ended December 31, 2016 the company issued 272,000,000 warrants at no cost to employees and Directors of the company. The warrants have an exercise price of AUD$0.0055 and an expiry date of November 17, 2026. The options vest on November 17, 2017. The have been valued at AUD$0.0038 using a binomial option pricing model. The company also issued 48,000,000 warrants to Australian based employees and directors of the Company. These warrants have an exercise price of AUD$0.007, vest on November 17, 2017 and expire on November 27, 2026. The expense related to both warrants grants will be recognized over the vesting period. To date share based payments of $0.3 million has been recognized. A further $0.8 million will be recognized prior to the options vesting date, assuming all employees and directors remain with the company.

9. Cash Flow Statement

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

	Six months ended
	31-Dec-16			31-Dec-15
Net loss after tax	$	(2,349,030	)	$	(16,801,007	)
Depletion, depreciation and amortization		1,033,932			2,883,243
Accretion of asset retirement obligation		156,028			30,004
Impairment expense		244,480			9,802,987
Exploration and evaluation expenditure		24,545			4,192,719
Amortization borrowing costs		133,698			70,972
Non cash (gain)/loss on derivative instruments		91,185			(462,885	)
Net gain from sale of assets		(1,634,174	)		-
Share based payments		354,558
Changes in assets and liabilities:
(Increase)/decrease in receivables		(593,005	)		1,931,129
Increase/(decrease) in provision for annual leave		35,078			(25,395	)
Increase/(decrease) in payables		972,747			(1,104,431	)
NET CASH FLOWS(USED IN)/PROVIDED BY OPERATING ACTIVITIES	$	(1,529,958	)	$	517,336

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10. Credit Facility

	Six months ended
	31-Dec-16			31-Dec-15
Credit facility at beginning of period	$	30,500,000		$	18,699,000
Cash advanced under facility	$	-			301,000
Repayments		(11,597,442	)		-
Credit facility at end of period(1)	$	18,902,558		$	19,000,000
Funds available for drawdown under the facility		1,097,442			-

(1) The credit facility is recognized as a current liability as the facility is currently due for repayment in October 2017.

In January 2014, we entered into a $25.0 million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was increased to $15.5 million in June 2014. In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. As a result of this amendment to the facility agreement, the following changes were made to the original facility agreement:

· The addition of more restrictive financial covenants (including the debt to EBITDA ratio and the minimum liquidity requirement);

· Increases in the interest rate and unused facility fee;

· The addition of a minimum hedging requirement of 75% of forecasted production;

· A requirement to reduce our general and administrative costs from $6 million per year to $3 million per year;

· A requirement to raise $5 million in equity on or before September 30, 2016 (this was extended to November 15, 2016 and then effective November 10, 2016 Mutual of Omaha agreed that this requirement had been met following the $1.4 million capital raise completed in April 2016 and by the application of retained funds from the North Stockyard sale);

· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 in line with the closing of the North Stockyard sale) and we repaid $11.5 million on October 31, 2016; and

· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement. $0.1 million has been repaid under this covenant.

Effective November 10, 2016 Mutual of Omaha increased our borrowing base to $20 million, of which $19 million is drawn.

The borrowing base under our credit facility may be increased, (up to the credit facility maximum of $50.0 million) or decreased depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures October 31, 2017. The interest rate is LIBOR plus 6.00% or approximately 6.30% for the quarter ended September 30, 2016. This decreased to 3.5% plus LIBOR following the pay down of the facility in October 2016. This rate was in effect on December 31, 2016.

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

· Current ratio greater than 1

· Debt to EBITDAX (annualized) ratio no greater than 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017

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· Senior leverage ratio of no greater than 4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter

· Interest coverage ratio minimum of between 2.5 and 1.0

We were in compliance with all of our covenants as at June 30, 2016.

As at December 31, 2016 we were in breach of our spending cap with respect to the general and administrative expenses. We have received a waiver with respect to this covenant.

We were in compliance with all other covenants as at December 31, 2016.

If the current pricing environment does not improve it will difficult to maintain compliance with covenants based our current debt levels. If we are not in compliance with the financial covenants in the credit facility, or if we do not receive a waiver from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations. We also must continue to improve our operations to address our working capital deficit.

We incurred $0.6 million in borrowing costs (including legal fees and bank fees) in connection with the establishment of this facility which have been deferred and are being amortized over the life of the facility.

11. Derivatives

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

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil. The Company seeks to manage this risk through the use of commodity derivative contracts These derivative contracts allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil sales. At December 31, 2016, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

Collar	Collars contain a fixed floor price (put) and fixed ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price.  If the market price is between the call and the put strike price, no payments are due from the either party.
Fixed price swap	The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

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

During the six months ended December 31, 2016 we recognized $443,356 in gain on derivative instruments in the Statement of Operations.

Following the closing of the North Stockyard project, we closed out we closed out a portion of our previous hedge positions in line with the reduced production forecast.

Following the sale of our North Stockyard property in October 2016, we closed out 42,300 barrels of oil hedges and 220,750 mcf of natural gas hedges at a cost of $169,182 to us, including $165,003 in deferred premiums.

At December 31, 2016 the Company’s open derivative contracts consisted of the following:

Collars
Product	Start Date	End Date	Volume (BO/Mmbtu)		Floor		Ceiling
WTI	1-Jan-17	30-Apr-18		52,595		41.50		63.00
WTI	1-May-18	31-Dec-18		107,800		45.00		56.00
Henry Hub	1-Feb-17	31-Mar-17		25,842		2.60		3.35
Henry Hub	1-Apr-17	31-Dec-17		91,850		2.40		2.91
Henry Hub	1-Jan-18	30-Apr-18		444,000		2.80		3.60
Henry Hub	1-May-18	31-Dec-18		80,850		2.65		2.90

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Costless Swaps
Product	Start	End	Volume (BO)		Swap
WTI	1-Jan-17	31-Dec-17		141,255		44.09
WTI	1-Jan-18	30-Apr-18		39,720		45.55

12. Subsequent Events

None

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, 2016, included in our Annual Report on Form 10-K and the Consolidated Financial Statements included elsewhere herein.

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

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties.  Our strategy is to focus on the exploration, exploitation and development of our major oil plays – the Madison Group reservoirs in the Williston Basin in Williams and McKenzie Counties, North Dakota, and Roosevelt County in Montana.   Our principal exploratory play is located in the Paradox Basin in Utah.

In March 2016 we closed on an acquisition (the “Foreman Butte Acquisition”) of certain assets located in North Dakota and Montana, which we refer to as the “Foreman Butte Project,” for a purchase price of $16 million. The acquired assets consist of producing oil and gas wells, shut in wells and associated facilities. The wells are located in the Madison and Ratcliffe formations. The majority of these wells will be operated by us, however there are a number of non-operated wells also included in this package.

Our net oil production was 76,784 barrels of oil for the quarter ended December 31, 2016, compared to 51,888 barrels of oil for the quarter ended December 31, 2015.  The decrease in oil production as a result of the sale of our North Stockyard property was offset by the increase in production as a result of the Foreman Butte Acquisition.

Our net gas production was 15,186 Mcf for the quarter ended December 31, 2016, compared to 93,332 Mcf for the quarter ended December 31, 2015. Coupled with the decrease in production following our North Stockyard sale, another of our significant gas wells was down for 90 days during the quarter while undergoing workover operations. Associated gas produced in the Foreman Butte project area is not as significant as the oil production, therefore the acquisition has not offset decline from the sale.

Our net oil production was 167,602 barrels of oil for the six months ended December 31, 2016 compared to 113,124 barrels of oil for the six months ended December 31, 2015. Production has increased as a result of our acquisition of the Foreman Butte project and our subsequent workover activity in this project area. This activity offset the decrease in production as a result of the sale of the North Stockyard property, which closed on October 29, 2016.

Our net gas production was 59,565 Mcf of gas for the six months ended December 31, 2016 compared to 183,414 Mcf of gas for the six months ended December 31, 2015. Associated gas produced in the Foreman Butte project area is not as significant as the oil production, therefore the acquisition has not offset decline from the sale of the North Stockyard project area. Another of our significant gas wells was down for 135 days during the six months ended December 31, 2016 while undergoing workover operations.

For the three months ended December 31, 2016 and December 31, 2015, we reported a net loss of $1.5 million and a net loss of $14.7 million, respectively. The loss in the current period reflects $0.5 million in depletion and amortization and $1.5 million in losses on derivative instruments while the loss in the prior period reflects a $3.7 million in exploration expenditure and impairment expense of $9.8 million.

15

For the six months ended December 31, 2016 and December 31, 2015, we reported a net loss of $2.1 million and a net loss of $16.8 million, respectively. The loss in the current period reflects $1.5 million in depletion and amortization while the loss in the prior period reflects a $4.2 million in exploration expenditure and impairment expense of $9.8 million.

See “Results of Operations” below.

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

Notable Activities and Status of Material Properties during the Quarter Ended December 31, 2016 and Current Activities

Acquisition: Producing Properties

Foreman Butte Project, McKenzie County, North Dakota

Mississippian Madison Formation, Williston Basin

Samson 87% Operated Average Working Interest

While the initial results of the multi-stage acid stimulation on the Maris 1-16H well are inconclusive, due to an emulsion now being produced with the oil, the fresh water cleanout of the Evans 1-10H well was a success in that it created a two times uplift in production. These two wells are horizontal open hole completions in the Ratcliffe Member of the Mississippian Madison Formation, which is predominantly a limestone reservoir.

The multi-stage acid stimulation job on the Maris 1-16H well placed 4,600 bbls of HCl acid and included in addition to other water based fluids, the injection of 4,200 barrels of diversion agent, spacers and pads necessary to complete the placement of acid in 19 stages across 5 zones. The Maris well is currently producing around 20 barrels of oil per day (“BOPD”) and 200 barrels of water per day.

The Evans 1-10H fresh water cleanout operation involved pumping 4,000 barrels of water into the wellbore to remove any blockages and salt deposits potentially blocking the well bore or reducing production. The Evans well is currently producing around 60 BOPD and 400 BWPD.

We plan to continue to assess the results of both the acid stimulation and the fresh water clean out, however it currently appears as if the remaining 18 wells to be worked over in Foreman Butte Field would be better suited for fresh water cleanouts rather than multi-stage acid stimulations. Importantly a fresh water clean out is substantially less expensive ($100,000) than an acid stimulation ($500,000).

We are continuing with our workover operations to return several shut-in wells back to production in the Foreman Butte Project. A fluid-level/production efficiency study has been completed on all the wells in the field to optimize well pump efficiency. We have discovered that many of the wells have sub-performing pump stroke lengths and/or improperly sized pumping units as evidenced from high-fluid levels located inside the wells. Concurrently, a number of wells with behind-pipe pay zones have been identified as recompletion candidates. These recompletions, well optimizations, and several fresh-water cleanout jobs will commence this quarter and should result in a substantial increase in production.

Additionally, two new horizontal laterals are currently being planned to be drilled out of the Maris 1-16H wellbore this spring. The first will test the Ratcliffe Formation of the Mississippian Madison Group. The second will test the Mission Canyon Formation of the Mississippian Madison Group. The lateral in the Ratcliffe Formation will help define the pressure depletion radius from the existing producing wellbores which will ultimately determine the number of PUD’s (proven undeveloped drilling locations) we can drill in this reservoir. Third-party pressure modelling of the Ratcliffe reservoir shows that relatively high reservoir pressure resides approximately 500 feet away from the Maris 1-16 surface location. It is estimated that this new lateral could produce at around 300 BOPD if the third-party pressure modelling proves to be correct. The second lateral in the Mission Canyon Formation will test an undeveloped reservoir that could prove up a new oil field with the potential for many additional well locations.

Undeveloped Properties: Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% working interest

The recompletion of the Bluff #1-11 well was delayed until February 2017 due to bad weather. The Jurassic Canyon Springs Formation will be perforated and flow tested first. If this is unsuccessful, the Cretaceous Dakota Formation will subsequently be perforated and flow tested. This well will be plugged and abandoned should these two operations be unsuccessful.

Spirit of America US34 #2-29 well

Samson 100% Working Interest

This well was plugged and abandoned during the second quarter of fiscal 2017.

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Cane Creek Project, Grand & San Juan Counties, Utah

Pennsylvanian Paradox Formation, Paradox Basin

Samson 100% Working Interest

On November 5, 2014, we entered into an Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”) covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA. We were granted an option period for two years in order to enter into a Multiple Mineral Development Agreement (“MMDA”) with another company who hold leases to extract potash in an acreage position situated within our project area. In November 2015, we paid an extension fee of $40,000 in order to extend the option period to December 2016. In November 2016, we paid a further extension fee of $40,000 to extend the option period to December 2017.

The MMDA has been finalized and is awaiting signature by both parties. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area at cost of $75 per acre to us.

This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline and exposure to open natural fractures. The 3-D seismic is currently being designed to image these natural fractures. The seismic shoot was surveyed and permitted this past summer. While we can make no assurances, we believe this project has the potential to provide robust economics in a low priced oil environment using the evidence obtained from a nearbycompetitor well that has produced 802,967 barrels of oil(“BO”) in just over two years.

Developed Properties: Drilling Activities

North Stockyard Oilfield, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Bakken & Three Forks infill wells

Samson ~25-30% working interest

The sale of this project area was completed on October 28, 2016. The impact of this sale has been recognized in the accounts for the six months ended December 31, 2016 as the effective date of the transaction was October 29, 2016. The project was sold for $14.95 million.

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

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

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

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

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

The first well in this project area, the Gladys 1-20H well (23% working interest), was drilled and completed in January 2014. During the quarter the Gladys 1-20H well produced 6,448 barrels of oil (gross). We have no further drilling planned in this project area until there is a sustained recovery in the oil prices, however six additional wells could be drilled in the 1,280 acre unit.

Results of Operations

For the three months ended December 31, 2016, we reported a net loss of $1.8 million compared to a net loss of $14.7 million for the same period in 2015.

For the six months ended December 31, 2016, we reported a net loss of $2.4 million compared to a net loss of $16.8 million for the same period in 2015.

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

	Three months ended
	31-Dec-16			31-Dec-15
Production Volume
Oil (Bbls)		76,784			51,888
Natural gas (Mcf)		15,186			93,332
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)		79,315			67,443
Sales Price
Realized Oil ($/Bbls)	$	41.17		$	36.48
Impact of settled derivative instruments	$	(8.93	)	$	1.74
Derivative adjusted price	$	32.24		$	38.22
Realized Gas ($/Mcf)	$	4.33		$	2.25
Expense per BOE:
Lease operating expenses	$	32.50		$	12.38
Production and property taxes	$	3.90		$	4.16
Depletion, depreciation and amortization	$	6.48		$	20.75
General and administrative expense	$	16.57		$	13.52

	Six months ended
	31-Dec-16			31-Dec-15
Production Volume
Oil (Bbls)		167,602			113,124
Natural gas (Mcf)		59,565			183,414
BOE		177,530			143,693
Sales Price
Realized Oil ($/Bbls)	$	40.26		$	38.20
Impact of settled derivative instruments	$	(5.69	)	$	0.97
	$	34.57		$	39.17
Realized Gas ($/Mcf)	$	3.50		$	2.33
Expense per BOE:
Lease operating expenses	$	24.81		$	15.67
Production and property taxes	$	3.70		$	4.03
Depletion, depreciation and amortization	$	5.82		$	20.07
General and administrative expense	$	13.89		$	13.73

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

	Three months ended
	31-Dec-16			31-Dec-15			2Q16 to 2Q15 change
Oil sales	$	3,161,515		$	1,898,240		$	1,263,275
Gas sales		65,752			210,212			(144,460	)
Other liquids		11,540			27,201			(15,661	)
Interest income		161			667			(506	)
Gain on derivative instruments		-			200,017			(200,017	)
Other		1,634,174			265			1,633,909
Lease operating expense		(2,887,532	)		(1,102,441	)		(1,785,091	)
Depletion, depreciation and amortization		(514,049	)		(1,399,511	)		885,462
Impairment		-			(9,682,965	)		9,682,965
Exploration and evaluation expenditure		(18,490	)		(3,699,651	)		3,681,161
Accretion of asset retirement obligations		(76,841	)		(15,116	)		(61,725	)
Interest expense		(343,256	)		(196,357	)		(146,899	)
Loss on  derivative instruments		(1,488,504	)		-			(1,488,504	)
Amortization of borrowing costs		(66,849	)		(35,486	)		(31,363	)
General and administrative		(1,314,104	)		(911,925	)		(402,179	)
Income tax benefit		-			-			-
Net loss	$	(1,836,483	)	$	(14,706,850	)	$	12,870,367

	Six months ended
	31-Dec-16			31-Dec-15			2Q16 to 2Q15 change
Oil sales	$	6,747,723		$	4,320,823		$	2,426,900
Gas sales		208,278			426,959			(218,681	)
Other liquids		26,573			28,547			(1,974	)
Interest income		276			2,202			(1,926	)
Gain on derivative instruments		-			572,569			(572,569	)
Other		1,800,117			17,902			1,782,215
Lease operating expense		(5,060,846	)		(2,831,170	)		(2,229,676	)
Depletion, depreciation and amortization		(1,033,932	)		(2,883,243	)		1,849,311
Impairment		(244,480	)		(9,802,987	)		9,558,507
Exploration and evaluation expenditure		(24,545	)		(4,192,719	)		4,168,174
Accretion of asset retirement obligations		(156,028	)		(30,004	)		(126,024	)
Interest expense		(966,649	)		(70,972	)		(895,677	)
Loss on  derivative instruments		(1,045,148	)		-			(1,045,148	)
Amortization of borrowing costs		(133,698	)		(386,396	)		252,698
General and administrative		(2,466,671	)		(1,972,518	)		(494,153	)
Net loss	$	(2,349,030	)	$	(16,801,007	)	$	14,451,977

Comparison of Quarter Ended December 31, 2016 to Quarter Ended December 31, 2015 and for the six months ended December 31, 2016 and six months ended December 31, 2015.

Oil and gas revenues

Oil revenues increased from $1.9 million for the three months ended December 31, 2015 to $3.2 million for the three months ended December 31, 2016, as a result of the increase in the oil price and an increase in oil production. Oil production increased from 51,888 barrels for the three months ended December 31, 2015 to 76,784 for the three months ended December 31, 2016. This increase was due to our Foreman Butte acquisition which was completed in April 2016. This project added 65,814 barrels of oil to our production total for the three months ended December 31, 2016 compared to nil for the three months ended December 31, 2015. This increase was offset by the decrease in production associated with the sale of the North Stockyard project which was completed on October 29, 2016.

The realized oil price also increased from $36.48 per Bbl for the three months ended December 31, 2015 to $41.17 per Bbl (excluding the impact of derivatives) for the three months ended December 31, 2016 following a recovery in the global oil price.

Oil revenues increased from $4.3 million for the six months ended December 31, 2015 to $6.7 million for the six months ended December 31, 2016, as a result of the increase in the oil price and an increase in oil production. Oil production increased from 113,124 barrels for the six months ended December 31, 2015 to 167,602 for the six months ended December 31, 2016. This increase was due to our Foreman Butte acquisition which was completed in April 2016. This project added 125,773 barrels of oil to our production total for the six months ended December 31, 2016 compared to nil for the six months ended December 31, 2015. This increase was offset by the decrease in production associated with the sale of the North Stockyard project which was completed on October 29, 2016.

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The realized oil price also increased from $38.20 per Bbl for the six months ended December 31, 2015 to $40.26 per Bbl (excluding the impact of derivatives) for the six months ended December 31, 2016 following a recovery in the global oil price.

Gas revenues decreased from $0.2 million for the three months ended December 31, 2015 to $0.1 million for the three months ended December 31, 2016. This decrease is due to a decrease in gas production which has offset an increase in the realized gas price. Production decreased from 93,332 Mcf for the quarter ended December 31, 2015 to 15,186 Mcf for the quarter ended December 31, 2016. The decrease in production was primarily due to the sale of the North Stockyard project area which was completed on October 29, 2016. The Foreman Butte acquisition has not added significantly to the gas production as the wells in the acquisition area do not have a high gas content. The decrease in production was offset by an increase in the realized gas price from $2.25 per Mcf for the quarter ended December 31, 2015 to $4.33 per Mcf for the quarter ended December 31, 2016.

Gas revenues decreased from $0.4 million for the six months ended December 31, 2015 to $0.1 million for the six months ended December 31, 2016. This decrease is due to a decrease in gas production which has offset an increase in the realized gas price. Production decreased from 93,332 Mcf for the quarter ended December 31, 2015 to 15,186 Mcf for the quarter ended December 31, 2016. The decrease in production was primarily due to the sale of the North Stockyard project area which was completed on October 29, 2016. The Foreman Butte acquisition has not added significantly to the gas production as the wells in the acquisition area do not have a high gas content. The decrease in production was offset by an increase in the realized gas price which increased slightly from $2.33 per Mcf for the six months ended December 31, 2015 to $3.50 per Mcf for the six months ended December 31, 2016.

Impact of North Stockyard sale

During the six months ended December 31, 2016 the North Stockyard field, which was sold effective October 29, 2016 produced 36,894barrels of oil or approximately 22% of our total production for the six month period. During the period, the North Stockyard field produced 44,192mcf of gas or approximately 74% of our gas production for the six month period.

Commencing October 29, 2016 we no longer received the benefit of production from this field.

Sale of Assets

For the three months and six months ended December 31, 2016, we recognized $1.6 million in income from sale of assets as a result of the sale of our North Stockyard property. As at the sale date, the value of the property was $13.7 million and $0.3 million in asset retirement obligation. The sale value of the property was $14.95 million and we recognized $1.6 million in income from sale of assets after taking into account costs associated with the sale.

There was no similar sale during the three months and six months ended December 31, 2015.

Exploration expense

Exploration expenditures decreased from $3.7 million for the quarter ended December 31, 2015, to $0.01 for the quarter ended December 31, 2016. Exploration costs in the current period relate to general exploration expense. Exploration costs in the prior period related to previously capitalized exploration expenditure written off in relation to our Hawk Springs project in Wyoming and wells drilled in this project area. With the continued weak oil price, exploration expenditure has been significantly reduced. Leases have been let go as they expire or delay rental payments not made causing the leases to expire.

Impairment expense

During the three months ended December 31, 2015 we recognized $9.7 million in impairment expense compared to $nilmillion during the quarter ended December 31, 2016. The impairment expense recognized in the prior quarter relates primarily to our North Stockyard field and was driven by the sustained decrease in the oil price witnessed during the 2015 calendar year.

During the six months ended December 31, 2015 we recognized $9.8 million in impairment expense compared with $nil million in impairment expense for the six months ended December 31, 2016. The impairment recognized in the current period relates to a write down in the value of oil inventory held on the balance sheet related to our accounting policy of the holding inventory at the lower of cost or net realizable value.

Lease operating expense

Lease operating expenses (“LOE”) increased from $1.1 million for the quarter ended December 31, 2015, to $2.9 million for the quarter ended December 31, 2016. Costs per BOE, excluding the impact of the workovers were $24.80 a barrel. Costs have increased from $12.38 for the quarter ended December 31, 2015 due to increased salt water disposal costs in our Foreman Butte project area. We are continuing to review our lease operating expenses and will shut wells in that are not economic to produce in the current oil pricing environment. We are also reviewing our salt water disposals options in order to ensure we are minimizing costs.

Lease operating expenses increased from $2.8 million for the six months ended December 31, 2015 to $5.1 million for the six months ended December 31, 2016. Costs per BOE have increased from $15.87 for the six months ended December 31, 2015 to $24.81 for the six months ended December 31, 2016. Excluding the impact of workovers, LOE for the period ended December 31, 2016 was $20.03 per BOE.

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Impact of North Stockyard sale

During the six months ended December 31, 2016 the North Stockyard field contributed $0.6 million to the lease operating expense. This equates to approximately $13 per barrel, excluding production taxes.

Commencing October 29, 2016 we were no longer responsible for the lease operating costs or production taxes associated with this field.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense decreased from $1.4 million for the quarter ended December 31, 2015 to $0.5 million for the quarter ended December 31, 2016. The decrease in depletion is a result of the increase in the reserve base over which depletion is following the Foreman Butte project acquisition. Depletion was not charged on the North Stockyard assets, as is customary when assets are held for sale. The per BOE cost decreased from $20.75 for the three months ended December 31, 2015 to $6.48 for the three months ended December 31, 2016.

Depletion, depreciation and amortization expense decreased from $2.9 million for the six months ended December 31, 2015 to $1.0 million for the six months ended December 31, 2016. The decrease in depletion is a result of the increase in the reserve base over which depletion is following the Foreman Butte project acquisition. Depletion has not been charged on the North Stockyard assets, as is customary when assets are held for sale. The per BOE cost decreased from $20.07 for the six months ended December 31, 2015 to $5.82 for the six months ended December 31, 2016.

General and administrative expense

General and administrative expense, excluding share based payments of $0.3 million, remained consistent at $0.9 million for the quarter ended December 31, 2015 and for quarter ended December 31, 2016. We have been actively trying to reduce our general and administrative costs in recent periods. General and administrative costs has on a per BOE basis has been offset by increased production. The BOE costs decreased, excluding share based payments, from $13.52 for the quarter ended December 31, 2015 to $12.10 for the quarter ended December 31, 2016.

General and administrative expense, excluding share based payments of $0.3 million, increased from $1.9 million for the six months ended December 31, 2015 to $2.1 million for the six months ended December 31, 2016. We have been actively trying to reduce our general and administrative costs in recent periods. The slight increase in general and administrative costs has been offset at on a per BOE basis by increased production. The BOE costs decreased, excluding share based payments, from $13.73 for the six months ended December 31, 2015 to $11.90 for the six months ended December 31, 2016.

Cash Flows

The table below shows cash flows for the following periods: 

	Six months ended
	31-Dec-16			31-Dec-15
Cash (used in)/provided by operating activities	$	(1,529,958	)	$	517,336
Cash provided by/(used in) investing activities		12,029,347			(1,873,615	)
Cash used in/(provided by) financing activities		(11,597,443	)		302,475

Cash provided by operations decreased from a net inflow of $0.5 million for the six months ended December 31, 2015, to a net outflow of ($1.4 million) for the six months ended December 31, 2016. Cash receipts from customers increased slightly from $6.5 million for six months ended December 31, 2015 to $6.8 million for the six months ended December 31, 2016, due to an increase in production and a slight increase in the realized oil price. Payments to suppliers and employees also increased slightly from $5.7 million for the six months ended December 31, 2015 to $6.5 million for the six months ended December 31, 2016 following increased workover activity in our Foreman Butte project area. Payments for derivative instruments and interest expense increased significantly in the six months ended December 31, 2016 compared to the six months ended December 31, 2015. Payments for derivative instruments increased due to an increase in the oil price compared to the price of derivative instruments. Interest expense increased due to the higher value of the credit facility held during the six months ended December 31, 2016 following the closing of the Foreman Butte project.

Cash used in investing activities decreased from $2.0 million for the six months ended December 31, 2015 to inflow of $11.9 million for the six months ended December 31, 2016 following the receipt of proceeds from the sale of our North Stockyard project area. The cash outflow for the prior period related to ongoing activities in our North Stockyard project in North Dakota. The cash outflow in the current period relates to continued work in Foreman Butte field.

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Cash provided by financing activities decreased from a cash inflow of $0.3 million for the six months ended December 31, 2015 to cash out of ($11.9 million) for the six months ended December 31, 2016. Cash inflow for the prior period related to in proceeds from the exercise of options. Cash out flow in the current period relates to repayments borrowings with respect to our credit facility with Mutual of Omaha Bank

All options outstanding as at December 31, 2016 are currently out of the money.

Liquidity, Capital Resources and Capital Expenditures

Our primary use of capital has been acquiring, developing and exploring oil and natural gas properties and we anticipate this will be our primary use of capital during fiscal 2017.  

Following the closing of our Foreman Butte Acquisition, our current budget for exploration, exploitation and development capital expenditures in fiscal 2017 is $3.0 million, of which we incurred approximately $2.0 million during the first six months of the fiscal year. These expenditures were funded through our current cash on hand, cash generated from oil sales and net proceeds from the sale of our North Stockyard project. We have additional workovers planned in our Foreman Butte Project during the course of the year.

In January 2014, we entered into a $25.0 million credit facility with our primary lender, Mutual of Omaha Bank, with an initial borrowing base of $8.0 million, which was increased to $15.5 million in June 2014. In November 2014, the borrowing base was increased to $19.0 million, which was fully drawn prior to the closing of the Foreman Butte Acquisition. In March 2016, our credit facility was amended to increase the borrowing base to $30.5 million to partially fund the Foreman Butte Acquisition. An additional $4 million in financing was also provided by the seller. This promissory note is due April 1, 2017 and has a 10% interest rate. We were required under the amended credit agreement to repay Mutual of Omaha $10 million by June 30, 2016. This was ultimately increased to $11.5 million and extended to October 31, 2016. The pay down was achieved through the sale of our North Stockyard property for $14.95 million on October 28, 2016 and was made on October 31, 2016.

As a result of the amendment of the credit facility, the interest rate was increased to 6% plus the 90 day LIBOR or approximately 6.5% from April 1, 2016 onwards. This was reduced following the pay down of the facility as detailed above. The amendment to our credit facility also requires us to comply with additional restrictions, which are described below. Following the repayment of the facility on October 31, 2016 the interest rate has been reduced to LIBOR plus 3.5%.

As of November 10, 2016 our borrowing base was increased to $20 million by Mutual of Omaha Bank, of which $19 million has been drawn down. The additional borrowing base capacity has no additional restrictions on it.

The borrowing base under our credit facility may be increased (up to the credit facility maximum of $50.0 million, which would require syndication of the loan) or decreased in the future depending on the value of our reserves. Borrowing base redeterminations are performed by the lender every six months based on our June and December reserve reports. We also have the ability to request a borrowing base redetermination at another period, once a year. The facility matures January 28, 2017. Mutual of Omaha Bank have indicated that they will perform a borrowing base determination based on our December 31, 2016 reserves. We can make no assurances, but we expect this borrowing base review to result in a significant increase to our current borrowing base and have commenced discussions with other banks with a view to syndicating the loan, at the suggestion of Mutual of Omaha Bank. While the new borrowing based is currently being determined by Mutual of Omaha Bank, based on the Company’s proved reserves the Company expects the borrowing base will be in excess of the current drawdown creating additional liquidity in the facility. Should we not be able to renegotiate the credit facility to its satisfaction, we may need to consider further asset sales or capital raises to provide the company with ongoing liquidity to repay its long and short term debts as and when they fall due.

In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. As a result of this amendment to the facility agreement, the following changes were made to the original facility agreement:

· The addition of more restrictive financial covenants (including the debt to EBITDA ratio and the minimum liquidity requirement);

· Increases in the interest rate and unused facility fee;

· The addition of a minimum hedging requirement of 75% of forecasted production;

· A requirement to reduce our general and administrative costs from $6 million per year to $3 million per year;

· A requirement to raise $5 million in equity on or before September 30, 2016 (this was extended to November 15, 2016 and then effective November 10, 2016. Mutual of Omaha agreed that this requirement had been met following the $1.4 million capital raise completed in April 2016 and by the application of retained funds from the North Stockyard sale);

· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 in line with the closing of the North Stockyard sale) and we repaid $11.5 million on October 31, 2016; and

· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement. No repayments have been made under this covenant.

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

· Current ratio greater than 1

· Debt to EBITDAX (annualized) ratio no greater than 5.75 for the quarter ended March 30, 2016 through to September 30, 2016 reducing to 4.00 by September 30, 2017

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· Senior leverage ratio of no greater than 4.25 to 1 for the quarter ended June 30, 2016 reducing to 3.75 for the quarter ending December 31, 2016 and thereafter

· Interest coverage ratio minimum of between 2.5 and 1.0

We were in compliance with all of our covenants as at June 30, 2016.

As at December 31, 2016 we were in breach of our spending cap with respect to the general and administrative expenses. We have received a waiver with respect to this covenant.

We were in compliance with all other covenants as at December 31, 2016.

Our credit facility of $19 million has been recorded as a current liability and is due for repayment October 2017. We are working with the bank to renegotiate our facility and extend its term. We believe we will meet the covenants in the future, however if we do not we will continue to ask for waivers on a quarterly basis as necessary; however there can be no guarantee they will be granted. If we do not receive a waiver from the lender, and if we fail to cure any such noncompliance during the applicable cure period, the due date of our debt could be accelerated by the lender. In addition, failure to comply with any of the covenants under our credit facility could adversely affect our ability to fund ongoing operations.

The funds drawn from our credit facility were used to fund drilling in our North Stockyard project in North Dakota and more recently, to partially fund the Foreman Butte acquisition.

Uncertainties relating to our capital resources and requirements include the effects of results from our exploration and drilling program and changes in oil and natural gas prices, either of which could lead us to accelerate or decelerate exploration and drilling activities. The aggregate levels of capital expenditures for our fiscal year ending June 30, 2017, and the allocation of those expenditures, are dependent on a variety of factors, including the availability of capital resources to fund the expenditures and changes in our business assessments as to where our capital can be most profitably employed. Accordingly, the actual levels of capital resources and expenditures and the allocation of those expenditures may vary materially from our estimates.

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

Our main sources of liquidity during the three months ended December 31, 2016 were cash on hand and cash flow from operations.

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

Our cash position as of December 31, 2016 decreased from June 30, 2016 largely due to payments for recompletion and workover activities in our Foreman Butte project in North Dakota and Montana, coupled with significant payments for our derivative instruments and higher interest payments.

In October 2016, we closed on the sale of our North Stockyard project for $15.05 million. $11.5 million of this has been used to pay down our credit facility with Mutual of Omaha Bank. $0.2 million was used to close out a portion of our hedge positions to balance our hedge book following the sale of production. The remaining $3.35 million, including the $1.0 million deposit paid in June 2016, will be used for future working capital.

In April 2016, we issued 378,020,400 ordinary shares at $0.0037 per ordinary share to raise gross proceeds of $1,398,675.

In April 2016, we also received cash of $725,000 from Halliburton following the settlement of our legal dispute with them.

If future production rates are less than anticipated, and/or the oil price continues to deteriorate for an extended period, 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 oil and gas properties. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2016. See also Part II, Item 1A of this report below.

Looking Ahead

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

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

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· Continued focus on strengthening the balance sheet through strong capital management;

· The successful integration of the properties and assets acquired in the Foreman Butte Acquisition, and the review and workover of such assets;

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

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

· Repayment of the $4 million promissory note issued to the seller in the Foreman Butte Acquisition; and

· Regaining and maintaining compliance with NYSE MKT listing standards.

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

Item 3.   Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

Item 4.    Controls and Procedures.

As of December 31, 2016, 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, 2016, our disclosure controls and procedures were effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.  

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

Part II — Other Information

Item 1.    Legal Proceedings.

In the ordinary course of our business we are named from time to time as a defendant in various legal proceedings.  We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business ordinarily is subject. There are no material pending legal proceedings to which the Company is a party or of which our property is the subject.

Item 1A.   Risk Factors.

In addition to 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, 2016.  The risks disclosed herein and in our Annual Report on Form 10-K could materially affect our business, financial condition or future results.  The risks described herein and in our Annual Report on Form 10-K are not the only risks facing us.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or operating results in the future.

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

Not applicable.

Item 3.    Defaults Upon Senior Securities.

Not applicable.

Item 4.    Mine Safety Disclosures.

Not applicable.

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Item 5.    Other Information. 

Not applicable.

Item 6.    Exhibits.

Exhibit No.	Title of Exhibit
31.1	Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
	*Furnished herewith

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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 21, 2017	By:	/s/ Terry Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)
Date: February 21, 2017	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

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