Samson Oil & Gas LTD - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - Samson Oil & Gas LTD	tv479914_ex32-1.htm
EX-31.2 - EXHIBIT 31.2 - Samson Oil & Gas LTD	tv479914_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Samson Oil & Gas LTD	tv479914_ex31-1.htm
EX-16.1 - EXHIBIT 16.1 - Samson Oil & Gas LTD	tv479914_ex16-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2017

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 an emerging growth company. See definition of “accelerated filer,” “large accelerated filer” and “emerging growth company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer ¨		Accelerated filer ¨

Non-accelerated filer ¨		Smaller reporting company x
(Do not check if a smaller reporting company)
		Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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 3,283,000,444 ordinary shares outstanding as of November 17, 2017.

SAMSON OIL & GAS LIMITED

FORM 10-Q

QUARTER ENDED September 30, 2017

TABLE OF CONTENTS

		Page

Part I — Financial Information		4

Item 1.	Financial Statements (unaudited)	4

	Consolidated Balance Sheets, September 30, 2017 and June 30, 2017	4

	Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months ended September 30, 2017 and 2016	5

	Consolidated Statements of Changes in Stockholders’ Equity/(Deficit) for the three months ended September 30, 2017	6

	Consolidated Statements of Cash Flows for the three months ended September 30, 2017 and 2016	7

	Notes to Consolidated Financial Statements (unaudited)	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22

Item 4.	Controls and Procedures	23

Part II — Other Information		23

Item 1.	Legal Proceedings	23

Item 1A.	Risk Factors	23

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	23

Item 3.	Defaults Upon Senior Securities	23

Item 4.	Mine Safety Disclosures	23

Item 5.	Other Information	24

Item 6.	Exhibits	24

Signatures		25

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 Foreman Butte and other properties, oil and gas pipeline availability and capacity, natural gas and oil reserves and production, our intentions and prospects with respect to our credit facility and term loan negotiations, meeting our capital raising targets and the use of proceeds, our plans, our ability to and methods by which we may raise additional capital, production and future operating results, and the objectives outlined under the section “Looking Ahead” below.

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;

•

climatic conditions; and

•

effectiveness of management strategies and decisions

Many of these factors are beyond our ability to control or predict. Neither these factors nor those included in the “Risk Factors” section of this quarterly report, 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.

Part I — Financial Information

Item 1. Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	30-Sep-17			30-Jun-17
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	807,652		$	628,778
Accounts receivable		1,411,405			1,550,438
Prepayments		118,001			54,519
Oil inventory		219,288			219,288
Oil and gas properties held for sale		-			-
Total current assets		2,556,346			2,453,023
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $14,930,012 and $14,474,391 at September 30, 2017 and June 30, 2017, respectively		31,046,704			31,497,273
Other property and equipment, net of accumulated depreciation and amortization of $671,164 and $693,945 at September 30, 2017 and June 30, 2017, respectively		278,831			296,077
Net property, plant and equipment		31,325,535			31,793,350
OTHER NON CURRENT ASSETS
Fair value of derivative instrument		-			99,603
Undeveloped capitalized acreage		271,078			271,078
Restricted cash - bonding		450,000			450,000
Other		299,258			291,181
TOTAL ASSETS	$	34,902,217		$	35,358,235

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,649,880		$	4,287,955
Accruals		382,041			821,319
Fair value of derivative instruments		780,460			363,960
Credit facility		23,869,749			23,419,749
Provision for annual leave		249,645			249,060
Total current liabilities		29,931,775			29,142,043
NON CURRENT LIABILITIES
Asset retirement obligations		3,392,705			3,156,236
Fair value of derivative instruments		25,476			-
Credit facility		-			-
TOTAL LIABILITIES		33,349,956			32,298,279
STOCKHOLDERS’EQUITY – nil par value
3,283,000,444 (equivalent to 16,415,002 ADR’s) and 3,283,000,444 (equivalent to 16,415,002 ADR’s) ordinary shares issued and outstanding at September 30, 2017 and June 30, 2017, respectively		106,627,581			106,390,864
Accumulated other comprehensive income		890,789			892,017
Accumulated deficit		(105,966,109	)		(104,222,925	)
Total stockholders’ equity		1,552,261			3,059,956
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	34,902,217		$	35,358,235

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three months ended
	30-Sep-17			30-Sep-16
REVENUES AND OTHER INCOME:
Oil sales	$	2,584,521		$	3,586,208
Gas sales		49,257			142,526
Other liquids		1,579			15,033
Interest income		58			115
Gain on derivative instruments		-			443,356
Other		178,658			165,943
TOTAL REVENUE AND OTHER INCOME		2,814,073			4,353,181

EXPENSES:
Lease operating expense		(1,651,677	)		(2,194,315	)
Depletion, depreciation and amortization		(478,058	)		(519,883	)
Impairment expense		-			(244,480	)
Abandonment expense		(40,856	)		-
Exploration and evaluation expenditure		(3,173	)		(6,055	)
Accretion of asset retirement obligations		(80,171	)		(79,187	)
Amortization of borrowing costs		(28,950	)		(66,849	)
Interest expense		(247,690	)		(623,393	)
Loss on derivative instruments		(667,395	)		-
Acquisition costs		-			-
General and administrative		(1,359,287	)		(1,154,461	)
TOTAL EXPENSES		(4,557,257	)		(4,888,623	)

Income (Loss) from operations		(1,743,184	)		(535,442	)
Income tax benefit		-			-
Net income (loss)		(1,743,184	)		(535,442	)
OTHER COMPREHENSIVE LOSS
Foreign currency translation loss		(1,228	)		13,813
Total comprehensive gain/(loss) for the period	$	(1,744,412	)	$	(521,629	)

Net loss per ordinary share from operations:
Basic – cents per share		(0.05	)		(0.02	)
Diluted – cents per share		(0.05	)		(0.02	)

Weighted average ordinary shares outstanding:
Basic		3,283,000,444			3,215,854,701
Diluted		3,283,000,444			3,215,854,701

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

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

(Unaudited)

						Accumulated
						Other			Total
	Ordinary					Comprehensive			Stockholders
	Shares		(Accumulated Deficit)			Income/(Loss)			Deficit
Balance at June 30, 2017	$	106,390,864	$	(104,222,925	)	$	892,017		$	3,059,956
Net loss		-		(1,743,184	)		-			(1,743,184	)
Foreign currency translation loss, net of tax of nil		-		-			(1,228	)		(1,228	)
Total comprehensive loss for the period		-		(1,743,184	)		(1,228	)		(1,744,412	)
Shares issued		-								-
Share based payments		236,717		-			-			236,717
Cost associated with issue of equity		-		-			-			-
Balance at September 30, 2017	$	106,627,581	$	(105,966,109	)	$	890,789		$	1,552,261

See accompanying Notes to Consolidated Financial Statements.

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended
	30-Sep-17			30-Sep-16
Cash flows (used in)/provided by operating activities
Receipts from customers	$	2,967,996		$	3,406,824
Payments to suppliers & employees		(2,687,828	)		(2,744,718	)
Interest received		58			115
Payments on from derivative instruments		(125,815	)		(188,389	)
Interest paid		(323,120	)		(402,634	)
Net cash flows (used in)/provided by operating activities		(168,709	)		71,198
Cash flows provided by/(used in) investing activities
Proceeds from sale of oil and gas properties		-			156,139
Payments for plant & equipment		(4,060	)		(77,690	)
Payments for exploration and evaluation		(2,671	)		(16,130	)
Payments for oil and gas properties		(92,848	)		(1,203,191	)
Net cash flows provided by/(used in) investing activities		(99,579	)		(1,140,872	)
Cash flows (used in)/provided by financing activities
Proceeds from the exercise of options		-			-
Proceeds from borrowings		450,000			-
Repayment of borrowings		-			-
Share issuance costs		-			-
Net cash flows (used in)/provided by financing activities		450,000			-
Net (decrease) in cash and cash equivalents		181,712			(1,069,674	)
Cash and cash equivalents at the beginning of the fiscal period		628,778			2,654,812
Effects of exchange rate changes on cash and cash equivalents		(2,838	)		(2,214	)
Cash and cash equivalents at end of fiscal period	$	807,652		$	1,582,924

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, 2017. 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, 2017 and September 30, 2017 consist primarily of estimates for goods and services received but not yet invoiced.

Prepayments. Prepayments at June 30, 2017 and September 2017 include tubing and chemicals 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.

Liquidity

These financial statements have been prepared on the going concern basis, which contemplates the continuity of normal business activities and the realization of assets and settlement of liabilities in the normal course of business.

As disclosed in the financial statements, we incurred losses of $1.7 million for the three months ended September 30, 2017 and had cash outflows from operations of ($0.2 million). As at September 30, 2017 we had net current liabilities of $27.2 million. Our ability to continue as a going concern is dependent on the renegotiation of our finance facilities to permit additional development of our oil and gas properties or a monetization of some or all of those properties. We are engaged in discussions with our current lender concerning a potential refinancing and with an investment banker concerning replacing our current bank facility with non-bank financing. We are also exploring the possible sale of some or all of our producing oil and gas assets in North Dakota and Montana. Based on our current financial position we may be required to accept terms less favorable than would otherwise be available to us. There also can be no assurances that we will be successful in renegotiation or refinancing of our debt or our efforts explore the sale of some or all of our assets. These factors indicate there is substantial doubt about our ability to continue as a going concern.

Recent Accounting Standards

In August 2014, the FASB issued Accounting Standards Update (“ASU”) 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 has been adopted by the Company and additional disclosures were made in the Form 10k for the period ended June 30, 2017.

In May 2014, the FASB issued Accounting Standards Update 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.

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
	30-Sep-17		30-Sep-16
Dilutive		-		-
Anti–dilutive		411,033,246		320,615,486

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

	Three months ended
	30-Sep-17			30-Sep-16
Net income (loss)	$	(1,743,184	)	$	(535,442	)

Basic weighted average ordinary shares outstanding		3,283,000,444			3,215,854,701
Basic earnings/(loss) per ordinary share – cents per share		(0.05	)		(0.02	)
Diluted earnings/(loss) per ordinary share – cents per share		(0.05	)		(0.02	)

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.

In the current year, the liabilities settled relate to wells plugged and abandoned in our Sabretooth project in Texas. Disposition of properties relate to the sale of certain wells in Wyoming.

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

The following table summarizes the activities for the Company’s asset retirement obligations for the three months ended September 30, 2017 and 2016:

	Three months ended
	30-Sep-17			30-Sep-16
Asset retirement obligations at beginning of period	$	3,456,236		$	3,750,245
Liabilities incurred or acquired		-			-
Liabilities settled		(12,500	)		(13,976	)
Disposition of properties		(131,202	)		-
Accretion expense		80,171			79,187
Asset retirement obligations at end of period		3,392,705			3,815,456
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		-			(300,000	)
Long-term asset retirement obligations	$	3,392,705		$	3,515,456

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 September 30, 2017 and June 30, 2017.

	Carrying value at September 2017		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at September 2017
Current Assets:
Cash and cash equivalents	$	807,652	$	807,652	$	-	$	-	$	-		$	807,652
Derivative Instruments		-		-		173,711		-		(173,711	)		-

Non Current Assets
Derivative Instruments		-		-		122,534		-		(122,534	)		-

Current Liabilities
Derivative instruments		780,460		-		954,171		-		(173,711	)		780,460

Non Current Liabilities
Derivative Instruments		25,476		-		148,010		-		(122,534	)		25,476

	Carrying value at June 30, 2017		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Fair Value at June 30, 2017
Current Assets:
Cash and cash equivalents	$	628,778	$	628,778	$	-	$	-	$	-		$	628,778
Derivative Instruments		-		-		167,307		-		(167,307	)		-

Non Current Assets
Derivative Instruments		99,603		-		370,494		-		(270,891	)		99,603

Current Liabilities
Derivative instruments		363,960		-		531,267		-		(167,307	)		363,960

Non Current Liabilities
Derivative Instruments		-		-		270,891		-		(270,891	)		-

(1)

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

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

Level 1 Fair value Measurements

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

Level 2 Fair Measurements

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

Other fair value measurements

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

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

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.

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

the period for which Samson has the right to explore;

planned and budgeted future exploration expenditure;

activities incurred during the year; and

activities planned for future periods.

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

As of September 30, 2017, we had capitalized exploration expenditures of $271,078. 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

No shares were issued during three months ended September 30, 2016 and September 30, 2017

Issue of Warrants

During the year ended June 30, 2017 we 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 vested on November 17, 2017. The warrants have been valued at AUD$0.0038 using a binomial option pricing model. We 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 sets of warrant grants will be recognized over the vesting period. For the period ended September 30, 2017 share based payment expense of $0.2 million has been recognized. A further $0.2 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:

	Three months ended
	30-Sep-17			30-Sep-16

Net loss after tax	$	(1,743,184	)	$	(535,442	)
Depletion, depreciation and amortization		478,058			519,883
Accretion of asset retirement obligation		80,171			79,187
Impairment expense		-			244,480
Exploration and evaluation expenditure		3,173			6,055
Amortization borrowing costs		28,950			66,849
Abandonment expense		40,856			-
Non cash (gain)/loss on derivative instruments		541,580			(711,876	)
Acquisition costs		-			-
Net (gain)/loss from sale of assets		(178,658	)		156,139
Share based payments		236,717			-

Changes in assets and liabilities:

Increase/(Decrease) in receivables		139,033			(289,723	)
Increase/(decrease) in provision for annual leave		585			47,498
Increase in payables		204,011			488,148
NET CASH FLOWS(USED IN)/PROVIDED BY OPERATING ACTIVITIES	$	(168,708	)	$	71,198

10. Credit Facility

	Three months ended
	30-Sep-17			30-Sep-16
Credit facility at beginning of period	$	23,419,749		$	30,500,000
Cash advanced under facility		450,000			-
Cash committed to be advanced under facility		-			-
Repayments		-			-
Credit facility at end of period ⁽¹⁾	$	23,869,749		$	30,500,000

Less amount of credit facility currently due for repayment within a year, recorded seperately in Current Liabilities for prior year	$	(23,869,749	)		(11,500,000	)
Total non current credit facility at end of period		-			19,000,000

Funds available for drawdown under the facility		130,251			-

(1)

The credit facility is recognized as a current liability due the Company’s continued breach of the covenants in the facility. The loan is due October 2018.

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 (as defined below). 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 was paid off in May 2017. 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.

In May 2017, Mutual of Omaha agreed to repay our outstanding promissory note to the seller of the Foreman Butte Acquisition through a term note in addition to our current facility. This closed on May 5, 2017. Samson paid $0.45 million in interest from existing cash reserves, while Mutual of Omaha paid $4.0 million in principal.

As a result of this amendment to the credit facility the interest changed from being based on LIBOR to the Wall Street Journal published Prime Rate (“Prime”). The interest rate on the term loan is Prime plus 2.5% or approximately 6.5% and the credit facility is Prime plus 1.0% or 5%.

In June 2017, Samson and Mutual of Omaha Bank agreed to extend both the $4 million term loan and our $19.45 million reserve base facility until October 2018. The previous maturity date was October 31, 2017.

The current borrowing base is $24.0 million and was fully drawn as at September 30, 2017. 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 time, once a year.

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. To date, $0.1 million in repayments have been repaid 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

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

As at September 2017 we were in breach of all four covenants. We have requested a waiver of these covenants.

If the current pricing environment for oil and gas does not improve, it will be difficult for the Company to re-attain compliance with these covenants based our current debt levels. If we are not in compliance with these covenants in the credit facility, we do not receive a waiver from the lender, and we fail to cure any such noncompliance during the applicable cure period, then the due date of our debt could be accelerated by the lender. In addition, any failure to comply with these covenants adversely affects 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. These costs 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 September 30, 2017, 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 three months ended September 30, 2017 we recognized $667,395 in loss on derivative instruments in the Statement of Operations. $0.1 million was realized during the quarter, while the remaining $0.55 million was unrealized.

At September 30, 2017, the Company’s open derivative contracts consisted of the following:

Collars

Product

Start Date

End Date

Volume
(BO/Mmbtu)

Floor

Ceiling

WTI

1-Oct-17

30-Apr-18

24,558

41.50

63.00

WTI

1-May-18

31-Dec-18

107,800

45.00

56.00

Henry Hub

1-Nov-17

30-Apr-18

64,774

2.80

3.60

Henry Hub

1-May-18

31-Dec-18

80,850

2.65

2.90

Costless Swaps

Product

Start

End

Volume (BO)

Swap

WTI

1-Oct-17

31-Dec-17

47,214

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, 2017, 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 principal business is the exploration and development of oil and natural gas properties in the United States. 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 were comprised 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 are operated by us, however a number of non-operated wells were also included in this package. We continue to concentrate our efforts on the operations of this field and the development of the PUD drilling program in the Home Run field. Our development efforts are currently constrained, however, by our lack of access to capital to fund any development activities. We have four current drilling permits for our Home Run field and anticipate drilling our first PUD well as soon as we obtain the necessary funding through a refinance of our credit facility or through the partial sale of our North Dakota and Montana assets, through there can be no assurance this will be possible.

Our net oil production was 54,869 barrels of oil for the quarter ended September 30, 2017, compared to 90,957 barrels of oil for the quarter ended September 30, 2016. Production was high during the period ended September 30, 2016 due to flush production from a number of wells that were worked over towards the end of June 2016 . This production has generally decreased in line with the expected decline curves. In light of recent weakness and volatility in the oil price and our lack of access to capital, we have discontinued workovers on marginally economical wells that stopped production during the period ended September 30, 2017. In addition, during the period ended September 30, 2017 two of our more significant wells were shut in with surface facility issues. In particular, the R Field did not produce for 28 days during the current quarter and the Evans well was shut in for 8 days.

Our net gas production was 8,578 Mcf for the quarter ended September 30, 2017, compared to 68,580 Mcf for the quarter ended September 30, 2016. Coupled with the decrease in natural gas production following our North Stockyard sale, one of our significant gas wells has been down since October 2016 while undergoing workover operations. These workover operations were not successful and, as a result, this well was plugged and abandoned. Associated gas produced in the Foreman Butte project area is not as significant as it was in the oil and gas properties previously owned by the Company, therefore the increased gas production from the acquisition has not offset the decline from the sale.

For the three months ended September 30, 2017 and September 30, 2016, we reported a net loss of $1.7 million and a net loss of $0.5 million, respectively. The loss in the current period reflects $0.6 million in depletion and amortization and $0.6 million in loss on derivative instruments.

Our ability to continue as a going concern is dependent on the renegotiation of our credit facility with our primary lender to permit additional development of our oil and gas properties or the monetization of some or all of those properties. We are engaged in discussions with our current lender concerning a potential refinancing and with an investment banking firm concerning replacement of our current bank facility with non-bank financing. We are also exploring to the possible sale of some or all of our producing oil and gas assets in North Dakota and Montana. In light of our current financial position, we may be required to accept terms less favorable than would otherwise be available to us in one or more of these transactions.

See “Results of Operations” below.

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

Notable Activities and Status of Material Properties during the Quarter Ended September 30, 2017 and Current Activities

Acquisition: Producing Properties

Foreman Butte Project, McKenzie County, North Dakota

Mississippian Madison Formation, Williston Basin

Samson 87% Operated Average Working Interest

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.

Our water flood pilot project for the Home Run Field was recently approved by the NDIC and commenced October 1st. The waterflood pilot project utilizes an existing wellbore, the Mays 1-20H, which is located on the flank of the field and is non-economic to produce for oil. The water flood is being used to add pressure to the reservoir which should enhance the recovery of oil. The well performance in the offsetting wells will be monitored to establish the viability of the flood. The water being used is produced formation water so that there is no chemical compatibility issue. In essence the water is being returned to the reservoir from which it originated. Initially this water will be trucked to the injector from the existing producing wells, but may be ultimately be pipelined. This waterflood will allow Samson to turn back on many wells that have been shut-in for the past 2 years. These shut-in wells were previously uneconomic to produce due to high water disposal costs.

The Home Run Field (also known as the Foreman Butte Field) is the largest area oil field in our portfolio. It was developed on a 640 acre spacing pattern and our engineering and geologic analyses have determined that only 3.2% of the original oil in place has been recovered to date. Given that oil fields typically recover up to around 20% of their oil in place there would appear to be significant un-developed oil to be recovered from this field.

Accordingly, we are planning to drill our first development well early next year if we can obtain access to the necessary capital. The first lateral would test the Ratcliffe Formation of the Mississippian Madison Group. Currently there are 20 Ratcliffe PUD locations identified. The second lateral would test an undeveloped reservoir in the Mission Canyon Formation of the Mississippian Madison Group. This lateral could prove up a new oil field with the potential for additional well locations (up to 20 vertical wells or 8 drill-out laterals). A 3,500 acre 4-way structural closure has been mapped from an abundance of existing well control in the area. In 2004, the Banks 1-18H well was planned to be drilled as a dual lateral into both the Ratcliffe and Mission Canyon reservoirs. The Mission Canyon lateral produced hundreds of barrels of oil while the lateral was being drilled. But the well was ultimately completed as just a single lateral into the Ratcliffe zone due to the operator being unable to remove a stuck whipstock that was set above the Mission Canyon lateral in order to drill the Ratcliffe lateral. Assuming we obtain financing to drill, this history makes the Company highly optimistic about the prospects for the currently planned Mission Canyon lateral.

Undeveloped Properties: Exploration Activities

Hawk Springs Project, Goshen County, Wyoming

Permo-Penn Project, Northern D-J Basin

Samson 37.5% working interest

Following a delay due to bad weather in the latter part of 2016, the recompletion of the Bluff #1-11 well has been further delayed due to our current focus on more capital efficient projects in the Foreman Butte project area. 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.

Cane Creek Project, Grand & San Juan Counties, Utah

Pennsylvanian Paradox Formation, Paradox Basin

Samson 100% Working Interest

We can exercise an option to lease 8,080 net acres with Utah SITLA (Utah School and Institutional Trust Lands Administration) at a cost of $75 per acre before November 30, 2017. Should Samson not be able to access additional capital prior to the option expiration, it is likely that we let this expire. We would have to write off the current carrying value of $0.2 million. This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline in Grand and San Juan Counties, Utah. The primary drilling objective is the over-pressured and oil saturated Cane Creek Clastic interval. Recent reprocessing of the original Potash 3-D seismic survey has improved the image of the subsurface. New prospects have been mapped and can potentially be drilled in the coming year.

Developed Properties: Drilling Activities

Rainbow Project, Williams County, North Dakota

Mississippian Bakken Formation, Williston Basin

Samson 23% and 52% working interest

Kraken Operating, LLC, the operator of the Gladys 1-20H well, has been producing this well at an average rate of 45 BOPD and 63 MCFPD during the quarter.

Results of Operations

For the three months ended September 30, 2017, we reported a net loss of $1.7 million compared to a net loss of $0.5 million for the same period in 2016.

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

	Three months ended
	30-Sep-17			30-Sep-16
Production Volume
Oil (Bbls)		54,869			90,957
Natural gas (Mcf)		8,578			68,458
BOE (Barrels of oil equivalent - based on one barrel of oil to six Mcf of natural gas)		56,299			102,367

Sales Price
Realized Oil ($/Bbls)	$	47.10		$	39.43
Impact of settled derivative instruments	$	(2.29	)	$	(2.95	)
Derivative adjusted price	$	44.81		$	36.48

Realized Gas ($/Mcf)	$	5.74		$	2.08

Expense per BOE:
Lease operating expenses	$	25.97		$	18.05
Production and property taxes	$	3.37		$	3.38
Depletion, depreciation and amortization	$	8.49		$	5.08
General and administrative expense	$	24.14		$	11.28

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

	Three months ended
	30-Sep-17			30-Sep-16			1Q17 to 1Q16 change
Oil sales	$	2,584,521		$	3,586,208		$	(1,001,687	)
Gas sales		49,257			142,526			(93,269	)
Other liquids		1,579			15,033			(13,454	)
Interest income		58			115			(57	)
Gain on derivative instruments		-			443,356			(443,356	)
Other		178,658			165,943			12,715

Lease operating expense		(1,651,677	)		(2,194,315	)		542,638
Depletion, depreciation and amortization		(478,058	)		(519,883	)		41,825
Impairment		-			(244,480	)		244,480
Abandonement		(40,856	)
Exploration and evaluation expenditure		(3,173	)		(6,055	)		2,882
Accretion of asset retirement obligations		(80,171	)		(79,187	)		(984	)
Interest expense		(247,690	)		(623,393	)		375,703
Loss on derivative instruments		(667,395	)		-			(667,395	)
Amortization of borrowing costs		(28,950	)		(66,849	)		37,899
General and administrative		(1,359,287	)		(1,154,461	)		(204,826	)
Net loss	$	(1,743,184	)	$	(535,442	)	$	(1,166,886	)

Comparison of Quarter Ended September 30, 2017 to Quarter Ended September 30, 2016.

Oil and gas revenues

Oil revenues decreased from $3.6 million for the three months ended September 30, 2016 to $2.6 million for the three months ended September 30, 2017, as a result of the decrease in oil production. Oil production decreased from 90,957 barrels for the three months ended September 30, 2016 to 54,869 barrels for the three months ended September 30, 2017. Production was higher during the period ended September 30, 2016 due to flush production from a number of wells that were worked over towards the end of June 2016. Subsequent production has generally decreased in line with the expected decline curves. In light of recent weakness and volatility in the oil price and our lack of access to capital, we have discontinued workovers on marginally economical wells that stopped production during the period ended September 30, 2017. In addition, during the period ended September 30, 2017, two of our more significant wells were shut in with surface facility issues. In particular, the R Field did not produce for 28 days during the current quarter and the Evans well was shut in for 8 days.

The realized oil price increased from $39.43 per Bbl for the three months ended September 30, 2016 to $47.10. per Bbl (excluding the impact of derivatives) for the three months ended September 30, 2017 following a recovery in the global oil price.

Gas revenues decreased from $0.1 million for the three months ended September 30, 2016 to $0.05 million for the three months ended September 30, 2017. This decrease was due to a decrease in production.

Sale of Assets

For the three months ended September 30, 2017 we recognized $0.2 million in profit on the sale of our working interest in a number of non operated wells in Wyoming. The wells were sold for the value of the current accounts payable owed to the operator and the plugging liability.

There were no comparable sales for three months ended September 30, 2016.

Exploration expense

Exploration expenditures for the quarter ended September 30, 2017 and September 30, 2016 were less than $10,000 for either quarter.

Impairment expense

We did not recognize any impairment expense during the three months ended September 2017. During the three months ended September 30, 2016 we recognized $0.2 million in impairment expense. The impairment recognized in the prior quarter 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”) decreased from $2.2 million for the quarter ended September 2016, to $1.5 million for the quarter ended September 30, 2017 due to lower production. Costs per BOE, excluding the impact of the workovers and production taxes were $23.39 a barrel. Costs have increased from $18.05 for the quarter ended September 30, 2016 due to increased salt water disposal costs in our Foreman Butte project area. The wells in the Foreman Butte project area are also older wells than those we have previously owned and require additional fresh water and hot oil cleanouts which increase in the operating costs of the wells. 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. Production also decreased during the quarter ended September 30, 2017, which partially contributed to the increase in per barrel LOE costs as a fixed costs were distributed over a smaller number of barrels.

During the quarter ended September 30, 2017 we received approval for our water flood project in the Home Run Field from the North Dakota Industrial Commission. This should lead to lower salt water disposal costs as this project involves injecting produced water (rather than disposing of it) in the May’s well to increase reservoir pressure in the oil field, up dip of the injection well. Injection operations commenced October 1^st.

Depletion, depreciation and amortization expense

Depletion, depreciation and amortization expense decreased slightly from $0.5 million for the quarter ended September 30, 2016 to $0.45 million for the quarter ended September 2017. The decrease is due to a decrease in production.

General and administrative expense

General and administrative expense, excluding share based payments of $0.2 million, remained consistent at $1.2 million for the quarter ended September 30, 2016 and September 30, 2017. We have been actively trying to reduce our general and administrative costs in recent periods. Effective October 1, 2017, all staff and directors took 25% pay cuts in order to reduce salary costs. The cost of a number of consultants have also been reduced.

Cash Flows

The table below shows cash flows for the following periods:

	Three months ended
	30-Sep-17			30-Sep-16
Cash (used in)/provided by operating activities	$	(168,709	)	$	71,198
Cash provided by/(used in) investing activities		(99,579	)		(1,140,872	)
Cash used in/(provided by) financing activities		450,000			-

Cash provided by operations decreased from a net inflow of $0.1 million for the three months ended September 30, 2016, to a net outflow of ($0.2 million) for the three months ended September 30, 2017. Cash receipts from customers increased decreased from $3.4 million for the three months ended September 30, 2016 to $3.0 million for the three months ended September 30, 2017, with an increase in price offset by a decrease in production. Payments to suppliers and employees also remained flat at $2.7 million for the three months ended September 30, 2016 and 2017. Payments for derivative instruments decreased slightly. Interest expense decreased slightly in the three months ended September 30, 2017 compared to the three months ended September 30, 2016. A decrease in the value of the credit facility from September 30, 2016 to September 30, 2017 was offset by an increase in the interest rate payable.

Cash used in investing activities decreased from $1.1 million for the three months ended September 30, 2016 to outflow of $0.1 million for the three months ended September 30, 2017 following a cessation of significant activity in our Foreman Butte project, while we secure the additional capital needed to exploit the PUD locations in this field. The cash outflow in the prior period relates to continued work in Foreman Butte field.

Cash provided by financing activities increased from a cash inflow of $nil million for the three months ended September 30, 2016 to cash inflow of $0.5 million for the three months ended September 30, 2017, following the drawdown of funds under our Mutual of Omaha Bank credit facility.

All options outstanding as at September 30, 2017 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. While we are planning for this to be our primary use of capital during the remainder of fiscal 2017-2018, we cannot conduct any further development activities until we secure additional funding. There can be no guarantee we will be able to secure this funding.

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 was paid off in May 2017. 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.

The current borrowing base is $24.0 million and was fully drawn as at September 30, 2017. The additional borrowing base capacity has no additional restrictions on it.

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);

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

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

As at September 30, 2017 we are in breach of all four of these covenants. We have requested waivers from Mutual of Omaha but there is no assurance that the waivers will in fact be granted.

Our credit facility has been recorded as a current liability and is due for repayment October 2018. If we do not meet the credit facility covenants, we will continue to ask for waivers on a quarterly basis as necessary, though there can be no guarantee than any waiver will be granted. If we do not receive a waiver from the lender, and 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, our failure to comply with these covenants under our credit facility would adversely affect our ability to fund ongoing operations.

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

The uncertainties surrounding our capital resources and requirements are further exacerbated by the variable results of 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 those 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 September 30, 2017 were cash on hand and a drawdown of $0.45 million from our Mutual of Omaha Bank credit facility.

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 September 30, 2017 increased slightly from June 30, 2017 largely due to a drawdown in our Mutual of Omaha Bank credit facility of $0.45 million.

In October 2016, we closed on the sale of our North Stockyard project for $15.05 million. $11.5 million of the proceeds of the sale were 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, was 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. Our ability to continue operations could also be adversely affected. See the risk factors in our Annual Report on Form 10-K for the fiscal year ended June 30, 2017. See also Part II, Item 1A of this report below.

Off-Balance Sheet Arrangements

Since our inception, we have not engaged in any off-balance sheet arrangements, including the use of structured finance, special purpose entities or variable interest entities.

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;

Strengthening the balance sheet through diligent capital management;

The successful integration of the properties and assets acquired in the Foreman Butte Acquisition, and the review and workover of such assets as capital becomes available; and

Renegotiation of our credit facility and extend its term.

Our ability to meet these objectives, depends on our success in raising additional capital to fund the planned development of our oil and gas properties.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Not applicable.

Item 4. Controls and Procedures.

Control weakness – Accounts Payable processing

The Company took over operatorship of the Foreman Butte field in May and June of 2016. This change necessitated a review of our accounts payable procedures. During this review we noted that the design of one of processes was not sufficient to adequately capture all invoices in a timely fashion. The impact of this was stated in Note 2 to our Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 15, 2017. At that time, we concluded that this control was not operating effectively for the quarter ended March 31, 2017. We have since revised and redesigned our accounts payable procedures and controls, with particular emphasis on ensuring the accuracy and completeness of our Annual Report on Form 10-K and this Quarterly Report on Form 10-Q. We have implemented these new controls however they have not been in place long enough to fully assess their control design and effectiveness.

As of September 30, 2017, we have carried out an evaluation under the supervision of, and with the participation of, our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2017, because of the deficiency noted above, our disclosure controls and procedures were not 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.

Other than disclosed above, there were no changes in our internal control over financial reporting that occurred during the three months ended September 30, 2017, 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, 2017. The risks disclosed herein and in our Annual Report on Form 10-K could materially affect our business, financial condition or future results. The risks described herein and in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or operating results in the future.

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

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Changes in Registrant’s Certifying Accountant

Effective November 16, 2017, Hein & Associates LLP (“Hein”), the independent registered public accounting firm for the Company, combined with Moss Adams LLP (“Moss Adams”). As a result of this transaction, on November 20, 2017, Hein resigned as the independent registered public accounting firm for the Company. Concurrent with such resignation, the Company’s audit committee approved the engagement of Moss Adams as the new independent registered public accounting firm for the Company.

The audit reports of Hein on the Company’s financial statements for the fiscal years ended June 31, 2017 and 2016 did not contain an adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles other than Hein’s report for the year ended June 30, 2017 contained an explanatory paragraph expresses substantial doubt about our ability to continue as a going concern.

During the two most recent fiscal years ended June 30, 2017 and through the subsequent interim period preceding Hein’s resignation, there were no disagreements between the Company and Hein on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of Hein would have caused them to make reference thereto in their reports on the Company’s financial statements for such years.

During the two most recent fiscal years ended June 30, 2017 and through the subsequent interim period preceding Hein’s resignation, there were no reportable events within the meaning set forth in Item 304(a)(1)(v) of Regulation S-K, other than Hein notifying us of the material weakness noted in item 4.

During the two most recent fiscal years ended June 30, 2017 and through the subsequent interim period preceding Moss Adam’s engagement, the Company did not consult with Moss Adams on either (1) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that may be rendered on the Company’s financial statements, and Moss Adams did not provide either a written report or oral advise to the Company that Moss Adams concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (2) any matter that was either the subject of a disagreement, as defined in Item 304(a)(1)(iv) of Regulation S-K, or a reportable event, as defined in Item 304(a)(1)(v) of Regulation S-K.

The Company has provided Hein a copy of the disclosures in this Form 10-Q and has requested that Hein furnish it with a letter addressed to the Securities and Exchange Commission stating whether or not it agrees with the Company’s statements herein. A copy of the letter dated November 20, 2017 is filed as Exhibit 16.1 to this Form 10-Q.

Item 6. Exhibits.

Exhibit No.		Title of Exhibit

16.1		Letter from Hein & Associates LLP dated November 20, 2017

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

+ Management contract or compensatory plan or arrangement

Signatures

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

	SAMSON OIL & GAS LIMITED

Date: November 20, 2017	By:	/s/ Terry Barr
		Terence M. Barr
		Managing Director, President and Chief Executive Officer (Principal Executive Officer)

Date: November 20, 2017	By:	/s/ Robyn Lamont
		Robyn Lamont
		Chief Financial Officer (Principal Financial Officer)

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Samson Oil & Gas LTD Reports

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