10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended June 30, 2019

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

For the transition period from                         to                             

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 8 99 St Georges Terrace Perth, Western Australia 6000
(Address of principal executive offices)	(Zip Code)

+61 8 9486 4036

(Registrant’s telephone number, including area code)

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

Securities Registered Pursuant to Section 12(b) of the Act:

American Depositary Shares* Ordinary Shares**	OTC MARKETS’ OTCQB
Title of Each Class	Name of Exchange on Which Registered

*	American Depositary Shares evidenced by American Depository Receipts.  Each American Depositary Share represents 200 Ordinary Shares.
**	No par value. Not for trading, but only in connection with the listing of American Depositary Shares.

Securities Registered Pursuant to Section 12(g) of the Act:   None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ¨     No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes  ¨     No  x

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. Yes  x     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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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

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

The aggregate market value of the registrant's ordinary shares held by non-affiliates of the registrant on December 31, 2018 was approximately $2.1 million based on the closing price of its American Depositary Shares, each of which represents 200 ordinary shares, as reported on the OTCQB over the counter trading platform (treating, for this purpose, all executive officers and directors of the registrant, as affiliates).

There were 328,300,044 ordinary shares outstanding as of October 15, 2019.

DOCUMENTS INCORPORATED BY REFERENCE

Part III of this Form 10-K is incorporated by reference from the registrant’s definitive proxy statement which will be filed no later than 120 days after June 30, 2019.

SAMSON OIL & GAS LIMITED

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS		1
GLOSSARY OF TECHNICAL TERMS		2
PART I		3
Item 1 and 2.	Business and Properties	3
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	25
Item 3.	Legal Proceedings	27
Item 4.	Mine Safety Disclosures	27
PART II		27
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 8.	Financial Statements and Supplementary Data	43
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	43
Item 9A.	Controls and Procedures	43
Item 9B.	Other Information	45
PART III		45
Item 10.	Directors, Executive Officers and Corporate Governance	45
Item 11.	Executive Compensation	45
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	45
Item 13.	Certain Relationships and Related Transactions, and Director Independence	45
Item 14.	Principal Accounting Fees and Services	45
PART IV		45
Item 15.	Exhibits and Financial Statement Schedules	45
SIGNATURES		50

i

FORWARD-LOOKING STATEMENTS

Written forward–looking statements may appear in documents filed with the Securities and Exchange Commission (“SEC”), including this annual 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.

In this annual report, the use of words such as “anticipate,” “continue,” “estimate,” “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 appear in a number of places in this annual report and include, but are not limited to, management’s comments regarding the anticipated outcome and timing of the administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32; the anticipated outcome and timing of our efforts to renegotiate the Credit Agreement (as defined in Item 1), obtain a waiver of our breaches of the Credit Agreement from the Lender (as defined in Item 1), and sell our assets; our financial and operational prospects (whether or not a sale is consummated or the Lender agrees to renegotiate the Credit Agreement and waive our breaches under the Credit Agreement); the potential remedies available to the Lender under our credit agreement and our options with respect to meeting our financial obligations; trading liquidity and other risks relating to our common stock and ADSs; 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; the cost of compliance with environmental laws; our strategy to control general and administrative costs; our intentions with respect to meeting our capital raising targets and the use of proceeds; our plans, our ability to and the methods by which we may raise additional capital; our prospects for continuing as a going concern and regarding our production and future operating results, such as the following:

· 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 annual report represent a complete list of the factors that may affect us. We do not undertake to update our forward–looking statements.

1 

GLOSSARY OF TECHNICAL TERMS

Bbl.   Barrel (of oil or natural gas liquids).

Bbls.   Barrels of oil.

BOE.   Barrel of oil equivalent., based on 6 MCF of gas conversion to 1 barrel of oil

BOEPD.  Barrels of oil equivalent per day.

BOPD.   Barrels of oil per day.

Btu. British thermal unit. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Contingent Resources. Potentially recoverable volumes associated with a development plan that targets discovered volumes but is not (yet) commercial, as defined below.

To be considered as “commercial”, there must be a firm intention to proceed with the project in a reasonable time frame (typically 5 years), and such intention must be based upon all of the following criteria:

· A reasonable assessment of the future economics of the development project meeting defined investment and operating criteria;

· A reasonable expectation that there will be a market for all or at least the expected sales quantities of production required to justify development;

· Evidence that the necessary production and transportation facilities are available or can be made available; and

· Evidence that legal, contractual, environmental and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated.

Developed acres.   The number of acres that are allocated or held by producing wells or wells capable of production.

Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities. The terminal point is generally regarded as the outlet valve on the lease or field storage tank.

Exploratory well.   A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Fracture stimulation. The process of initiating and subsequently propagating a fracture in a rock layer, employing the pressure of a fluid as the source of energy in order to increase the extraction rates and ultimate recovery of oil and natural gas.

Gross acres or gross wells.   The total acres or wells, as the case may be, in which a working interest is owned.

MBbls.  Thousand barrels of oil.

2 

MMbo. Million barrels of oil.

MMBOE. Thousands of barrels of oil equivalent

Mcf.   Thousand cubic feet (of natural gas).

Mcf/d. Thousand cubic feet (of natural gas) per day

Mcfe.   Thousand cubic feet equivalent.

MMBtu.   One million British Thermal Units, a common energy measurement.

 Productive wells.   Producing wells and wells that are capable of production, including injection wells, salt water disposal wells, service wells, and wells that are shut–in.

Proved developed reserves. Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved properties. Properties with proved reserves.

Proved reserves.   Estimated quantities of crude oil, natural gas, and natural gas liquids which, upon analysis of geologic and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.  Proved reserves are sub–classified into either proved developed reserves or proved undeveloped reserves.

Proved developed producing reserves (PDP).   Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and that are currently being produced.

Proved Developed Producing Behind Pipe (PDP BP). Those reserves expected to be recovered from completion intervals not yet open but remain behind casing in existing wells.

Proved Developed Not Producing (PDNP). Estimated proved reserves expected to recovered from existing wells where there is a requirement to achieve a workover to re-establish production.

Proved undeveloped reserves (PUD).   Estimated proved reserves that are expected to be recovered from new wells on undeveloped acreage or from existing wells where a relatively major expenditure is required for recompletion.

Undeveloped acreage.   Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains estimated proved reserves.

Working interest.   An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

PART I

Item 1 and 2. Business and Properties

Samson Oil & Gas Limited (“we”, “Samson” or the “Company”) is a company limited by shares, incorporated on April 6, 1979, under the laws of Australia.  Our principal business is the exploration and development of oil and natural gas properties in the United States. 

Recent activities

On April 9, 2019, Samson Oil and Gas, USA, Inc., our wholly owned subsidiary, entered into a credit agreement (“Credit Agreement”) with AEP I FINCO LLC (“Lender”) providing for a $33.5 million term loan. The Company used the proceeds of the Credit Agreement to retire the Company’s previous credit facility of $23.9 million with Mutual of Omaha Bank, repay outstanding creditors, royalty and working interest owners and provide working capital to pursue its infill development drilling program. In conjunction with the closing of the Credit Agreement, the Company paid $1.4 million in deferred borrowing costs.

3 

The Credit Agreement is secured by certain of the Company’s oil and gas properties and has a 5-year term with a maturity date on April 9, 2024. Interest on the Credit Facility accrues at a rate equal to LIBOR plus a margin of 10.5% and is payable on the last day of each interest period. Under the terms of the Credit Agreement, the Company is subject to certain covenants and obligations, as described in Note 8 to the Consolidated Financial Statements. At June 30, 2019, we were in violation of certain financial covenants. We have, therefore, classified the total amount outstanding under our debt facility of $33.5 million as a current liability and fully amortized the $1.4 million of deferred borrowing costs as a charge to finance expense in our statement of operations.

The infill development drilling program is designed to drill horizontal laterals from the existing well bores. The ability to drill out of an existing wellbore has made the economics of these development wells attractive, given the ability to use surface facilities associated with the existing well. Over the next nine months, we expect to drill a total of eight lateral wells within the Home Run Field (the “Home Run Field Drill Program”), which is the largest (by area) of the oil fields in Samson’s portfolio. The Company has in its portfolio a total of 26 Contingent resource locations that management expects will provide an excellent growth platform. The Credit Agreement is expected to provide sufficient working capital to initiate and maintain the planned development drilling program. Due to our recent breaches of the Credit Agreement, however, the Lender may declare an event of default and foreclose on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses, depleting our working capital such that we would be unable to maintain the planned development drilling program.

Going concern

We do not generate adequate revenue to satisfy our current operations, we have negative cash flows from operations, and we have incurred significant net operating losses during the years ended June 30, 2019, and 2018, which raise substantial doubt about our ability to continue as a going concern. We are also in breach of several of our covenants under the Credit Agreement, resulting in our borrowings payable of $33.5 million being classified as current liabilities.

Accordingly, our 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. We are currently negotiating with a prospective party a transaction to divest all of our oil and gas assets, which we believe, if successful, will result in proceeds not less than our obligations under the Credit Agreement and to our vendors. We are also currently negotiating with the Lender in an effort to obtain a waiver for our breach of the Credit Agreement.

Our ability to continue as a going concern is dependent on our re-negotiation of the Credit Agreement, our ability to sell our assets, development of our Foreman Butte property, and our ability to reduce costs or raise further capital. There can be no assurances that we will successfully obtain a waiver from the Lender, successfully divest our assets, or increase our cash flows from operations. Given our current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

Prior Transactions

In March 2016, we acquired the Foreman Butte Project, comprised of a number of producing and non-producing, operated and non-operated properties in the Ratcliffe and Madison formations in North Dakota and Montana. The purchase price was $16.0 million (before post-closing settlement adjustments) and following a review of the fair market value of the assets and liabilities on the closing date of the transaction, we recorded a bargain purchase gain of $10.7 million. This acquisition was financed through an extension in our credit facility with Mutual of Omaha Bank of $11.5 million and a $4.0 million promissory note provided to the seller of the assets. This note was repaid in May 2017 through a term note facility from Mutual of Omaha Bank.

On June 30, 2016, we signed a purchase and sale agreement for the sale of our North Stockyard project in North Dakota. The sale price was $15.0 million and closed on October 31, 2016, of which $11.5 million of the total proceeds from this transaction were used to pay down our credit facility with Mutual of Omaha Bank. The remaining proceeds were used to rebalance our hedge book, following the sale of a portion of our production, and for working capital.

In May 2017, we closed on the sale of our State GC assets in New Mexico. The sale price of $1.2 million was applied to pay down our facility with Mutual of Omaha Bank. In June 2017, Samson and Mutual of Omaha Bank agreed to extend both the $4 million term loan and our $19.5 million reserve base facility until October 2018. The previous maturity date was October 31, 2017.

4 

In June 2018, we signed a purchase and sale agreement for the sale of the majority of our working interest in the Foreman Butte project in Montana and North Dakota for $40 million. This sale was expected to close on October 15, 2018 however the buyer failed to close. We terminated the purchase and sale agreement with the buyer and engaged PLS Energy Advisors Group to remarket the asset. A non-refundable $1 million deposit placed into escrow by the buyer was released to us.

Business Strategy

Our business strategy is to acquire, explore and develop oil, natural gas and natural gas liquids ("NGL's") in the United States, primarily with a focus in Montana and North Dakota. Our long-term strategy is to seek to deliver net asset value per share growth to our investors via attractive investments within the oil and gas industry. In the event we are able to obtain sufficient additional capital we expect to seek properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, and re-completion and re-working projects.

Production and Reserves Estimates

Production Activities

Average net barrel of oil equivalent (“BOE”) production per day (“BOEPD”) for the fiscal year ended June 30, 2019, was 629 BOEPD, an increase of 112 BOEPD or 21.5% compared to the same period in the prior year. Current 30 day production rate (as of August 31, 2019), is averaging 1,101 BOPD (on a gross Operated basis) and approximately 780 BOPD net to Samson. This increase is due to bringing wells back online through a series of workovers.

Prior 12-month net sales volumes by quarter:

	Q3 2018		Q4 2018		Q1 2019		Q2 2019		Total
OIL, BBL		54,779		63,618		46,258		59,135		223,790
GAS, MCF		11,941		10,583		5,213		7,882		35,619
BOE		56,769		65,381		47,127		60,449		229,726
BOEPD		617		711		524		664		629

We have an interest in the following joint operations whose principal activities are oil and gas exploration and production.

		Working Interest Held
Project/Property Name		%		%
Exploration	Location	2019		2018
Roosevelt *	United States of America		66.00		66.00

* leases expired or wells plugged and abandoned

Production
Big Hand	United States of America	4.00	4.00
Bird Canyon	United States of America	16.00	16.00
Jalmat	United States of America	60.00	60.00
LA Ward	United States of America	3.00	3.00
Neta	United States of America	13.00	13.00
Powder River Basin	United States of America	18.00	18.00
Scribner	United States of America	28.00	28.00
Wagensen	United States of America	8.00	8.00
Foreman Butte	United States of America	1-100	1-100

5 

Reserve Analysis

The Company’s estimated total net proved reserves of oil and natural gas as of June 30, 2019, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following tables. All of our reserves are located in the United States. The estimates quoted for June 2019, are based on, and fairly represent, information and supporting documentation prepared by an employee of Netherland Sewell & Associates Inc, an independent petroleum engineering consulting firm. Netherland, Sewell & Associates, Inc. and its employees and its registered petroleum engineers have no interest in Samson and performed those services at their standard rates. Netherland, Sewell & Associates, Inc.’s estimates were based on a review of geologic, economic, ownership, and engineering data provided to them by us.

In accordance with SEC regulations, no price or cost escalation or reduction was considered. The technical persons at Netherland, Sewell & Associates, Inc. responsible for preparing our reserve estimate meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the estimating and auditing of oil and gas reserves information promulgated by the Society of Petroleum Engineers.

In substance, the Netherland, Sewell & Associates, Inc. report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical factors. Information for this purpose was obtained from owners of interests in the areas involved, state regulatory agencies, commercial services, outside operators and files of Netherland, Sewell & Associates, Inc.

Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with SEC rules and regulations as well as with established industry practices. Our officers, executives and geologists have experience evaluating reserves on a well by well basis and on a company wide basis. Prior to generation of the annual reserves, management and staff prepare an internal reserve study and then meet with Netherland, Sewell & Associates, Inc. to review properties and discuss assumptions used in our internal study and the calculation of reserves. Management reviews all information submitted to Netherland, Sewell & Associates, Inc. to ensure the accuracy of the data. Management also reviews the final report from Netherland, Sewell & Associates, Inc. and discusses any differences from Management expectations with them.

The reserve estimates are reported to the Board of Directors, at least annually. Our Board members have experience in reviewing and understanding reserve estimates.

The following tables summarize our proved oil and natural gas reserves at June 30, 2019, using SEC regulations and our contingent resources at June 30, 2019:

	As at 30 June 2019
Reserves	NET OIL MBBLS		NET GAS MMCF		NET BOE MBBLS		NPV 10 MILLION
PDP		2,930		915		3,083	$	47.6

Contingent Resources *	NET OIL MBBLS		NET GAS MMCF		NET BOE MBBLS		NPV 10 MILLION
1C - Non-producing		102		141		126	$	1.4
1C - Undeveloped		2,682		2,236		3,055	$	44.8
Total contingent resources		2,784		2,377		3,181	$	46.2
Total proved plus contingent resources		5,714		3,292		6,264	$	93.8

* Contingent Resources are potentially recoverable volumes associated with a development plan that targets discovered volumes but is not (yet) commercial, as defined below.

6 

To be considered as “commercial”, there must be a firm intention to proceed with the project in a reasonable time frame (typically 5 years), and such intention must be based upon all of the following criteria:

· A reasonable assessment of the future economics of the development project meeting defined investment and operating criteria;

· A reasonable expectation that there will be a market for all or at least the expected sales quantities of production required to justify development;

· Evidence that the necessary production and transportation facilities are available or can be made available; and

· Evidence that legal, contractual, environmental and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated.

Given our current financial condition there is no assurance that we will have the necessary financial resources available to meet the defined investment and operating criteria, noted above, in order to execute the development plan necessary to categorize the Contingent resources as proven reserves.

Notes to Reserves and Resources Estimates

NET BOE MBBLS is thousand barrels of oil equivalent

BOE is calculated using a heating value of gas and converted as 1 BOE equals 6 MCF

PDP is Proved Developed Producing Reserves

1C – Non-Producing is Contingent Developed Non-Producing Resources

1C - Undeveloped is Contingent Undeveloped Resources

NPV₁₀ is Net Present Value at 10% discount rate

The oil price after basis adjustments used in our June 30, 2019 reserve study for oil was $55.68 per Bbl and for natural gas was $3.89 per Mcf. The assumed prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect actual market prices for oil production sold after June 30, 2019. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.

The following reserve estimate using the NYMEX and Henry Hub strip prices are as follows:

As of June 30, 2019
Reserve category	Net Oil MBBLS		Net Gas MMCF		Net BOE MBBLS		NPV 10 $ MILLION
Proved Developed Producing		2,788		856		2,930	$	37.93

Notes to Reserves Estimates

NET BOE MBBLS is thousand barrels of oil equivalent

BOE is calculated using a heating value of gas and converted as 1 BOE equals 6 MCF

PDP is Proved Developed Producing Reserves

NPV₁₀ is Net Present Value at 10% discount rate

7 

The commodity prices used in this estimate are as follows:

	Oil Price $/Bbl		Gas Price ($/MMBTU)
December 31, 2019		52.27		3.24
December 31, 2020		50.46		3.41
December 31, 2021		48.41		3.45
December 31, 2022		47.81		3.47
December 31, 2023		47.90		3.54
Thereafter		48.32		3.64

Reporting and Financials

We became required to file our periodic reports to the SEC as a U.S. domestic issuer as of July 1, 2011. Since we remain an Australian corporation, however, we are still considered to be a domestic company in Australia as well.  As a result, we are required to report our financial results in the U.S. using U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) and in Australia using International Financial Reporting Standards (“IFRS”).

We publish our consolidated financial statements, both U.S. GAAP and IFRS, in U.S. dollars.  In this annual report, unless otherwise specified, all dollar amounts are expressed in U.S. dollars, and references to “dollars,” “$” or “US$” are to United States dollars.  All references to “A$” are to Australian dollars.

Our registered office is located at Level 8, 99 St Georges Terrace, Perth, Western Australia 6000 and our telephone number at that office is +61 8-9486-4036. Our principal office in the United States is located at 1331 17^th Street, Suite 710, Denver, Colorado 80202 and our telephone number at that office is +1 303-295-0344. Our website is www.samsonoilandgas.com.

Marketing, Major Customers and Delivery Commitments

Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors. These contracts are generally set up on a month to month basis and can be cancelled at any time by either party giving 30 days’ notice. We had no material delivery commitments as of the date of this report.

Regulatory Environment

Our oil and gas exploration, production, and related operations are subject to numerous and frequently changing federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These regulations relate to, among other things, environmental and land-use matters, conservation, safety, pipeline use, drilling and spacing of wells, well stimulation, transportation, and forced pooling and protection of correlative rights among interest owners. Environmental laws and regulations may require the acquisition of certain permits prior to or in connection with our activities and operations. In addition, they may restrict or prohibit the types, quantities, and concentration of substances that can be released into the environment, including releases from drilling and production operations, and restrict or prohibit drilling or other operations that could impact wetlands, endangered or threatened species or other protected areas or natural resources. Following is a summary of some key statutory and regulatory programs that affect our operations.

Regulation of Oil and Gas

Certain regulations may govern the location of wells, the method of drilling and casing wells, the rates of production or “allowables,” the surface use and restoration of properties upon which wells are drilled, and the notification of surface owners and other third parties. Certain laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. We also are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases and other exploration agreements, fees, taxes, or other burdens, obligations, and issues unique to oil and gas ownership and operations within Native American reservations.

Environmental and Land Use Regulation

A wide variety of environmental and land-use regulations apply to companies engaged in the production and sale of oil and natural gas. These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. Failure to comply with these requirements can result in civil and/or criminal penalties and liability for non-compliance, clean-up costs and other environmental and natural resource damages. It also is possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect.

Discharges to Waters.   The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and comparable state statutes impose restrictions and controls on the discharge of “pollutants,” which include dredge and fill material, produced waters, various oil and natural gas wastes, including drilling fluids, drill cuttings, and other substances. Discharge of such pollutants into wetlands, onshore (streams, rivers, etc.), coastal and offshore waters without appropriate permits is prohibited. These controls generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Violation of the Clean Water Act and similar state regulatory programs can result in civil, criminal and administrative penalties for the unauthorized discharges of pollutants. Violations also put operators at risk of citizen lawsuits under the Clean Water Act, seeking both enforcement of the Clean Water Act’s provisions and civil penalties and litigation costs. Operators may also face substantial liability for the costs of removal or remediation associated with improper discharges of pollutants.

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The Clean Water Act also regulates stormwater discharges from industrial properties and construction sites, and requires permits and the implementation of site-specific Stormwater Pollution Prevention Plans (“SWPPPs”), best management practices, training, and periodic monitoring of covered activities. Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure (“SPCC”) plans, and in some circumstances, facility response plans to address potential oil and produced water spills. Certain exemptions from some Clean Water Act requirements were created or broadened pursuant to the Energy Policy Act of 2005.

The Oil Pollution Act (“OPA”) of 1990 places strict liability for oil spills on the "responsible party," which it defines for onshore facilities as the owner or operator of a facility or pipeline. Strict liability means liability without fault. The OPA provides for the recovery of cleanup and removal costs, and also recognizes as recoverable damages the loss of profits or impairment of earning capacity due to the injury to natural resources caused by an oil spill. Further, a federal, state, foreign government, or Indian tribe trustee may recover damages for injury to natural resources, including the reasonable cost of assessing the damage. Finally, federal and state governments may also recover damages for the loss of taxes, royalties, rents, fees, or profits brought about by injury to property or natural resources. We may be subject to strict liability under OPA for all or part of the costs of cleaning up oil spills from our facilities and for natural resource damages. We have not, to our knowledge, been identified as a responsible party under OPA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their operation of those properties.

Safe Drinking Water Act – Regulation of Hydraulic Fracturing. The federal Safe Drinking Water Act, or the “SDWA”, is the main federal law that authorizes the United States Environmental Protection Agency (“EPA”) to set standards for drinking water quality and oversee the states, localities, and water suppliers who implement those standards. The Underground Injection Control (UIC) Program under the SDWA is responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids underground. The Energy Policy Act of 2005 currently excludes hydraulic fracturing from regulation by the SDWA. Hydraulic fracturing is a process that creates a fracture extending from a well bore into a low-permeability rock formation to enable oil or natural gas to move more easily to a production well. Hydraulic fractures typically are created through the injection of water, sand and chemicals into the rock formation.

The United States Congress has on multiple occasions considered, and may in the future consider, legislation such as the Fracturing Responsibility and Awareness of Chemicals Act, or the FRAC Act, to amend the SDWA to repeal this exemption. However, Congress has not taken any significant action on such legislation. A version of the FRAC Act was introduced in 2017 but remains in the first stages of the legislative process. If enacted as currently proposed, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, including disclosure of chemicals used in the fracturing process, and meet plugging and abandonment requirements. The FRAC Act’s proposal to require the reporting and public disclosure of chemicals used in the fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. It is not possible to predict whether a future session of Congress may act further on hydraulic fracturing legislation. Such legislation, if adopted, could establish additional regulation and permitting requirements at the federal level.

In addition, in March 2010, at the request of the U.S. Congress, EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water resources. A progress report was released in December 2012. In May 2014, the EPA indicated that as a first step, it would convene a stakeholder process to develop an approach to obtain information on chemical substances and mixtures used in hydraulic fracturing. To gather information to inform EPA's proposal, the EPA issued an advance notice of proposed rulemaking (ANPR) and initiated a public participation process to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanism for obtaining this information. EPA issued a draft report in June 2015, concluding that, although hydraulic fracturing activities have the potential to impact drinking water resources through water withdrawals, spills, fracturing directly into such resources, underground migration of liquids and gases, and inadequate treatment and discharge of wastewater, EPA did not find evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States. EPA finalized the report in December 2016, after considering public comments on the draft report. The key findings remain largely unchanged from the draft report, although EPA noted in the final report that data gaps and uncertainties limited EPA’s ability to fully assess the potential impacts on drinking water resources locally and nationally.

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Hydraulic fracturing currently is regulated primarily at the state level. Colorado, Wyoming, Montana, North Dakota, Texas, and New Mexico recently enacted rules to regulate certain aspects of hydraulic fracturing. These regulations generally require companies to disclose the chemicals used in hydraulic fracturing operations, as well as the concentrations of those chemicals, on a well-by-well basis, either prior to or following well completion, depending on which state’s regulations apply.

Air Emissions.  Our operations are subject to local, state and federal regulations governing emissions of air pollutants. Major sources of air pollutants are subject to more stringent, federally based permitting requirements. Producing wells, natural gas plants and electric generating facilities all emit volatile organic compounds (“VOCs”) and nitrous oxides in their normal operation.  Civil and administrative enforcement actions for failure to comply strictly with air pollution regulations or permits generally are resolved by payment of monetary fines, performance of mitigation projects to offset excess emissions and the correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain sources of emissions.

In April 2012, EPA issued regulations specifically applicable to the oil and gas industry that among other things, requires operators to capture 95 percent of the VOC emissions from natural gas wells that are hydraulically fractured. The reduction in VOC emissions is accomplished primarily through the use of “reduced emissions completion” methods to capture natural gas that would otherwise escape into the air or be combusted. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, valves and connectors. In June 2016, EPA issued additional regulations specific to the oil and gas industry adding methane standards for equipment and processes covered by the 2012 regulations.  The 2016 final regulations also add leak detection and repair (LDAR) requirements for equipment such as valves, connectors, pressure relief valves, open-ended lines, access doors, flanges, crank case vents, pump seals or diaphragms, closed vent systems, compressors, separators, dehydrators, thief hatches on storage tanks, and sweetening units at gas processing plants. On April 19, 2017, EPA announced its intent to administratively reconsider the methane rules, staying a June 3, 2017 effective date for certain provisions—such as the LDAR provisions—for 90 days. Environmental groups filed a petition to stop the administrative stay in the D.C. Circuit, and on July 3, 2017, the D.C. Circuit granted relief for the petitioners, which had the impact of making the previously-stayed rules effective. And on September 12, 2018, EPA proposed revisions to its 2016 methane regulations and sought comment on additional areas for possible revision as part of its previously noted reconsideration of those rules. While EPA continues to reconsider aspects of the methane rule, it will remain effective.  These new and revised regulations, or the adoption of any other laws or regulations restricting or reducing these emissions, will increase our operating costs.

Another regulatory development that may impact our operations is EPA’s notice of finding and determination that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment.  In response to that finding, EPA has implemented GHG-related reporting, monitoring, and recordkeeping rules for petroleum and natural gas systems, among other industries, and developed a Climate Action Plan, including a Methane Strategy which formed the basis for methane regulations issued in June 2016. However, the Executive Office report calling for the Climate Action Plan and Methane Strategy was rescinded by President Donald Trump by Executive Order 13,783, and the June 2016 methane regulations, though currently effective, are the subject of proposed and possible further reconsideration and revision, as noted above. EPA has also solicited comment on a proposed two-year stay of those methane rules. Those methane regulations remain in effect until possible revision or repeal by separate EPA rulemaking in the future, which action is also likely to be challenged in the courts. While the U.S. Congress has considered, and may in the future again consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and could require major sources of GHG emissions to obtain GHG emission “allowances” to continue their operations, the current administration’s decision to withdraw from the Paris Climate accords, announced on June 1, 2017, among other factors, makes passage of such legislation less likely in the near term.  Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would be likely to increase our operating costs and could also have an adverse effect on demand for our production.

Waste Disposal.   We currently own or lease a number of properties that have been used for production of oil and natural gas for many years. Although we believe the prior owners and/or operators of those properties generally utilized operating and disposal practices that met applicable standards in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we currently own or lease. State and federal laws applicable to oil and natural gas wastes have become more stringent over time. Under new and existing laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial well-plugging operations to prevent future, or mitigate existing, contamination.

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We may generate wastes, including “solid” wastes and “hazardous” wastes that are subject to the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes, although certain oil and natural gas exploration and production (“E&P”) wastes currently are excluded from regulation as hazardous wastes under RCRA. On May 4, 2016, several environmental groups filed a declaratory judgment action in federal district court for the District of Columbia seeking to compel the EPA to review the exemption of E&P wastes under RCRA. The groups had previously filed a Notice of Intent (“NOI”) to Sue EPA in August 2015 for failure to act on a 2010 petition to review the E&P RCRA exemption. In late December 2016, EPA entered into a consent decree with the environmental groups and agreed to reconsider the Agency’s current treatment of E&P wastes. The District Court approved the consent decree, binding EPA to a court-imposed timeline for determining how oil and gas wastes should be regulated under RCRA. In April 2019, EPA concluded that it would not revise federal regulations on E&P waste management under the RCPA at this time. This decision received criticism from environmental groups and both the federal government and state governments will likely continue to receive pressure to further regulate E&P waste. If E&P waste becomes regulated as hazardous waste, then generators, transporters, and owners/operators of disposal and treatment facilities will be subject to RCRA regulations at significant increased cost. Thus, it is possible that certain wastes generated by our oil and natural gas operations that currently are excluded from regulation as hazardous wastes may in the future be designated as hazardous wastes, and may therefore become subject to more rigorous and costly management, disposal and clean-up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both onshore and offshore.

Superfund. Under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, also known as CERCLA or the Superfund law, and similar state laws, responsibility for the entire cost of cleaning up a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators and any party who releases or threatens to release one or more designated “hazardous substances” at the site, regardless of whether the original activities that led to the contamination were lawful at the time of disposal. This is known as strict liability, meaning liability without fault. CERCLA also authorizes EPA and, in some cases, third parties, to take actions in response to releases of hazardous substances into the environment and to seek to recover from the potentially responsible parties the costs of such response actions. Although CERCLA generally excludes petroleum from the definition of hazardous substances, in the course of our operations we may have generated and may generate other wastes that fall within CERCLA’s definition of hazardous substances. We also may be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be subject to joint and several liability as well as strict liability under CERCLA for all or part of the costs of cleaning up facilities at which such substances have been released and for natural resource damages. Joint and several liability is liability that may be apportioned either among two or more parties or to only one or a few select members of a group, making each party individually responsible for the entire obligation. In some situations, we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of third parties at, or prior operators of, properties we have acquired. This includes, in some circumstances, operators of properties in which we have an interest and parties that provide transportation services for us. If exposed to joint and several liability, we could be responsible for more than our share of costs for remediating a particular site, and potentially for the entire obligation, even where other parties were involved in the activity giving rise to the liability. We have not, to our knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.

BLM Venting and Flaring Proposed Rule. On January 22, 2016 the Department of Interior’s Bureau of Land Management (BLM) released a proposed BLM Waste Prevention, Production Subject to Royalties, and Resource Conservation proposed rule. Comment on the proposed rule closed on April 22, 2016, and BLM issued its final rule on November 18, 2016. Petitions for judicial review of the rule were filed by industry groups and, as a result, BLM postponed compliance dates for certain sections of the rule pending judicial review. The 2016 rule was designed to replace the BLM's notice to lessees, NTL-4A, on venting and flaring at oil and gas facilities producing on federal and tribal lands by dealing with provisions related to venting and flaring of oil and natural gas, leak detection, storage tanks, pneumatic controllers and pumps, well maintenance and unloading, drilling and completions, and royalties. On September 18, 2018, however, the BLM substantially revised its 2016 Waste Prevention Rule, which had also been the subject of multiple court challenges but had become effective at certain points in the interim due to various court rulings. The 2018 rule essentially reverts the agency’s regulation of venting and flaring to what existed before the 2016 Waste Prevention Rule was promulgated.

Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations

Significant potential costs relating to environmental and land-use regulations associated with our existing properties and operations include those relating to: (i) plugging and abandonment of facilities; (ii) clean-up costs and damages due to spills or other releases; and (iii) penalties imposed for spills, releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, obligations relating to plugging and abandonment, clean-up and other environmental costs in connection with our acquisition of operating interests in fields, and these costs can be significant.

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Plugging and Abandonment Costs

Our operations are subject to stringent abandonment and closure requirements imposed by the various regulatory bodies including the BLM and State agencies.

As described in our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $3.6 million as of June 30, 2019. This figure reflects the expected future costs associated with site reclamation, facilities dismantlement and plugging and abandonment of wells. The discount rates used to calculate the present value varied depending on the estimated timing of the obligation, but typically ranged between 4% and 13 %. Actual costs may differ from our estimates. Our financial statements do not reflect any liabilities relating to other environmental obligations.

Competition

The oil and natural gas business is highly competitive in the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. The principal competitive factors in the acquisition of undeveloped oil and gas leases include the availability and quality of staff and data necessary to identify, investigate and purchase such leases, and the financial resources necessary to acquire and develop such leases. Many of our competitors have substantially greater financial resources, and more fully developed staffs and facilities than ours. In addition, the producing, processing and marketing of natural gas and crude oil are affected by a number of factors that are beyond our control, the effect of which cannot be accurately predicted. See “Item 1A. Risk Factors.” Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.

Employees

At October 15, 2019, we had 5 full-time employees in Denver, Colorado, U.S.

Available Information

We are subject to the informational requirements of the Securities Exchange Act of 1934 (the “Exchange Act”).  We therefore file periodic reports, proxy statements and other information with the Securities and Exchange Commission (the “SEC”). Such reports may be obtained by visiting the Public Reference Room of the SEC at 100 F Street, NE, Washington, D.C. 20549, or by calling the SEC at 800-SEC-0330.  In addition, the SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information.

Financial and other information can also be accessed on the investor section of our website at www.samsonoilandgas.com.  We make available, free of charge, copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Information on our website is not incorporated into this Form 10-K or our other securities filings and is not a part of them.

Item 1A. Risk Factors

 Our business, operating or financial condition could be harmed due to any of the following risk factors.  Accordingly, investors should carefully consider these risks in making a decision as to whether to purchase, sell or hold our securities.  In addition, investors should note that the risks described below are not the only risks facing the Company.  Additional risks not presently known to us, or risks that do not seem significant today, may also impair our business operations in the future. When determining whether to invest in our securities, you should also refer to the other information contained in this Annual Report on Form 10-K, including our consolidated financial statements and the related notes, and in our other filings with the SEC.  As an Australian company, the rights of our shareholders may differ from the rights typically offered to shareholders of a company incorporated in the United States.

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Risks Related to Our Business, Operations and Industry

We are in breach of our Credit Agreement and the terms governing our indebtedness may limit our ability to execute capital spending or to respond to other initiatives or opportunities as they may arise.

As of the filing of this Form 10-K, we are in breach of several of our financial covenants under the Credit Agreement. Due to our breach of certain financial covenants under the Credit Agreement, the Lender may declare all amounts and obligations of the Company due and payable immediately. We are currently negotiating a waiver from our Lender for this breach. As of the filing of this Form 10-K, we have not received a waiver, and, as such, we have classified the total amount of outstanding debt of $33.5 million as a current liability and we expensed $1.4 million of deferred loan fees that were recorded as a debt discount. If we do not succeed in renegotiating the Credit Agreement or acquire sufficient funds to repay the Lender, the Lender could declare an event of default and foreclose on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses. In any of these scenarios we may be forced to cease operations or seek bankruptcy protection, in which event our shareholders could lose their entire investment.

Even if we are successful in renegotiating our Credit Agreement, it is unlikely that we would obtain substantially better terms than under the existing Credit Agreement. Under the terms of our Credit Agreement, we are subject to very stringent financial covenants and obligations. Any decline in cash flow from our oil and natural gas reserves, if continued for any extended period, would very likely result in us having to make mandatory payments to pay down amounts owed to a level that is in compliance with the Credit Agreement. A required repayment of the Credit Agreement could be significant. Additionally, the terms of the Credit Agreement restrict our ability to incur additional debt, which limits our ability to obtain additional funding.

The Credit Agreement contains covenants and other restrictions that are highly unfavorable to us, including those customary for oil and gas credit facilities, such as limitations on debt, liens, dividends, voluntary redemptions of debt, investments, and asset sales. The Credit Agreement requires us to maintain compliance with certain financial tests and financial covenants. If future debt financing is not available to us when required as a result of limited access to the credit markets or otherwise, or is not available on acceptable terms, we may be unable to invest needed capital for our continuing drilling and exploration activities, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt. In addition, we may be forced to sell some of our assets on an untimely basis or under unfavorable terms. Any of these results could have a material adverse effect on our operating results and financial condition.

We are subject to a pending administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC”), which could result in us having to pay a substantial fee.

On September 4, 2019, the Company received an administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC). The notice makes claim to the status of certain shut-in wells and other location items operated by Samson. Samson submitted its formal response in September 2019 and has met with the NDIC concerning this matter and has presented the Company’s plan to address the administrative action. No final resolution or settlement has been entered into as of the filing of this report and the Company cannot reasonably estimate the amount of any potential penalties or fees that may be assessed against the Company. Any amount assessed against the Company is likely to be significant and, once assessed, could cause the Lender to declare an event of default and foreclose on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses. In any of these scenarios we may be forced to cease operations or seek bankruptcy protection, in which event our shareholders could lose their entire investment.

Our Credit Agreement is subject to variable rates of interest which could negatively impact us.

Borrowings under our Credit Agreement are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and the Company’s income and cash flows would decrease.

Our auditors and management have expressed substantial doubt about our ability to continue as a going concern.

As disclosed in the financial statements, we incurred a net loss of $7.2 million for the year ended June 30, 2019. As of that date, our total current liabilities of $43.3 million exceed our total current assets of $4.8 million. Additionally, we are in violation of our debt covenant and have suffered recurring losses from operations. We believe these circumstances raise substantial doubt about our ability to continue as a going concern.

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If we are not able to generate the funds needed to cover our ongoing expenses, then we may be forced to cease operations or seek bankruptcy protection, in which event our shareholders could lose their entire investment.

Declines in oil or gas prices have and will materially adversely affect our Revenues.

Our financial condition and results of operations depend in large part upon the prices of oil and natural gas and the costs of finding, acquiring, developing and producing reserves. As seen in recent years, prices for oil and natural gas are subject to extreme fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide political instability (especially in the Middle East and other oil producing regions), the foreign supply of oil and gas, the price of foreign imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels, speculating activities in the commodities markets, and the overall economic environment. Our operations are substantially adversely impacted as oil prices decline. Lower prices dramatically affect revenues from drilling operations. Drilling of new wells, development of leases and acquisitions of new properties are also adversely affected and limited. As a result, our potential revenues from operations as well as the proved reserves may substantially decrease from levels achieved during periods when oil prices were much higher. There can be no assurances as to the future prices of oil or gas. A substantial or extended decline in oil or gas prices would have a material adverse effect on our financial position, results of operations, quantities of oil and gas that may be economically produced, and access to capital. Oil and natural gas prices have historically been and are likely to continue to be volatile.

This volatility makes it difficult to estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration and development projects involving our oil and gas properties. In addition, unusually volatile prices often disrupt the market for oil and gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties.

Our ongoing infill development drilling program is critical to our future success

We have embarked on an infill development drilling program at the Gonzales location in the Home Run Field. The drilling program is designed to drill two horizontal laterals from the existing well bore. The existing development consists of a single 5,300 ft. lateral drilled with a single 640-acre spacing unit. The two new well bores will be directionally drilled to access the balance of the 640-acre spacing unit. The ability to drill out of an existing wellbore made the economics of these developmental wells more attractive due to the ability to use existing surface facilities associated with the existing well. While we believe that these two lateral wells are likely to be completed and achieve commercial levels of production, oil drilling of any kind carries numerous risks and uncertainties that cannot be disregarded.

We plan to drill a total of 8 similar lateral wells to the Gonzales wells within the next 12 months. We have identified a total of 26 Contingent resource locations for future drilling. While we believe that our recent refinancing will provide sufficient working capital to initiate the development drilling program, our ability to drill subsequent wells will depend upon the success of our earlier developmental drilling and the additional capital available to us as a result of that success. There can be no assurance that the earlier developmental drilling will achieve the success needed to complete the entire planned drilling program. Additionally, if the lender declares an event of default due to our current violations of the Credit Agreement and forecloses on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses, we may be forced to cease our drilling program and/or sell our Gonzales location. If we cease our drilling program, we may be forced to cease all operations or seek bankruptcy protection, in which event our shareholders could lose their entire investment.

Reserve estimates are imprecise and subject to revision.

Estimates of oil and natural gas reserves are projections based on available geologic, geophysical, production and engineering data. There are uncertainties inherent in the manner of producing, and the interpretation of, this data as well as in the projection of future rates of production and the timing of development expenditures. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of factors including:

· the quality and quantity of available data;

· the interpretation of that data;

· our ability to access the capital required to develop proved undeveloped locations;

· the accuracy of various mandated economic assumptions; and

· the judgment of the engineers preparing the estimate.

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Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves will likely vary from our estimates. Any significant variance could materially affect the quantities and value of our reserves. Our reserves may also be susceptible to drainage by operators on adjacent properties. We are required to adjust our estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices.   These reserve reports are necessarily imprecise and may significantly vary depending on the judgment of the reservoir engineering consulting firm.

Investors should not construe the present value of future net cash flows as the current market value of the estimated oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate, in accordance with applicable regulations, even though actual future prices and costs may be materially higher or lower. As a result of significant recent declines in commodity prices, such average sales prices are significantly in excess of more recent prices. Unless commodity prices or reserves increase, the estimated discounted future net cash flows from our proved reserves would generally be expected to decrease as additional months with lower commodity sales prices will be included in this calculation in the future. Factors that will affect actual future net cash flows include:

· the amount and timing of actual production;

· the price for which that oil and gas production can be sold;

· supply and demand for oil and natural gas;

· curtailments or increases in consumption by natural gas and oil purchasers; and

· changes in government regulations or taxation.

As a result of these and other factors, we will be required to periodically reassess the amount of our reserves, which reassessment may require us to recognize a write–down of our oil and gas properties, as occurred at June 30, 2016 and June 30, 2015. We have not recorded any write downs of our oil and gas properties for the years ended June 30, 2019 and 2018.

Additionally, in recent years, there has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. The interpretation of SEC rules regarding the classification of reserves and their applicability in different situations remain unclear in many respects. Changing interpretations of the classification standards of reserves or disagreements with our interpretations could cause us to write-down reserves.

Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations.

Producing oil and reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we estimated. The rate can change due to other circumstances as well. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production, profitability and reserves.

Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil and natural gas reserves. To date, we have financed capital expenditures primarily with cash generated by operations, capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including:

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● our proved reserves;

● the amount of crude oil and natural gas we are able to produce from existing wells;

● our ability to acquire, locate and produce new reserves;

● the prices at which crude oil and natural gas are sold; and

● the costs to produce crude oil and natural gas.

If our revenues decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources would increase. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. Our Credit Agreement restricts our ability to incur additional debt. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability. We have, in the past, funded a portion of our capital expenditures with proceeds from the sale of our properties, such as the sale of a portion of the North Stockyard properties to Slawson Exploration Company in August 2013. More recent sales of properties have been used to repay debt or provide working capital.

Petroleum exploration, drilling and development involve substantial business risks.

The business of exploring for and developing oil and gas properties involves a high degree of business and financial risk, and thus a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. In addition, oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

● unexpected drilling conditions;

● unexpected geological formations including abnormal pressure or irregularities in formations;

● equipment failures or accidents;

● adverse changes in prices;

● weather conditions;

● ability to fund capital necessary to develop exploration properties and producing properties;

● shortages in experienced labor; and

● shortages or delays in the delivery of equipment, including equipment needed for drilling, fracture stimulating and completing wells.

Acquisition and completion decisions generally are based on subjective judgments and assumptions that are speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational, or market–related factors, including, but not limited to, unusual or unexpected geological formations, pressures, equipment failures or accidents, fires, explosions, blowouts, cratering, pollution and other environmental risks, shortages or delays in the viability of drilling rigs and the delivery of equipment, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable. A productive well may become uneconomic if water or other substances are encountered that impair or prevent the production of oil or natural gas from the well.

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If our access to markets for our oil and gas production is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell oil and natural gas and receive market prices for our oil and natural gas may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the unavailability of satisfactory transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production. We currently own an interest in several wells that are capable of producing but may have their production curtailed from time to time at some point in the future pending gas sales contract negotiations, as well as construction of gas gathering systems, pipelines, and processing facilities.

A significant portion of our producing properties are located in geographic areas that are vulnerable to extreme seasonal weather, as well as additional environmental regulation and production constraints.

A significant portion of our operating properties are located in the Rocky Mountain region.  As a result, the success of our operations and our profitability may be disproportionately exposed to the impact of adverse conditions unique to that region. Such conditions can include extreme seasonal weather, which could limit our ability to access our properties or otherwise delay or curtail our operations.  Also, there could be delays or interruptions of production from existing or planned new wells by significant governmental regulation, transportation capacity constraints, curtailment of production, interruption of transportation, or fluctuations in prices of oil and natural gas produced from the wells in the region.

In addition, some of the properties that we may develop for production are located on federal lands where drilling and other related activities cannot be conducted during certain times of the year due to environmental considerations. This could adversely affect our ability to operate in those areas and may intensify competition during certain times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs, particularly if our exploration or development activities on federal lands, or our production from federal lands increases.

Our business involves significant operating risks that could adversely affect our production and could be expensive to remedy. We do not have insurance to cover all of the risks that we may face.

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including:

● well blowouts;

● cratering and explosions;

● pipe failures and ruptures;

● pipeline accidents and failures;

● casing collapses;

● fires;

● mechanical and operational problems that affect production;

● formations with abnormal pressures;

● uncontrollable flows of oil, natural gas, brine or well fluids;

● releases of contaminants into the environment; and

● failure of subcontractors to perform or supply goods or services or personnel shortages.

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These industry operating risks can result in injury or loss of life, severe damage to or destruction of property, damage to natural resources and equipment, pollution or other environmental damage, clean–up responsibilities, regulatory investigation and penalties, and suspension of operations, any of which could result in substantial losses. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed. We may also be subject to damage claims by other oil and gas companies.

We do not maintain insurance in amounts that cover all of the losses to which we may be subject, and some risks, such as pollution and environmental risks, are not generally fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses, and we do not have access to insurance coverage or rights to indemnity for all risks. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could adversely affect our financial position and results of operations.

Other business risks also include the risk of cyber security breaches. If management’s systems for protecting against cyber security risk prove not to be sufficient, the company could be adversely affected such as by having its business systems compromised, its proprietary information altered, lost or stolen, or its business operations disrupted.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is highly competitive, and we compete with other companies that are significantly larger and have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay higher prices for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these competitors may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We may not be able to keep pace with technological developments in our industry.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

We are subject to complex environmental federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, and production operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and reclaim oil and natural gas wells and related production facilities. Under these laws and regulations, we also could be held liable for personal injuries, property damage, clean-up costs, and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

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The environmental laws and regulations to which we are subject:

1.	require applying for and receiving permits before drilling commences;
2.	restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
3.	limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected or sensitive areas; and
4.	impose substantial liabilities for unpermitted releases and emissions resulting from our operations.

If any of our operations require federal permits or otherwise involve a “major federal action” that significantly impacts the environment, we may be required to prepare an environmental impact statement (“EIS”) pursuant to the National Environmental Policy Act to obtain the federal permits necessary to proceed with the development of certain oil and gas properties. There can be no assurance that we will obtain all necessary permits and, if obtained, that the costs associated with completing the EIS and obtaining such permits will not exceed those that previously had been estimated. It is possible that the costs and delays associated with compliance with such requirements could cause us to delay or abandon the further development of certain properties.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, emission controls, storage, transportation, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our earnings, results of operations, competitive position or financial condition. For example, because of its potential effect on ground water, seismic activity, and local communities, hydraulic fracturing and associated water disposal currently are the subject of regulatory scrutiny, negative press, and proposed legislative changes, particularly at the state and local level. Hydraulic fracturing is a process that creates a fracture extending from a well bore into a low-permeability rock formation to enable oil or natural gas to move more easily to a production well. Hydraulic fractures typically are created through the injection of water, sand and chemicals into the rock formation. Legislative and regulatory efforts to further regulate this process may render permitting and compliance requirements more stringent for hydraulic fracturing, which may limit or prohibit use of the process. While none of our properties are expected to be subject to any such changes, there is no assurance that this will remain the case.

President Donald Trump’s election and inauguration in January 2017 has resulted in uncertainty with respect to the future environmental regulation of the oil and natural gas industry. This uncertainty may affect how the oil and gas industry is regulated, and could also increase the level of public interest in environmental protection and safety concerns and may result in new or different pressures being exerted. For example, President Donald Trump issued Executive Order 13,783 (March 28, 2017) entitled “Promoting Energy Independence and Economic Growth.” The stated goal is to “suspend, revise, or rescind [regulations] that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest.” This Executive Order identified a number of Obama-era Clean Air Act and Clean Water Act regulations for reconsideration by the EPA. Public interest groups may increase their use of litigation as a means to require more stringent regulation of the oil and natural gas industry. As noted, there may be heightened litigation regarding any revision or rescission of these rules, resulting in uncertainty for the regulated community.

Over the years, we have owned or leased numerous properties for oil and gas activities upon which petroleum hydrocarbons or other materials may have been released by us or predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including CERCLA, RCRA and analogous state laws, we could be held strictly liable for the removal or remediation of any such previously released contaminants at such locations, in some cases regardless of whether we were responsible for the release or whether the operations were compliant with applicable regulations or standard practice within the industry at the time they were performed.

Our operations also are subject to wildlife-protection laws and regulations such as the Migratory Bird Treaty Act (MBTA). For example, some oil companies have been charged under the MBTA with killing migratory birds that have died in reserve pits in North Dakota, where we conduct operations. Reserve pits are used during oil and gas drilling operations and can pose an attractive nuisance to migratory birds. During the cleanup phase of a reserve pit, North Dakota requires companies to cover the pit with a net if it is open for more than 90 days to reduce the risk of bird mortality.

The federal Clean Water Act and analogous state laws impose strict controls against the unpermitted discharge of pollutants and fill material, including spills and leaks of crude oil and other substances from our operations. The Clean Water Act also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The Clean Water Act also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") plan requirements of the Clean Water Act dictate use of appropriate secondary containment loadout controls, piping controls, berms, and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture, or leak, and that these measures be included in a written SPCC plan that is updated periodically.

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The BLM had issued a final rule regulating hydraulic fracturing in 2015 (the “HF Rule”), and though never effective due to numerous court challenges, the HF Rule was rescinded by final rule of BLM published in the Federal Register December 28, 2017. That rescission was effected as part of President Trump’s goal to reduce the burden of federal regulations that hinder economic growth and energy development, and Department of Interior Secretarial Order No. 3349, “Promoting Energy Independence and Economic Growth.”

Additionally, BLM also published a final rule on September 18, 2018, substantially revising its 2016 Waste Prevention Rule, which was also the subject of multiple court challenges, and had become effective at certain points in the interim due to various court rulings. The final rule essentially reverts the agency’s regulation of venting and flaring to what existed before the 2016 Waste Prevention Rule was promulgated.

Despite the noted BLM rescissions and revisions of prior hydraulic fracturing regulations at the federal level, EPA in 2014 and 2017 issued technical permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel fuels are used which guidance remains the agency’s current policy. Although Samson does not use diesel fuel in its hydraulic fracturing activities, continued EPA adherence to this guidance may create duplicative federal and state requirements in certain jurisdictions where Samson operates.

In April 2012, EPA issued regulations specifically applicable to the oil and gas industry that among other things, requires operators to capture 95 percent of the VOC emissions from natural gas wells that are hydraulically fractured. The reduction in VOC emissions is accomplished primarily through the use of “reduced emissions completion” methods to capture natural gas that would otherwise escape into the air or be combusted. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, valves and connectors. In June 2016, EPA issued additional regulations specific to the oil and gas industry adding methane standards for equipment and processes covered by the 2012 regulations.  The 2016 final regulations also add leak detection and repair (LDAR) requirements for equipment such as valves, connectors, pressure relief valves, open-ended lines, access doors, flanges, crank case vents, pump seals or diaphragms, closed vent systems, compressors, separators, dehydrators, thief hatches on storage tanks, and sweetening units at gas processing plants. On April 19, 2017, EPA announced its intent to administratively reconsider the methane rules, staying a June 3, 2017 effective date for certain provisions—such as the LDAR provisions—for 90 days. Environmental groups filed a petition to stop the administrative stay in the D.C. Circuit, and on July 3, 2017, the D.C. Circuit granted relief for the petitioners, which had the impact of making the previously-stayed rules effective. And on September 12, 2018, EPA proposed revisions to its 2016 methane regulations and sought comment on additional areas for possible revision as part of its previously noted reconsideration of those rules. While EPA continues to reconsider aspects of the methane rule, it will remain effective.  These new and revised regulations, or the adoption of any other laws or regulations restricting or reducing these emissions, will increase our operating costs.

Another regulatory development that may impact our operations is EPA’s notice of finding and determination that emissions of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment.  In response to that finding, EPA has implemented GHG-related reporting, monitoring, and recordkeeping rules for petroleum and natural gas systems, among other industries, and developed a Climate Action Plan, including a Methane Strategy which formed the basis for methane regulations issued in June 2016. However, the Executive Office report calling for the Climate Action Plan and Methane Strategy was rescinded by President Trump by Executive Order 13,783, and the June 2016 methane regulations, though currently effective, are the subject of proposed and possible further reconsideration and revision, as noted above. EPA has also solicited comment on a proposed two-year stay of those methane rules. Those methane regulations remain in effect until possible revision or repeal by separate EPA rulemaking in the future, which action is also likely to be challenged in the courts. While the U.S. Congress has considered, and may in the future again consider, “cap and trade” legislation that would establish an economy-wide cap on emissions of GHGs in the United States and could require major sources of GHG emissions to obtain GHG emission “allowances” to continue their operations, the current administration’s decision to withdraw from the Paris Climate accords, announced on June 1, 2017, among other factors, makes passage of such legislation less likely in the near term.  Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would be likely to increase our operating costs and could also have an adverse effect on demand for our production.

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Finally, another federal regulation affecting hydraulic fracturing activities is the Occupational Safety and Health Administration’s (OSHA) final rule on Occupational Exposure to Respirable Crystalline Silica, which includes specific requirements applicable to hydraulic fracturing operations in the oil and gas industry published on March 25, 2016. Hydraulic fracturing operations in the oil and gas industry are regulated under OSHA’s “general industry” regulations. The final silica rule establishes a new permissible exposure limit (PEL) of 50 micrograms of respirable crystalline silica per cubic meter of air (50 µg/m3) as an 8-hour, time-weighted average in all industries covered by the rule. The rule also includes other employee-protection provisions, such as requirements for exposure assessment, methods for controlling exposure, respiratory protection, medical surveillance, hazard communication, and recordkeeping. Implementation of this rule could increase operating costs. The final rule took effect on June 23, 2016, after which industries have one to five years to comply with most requirements.

We depend on key members of our management team.

The loss of key members of our management team could reduce our competitiveness and prospects for future success. We do not have any “key man” insurance policies for our Chief Executive Officer; or any other executive. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced management professionals. Competition for these professionals is extremely intense. 

Instability in the global financial system may have impacts on our liquidity and financial condition that we currently cannot predict.

Instability in the global financial system may have a material impact on our liquidity and our financial condition. We previously relied upon access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash flow from operations or other sources. Our ability to access the capital markets or borrow money may be restricted or made more expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions, including with respect to commodity prices such as for oil and gas, could have an impact on our oil and gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, challenges in the economy have led and could further lead to reductions in the demand for oil and gas, or further reductions in the prices of oil and gas, or both, which could have a negative impact on our financial position, results of operations and cash flows.

Failure to adequately protect critical data and technology systems could materially affect our operations.

Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows.

Risks Related to Our Securities

Currency fluctuations may adversely affect the price of our American Depository Shares (“ADSs”) relative to the price of our ordinary shares.

The price of our ordinary shares is quoted in Australian dollars and the price of our ADSs is quoted in U.S. dollars.  Movements in the Australian dollar/U.S. dollar exchange rate may adversely affect the U.S. dollar price of our ADSs and the U.S. dollar equivalent of the price of our ordinary shares. During the year ended June 30, 2019, the Australian dollar has, as a general trend, maintained its value against the U.S. dollar, but remains volatile. As the Australian dollar weakens against the U.S. dollar, the U.S. dollar price of the ADSs could decline correspondingly, even if the price of our ordinary shares in Australian dollars increases or remains unchanged. In the unlikely event that dividends are payable, we will likely calculate and pay any cash dividends in Australian dollars and, as a result, exchange rate movements will affect the U.S. dollar amount of any dividends holders of our ADSs will receive from The Bank of New York Mellon, our depositary. While we would ordinarily expect such variances to be adjusted by inter-market arbitrage activity that accounts for the differences in currency values, there can be no assurance that such activity will in fact be an efficient offset to this risk.

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The prices of our ordinary shares and ADSs have been and will likely continue to be volatile.

Trading in our ordinary shares is currently suspended on the ASX. The trading prices of our ordinary shares on the ASX and of our ADSs on the OTCQB have been volatile and will likely to continue to be volatile (in the case of our ordinary shares, assuming the resumption of trading on the ASX).  Other natural resource companies have experienced similar volatility for their shares, leading us to expect that the results of exploration activities, the price of oil and natural gas, future operating results, market conditions for natural resource shares in general, and other factors beyond our control, could have a significant adverse or positive impact on the market price of our ordinary shares and ADSs. We also believe that this volatility creates opportunities for arbitrage trading between the ASX and OTCQB markets.  While we recognize that arbitrage trading is an appropriate market mechanism to eliminate the differences between different trading markets resulting from the combination of volatile stock prices and inter-market inefficiencies, some of our shareholders may not be in a position to take advantage of the potential profits available to arbitrageurs in such cases.

Our ADSs may be deemed a “penny stock,” which makes it more difficult for our investors to sell their shares.

As a result of our delisting from the NYSE American our ADSs may now be subject to the “penny stock” rules adopted under Section 15(g) of the Exchange Act. The penny stock rules generally apply to companies whose common stock is not listed on a national securities exchange and trades at less than $5.00 per share, other than companies that have had average revenue of at least $6,000,000 for the last three years or that have net tangible assets worth of at least $2,000,000 if the company has been operating for three or more years. These rules require, among other things, that brokers who trade penny stock to persons other than “established customers” complete certain documentation, make suitability inquiries of investors and provide investors with certain information concerning trading in the security, including a risk disclosure document and quote information under certain circumstances. Many brokers have decided not to trade penny stocks because of the requirements of the penny stock rules and, as a result, the number of broker-dealers willing to act as market makers in such securities is limited. If we remain subject to the penny stock rules for any significant period, it could have an adverse effect on the market, if any, for our securities. If our securities are subject to the penny stock rules, investors will find it more difficult to dispose of our securities. If we identify a viable buyer and sell Foreman Butte Project, we will likely have net tangible assets in excess of $2,000,000 and would therefore no longer be subject to the penny stock rules.

We may issue shares of blank check preferred stock in the future that may adversely impact rights of holders of our ordinary shares and ADSs.

Our corporate constitution authorizes us to issue an unlimited amount of “blank check” preferred stock.  Accordingly, our board of directors will have the authority to fix and determine the relative rights and preferences of preferred shares, as well as the authority to issue such shares, without further shareholder approval.  As a result, our board of directors could authorize the issuance of a series of preferred stock that would grant to holders preferred rights to our assets upon liquidation, the right to receive dividends before dividends are declared to holders of our common stock, and the right to the redemption of such preferred shares, together with a premium, prior to the redemption of the common stock.  To the extent that we do issue such additional shares of preferred stock, the rights of ordinary share and ADS holders could be impaired thereby, including, without limitation, dilution of their ownership interests in us.  In addition, shares of preferred stock could be issued with terms calculated to delay or prevent a change in control or make removal of management more difficult, which may not be in the interest of holders of ordinary shares or ADSs.

Our ADSs are required to trade on the over-the-counter market and therefore selling the ADS could be more difficult.

As our ADSs on the over-the-counter market, selling them may be difficult due to reduced trading volume, transaction delays, and reduced security analyst coverage. In addition, as the ADSs have been delisted from the NYSE American, additional regulatory burdens are imposed upon broker-dealers that may discourage them from effecting transactions in such securities, as discussed in greater detail below, further limiting the liquidity of the ADSs. These factors could result in lower prices and larger spreads in the bid and ask prices for our securities. The delisting from the NYSE American exchange and continued or further declines in our share price could also greatly impair our ability to raise additional necessary capital through equity or debt financing and could significantly increase the ownership dilution to shareholders caused by our issuing equity in financing or other transactions. Any such limitations on our ability to raise debt and equity capital could prevent us from making future investments and satisfying maturing debt commitments.

We report as a U.S. domestic issuer, which means increased compliance costs notwithstanding continued eligibility for certain NYSE American rule waivers.

On July 1, 2011, we commenced reporting as a U.S. domestic issuer instead of as a “foreign private issuer” as we had in prior years. Accordingly, we are now required to comply with the reporting and other requirements imposed by U.S. securities laws on U.S. domestic issuers, which are more extensive than those applicable to foreign private issuers. We are also required to prepare financial statements in accordance with U.S. GAAP in addition to our financial statements prepared in accordance with IFRS pursuant to ASX requirements. Generating two separate sets of financial statements is a substantial burden that imposes significant administrative and accounting costs on us. As a result of becoming a U.S. domestic issuer, the legal, accounting, regulatory and compliance costs to us under U.S. securities laws are significantly higher than those that were incurred by us as a foreign private issuer.

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We do not expect to pay dividends in the foreseeable future. As a result, holders of our ordinary shares and ADSs must rely on appreciation for any return on their investment.

We do not anticipate paying cash dividends on our ordinary shares in the foreseeable future. Accordingly, holders of our ordinary shares and ADSs will have to rely on capital appreciation, if any, to earn a return on their investment in our ordinary shares.

The trading prices of our ADSs may be adversely affected by short selling.

“Short selling” is the sale of a security that the seller does not own, including a sale that is completed by the seller’s delivery of a “borrowed” security (i.e. the short seller’s promise to deliver the security).   Short sellers make a short sale because they believe that they will be able to buy the stock at a lower price than their sales price. Significant amounts of short selling, or the perception that a significant amount of short sales could occur, could depress the market price of our ADSs.  The price decline could be exacerbated if sufficient “naked short selling” occurs, which is the practice by which short sellers place short sell orders for shares without first borrowing the shares to be sold, or without having first adequately located such shares and arranged for a firm contract to borrow such shares prior to the delivery date set to close the sale.  The result is an artificial deluge into the market of shares for sale – shares that the seller does not own and has not even borrowed.  Although there are regulations in the United States designed to address abusive short selling, the regulations may not be adequately structured or enforced.

We may be deemed to be a passive foreign investment company (a “PFIC”) for U.S. federal income tax purposes.  If we are or we become a PFIC, it could have adverse tax consequences to holders of our ordinary shares or ADSs.

Potential investors in our ordinary shares or ADSs should consider the risk that we could be now, or could in the future become, a PFIC for U.S. federal income tax purposes. We do not believe that we were a PFIC for the taxable year ended June 30, 2018, and do not expect to be a PFIC in the foreseeable future. However, the tests for determining PFIC status depend upon a number of factors, some of which are beyond our control and subject to uncertainties, and accordingly we cannot be certain of our PFIC status for the current, or any other, taxable year. We do not undertake an obligation to determine our PFIC status, or to advise investors in our securities as to our PFIC status, for any taxable year.

If we were to be a PFIC for any year, holders of our ordinary shares or ADSs who are U.S. persons for U.S. federal income tax purposes (“U.S. holders”) whose holding period for such ordinary shares or ADSs includes part of a year in which we are a PFIC generally will be subject to a special, highly adverse, tax regime imposed on “excess distributions” made by us.  This regime will continue to apply irrespective of whether we are still a PFIC in the year an “excess distribution” is made or received. “Excess distributions” for this purpose would include certain distributions received on our ordinary shares or ADSs.  In addition, gains by a U.S. holder on a sale or other transfer of our ordinary shares or ADSs (including certain transfers that would otherwise be tax-free) would be treated in the same manner as excess distributions.  Under the PFIC rules, excess distributions (including gains treated as excess distributions) would be allocated ratably to each day in the U.S. holder’s holding period of the ordinary shares or ADSs with respect to which the excess distribution is made or received. The portion of any excess distributions allocated to the current year or prior years before the first day of the first taxable year beginning after December 31, 1986, in which we became a PFIC would be includible by the U.S. holder as ordinary income in the current year. The portion of any excess distributions allocated to prior taxable years in which we were a PFIC would be taxed to such U.S. holder at the highest marginal rate applicable to ordinary income for each such year (regardless of the U.S. holder’s actual marginal rate for that year and without reduction by any losses or loss carryforwards), and any such tax owing would be subject to interest charges.  In addition, dividends received from us will not be “qualified dividend income” if we are a PFIC in the year of payment, or were a PFIC in the year preceding the year of payment, and will be subject to taxation at ordinary income rates.

In certain cases, U.S. holders may make elections to mitigate the adverse tax rules that apply to PFICs (the “mark-to-market” and “qualified electing fund” or “QEF” elections), but these elections may also accelerate the recognition of taxable income and could result in the recognition of ordinary income.  We have never received a request from a holder of our ordinary shares or ADSs for the annual information required to make a QEF election and we have not decided whether we would provide such information if such a request were to be received.  Additional adverse tax rules would apply to U.S. holders for any year in which we are a PFIC and own or dispose of shares in another corporation that is itself a PFIC. Special adverse rules that impact certain estate planning goals could apply to our ordinary shares or ADSs if we are a PFIC.

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The market price of our ordinary shares and ADSs could be adversely affected by sales of substantial amounts of shares in the public markets or the issuance of additional shares in the future, including in connection with acquisitions.

Sales of a substantial number of our ordinary shares in the public market, either directly or indirectly as the sale of ADSs, or the perception that such sales may occur, could cause the market price of our ordinary shares (and ADSs) to decline. In addition, the sale of these shares in the public market, or the possibility of such sales, could impair our ability to raise capital through the sale of additional shares or other securities. As of June 30, 2019, subject to meeting the vesting requirements we had outstanding options to purchase an aggregate of approximately 314,500,000 of our ordinary shares granted to certain of our directors, officers and employees. These option holders, subject to compliance with applicable securities laws, are permitted to sell shares they own or acquire upon the exercise of options in the public market. The exercise prices of the options are between A$0.0055 and A$0.07 per share, and the options expire around November 2026. The exercise of such options could have similarly adverse consequences on the trading prices for our shares.

For further details on our outstanding options, see “Note 9 – Share-Based Payments” in the Notes to our Consolidated Financial Statements.

In addition, in the future, we may issue ordinary shares or ADSs including in connection with acquisitions of assets or businesses. If we use our shares for this purpose, the issuances could have a dilutive effect on the market value of our ordinary shares, depending on market conditions at the time of an acquisition, the price we pay, the value of the business or assets acquired, our success in exploiting the properties or integrating the businesses we acquire and other factors.

Our ADS holders are not shareholders and do not have shareholder rights.

The Bank of New York Mellon, as depositary, executes and delivers our ADSs on our behalf. Each ADS is represented by a certificate evidencing a specific number of ADSs. Our ADS holders are not required to be treated as shareholders and do not have the rights of shareholders. The depositary is the holder of the ordinary shares underlying our ADSs. Holders of our ADSs have ADS holder rights. A deposit agreement among us, the depositary and our ADS holders sets out ADS holder rights as well as the rights and obligations of the depositary. New York law governs the deposit agreement and the ADSs.

Our ADS holders do not have the right to receive notices of general meetings or to attend and vote at our general meetings of shareholders. Our practice is to give ADS holders notices of general meetings and to enable them to vote at our general meetings of shareholders, but we are not obligated to continue to do so.  Our ADS holders may instruct the depositary to vote the ordinary shares underlying their ADSs, but only when we ask the depositary to ask for their instructions.  Although our practice is to have the depositary ask for the instructions of ADS holders, we are not obligated to do so, and if we do not, our ADS holders would not be able to exercise their right to vote.  ADS holders can exercise their right to vote the ordinary shares underlying their ADSs by withdrawing the ordinary shares. It is possible, however, that our ADS holders would not know about the meeting enough in advance to withdraw the ordinary shares.

When we do ask the depositary to seek our ADS holders’ instructions, the depositary notifies our ADS holders of the upcoming vote and arranges to deliver our voting materials and form of notice to them. The depositary then tries, as far as practicable, subject to Australian law and the provisions of the depositary agreement, to vote the ordinary shares as our ADS holders instruct. The depositary does not vote or attempt to exercise the right to vote other than in accordance with the instructions of the ADS holders. We cannot assure our ADS holders that they will receive the voting materials in time to ensure that they can instruct the depositary to vote their shares. In addition, there may be other circumstances in which our ADS holders may not be able to exercise voting rights.

Similarly, while our ADS holders would generally receive the same dividends or other distributions as holders of our ordinary shares, their rights are not identical.  Dividends and other distributions payable with respect to our ordinary shares generally will be paid directly to those holders.  By contrast, any dividends or distributions payable with respect to ordinary shares that are held as ADSs will be paid to the depositary, which has agreed to pay to our ADS holders the cash dividends or other distributions it or the custodian receives on shares or other deposited securities, after deducting its fees and expenses. Our ADS holders will receive these distributions in proportion to the number of ordinary shares their ADSs represent. In addition, while it is unlikely, there may be circumstances in which the depositary may not pay to our ADS holders the same amounts distributed by us as a dividend or distribution, such as when it is unlawful or impractical to do so. See the next risk factor below.

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There are circumstances where it may be unlawful or impractical to make distributions to the holders of our ADSs.

Our depositary, The Bank of New York Mellon, has agreed to pay to our ADS holders the cash dividends or other distributions it or the custodian receives on shares or other deposited securities, after deducting its fees and expenses. Our ADS holders will receive these distributions in proportion to the number of ordinary shares their ADSs represent.

In the case of a cash dividend, the depositary will convert any cash dividend or other cash distribution we pay on the ordinary shares into U.S. dollars if it can do so on a reasonable basis and can transfer the U.S. dollars to the United States.  In the unlikely event that it is not possible to convert a cash dividend or distribution into U.S. dollars, then the deposit agreement with the depositary allows the depositary to distribute foreign currency only to those ADS holders to whom it is possible to do so.  There is also a risk that, if a distribution is payable by us in Australian dollars, the depositary may hold some or all of the foreign currency for a short period of time rather than immediately converting it for the account of the ADS holders.   Because the depositary will not invest the foreign currency, will not be liable for any interest on the unpaid distribution or for any fluctuation in the exchange rates during a time when the depositary has not converted the foreign currency, our ADS holders could lose some of the value of the distribution.

The depositary may determine that it is unlawful or impractical to convert foreign currency to U.S. dollars or to make a distribution to ADS holders that is made to the holders of ordinary shares. This means that, under rare circumstances, our ADS holders may not receive the same distributions we make to the holders of our ordinary shares or receive the same value for their ADSs if it is illegal or impractical for us to or the depositary to do so.

There may be difficulty in effecting service of legal process and enforcing judgments against us and our directors and management.

We are a public company limited by shares, registered and operating under the Australian Corporations Act 2001. Two of our four directors reside outside the United States. Substantially all of the assets of those persons are located outside the U.S. As a result, it may not be possible to effect service on such persons in the U.S. or to enforce, in foreign courts, judgments against such persons obtained in U.S. courts and predicated on the civil liability provisions of the federal securities laws of the U.S. There is doubt as to the enforceability in the Commonwealth of Australia, in original actions or in actions for enforcement of judgments of U.S. courts, of civil liabilities predicated solely upon federal or state securities laws of the U.S., especially in the case of enforcement of judgments of U.S. courts where the defendant has not been properly served in Australia.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Developed Properties

Foreman Butte Project – Williston Basin, North Dakota and Montana

Various working interests

In March 2016, we closed on the acquisition of the Foreman Butte project. This project includes a number of producing and non- producing, operated and non-operated wells in the Ratcliffe and Madison formations in Montana and North Dakota.

This project consists of 131 wells (both operated and non-operated) across a number of fields in Montana and North Dakota. The wells are conventional wells drilled as early as 1980 to as recently as 2010.

In June 2018, we signed a purchase and sale agreement to sell the majority of this project for $40 million, with an effective date of January 1, 2018. The buyer failed to close the transaction and the purchase and sale agreement expired and we were able to keep the $1.0 million non-refundable deposit made to us.

The Home Run Field (aka 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.

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This has been confirmed through the use of a 3-dimensional numerical simulation of the reservoir volume, and the expected production curve for these wells has been developed from the resulting numerical model.

The current reservoir pressure has also been established using a field wide fluid level study, and the initial development wells will be located in areas of demonstrated higher pressure.

Currently we have 26 Ratcliffe Contingent resource locations identified. The second lateral well expected to be drilled will test an undeveloped reservoir in the Mission Canyon Formation of the Mississippian Madison Group. Although we can make no assurances of the results of this drilling, we are optimistic about its prospects. It is possible that this lateral could prove up a new oil field with the potential for many additional well locations (up to 20 vertical wells or 8 drill-out laterals), A 3,500 acre 4-way structural closure has already been mapped from the abundance of existing well control in the area.

In September 2017, we received approval for a water flood pilot project for the Home Run Field utilizing an existing wellbore which is located on the flank of the field and which is non-productive. This well, the Mays 1-20H has been tested and readied for injected water following the approval from the North Dakota Industrial Commission. We commenced injection in October 2017. The water flood is being used to add pressure to the reservoir which we believe 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 are no chemical compatibility issues, in essence the water is being returned to the reservoir from which it originated. The water is currently being trucked to the injector from the existing producing wells.

Exploration / Undeveloped Properties

Hawk Springs Project, Goshen County, Wyoming

37.5% -100% working interest

Bluff 1-11 (25% working interest)

During the year ended June 30, 2014, we drilled the Bluff Prospect to test multiple targets in the Permian and Pennsylvanian sections in a 4-way structural trapping configuration. The Bluff #1-11 well reached a total depth of 8,900 feet after intersecting the pre-Cambrian basement on June 13, 2014. This well failed to produced economic quantities of hydrocarbons.

This well was plugged during the year ended June 30, 2019.

Roosevelt Project, Roosevelt County, Montana

100% Working Interest

Australia II

100% working interest

In December 2011, we drilled Australia II in the Roosevelt Project, our first appraisal (exploratory) well in this project area. This well was drilled to a total measured depth of 14,972 feet with the horizontal lateral remaining within the target zone for the entire lateral length. Oil and gas shows were returned during the drilling of this well and approximately 3,425 barrels of oil were produced. This well was being pumped, and although this well was productive, we did not believe that we would be able to recover our costs associated with drilling it. We expensed $13.1 million of previously capitalized exploration expenditure in the Statement of Operations as deferred exploration expenditure written off, which represents 100% of the costs incurred to June 30, 2012.

This well was plugged during the year ended June 30, 2018.

Rainbow Project, Williams County, North Dakota Mississippian Bakken Formation, Williston Basin

23% -52% working interest

During the year ended June 30, 2013, we acquired, in two tranches, a net 950 acres in two 1,280 acre drilling units located in the Rainbow Project, Williams County, North Dakota. The Rainbow Project is located in Sections 17, 18, 19 and 20 in T158N R99W.

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The acquisition involved an acreage trade by the parties and a future carry of the vendor by us in the initial drilling program on the Rainbow Project. We transferred 160 net acres from our 1,200 acre undeveloped acreage holding in North Stockyard and the vendor will fund its share (between 7.5% and 8.5%) of the North Stockyard initial infill program. We have acquired 950 net acres in the Rainbow Project from the vendor for this acreage trade and have paid $1 million to the vendor, in lieu of a carry as we did not spud a well within the desired time frame. $0.6 million of this payment was made prior to June 30, 2015 with the remaining $0.4 million paid during the year ended June 30, 2016.

In the western drilling unit of the acquired acreage, we hold a 52.21% working interest. In the eastern drilling unit, our interest is 23%.

Our first Rainbow well, Gladys 1-20, drilled by Continental Resources, spud on June 28, 2014 and was drilled to a total depth of 19,994 feet. The well is 1,280 acre lateral (approximately 10,000 feet) in the middle member of the Bakken formation.

There has been no further drilling activity on this lease and 652 acres have expired.

All our properties are encumbered by the Credit Agreement. Due to our breach of certain financial covenants under the Credit Agreement, the Lender may declare all amounts and obligations of the Company due and payable immediately. If we do not succeed in renegotiating the Credit Agreement or acquire sufficient funds to repay the Lender, the Lender could seize our properties.

Item 3. Legal Proceedings

On September 4, 2019, the Company received an administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC). The notice makes claim to the status of certain shut-in wells and other location items operated by Samson. Samson submitted its formal response in September 2019, and has met with the NDIC concerning this matter and has presented the Company’s plan to address the administrative action. No final resolution or settlement has been entered into as of the filing of this report and the Company cannot reasonably estimate the amount of any potential penalties or fees that may be assessed against the Company at June 30, 2019, therefore, no accrual for potential contingent liabilities have been included in the Company’s financial statements. Any amount assessed against the Company, however, is likely to be significant and, once assessed, could cause the Lender to declare an event of default and foreclose on some or all of our assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

A.  Market Information – 

Our American Depositary Shares (“ADS”), were listed on the NYSE American from January 7, 2008 to November 16, 2017 under the symbol “SSN”. Following our delisting from the NYSE American exchange, we began trading on the OTC QB under the symbol “SSNYY”.  As of October 15, 2019, 10,730,914 ADSs were outstanding and we had approximately 11,396 beneficial owners of ADS.  On March 30, 2015, the ratio of ordinary shares to ADS was changed from 20 to 1, to 200 to 1.

The following table sets forth, for the periods indicated, the highest and lowest market quotations for the ADSs reported on NYSE American or OTCQB as appropriate. On October 15, 2019, the closing price of our ADSs on OTC QB was $

	NYSE American/ OTC QB American Depositary Share (ADS) Price (in USD)
	Fiscal 2019				Fiscal 2018
	High		Low		High		Low
First Quarter (July 1 – September 30)	$	0.28	$	0.10	$	0.50	$	0.33
Second Quarter (October 1 – December 31)	$	0.21	$	0.07	$	0.44	$	0.12
Third Quarter (January 1 – March 31)	$	0.12	$	0.06	$	0.29	$	0.14
Fourth Quarter (April 1 – June 30)	$	0.11	$	0.06	$	0.29	$	0.18

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Our ordinary shares were listed on the Australian Securities Exchange Ltd. (the “ASX”) beginning on April 17, 1980.  As of October 15, 2019, 328,300,044 ordinary shares were outstanding, and we had approximately 328,300,044 shareholders of record.  The following table sets forth, for the periods indicated, the highest and lowest market quotations for the ordinary shares reported on the Daily Official List of the ASX.  Our trading on the ASX was halted on April 12, 2018, and we have requested voluntary suspension of our trading since then. On April 11, 2018, the last day the stock traded on the ASX, the closing price of our ordinary shares on the ASX was A$0.002.

	ASX Ordinary Share Price (in AUD)
	Fiscal 2019				Fiscal 2018
	High		Low		High		Low
First Quarter (July 1 – September 30)	$	N/A	$	N/A	$	.003	$	.001
Second Quarter (October 1 – December 31)	$	N/A	$	N/A	$	.002	$	.001
Third Quarter (January 1 – March 31)	$	N/A	$	N/A	$	.002	$	.001
Fourth Quarter (April 1 – June 30)	$	N/A	$	N/A	$	.002	$	.001

B.  Holders

As of October 15, 2019, there were approximately 3,821 holders of record of our ordinary shares.  Our depositary for the ADSs, The Bank of New York Mellon, constitutes the single record holder of our ADSs and there were approximately 11,396 beneficial holders of our ADS as of October 15, 2019.

C.  Dividends

We have never paid dividends on our ordinary shares and do not anticipate paying any cash dividends on our ordinary shares in the foreseeable future.  Under Australian law, we may not pay a dividend unless our assets exceed our liabilities immediately before the dividend is declared and the excess is sufficient for the payment of the dividend.  Moreover, Australian law requires that the dividend is fair and reasonable to the holders of our ordinary shares and the payment of the dividend does not materially prejudice our ability to pay our creditors.

D.  Securities Authorized for Issuance Under Equity Compensation Plans

Information regarding equity compensation plans under which our equity securities may be issued is included in Item 12 of Part III of this report through incorporation by reference to our definitive Proxy Statement to be filed in connection with our 2019 Annual General Meeting of Shareholders. In the event that our definitive Proxy Statement is not filed on or before October 28, 2019, we will amend this Form 10-K report to add the required information in Part III.

E. Taxation

The taxation discussion set forth below describes the material Australian income tax and U.S. federal income tax consequences of ownership of our ordinary shares or ADSs by a U.S. Holder (as defined below).  This discussion is based on the Australian and U.S. tax laws currently in force at the date of this Annual Report.  The comments do not take into account or anticipate any changes in law (by legislation or judicial decision) or any changes in administrative practice or interpretation by the relevant authorities.  If there is a change, including a change having a retrospective effect, the comments would have to be considered in light of the changes.  This discussion does not address any tax consequences arising under the laws of any state or local jurisdiction, nor of any foreign jurisdictions other than Australia and the United States.

These comments are not exhaustive of all income tax consequences that could apply in all circumstances of any given shareholder or ADS holder.  We recommend that prospective purchasers or holders of our ordinary shares or ADSs consult their own tax advisors regarding the Australian and U.S. federal, state and local tax, and other tax consequences of, purchasing, holding, owning, disposing of or otherwise transferring our ordinary shares and ADSs in their particular circumstances.  Neither the Company nor any officers accept liability or responsibility with respect of such consequences.  Further, special additional rules may apply to particular shareholders, such as insurance companies, superannuation funds and financial institutions.

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Australian Taxation

The following discussion of the Australian taxation implications is based on the provisions of the Income Tax Assessment Act 1936, the Income Tax Assessment Act 1997, International Tax Agreements Act 1953 (IntTAA) which includes the United States Convention as amended by the United States Protocol (USDTA), public taxation rulings and available case law current as of the date of this Annual Report on Form 10-K (all of which are collectively referred to in this section as “Australian Taxation Laws”).  The Australian Taxation Laws and their interpretation are subject to change at any time.

General Principle of Taxation in Australia

This discussion only deals with two items of income that may arise from an investment in the shares or ADSs in us, namely:

· any capital gain made on a sale of the shares or ADSs; and

· any dividends which may be paid by the Company with respect to those shares (or ADSs).  Please note that we have not paid any dividends to date and do not expect to pay any in the near to medium term.

The discussion is relevant only to shareholders or ADS holders that are not residents of Australia for tax purposes and are residents of the U.S. for the purposes of the USDTA (“U.S. Equity Holders”).

Capital Gains on Sale of Shares or ADSs

Under Australian law, income tax is typically not payable on the gain made on the disposal of ordinary shares or ADSs by U.S. Equity Holders unless the profit is of income in nature and sourced in Australia or the sale is subject to tax on any net capital gains, in each case as broadly summarized below.

When the Profit on Sale is Income in Nature

Where a U.S. Equity Holder:

· holds its ordinary shares or ADSs as trading stock or otherwise on revenue account;

· carries on a business in Australia through a permanent establishment or fixed base; and

· holds the ordinary shares or ADSs as part of that business.

any profit on the sale of the ordinary shares or ADSs (as the case may be) would be required to be included in the assessable income of the relevant U.S. Equity Holders and taxed accordingly.

When the Sale is Subject to Capital Gains Tax

A U.S. Equity Holder will be required to include in its assessable income in Australia any “net capital gains” that it makes on “indirect Australian real property interests” (“IARPI”).  Broadly, IARPI will exist where:

· the U.S. Equity Holder and its associates have a 10% or more direct participation interest in us and owned the shareholding at the time of disposal or throughout a 12- month period beginning no earlier than 24 months before the sale of the shareholding, and ending no later than the date of sale of the shareholding; and

· at the time of the sale of the shareholding more than 50% of the market value of our assets are attributable to Australian real property (broadly Australian land and interest in Australian land).

Therefore, unless a U.S. Equity Holder and its associates holds a direct participation interest of at least 10% (as described above), it should not make a taxable capital gain or capital loss for Australian tax purposes with respect to the sale of shares or ADSs, irrespective of the percentage of our assets that constitute Australian real property. There should therefore be no tax payable on any gain on the sale of the shares or ADSs.

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Where a U.S. Equity Holder, with its associates holds;

· a direct participation interest of at least 10% (as described above); and

· at the time of sale less than 50% of the market value of our assets are attributable to Australian real property,

that U.S. Equity Holder will not be subject to Australian tax on any capital gain or loss with respect to the sale of shares or ADSs.

Where a U.S. Equity Holder, with its associates holds;

· a direct participation interest of at least 10% (as described above); and

· at the time of sale more than 50% of the market value of our assets are attributable to Australian real property,

that U.S. Equity Holder will be required to calculate its net capital gains for the relevant income year taking into account the capital gain or capital loss made on the sale of the shares or ADSs.  The net capital gain is then included in the U.S. Holder’s assessable income in Australia and will be taxed accordingly.

A summary of a method for calculating net capital gains is to:

· direct participation interest of at least 10% (as described above); and

· at the time of sale more than 50% of the market value of our assets are attributable to Australian real property,

Dividends

Dividends paid by Samson to U.S. Equity Holders are only subject to the withholding tax provisions of the Australian Taxation Laws.

Australia has an imputation system which allows a company which distributes profits to its members to pass on to its members a credit for the tax already paid by the company to its members.  This is known as a franking credit. The amount of the franking credit attached to the dividend is at the discretion of the paying company but cannot exceed the balance of the company’s franking account (broadly the net of any income tax paid less franking credits attached to previous dividends).  To the extent that the dividend is franked, the dividend is not subject to withholding tax when paid to U.S. Equity Holders.  This means that a fully franked dividend is not subject to any withholding tax.

Any part of a dividend paid to the U.S. Equity Holder which is not franked is subject to dividend withholding tax in Australia.  The withholding tax rates under the USDTA are as follows:

· generally 15% of the gross amount of the dividend, however;

· this is reduced to 5% of the gross amount of the dividend if the U.S. Equity Holder who is beneficially entitled to the dividend is a company which holds at least 10% of the voting power in the company, and

· this is reduced to nil if the U.S. Equity Holder who is beneficially entitled to the dividends is a company who has held shares (or ADSs) which hold a voting power of at least 80% for at least a 12-month period (subject to certain other conditions).

In the case of a U.S. Equity Holder carrying on business in Australia through a permanent establishment or performing independent personal services through a fixed base in Australia with which the holding of shares (or ADSs) is effectively connected, no withholding tax will apply, instead the dividends form part of the normal assessable income subject to tax in Australia under the USDTA.

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A dividend which is unfranked is also exempt from withholding tax to the extent that it consists of certain income from foreign sources (for example dividends from foreign companies in which the shareholder owns at least a 10% interest).  It may be possible to pay such dividends to U.S. Equity Holders without the imposition of withholding tax under the Australian “Conduit Foreign Income” rules.  Essentially conduit foreign income is foreign income received by a non-Australian resident (you) via an Australian corporate tax entity (us).

In the unlikely event we paid a dividend we would provide Equity Holders with notices detailing the extent to which a dividend is franked or unfranked, or represents conduit foreign income, and the deduction, if any, of withholding tax.  If a dividend paid is subject to withholding tax, or would be so but for being franked, no further Australian tax is payable on the dividend.

There are also additional exemptions depending on the nature of the shareholder which are designed to ensure that an entity that is otherwise exempt from tax is not subject to withholding tax, e.g., charitable institutions.

U.S. Taxation

This section describes the material U.S. federal income tax consequences to a U.S. Holder (as defined below) of owning our ordinary shares or ADSs.  This summary addresses only U.S. federal income tax considerations of U.S. Holders (as defined below) that hold our ordinary shares or ADSs as capital assets for U.S. federal income tax purposes.

This summary is based on U.S. tax laws, including the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations promulgated thereunder, rulings, judicial decisions, administrative pronouncements, and the USDTA, all as of the date hereof, and all of which are subject to change or changes in interpretation, possibly with retroactive effect.

For purposes of this section headed “U.S. Taxation,” the term “U.S. Holder” means a beneficial owner of ordinary shares or ADSs who is a U.S. person for U.S. federal income tax purposes, and generally includes:

· a U.S. citizen or an individual who is a resident of the United States for U.S. federal income tax purposes;

· a corporation, or an entity treated as a corporation, created or organized in or under the laws of the United States or any state thereof or the District of Columbia;

· a trust that (i) is subject to (a) the primary supervision of a court within the United States and (b) the authority of one or more United States persons to control all substantial decisions or (ii) has a valid election in effect under applicable Treasury Regulations to be treated as a United States person; or,

· an estate that is subject to U.S. federal income tax on its income regardless of its source.

If a partnership (including for this purpose any entity treated as a partnership for U.S. federal income tax purposes) holds our ordinary shares or ADSs, the U.S. federal income tax treatment of a partner thereof generally will depend on the status of such partner and the activities of the partnership.  If you are a partner in a partnership holding our ordinary shares or ADSs, you should consult your tax advisor(s).

Holders of our ordinary shares or ADSs who are not U.S. Holders should consult with their tax advisor(s) in connection with the U.S. federal, state, local and foreign tax consequences of the matters discussed herein.

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This discussion does not address all aspects of U.S. federal income taxation that may be relevant to you in light of your particular circumstances or that may be applicable to you if you are subject to special treatment under the U.S. federal income tax laws, including if you are:

· a financial institution;

· a tax–exempt organization;

· an S corporation or other pass–through entity;

· an insurance company;

· a mutual fund;

· a dealer in stocks and securities, or foreign currencies;

· a trader in securities who elects the mark–to–market method of accounting for your securities;

· subject to the alternative minimum tax provisions of the Code;

· a U.S. Holder who received our ordinary shares or ADSs through the exercise of employee stock options, otherwise as compensation, or through a tax–qualified retirement plan;

· a U.S. Holder who has a functional currency other than the U.S. dollar, certain expatriates, or not a U.S. Holder;

· a U.S. Holder who holds our ordinary shares or ADSs as part of a hedge, straddle or constructive sale or conversion transaction; or,

· a U.S. Holder who owns, or is treated as owning under certain attribution rules, 5% or more of the aggregate amount of our ordinary shares or ADSs.

This section is based in part upon the representations of the depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms.

In general, and taking into account the assumptions stated herein, for U.S. federal income tax purposes a holder of ADSs will be treated as the owner of the ordinary shares represented by those ADSs.  Exchanges of ordinary shares for ADSs, and of ADSs for ordinary shares, generally will not be subject to U.S. federal income tax.  This discussion (except where otherwise expressly noted) applies equally to U.S. Holders of ordinary shares and U.S. Holders of ADSs.

U.S. Holders should consult their own tax advisors regarding the specific U.S. federal, state and local tax consequences of the ownership and disposition of ordinary shares and ADSs in light of their particular circumstances as well as any consequences arising under the laws of any other taxing jurisdiction. In particular, U.S. Holders are urged to consult their own tax advisors regarding whether they are eligible for benefits under the USDTA.

This summary assumes that we are not and will not become a controlled foreign corporation for purposes of the Code and, except as otherwise indicated, that we are not and will not become a passive foreign investment company.

Sale of ordinary shares and ADSs

Subject to the passive foreign investment company rules discussed below, a U.S. Holder that sells or otherwise disposes of our ordinary shares or ADSs will recognize capital gain or loss for U.S. federal income tax purposes equal to the difference between (i) the U.S. dollar value of the amount realized on the sale or disposition and (ii) the tax basis, determined in U.S. dollars, of those ordinary shares or ADSs. Such gain or loss generally will be long-term capital gain or loss if the holding period for the ordinary shares or ADSs sold or disposed of exceeds one year at the time of disposition. The deductibility of capital losses is subject to significant limitations.  The gain or loss on the sale or other disposition of our ordinary shares or ADSs by a U.S. Holder will generally be income or loss from sources within the United States for purposes of computing the foreign tax credit limitation. Capital gains may be subject to the surtax on unearned income, as discussed below under “Surtax on Unearned Income.”

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Dividends

We do not expect to pay dividends in the foreseeable future.  However, subject to the passive foreign investment company rules discussed below, a U.S. Holder must include in gross income as dividend income the gross amount of any distribution (including the amount of any Australian withholding tax thereon) paid by us out of our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes) with respect to ordinary shares or ADSs.  Such distributions are taxable to a U.S. Holder when the U.S. Holder (in the case of ordinary shares) or the depositary (in the case of ADSs) actually or constructively receives the distribution.

Except as described below, dividends paid to a non–corporate U.S. Holder of our ordinary shares or ADSs will be “qualified dividend income” and will be taxed to such holder at the rates applicable to long–term capital gains. However, dividend income will not be qualified dividend income (and will be taxed at ordinary income rates) if (i) the holder fails to hold the ordinary shares or ADSs for at least 61 days during the 121-day period beginning 60 days before the ex–dividend date; (ii) the Internal Revenue Service determines that the USDTA is not a comprehensive income tax treaty that entitles our dividends to qualified dividend treatment and our ordinary shares or ADSs are not readily tradable on an established securities market in the United States; or (iii) we are a passive foreign investment company for the taxable year in which the dividend is paid or in the preceding taxable year. Dividends may be subject to the surtax on unearned income, as discussed below under “Surtax on Unearned Income.”

In the case of a corporate U.S. Holder, dividends on ordinary shares and ADSs are taxed as ordinary income and will not generally be eligible for the dividends received deduction generally allowed to U.S. corporations for dividends received from other U.S. corporations.

Distributions in excess of current and accumulated earnings and profits (as determined for U.S. federal income tax purposes) will be treated as a non–taxable return of capital to the extent of the holder’s tax basis in the ordinary shares or ADSs and thereafter as capital gain.

For foreign tax credit limitation purposes, at least a portion of the dividends paid by us generally would be U.S. source income if, and to the extent that, more than a de minimis amount of our earnings and profits out of which the dividends are paid is from sources within the United States. The remaining portion of the dividends paid by us will be income from sources outside the United States. The use of foreign tax credits is subject to complex conditions and limitations. In lieu of a credit, a U.S. Holder who itemizes deductions may elect to deduct all of such holder’s foreign taxes in the taxable year such foreign taxes are paid or deemed paid. A deduction does not reduce U.S. tax on a dollar-for-dollar basis like a tax credit, but the deduction for foreign taxes is not subject to the same limitations applicable to foreign tax credits. U.S. Holders are urged to consult their own tax advisors regarding the availability of foreign tax credits.

The amount of any distribution paid in foreign currency (including the amount of any Australian withholding tax thereon) generally will be includible in the gross income of a U.S. Holder of ordinary shares or ADSs in an amount equal to the U.S. dollar value of the foreign currency, calculated by reference to the spot rate in effect on the date of receipt by the U.S. Holder, or, the case of ADSs, by the depositary, regardless of whether the foreign currency is converted into U.S. dollars on such date. The amount of any distribution paid in a foreign currency generally will be converted into U.S. dollars by the depositary upon its receipt. Accordingly, a U.S. Holder of ADSs generally will not be required to recognize foreign currency gain or loss in respect of the distribution. Special rules govern and specific elections are available to accrual method taxpayers to determine the U.S. dollar amount includible in income in the case of taxes withheld in a foreign currency. Accrual basis taxpayers are therefore urged to consult their own tax advisors regarding the requirements and elections applicable in this regard.  

Passive Foreign Investment Company (“PFIC”) Status

A non-U.S. corporation will be classified as a PFIC in any taxable year in which, after taking into account the income and assets of certain subsidiaries, either (i) at least 75% of its gross income is passive income, or (ii) at least 50% of the average value of its assets is attributable to assets that produce or are held for the production of passive income.  Whether or not we will be classified as a PFIC in any taxable year is a factual determination and will depend upon our assets, the market value of our ordinary shares, and our activities in each year and is therefore subject to change.

Although we do not believe that we were a PFIC for the taxable year ended June 30, 2019 and do not expect to be a PFIC in the foreseeable future, the tests for determining PFIC status depend upon a number of factors. Some of these factors are beyond our control and may be subject to uncertainties, and we cannot assure you that we have not been or will not be a PFIC. We have not undertaken a formal study as to our PFIC status, and we do not undertake an obligation to determine our PFIC status, or to advise investors in our securities as to our PFIC status, for any year.

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If we are a classified as a PFIC for any taxable year, the so–called “excess distribution” regime of Code Section 1291 will apply to any U.S. Holder of ordinary shares or ADSs that does not make a mark–to–market or qualified electing fund election, as described below.  Under the excess distribution regime, (i) any gain the U.S. Holder realizes on the sale or other disposition of the ordinary shares or ADSs (possibly including a gift, exchange in a corporate reorganization, or grant as security for a loan) and any “excess distribution” that we make to such holder (generally, any distributions to such holder in respect of the ordinary shares or ADSs during a single taxable year that are greater than 125% of the average annual distributions received by such holder in the three preceding years or, if shorter, such holder’s holding period for the ordinary shares or ADSs), will be treated as ordinary income that was earned ratably over each day in such holder’s holding period for the ordinary shares or ADSs; (ii) the portion of any excess distributions allocated to the current year or prior years before the first day of the first taxable year beginning after December 31, 1986 in which we became a PFIC would be includible by the U.S. Holder as ordinary income in the current year; (iii) the portion of such gain or distribution that is allocable to prior taxable years during which we were a PFIC will be subject to tax at the highest rate applicable to ordinary income for the relevant taxable years, regardless of the tax rate otherwise applicable to such holder and without reduction for deductions or loss carryforwards; and (iv) the interest charge generally applicable to underpayments of tax will be imposed with respect of the tax attributable to each such year.

Dividends received from us will not be “qualified dividend income” if we are a PFIC in the year of payment or were a PFIC in the year preceding the year of payment, and will be subject to taxation at ordinary income rates.

If we are classified as a PFIC for any taxable year and our ordinary shares or ADSs are treated as “marketable securities” under applicable Treasury Regulations, a U.S. Holder may avoid the excess distribution regime described above by making a valid “mark–to–market” election with respect to the ordinary shares or ADSs.  If a valid mark–to–market election is made, an electing U.S. Holder generally (i) will be required to recognize as ordinary income an amount equal to the excess, if any, of the fair market value of the ordinary shares or ADSs over the holder’s adjusted tax basis in such ordinary shares or ADSs at the close of each taxable year, or (ii) if the U.S. Holder’s adjusted tax basis in the ordinary shares or ADSs exceeds their fair market value at the close of each taxable year, will be allowed to deduct the excess as an ordinary loss to the extent of the net amount of income previously included as a result of the mark–to–market election.  A U.S. Holder’s basis in its ordinary shares or ADSs will be adjusted to reflect the amounts included or deducted with respect to the mark–to–market election, and any gain or loss on the disposition of ordinary shares or ADSs will generally be ordinary income, or, to the extent of previously included mark–to–market inclusions, ordinary loss.  Each U.S. Holder must make their own mark–to–market election.  Once made, the election cannot be revoked without the consent of the Internal Revenue Service unless the ordinary shares or ADSs cease to be marketable securities.  Under applicable. Treasury Regulations, marketable securities include stock of a PFIC that is “regularly traded” on a qualified exchange or other market.  Because our ordinary shares are traded on the Australian Stock Exchange and our ADSs are traded on the NYSE American, we expect that our ordinary shares and ADSs will be treated as “regularly traded,” and a U.S. Holder should be able to make a mark–to–market election.  However, no assurance that our ordinary shares or ADSs are or will be marketable securities can be given.

The excess distribution regime would not apply to any U.S. Holder who is eligible for and timely makes a valid “qualified electing fund” (“QEF”) election, in which case such holder would be required to include in income on a current basis such holder’s pro rata share of our ordinary income and net capital gains.  To be timely, a QEF election must be made for the U.S. Holder’s first taxable year that includes any portion of the U.S. Holder’s holding period in our ADS or ordinary shares during which we are a PFIC.  For this purpose, a U.S. Holder may elect to restart the U.S. Holder’s holding period in our ADSs or ordinary shares by agreeing to recognize, and pay tax and interest on under the excess distribution regime described above, the amount of any appreciation in the ADSs or ordinary shares held.   However, a U.S. Holder’s QEF election will be valid only if we provide certain annual information to our shareholders.  We have not decided at this time whether we will provide such annual information and thus it is possible that U.S. Holders will not be able to make a valid QEF election with respect to our ordinary shares and ADSs.

Special rules apply with respect to the calculation of the amount of the foreign tax credit with respect to excess distributions made by a PFIC.  In general, these rules allocate creditable foreign taxes over the U.S. Holder’s holding period for ordinary shares or ADSs and otherwise coordinate the foreign tax credit limitation rules with the PFIC rules.

If we are a PFIC in a taxable year and own shares in another PFIC (a “lower–tier PFIC”), a U.S. Holder also will be subject to the excess distribution regime with respect to its indirect ownership of the lower–tier PFIC.  The mark–to–market election would not be available for any indirect ownership of a lower–tier PFIC.  A QEF election can be made for a lower–tier PFIC, but only if we provide the U.S. Holder with the annual information necessary to make such an election. We have not decided at this time whether we will provide such annual information and thus it is possible that U.S. Holders will not be able to make a valid QEF election with respect to any lower-tier PFIC.

U.S. Holders who own ordinary shares or ADSs during any year in which we are a PFIC must file Internal Revenue Service Form 8621 with their U.S. federal income tax return for each year in which such holder owns ordinary shares or ADSs. In addition to providing the information required on such form with respect to the ownership of PFIC shares, the U.S. Holder will also be required to report gain recognized on a disposition of such ordinary shares or ADSs, the receipt of certain distributions from us, or the making of elections with respect to PFIC status.

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Tax Rates Applicable to Ordinary Income and Capital Gains of Non-Corporate U.S. Holders

Ordinary income and short-term capital gains of non-corporate U.S. Holders are generally subject to U.S. federal income tax at rates of up to 21%. Long-term capital gains of non-corporate U.S. Holders are generally subject to U.S. federal income tax at rates of up to 20%.

Surtax on Unearned Income

A surtax of 3.8% (the “unearned income Medicare contribution tax”) is imposed on the “net investment income” of certain U.S. Holders in excess of a threshold amount. Net investment income generally includes interest, dividends, royalties, rents, gross income from a trade or business involving “passive” activities, and net gain from disposition of property (other than property held in a “non-passive” trade or business). Net investment income is reduced by deductions that are properly allocable to such income.

HIRE Act

U.S. Holders should consult their tax advisors regarding the effect, if any, of the Hiring Incentives to Restore Employment Act, signed into law on March 18, 2010, which provides disclosure and withholding rules relating to ownership by U.S. persons of financial accounts with foreign financial institutions.

U.S. Information Reporting and Backup Withholding

Dividend payments with respect to ordinary shares or ADSs and proceeds from the sale, exchange, redemption, or other disposition of ordinary shares or ADSs may be subject to information reporting to the Internal Revenue Service and U.S. backup withholding.  Certain exempt recipients, including corporations, are not subject to these information reporting requirements.  Backup withholding will not apply to a holder who furnishes a correct taxpayer identification number or certificate of foreign status and who makes any other required certification.  U.S. persons who are required to establish their exempt status generally must provide to us or our depositary an Internal Revenue Service Form W–9 (Request for Taxpayer Identification Number and Certification).

Backup withholding is not an additional tax.  Amounts withheld as backup withholding may be credited against a U.S. Holder’s U.S. federal income tax liability, and a U.S. Holder may obtain a refund of any excess amounts withheld by filing a timely claim for refund with the Internal Revenue Service and furnishing any required information.

F. Recent Sales of Unregistered Securities

None.

Item 6. Selected Financial Data

Not applicable.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes and the other information appearing in this Annual Report on Form 10-K. As used in this report, unless the context otherwise indicates, references to “we,” “our,” “ours,” and “us” refer to Samson Oil and gas Limited and its subsidiaries collectively.

Overview

We are an independent energy company whose business plan is to acquire, explore and develop oil, natural gas and natural gas liquids ("NGL's") in the United States, primarily with a focus in Montana and North Dakota. Due to our limited capital and low commodity prices, we have not been able to execute on our business plan. Our long-term strategy is to seek to deliver net asset value per share growth to our investors via attractive investments within the oil and gas industry. In the event we are able to obtain sufficient additional capital we expect to seek properties that offer profit potential from overlooked and by-passed reserves of oil and natural gas, which may include shut-in wells, in-field development, stripper wells, re-completion and re-working projects.

Our 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. We incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. As of the balance sheet date of this report we had total current liabilities of $43.3 million, which exceeded our total current assets of $4.8 million by $38.5 million. We are in breach of several of our covenants related to the Credit Agreement (defined in Note 8 – Credit Facility), resulting in our borrowings payable of $33.5 million being classified in current liabilities. In addition, we expensed $1.4 million of debt discount costs due to the reclassification of our borrowings in our statement of operations as a finance expense.

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Our ability to continue as a going concern is dependent on the re-negotiation of the Credit Agreement, the sale of assets and/or raising further capital. These factors raise substantial doubt over our ability to continue as a going concern and whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the financial statements.

We believe that we can negotiate a waiver with our Lender and increase our cash flows from operations through the successful development of the Foreman Butte project and reducing our operating and general and administrative costs. In addition, we are negotiating with a prospective party a transaction to divest all of our oil and gas assets, which we believe, if successful, will result in proceeds not less than our obligations under the Credit Agreement and to our vendors.

However, there can be no assurances the we will successfully obtain a waiver, successfully divest our assets or increase our cash flows from operations. Given our current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

As of the date of this report the Lender has not waived our breaches of the Credit Agreement.

To provide an understanding of our past performance, financial condition and prospects for the future we discuss and provide our analysis of the following:

· Results of operations;

· Liquidity and capital resources;

· Contractual obligations;

· Off balance sheet arrangements;

· Critical accounting policies; and

· New accounting pronouncements.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. Our oil and gas are sold under contracts paying us various industry posted prices, adjusted for basis differentials. We are paid the average of the daily settlement price for the respective posted prices for the period in which the product is sold, adjusted for quality, transportation and location differentials.

We expect future prices for oil, gas, and NGLs to continue to be volatile. In addition to supply and demand fundamentals, as a global commodity, the price of oil is affected by real or perceived geopolitical risks in all regions of the world as well as the relative strength of the dollar compared to other currencies. Oil markets continue to be unstable.

Results of Operations

Presented below is a discussion of our results of operations for the fiscal years ended June 30, 2019, and 2018.

Net Loss Applicable to Common Stockholders

Our net loss applicable to common stockholders for the fiscal years ended June 30, 2019, and 2018, were $7.2 million and $6.0 million, respectively. Our oil and natural gas sales were $2.6 million higher compared to the prior year. However, our oil and gas producing costs increased $5.5 million, which was slightly offset by a decrease of $0.9 million in general and administrative expenses (“G&A”) compared to the prior year. Interest expense increased $2.0 million due to a higher interest rate related to our Credit Agreement that we entered into in April 2019. We recognized $1.0 million of other income because we were able to keep the non-refundable deposit made to us due to the failed purchase and sale agreement with Eagle Energy Partners I, LLC.

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Oil and Gas Producing Activities

The results of our producing oil and gas properties are presented below for the fiscal years ended June 30, 2019 and 2018:

	Fiscal Year ended June 30,
	2019		2018
Production Volume:
Oil (Bbls)		223,790		186,559
Natural gas (Mcf)		35,619		14,780
BOE		229,726		189,022
Oil Price per Bbl Produced (in dollars):
Realized price, excluded in the impact of derivative instruments	$	55.37	$	53.23
Natural Gas Price per Mcf Produced (in dollars):
Realized price	$	7.24	$	8.04

	Fiscal Year ended June 30,
	2019			2018
Expense per BOE:
Lease operating expenses	$	53.72		$	40.47
Depletion, depreciation and amortization	$	10.39		$	7.88
General and administrative expense	$	12.13		$	19.61
Production taxes, gathering and processing fees as a % of sales		8.6	%		8.9	%
Production taxes, gathering and processing fees		1,093,585			898,876

Comparison of Year Ended June 30, 2019 to year ended June 30, 2018:

	Year ended June 30,
Item	2019			2018			Variance			% Change
OPERATING REVENUES:
Oil sales	$	12,391,536			9,931,065		$	2,460,471			24.8	%
Gas sales		257,895			118,783			139,112			117.1	%
Other liquids		13,434			8,871			4,563			51.4	%
Total oil and gas income		12,662,865			10,058,719			2,604,146			25.9	%
OPERATING EXPENSES:
Lease operating expense		12,341,869			6,866,922			5,474,947			79.7	%
Depletion, depreciation, amortization and accretion of asset retirement obligation		2,385,964			1,488,772			897,192			60.3	%
Exploration and evaluation expenditure		73,016			325,304			(252,288	)		-77.6	%
Abandonment Expense		156,809			189,259			(32,450	)		-17.1	%
General and administrative		2,785,687			3,706,182			(920,495	)		-24.8	%
Provision for doubtful accounts		175,000			75,000			100,000			133.3	%
Total operating expenses		17,918,345			12,651,439			5,266,906			41.6	%
LOSS FROM OPERATIONS		(5,255,480	)		(2,592,720	)		(2,662,760	)		102.7	%
Interest expense, net		(3,765,652	)		(1,715,342	)		(2,050,310	)		119.5	%
Realized loss on derivative instruments		(968,418	)		(1,775,728	)		807,310			-45.5	%
Unrealized gain (loss) on derivative instruments		1,425,634			(946,438	)		2,372,072			-250.6	%
Gain on sale of assets		120,000			178,407			(58,407	)		-32.7	%
Income from forfeiture of escrowed funds from oil and gas sale		1,000,000			-			1,000,000			100.0	%
Other		247,941			80,899			167,042			206.5	%
LOSS BEFORE INCOME TAXES		(7,195,975	)		(6,770,922	)		(425,053	)		6.3	%
Income tax benefit		47,944			732,056			(684,112	)		-93.5	%
NET LOSS	$	(7,148,031	)	$	(6,038,866	)	$	(1,109,165	)		18.4	%
OTHER COMPREHENSIVE LOSS:
Foreign Currency Translation loss		(11,152	)		(45,461	)		34,309			-75.5	%
Total comprehensive loss for the period	$	(7,159,183	)	$	(6,084,327	)	$	(1,074,856	)		17.7	%

Our oil sales for the years ended June 30, 2019, and 2018, were $12.4 million and $9.9 million, respectively, an increase of $2.5 million or 24.8%. This increase can be attributed to increased sales volumes, which were 223,790 barrels of oil compared to 186,559 barrels of oil, which is an increase of 37,231 barrels or 20.0%. The increase in barrels is a direct result of our effort to re-work several of our wells to increase well bore efficiency and increase production volumes. The effect on our oil sales due to the increased sales volumes was an increase of $2.0 million and higher average realized oil prices of $55.37 per barrel increased our oil sales by $0.5 million.

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Our natural gas sales for the years ended June 30, 2019, and 2018, were approximately $258,000 and $119,000, respectively, an increase of approximately $139,000 or 117.1%. The average realized natural gas prices, including proceeds from sales of natural gas liquids, in 2019 and 2018, were $7.24 and $8.04 per Mcf, respectively, a decrease of $0.80 or 9.9%. The impact on natural gas sales in the current year due to the lower realized prices decreased natural gas sales approximately $28,000. These lower prices were offset by greater volumes, which were 20,839 Mcf or 141.0% higher compared to the prior year, increasing our natural gas sales approximately $167,000.

Lease operating expenses ("LOE") include workover expenses of $2.9 million and $1.1 million for the fiscal years ended June 30, 2019, and 2018, respectively. LOE, excluding workover expenses were $8.3 million and $4.9 million for fiscal year ended June 30, 2019, and 2018, respectively. This represents an increase of $3.4 million, which is due to increases in repairs and maintenance of $1.0 million, increased salt water disposal costs of $1.7 million, inreased chemical, environmental and labor costs of $0.4 million and an increase in COPAS overhead charges and other costs of $0.3 million. Approximately 50% of the increase in LOE is related to workover expenses and repairs and maintenance costs, which aggregated to $2.8 million, as part of our effort to rehabilitate the field and increase efficiency in order to increase volumes.

Production taxes were $1.0 million and $0.8 million for the fiscal years ended June 30, 2019, and 2018, respectively. This represents an increase of $0.2 million or 21.7%. We generally expect absolute production tax expense to trend as a percentage with our oil, natural gas, and NGL sales revenue. Production taxes as a percentage of revenue in fiscal year 2019 and 2018 were 8.64% and 8.94%.

Our depletion, depreciation and amortization (“DD&A”) expenses were $2.4 million for fiscal year ended June 30, 2019, compared to $1.5 million for fiscal year ended June 30, 2018, an increase of $0.9 million or 60.3%. During fiscal year ended June 30, 2018, the majority of our oil and gas properties were categorized as Assets Held for Sale for approximately half the fiscal year. When assets are categorized as held for sale there is no DD&A calculated until such time that the assets are no longer held for sale, at which time there is a one time “catch-up” calculation to capture the amount that would have been recorded as DD&A expense had the assets not been categorized as Assets Held for Sale. The increase in DD&A is primarily attributed to this recapture of DD&A expense due to the purchase and sale agreement that expired related to the Eagle Energy Partners I, LLC transaction, which occurred in fiscal year 2019.

We perform assessments of our long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. To the extent such assessments indicate a reduction of the estimated useful life or estimated future cash flows of our oil and gas properties, the carrying value may not be recoverable and, therefore, an impairment charge would be required to reduce the carrying value of the proved properties to their fair value.

The cash flow model we use to assess proved properties for impairment includes numerous assumptions. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's price outlook (iv) increases or decreases in production costs and capital costs associated with those reserves and (v) our ability to fund the capital costs related to undeveloped reserves. All inputs to the cash flow model are evaluated at each measurement date.

There were no charges to impairment expense related to our oil and gas properties based on the assumptions that management used to evaluate the future cash flows.

General and administrative expenses decreased $0.9 million or 24.8% for the fiscal year ended June 30, 2019, compared to the same period in 2018. This reduction was primarily due to a decrease in salaries and employee benefits, which decreased by $1.2 million. This decrease was offset by penalties and late charges assessed to us for late payments of certain royalties and taxes in the amount of $0.4 million. Legal, accounting and assurance costs, filing fees and other general and administrative costs remained consistent with the prior year decreasing $0.1 million or 2.0%.

Interest expense, net of interest income, for the fiscal years ended June 30, 2019, and 2018, were $3.8 million and $1.7 million, respectively, an increase of $2.1 million or 119.5%. The components of interest expense include cash paid for interest expense of $2.4 million and $1.4 million of deferred financing fees related to the Credit Agreement previously categorized as a debt discount, but expensed at June 30, 2019, due to the breach of certain covenants under the Credit Agreement. In addition, the interest rate under the Credit Agreement is LIBOR plus 10.5% (approximately 13.0% at June 30, 2019), compared to the previous debt facility, which had an effective interest rate equal to the Prime Rate plus 1.0% to 2.5% (approximately 5.25% to 6.75% at June 30, 2018).

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Liquidity and Capital Resources

We do not generate adequate revenue to satisfy our current operations, we have negative cash flows from operations, and we have incurred significant net operating losses during the years ended June 30, 2019, and 2018, which raise substantial doubt about our ability to continue as a going concern. Because of this our 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. We are in breach of several of our covenants related to the Credit Agreement resulting in our borrowings payable of $33.5 million being classified in current liabilities.

Our ability to continue as a going concern is dependent on the re-negotiation of the Credit Agreement, the sale of assets and/or raising further capital. These factors raise substantial doubt over our ability to continue as a going concern and therefore whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the financial statements.

We believe that we can negotiate a waiver with our Lender and increase our cash flows from operations through the successful development of the Foreman Butte project and reducing our operating and general and administrative costs. In addition, we are negotiating with a prospective party a transaction to divest all of our oil and gas assets, which we believe, if successful, will result in proceeds not less than our obligations under the Credit Agreement and to our vendors.

However, there can be no assurances that we will successfully obtain a waiver, successfully divest our assets or increase our cash flows from operations. Given our current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

We used $5.4 million of cash flow from our operations during the fiscal year ended June 30, 2019, compared to $0.7 million of cash provided by operations during the same period in the prior year, a change of $6.1 million. Our loss can be primarily attributed to higher LOE costs, which included $2.9 million of workover expenses and higher interest expenses related to our Credit Agreement, which, aggregated with LOE costs, equaled $14.7 million compared to $8.6 million in the prior year. These costs were offset by $1.0 million of other income related to the forfeiture of the non-refundable deposit from the purchase and sale transaction with Eagle Energy Partners I, LLC.

Cash flows used in investing activities during the fiscal year ended June 30, 2019, was $1.5 million compared to $0.4 million in the prior year. During fiscal year ended June 30, 2019, we incurred $1.6 million of capital costs, primarily related to drilling the first Gonzalez location in our Home Run field. We also sold two oil and gas properties that had been fully depleted for proceeds of $120,000.

We realized cash flows from financing activities of $2.8 million and $1.4 million for the years ended June 30, 2019, and 2018, respectively. On April 9, 2019, we entered into a new debt facility. We received $33.5 million of proceeds from borrowings under the new agreement and used the proceeds to retire the previous credit facility of $23.9 million. We also paid $1.4 million in deferred borrowing costs.

Off-Balance Sheet Arrangements

At June 30, 2019, we had no existing off-balance sheet arrangements, as defined under SEC rules, that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Acquisitions and Divestitures

Acquisitions

We had no material acquisitions in fiscal years ended June 30, 2019 or June 30, 2018.

Divestitures

During the fiscal year ended June 30, 2019, we sold our interest in two oil and gas properties that had been fully depleted for aggregate cash consideration of $120,000.

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On June 14, 2018, we signed a purchase and sale agreement for the sale of the majority working interest in our Foreman Butte project in Montana and North Dakota for $40 million. The effective date of the transaction was January 1, 2018 and the transaction was expected to close on October 15, 2018. The buyer, however, failed to close this transaction and we retained the $1.0 million non-refundable deposit.

Critical Accounting Policies

Going concern. Our 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. We incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. At June 30, 2019, we had total current liabilities of $43.3 million, which exceeded our total current assets of $4.8 million. Our ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and/or raising further capital. These factors raise substantial doubt over our ability to continue as a going concern and therefore whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the financial report.

We are in breach of several of our covenants related to the Credit Agreement resulting in borrowings payable of $33.5 million being classified as current liabilities. We are negotiating with the Lender in an effort to obtain a waiver for the breach. As of the date this report was issued, no waiver has been received.

We are negotiating with a prospective party to divest our oil and gas assets, which we believe will result in proceeds not less than our obligations to the Lender and our other creditors. While we are confident we will be able to successfully recognize amounts in excess of the carrying value of the oil and gas assets as a result of a divestment, or alternatively through the successful development of our Foreman Butte project, there can be no assurances that we will be successful. Given the current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

Revenue Recognition and Gas Imbalances.   In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective July 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to or business processes, systems, or controls. However, upon adoption, we expanded our disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.

We use the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. Our production imbalances were not material at June 30, 2019, or 2018.

Successful Efforts Method of Accounting for Oil and Gas Properties. We account for our oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly.

Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project.

The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method. Mineral interests and leasehold acquisition costs are depleted over total proved reserves while costs of completed wells and related facilities and equipment are depleted over proved developed producing reserves.

40 

If the estimates of total proved or proved developed reserves decline, the rate at which we record depreciation, depletion and amortization expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, we determine the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

We review proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our oil and gas properties and compare these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by us. Impairment on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties are less than the carrying value.

In determining whether an unproved property is impaired, we consider numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

Exploration and evaluation costs including capitalized exploration written off and dry hole expenses. 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 expenditure under our policy, we conclude that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement.

During the fiscal years ended June 30, 2019, and 2018, we expensed $0 and $0.2 million, respectively, in deferred exploration expense.

Asset Retirement Obligations. The accounting standards set forth by the FASB with respect to accounting for asset retirement obligations provide that, if the fair value for asset retirement obligations can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and natural gas producing companies incur this liability upon acquiring or drilling a well. Under this method, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with the offsetting increase to property cost. Periodic accretion of discount of the estimated liability is recorded in the income statement. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our properties at the end of their productive lives, in accordance with applicable laws. We have determined our asset retirement obligation by calculating the present value of estimated cash flows related to each liability. The discount rates used to calculate the present value vary depending on the estimated timing of the relevant obligation, but typically ranged between 4% and 10%. We periodically review the estimate of costs to plug, abandon and remediate our properties at the end of their productive lives. This includes a review of both the estimated costs and the expected timing to incur such costs. We believe most of these costs can be estimated with reasonable certainty based upon existing laws and regulatory requirements and based upon wells and facilities currently in place. Any changes in regulatory requirements, which changes cannot be predicted with reasonable certainty, could result in material changes in such costs. Changes in reserve estimates and the economic life of oil and natural gas properties could affect the timing of such costs and accordingly the present value of such costs.

41 

Share Based Payments. We measure the cost of equity settled transactions by reference to the fair value of the equity instruments at the date they are granted.  Where the fair value of the equity instrument cannot be readily determined in reference to the market price of our ordinary shares, the fair value is determined using the Black Scholes option pricing model.  The use of the Black Scholes option pricing model requires Samson to make estimates in regard to certain inputs required by the model, in particular in regard to the time to expiry of the option and the volatility of our share price.  We review inputs to this model each time a valuation is performed with reference to inputs used in the past and recent developments.

Income Taxes and Uncertain Tax Positions. Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. We have recognized a valuation allowance against our net deferred taxes because we cannot conclude that it is more likely than not that the net deferred tax assets will be realized as a result of estimates of our future operating income based on current oil and natural gas commodity pricing. In assessing the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. We will continue to evaluate whether the valuation allowance is needed in future reporting periods. We are subject to taxation in many jurisdictions, and the calculation of our income tax liabilities involves dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. We recognize certain income tax positions that meet a more-likely-than not recognition threshold. If we ultimately determine that the payment of these liabilities will be unnecessary, we will reverse the liability and recognize an income tax benefit during the period in which we determine the liability no longer applies.

Derivatives. We have elected not to apply hedge accounting to any of our derivative transactions and, consequently, we recognize mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges. All derivative instruments are recorded on the balance sheet at fair value.

Recently Issued Accounting Pronouncements

ASU 2016-02, Leases (Topic 842) In January 2016, ASC 842 was issued, which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. ASC 842 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments, as a right of use asset and respective liability. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss.

We operate predominantly as a lessee. The standard will affect primarily the accounting for our operating leases, with no significant impact expected for our finance leases. The new lease standard is effective for us on July 1, 2019, and will be adopted effective on that date using the simplified cumulative catch-up method. This adoption method will allow the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at July 1, 2019, will be made for the difference between the right of use asset and liability recorded. In addition, lease incentives will be rolled into the respective right of use asset, rather than recorded as a deferral. Upon adoption of the new standard, we intend to elect to apply hindsight in assessing the lease term, and to grandfather previous conclusions reached as to whether existing contracts are or contain leases. We continue to evaluate other practical elections, which may apply to individual asset classes and to portfolios of leases that contain similar characteristics. As of June 30, 2019, we had approximately $220,000 of contractual obligations related to our non-cancelable leases. We are in the process of evaluating those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASC 842. We also are in the process of implementing changes to our accounting policies, internal controls, and financial statements as a result of adoption of this standard. We will continue to assess the additional disclosures that will be required upon implementation of the standard. 

42 

Item 8. Financial Statements and Supplementary Data

See “Index to Consolidated Financial Statements” on page 53 of this report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Controls and Procedures.   We conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”) as of June 30, 2019. This evaluation was conducted under the supervision and with the participation of management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting. We are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of assets of the company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we assessed the effectiveness of our internal control over financial reporting as of June 30, 2019, the end of our fiscal year. This assessment was based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on our assessment for the reasons noted above, management has concluded that, as of June 30, 2019, our internal control over financial reporting is not effective based upon these criteria.

A deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent, or detect and correct misstatements on a timely basis. A material weakness is a deficiency or combination of deficiencies in internal control, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented or detected and corrected on a timely basis. We consider the following deficiencies in Samson Oil and Gas Limited’s (“SSN”) internal control to be material weaknesses:

Management identified control deficiencies that, in the aggregate, represent a material weakness in our internal control over financial reporting as of June 30, 2019. We have identified deficiencies in the design and/or operations of our controls associated with the Financial Close and Reporting process that, in the aggregate, represent a material weakness, including: (i) deficiencies in control design and operating effectiveness relating to manual processes performed to adequately capture accounts payable invoices and estimate costs that were incurred during the reporting period for which the invoices had not been received; (ii) deficiencies in operating effectiveness of controls over reconciliations of balance sheet accounts and review of journal entries; and (iii) a lack of segregation of duties.

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Since the Company took over operatorship of the Foreman Butte field in 2016 the design of our accounts payable cut-off process has not been sufficient enough to adequately capture all invoices in a timely fashion. The impact of this was originally 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. At June 30, 2019, we have concluded that this process is still not adequate to capture all invoices in a timely fashion. Additionally, we note that our process for recording accrued liabilities, which involves estimating those costs that have been incurred where the invoice had not been received, was not adequate at June 30, 2019. During audit fieldwork, it was noted that several non-operated joint interest billings and several invoices received after the financial close exceeded the original estimated accrual for unrecorded liabilities.

The inadequate segregation of duties is a weakness because it could lead to the untimely identification and resolution of accounting and disclosure matters or could lead to a failure to perform timely and effective reviews. During the fiscal year ended June 30, 2019, we had only one person, an executive officer, that performed nearly all aspects of our financial reporting process, including, but not limited to, access to the underlying accounting records and systems, the ability to post and record journal entries and responsibility for the preparation of the financial statements. This provides for a lack of review over the financial reporting process that may result in a failure to detect errors in spreadsheets, calculations, or assumptions used to compile the financial statements and related disclosures as filed with the SEC. As we had only two full time employees, we do not have a sufficient compliment of personnel with appropriate training and experience in GAAP and SEC reporting to fully address complex financial reporting matters.

The material weakness we identified associated with accounts payable and accrued liabilities are due to the lack of analysis of capital expenditures, costs related to non-operated properties, operated properties and general and administrative expenses. The material weakness related to the Financial Close and Reporting process arises primarily from; (i) a lack of a sufficient complement of accounting and financial reporting personnel who were unable to implement formal accounting policies with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements; and (ii) inadequate reconciliations of balance sheet accounts directly related to financial statement processes.

Remedial Action

Hired a CFO on October 1, 2019, with the accounting knowledge and experience to help institute appropriate controls and procedures to remediate the above discussed material weaknesses.

Planned Actions

· Continue working to document and remediate weaknesses, and to structure the Company’s accounting/finance department to meet financial and reporting requirements;

· Create and implement a formal closing checklist;

· Document internal control procedures for significant accounting areas with an emphasis on implementing additional documented review and approval procedures and automated controls within the Company’s accounting system;

· Conduct formal training related to key accounting policies, internal controls, and SEC compliance for all key personnel which have a direct and indirect impact on the transactions underlying the financial statements;

· Implement Information Technology systems and documentation and new controls that have an impact on financial reporting.

In light of the material weakness in internal control over financial reporting described above, we performed additional analysis and other post-closing procedures to ensure that our financial statements were prepared in accordance with generally accepted accounting principles. Despite the material weakness in our internal controls over financial reporting, we believe that the financial statements included in our Form 10-K for the period ended June 30, 2019, fairly present, in all material respects, our financial condition, results of operations, changes in stockholders’ deficit and cash flows for the periods presented.

The foregoing has been approved by our management, including our CEO and CFO, who have been involved with the reassessment and analysis of our internal control over financial reporting.

Inherent Limitations on Effectiveness of Controls

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Accordingly, our disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure system are met. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

44 

Changes in Internal Control over Financial Reporting

Other than as discussed above, there were no changes in our internal control over financial reporting during the year ended June 30, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information relating to this item will be in the proxy statement for our 2019 annual shareholders’ meeting and is incorporated by reference in this report or, if necessary, will be included in an amendment to this report.

Item 11. Executive Compensation

Information relating to this item will be in the proxy statement for our 2019 annual shareholders’ meeting and is incorporated by reference in this report or, if necessary, will be included in an amendment to this report. 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information relating to this item will be in the proxy statement for our 2019 annual shareholders’ meeting and is incorporated by reference in this report or, if necessary, will be included in an amendment to this report.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information relating to this item will be in the proxy statement for our 2019 annual shareholders’ meeting and is incorporated by reference in this report or, if necessary, will be included in an amendment to this report.

Item 14. Principal Accounting Fees and Services

Information relating to this item will be in the proxy statement for our 2019 annual shareholders’ meeting and is incorporated by reference in this report or, if necessary, will be included in an amendment to this report.

PART IV

Item 15. Exhibits and Financial Statement Schedules

Financial Statements and Financial Statement Schedules

See “Index to Consolidated Financial Statements” on page 51.

45 

Exhibits

Number	Description
3.1	Constitution of Samson Oil & Gas Limited dated November 30, 2017 (incorporated by reference to Exhibit 3.1 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on February 14, 2018)
4.1	Form of Deposit Agreement between Samson Oil & Gas Limited and The Bank of New York (incorporated by reference to Exhibit 1 to the Registration Statement on Form F-6EF filed on April 29, 2010).
4.2	Terms and Conditions of Warrants, included in the Form of Subscription Agreement filed as Exhibit 10.1 hereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 22, 2013).
10.4	Employment Agreement between Samson Oil and Gas USA, Inc. and Terence Barr, dated as of January 1, 2011 (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K filed on September 13, 2012).+
10.5	Amendment to Employment Agreement between Samson Oil and Gas USA, Inc. and Terence Barr, dated as of December 20, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 27, 2011).+
10.6	Employment Agreement between Samson Oil and Gas USA, Inc. and Robyn Lamont, dated as of January 1, 2011 (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K filed on September 13, 2012).+
10.7	Employment Agreement between Samson Oil and Gas USA, Inc. and David Ninke, dated as of January 1, 2011 (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K filed on September 13, 2012).+
10.8	Employment Agreement between Samson Oil and Gas USA, Inc. and Daniel Gralla, dated as of January 1, 2011 (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K filed on September 13, 2012).+
10.9	Samson Oil & Gas Limited Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-8 of Samson Oil & Gas Limited filed on April 21, 2011).+
10.10	Purchase and Sale Agreement with Slawson Exploration Company, Inc. dated August 15, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 20, 2013).
10.11	Form of Subscription Agreement dated March 20, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 22, 2013).
10.12	Form of Subscription Agreement dated August 19, 2013 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 22, 2013).
10.13	Term Loan Credit Agreement dated January 27, 2014 among Samson Oil and Gas USA, Inc. as borrower, Samson Oil & Gas Limited and Samson Oil and Gas Montana, Inc. as guarantors, and Mutual of Omaha Bank as lender and administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 31, 2014).
10.14	Farmout Agreement dated February 28, 2014, among Samson Oil and Gas USA Montana, Inc., Fort Peck Energy Company, LLC and Momentus Energy LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on March 6, 2014).
10.15	Form of Subscription Agreement dated April 16, 2014, among Samson Oil & Gas Limited and each of the purchasers party thereto (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K filed on April 17, 2014).
10.16	First Amendment to Mutual of Omaha Credit Agreement dated November 24, 2014 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on February 9, 2015).

46 

10.17	Purchase and Sale Agreement dated December 31, 2015 between Samson Oil and Gas USA, Inc. and Oasis Petroleum North America LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on January 7, 2016).
10.18	First Amendment to Purchase and Sale Agreement dated March 31, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on April 6, 2016).
10.19	Secured Promissory Note dated March 31, 2016 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on April 6, 2016).
10.20	Third Amendment to Credit Agreement dated March 31, 2016 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on April 6, 2016).
10.21	Form of Subscription Agreement (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K filed on April 14, 2016).
10.22	Engagement Agreement dated February 22, 2016 between Samson and Euro-Pacific (incorporated by reference to Exhibit 1.2 to the Current Report on Form 8-K filed on April 14, 2016).
10.23	Amendment to Employment Agreement dated May 6, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 9, 2016).+
10.24	Purchase and Sale Agreement dated June 30, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 7, 2016).
10.25	Fourth Amendment to Credit Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 18, 2016).
10.26	Fifth Amendment to Credit Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 3, 2016).
10.27	Letter dated April 3, 2017 modifying payment terms of Secured Promissory Note dated March 31, 2016 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 7, 2017).
10.28	Amended and Restated Employment Agreement, by and between Samson Oil and Gas USA and Terence Barr, dated January 1, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017).+
10.29	Amended and Restated Employment Agreement, by and between Samson Oil and Gas USA and Robyn Lamont, dated January 1, 2017 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017).+
10.30	Amended and Restated Employment Agreement, by and between Samson Oil and Gas USA and David Ninke, dated January 1, 2017 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017).+
10.31	Employment Agreement, by and between Samson Oil and Gas USA and Mark Ulmer, dated April 1, 2016 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 26, 2017).+
10.32	Sixth Amendment to Credit Agreement dated May 5, 2017 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 8, 2017)

47 

10.33	Term Note for the benefit of Mutual of Omaha Bank dated May 5, 2017 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 8, 2017)
10.44	Purchase and Sale Agreement dated May 1, 2017 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2017)
10.45	Seventh Amendment to Credit Agreement dated July 14, 2017 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 20, 2017)
10.46	2016 Stock Option Plan (incorporated by reference to Exhibit 10.46 to the Annual Report on Form 10-K filed with the Securities and Exchange Commission on September 28, 2017)+
10.47	Amended & Restated Employment Agreement dated as of January 1, 2018 between Samson Oil and Gas USA, Inc. and Terence M. Barr (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on February 5, 2018) +
10.48	Agreement, dated as of February 9, 2018, between Samson Oil and Gas, USA, Inc., Samson Oil & Gas Limited, Samson Oil and Gas USA Montana, Inc., and Mutual of Omaha Bank (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on February 14, 2018).
10.49	Subscription Agreement dated March 30, 2018 between the Company and DynEvolve Capital, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 5, 2018).
10.50	Stockholders Agreement dated March 30, 2018 between the Company, DynEvolve Capital Group and future stockholders party thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 5, 2018).
10.51	Purchase and Sale Agreement dated June 12, 2018 between Samson Oil and Gas USA, Inc., and Eagle Energy Partners I, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 20, 2018).
10.52	Agreement dated June 14, 2018 between Samson Oil and Gas, USA, Inc., Samson Oil & Gas Limited, Samson Oil and Gas USA Montana, Inc., and Mutual of Omaha Bank (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 20, 2018).
10.53	Amendment to Purchase and Sale Agreement dated September 28, 2018 between Samson Oil and Gas USA, Inc., and Eagle Energy Partners I, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 4, 2018).
10.54	Amendment to Agreement dated September 28, 2018 between Samson Oil and Gas, USA, Inc., Samson Oil & Gas Limited, Samson Oil and Gas USA Montana, Inc., and Mutual of Omaha Bank (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 4, 2018).
10.55	Employment Agreement dated March 1, 2019 by and between Samson Oil and Gas USA, Inc. and Janna Blanter (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on March 6, 2019).+
10.56	Credit Agreement dated April 9, 2019 by and among Samson Oil and Gas USA, Inc., the lenders party thereto, and AEP I Finco LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2019).

48 

10.57	Guaranty dated April 9, 2019 by and between Samson Oil & Gas Limited and AEP I Finco LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2019).
10.58	Security Agreement dated April 9, 2019 by and among Samson Oil & Gas Limited, Samson Oil and Gas USA, Inc., Samson Oil and Gas USA Montana, Inc., certain subsidiary parties, and AEP I Finco LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2019).
10.59	Engagement Letter dated April 30, 2019 by and among Nicholas Ong, Minerva Corporate Pty Limited and Samson Oil & Gas Limited (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on July 26, 2019).+
10.60	Employment Agreement dated October 1, 2019 among Tristan Farel, LTN Ergy, LLC, and Samson Oil & Gas Limited (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on October 4, 2019).+
21.1	List of Subsidiaries (incorporated by reference to Exhibit 21 to the Annual Report on Form 10-K filed on September 13, 2011).
23.1	Consent of Moss Adams LLP. *
23.2	Consent of Netherland, Sewell & Associates, Inc.*
31.1	Certification of the Principal Executive Officer pursuant to Rule 13a–14(a) and Rule 15d–14(a) of the Securities Exchange Act of 1934, as amended. *
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a–14(a) and Rule 15d–14(a) of the Securities Exchange Act of 1934, as amended. *
32.1	Certifications of the Principal Executive Officer and Principal Financial Officer pursuant to 18 USC 1350, as adopted, pursuant to Section 906 of the Sarbanes–Oxley Act of 2002. **
101.INS	XBRL Instance Document
	XBRL Taxonomy Extension Schema Document
	XBRL Taxonomy Extension Calculation Linkbase Document
	XBRL Taxonomy Extension Definition Linkbase Document
	XBRL Taxonomy Extension Label Linkbase Document
	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith

**Furnished herewith

+ Management contract or compensatory plan or arrangement

49 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 and Gas Limited
By:	/s/ Terence Barr
Name:	Terence Barr
Title:	Managing Director, President and Chief Executive Officer
Date:	October 15, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Terence Barr	Managing Director, President and Chief Executive Officer (Principal Executive Officer)	October 15, 2019
Terence Barr
/s/ Tristan Farel	Chief Financial Officer (Principal Financial Officer)	October 15, 2019
Tristan Farel
/s/ Peter Hill	Director	October 15, 2019
Peter Hill
/s/ Greg Channon	Director	October 15, 2019
Greg Channon
/s/ Nicholas Ong	Director	October 15, 2019
Nicholas Ong

50 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	52
Consolidated Balance Sheets as of June 30, 2019 and 2018	53
Consolidated Statements of Operations and Comprehensive Loss for the Fiscal Years Ended June 30, 2019 and 2018	54
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the Fiscal Years Ended June 30, 2019 and 2018	55
Consolidated Statements of Cash Flows for the Fiscal Years Ended 2019 and 2018	56
Notes to Consolidated Financial Statements	57

51 

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of

Samson Oil & Gas Limited

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Samson Oil & Gas Limited (the “Company”) as of June 30, 2019 and 2018, the related consolidated statements of operations and comprehensive loss, stockholders’ deficit and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of June 30, 2019 and 2018, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Uncertainty

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company is in violation of its debt covenants, incurred a net loss from operations, has cash outflows from operations, and its current liabilities exceed its current assets as of and for the year ended June 30, 2019. These conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Denver, CO

October 15, 2019

We have served as the Company’s auditor since 2017.

52 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	June 30,
	2019			2018
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	685,737		$	1,376,676
Restricted cash - required reserve amounts related to Credit Agreement		2,088,750			-
Accounts receivable, net of allowance for doubtful accounts of $250,000 and $75,000, respectively		1,982,123			1,908,879
Oil Inventory		-			219,288
Prepayments		-			137,342
Total current assets		4,756,610			3,642,185
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, net, successful efforts method of accounting, less accumulated depreciation, depletion and amortization of $9,491,784 and $6,105,315 at June 30, 2019, and 2018, respectively		30,214,829			30,420,841
Other property and equipment, net of accumulated depreciation and amortization of $755,241 and $775,057 at June 30, 2019 and June 30, 2018, respectively		174,931			242,822
Net property, plant and equipment		30,389,760			30,663,663
OTHER ASSETS
Fair value of derivative instruments		365,542			-
Deposits		559,722			584,644
Deferred tax asset		780,000			732,056
TOTAL ASSETS	$	36,851,634		$	35,622,548
LIABILITIES AND STOCKHOLDERS’ DEFICIT
CURRENT LIABILITIES
Accounts payable	$	8,121,217		$	8,532,987
Accrued liabilities		1,300,185			1,339,164
Fair value of derivative instruments		150,703			1,210,795
Current portion of asset retirement obligation		274,404			-
Current portion of credit facility		33,500,000			23,867,558
Total current liabilities		43,346,509			34,950,504
Asset retirement obligations		3,336,376			3,344,112
Total liabilities		46,682,885			38,294,616
Commitments and contingencies (Note 11 & 12)
STOCKHOLDERS’ DEFICIT
Common stock, 328,300,044 shares issued and outstanding at June 30, 2019 and 2018		106,743,167			106,743,167
Accumulated other comprehensive income		835,404			846,556
Accumulated deficit		(117,409,822	)		(110,261,791	)
Total stockholders’ deficit		(9,831,251	)		(2,672,068	)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	36,851,634		$	35,622,548

See accompanying Notes to Consolidated Financial Statements.

53 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

	Fiscal year ended June 30,
	2019			2018
OPERATING REVENUES:
Oil sales	$	12,391,536		$	9,931,065
Gas sales		257,895			118,783
Other liquids		13,434			8,871
Total oil and gas income		12,662,865			10,058,719
OPERATING EXPENSES:
Lease operating expense		12,341,869			6,866,922
Depletion, depreciation, amortization and accretion of asset retirement obligation		2,385,964			1,488,772
Exploration and evaluation expenditure		73,016			325,304
Abandonment Expense		156,809			189,259
General and administrative		2,785,687			3,706,182
Provision for doubtful accounts		175,000			75,000
Total operating expenses		17,918,345			12,651,439
LOSS FROM OPERATIONS		(5,255,480	)		(2,592,720	)
Interest expense, net		(3,765,652	)		(1,715,342	)
Realized loss on derivative instruments		(968,418	)		(1,775,728	)
Unrealized gain (loss) on derivative instruments		1,425,634			(946,438	)
Gain on sale of assets		120,000			178,407
Income from forfeiture of non-refundable deposit		1,000,000			-
Other		247,941			80,899
LOSS BEFORE INCOME TAXES		(7,195,975	)		(6,770,922	)
Income tax benefit		47,944			732,056
NET LOSS	$	(7,148,031	)	$	(6,038,866	)
OTHER COMPREHENSIVE LOSS:
Foreign Currency Translation loss		(11,152	)		(45,461	)
Total comprehensive loss for the period	$	(7,159,183	)	$	(6,084,327	)
NET LOSS PER COMMON SHARE:
Basic and diluted – per share		(0.02	)		(0.02	)
Weighted average common shares outstanding:
Basic and diluted shares		328,300,044			328,300,044

See accompanying Notes to Consolidated Financial Statements.

54 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

						Accumulated Other
	Issued		Accumulated			Comprehensive			Total Equity
	Capital		Deficit			Income			(Deficit)
Balance at July 1, 2018	$	106,390,864	$	(104,222,925	)	$	892,017		$	3,059,956
Net loss		-		(6,038,866	)		-			(6,038,866	)
Foreign currency translation loss		-		-			(45,461	)		(45,461	)
Total comprehensive loss for the period		-		(6,038,866	)		(45,461	)		(6,084,327	)
Stock based compensation		352,303		-			-			352,303
Balance at June 30, 2018	$	106,743,167	$	(110,261,791	)	$	846,556		$	(2,672,068	)
Net loss		-		(7,148,031	)		-			(7,148,031	)
Foreign currency translation loss		-		-			(11,152	)		(11,152	)
Total comprehensive loss for the period		-		(7,148,031	)		(11,152	)		(7,159,183	)
Balance at June 30, 2019	$	106,743,167	$	(117,409,822	)	$	835,404		$	(9,831,251	)

See accompanying Notes to Consolidated Financial Statements.

55 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	June 30,
	2019			2018
Cash Flows from Operating Activities:
Net loss		(7,148,031	)		(6,038,866	)
Adjustments to reconcile net loss to net cash provided by (used) for operating activities:					-
Depreciation, depletion and amortization		1,824,014			1,237,989
Accretion of discount on asset retirement obligations		561,950			250,783
Exploration and evaluation assets written off		-			325,290
Unrealized (gain) loss on derivative instruments		(1,425,634	)		946,438
Share based compensation		-			352,303
Amortization of debt discount		1,390,564			32,808
Settlement of asset retirement obligations		(295,282	)		(289,896	)
Provision for bad debt expense		175,000			75,000
Direct write-off of uncollectible accounts receivable's		22,346			-
Oil inventory		219,288			-
Gain on sale of properties		(120,000	)		(178,407	)
Deferred tax asset		(47,944	)		(732,056	)
Changes in operating assets and liabilities:
Accounts receivables		(270,590	)		(284,023	)
Prepayments		137,342			(82,823	)
Accounts payable		(376,509	)		4,702,429
Accrued liabilities		(38,979	)		268,785
Deposits		24,999			156,535
Net cash (used in) provided from operating activities		(5,367,466	)		742,289
Cash Flows from Investing Activities:
Proceeds from sale of oil and gas properties		120,000			105,396
Payments for oil and gas properties		(1,588,102	)		(414,480	)
Payments for exploration and evaluation, net		-			(54,212	)
Payments for furniture and fittings		-			(31,379	)
Net cash flows used in investing activities		(1,468,102	)		(394,675	)
Cash Flows from Financing Activities:
Proceeds from borrowings		33,561,707			450,000
Repayments of borrowings		(23,929,264	)		(35,000	)
Payments for costs associated with borrowings		(1,390,565	)		-
Net cash provided by financing activities		8,241,878			415,000
Net increase in cash and equivalents and restricted cash		1,406,310			762,614
Cash and equivalents, beginning of period and restricted cash		1,376,676			628,778
Effect of exchange rate changes on cash and equivalents		(8,499	)		(14,716	)
Cash, restricted cash and equivalents, end of period	$	2,774,487		$	1,376,676
Cash paid for interest		(2,458,205	)	$	(1,715,342	)
Cash paid for taxes	$	-		$	-

See accompanying Notes to Consolidated Financial Statements.

56 

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Operations.   Samson Oil & Gas Limited along with its consolidated subsidiaries (“Samson” or the “Company”), is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties in North Dakota and Montana.

Going concern. 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. The Company incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. At June 30, 2019, the Company’s total current liabilities of $43.3 million exceed its total current assets of $4.8 million. Its ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and/or raising further capital. These factors raise substantial doubt over the Company’s ability to continue as a going concern and therefore whether it will realize its assets and extinguish its liabilities in the normal course of business and at the amounts stated in the financial report.

At June 30, 2019, the Company was in breach of several of its covenants related to the Credit Agreement (defined in Note 8 – Credit Facility), resulting in borrowings payable of $33.5 million being classified as current liabilities. It is currently negotiating with the Lender in an effort to obtain a waiver for the breach. As of the date of this report, no waiver has been received.

The Company is currently negotiating with a prospective party to divest its oil and gas assets, as well as, continuing to execute on its drilling and development plan, which it believes will result in proceeds that will sufficiently cover the Company’s obligations to the Lender and its other creditors. Although the Company is confident it will be able to successfully recognize amounts in excess of the carrying value of its oil and gas assets as a result of its ultimate divestment or, alternatively, through the successful development of its Foreman Butte project, there can be no assurances made that the Company will be able to successfully execute these plans. Given the current financial situation it is possible that the Company may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Principles of Consolidation.   The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated in consolidation.

Certain amounts in prior year financial statements have been reclassified to current year presentation, and the reclassification had no impact on net loss.

Use of Estimates.   The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long–lived assets; (3) depreciation, depletion and amortization (“DD&A”); (4) asset retirement obligations (“ARO”); (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) certain accrued liabilities; (9) valuation of share-based payments, (10) income taxes and (11) carrying value of exploration and evaluation expenditures. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions through the date of this report for matters that may require recognition or disclosure in these financial statements.

Business Segment Information.   The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids (“NGL”). All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers.

Revenue Recognition and Gas Imbalances.   In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective July 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.

57 

The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at June 30, 2019 or 2018.

Cash and Cash Equivalents.   The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank.

Restricted cash. ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash) This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The Company has adopted this standard.

In accordance with the terms of our Credit Agreement, the Company is required to have a Capital Reserve Amount (as defined in the Credit Agreement) equal to $1.0 million and a Debt Service Reserve Amount (as defined in the Credit Agreement) equal to approximately $1.1 million. These amounts are carried on the balance sheet as Restricted Cash - Required reserve amounts related to Credit Agreement.

Accounts Receivable.   The components of accounts receivable include the following:

	June 30
	2019			2018
Oil and natural gas sales	$	1,538,451		$	1,159,905
Cost recovery from partners		650,885			768,281
Less provision for doubtful debts		(250,000	)		(75,000	)
Other		42,787			55,693
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018	$	1,982,123		$	1,908,879

The Company's accounts receivable’s result from; (i) oil and natural gas sales to oil and intrastate gas pipeline companies, (ii) billings to joint working interest partners in properties operated by the Company, and (iii) settlements for derivatives with our counter-party. The Company's trade and accrued production receivables are primarily from operated oil and gas properties. A portion of its oil and natural gas revenues are from non-operated oil and gas properties, whereby, the operators of the various projects negotiate the sale of oil and gas to third parties on the Company’s behalf. Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable.

At June 30, 2019 and 2018, the Company recorded an allowance for accounts receivable of $175,000 and $75,000, respectively.

Oil and Gas Properties.

Oil and gas properties and equipment consist of the following at June 30:

	2019			2018
Proved properties, net of impairment	$	39,666,294		$	38,110,237
Work in progress		40,319			8,271
Less accumulated depreciation, depletion and amortization		(9,491,784	)		(7,697,667	)
	$	30,214,829		$	30,420,841
Unproved acreage	$	-		$	-

58 

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly.

Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method. Mineral interests and leasehold acquisition costs are depleted over total proved reserves while costs of completed wells and related facilities and equipment are depleted over proved developed producing reserves.

If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Company. Impairment on properties sold is recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

Exploration and evaluation costs including capitalized exploration written off and dry hole expenses

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: 

59 

· 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 expenditure under our policy, the Company concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement.

During the fiscal years ended June 30, 2019, and 2018, we expensed $0 and $0.2 million, respectively, in deferred exploration expense.

Impairment 

The Company had no impairment charges for the years ended June 30, 2019, and 2018.

Other Property and Equipment.   

Other property and equipment, which includes leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight–line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended June 30, 2019, and 2018, was approximately $30,000 and $85,000, respectively.

Other property and equipment consist of the following at June 30:

	2019			2018
Furniture, fittings and equipment	$	930,173		$	1,017,879
Less accumulated depreciation		(755,242	)		(775,057	)
	$	174,931		$	242,822

Derivative Financial Instruments.   The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. All of the Company's derivative counterparties are major oil companies. The Company has elected not to apply hedge accounting to any of its derivative transactions and consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.

Asset Retirement Obligations.   The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long–lived asset are recorded at the time the well is spud or acquired.

Environmental.   The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non–capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company is not aware of any material noncompliance with existing laws and regulations.

Income Taxes.   Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.

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The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

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

	Year ended June 30,
	2019			2018
Net loss:	$	(7,148,031	)	$	(6,038,866	)
Basic and diluted weighted average common shares outstanding		328,300,044			328,300,044
Basic and diluted loss per common share – cents per share		(0.02	)		(0.02	)

Stock-Based Compensation.   Stock-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). The Company recognizes stock-based compensation net of an estimated forfeiture rate, and recognizes compensation expense only for shares that are expected to vest.  Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Foreign Currency Translation.   The functional currency of Samson Oil & Gas Limited (Parent Entity) is Australian dollars, the reason for this being the majority of cash flows of the Parent Entity are denominated in Australian dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S. dollars. The presentation currency of the Company is U.S. dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction.  Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income.

Business Combinations Samson applies the acquisition method in accounting for business combinations. The consideration transferred by the Company is calculated as the sum of the acquisition date fair value of assets transferred, liabilities incurred and any equity interests issued by the Company, which includes the fair value of any asset or liability arising from any contingent consideration arrangements. Acquisition costs are expensed as incurred. The Company treats the acquisition of oil and gas assets as a business combination.

The Company recognizes identifiable assets acquired and liabilities assumed in a business combination regardless of whether they have been previously recognized in the acquiree’s financial statements prior to the acquisition. Assets acquired and liabilities assumed are generally measured at their acquisition date fair values.

If the fair values of identifiable net assets exceed the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately.

Recently Issued Accounting Pronouncements

ASU 2016-02, Leases (Topic 842) In January 2016, ASC 842 was issued, which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. ASC 842 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments, as a right of use asset and respective liability. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss.

The Company operates predominantly as a lessee. The standard will affect primarily the accounting for its operating leases, with no significant impact expected for its finance leases. The new lease standard is effective for the Company on July 1, 2019, and will be adopted effective on that date using the simplified cumulative catch-up method. This adoption method will allow the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at July 1, 2019, will be made for the difference between the right of use asset and liability recorded. In addition, lease incentives will be rolled into the respective right of use asset, rather than recorded as a deferral. Upon adoption of the new standard, the Company intends to elect to apply hindsight in assessing the lease term, and to grandfather previous conclusions reached as to whether existing contracts are or contain leases. It continues to evaluate other practical elections, which may apply to individual asset classes and to portfolios of leases that contain similar characteristics. As of June 30, 2019, the Company had approximately $220,000 of contractual obligations related to its non-cancelable leases. The Company is in the process of evaluating those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASC 842. It is also in the process of implementing changes to its accounting policies, internal controls, and financial statements as a result of adoption of this standard. The Company will continue to assess the additional disclosures that will be required upon implementation of the standard.

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2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Rocky Mountain regions. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers.

The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for fiscal years ended June 30:

	2019		2018
Oil sales	$	12,391,536	$	9,931,065
Gas sales		257,895		118,783
Other liquids		13,434		8,871
Total oil and gas income	$	12,662,865	$	10,058,719

The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has two categories under which oil, gas, and NGL production revenue is generated, as summarized below:

1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.

2) The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.

Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead or inlet of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of June 30, 2019, and 2018, were $1.5 million and $1.0 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the fiscal year ended June 30, 2019, that related to performance obligations satisfied in prior reporting periods, was immaterial.

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3. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Agreements.   The Company utilizes swap and collar option contracts to hedge the effect of price changes on a portion of its future oil and natural gas production. The objective of the Company’s hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements. The Company may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of the Company’s existing positions. The Company may use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional unmitigated commodity price risk.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are with a single major oil company with no history of default with the Company. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

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

At June 30, 2019, 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 rather than the market price. If the market price is between the call and the put strike price, no payments are due from 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 and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with AEP I FINCO LLC, the Company’s lender. As such no collateral is required by the counterparty.

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During the third quarter of fiscal year ending June 30, 2019, the company entered into a series of swaps and costless collars for its oil and natural gas production. As of June 30, 2019, the Company had commodity derivative instruments outstanding through the first quarter of 2023, as summarized in the table below.

	Price per Bbl – WTI								Estimated
Asset (liability)	Floor		Ceiling		Swap				Fair Value
Year	$		$		$		Units (Bbl)		$
Crude Oil Derivatives
2019		N/A		N/A		55.75 – 58.10		109,000		(118,762	)
2020		N/A		N/A		55.39 – 57.05		200,000		38,418
2021		N/A		N/A		54.03 – 55.70		182,000		118,142
2022		N/A		N/A		53.15 – 55.70		163,000		134,254
2023		N/A		N/A		53.46 – 55.70		39,000		20,802
		N/A		N/A				693,000		192,854

	Price per Mcf – Henry Hub								Estimated
	Floor		Ceiling		Swap				Fair Value
Year	$		$		$		Units (Mcf)		$
Natural Gas Derivatives
2019	$	2.60	$	2.80	$	-		30,000		6,875
2020	$	2.60	$	2.80	$	-		63,900		7,709
2021	$	2.60	$	2.80	$	-		57,600		5,122
2022	$	2.60	$	2.80	$	-		51,300		3,676
2023	$	2.60	$	2.80	$	-		11,700		(1,397	)
								214,500		21,985

Derivative Assets and Liabilities Fair Value. The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the derivative commodity contracts was a net asset of $0.2 million at June 30, 2019, and a net liability of $1.2 million at June 30, 2018.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:

	As of June 30, 2019
	Derivative Assets			Derivative Liabilities
	Balance Sheet			Balance Sheet
	Classification	Fair Value		Classification	Fair Value
Commodity contracts	Current assets		-	Current liabilities		150,703
Commodity contracts	Noncurrent assets		365,542	Noncurrent liabilities		-
Total commodity contracts			365,542			150,703

	As of June 30, 2018
	Derivative Assets			Derivative Liabilities
	Balance Sheet			Balance Sheet
	Classification	Fair Value		Classification	Fair Value
Commodity contracts	Current assets		-	Current liabilities		1,210,795
Commodity contracts	Noncurrent assets		-	Noncurrent liabilities		-
Total commodity contracts			-			1,210,795

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Offsetting of Derivative Assets and Liabilities. As of June 30, 2019, and 2018, all derivative instruments held by the Company were subject to a master netting arrangement with one financial institution. In general, the terms of the Company’s agreement provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreement also provides that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying balance sheets.

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the fiscal years ended June 30, 2019, and 2018. The following table summarizes the components of the net derivative gain (loss) line item presented in the accompanying statements of operations:

	For the Years Ended June 30,
	2019			2018
Unrealized gain (loss) on derivatives		1,425,634			(946,438	)
Realized gain (loss) on derivatives		(968,418	)		(1,775,728	)
Total gain (loss) on derivatives		457,216			(2,722,166	)

See Note 4 for additional fair value disclosures about the Company’s oil and gas derivatives.

Credit Related Contingent Features. As of June 30, 2019, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group.  

4. 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 less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of June 30, 2019 and 2018.

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	Fair Value at June 30, 2019
	Level 1		Level 2			Level 3		Netting (1)			Total
Current Assets:
Cash, restricted cash and cash equivalents	$	2,774,487	$	-		$	-	$	-		$	2,774,487
Derivative Instruments		-		16,889			-		(16,889	)		-
Non Current Assets:
Derivative Instruments		-		377,845			-		(12,303	)		365,542
Current Liabilities
Derivative Instruments		-		(167,592	)		-		16,889			(150,703	)
Non Current Liabilities:
Derivative Instruments				(12,303	)		-		12,303			-

	Fair Value at June 30, 2018
	Level 1		Level 2		Level 3		Netting (1)			Total
Current Assets:
Cash and cash equivalents	$	1,376,676	$	-	$	-	$	-		$	1,376,676
Derivative Instruments		-		4,218		-		(4,218	)		-
Non Current Assets:
Derivative Instruments		-		-		-		-			-
Current Liabilities
Derivative Instruments		-		1,215,013		-		(4,218	)		1,210,795
Non Current Liabilities:
Derivative Instruments				-				-			-

(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:

Commodity Derivative Contracts.   The Company’s commodity derivative instruments consisted of collars and swap contracts for oil and natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as level 2 within the fair value hierarchy. The discount rates used in the assumptions include consideration of non-performance risk. The Company accounts for its commodity derivatives at fair value (see Note 3) on a recurring basis.

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

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

Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. The Company utilizes the discounted cash flow method; estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operational costs, and a risk–adjusted discount rate. The fair value measurement was based on Level 3 inputs.

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5. ASSET RETIREMENT OBLIGATIONS

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

The following table summarizes the activities for the Company’s asset retirement obligations for the years ended June 30:

	2019			2018
Asset retirement obligations at beginning of period	$	3,344,112		$	3,240,007
Liabilities incurred or acquired		-			-
Liabilities settled		(295,282	)		(73,667	)
Disposition of properties		-			(73,011	)
Accretion expense		561,950			250,783
Asset retirement obligations at end of period		3,610,780			3,344,112
Long-term asset retirement obligations	$	3,610,780		$	3,344,112

Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 13%.

6. INCOME TAXES

The Company accounts for income taxes under the asset and liability approach prescribed by GAAP, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s consolidated financial statements or tax returns.

The Company’s income tax provision (benefit) is composed of the following:

	June 30
	2019			2018
Current:
Federal	$	-		$	-
State		200			-
		200			-
Deferred:
Federal		(48,144	)		(732,056	)
State		-			-
Total income tax benefit	$	(47,944	)	$	(732,056	)

A reconciliation of the income tax provision (benefit) computed by applying the Australian federal statutory rate of 30% to the Company’s income tax provision (benefit) is as follows:

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	June 30
	2019			2018
Income tax expense (benefit) at federal statutory rate	$	(1,979,000	)	$	(1,956,277	)
Effect of Permanent Differences and Other-US		121,000			115,616
State Taxes, Net of Federal Benefit		(600,000	)		(123,694	)
Change in Valuation Allowance		1,692,000			(10,104,596	)
Change in Tax Rate		342,000			11,207,430
US income taxed at a different rate		432,000			116,777
Other		(55,944	)		12,688
Total income tax benefit	$	(47,944	)	$	(732,056	)

The components of the deferred tax assets and (liabilities) are as follows:

	June 30
	2019			2018
Deferred income tax assets:
Net operating losses	$	26,450,000		$	23,674,591
Asset retirement obligation		807,000			737,876
Abandonment limitation		-			544,869
Debt issuance costs		312,000			-
AMT Credit		780,000			780,443
Provision for Annual Leave		50,000			51,837
Allowance For Doubtful Accounts		59,000			17,558
Share based comp		459,000			500,845
Hedge Liability		-			283,458
Gross deferred tax assets	$	28,917,000		$	26,591,477
Deferred income tax liabilities:
Oil and gas property		(2,085,000	)		(1,908,395	)
Hedge Liability		(51,000	)		-
Gross deferred tax liabilities	$	(2,136,000	)	$	(1,908,395	)
Net deferred income tax assets (liabilities)		26,781,000			24,683,082
Valuation allowance		(26,001,000	)		(23,951,026	)
Noncurrent deferred tax asset	$	780,000		$	732,056

The Company has tax losses carried forward arising in Australia of $17.4 million.  The benefit of these losses of $4.8 million will only be obtained in future years if:

(i)	the Parent Entity derive future assessable income of a nature and an amount sufficient to enable the benefit from the deduction for the losses to be realized; and
(ii)	the Parent Entity have complied and continue to comply with the conditions for deductibility imposed by law; and
(iii)	no changes in tax legislation adversely affect the Parent Entity in realizing the benefit from deduction for the losses.

The Company has federal net operating tax losses in the United States of approximately $94.1 million.  The 2000-2005 years are limited to $403,194 per year as a result of a change in ownership of the one of the subsidiaries which occurred in January 2005. NOLs generated after this ownership change are not limited due to any known ownership changes.  If not utilized, the tax net operating losses will expire during the period from 2020 to 2038. NOL's generated in 2019 do not expire and can be carried forward indefinitely. Of the $9.2 million available as of July 1, 2011, $4.0 million will never be utilized and will expire by June 2025.

In addition to the above-mentioned Federal carried forward losses in the United States, the Company also has approximately $52.9 million of State carried forward tax losses, with expiry dates between 2020 and 2039.  A deferred income tax asset in relation to these losses has not been recognized as realization of the benefit is not regarded as probable.

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In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, Management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income. As of the current year end, the company does not believe the realizability of the deferred tax assets to be more likely than not except for AMT credits. As such, the company has a full valuation allowance offsetting the deferred tax asset, with the exception of the valuation allowance related to the refundable AMT Credit which is now realizable due to the tax law changes in the Tax Cuts and Jobs Act passed during 2018.

The Company adopted the uncertainty provision of FASB ASC Topic 740, "Income Taxes" and has analyzed filing positions in all federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in this jurisdiction. Most uncertain tax positions relate primarily to timing differences and management does not believe any such uncertain tax positions will materially impact the Company's effective tax rate in future periods. The Company anticipates that no additional uncertain tax positions will be recognized within the next twelve months. Our policy is to recognize any interest and penalties related to the unrecognized tax benefits in income tax expense. In our major tax jurisdictions, the earliest years remaining open to examination are as follows US - 6/30/1996 due to the usage of net operating losses from that period. If recognized, these uncertain tax positions would impact the Company's effective income tax rate. The company currently has no unrecognized positions.

7. COMMON STOCK

	June 30,
	2019		2018
328,300,044 ordinary fully paid shares including shares to be issued	$	106,743,167	$	106,743,167

	2019				2018
Movements in contributed equity for the year	No. of shares		$		No. of shares		$
Opening balance		328,300,044		106,743,167		328,300,044		106,390,864
Capital raising (i)		-		-		-		-
Shares issued upon exercise of options (ii)		-		-		-		-
Share based compensation		-		-		-		352,303
Transaction costs incurred		-		-		-		-
Shares on issue at balance date		328,300,044		106,743,167		328,300,044		106,743,167

8. CREDIT FACILITY

	June 30,
	2019			2018
Credit facility at beginning of period	$	23,867,557		$	23,419,749
Cash advanced under Credit Agreement		33,561,707			450,000
Repayments		(23,929,264	)		(2,192	)
Credit facility at end of period	$	33,500,000		$	23,867,557
Funds available for drawdown under the facility		-			-

On April 9, 2019, the Company closed a $33.5 million refinancing with AEP I FINCO LLC (“Lender”), as administrative agent, and certain other financial institutions (the “Credit Agreement”). The proceeds of the Credit Agreement were used to retire the Company’s previous credit facility of $23.9 million, repay outstanding creditors, royalty and working interest owners and provide working capital to pursue its infill development drilling program. In conjunction with the closing of the Credit Agreement, the Company paid $1.4 million in deferred borrowing costs.

The Credit Agreement is secured by certain of the Company’s oil and gas properties and has a 5-year term with a maturity date on 09 April 2024. Interest on the Credit Facility accrues at a rate equal to LIBOR plus a margin of 10.5% and is payable on the last day of each interest period. The effective interest rate at for fiscal year ended June 30, 2019, had a range between 5.0% and 13.0%.

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Under the Credit Facility, the Company is required to maintain the following financial ratios:

· a maximum Leverage Ratio, consisting of Consolidated Total Debt to Consolidated EBITDAX (as defined in the Credit Agreement) not to; (i) exceed 4.75 to 1.00 as of the last day of Fiscal Quarter (as defined in the Credit Facility) ending June 30, 2019, (ii) exceed 4.00 to 1.00 as of the last day of any Fiscal Quarter beginning after June 30, 2019, but ending on or before 31 March 2020; (iii) for Fiscal Quarters ending June 30, 2020, and September 30, 2020, to exceed 3.50 to 1.00, and (iv) for all Fiscal Quarters thereafter, exceed 3.00 to 1.00;

· a minimum Current Ratio, consisting of consolidated current assets (as defined in the Credit Agreement) to consolidated current liabilities (as defined in the Credit Agreement), of not less than 1.0 to 1.0 as of the last day of any Fiscal Quarter;

· an Asset Coverage Ratio, consisting of Modified Proved NPV (as defined in the Credit Agreement) to Consolidated Total Debt, beginning with Fiscal Quarter ending June 30, 2019, (i) to be less than 2.0 to 1.0 during any Fiscal Quarter ending before March 31, 2021, and (ii) for all Fiscal Quarters thereafter, to be less than 2.50 to 1.00;

· an Asset Coverage Ratio (PDP), consisting of Modified Proved NPV for PDP to Consolidated Total Debt, to be (i) less than 1.10 to 1.00 for Fiscal Quarter ending June 30, 2019, (ii) for Fiscal Quarters ending on September 30, 2019 and December 31, 2019, to be less than 1.15 to 1.00, (iii) during the Fiscal Quarter ended March 31, 2020, to be less than 1.25 to 1.00, (iv) for Fiscal Quarters ending on June 30, 2020, September 30, 2020, December 31, 2020, and March 31, 2021 to be less than 1.50 to 1.00, and (v) for all Fiscal Quarters thereafter, to be less than 1.75 to 1.00;a Fixed Charge Coverage Ratio, consisting of Consolidated EBITDAX for the Fiscal Quarter just ended, plus unrestricted cash and cash equivalents on the last day of the preceding Fiscal Quarter to Consolidated Fixed Charges (as defined in the Credit Facility) for the just ended Fiscal Quarter; (i) for the fiscal quarter ended June 30, 2019, to be less than 1.35 to 1.00, and (ii) for all Fiscal Quarters thereafter, to be less than 1.40 to 1.00; and

· the Company shall not make Capital Expenditures (as defined in the Credit Agreement) in any fiscal Quarter, beginning with the fiscal Quarter ended June 30, 2019, that would cause the aggregate amount of all Capital Expenditures in such Fiscal Quarter to exceed by more than (i) 10% the amount of Capital Expenditures for such Fiscal Quarter set forth on the then current and Approved Acquisition and Development Plan (defined in the Credit Agreement), or (ii) 10% the amount of the Capital Expenditures set forth in the then-current and Acquisition and Development Plan in the aggregate.

At June 30, 2019, the Company was not in compliance with certain financial covenants under the Credit Agreement, therefore, the total outstanding amount of the Credit Agreement has been categorized as a current liability and the deferred financing fees in the amount of $1.4 million, previously recorded as debt discount, have been expensed. Due to the Company’s recent breaches of the Credit Agreement, the Lender may declare an event of default and foreclose on some or all of the Company’s assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses.

9. SHARE-BASED PAYMENTS (all figures are in Australian dollars in this note unless noted otherwise)

During the year ended June 30, 2011, the Company registered a Form S-8 with the Securities Exchange Commission.  The Form S-8 is a registration statement used by U.S. public companies to register securities to be offered pursuant to employee benefit plans, in this case the ordinary shares issuable and reserved for issuance underlying the options which may be issued pursuant to the Samson Oil & Gas Limited Stock Option Plan were registered.

All incentive options issued by the Company are valued using a Black-Scholes pricing model which requires inputs for the share price at grant date, exercise price, time to expiry, risk free interest rate, share price volatility and dividend yield. The risk-free interest rate is based on the interest rate applicable to Australian Government Bonds with a similar remaining life to the options on the day of grant.   The dividend yield is the expected annual dividend yield over the expected life of the option.  The volatility factors are based on historic volatility of the Company’s stock.  Estimates of fair value are not intended to predict actual future events or the value ultimately realized by certain employees who receive stock options, and subsequent events are indicative of the reasonableness of the original fair value estimates.

No options were issued during the fiscal years ended June 30, 2019, and 2018, as share-based payments.

70 

The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 2019 and 2018 (all values in AUD unless otherwise noted):

	2019						2018
			Weighted		Aggregate					Weighted
			Average		Intrinsic					Average
			Exercise Price		Value of					Exercise Price
	Number		A$		A$		Number			A$
Outstanding, start of period		314,500,000		0.057		-		411,033,246			0.0118
Granted		-		-		-		-			-
Exercised		-		-		-		-			-
Cancelled/expired		-		-		-		(96,533,246	)		0.0380
Outstanding, end of period		314,500,000		0.057		-		314,500,000			0.0570
Exercisable, end of period		314,500,000		0.057		-		314,500,000			0.0570

 (1) The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date.  If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option.

No options were exercised during 2018.

Additional information related to options and warrants outstanding at June 30, 2019 are as follows:

	Options/Warrants Outstanding and Exercisable
			Weighted
			Average
Range of			Remaining
Exercise	Number		Contractual
Prices (A$)	Outstanding		Life - years
$0.070		48,000,000		7.42
$0.055		266,500,000		7.42
		314,500,000

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10. RELATED PARTY TRANSACTIONS

There were no related party transactions during the years ended June 30, 2019 and 2018.

11. COMMITMENTS

Leases –The Company has entered into a lease agreement for office space in Denver, Colorado. As of June 30, 2019, future minimum lease payments under this operating lease with remaining non–cancelable terms in excess of one year are

as follows:

	Total		2020		2021		2022		2023		Thereafter
Leases		219,643		103,616		107,080		8,947		-		-

72 

12. CONTINGENCIES

Samson may be subject to various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, and claims for underpayment of royalties, property damage claims and contract actions.

The Company records an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to its business operations is likely to have a material adverse effect on the company’s consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

13. SUBSEQUENT EVENTS

On September 4, 2019, the Company received an administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC). The notice makes claim to the status of certain shut-in wells and other location items operated by Samson. Samson submitted its formal response in September 2019, and has met with the NDIC concerning this matter and has presented the Company’s plan to address the administrative action. No final resolution or settlement has been entered into as of the filing of this report and the Company cannot reasonably estimate the amount of any potential penalties or fees that may be assessed against the Company at June 30, 2019, therefore, no accrual for potential contingent liabilities have been included in the Company’s financial statements.

14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES, INCLUSIVE OF DISCONTINUED OPERATIONS (UNAUDITED)

Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by Netherland, Sewell & Associates, Inc. All of the Company’s reserves were located in the United States.

Capitalized Costs Incurred. Costs incurred for oil and natural gas exploration, development and acquisition are summarized below.

	Year ended June 30,
	2019		2018
Development		1,462,483		13,272
Undeveloped capitalized acreage		-		-
Total costs incurred	$	1,462,483	$	13,272

Oil and Gas Reserve Quantities. The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure.

Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the fiscal years ended June 30, 2019, and 2018. The Company engaged Netherland, Sewell & Associates, Inc. to audit internal engineering estimates for 100 percent of the Company’s total calculated proved reserves PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

73 

	Year ended June 30, 2019									Year ended June 30, 2018
	Oil			Gas			Total			Oil			Gas			Total
	Mbbls			MMcf			MBOE			Mbbls			MMcf			MBOE
Beginning of year		3,515			1,292			3,732			5,359			3,565			5,954
Revisions of previous quantity estimates *		(361	)		(342	)		(419	)		(1,657	)		(2,258	)		(2,033	)
Extensions and discoveries		-			-			-			-			-			-
Sale of reserves in place		-			-			-			-			-			-
Acquisitions		-			-			-			-			-			-
Production		(224	)		(35	)		(230	)		(187	)		(15	)		(189	)
End of year		2,930			915			3,083			3,515			1,292			3,732
Proved developed producing reserves		2,930			915			3,083			2,663			623			2,768
Proved developed non producing *		-			-			-			544			418			614
Proved undeveloped reserves *		-			-			-			308			251			350
Total proved reserves		2,930			915			3,083			3,515			1,292			3,732

* Given the Company’s current financial condition there is no assurance that it will have the necessary financial resources available to meet the investment and operating criteria, as defined under SEC regulation, to execute the development plan necessary to include PDNP and PUD reserves in the Company’s reserve report.

Standardized Measure of Discounted Future Net Cash Flows. The Company computes a standardized measure of future net cash flows (“Standardized Measure”) and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10 percent annual discount factor. The impact of income taxes has not been included in the current or prior year, as the net operating losses and the tax basis of the assets exceed the future cash flows.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves in place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities.

The assumptions used to compute the Standardized Measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the Standardized Measure:

The following table shows the estimated standardized measure of discounted future net cash flows relating to proved reserves (in US$’000’s):

	As at June 30,
	2019			2018
Future cash inflows	$	166,709		$	187,249
Future production costs		(85,626	)		(99,620	)
Future development costs		-			(1,642	)
Future income taxes		-			-
Future net cashflows		81,083			85,987
10 % discount		(33,513	)		(38,325	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	47,570		$	47,662

74 

	Standardized Measure			PV10
Future cash inflows	$	166,709		$	97,805
Future production costs		(85,626	)		(50,235	)
Future development costs		-			-
Future income taxes		-			-
Future net cash flows		81,083			47,570
10% annual discount		(33,513	)		-
Discounted future net cash flows	$	47,570		$	47,570

The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2019 and June 30, 2018 are as follows (in US$’000’s):

	Fiscal Year Ended June 30
	2019			2018
Beginning of year	$	47,662		$	65,262
Sales of oil and gas, net of production costs and taxes		(321	)		(3,902	)
Extensions and discoveries, net of costs		-396			-
Purchases of reserves in place		-			-
Sales of reserves in place		-			-
Changes in prices and production costs		3,476			2,822
Revisions of previous quantity estimates and other		(8,884	)		(10,088	)
Previously estimated development costs incurred		-			-
Changes in estimated future development costs		502			(11,625	)
Accretion of discount		4,766			-
Net changes in income taxes		-			6,526
Changes in timing and other		(27	)		(1,333	)
Balance at end of year	$	47,570		$	47,662

The impact of income taxes has not been included in the current year as the Company’s net operating losses, the tax basis of oil and gas assets and future expected deductions, exceed the future cash flows.

75 

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Form S-3 Nos. 333-183327, and 333- 207306, and Form S-8 No. 333-173647) of our report dated October 15, 2019, relating to the consolidated financial statements of Samson Oil and Gas Limited, appearing in this Annual Report (Form 10-K) for the year ended June 30, 2019.

Our report dated October 15, 2019 contains an explanatory paragraph that states that the Company is in violation of its debt covenants, incurred a net loss from operations, has cash outflows from operations, and its current liabilities exceed its current assets as of and for the year ended June 30, 2019. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Moss Adams LLP

Denver, CO

October 15, 2019

EX-23.2

Exhibit 23.2

 

Mr. Terence M. Barr

Samson Oil & Gas Limited

1331 17th Street, Suite 710

Denver, Colorado 80202

Dear Mr. Barr:

In accordance with your request, we have estimated the proved reserves and future revenue, as of June 30, 2019, to the Samson Oil & Gas Limited (Samson) interest in certain oil and gas properties located in Montana, New Mexico, North Dakota, and Wyoming. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Samson. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Samson Oil & Gas Limited's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Samson interest in these properties, as of June 30, 2019, to be:

	Net Reserves		Future Net Revenue (M$)
	Oil	Gas		Present Worth
Category	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	2,930.1	0,915.0	081,082.8	47,570.0

The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As requested, proved developed non-producing, proved undeveloped, and probable reserves that may exist for these properties have not been included. No study was made to determine whether possible reserves might be established for these properties. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage.

Gross revenue is Samson's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Samson's share of production taxes, ad valorem taxes, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2018 through June 2019. For oil volumes, the average West Texas Intermediate spot price of $61.45 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.018 per MMBTU is adjusted for energy content, transportation fees, and market differentials. The adjusted product prices of $55.68 per barrel of oil and $3.890 per MCF of gas are held constant throughout the lives of the properties.

 

 

Operating costs used in this report are based on operating expense records of Samson. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and Samson's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs and are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Samson interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Samson receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Samson, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Samson, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Benjamin W. Johnson, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2007 and has over 2 years of prior industry experience. John G. Hattner, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
	/s/ Benjamin W. Johnson		/s/ John G. Hattner
By:		By:
	Benjamin W. Johnson, P.E. 124738		John G. Hattner, P.G. 559
	Vice President		Senior Vice President
Date Signed:  October 10, 2019		Date Signed:  October 10, 2019
BWJ:ADM

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Definitions - Page 2 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)	When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)	Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)	Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)	The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)	Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)	Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Definitions - Page 3 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

Definitions - Page 4 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

Definitions - Page 5 of 6

 

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

• The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company's historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Terence M. Barr, certify that:

1.   I have reviewed this annual report on Form 10-K of Samson Oil & Gas Limited;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.   The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)   Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the company’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.   The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

/s/ Terence M. Barr

Terence M. Barr

President, Chief Executive Officer and Managing Director

October 15, 2019

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Tristan Farel, certify that:

1.   I have reviewed this annual report on Form 10-K of Samson Oil & Gas Limited;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.   The company’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)   Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the company’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.   The company’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

/s/ Tristan Farel

Tristan Farel

Chief Financial Officer

October 15, 2019

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

         Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), the undersigned officers of Samson Oil & Gas Limited (the “Company”), do hereby certify, to such officer’s knowledge, that:

        (1)    The Annual Report on Form 10-K for the year ended June 30, 2019 (the “Report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

        (2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Terence M Barr

Terence M. Barr

President, Chief Executive Officer and Managing Director

October 15, 2019

/s/ Tristan Farel

Tristan Farel

Chief Financial Officer

October 15, 2019

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Subsequent Events

12 Months Ended

Jun. 30, 2019

Subsequent Events [Abstract]

Subsequent Events

13.  SUBSEQUENT EVENTS

On September 4, 2019, the Company received an administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC). The notice makes claim to the status of certain shut-in wells and other location items operated by Samson. Samson submitted its formal response in September 2019, and has met with the NDIC concerning this matter and has presented the Company’s plan to address the administrative action. No final resolution or settlement has been entered into as of the filing of this report and the Company cannot reasonably estimate the amount of any potential penalties or fees that may be assessed against the Company at June 30, 2019, therefore, no accrual for potential contingent liabilities have been included in the Company’s financial statements.

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Asset Retirement Obligations

12 Months Ended

Jun. 30, 2019

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

5. ASSET RETIREMENT OBLIGATIONS

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

The following table summarizes the activities for the Company’s asset retirement obligations for the years ended June 30:

	2019		2018
Asset retirement obligations at beginning of period	$	3,344,112	$	3,240,007
Liabilities incurred or acquired		-		-
Liabilities settled		(295,282)		(73,667)
Disposition of properties		-		(73,011)
Accretion expense		561,950		250,783
Asset retirement obligations at end of period		3,610,780		3,344,112
Long-term asset retirement obligations	$	3,610,780	$	3,344,112

Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4% and 13%.

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Share-Based Payments

12 Months Ended

Jun. 30, 2019

Share-Based Payments [Abstract]

Share-Based Payments

9. SHARE-BASED PAYMENTS (all figures are in Australian dollars in this note unless noted otherwise)

During the year ended June 30, 2011, the Company registered a Form S-8 with the Securities Exchange Commission.  The Form S-8 is a registration statement used by U.S. public companies to register securities to be offered pursuant to employee benefit plans, in this case the ordinary shares issuable and reserved for issuance underlying the options which may be issued pursuant to the Samson Oil & Gas Limited Stock Option Plan were registered.

All incentive options issued by the Company are valued using a Black-Scholes pricing model which requires inputs for the share price at grant date, exercise price, time to expiry, risk free interest rate, share price volatility and dividend yield. The risk-free interest rate is based on the interest rate applicable to Australian Government Bonds with a similar remaining life to the options on the day of grant.   The dividend yield is the expected annual dividend yield over the expected life of the option.  The volatility factors are based on historic volatility of the Company’s stock.  Estimates of fair value are not intended to predict actual future events or the value ultimately realized by certain employees who receive stock options, and subsequent events are indicative of the reasonableness of the original fair value estimates.

No options were issued during the fiscal years ended June 30, 2019, and 2018, as share-based payments.

The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 2019 and 2018 (all values in AUD unless otherwise noted):

	2019			2018
		Weighted	Aggregate		Weighted
		Average	Intrinsic		Average
		Exercise Price	Value of		Exercise Price
	Number	A$	A$	Number	A$
Outstanding, start of period	314,500,000	0.057	-	411,033,246	0.0118
Granted	-	-	-	-	-
Exercised	-	-	-	-	-
Cancelled/expired	-	-	-	(96,533,246)	0.0380
Outstanding, end of period	314,500,000	0.057	-	314,500,000	0.0570
Exercisable, end of period	314,500,000	0.057	-	314,500,000	0.0570

(1) The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date.  If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option.

No options were exercised during 2018.

Additional information related to options and warrants outstanding at June 30, 2019 are as follows:

	Options/Warrants Outstanding and Exercisable
		Weighted
		Average
Range of		Remaining
Exercise	Number	Contractual
Prices (A$)	Outstanding	Life - years
$0.070	48,000,000		7.42
$0.055	266,500,000		7.42
	314,500,000

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Summary Of Significant Accounting Policies (Schedule Of Other Property And Equipment) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Summary Of Significant Accounting Policies [Abstract]
Furniture, fittings and equipment	$ 930,173	$ 1,017,879
Less accumulated depreciation	(755,241)	(775,057)
Total other property and equipment	$ 174,931	$ 242,822

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Tables)

12 Months Ended

Jun. 30, 2019

Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]

Summary Of Costs Incurred For Oil And Natural Gas Exploration, Development And Acquisition

	Year ended June 30,
	2019		2018
Development		1,462,483		13,272
Undeveloped capitalized acreage		-		-
Total costs incurred	$	1,462,483	$	13,272

Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities

	Year ended June 30, 2019			Year ended June 30, 2018
	Oil	Gas	Total	Oil	Gas	Total
	Mbbls	MMcf	MBOE	Mbbls	MMcf	MBOE
Beginning of year	3,515	1,292	3,732	5,359	3,565	5,954
Revisions of previous quantity estimates *	(361)	(342)	(419)	(1,657)	(2,258)	(2,033)
Extensions and discoveries	-	-	-	-	-	-
Sale of reserves in place	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-
Production	(224)	(35)	(230)	(187)	(15)	(189)
End of year	2,930	915	3,083	3,515	1,292	3,732
Proved developed producing reserves	2,930	915	3,083	2,663	623	2,768
Proved developed non producing *	-	-	-	544	418	614
Proved undeveloped reserves *	-	-	-	308	251	350
Total proved reserves	2,930	915	3,083	3,515	1,292	3,732

*Given the Company’s current financial condition there is no assurance that it will have the necessary financial resources available to meet the investment and operating criteria, as defined under SEC regulation, to execute the development plan necessary to include PDNP and PUD reserves in the Company’s reserve report.

Schedule Of Estimated Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Reserves

	As at June 30,
	2019		2018
Future cash inflows	$	166,709	$	187,249
Future production costs		(85,626)		(99,620)
Future development costs		-		(1,642)
Future income taxes		-		-
Future net cashflows		81,083		85,987
10 % discount		(33,513)		(38,325)
Standardized measure of discounted future net cash flows relating to proved reserves	$	47,570	$	47,662

	Standardized Measure		PV10
Future cash inflows	$	166,709	$	97,805
Future production costs		(85,626)		(50,235)
Future development costs		-		-
Future income taxes		-		-
Future net cash flows		81,083		47,570
10% annual discount		(33,513)		-
Discounted future net cash flows	$	47,570	$	47,570

Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows

	Fiscal Year Ended June 30
	2019		2018
Beginning of year	$	47,662	$	65,262
Sales of oil and gas, net of production costs and taxes		(321)		(3,902)
Extensions and discoveries, net of costs		396		-
Purchases of reserves in place		-		-
Sales of reserves in place		-		-
Changes in prices and production costs		3,476		2,822
Revisions of previous quantity estimates and other		(8,884)		(10,088)
Previously estimated development costs incurred		-		-
Changes in estimated future development costs		502		(11,625)
Accretion of discount		4,766		-
Net changes in income taxes		-		6,526
Changes in timing and other		(27)		(1,333)
Balance at end of year	$	47,570	$	47,662

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Credit Facility (Narrative) (Details)		12 Months Ended
	Apr. 09, 2019 USD ($)	Jun. 30, 2019 USD ($)
Line of Credit Facility [Line Items]
Payments for costs associated with borrowings		$ 1,390,565
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 33,500,000
Payments for costs associated with borrowings	1,400,000	$ 1,400,000
Term		5 years
Line of credit facility, expiration date		Apr. 09, 2024
Debt instrument, basis spread on variable rate		10.50%
Previous Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 23,900,000
Minimum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Debt instrument, interest rate at period end		5.00%
Current ratio		1.0
Maximum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Debt instrument, interest rate at period end		13.00%
Maximum [Member] | Credit Agreement [Member] | Date [Member]
Line of Credit Facility [Line Items]
Debt to EBITDAX		4.75
Maximum [Member] | Credit Agreement [Member] | Date B [Member]
Line of Credit Facility [Line Items]
Debt to EBITDAX		4.00
Maximum [Member] | Credit Agreement [Member] | Date C [Member]
Line of Credit Facility [Line Items]
Debt to EBITDAX		3.50
Maximum [Member] | Credit Agreement [Member] | Date D [Member]
Line of Credit Facility [Line Items]
Debt to EBITDAX		3.00
Maximum [Member] | Credit Agreement [Member] | Date E [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio		2.0
Maximum [Member] | Credit Agreement [Member] | Date F [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio		2.50
Maximum [Member] | Credit Agreement [Member] | Date G [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio (PDP)		1.10
Maximum [Member] | Credit Agreement [Member] | Date H [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio (PDP)		1.15
Maximum [Member] | Credit Agreement [Member] | Date I [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio (PDP)		1.25
Maximum [Member] | Credit Agreement [Member] | Date J [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio (PDP)		1.50
Maximum [Member] | Credit Agreement [Member] | Date K [Member]
Line of Credit Facility [Line Items]
Asset Coverage Ratio (PDP)		1.75
Maximum [Member] | Credit Agreement [Member] | Date L [Member]
Line of Credit Facility [Line Items]
Fixed Charge Coverage Ratio		1.35
Maximum [Member] | Credit Agreement [Member] | Date M [Member]
Line of Credit Facility [Line Items]
Fixed Charge Coverage Ratio		1.40
Maximum [Member] | Credit Agreement [Member] | Date N [Member]
Line of Credit Facility [Line Items]
Capital Expenditures		10.00%
Maximum [Member] | Credit Agreement [Member] | Date O [Member]
Line of Credit Facility [Line Items]
Capital Expenditures		10.00%

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Share-Based Payments (Schedule Of Additional Information Related To Options Outstanding) (Details)	12 Months Ended
	Jun. 30, 2019 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Outstanding	314,500,000
$0.070 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Max | $ / shares	$ 0.070
Number Outstanding	48,000,000
Weighted Average Remaining Contractual Life - years	7 years 5 months 1 day
$0.055 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Range of Exercise Prices, Min | $ / shares	$ 0.055
Number Outstanding	266,500,000
Weighted Average Remaining Contractual Life - years	7 years 5 months 1 day

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Asset Retirement Obligations (Summary Of Activities Of Asset Retirement Obligations) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Asset Retirement Obligations [Abstract]
Asset retirement obligations at beginning of period	$ 3,344,112	$ 3,240,007
Liabilities incurred or acquired
Liabilities settled	(295,282)	(73,667)
Disposition of properties		(73,011)
Accretion expense	561,950	250,783
Asset retirement obligations at end of period	3,610,780	3,344,112
Long-term asset retirement obligations	$ 3,610,780	$ 3,344,112

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Hedging And Derivative Financial Instruments (Fair Value Of Derivatives) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Hedging And Derivative Financial Instruments [Abstract]
Noncurrent assets	$ 365,542
Assets	365,542
Current liabilities	150,703	$ 1,210,795
Liabilities	$ 150,703	$ 1,210,795

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Estimated Standard Measure Of Discounted Future Net CF Relating To Proved Reserves) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2017
Standardized Measure [Abstract]
Future cash inflows	$ 166,709	$ 187,249
Future production costs	(85,626)	(99,620)
Future development costs		(1,642)
Future net cashflows	81,083	85,987
10% discount	(33,513)	(38,325)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	47,570	$ 47,662	$ 65,262
PV10 [Abstract]
Future cash inflows	97,805
Future production costs	(50,235)
Future net cashflows	47,570
Discounted future net cash flows	$ 47,570

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Revenue From Contracts With Customers (Tables)

12 Months Ended

Jun. 30, 2019

Revenue From Contracts With Customers [Abstract]

Disaggregation of Revenue

	2019		2018
Oil sales	$	12,391,536	$	9,931,065
Gas sales		257,895		118,783
Other liquids		13,434		8,871
Total oil and gas income	$	12,662,865	$	10,058,719

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Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash Flows from Operating Activities:
Net loss	$ (7,148,031)	$ (6,038,866)
Adjustments to reconcile net loss to net cash provided by (used) for operating activities:
Depreciation, depletion and amortization	1,824,014	1,237,989
Accretion of discount on asset retirement obligations	561,950	250,783
Exploration and evaluation assets written off		325,290
Unrealized (gain) loss on derivative instruments	(1,425,634)	946,438
Share based compensation		352,303
Amortization of debt discount	1,390,564	32,808
Settlement of asset retirement obligations	(295,282)	(289,896)
Provision for bad debt expense	175,000	75,000
Write-off of uncollectible accounts receivable's	22,346
Oil inventory	219,288
Gain on sale of properties	(120,000)	(178,407)
Deferred tax asset	(47,944)	(732,056)
Changes in operating assets and liabilities:
Accounts receivables	(270,590)	(284,023)
Prepayments	137,342	(82,823)
Accounts payable	(376,509)	4,702,429
Accrued liabilities	(38,979)	268,785
Deposits	24,999	156,535
Net cash (used in) provided from operating activities	(5,367,466)	742,289
Cash Flows from Investing Activities:
Proceeds from sale of oil and gas properties	120,000	105,396
Payments for oil and gas properties	(1,588,102)	(414,480)
Payments for exploration and evaluation, net		(54,212)
Payments for furniture and fittings		(31,379)
Net cash flows used in investing activities	(1,468,102)	(394,675)
Cash Flows from Financing Activities:
Proceeds from borrowings	33,561,707	450,000
Repayments of borrowings	(23,929,264)	(35,000)
Payments for costs associated with borrowings	(1,390,565)
Net cash provided by financing activities	8,241,878	415,000
Net increase in cash and equivalents and restricted cash	1,406,310	762,614
Cash and equivalents, beginning of period and restricted cash	1,376,676	628,778
Effect of exchange rate changes on cash and equivalents	(8,499)	(14,716)
Cash, restricted cash and equivalents, end of period	2,774,487	1,376,676
Cash paid for interest	(2,458,205)	(1,715,342)
Cash paid for taxes

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Consolidated Balance Sheets - USD ($)	Jun. 30, 2019	Jun. 30, 2018
CURRENT ASSETS
Cash and cash equivalents	$ 685,737	$ 1,376,676
Restricted cash - required reserve amounts related to Credit Agreement	2,088,750
Accounts receivable, net of allowance for doubtful accounts of $250,000 and $75,000, respectively	1,982,123	1,908,879
Oil Inventory		219,288
Prepayments		137,342
Total current assets	4,756,610	3,642,185
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, net, successful efforts method of accounting, less accumulated depreciation, depletion and amortization of $9,491,784 and $6,105,315 at June 30, 2019, and 2018, respectively	30,214,829	30,420,841
Other property and equipment, net of accumulated depreciation and amortization of $755,241 and $775,057 at June 30, 2019 and June 30, 2018, respectively	174,931	242,822
Net property, plant and equipment	30,389,760	30,663,663
OTHER ASSETS
Fair value of derivative instruments	365,542
Deposits	559,722	584,644
Deferred tax asset	780,000	732,056
TOTAL ASSETS	36,851,634	35,622,548
CURRENT LIABILITIES
Accounts payable	8,121,217	8,532,987
Accrued liabilities	1,300,185	1,339,164
Fair value of derivative instruments	150,703	1,210,795
Current portion of asset retirement obligation	274,404
Current portion of credit facility	33,500,000	23,867,558
Total current liabilities	43,346,509	34,950,504
Asset retirement obligations	3,336,376	3,344,112
Total liabilities	46,682,885	38,294,616
Commitments and contingencies (Note 11 & 12)
STOCKHOLDERS' EQUITY (DEFICIT)
Common stock, 328,300,044 shares issued and outstanding at June 30, 2019 and 2018	106,743,167	106,743,167
Accumulated other comprehensive income	835,404	846,556
Accumulated deficit	(117,409,822)	(110,261,791)
Total stockholders' deficit	(9,831,251)	(2,672,068)
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT	$ 36,851,634	$ 35,622,548

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Income Taxes (Tables)

12 Months Ended

Jun. 30, 2019

Income Taxes [Abstract]

Schedule Of Components Of Income Tax Provision (Benefit)

	June 30
	2019		2018
Current:
Federal	$	-	$	-
State		200		-
		200		-
Deferred:
Federal		(48,144)		(732,056)
State		-		-
Total income tax benefit	$	(47,944)	$	(732,056)

Schedule Of Effective Income tax Rate Reconciliation

		June 30
	2019		2018
Income tax expense (benefit) at federal statutory rate	$	(1,979,000)	$	(1,956,277)
Effect of Permanent Differences and Other-US		121,000		115,616
State Taxes, Net of Federal Benefit		(600,000)		(123,694)
Change in Valuation Allowance		1,692,000		(10,104,596)
Change in Tax Rate		342,000		11,207,430
US income taxed at a different rate		432,000		116,777
Other		(55,944)		12,688
Total income tax benefit	$	(47,944)	$	(732,056)

Schedule Of Components Of Deferred Tax Assets and (Liabilities)

	June 30
	2019		2018
Deferred income tax assets:
Net operating losses	$	26,450,000	$	23,674,591
Asset retirement obligation		807,000		737,876
Abandonment limitation		-		544,869
Debt issuance costs		312,000		-
AMT Credit		780,000		780,443
Provision for Annual Leave		50,000		51,837
Allowance For Doubtful Accounts		59,000		17,558
Share based comp		459,000		500,845
Hedge Liability		-		283,458
Gross deferred tax assets	$	28,917,000	$	26,591,477
Deferred income tax liabilities:
Oil and gas property		(2,085,000)		(1,908,395)
Hedge Liability		(51,000)		-
Gross deferred tax liabilities	$	(2,136,000)	$	(1,908,395)
Net deferred income tax assets (liabilities)		26,781,000		24,683,082
Valuation allowance		(26,001,000)		(23,951,026)
Noncurrent deferred tax asset	$	780,000	$	732,056

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Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Income Taxes [Line Items]
Tax expense (benefit)	$ 200
Tax Year 2011 [Member]
Income Taxes [Line Items]
Net operating tax losses	$ 9,200,000
Australian Taxation Office [Member]
Income Taxes [Line Items]
Federal statutory rate	30.00%
Tax losses carried forward	$ 17,400,000
Benefit of tax losses carried forward	4,800,000
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Net operating tax losses	94,100,000
Limitation per year	$ 403,194
Internal Revenue Service (IRS) [Member] | Tax Year 2011 [Member]
Income Taxes [Line Items]
Net operating losses, expiration year	Jun. 30, 2025
Amount not utilized	$ 4,000,000
Minimum [Member] | Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Net operating losses, expiration year	Jan. 01, 2020
Minimum [Member] | State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Net operating losses, expiration year		Dec. 31, 2020
Maximum [Member] | Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Net operating losses, expiration year	Dec. 31, 2038
Maximum [Member] | State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Net operating losses, expiration year		Dec. 31, 2039

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Hedging And Derivative Financial Instruments (Componenets Of Derivative (Gain) Loss) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Hedging And Derivative Financial Instruments [Abstract]
Unrealized gain (loss) on derivatives	$ 1,425,634	$ (946,438)
Realized gain (loss) on derivatives	(968,418)	(1,775,728)
Total gain (loss) on derivatives	$ 457,216	$ (2,722,166)

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details)	12 Months Ended
	Jun. 30, 2019 MBoe MBbls MMcf	Jun. 30, 2018 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Proved Developed Reserves ProductionBOE | MBoe	(230)	(189)
Beginning of year (BOE) | MBoe	3,732	5,954
Revisions of previous quantity estimates (BOE) | MBoe	(419)	(2,033)
End of year (BOE) | MBoe	3,083	3,732
Proved developed producing reserves (BOE) | MBoe	3,083	2,768
Proved undeveloped reserves (BOE) | MBoe		350
Proved Developed Non Producing (BOE) | MBoe		614
Proved reserves (BOE) | MBoe	3,083	3,732
Oil [Member]
Reserve Quantities [Line Items]
Beginning of year (Volume) | MBbls	3,515	5,359
Revisions of previous quantity estimates (Volume) | MBbls	(361)	(1,657)
Production (Volume) | MBbls	(224)	(187)
End of year (Volume) | MBbls	2,930	3,515
Proved developed producing reserves (Volume) | MBbls	2,930	2,663
Proved Developed Non Producing (Volume) | MBbls		544
Proved undeveloped reserves (Volume) | MBbls		308
Proved reserves (Volume) | MBbls	2,930	3,515
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of year (Volume) | MMcf	1,292	3,565
Revisions of previous quantity estimates (Volume) | MMcf	(342)	(2,258)
Production (Volume) | MMcf	(35)	(15)
End of year (Volume) | MMcf	915	1,292
Proved developed producing reserves (Volume) | MMcf	915	623
Proved Developed Non Producing (Volume) | MMcf		418
Proved undeveloped reserves (Volume) | MMcf		251
Proved reserves (Volume) | MMcf	915	1,292

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Jun. 30, 2019

Summary Of Significant Accounting Policies [Abstract]

Schedule Of Components Of Accounts Receivable

	June 30
	2019		2018
Oil and natural gas sales	$	1,538,451	$	1,159,905
Cost recovery from partners		650,885		768,281
Less provision for doubtful debts		(250,000)		(75,000)
Other		42,787		55,693
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018	$	1,982,123	$	1,908,879

Schedule Of Oil And Gas Properties And Equipment

	2019		2018
Proved properties, net of impairment	$	39,666,294	$	38,110,237
Work in progress		40,319		8,271
Less accumulated depreciation, depletion and amortization		(9,491,784)		(7,697,667)
	$	30,214,829	$	30,420,841
Unproved acreage	$	-	$	-

Schedule Of Other Property And Equipment

	2019		2018
Furniture, fittings and equipment	$	930,173	$	1,017,879
Less accumulated depreciation		(755,242)		(775,057)
	$	174,931	$	242,822

Schedule Of Earnings Per Share, Basic And Diluted

	Year ended June 30,
	2019		2018
Net loss:	$	(7,148,031)	$	(6,038,866)
Basic and diluted weighted average common shares outstanding		328,300,044		328,300,044
Basic and diluted loss per common share – cents per share		(0.02)		(0.02)

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Summary Of Significant Accounting Policies

12 Months Ended

Jun. 30, 2019

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Description of Operations.   Samson Oil & Gas Limited along with its consolidated subsidiaries (“Samson” or the “Company”), is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties in North Dakota and Montana.

Going concern. 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. The Company incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. At June 30, 2019, the Company’s total current liabilities of $43.3 million exceed its total current assets of $4.8 million. Its ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and/or raising further capital. These factors raise substantial doubt over the Company’s ability to continue as a going concern and therefore whether it will realize its assets and extinguish its liabilities in the normal course of business and at the amounts stated in the financial report.

AtJune 30, 2019, the Companywas in breach of several of its covenants related to the Credit Agreement (defined in Note 8 – Credit Facility), resulting in borrowings payable of $33.5 million being classified as current liabilities. It is currently negotiating with the Lender in an effort to obtain a waiver for the breach. As of the date of this report, no waiver has been received.

The Company is currently negotiating with a prospective party to divest its oil and gas assets,as well as, continuing to execute on its drilling and development plan, which it believes will result in proceeds that will sufficientlycover the Company’s obligations to the Lender and its other creditors. Although the Company is confident it will be able to successfully recognize amounts in excess of the carrying value of its oil and gas assets as a result of its ultimate divestment or, alternatively, through the successful development of its Foreman Butte project, there can be no assurances made that the Company will be able to successfully execute these plans. Given the current financial situation it is possible that the Company may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Principles of Consolidation.   The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated in consolidation.

Certain amounts in prior year financial statements have been reclassified to current year presentation, and the reclassification had no impact on net loss.

Use of Estimates.   The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long–lived assets; (3) depreciation, depletion and amortization (“DD&A”); (4) asset retirement obligations (“ARO”); (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) certain accrued liabilities; (9) valuation of share-based payments, (10) income taxes and (11) carrying value of exploration and evaluation expenditures. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions through the date of this report for matters that may require recognition or disclosure in these financial statements.

Business Segment Information.   The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids (“NGL”). All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers.

Revenue Recognition and Gas Imbalances.   In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective July 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.

The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at June 30, 2019 or 2018.

Cash and Cash Equivalents.   The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank.

Restricted cash.ASU 2016-18,  Statement of Cash Flows (Topic 230): Restricted Cash)This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The Company has adopted this standard.

In accordance with the terms of our Credit Agreement, the Company is required to have a Capital Reserve Amount (as defined in the Credit Agreement) equal to $1.0 million and a Debt Service Reserve Amount (as defined in the Credit Agreement) equal to approximately $1.1 million.  These amounts are carried on the balance sheet as Restricted Cash-Required reserve amounts related to Credit Agreement. 

Accounts Receivable.   The components of accounts receivable include the following:

	June 30
	2019		2018
Oil and natural gas sales	$	1,538,451	$	1,159,905
Cost recovery from partners		650,885		768,281
Less provision for doubtful debts		(250,000)		(75,000)
Other		42,787		55,693
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018	$	1,982,123	$	1,908,879

The Company's accounts receivable’s result from; (i) oil and natural gas sales to oil and intrastate gas pipeline companies, (ii) billings to joint working interest partners in properties operated by the Company, and (iii) settlements for derivatives with our counter-party. The Company's trade and accrued production receivables are primarily from operated oil and gas properties. A portion of its oil and natural gas revenues are from non-operated oil and gas properties, whereby, the operators of the various projects negotiate the sale of oil and gas to third parties on the Company’s behalf.  Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable.

At June 30, 2019 and 2018, the Company recorded an allowance for accounts receivable of $175,000 and $75,000, respectively.

Oil and Gas Properties.

Oil and gas properties and equipment consist of the following at June 30:

	2019		2018
Proved properties, net of impairment	$	39,666,294	$	38,110,237
Work in progress		40,319		8,271
Less accumulated depreciation, depletion and amortization		(9,491,784)		(7,697,667)
	$	30,214,829	$	30,420,841
Unproved acreage	$	-	$	-

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly.

Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method.  Mineral interests and leasehold acquisition costs are depleted over total proved reserves while costs of completed wells and related facilities and equipment are depleted over proved developed producing reserves.

If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Company. Impairment on properties sold is recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

Exploration and evaluation costs including capitalized exploration written off and dry hole expenses

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 expenditure under our policy, the Company concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement.

During the fiscal years ended June 30, 2019, and 2018, we expensed $0 and $0.2 million, respectively, in deferred exploration expense.

Impairment

The Company had no impairment charges for the years ended June 30, 2019, and 2018.

Other Property and Equipment.

Other property and equipment, which includes leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight–line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended June 30, 2019, and 2018, was approximately $30,000 and $85,000, respectively.

Other property and equipment consist of the following at June 30:

	2019		2018
Furniture, fittings and equipment	$	930,173	$	1,017,879
Less accumulated depreciation		(755,242)		(775,057)
	$	174,931	$	242,822

Derivative Financial Instruments.   The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. All of the Company's derivative counterparties are major oil companies.  The Company has elected not to apply hedge accounting to any of its derivative transactions and consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. 

Asset Retirement Obligations.   The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long–lived asset are recorded at the time the well is spud or acquired.

Environmental.   The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non–capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company is not aware of any material noncompliance with existing laws and regulations.

Income Taxes.   Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

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

	Year ended June 30,
	2019		2018
Net loss:	$	(7,148,031)	$	(6,038,866)
Basic and diluted weighted average common shares outstanding		328,300,044		328,300,044
Basic and diluted loss per common share – cents per share		(0.02)		(0.02)

Stock-Based Compensation.   Stock-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). The Company recognizes stock-based compensation net of an estimated forfeiture rate, and recognizes compensation expense only for shares that are expected to vest.  Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Foreign Currency Translation.   The functional currency of Samson Oil & Gas Limited (Parent Entity) is Australian dollars, the reason for this being the majority of cash flows of the Parent Entity are denominated in Australian dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S. dollars. The presentation currency of the Company is U.S. dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction.  Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income.

Business Combinations Samson applies the acquisition method in accounting for business combinations.  The consideration transferred by the Company is calculated as the sum of the acquisition date fair value of assets transferred, liabilities incurred and any equity interests issued by the Company, which includes the fair value of any asset or liability arising from any contingent consideration arrangements.  Acquisition costs are expensed as incurred. The Company treats the acquisition of oil and gas assets as a business combination.

The Company recognizes identifiable assets acquired and liabilities assumed in a business combination regardless of whether they have been previously recognized in the acquiree’s financial statements prior to the acquisition.  Assets acquired and liabilities assumed are generally measured at their acquisition date fair values.

If the fair values of identifiable net assets exceed the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. 

Recently Issued Accounting Pronouncements

ASU 2016-02, Leases (Topic 842)In January 2016, ASC 842 was issued, which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. ASC 842 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments, as a right of use asset and respective liability. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss.

The Company operates predominantly as a lessee. The standard will affect primarily the accounting for its operating leases, with no significant impact expected for its finance leases. The new lease standard is effective for the Company on July 1, 2019, and will be adopted effective on that date using the simplified cumulative catch-up method. This adoption method will allow the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at July 1, 2019, will be made for the difference between the right of use asset and liability recorded. In addition, lease incentives will be rolled into the respective right of use asset, rather than recorded as a deferral. Upon adoption of the new standard, the Company intends to elect to apply hindsight in assessing the lease term, and to grandfather previous conclusions reached as to whether existing contracts are or contain leases. It continues to evaluate other practical elections, which may apply to individual asset classes and to portfolios of leases that contain similar characteristics. As of June 30, 2019, the Company had approximately $220,000 of contractual obligations related to its non-cancelable leases. The Company is in the process of evaluating those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASC 842. It is also in the process of implementing changes to its accounting policies, internal controls, and financial statements as a result of adoption of this standard. The Company will continue to assess the additional disclosures that will be required upon implementation of the standard.

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Consolidated Balance Sheets (Parenthetical) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Consolidated Balance Sheets [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 250,000	$ 75,000
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion Amortization and Impairment	9,491,784	6,105,315
Other property and equipment, accumulated depreciation and amortization	$ 755,241	$ 775,057
Common stock, shares issued	328,300,044	328,300,044
Common stock, shares outstanding	328,300,044	328,300,044

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Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2019

Asset Retirement Obligations [Abstract]

Summary Of Activities For Asset Retirement Obligations

	2019		2018
Asset retirement obligations at beginning of period	$	3,344,112	$	3,240,007
Liabilities incurred or acquired		-		-
Liabilities settled		(295,282)		(73,667)
Disposition of properties		-		(73,011)
Accretion expense		561,950		250,783
Asset retirement obligations at end of period		3,610,780		3,344,112
Long-term asset retirement obligations	$	3,610,780	$	3,344,112

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Fair Value Measurements

12 Months Ended

Jun. 30, 2019

Fair Value Measurements [Abstract]

Fair Value Measurements

4. 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 less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of June 30, 2019 and 2018.

	Fair Value at June 30, 2019
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash, restricted cash and cash equivalents	$	2,774,487	$	-	$	-	$	-	$	2,774,487
Derivative Instruments		-		16,889		-		(16,889)		-
Non Current Assets:
Derivative Instruments		-		377,845		-		(12,303)		365,542
Current Liabilities
Derivative Instruments		-		(167,592)		-		16,889		(150,703)
Non Current Liabilities:
Derivative Instruments				(12,303)		-		12,303		-
	Fair Value at June 30, 2018
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash and cash equivalents	$	1,376,676	$	-	$	-	$	-	$	1,376,676
Derivative Instruments		-		4,218		-		(4,218)		-
Non Current Assets:
Derivative Instruments		-		-		-		-		-
Current Liabilities
Derivative Instruments		-		1,215,013		-		(4,218)		1,210,795
Non Current Liabilities:
Derivative Instruments				-				-		-

(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:

Commodity Derivative Contracts.   The Company’s commodity derivative instruments consisted of collars and swap contracts for oil and natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as level 2 within the fair value hierarchy. The discount rates used in the assumptions include consideration of non-performance risk. The Company accounts for its commodity derivatives at fair value (see Note 3) on a recurring basis.

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

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

Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. The Company utilizes the discounted cash flow method; estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operational costs, and a risk–adjusted discount rate. The fair value measurement was based on Level 3 inputs.

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Credit Facility

12 Months Ended

Jun. 30, 2019

Credit Facility [Abstract]

Credit Facility

8.   CREDIT FACILITY

	June 30,
	2019		2018
Credit facility at beginning of period	$	23,867,557	$	23,419,749
Cash advanced under Credit Agreement		33,561,707		450,000
Repayments		(23,929,264)		(2,192)
Credit facility at end of period	$	33,500,000	$	23,867,557
Funds available for drawdown under the facility		-		-

On April 9, 2019, the Company closed a $33.5 million refinancing with AEP I FINCO LLC (“Lender”), as administrative agent, and certain other financial institutions (the “Credit Agreement”).  The proceeds of the Credit Agreement were used to retire the Company’s previous credit facility of $23.9 million, repay outstanding creditors, royalty and working interest owners and provide working capital to pursue its infill development drilling program. In conjunction with the closing of the Credit Agreement, the Company paid $1.4 million in deferred borrowing costs.

The Credit Agreement is secured by certain of the Company’s oil and gas properties and has a 5-year term with a maturity date on 09 April 2024. Interest on the Credit Facility accrues at a rate equal to LIBOR plus a margin of 10.5% and is payable on the last day of each interest period. The effective interest rate at for fiscal year ended June 30, 2019, had a range between 5.0% and 13.0%.

Under the Credit Facility, the Company is required to maintain the following financialratios:

· a maximum Leverage Ratio, consisting of Consolidated Total Debt to Consolidated EBITDAX (as defined in the Credit Agreement) not to; (i) exceed 4.75 to 1.00 as of the last day of Fiscal Quarter (as defined in the Credit Facility) ending June 30, 2019, (ii) exceed 4.00 to 1.00 as of the last day of any Fiscal Quarter beginning after June 30, 2019, but ending on or before 31 March 2020; (iii) for Fiscal Quarters ending June 30, 2020, and September 30, 2020, to exceed 3.50 to 1.00, and (iv) for all Fiscal Quarters thereafter, exceed 3.00 to 1.00;

· a minimum Current Ratio, consisting of consolidated current assets (as defined in the Credit Agreement) to consolidated current liabilities (as defined in the Credit Agreement), of not less than 1.0 to 1.0 as of the last day of any Fiscal Quarter;

· an Asset Coverage Ratio, consisting of Modified Proved NPV (as defined in the Credit Agreement) to Consolidated Total Debt, beginning with Fiscal Quarter ending June 30, 2019, (i) to be less than 2.0 to 1.0 during any Fiscal Quarter ending before March 31, 2021, and (ii) for all Fiscal Quarters thereafter, to be less than 2.50 to 1.00;

· an Asset Coverage Ratio (PDP), consisting of Modified Proved NPV for PDP to Consolidated Total Debt, to be (i) less than 1.10 to 1.00 for Fiscal Quarter ending June 30, 2019, (ii) for Fiscal Quarters ending on September 30, 2019 and December 31, 2019, to be less than 1.15 to 1.00, (iii) during the Fiscal Quarter ended March 31, 2020, to be less than 1.25 to 1.00, (iv) for Fiscal Quarters ending on June 30, 2020, September 30, 2020, December 31, 2020, and March 31, 2021 to be less than  1.50 to 1.00, and (v) for all Fiscal Quarters thereafter, to be less than 1.75 to 1.00;a Fixed Charge Coverage Ratio, consisting of Consolidated EBITDAX for the Fiscal Quarter just ended, plus unrestricted cash and cash equivalents on the last day of the preceding Fiscal Quarter to Consolidated Fixed Charges (as defined in the Credit Facility) for the just ended Fiscal Quarter; (i) for the fiscal quarter ended June 30, 2019, to be less than 1.35 to 1.00, and (ii) for all Fiscal Quarters thereafter, to be less than 1.40 to 1.00; and

· the Company shall not make Capital Expenditures (as defined in the Credit Agreement) in any fiscal Quarter, beginning with the fiscal Quarter ended June 30, 2019, that would cause the aggregate amount of all Capital Expenditures in such Fiscal Quarter to exceed by more than (i) 10% the amount of Capital Expenditures for such Fiscal Quarter set forth on the then current and Approved Acquisition and Development Plan (defined in the Credit Agreement), or (ii) 10% the amount of the Capital Expenditures set forth in the then-current and Acquisition and Development Plan in the aggregate.

At June 30, 2019, the Company was not in compliance with certain financial covenants under the Credit Agreement, therefore, the total outstanding amount of the Credit Agreement has been categorized as a current liability and the deferred financing fees in the amount of $1.4 million, previously recorded as debt discount, have been expensed. Due to the Company’s recent breaches ofthe Credit Agreement, the Lender may declare an event of default and foreclose on some or all of the Company’s assets and/oraccelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and otherlender costs and expenses.

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Contingencies

12 Months Ended

Jun. 30, 2019

Contingencies [Abstract]

Contingencies

12. CONTINGENCIES

Samson may be subject to various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, and claims for underpayment of royalties, property damage claims and contract actions.

The Company records an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to its business operations is likely to have a material adverse effect on the company’s consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

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Summary Of Significant Accounting Policies (Schedule Of Earnings Per Share, Basic And Diluted) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Summary Of Significant Accounting Policies [Abstract]
Net loss	$ (7,148,031)	$ (6,038,866)
Basic and diluted weighted average common shares outstanding	328,300,044	328,300,044
Basic and diluted loss per common share - cents per share	$ (0.02)	$ (0.02)

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Summary Of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Jun. 30, 2019 USD ($) segment	Jun. 30, 2018 USD ($)
Significant Accounting Policies [Line Items]
Net loss	$ (7,148,031)	$ (6,038,866)
Cash outflows from operating activities	(5,367,466)	742,289
Current liabilities	43,346,509	34,950,504
Capital Reserve Amount	1,000,000
Debt Service Reserve	1,100,000
Current assets	4,756,610	3,642,185
Current portion of credit facility	$ 33,500,000	23,867,558
Number of operating segments | segment	1
Depreciation Depletion And Amortization	$ 1,824,014	1,237,989
Provision for bad debt expense	175,000	75,000
Exploratory costs charged to expense		200,000
Impairment of oil and natural gas properties	$ 0
Minimum percentage of likelihood tax benefits recognized from uncertain tax position, reasonably possible upon settlement	50.00%
Operating Leases, Future Minimum Payments Due	$ 219,643
Other Property And Equipment [Member]
Significant Accounting Policies [Line Items]
Depreciation Depletion And Amortization	$ 30,000,000,000	$ 85,000,000,000
Other Property And Equipment [Member] | Minimum [Member]
Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Other Property And Equipment [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Useful Life	25 years

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Common Stock (Movements In Contributed Equity For The Year) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Shares issued upon exercise of options, shares	0
Stock based compensation		$ 352,303
Issued Capital [Member]
Beginning Balance, shares	328,300,044	328,300,044
Opening balance, value	$ 106,743,167	$ 106,390,864
Capital raising, shares
Capital raising
Shares issued upon exercise of options, shares	0
Shares issued upon exercise of options, value
Share based payment, shares
Stock based compensation		$ 352,303
Transaction costs incurred, value
Ending Balance, shares	328,300,044	328,300,044
Shares on issue at balance date, value	$ 106,743,167	$ 106,743,167

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Share-Based Payments (Summary Of Stock Option Activity) (Details)	12 Months Ended
	Jun. 30, 2019 AUD ($) $ / shares shares		Jun. 30, 2019 AUD ($) $ / shares shares		Jun. 30, 2018 $ / shares shares	Jun. 30, 2018 $ / shares shares
Share-Based Payments [Abstract]
Outstanding, start of period | shares	314,500,000		314,500,000		411,033,246	411,033,246
Granted | shares
Exercised | shares	0		0
Cancelled/expired | shares					(96,533,246)	(96,533,246)
Outstanding, end of period | shares	314,500,000		314,500,000		314,500,000	314,500,000
Exercisable, end of period | shares	314,500,000		314,500,000		314,500,000	314,500,000
Weighted average exercise price - cents (AUD), outstanding, start of period | $ / shares	$ 0.0570				$ 0.0118
Weighted average exercise price - cents (AUD), granted | $ / shares
Weighted average exercise price - cents (AUD), exercised | $ / shares
Weighted average exercise price - cents (AUD), cancelled/expired | $ / shares					0.0380
Weighted average exercise price - cents (AUD), outstanding, end of period | $ / shares	0.0570				0.0570
Weighted average exercise price - cents (AUD), exercisable, end of period | $ / shares	$ 0.0570				$ 0.0570
Aggregate intrinsic value of options - cents (AUD) | $		[1]		[1]

[1] The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date. If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option.

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]
Beginning of year	$ 47,662	$ 65,262
Sales of oil and gas produced during the period, net of production costs	(321)	(3,902)
Extensions, discoveries and improved recovery	396
Changes in prices and production costs	3,476	2,822
Revisions of previous quantity estimates and other	(8,884)	(10,088)
Changes in estimates of future development costs	502	(11,625)
Accretion of discount	4,766
Net changes in income taxes		6,526
Changes in timing and other	(27)	(1,333)
Balance at end of year	$ 47,570	$ 47,662

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Asset Retirement Obligations (Narrative) (Details)	12 Months Ended
	Jun. 30, 2019
Minimum [Member]
Asset Retirement Obligations, Discount Rate	4.00%
Maximum [Member]
Asset Retirement Obligations, Discount Rate	13.00%

XML

Hedging And Derivative Financial Instruments (Schedule Of Open Derivative Contracts) (Details)	12 Months Ended
	Jun. 30, 2019 USD ($) $ / bbl bbl
W&T Offshore, Inc. [Member]
Derivative [Line Items]
Volumes | bbl	693,000
Estimated Fair Value | $	$ 192,854
W&T Offshore, Inc. [Member] | Derivative Contract One [Member]
Derivative [Line Items]
Year	Dec. 31, 2019
Volumes | bbl	109,000
Estimated Fair Value | $	$ (118,762)
W&T Offshore, Inc. [Member] | Derivative Contract Two [Member]
Derivative [Line Items]
Year	Dec. 31, 2020
Volumes | bbl	200,000
Estimated Fair Value | $	$ 38,418
W&T Offshore, Inc. [Member] | Derivative Contract Three [Member]
Derivative [Line Items]
Year	Dec. 31, 2021
Volumes | bbl	182,000
Estimated Fair Value | $	$ 118,142
W&T Offshore, Inc. [Member] | Derivative Contract Five [Member]
Derivative [Line Items]
Year	Dec. 31, 2022
Volumes | bbl	163,000
Estimated Fair Value | $	$ 134,254
W&T Offshore, Inc. [Member] | Derivative Contract Six [Member]
Derivative [Line Items]
Year	Dec. 31, 2023
Volumes | bbl	39,000
Estimated Fair Value | $	$ 20,802
Henry Hub [Member]
Derivative [Line Items]
Volumes | bbl	214,500
Estimated Fair Value | $	$ 21,985
Henry Hub [Member] | Derivative Contract Seven [Member]
Derivative [Line Items]
Year	Dec. 31, 2019
Volumes | bbl	30,000
Floor price	2.60
Ceiling price	2.80
Estimated Fair Value | $	$ 6,875
Henry Hub [Member] | Derivative Contract Eight [Member]
Derivative [Line Items]
Year	Dec. 31, 2020
Volumes | bbl	63,900
Floor price	2.60
Ceiling price	2.80
Estimated Fair Value | $	$ 7,709
Henry Hub [Member] | Derivative Contract Nine [Member]
Derivative [Line Items]
Year	Dec. 31, 2021
Volumes | bbl	57,600
Floor price	2.60
Ceiling price	2.80
Estimated Fair Value | $	$ 5,122
Henry Hub [Member] | Derivative Contract Ten [Member]
Derivative [Line Items]
Year	Dec. 31, 2022
Volumes | bbl	51,300
Floor price	2.60
Ceiling price	2.80
Estimated Fair Value | $	$ 3,676
Henry Hub [Member] | Derivative Contract Eleven [Member]
Derivative [Line Items]
Year	Dec. 31, 2023
Volumes | bbl	11,700
Floor price	2.60
Ceiling price	2.80
Estimated Fair Value | $	$ (1,397)
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract One [Member]
Derivative [Line Items]
Swap	55.75
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Two [Member]
Derivative [Line Items]
Swap	55.39
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Three [Member]
Derivative [Line Items]
Swap	54.03
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Five [Member]
Derivative [Line Items]
Swap	53.15
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Six [Member]
Derivative [Line Items]
Swap	53.46
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract One [Member]
Derivative [Line Items]
Swap	58.10
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Two [Member]
Derivative [Line Items]
Swap	57.05
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Three [Member]
Derivative [Line Items]
Swap	55.70
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Five [Member]
Derivative [Line Items]
Swap	55.70
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Six [Member]
Derivative [Line Items]
Swap	55.70

XML

Income Taxes (Schedule Of Effective Income tax Rate Reconciliation) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Income Taxes [Abstract]
Income tax expense (benefit) at federal statutory rate	$ (1,979,000)	$ (1,956,277)
Effect of permanent differences and other - US	121,000	115,616
State Taxes, Net of Federal Benefit	(600,000)	(123,694)
Change in Valuation Allowance	1,692,000	(10,104,596)
Change in tax rate	342,000	11,207,430
US income taxed at a different rate	432,000	116,777
Other	(55,944)	12,688
Effective income tax rate	$ (47,944)	$ (732,056)

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Hedging And Derivative Financial Instruments

12 Months Ended

Jun. 30, 2019

Hedging And Derivative Financial Instruments [Abstract]

Hedging And Derivative Financial Instruments

3. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Derivative Agreements.   The Company utilizes swap and collar option contracts to hedge the effect of price changes on a portion of its future oil and natural gas production. The objective of the Company’s hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements. The Company may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of the Company’s existing positions. The Company may use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional unmitigated commodity price risk.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are with a single major oil company with no history of default with the Company. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

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

At June 30, 2019, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

CollarCollars 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 rather than the market price.  If the market price is between the call and the put strike price, no payments are due from either party.

Fixed price swapThe 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 and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with AEP I FINCO LLC, the Company’s lender. As such no collateral is required by the counterparty.

During the third quarter of fiscal year ending June 30, 2019, the company entered into a series of swaps and costless collars for its oil and natural gas production. As of June 30, 2019, the Company had commodity derivative instruments outstanding through the first quarter of 2023, as summarized in the table below.

Asset (liability)	Price per Bbl – WTI				Estimated
	Floor	Ceiling	Swap		Fair Value
Year	$	$	$	Units (Bbl)	$
Crude Oil Derivatives
2019	N/A	N/A	55.75 – 58.10	109,000	(118,762)
2020	N/A	N/A	55.39 – 57.05	200,000	38,418
2021	N/A	N/A	54.03 – 55.70	182,000	118,142
2022	N/A	N/A	53.15 – 55.70	163,000	134,254
2023	N/A	N/A	53.46 – 55.70	39,000	20,802
	N/A	N/A		693,000	192,854
	Price per Mcf – Henry Hub				Estimated
	Floor	Ceiling	Swap	Units (Mcf)	Fair Value
Year	$	$	$		$
Natural Gas Derivatives
2019	$              2.60	$              2.80	$                   -	30,000	6,875
2020	$              2.60	$              2.80	$                   -	63,900	7,709
2021	$              2.60	$              2.80	$                   -	57,600	5,122
2022	$              2.60	$              2.80	$                   -	51,300	3,676
2023	$              2.60	$              2.80	$                   -	11,700	(1,397)
				214,500	21,985

Derivative Assets and Liabilities Fair Value.  The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the derivative commodity contracts was a net asset of $0.2 million at June 30, 2019, and a net liability of $1.2 million at June 30, 2018.

The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category:

	As of June 30, 2019
	Derivative Assets		Derivative Liabilities
	Balance Sheet		Balance Sheet
	Classification	Fair Value	Classification	Fair Value
Commodity contracts	Current assets	-	Current liabilities	150,703
Commodity contracts	Noncurrent assets	365,542	Noncurrent liabilities	-
Total commodity contracts		365,542		150,703
	As of June 30, 2018
	Derivative Assets		Derivative Liabilities
	Balance Sheet		Balance Sheet
	Classification	Fair Value	Classification	Fair Value
Commodity contracts	Current assets	-	Current liabilities	1,210,795
Commodity contracts	Noncurrent assets	-	Noncurrent liabilities	-
Total commodity contracts		-		1,210,795

Offsetting of Derivative Assets and Liabilities.  As of June 30, 2019, and 2018, all derivative instruments held by the Company were subject to a master netting arrangement with one financial institution. In general, the terms of the Company’s agreement provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreement also provides that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying balance sheets.

The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the fiscal years ended June 30, 2019, and 2018.  The following table summarizes the components of the net derivative gain (loss) line item presented in the accompanying statements of operations:

	For the Years Ended June 30,
	2019	2018
Unrealized gain (loss) on derivatives	1,425,634	(946,438)
Realized gain (loss) on derivatives	(968,418)	(1,775,728)
Total gain (loss) on derivatives	457,216	(2,722,166)

See Note 4 for additional fair value disclosures about the Company’s oil and gas derivatives.

Credit Related Contingent Features.  As of June 30, 2019, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group.

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Common Stock (Tables)

12 Months Ended

Jun. 30, 2019

Common Stock [Abstract]

Contributed Equity

	June 30,
	2019		2018
328,300,044 ordinary fully paid shares including shares to be issued	$	106,743,167	$	106,743,167

Movements In Contributed Equity For The Year

Movements in contributed equity for the year	2019				2018
	No. of shares		$		No. of shares		$
Opening balance		328,300,044		106,743,167		328,300,044		106,390,864
Capital raising (i)		-		-		-		-
Shares issued upon exercise of options (ii)		-		-		-		-
Share based compensation		-		-		-		352,303
Transaction costs incurred		-		-		-		-
Shares on issue at balance date		328,300,044		106,743,167		328,300,044		106,743,167

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations

12 Months Ended

Jun. 30, 2019

Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]

Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations

14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES, INCLUSIVE OF DISCONTINUED OPERATIONS (UNAUDITED)

Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by Netherland, Sewell & Associates, Inc. All of the Company’s reserves were located in the United States.

Capitalized Costs Incurred.  Costs incurred for oil and natural gas exploration, development and acquisition are summarized below.

	Year ended June 30,
	2019		2018
Development		1,462,483		13,272
Undeveloped capitalized acreage		-		-
Total costs incurred	$	1,462,483	$	13,272

Oil and Gas Reserve Quantities.  The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure.

Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the fiscal years ended June 30, 2019, and 2018. The Company engaged Netherland, Sewell & Associates, Inc. to audit internal engineering estimates for 100 percent of the Company’s total calculated proved reserves PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

	Year ended June 30, 2019			Year ended June 30, 2018
	Oil	Gas	Total	Oil	Gas	Total
	Mbbls	MMcf	MBOE	Mbbls	MMcf	MBOE
Beginning of year	3,515	1,292	3,732	5,359	3,565	5,954
Revisions of previous quantity estimates *	(361)	(342)	(419)	(1,657)	(2,258)	(2,033)
Extensions and discoveries	-	-	-	-	-	-
Sale of reserves in place	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-
Production	(224)	(35)	(230)	(187)	(15)	(189)
End of year	2,930	915	3,083	3,515	1,292	3,732
Proved developed producing reserves	2,930	915	3,083	2,663	623	2,768
Proved developed non producing *	-	-	-	544	418	614
Proved undeveloped reserves *	-	-	-	308	251	350
Total proved reserves	2,930	915	3,083	3,515	1,292	3,732

*Given the Company’s current financial condition there is no assurance that it will have the necessary financial resources available to meet the investment and operating criteria, as defined under SEC regulation, to execute the development plan necessary to include PDNP and PUD reserves in the Company’s reserve report.

Standardized Measure of Discounted Future Net Cash Flows.  The Company computes a standardized measure of future net cash flows (“Standardized Measure”) and changes therein relating to estimated provedreserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying pricesand costs, including transportation, quality, and basis differentials, to the year-end estimated future reserve quantities. Estimated future income taxes are computed using the current statutory income taxrates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10  percent annual discount factor.The impact of income taxes has not been included in the current or prior year, as the net operating losses and the tax basis of the assets exceed the futurecash flows.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reservesin place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by thecentral administrative office attributable to operating activities.

The assumptions used to compute the Standardized Measure are those prescribed by the FASB and the SEC. These assumptions do not necessarilyreflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reservequantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations since these reserve quantity estimatesare the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of theStandardized Measure: 

The following table shows the estimated standardized measure of discounted future net cash flows relating to proved reserves (in US$’000’s):

	As at June 30,
	2019		2018
Future cash inflows	$	166,709	$	187,249
Future production costs		(85,626)		(99,620)
Future development costs		-		(1,642)
Future income taxes		-		-
Future net cashflows		81,083		85,987
10 % discount		(33,513)		(38,325)
Standardized measure of discounted future net cash flows relating to proved reserves	$	47,570	$	47,662

	Standardized Measure		PV10
Future cash inflows	$	166,709	$	97,805
Future production costs		(85,626)		(50,235)
Future development costs		-		-
Future income taxes		-		-
Future net cash flows		81,083		47,570
10% annual discount		(33,513)		-
Discounted future net cash flows	$	47,570	$	47,570

The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2019 and June 30, 2018 are as follows (in US$’000’s):

	Fiscal Year Ended June 30
	2019		2018
Beginning of year	$	47,662	$	65,262
Sales of oil and gas, net of production costs and taxes		(321)		(3,902)
Extensions and discoveries, net of costs		396		-
Purchases of reserves in place		-		-
Sales of reserves in place		-		-
Changes in prices and production costs		3,476		2,822
Revisions of previous quantity estimates and other		(8,884)		(10,088)
Previously estimated development costs incurred		-		-
Changes in estimated future development costs		502		(11,625)
Accretion of discount		4,766		-
Net changes in income taxes		-		6,526
Changes in timing and other		(27)		(1,333)
Balance at end of year	$	47,570	$	47,662

The impact of income taxes has not been included in the current year as the Company’s net operating losses, the tax basis of oil and gas assets and future expected deductions, exceed the future cash flows.

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Consolidated Statements Of Changes In Stockholders' Deficit - USD ($)	Issued Capital [Member]	Accumulated Deficit [Member]	Accumulated Other Comprehensive Income [Member]	Total
Beginning Balance, value at Jun. 30, 2017	$ 106,390,864	$ (104,222,925)	$ 892,017	$ 3,059,956
Net loss		(6,038,866)		(6,038,866)
Foreign currency translation loss			(45,461)	(45,461)
Total comprehensive loss for the period		(6,038,866)	(45,461)	(6,084,327)
Stock based compensation	352,303			352,303
Ending Balance, value at Jun. 30, 2018	106,743,167	(110,261,791)	846,556	(2,672,068)
Net loss		(7,148,031)		(7,148,031)
Foreign currency translation loss			(11,152)	(11,152)
Total comprehensive loss for the period		(7,148,031)	(11,152)	(7,159,183)
Stock based compensation
Ending Balance, value at Jun. 30, 2019	$ 106,743,167	$ (117,409,822)	$ 835,404	$ (9,831,251)

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Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Jun. 30, 2019	Oct. 15, 2019	Dec. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Jun. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	Samson Oil & Gas LTD
Entity Central Index Key	0001404079
Current Fiscal Year End Date	--06-30
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		328,300,044
Entity Public Float			$ 2.1

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Hedging And Derivative Financial Instruments (Tables)

12 Months Ended

Jun. 30, 2019

Hedging And Derivative Financial Instruments [Abstract]

Schedule Of Open Derivative Contracts

Asset (liability)	Price per Bbl – WTI				Estimated
	Floor	Ceiling	Swap		Fair Value
Year	$	$	$	Units (Bbl)	$
Crude Oil Derivatives
2019	N/A	N/A	55.75 – 58.10	109,000	(118,762)
2020	N/A	N/A	55.39 – 57.05	200,000	38,418
2021	N/A	N/A	54.03 – 55.70	182,000	118,142
2022	N/A	N/A	53.15 – 55.70	163,000	134,254
2023	N/A	N/A	53.46 – 55.70	39,000	20,802
	N/A	N/A		693,000	192,854
	Price per Mcf – Henry Hub				Estimated
	Floor	Ceiling	Swap	Units (Mcf)	Fair Value
Year	$	$	$		$
Natural Gas Derivatives
2019	$              2.60	$              2.80	$                   -	30,000	6,875
2020	$              2.60	$              2.80	$                   -	63,900	7,709
2021	$              2.60	$              2.80	$                   -	57,600	5,122
2022	$              2.60	$              2.80	$                   -	51,300	3,676
2023	$              2.60	$              2.80	$                   -	11,700	(1,397)
				214,500	21,985

Fair Value Of Derivatives

	As of June 30, 2019
	Derivative Assets		Derivative Liabilities
	Balance Sheet		Balance Sheet
	Classification	Fair Value	Classification	Fair Value
Commodity contracts	Current assets	-	Current liabilities	150,703
Commodity contracts	Noncurrent assets	365,542	Noncurrent liabilities	-
Total commodity contracts		365,542		150,703
	As of June 30, 2018
	Derivative Assets		Derivative Liabilities
	Balance Sheet		Balance Sheet
	Classification	Fair Value	Classification	Fair Value
Commodity contracts	Current assets	-	Current liabilities	1,210,795
Commodity contracts	Noncurrent assets	-	Noncurrent liabilities	-
Total commodity contracts		-		1,210,795

Componenets Of Derivative (Gain) Loss

	For the Years Ended June 30,
	2019	2018
Unrealized gain (loss) on derivatives	1,425,634	(946,438)
Realized gain (loss) on derivatives	(968,418)	(1,775,728)
Total gain (loss) on derivatives	457,216	(2,722,166)

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Summary Of Significant Accounting Policies (Schedule Of Oil And Gas Properties And Equipment) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Summary Of Significant Accounting Policies [Abstract]
Proved properties, net of impairment	$ 39,666,294	$ 38,110,237
Work in progress	40,319	8,271
Less accumulated depreciation, depletion and impairment	(9,491,784)	(7,697,667)
Total oil and gas properties and equipment	30,214,829	30,420,841
Unproved acreage

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Commitments (Tables)

12 Months Ended

Jun. 30, 2019

Commitments [Abstract]

Contractual Obligations

	Total	2020	2021		2022		2023		Thereafter
Leases	219,643	103,616		107,080		8,947		-		-

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Revenue From Contracts With Customers (Disaggregation of Revenue) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Oil and gas income	$ 12,662,865	$ 10,058,719
Oil [Member]
Disaggregation of Revenue [Line Items]
Oil and gas income	12,391,536	9,931,065
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Oil and gas income	257,895	118,783
Other Liquids [Member]
Disaggregation of Revenue [Line Items]
Oil and gas income	$ 13,434	$ 8,871

XML

Income Taxes

12 Months Ended

Jun. 30, 2019

Income Taxes [Abstract]

Income Taxes

6. INCOME TAXES

The Company accounts for income taxes under the asset and liability approach prescribed by GAAP, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s consolidated financial statements or tax returns.

The Company’s income tax provision (benefit) is composed of the following:

	June 30
	2019		2018
Current:
Federal	$	-	$	-
State		200		-
		200		-
Deferred:
Federal		(48,144)		(732,056)
State		-		-
Total income tax benefit	$	(47,944)	$	(732,056)

A reconciliation of the income tax provision (benefit) computed by applying the Australian federal statutory rate of 30% to the Company’s income tax provision (benefit) is as follows:

		June 30
	2019		2018
Income tax expense (benefit) at federal statutory rate	$	(1,979,000)	$	(1,956,277)
Effect of Permanent Differences and Other-US		121,000		115,616
State Taxes, Net of Federal Benefit		(600,000)		(123,694)
Change in Valuation Allowance		1,692,000		(10,104,596)
Change in Tax Rate		342,000		11,207,430
US income taxed at a different rate		432,000		116,777
Other		(55,944)		12,688
Total income tax benefit	$	(47,944)	$	(732,056)

The components of the deferred tax assets and (liabilities) are as follows:

	June 30
	2019		2018
Deferred income tax assets:
Net operating losses	$	26,450,000	$	23,674,591
Asset retirement obligation		807,000		737,876
Abandonment limitation		-		544,869
Debt issuance costs		312,000		-
AMT Credit		780,000		780,443
Provision for Annual Leave		50,000		51,837
Allowance For Doubtful Accounts		59,000		17,558
Share based comp		459,000		500,845
Hedge Liability		-		283,458
Gross deferred tax assets	$	28,917,000	$	26,591,477
Deferred income tax liabilities:
Oil and gas property		(2,085,000)		(1,908,395)
Hedge Liability		(51,000)		-
Gross deferred tax liabilities	$	(2,136,000)	$	(1,908,395)
Net deferred income tax assets (liabilities)		26,781,000		24,683,082
Valuation allowance		(26,001,000)		(23,951,026)
Noncurrent deferred tax asset	$	780,000	$	732,056

The Company has tax losses carried forward arising in Australia of $17.4 million.  The benefit of these losses of $4.8 million will only be obtained in future years if:

(i)	the Parent Entity derive future assessable income of a nature and an amount sufficient to enable the benefit from the deduction for the losses to be realized; and
(ii)	the Parent Entity have complied and continue to comply with the conditions for deductibility imposed by law; and
(iii)	no changes in tax legislation adversely affect the Parent Entity in realizing the benefit from deduction for the losses.

The Company has federal net operating tax losses in the United States of approximately $94.1 million.  The 2000-2005 years are limited to $403,194 per year as a result of a change in ownership of the one of the subsidiaries which occurred in January 2005. NOLs generated after this ownership change are not limited due to any known ownership changes.  If not utilized, the tax net operating losses will expire during the period from 2020 to 2038.  NOL's generated in 2019 do not expire and can be carried forward indefinitely. Of the $9.2 million available as of July 1, 2011, $4.0 million will never be utilized and will expire by June 2025.

In addition to the above-mentioned Federal carried forward losses in the United States, the Company also has approximately $52.9 million of State carried forward tax losses, with expiry dates between 2020 and 2039.  A deferred income tax asset in relation to these losses has not been recognized as realization of the benefit is not regarded as probable.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, Management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income.  As of the current year end, the company does not believe the realizability of the deferred tax assets to be more likely than not except for AMT credits.  As such, the company has a full valuation allowance offsetting the deferred tax asset, with the exception of the valuation allowance related to the refundable AMT Credit which is now realizable due to the tax law changes in the Tax Cuts and Jobs Act passed during 2018.

The Company adopted the uncertainty provision of FASB ASC Topic 740, "Income Taxes" and has analyzed filing positions in all federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in this jurisdiction. Most uncertain tax positions relate primarily to timing differences and management does not believe any such uncertain tax positions will materially impact the Company's effective tax rate in future periods. The Company anticipates that no additional uncertain tax positions will be recognized within the next twelve months. Our policy is to recognize any interest and penalties related to the unrecognized tax benefits in income tax expense.  In our major tax jurisdictions, the earliest years remaining open to examination are as follows US - 6/30/1996 due to the usage of net operating losses from that period.  If recognized, these uncertain tax positions would impact the Company's effective income tax rate. The company currently has no unrecognized positions.

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Related Party Transactions

12 Months Ended

Jun. 30, 2019

Related Party Transactions [Abstract]

Related Party Transactions

10. RELATED PARTY TRANSACTIONS

There were no related party transactions during the years ended June 30, 2019 and 2018.

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Commitments (Details)	Jun. 30, 2019 USD ($)
Commitments [Abstract]
Operating leases, Total	$ 219,643
Operating leases, 2020	103,616
Operating leases, 2021	107,080
Operating leases, 2022	8,947
Operating leases, 2023

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Income Taxes (Schedule Of Components Of Deferred Tax Assets and (Liabilities)) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Income Taxes [Abstract]
Net operating losses	$ 26,450,000	$ 23,674,591
Asset retirement obligation	807,000	737,876
Abandonment limitation		544,869
Debt issuance costs	312,000
AMT Credit	780,000	780,443
Provision for Annual Leave	50,000	51,837
Allowance for doubtful debts	59,000	17,558
Share based compensation	459,000	500,845
Hedge Liability		283,458
Gross deferred tax assets	28,917,000	26,591,477
Oil and gas property	(2,085,000)	(1,908,395)
Hedge Liability	(51,000)
Gross deferred tax liabilities	(2,136,000)	(1,908,395)
Net deferred income tax assets (liabilities)	26,781,000	24,683,082
Valuation allowance	(26,001,000)	(23,951,026)
Noncurrent deferred tax asset	$ 780,000	$ 732,056

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Credit Facility (Schedule of Credit Facilities) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2017
Credit Facility [Abstract]
Credit facility at beginning of period	$ 23,867,557	$ 23,419,749
Cash advanced under facility	33,561,707	450,000
Repayments	(23,929,264)	(2,192)
Credit facility at end of period	33,500,000	23,867,557
Funds available for drawdown under the facility

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Revenue From Contracts With Customers (Narrative) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Jun. 30, 2018
Revenue From Contracts With Customers [Abstract]
Accounts receivable	$ 1.5	$ 1.0

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Summary Of Significant Accounting Policies (Schedule Of Components Of Accounts Receivable) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Less provision for doubtful debts	$ (250,000)	$ (75,000)
Total accounts receivable	1,982,123	1,908,879
Oil And Natural Gas Sales Related Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	1,538,451	1,159,905
Cost Recovery From JV Partner Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	650,885	768,281
Other Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total accounts receivable	$ 42,787	$ 55,693

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Share-Based Payments (Tables)

12 Months Ended

Jun. 30, 2019

Share-Based Payments [Abstract]

Summary Of Stock Option Activity

	2019			2018
		Weighted	Aggregate		Weighted
		Average	Intrinsic		Average
		Exercise Price	Value of		Exercise Price
	Number	A$	A$	Number	A$
Outstanding, start of period	314,500,000	0.057	-	411,033,246	0.0118
Granted	-	-	-	-	-
Exercised	-	-	-	-	-
Cancelled/expired	-	-	-	(96,533,246)	0.0380
Outstanding, end of period	314,500,000	0.057	-	314,500,000	0.0570
Exercisable, end of period	314,500,000	0.057	-	314,500,000	0.0570

(1) The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date.  If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option.

Schedule Of Additional Information Related To Options Outstanding

	Options/Warrants Outstanding and Exercisable
		Weighted
		Average
Range of		Remaining
Exercise	Number	Contractual
Prices (A$)	Outstanding	Life - years
$0.070	48,000,000		7.42
$0.055	266,500,000		7.42
	314,500,000

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Common Stock

12 Months Ended

Jun. 30, 2019

Common Stock [Abstract]

Common Stock

7. COMMON STOCK

	June 30,
	2019		2018
328,300,044 ordinary fully paid shares including shares to be issued	$	106,743,167	$	106,743,167

Movements in contributed equity for the year	2019				2018
	No. of shares		$		No. of shares		$
Opening balance		328,300,044		106,743,167		328,300,044		106,390,864
Capital raising (i)		-		-		-		-
Shares issued upon exercise of options (ii)		-		-		-		-
Share based compensation		-		-		-		352,303
Transaction costs incurred		-		-		-		-
Shares on issue at balance date		328,300,044		106,743,167		328,300,044		106,743,167

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Commitments

12 Months Ended

Jun. 30, 2019

Commitments [Abstract]

Commitments

11. COMMITMENTS

Leases –The Company has entered into a lease agreement for office space in Denver, Colorado. As of June 30, 2019, future minimum lease payments under this operating lease with remaining non–cancelable terms in excess of one year are

as follows:

	Total	2020	2021		2022		2023		Thereafter
Leases	219,643	103,616		107,080		8,947		-		-

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Common Stock (Contributed Equity) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Common Stock [Abstract]
328,300,044 ordinary fully paid shares including shares to be issued	$ 106,743,167	$ 106,743,167
Common stock outstanding and to be issued	328,300,044

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Share-Based Payments (Narrative) (Details) - shares	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Share-Based Payments [Abstract]
Options exercised	0

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Summary Of Costs Incurred For Oil And Natural Gas Exploration, Development And Acquisition) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]
Development costs	$ 1,462,483	$ 13,272
Total costs incurred	$ 1,462,483	$ 13,272

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Income Taxes (Schedule Of Components Of Income Tax Provision (Benefit)) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Income Taxes [Abstract]
Current State	$ 200
Current	200
Deferred Federal	(48,144)	$ (732,056)
Effective income tax rate	$ (47,944)	$ (732,056)

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Fair Value Measurements (Details) - USD ($)		Jun. 30, 2019	Jun. 30, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents		$ 2,774,487	$ 1,376,676
Non Current Assets, Derivative Instruments		365,542
Current Liabilities, Derivative Instruments		150,703	1,210,795
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents		2,774,487	1,376,676
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents
Current Assets, Derivative Instruments		16,889	4,218
Non Current Assets, Derivative Instruments		377,845
Current Liabilities, Derivative Instruments		167,592	1,215,013
Non Current Liabilities, Derivative Instruments		(12,303)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents
Current Assets, Derivative Instruments
Non Current Assets, Derivative Instruments
Current Liabilities, Derivative Instruments
Non Current Liabilities, Derivative Instruments
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current Assets, Derivative Instruments	[1]	(16,889)	(4,218)
Non Current Assets, Derivative Instruments	[1]	(12,303)
Current Liabilities, Derivative Instruments	[1]	(16,889)	$ (4,218)
Non Current Liabilities, Derivative Instruments	[1]	$ 12,303

[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.

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Hedging And Derivative Financial Instruments (Narrative) (Details) - USD ($)	Jun. 30, 2019	Jun. 30, 2018
Derivative [Line Items]
Assets	$ 365,542
Liabilities	150,703	$ 1,210,795
Commodity Contract [Member]
Derivative [Line Items]
Assets	$ 200,000
Liabilities		$ 1,200,000

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Jun. 30, 2019

Summary Of Significant Accounting Policies [Abstract]

Description Of Operations

Description of Operations.   Samson Oil & Gas Limited along with its consolidated subsidiaries (“Samson” or the “Company”), is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties in North Dakota and Montana.

Going Concern

Going concern. 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. The Company incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. At June 30, 2019, the Company’s total current liabilities of $43.3 million exceed its total current assets of $4.8 million. Its ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and/or raising further capital. These factors raise substantial doubt over the Company’s ability to continue as a going concern and therefore whether it will realize its assets and extinguish its liabilities in the normal course of business and at the amounts stated in the financial report.

AtJune 30, 2019, the Companywas in breach of several of its covenants related to the Credit Agreement (defined in Note 8 – Credit Facility), resulting in borrowings payable of $33.5 million being classified as current liabilities. It is currently negotiating with the Lender in an effort to obtain a waiver for the breach. As of the date of this report, no waiver has been received.

The Company is currently negotiating with a prospective party to divest its oil and gas assets,as well as, continuing to execute on its drilling and development plan, which it believes will result in proceeds that will sufficientlycover the Company’s obligations to the Lender and its other creditors. Although the Company is confident it will be able to successfully recognize amounts in excess of the carrying value of its oil and gas assets as a result of its ultimate divestment or, alternatively, through the successful development of its Foreman Butte project, there can be no assurances made that the Company will be able to successfully execute these plans. Given the current financial situation it is possible that the Company may be forced to accept terms on these transactions that are less favorable than would be otherwise available.

Comparatives

Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Principles Of Consolidation

Principles of Consolidation.   The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated in consolidation.

Certain amounts in prior year financial statements have been reclassified to current year presentation, and the reclassification had no impact on net loss.

Use Of Estimates

Use of Estimates.   The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long–lived assets; (3) depreciation, depletion and amortization (“DD&A”); (4) asset retirement obligations (“ARO”); (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) certain accrued liabilities; (9) valuation of share-based payments, (10) income taxes and (11) carrying value of exploration and evaluation expenditures. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions through the date of this report for matters that may require recognition or disclosure in these financial statements.

Business Segment Information

Business Segment Information.   The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids (“NGL”). All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers.

Revenue Recognition And Gas Imbalances

Revenue Recognition and Gas Imbalances.   In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective July 1, 2018, the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion.

The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at June 30, 2019 or 2018.

Cash And Cash Equivalents

Cash and Cash Equivalents.   The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank.

Restricted Cash

Restricted cash.ASU 2016-18,  Statement of Cash Flows (Topic 230): Restricted Cash)This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The Company has adopted this standard.

In accordance with the terms of our Credit Agreement, the Company is required to have a Capital Reserve Amount (as defined in the Credit Agreement) equal to $1.0 million and a Debt Service Reserve Amount (as defined in the Credit Agreement) equal to approximately $1.1 million.  These amounts are carried on the balance sheet as Restricted Cash-Required reserve amounts related to Credit Agreement. 

Accounts Receivable

Accounts Receivable.   The components of accounts receivable include the following:

	June 30
	2019		2018
Oil and natural gas sales	$	1,538,451	$	1,159,905
Cost recovery from partners		650,885		768,281
Less provision for doubtful debts		(250,000)		(75,000)
Other		42,787		55,693
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018	$	1,982,123	$	1,908,879

The Company's accounts receivable’s result from; (i) oil and natural gas sales to oil and intrastate gas pipeline companies, (ii) billings to joint working interest partners in properties operated by the Company, and (iii) settlements for derivatives with our counter-party. The Company's trade and accrued production receivables are primarily from operated oil and gas properties. A portion of its oil and natural gas revenues are from non-operated oil and gas properties, whereby, the operators of the various projects negotiate the sale of oil and gas to third parties on the Company’s behalf.  Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable.

At June 30, 2019 and 2018, the Company recorded an allowance for accounts receivable of $175,000 and $75,000, respectively.

Oil And Gas Properties

Oil and Gas Properties.

Oil and gas properties and equipment consist of the following at June 30:

	2019		2018
Proved properties, net of impairment	$	39,666,294	$	38,110,237
Work in progress		40,319		8,271
Less accumulated depreciation, depletion and amortization		(9,491,784)		(7,697,667)
	$	30,214,829	$	30,420,841
Unproved acreage	$	-	$	-

The Company accounts for its oil and natural gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly.

Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method.  Mineral interests and leasehold acquisition costs are depleted over total proved reserves while costs of completed wells and related facilities and equipment are depleted over proved developed producing reserves.

If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.

As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment.

Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Company. Impairment on properties sold is recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term.

Exploration and evaluation costs including capitalized exploration written off and dry hole expenses

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 expenditure under our policy, the Company concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement.

During the fiscal years ended June 30, 2019, and 2018, we expensed $0 and $0.2 million, respectively, in deferred exploration expense.

Impairment

Impairment

The Company had no impairment charges for the years ended June 30, 2019, and 2018.

Other Property And Equipment

Other Property and Equipment.

Other property and equipment, which includes leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight–line method over the estimated useful lives of the related assets, ranging from 3 to 25 years. Depreciation and amortization expense for the years ended June 30, 2019, and 2018, was approximately $30,000 and $85,000, respectively.

Other property and equipment consist of the following at June 30:

	2019		2018
Furniture, fittings and equipment	$	930,173	$	1,017,879
Less accumulated depreciation		(755,242)		(775,057)
	$	174,931	$	242,822

Derivative Financial Instruments

Derivative Financial Instruments.   The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. All of the Company's derivative counterparties are major oil companies.  The Company has elected not to apply hedge accounting to any of its derivative transactions and consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. 

Asset Retirement Obligations

Asset Retirement Obligations.   The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long–lived asset are recorded at the time the well is spud or acquired.

Environmental

Environmental.   The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non–capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company is not aware of any material noncompliance with existing laws and regulations.

Income Taxes

Income Taxes.   Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Loss Per Share

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

	Year ended June 30,
	2019		2018
Net loss:	$	(7,148,031)	$	(6,038,866)
Basic and diluted weighted average common shares outstanding		328,300,044		328,300,044
Basic and diluted loss per common share – cents per share		(0.02)		(0.02)

Stock-Based Compensation

Stock-Based Compensation.   Stock-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). The Company recognizes stock-based compensation net of an estimated forfeiture rate, and recognizes compensation expense only for shares that are expected to vest.  Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.

Foreign Currency Translation

Foreign Currency Translation.   The functional currency of Samson Oil & Gas Limited (Parent Entity) is Australian dollars, the reason for this being the majority of cash flows of the Parent Entity are denominated in Australian dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S. dollars. The presentation currency of the Company is U.S. dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction.  Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income.

Business Combinations

Business Combinations Samson applies the acquisition method in accounting for business combinations.  The consideration transferred by the Company is calculated as the sum of the acquisition date fair value of assets transferred, liabilities incurred and any equity interests issued by the Company, which includes the fair value of any asset or liability arising from any contingent consideration arrangements.  Acquisition costs are expensed as incurred. The Company treats the acquisition of oil and gas assets as a business combination.

The Company recognizes identifiable assets acquired and liabilities assumed in a business combination regardless of whether they have been previously recognized in the acquiree’s financial statements prior to the acquisition.  Assets acquired and liabilities assumed are generally measured at their acquisition date fair values.

If the fair values of identifiable net assets exceed the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. 

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements

ASU 2016-02, Leases (Topic 842)In January 2016, ASC 842 was issued, which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. ASC 842 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments, as a right of use asset and respective liability. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss.

The Company operates predominantly as a lessee. The standard will affect primarily the accounting for its operating leases, with no significant impact expected for its finance leases. The new lease standard is effective for the Company on July 1, 2019, and will be adopted effective on that date using the simplified cumulative catch-up method. This adoption method will allow the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at July 1, 2019, will be made for the difference between the right of use asset and liability recorded. In addition, lease incentives will be rolled into the respective right of use asset, rather than recorded as a deferral. Upon adoption of the new standard, the Company intends to elect to apply hindsight in assessing the lease term, and to grandfather previous conclusions reached as to whether existing contracts are or contain leases. It continues to evaluate other practical elections, which may apply to individual asset classes and to portfolios of leases that contain similar characteristics. As of June 30, 2019, the Company had approximately $220,000 of contractual obligations related to its non-cancelable leases. The Company is in the process of evaluating those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASC 842. It is also in the process of implementing changes to its accounting policies, internal controls, and financial statements as a result of adoption of this standard. The Company will continue to assess the additional disclosures that will be required upon implementation of the standard.

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Consolidated Statements Of Operations And Comprehensive Loss - USD ($)	12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
OPERATING REVENUES:
Total oil and gas income	$ 12,662,865	$ 10,058,719
OPERATING EXPENSES:
Lease operating expense	12,341,869	6,866,922
Depletion, depreciation, amortization and accretion of asset retirement obligation	2,385,964	1,488,772
Exploration and evaluation expenditure	73,016	325,304
Abandonment Expense	156,809	189,259
General and administrative	2,785,687	3,706,182
Provision for doubtful debts	175,000	75,000
Total operating expenses	17,918,345	12,651,439
LOSS FROM OPERATIONS	(5,255,480)	(2,592,720)
Interest expense, net	(3,765,652)	(1,715,342)
Realized loss on derivative instruments	(968,418)	(1,775,728)
Unrealized gain(loss) on derivative instruments	1,425,634	(946,438)
Gain on sale of assets	120,000	178,407
Income from forfeiture of non-refundable deposit	1,000,000
Other	247,941	80,899
LOSS BEFORE INCOME TAXES	(7,195,975)	(6,770,922)
Income tax benefit	47,944	732,056
NET LOSS	(7,148,031)	(6,038,866)
OTHER COMPREHENSIVE LOSS:
Foreign currency translation loss	(11,152)	(45,461)
Total comprehensive loss for the period	$ (7,159,183)	$ (6,084,327)
NET LOSS PER COMMON SHARE:
Basic and diluted - per share	$ (0.02)	$ (0.02)
Weighted average common shares outstanding:
Basic and diluted shares	328,300,044	328,300,044
Oil [Member]
OPERATING REVENUES:
Total oil and gas income	$ 12,391,536	$ 9,931,065
Natural Gas [Member]
OPERATING REVENUES:
Total oil and gas income	257,895	118,783
Other Liquids [Member]
OPERATING REVENUES:
Total oil and gas income	$ 13,434	$ 8,871

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Fair Value Measurements (Tables)

12 Months Ended

Jun. 30, 2019

Fair Value Measurements [Abstract]

Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis

	Fair Value at June 30, 2019
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash, restricted cash and cash equivalents	$	2,774,487	$	-	$	-	$	-	$	2,774,487
Derivative Instruments		-		16,889		-		(16,889)		-
Non Current Assets:
Derivative Instruments		-		377,845		-		(12,303)		365,542
Current Liabilities
Derivative Instruments		-		(167,592)		-		16,889		(150,703)
Non Current Liabilities:
Derivative Instruments				(12,303)		-		12,303		-
	Fair Value at June 30, 2018
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash and cash equivalents	$	1,376,676	$	-	$	-	$	-	$	1,376,676
Derivative Instruments		-		4,218		-		(4,218)		-
Non Current Assets:
Derivative Instruments		-		-		-		-		-
Current Liabilities
Derivative Instruments		-		1,215,013		-		(4,218)		1,210,795
Non Current Liabilities:
Derivative Instruments				-				-		-

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Revenue From Contracts With Customers

12 Months Ended

Jun. 30, 2019

Revenue From Contracts With Customers [Abstract]

Revenue From Contracts With Customers

2. REVENUE FROM CONTRACTS WITH CUSTOMERS

The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its RockyMountain regions. Oil, gas, and NGL production revenue presented within the accompanying statements of operationsis reflective of the revenue generated from contracts with customers.

The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for fiscal years ended June 30:

	2019		2018
Oil sales	$	12,391,536	$	9,931,065
Gas sales		257,895		118,783
Other liquids		13,434		8,871
Total oil and gas income	$	12,662,865	$	10,058,719

The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differsdepending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing,and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred priorto control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and otherdeductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has two categories

under which oil, gas, and NGL production revenue is generated, as summarized below:

1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead.

2) The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred.

Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownershipinterest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead or inlet of the midstreamprocessor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations isgenerally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers ofhydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amountof production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company isrecorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts withcustomers within the accompanying balance sheets as of June 30, 2019, and 2018, were $1.5 million and $1.0 million, respectively. Toestimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements,index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amountsreceived for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the fiscal year ended June 30, 2019,that related to performance obligations satisfied in prior reporting periods, was immaterial.

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Credit Facility (Tables)

12 Months Ended

Jun. 30, 2019

Credit Facility [Abstract]

Schedule of Credit Facilities

	June 30,
	2019		2018
Credit facility at beginning of period	$	23,867,557	$	23,419,749
Cash advanced under Credit Agreement		33,561,707		450,000
Repayments		(23,929,264)		(2,192)
Credit facility at end of period	$	33,500,000	$	23,867,557
Funds available for drawdown under the facility		-		-