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, 2016

¨ 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 16, AMP Building, 140 St Georges Terrace Perth, Western Australia 6000
(Address of principal executive offices)	(Zip Code)

+61 8 9220 9830

(Registrant’s telephone number, including area code)

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

American Depositary Shares* Ordinary Shares**	NYSE MKT
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  o   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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The aggregate market value of the registrant's ordinary shares held by non-affiliates of the registrant on December 31, 2015 was approximately $5.2 million based on the closing price as reported on the NYSE MKT (treating, for this purpose, all executive officers and directors of the registrant, as affiliates).

There were 3,215,854,791 ordinary shares outstanding as of September 26, 2016.

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, 2016.

SAMSON OIL & GAS LIMITED

ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS		1
GLOSSARY OF TECHNICAL TERMS		2
PART I		4
Item 1 and 2.	Business and Properties	4
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	31
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31
PART II		32
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	53
Item 9A.	Controls and Procedures	53
Item 9B.	Other Information	54
PART III		55
Item 10.	Directors, Executive Officers and Corporate Governance	55
Item 11.	Executive Compensation	55
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	55
Item 13.	Certain Relationships and Related Transactions, and Director Independence	55
Item 14.	Principal Accounting Fees and Services	55
PART IV		55
Item 15.	Exhibits and Financial Statement Schedules	55
SIGNATURES		58

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.

Forward–looking statements appear in a number of places in this annual report and include but are not limited to the timing of the anticipated closing of the North Stockyard asset sale and use of those proceeds, management’s comments regarding business strategy, exploration and development drilling prospects and activities at our Foreman Butte, North Stockyard, Hawk Springs, Roosevelt, State GC Field, Rainbow, Cane Creek, and Sabretooth 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 our credit facility negotiations, meeting our capital raising targets, and following any use of proceeds plans, our ability to and methods by which we may raise additional capital, 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.

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.

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.

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.

NYMEX.   New York Mercantile Exchange.

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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.

3

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. During the year, we underwent two transformative transactions. In March 2016, we closed on the acquisition of the Foreman Butte project, which included 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 for the seller of the assets.

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 is $15 million, and the purchaser has provided a deposit of $1 million. The transaction was initially scheduled to close on August 31, 2016. Under the terms of the purchase and sale agreement, the purchaser could extend the closing date to September 30, 2016 through the payment of $50,000. The purchaser exercised this option on August 31, 2016. The terms of the agreement allow another extension to October 31, 2016 upon payment of an additional $50,000. We have been advised by the purchaser that they intend to close October 20, 2016. We have received the $50,000 payment. If the transaction has not closed by October 31, 2016, the agreement will be terminated. The $1 million deposit is not refundable unless environmental or title issues are identified by the purchaser during their due diligence. This asset consists of 22 producing Bakken and Three Forks wells. The effective date of the transaction is the day after the transaction closes. $11.5 million of the proceeds from this transaction will be used to pay down our credit facility with Mutual of Omaha Bank. The remaining proceeds will be used to rebalance our hedge book, following the sale of a portion of our production and for working capital.

Upon the closing of the North Stockyard sale, the combination of that transaction with the Foreman Butte purchase would make a substantial contribution toward improving our financial stability and restoring the loan to value ratio in our credit facility with Mutual of Omaha Bank.

We engaged Netherland, Sewell & Associates, Inc. (“Netherland Sewell”) to prepare our proved oil and gas reserve estimates and the future net revenue to be derived from our properties.  Netherland Sewell is an independent petroleum engineering consulting firm that has provided consulting services throughout the world for over 75 years. Netherland Sewell’s estimates were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry.  Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and year-end costs. The proved reserve estimates represent our net revenue interest in our properties.  When preparing our reserve estimates, Netherland Sewell did not independently verify the accuracy and completeness of information and data furnished by us with respect to property interests, production from such properties, current costs of operation and development, current prices for production agreements relating to current and future operations and sale of production, and various other information and data.

According to a reserve report prepared by Netherland Sewell we had proved oil and gas reserves valued at approximately $66.5 million (before taxes) based on a present value calculation with 10% discounting rate. This present value as of June 30, 2016, utilizes an adjusted realized pricing of $37.12 per Bbl for oil and $0.37 per Mcf for natural gas. As of June 30, 2016, 87% of our proved reserves were oil and 37% was proved developed producing, 11% were proved non producing and 52% was proved undeveloped.

Our business strategy is to create a competitive and sustainable rate of return to shareholders by exploring for, acquiring and developing oil and natural gas resources in the United States.  Our primary financial goal is to develop profitably our oil properties while maintaining a strong balance sheet, and specifically to focus on the exploration, exploitation and development of our major oil project – the Foreman Butte project in Montana and North Dakota.

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”).

4

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 16, AMP Building, 140 St Georges Terrace, Perth, Western Australia 6000 and our telephone number at that office is +61 8-9220-9830. 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.

Preparation of Reserves Estimates

Our fiscal year-end petroleum reserves report was prepared by Netherland Sewell in the current year. In prior years it has been completed by Ryder Scott Company. The reports, as prepared by both independent reserve engineers were based upon their review of the property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, geoscience and engineering data, and other information we provide to the firm. The information we provided was reviewed by knowledgeable officers, employees and consultants to the Company, including the Chief Executive Officer, in order to ensure accuracy and completeness of the data prior to its submission to Netherland Sewell in the current year and Ryder Scott in previous years.

Upon analysis and evaluation of data provided, Netherland Sewell issues a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our consulting reserves engineer and our Chief Executive Officer for completeness of the data presented, reasonableness of the results obtained and compliance with the reserves definitions in Regulation S-X. Once all questions have been addressed, Netherland Sewell issues the final appraisal report, reflecting its conclusions.

The technical persons primarily responsible for preparing the estimates presented meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the SPE Standards. Dan Smith, a licensed professional engineer in the state of Texas, has been practicing consulting petroleum engineering at Netherland Sewell since 1980 and has over 7 years of prior industry experience. John G. Hattner, a licensed professional geoscientist in the state of Texas, has been practicing consulting petroleum geoscience at Netherland Sewell since 1991 and has over 11 years of prior industry experience.

Internally, the Chief Executive Officer, Terry Barr, is responsible for overseeing the preparation of the Company’s reserves report and working with Netherland Sewell on its final report. The CEO is a petroleum geologist who holds an associateship in applied geology and has over 40 years of relevant experience in the oil and gas industry.

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

Estimated Proved Reserves

The information set forth below regarding our oil and gas reserves for the fiscal years ended June 30, 2016 was prepared by Netherland Sewell and June 30, 2015 was prepared by Ryder Scott Company L.P.  

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved reserves are categorized as either developed or undeveloped.

5

The following table summarizes certain information concerning our reserves and production in fiscal years ended June 30, 2016 and 2015:

	2016									2015
	Oil  (MBbls)			Gas  (Mcf)			Total (MBOE)			Oil  (MBbls)			Gas  (Mcf)			Total (MBOE)
Beginning of year		1,285			1,183			1,483			1,478			1,763			1,773
Revisions of previous quantity estimates		2,597			2,662			3,041			(376	)		(547	)		(467	)
Extensions and discoveries		-			-			-			414			193			446
Sale of reserves in place		-			-			-			-			-			-
Acquisitions		6,340			5,317			7,226			-			-			-
Production		(240	)		(569	)		(335	)		(231	)		(226	)		(269	)
End of year		9,982			8,593			11,415			1,285			1,183			1,483
Proved developed reserves		3,724			3,092			4,240			1,285			1,183			1,483
Proved developed non producing		970			1,800			1,270			-			-			-
Proved undeveloped reserves		5,288			3,701			5,905			-			-			-
Total proved reserves		9,982			8,593			11,415			1,285			1,183			1,483

Acquisition

The acquisition of reserves consists of proved reserves associated with the Foreman Butte acquisition. This acquisition added 2.1 MMBOE in proved developed producing reserves, 1.4 MMBOE in proved developed non producing reserves and 3.7 MMBOE in proved undeveloped reserves on acquisition date of Mach 31, 2016.

Proved Developed Producing Reserves

In March 2016, we closed on an acquisition of proved reserves, the Foreman Butte project. This project contributed 4.2 MMBOE on June 30, 2016. Following the acquisition, we commenced a workover program to return previously shut in wells to production. This program has accounted for the increase in reserves from March 31, 2016 to June 30, 2016.

We have identified a further 29 wells that are economic to workover in the current oil price environment. These wells are included in the proved non producing reserve category. The work to return these wells to production is planned to be completed during the next year.

During the year ended June 30, 2015 we converted two proved undeveloped locations to proved developed producing locations. We also drilled eight additional wells that are now categorized as PDP.

We have one well which was producing during the year ended June 30, 2015 but was classified as Proved Developed Producing Behind Pipe at June 30, 2015. It had estimated workover costs of $37,000 in order for it to commence production again. This work was completed during the first quarter of the current fiscal year.

Proved Developed Not Producing (PDNP)

PDNP reserves are those estimated proved reserves expected to recovered from existing wells where there is a requirement to achieve a workover to re-establish production

As of June 30, 2016, the PDNP reserves were 1.3 MMBOE. Following the acquisition, we commenced a workover program to return previously shut in wells to production. We have identified a further 29 wells that are economic to workover in the current oil price environment. These wells are included in the proved non producing reserve category. The work to return these wells to production is planned to be completed during the next year.

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Proved Undeveloped Reserves

Proved undeveloped reserves (PUD) are those reserves expected to be recovered from new wells on undeveloped acreage.

As of June 30, 2016, the PUD reserves were 5.9 MMBOE. At acquisition date, the reserves included 12 PUD locations. Following further technical review since the acquisition date we have added 6 more PUD locations to the reserve value. We plan to drill these PUD wells within the next five years.

We did not convert any PUD locations during the year ended June 30, 2016, as we had no PUD locations as at June 30, 2015.

During the year ended June 30, 2015 we successfully drilled two PUD locations (with reserves of 141 MBbls at June 30, 2014) and converted them to PDP locations.

Production, Prices, Costs and Balance Sheet Information

Production

During the years ended June 30, 2016 and 2015, we produced 240,424 and 231,286 barrels of oil, respectively.  During the years ended June 30, 2016 and 2015 we produced 569,008 and 226,707 Mcf of gas, respectively.

For the year ended June 30, 2016 we had one Field (as such term is used within the meaning of applicable regulations of the SEC – See Glossary of Technical Terms) that contains more than 15% of our total proved reserves, namely our interests in the Foreman Butte field in North Dakota, which is part of our Foreman Butte project in North Dakota and Montana.  

The following table discloses our oil and gas production volume, revenue and expenses from the Foreman Butte field for the fiscal year ended June 30, 2016:

	Foreman Butte Field
Oil volume – Bbls		4,396
Revenue – $	$	171,138
Average Price per barrel – $	$	38.93
Gas volume – Mcf		-
Revenue – $		-
Average price per Mcf – $		-
Per unit production and lease operation costs per BOE – $	$	44.50

* We took over operatorship of this field which was acquired within the larger Foreman Butte acquisition on June 2, 2016; therefore the costs associated with this field reflect the structure of the previous operator.

For the year ended June 30, 2015 we had one Field (as such term is used within the meaning of applicable regulations of the SEC – See Glossary of Technical Terms) that contained more than 15% of our total proved reserves, namely our interests in the North Stockyard project in North Dakota.

The following table discloses our oil and gas production volume, revenue and expenses from the North Stockyard field for the fiscal years ended June 30, 2015:

	North Stockyard
Oil volume – Bbls		206,881
Revenue – $	$	11,021,976
Average Price per barrel – $	$	53.27
Gas volume – Mcf		127,660
Revenue – $	$	456,981
Average price per Mcf – $	$	3.58
Per unit production and lease operation costs per BOE – $*	$	22.70

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Prices and Costs

The average sale price (excluding the impact of derivative instruments) we achieved for oil during the years ended June 30, 2016 and June 30, 2015 was $34.27 and $53.33 per barrel, respectively.

The average sale price we achieved for gas during the years ended June 30, 2016 and June 30, 2015 was $1.25 and $3.68 per Mcf, respectively.

The average production costs (including lease operating expenses, production taxes and handling expenses for oil and gas) per barrel of oil was $16.35 for the year ended June 30, 2016 and $22.91 for the year ended June 30, 2015.

Drilling Activity

	Year Ended June 30
	2016		2015		2014
Net productive exploratory wells drilled		Nil		Nil		Nil
Net dry exploratory wells drilled		0.25		0.25		Nil
Net productive development wells drilled		Nil		2.5		2.0
Net dry development wells drilled		Nil		Nil		Nil

Our productive development wells, drilled in the previous years are all in our North Stockyard Project and are described below in “Description of Properties – North Stockyard Project”.

The exploratory wells drilled in the current year and the previous year were both drilled in our South Prairie project in North Dakota.

Present Drilling Activity

As of September 1, 2016, we were not participating in the process of drilling or completing any wells (including wells temporarily suspended).

For a discussion of our present development activity, see “Description of Properties—Exploration / Undeveloped Properties” in “Item 1 and 2. Business and Properties” and “Recent Developments”, “2015 and 2016 Capital Expenditures” and “Estimated 2017 Capital Expenditures” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Oil and Natural Gas Wells and Acreage

As at September 11, 2016, our wells and acreage were as follows:

Gross productive oil wells	209
Net productive oil wells	107
Gross productive gas wells	5
Net productive gas wells	1
Wells with multiple completions	0
Gross Developed Acres	72,520
Net Developed Acres	53,246
Gross Undeveloped Acres	24,081
Net Undeveloped Acres	6,470

In March 2016, we closed on an acquisition, our Foreman Butte project in Montana and North Dakota. This acquisition contributed 131 gross production oil wells and 94 net production oil wells, to the total as of September 11, 2016.

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All of our acreage positions are located in the continental United States, with the majority located in Wyoming, North Dakota and Montana.  We have extensive leases with a variety of remaining lease terms varying from 3 months to four years.  95% of our net developed acres are held by production.  In some cases we have the ability to extend the lease term.

Standardized Measure of Discounted Future Net Cash Flows

Future hydrocarbon sales and production and development costs have been estimated using a 12-month average price for the commodity prices for June 30, 2016 and June 30, 2015 and costs in effect at the end of the periods indicated. The 12-month historical average of the first of the month prices used for natural gas for June 30, 2016 and June 30, 2015 were $0.37 and $4.30 per Mcf, respectively. The 12-month historical average of the first of the month prices used for oil for June 30, 2016 and June 30, 2015 were $37.12 and $59.64 per barrel of oil, respectively.  Future cash flows were reduced by estimated future development, abandonment and production costs based on period–end costs.  No deductions were made for general overhead, depletion, depreciation and amortization or any indirect costs.  All cash flows are discounted at 10%.

Changes in demand for hydrocarbons, inflation and other factors make such estimates inherently imprecise and subject to substantial revisions.  This table should not be construed to be an estimate of current market value of the proved reserves attributable to Samson.

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,
	2016			2015
Future cash inflows	$	373,740		$	72,900
Future production costs		(184,691	)		(22,403	)
Future development costs		(50,752	)		(38	)
Future income taxes		-			0
Future net cashflows		138,297			50,459
10 % discount		(71,550	)		(16,206	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	66,747		$	34,253

In March 2016, we closed the acquisition of our Foreman Butte project. That project makes up $55.7 million in standardized measure of discounted future net cash flows relating to proved reserves as disclosed in the table above.

On June 30, 2016 we signed a purchase and sale agreement to sell our North Stockyard project. This project makes up $10.0 million in standardized measure of discounted further net cash flows relating to proved reserves as disclosed in the table above. The sale price of this asset was $15 million. This sale is expected to close on October 20, 2016. The effective date of the transaction is the day after the closing date.

During the year ended June 30, 2015, we drilled and completed ten wells which are classified as PDP wells, two of which were classified as PUD locations at June 30, 2014.

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The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2016 and June 30, 2015 are as follows (in $’000’s):

	Fiscal Year Ended June 30
	2016			2015
Beginning of year	$	34,253		$	42,593
Sales of oil and gas produced during the period, net of production costs		(3,575	)		(7,178	)
Net changes in prices and production costs		(15,705	)		(22,610	)
Previously estimated development costs incurred during the period		-			1,898
Changes in estimates of future development costs		(14,545	)		-
Extensions and discoveries		-			11,266
Revisions of previous quantity estimates and other		18,074			(6,197	)
Sale of reserves in place		-			-
Purchase of reserves in place		41,564			-
Change in future income taxes		-			11,809
Accretion of discount		3,452			5,440
Other		3,229			(2,768	)
Balance at end of year	$	66,747		$	34,253

The impact of income taxes has not been included in the current year as the net operating losses and the tax basis of the assets exceed the future cashflows.

Description of Properties

Production information is shown net to our interests. Our net revenue interest is included in the total amount.

Reserve information is presented as the net value to us and is the net present value discounted at 10%, based on the forward strip pricing as at June 30, 2016 as calculated by Netherland Sewell.

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.

Following the acquisition, we commenced a workover program to return previously shut in wells to production. This program consisted of working over 32 wells for an estimated cost of $0.8 million.

Since the effective date of the acquisition, the Foreman Butte Project area produced 47,928 barrels of oil.

At June 30, 2016, the Foreman Butte project had net proved reserves of 9.8 MMBo and 8.0 MMcf. These reserves include 3.5 MMBOE in proved developed producing reserves, 1.6 MMBOE in proved non producing reserves and 6.0 MMBOE in proved undeveloped reserves.

North Stockyard Project – Williston Basin, North Dakota

Various working interests

The Bakken formation gained significant prominence after the United States Geological Survey (USGS) published an estimate in April 2008 stating that the unit could recover between 3.0 and 4.3 billion barrels of oil.  The USGS estimated that the Bakken formation represents a “continuous” oil accumulation and suggested that advances in completion technology have increased the estimated recovery potential by 25 times since an earlier USGS study in 1995.

Together with our fellow working interest owners, we have drilled twenty four wells in this field, fourteen in the Bakken Formation, eight in the Three Forks Formation, one in the Mission Canyon formation and one in the second bench of the Three Forks Formation. 

On June 30, 2016 we entered into a purchase and sale agreement to sell our North Stockyard property for $15 million. This transaction is scheduled to close on October 20, 2016.

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At June 30, 2016, the North Stockyard project had net proved reserves of 0.8 MMBo and 1.3 MMcf.

State GC Oil and Gas Field, New Mexico 

Average 32.2% Working Interest

The State GC Oil and Gas Field, located in Lea County, New Mexico, was discovered in 1980 and covers approximately 600 acres.  The field is operated by Legacy Resources.

The State GC# 1 well was drilled in 1980 and has been productive since that time.

Average daily production during the year ended June 30, 2016 from the State GC Oil and Gas Field was approximately 11 BOPD and 13 Mcf/d.

At June 30, 2016, the State GC Oil and Gas Field had net proved reserves of 46,700 Bbls and 66,500 Mcf.

Davis Bintliff #1 Well (Sabretooth Prospect), Brazoria County, Texas  

12.5% Working Interest before payout, 9.375% Working Interest after payout

This well is operated by Davis Holdings. The Davis Bintliff #1 well was completed at the end of October 2008.  

Average daily producing during the year ended June 30, 2016 from the Davis Bintliff #1 well was 1 BOPD and 108 Mcf/d

At June 30, 2016, the Davis Bintliff well had net proved reserves of 1,900 Bbls and 222,100 Mcf.

Exploration / Undeveloped Properties

Hawk Springs Project, Goshen County, Wyoming

37.5% -100% working interest

Spirit of America US 34 #2-29 (Spirit of America II)

100% working interest

The Spirit of America I replacement well, Spirit of America II, was drilled to a total depth of 10,634 feet using a conservative drilling approach to penetrate the troublesome salt section along with heavy weight, oil based mud. Numerous operational difficulties were encountered and the well failed to produce economic quantities of hydrocarbons. $7.3 million in costs associated to drill this well, were written off to the Statement of Operations in the year ended June 30, 2013.

In July 2015, a workover rig was moved to the location to test the Dakota formation from 8,054 feet to 8,064 feet. This formation was found to be water saturated and no hydrocarbons were noted. All costs associated with this well have been written off to the Income Statement during the year ended June 30, 2016.

This well is planned to be plugged in October, 2016.

Defender US 33 #2-29H

37.5% working interest

This well commenced production in February 2012 and has experienced numerous operational and pumping issues. In July 2012, the well was cleaned out and resumed pumping. In June 2015, the well was struck by lightning which affected the electronic controllers associated with the well. These controllers have yet to be repaired due to the well’s low productivity rate.

There was no production from this well during the year ended June 30, 2016. This well is planned to be plugged in October 2016.

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.

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To date, this well has failed to produce economic quantities of hydrocarbons and all costs associated with drilling it have been written off the Statement of Operations.

In October 2016, we plan to test the upper canyon spring zone with a perforation and swab test. This operation is expected to cost $20,000, net to us. Should this operation fail to produce economic quantities of hydrocarbons this well will be plugged immediately.

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 is productive, we do not presently believe that we will 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.

In July 2014, we replaced the pump on the Australia II well and production from this well has recommenced production. During July 2014, the well averaged 100 barrels of oil per day. Following the continued decline in the oil price, this well was shut in from January 2015 to August 2016. It has no reserves associated with it at June 30, 2016.

This well was put back on production in August 2016 and produced at an average rate of 66 BOEPD.

Gretel II

100% working interest

We drilled our second appraisal (exploratory) well in the Roosevelt Project, Gretel II, in January 2012 and fracture stimulated the well in March 2012. Based on the results, it appears that this well was drilled on the north side of the Brockton Fault zone, which is believed to be the western edge of the continuous Bakken oil formation. The Gretel II well is currently shut in, as it was mainly producing water, with just a 5% oil cut. We do not believe that we will recover our costs associated with drilling it. We expensed $11.6 million of previously capitalized exploration expenditure as deferred exploration expenditure, which represent 100% of the costs incurred to June 30, 2012. No further work was been performed on this well bore during the year ended June 30, 2015 or 2016.

This well has not produced during the year ended June 30, 2016 and is expected to be plugged within the next two years.

In total, $24.7 million of previously capitalized exploration expenditure has been expensed to the Statement of Operations as exploration expenditure written off in relation to the drilling costs associated with these two wells during the year ended June 30, 2012.

During the year ended June 30, 2014, we entered into a seismic and drilling agreement with Momentus Energy Corp (“Momentus”), a Canadian exploration and development company based in Calgary, to further explore this project. Momentus shot and processed a 3D seismic survey over the acreage at no cost to us. They were also required to drill a Bakken well in the project area. Due to the recent significant uncertainty in the oil markets, Momentus declined to drill this well within the required time frame and thus the farm-out agreement is no longer valid.

As of June 30, 2015, we have elected to cease all work in the Roosevelt Project and have started letting leases lapse through non- payment of delay rentals, in accordance with the lease agreements. The remaining $8.1 million previously capitalized to the Balance Sheet with respect to this project was written off to the Income Statement during the year ended June 30, 2015.

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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.

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 subsequent to year end.

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. The well produced 87,059 gross barrels of oil during the year ended June 30, 2015. At June 30, 2016 the Gladys had reserves of 18,458 barrels of oil and 22,750 mcf of gas.

There has been no further drilling activity on this lease during the year ended June 30, 2016 and 652 acres have expired.

Cane Creek Project, Grand & San Juan Counties, Utah

Pennsylvanian Paradox Formation, Paradox Basin

100% working interest

On November 5, 2014, we entered into an Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”) covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA. We were granted an option period for two years, expiring November 30^th, 2016 in order to enter into a Multiple Mineral Development Agreement (“MMDA”) with another company who hold leases to extract potash in an acreage position situated within our project area. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area at a cost of $75 per acre to us. The MMDA has been finalized though it has not yet been executed. We are currently in the process of seeking farm out partners to move this project forward.

This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline and exposure to open natural fractures. A 3-D seismic is currently being designed to image these natural fractures. This project displays very robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well. Initial production rates from a well drilled by a competitor are around 1,500 BOPD and decline rates are very modest, as experienced by competitor wells in the area. We have not drilled a well in this area to date.

Risk and Insurance Program

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 the risk of well blowouts, oil spills and other adverse events. We could be held responsible for injuries suffered by third parties, contamination, property damage or other losses resulting from these types of events. In addition, we have generally agreed to indemnify our drilling rig contractors against certain of these types of losses. Because of these risks, we maintain insurance against some, but not all, of the potential risks affecting our operations and in coverage amounts and deductible levels that we believe to be economic. Our insurance program is designed to provide us with what we believe to be an economically appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or loss of human life or liability claims of third parties, attributed to certain assets and including such occurrences as well blowouts and resulting oil spills. We regularly review our risks of loss and the cost and availability of insurance and consider the need to revise our insurance program accordingly. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

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In general, our current insurance policies covering a blowout or other insurable incident resulting in damage to one of our oil and gas wells provide up to $20 million of well control, pollution cleanup and consequential damages coverage and $11 million of third party liability coverage for additional pollution cleanup and consequential damages, which also covers personal injury and death.

If a well blowout, spill or similar event occurs that is not covered by insurance or not fully protected by insured limits, we would be responsible for the costs, which could have a material adverse impact on our financial condition, results of operations and cash flows.

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 September 26, 2016.

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 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, 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. They also can impose substantial liability for the costs of removal or remediation associated with 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 twice 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. If enacted, 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. The draft report has not yet been finalized but a FY2016 budget request was made to fund a response to comments on the draft and to finalize the report.

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.

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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 generate volatile organic compounds (“VOCs”) and nitrous oxides. 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 correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air-emission sources.

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 volatile organic compounds (“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” or “green completion” methods to capture natural gas that would otherwise escape into the air. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves. 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. These new 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 standards regulations issued in June 2016. EPA also intends to conduct future rulemaking to make appropriate revisions to the Prevention of Significant Deterioration and Operating Permit rules under the Clean Air Act.  Moreover, 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 would require most sources of GHG emissions to obtain GHG emission “allowances” to continue their operations.  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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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.

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 Environmental Protection Agency (“EPA”) to review the exemption of E&P wastes under RCRA. The groups had previously filed a Notice of Intent to Sue (“NOI”) EPA in August 2015 for failure to act on a 2010 petition to review the E&P RCRA exemption. 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. 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. Strict liability means liability without fault, and 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, including, 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 22nd, 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 it is expected to be issued in final form later this year. The proposed rule is 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. It deals 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. We are evaluating the economic implications of complying with this rule, but the rule could potentially lead to plugging and abandoning some of our existing oil and gas locations on federal and tribal lands.

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 Note 5 to our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $3.4 million as of June 30, 2016. 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 September 9, 2016, we had 11 employees, including 2 part time employees. The 2 part time employees are located in Perth, Western Australia and are involved in facilitating the administration of the Company.  7 employees are located in Denver, Colorado and 2 are located in North Dakota and work specifically on our Foreman Butte project in North Dakota and Montana.  

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 depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.  Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves that are economically feasible and in developing existing proved reserves.  To the extent that cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired.

Inadequate liquidity could materially and adversely affect our business operations.

We have significant outstanding indebtedness under our credit facility with Mutual of Omaha Bank. As of June 30, 2016, we had drawn $30.5 million of the $30.5 million borrowing base under our credit facility. We were required to pay down our borrowing base by $10 million by June 30, 2016 however on June 30, 2016 we received an extension to make this pay down by August 31, 2016. We received a further extension to October 31, 2016 from Mutual of Omaha Bank following the extension in the anticipated closing date of our sale of the North Stockyard field.

Under the purchase and sale agreement, the purchaser of the North Stockyard field has the right to receive a further extension to the closing date to October 31, 2016 following the payment of $50,000. The purchaser has exercised this right and we have received payment of $50,000. We have also received an extension from Mutual of Omaha Bank with respect to paydown.

If the sale of the North Stockyard field fails to close by October 31, 2016 we would need to examine other options to meet Mutual of Omaha’s paydown requirements, including the sale of other assets, further capital raisings or a new credit facility with an alternative credit provider. This facility may be more expensive and restrictive that our current facility.

In addition to amounts outstanding under our credit facility, the seller in the Foreman Butte acquisition financed an additional $4 million of the purchase price through a secured promissory note issued at closing. The note has a 12-month term and bears interest at 10%. The note is secured by a second-lien mortgage and security interest in substantially all of the acquired assets.

Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition as well as our ability to refinance our current indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control.  We cannot assure you that our business will generate sufficient cash flows from operations, or that future borrowings will be available to us under our credit facility or otherwise, in an amount sufficient to fund our liquidity needs. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems, and we might be required to seek additional debt or equity financing or to dispose of material assets or operations to meet our debt service and other obligations.  We cannot assure you that we would be able to raise capital through debt or equity financings on terms acceptable to us or at all, or that we could consummate dispositions of assets or operations for fair market value, in a timely manner or at all.  Furthermore, any proceeds that we could realize from any financings or dispositions may not be adequate to meet our debt service or other obligations then due. As a result, there are uncertainties with respect to our liquidity, which uncertainty led our auditors in Australia to note, in their report accompanying our fiscal 2016 annual report to the ASX, the existence of a material uncertainty which may cast significant doubt about our ability to continue as a going concern.

Recent amendments to our credit agreement with our primary lender impose additional restrictions on our ability to operate our business and require us to meet additional financial and operational requirements.

As a condition to providing financing for our Foreman Butte acquisition, our primary lender required us to amend our credit agreement to include materially more restrictive terms. These new terms include: (1) more restrictive financial covenants (including the debt-to-EBITDA ratio and minimum liquidity requirements); (2) increases in the interest rate and unused facility fees; (3) a minimum hedging requirement of 75% of our forecasted production; (4) reducing annual G&A expenses from $6 million to $3 million; (5) raising an additional $5 million in equity on or before September 30, 2016, which date has been extended to November 15, 2016 (we raised $1.4 million in April 2016 towards this total and we expect Mutual of Omaha to apply the remaining proceeds from the North Stockyard sale against this balance however there can be no guarantee they will agree to this); (6) paying down at least $10 million of the credit facility by June 30, 2016 (which date has subsequently been extended, as discussed above); and (7) a monthly cash flow sweep of 50% of our cash operating income. These amendments could make it materially more difficult to operate our business, and there can be no assurance that we will be able to remain in compliance with these covenants, particularly in the current oil price environment.

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Our Foreman Butte acquisition is subject to uncertainties, such as our ability to evaluate recoverable reserves and potential liabilities associated with the assets being acquired, and our ability to successfully integrate such assets with our current business.

The success of the Foreman Butte acquisition depends on a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Our assessment of such factors is based on production reports, engineering studies, geophysical and geological analyses and seismic and other information, the results of which are inexact and inherently uncertain. Though the assessments we conducted were generally consistent with industry practices, we may not have fully assessed all of the deficiencies and capabilities of the acquired properties. The success of the Foreman Butte acquisition also depends on our ability to integrate the assets being acquired with our current business and to operate such assets for a profit. If we are not successful in achieving these objectives, the anticipated economic, operational and other benefits and synergies of the Foreman Butte acquisition may not be realized fully or at all, which could result in substantial costs and delays or other operational, technical or financial problems. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce or eliminate the anticipated benefits of the acquisition.

We recorded an impairment on the carrying value of our oil and gas assets during the fiscal year ended June 30, 2016 and 2015, and may again in the future record additional impairments.

We recognized impairment expense of $11.0 million for the twelve months ended June 30, 2016, in addition to the impairment expense of $21.5 million we recognized for the twelve months ended June 30, 2015. The impairment expense recognized in both years is primarily in relation to our North Stockyard project as a direct result of the significant fall in the oil price. Subsequent adverse changes in oil and gas prices or drilling results may result in us being unable to recover the carrying value of our long-lived assets, and make it appropriate to recognize more impairments in future periods. Such impairments could materially and adversely affect our results of operations.

Emerging plays, such as our Hawk Springs and Roosevelt Projects, are subject to heightened risks.

Part of our strategy through the years ended June 30, 2013, 2014 and 2015 was to pursue acquisition, exploration and development activities in emerging plays such as our Hawk Springs Project and Roosevelt Project. Our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Because emerging plays have limited or no production history, we have access to little if any past drilling results in those areas to help predict the results of our own exploratory drilling. In addition, part of our strategy to maximize recoveries from such new projects may involve the drilling of horizontal wells and/or using completion techniques that have proven to be successful in other similar formations.

Given the continued decline in the oil price, we do not intend to invest in our exploration plays in the near future. However, if the oil price recovers, we may determine it is in the best interests of the company to resume exploration activities.

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;

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

· the accuracy of various mandated economic assumptions; and

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· the judgment of the engineers preparing the estimate.

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.

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.

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Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our credit facility if required as a result of a borrowing base redetermination.

In January 2014, we entered into a $25 million credit facility agreement with Mutual of Omaha Bank. In November 2014 this facility was increased to $50 million.  The current borrowing base is $30.5 million and we are drawn to $30.5 million as at June 30, 2016. We intend to continue borrowing under our credit facility in the future as is allowable. The borrowing base is subject to periodic redetermination and is based in part on oil and natural gas prices and the value of properties owned, which could be reduced in the case of asset disposition. A negative adjustment could also occur if the estimates of future prices used by the banks in calculating the borrowing base remain significantly lower than those used in the last redetermination, including as a result of the recent decline in oil prices or an expectation that such reduced prices will continue. Any significant reduction in our borrowing base as a result of such redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of such redetermination, we would be required to repay indebtedness in excess of the newly established borrowing base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations in the future depends on our future performance. Our borrowing base will automatically be reduced to $19 million on October 31, 2016 in accordance with an amendment to our credit agreement, following the extension in the facility to partially fund the Foreman Butte acquisition and an agreement from Mutual of Omaha Bank with respect to the sale of the North Stockyard properties. We currently expect the credit line to be paid down with $11.5 million of the total proceeds from the close of the North Stockyard assets. However, there can be no assurance that this transaction will close or that we may successfully pay down our credit line. We expect our next determination in October 2016 based our reserves as of June 30, 2016.

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:

• 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 or the borrowing base under our revolving credit facility decreases 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. 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.

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;

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— 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.

Oil and natural gas prices are extremely volatile, and decreases in prices have in the past, and could in the future, adversely affect our profitability, financial condition, cash flows, access to capital and ability to grow.

Our revenues, profitability and future rate of growth depend principally upon the market prices of oil and natural gas, which fluctuate widely. The markets for these commodities are unpredictable and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Sustained declines in oil and gas prices may adversely affect our financial condition, liquidity and results of operations. Recently, oil prices have declined significantly. We are particularly dependent on the production and sale of oil and this recent commodity price decline has had, and may continue to have, an adverse effect on us. Further volatility in oil and gas prices or a continued prolonged period of low oil or gas prices may materially adversely affect our financial position, liquidity (including our borrowing capacity under our revolving credit facility), ability to finance planned capital expenditures and results of operations.

It is impossible to predict future oil and gas price movements with certainty. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. Factors that can cause market prices of oil and natural gas to fluctuate include:

• national and international financial market conditions;

• uncertainty in capital and commodities markets;

• the level of consumer product demand;

• weather conditions;

• U.S. and foreign governmental regulations;

• the price and availability of alternative fuels;

• political and economic conditions in oil producing countries, particularly those in the Middle East, including actions by the Organization of Petroleum Exporting Countries;

• the foreign supply of oil and natural gas;

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• the price of oil and gas imports, consumer preferences; and

• overall U.S. and foreign economic conditions.

At various times, excess domestic and imported supplies have depressed oil and gas prices. Additionally, the location of our producing wells may limit our ability to take advantage of spikes in regional demand and resulting increases in price. While increased demand would normally be expected to increase the prices we receive for our oil and natural gas, other factors, such as the recent sharp downturn in worldwide economic activity, may dampen or even reverse any such positive impact on prices.

The profitability of wells are generally reduced or eliminated as commodity prices decline. In addition, certain wells that are profitable may not meet our internal return targets. Recent price declines have caused us to significantly reduce our new exploration and development activity which may adversely affect our results of operations, cash flows and our business.

Lower oil and natural gas prices may not only decrease our revenues, but also may reduce the amount of oil and natural gas that we can produce economically. Such a reduction may result in substantial downward adjustments to our estimated proved reserves and require write–downs of our properties. If this occurs, or if our development costs increase, our production data factors change or our exploration results do not meet expectations, accounting rules may require us to write down the carrying value of our oil and natural gas properties to fair value, as a non–cash charge to earnings.

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, 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 we intend to 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.

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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.

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.

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Intense competition in the oil and gas industry requires us 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 abandon 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.

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 areas; and

4. impose substantial liabilities for pollution 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 (“NEPA”) to obtain the 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 currently is the subject of regulatory scrutiny, negative press, and 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 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.

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 standard in the industry at the time they were performed.

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Our operations also are subject to wildlife-protection laws and regulations such as the Migratory Bird Treaty Act (MBTA). For example, oil companies have been charged with killing migratory birds in North Dakota, where we conduct some of our operations. Reserve pits are used during oil and gas drilling operations. 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. The maximum penalty for each conviction under the MBTA is two years in prison and a $250,000 fine.

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 volatile organic compounds (“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” or “green completion” methods to capture natural gas that would otherwise escape into the air. EPA also issued regulations that set requirements for VOC emissions from several types of equipment, including storage tanks, compressors, dehydrators, and valves. 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. These new 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 standards regulations issued in June 2016. EPA also intends to conduct future rulemaking to make appropriate revisions to the Prevention of Significant Deterioration and Operating Permit rules under the Clean Air Act.  Moreover, 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 would require most sources of GHG emissions to obtain GHG emission “allowances” to continue their operations.  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.

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 rely 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.

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Risks Related to Our Securities

Currency fluctuations may adversely affect the price of our 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, 2016, the Australian dollar has, as a general trend, maintained its value against the U.S. dollar, though the exchange rate 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.

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

The trading prices of our ordinary shares on the ASX and of our ADSs on the NYSE MKT have been, and likely will continue to be, volatile.  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 NYSE MKT 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.

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.

We report as a U.S. domestic issuer, which means increased compliance costs notwithstanding continued eligibility for certain NYSE MKT 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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Even though Samson is now a “domestic issuer” for SEC reporting requirements, we remain a “foreign based entity” for purposes of Section 110 of the NYSE MKT Company Guide. This permits us to apply to the NYSE MKT to have certain of its listing criteria relaxed and receive exemptions from rules applicable to corporations incorporated in the United States. We currently are relying on one Section 110 exemption received in connection with our stock option plan, and is described in more detail in “Item 5—Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Market Information.” While we have no current plans to seek additional Section 110 relief from NYSE MKT, there can be no assurance that we will not do so in the future.

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 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, 2016, 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, 2016, we had outstanding options to purchase an aggregate of approximately 4,000,000 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. In addition, as of June 30, 2016, we had warrants outstanding which may be exercised by warrant holders for 316,615,486 ordinary shares. The exercise prices of the warrants and options are between A$0.033 and A$0.039 per share, and the warrants and options expire between March 2017 and April 2018. The exercise of such warrants could have similarly adverse consequences on the trading prices for our shares.

For further details on our outstanding options and warrants, see “Note 10 – 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. However it is possible 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 and one of our named executive officers 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 3. Legal Proceedings

None.

Item 4. Mine Safety Disclosures

Not applicable.

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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”), each representing 200 ordinary shares, have been listed on the NYSE MKT since January 7, 2008 under the symbol “SSN”. On March 30, 2015 the ratio of ordinary shares to ADS was changed from 20 to 1, to 200 to 1.  As of September 26, 2016 10,198,290 ADSs were outstanding and we had approximately 14,084 beneficial owners of ADS.  The following table sets forth, for the periods indicated, the highest and lowest market quotations for the ADSs reported on NYSE MKT, adjusted for change in ratio.  On September 26, 2016, the closing price of our ADSs on NYSE MKT was $0.735.

	NYSE MKT American Depositary Share (ADS) Price (in USD)
	Fiscal 2016				Fiscal 2015
	High		Low		High		Low
First Quarter (July 1 – September 30)	$	1.02	$	0.53	$	4.50	$	3.20
Second Quarter (October 1 – December 31)	$	0.97	$	0.40	$	3.40	$	1.90
Third Quarter (January 1 – March 31)	$	1.13	$	0.39	$	2.60	$	1.40
Fourth Quarter (April 1 – June 30)	$	0.63	$	0.95	$	1.66	$	0.94

Our ordinary shares were listed on the Australian Securities Exchange Ltd. (the “ASX”) beginning on April 17, 1980.  As of September 26, 2016, 3,215,854,701 ordinary shares were outstanding, and we had approximately 3,905 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.  On September 26, 2016, the closing price of our ordinary shares on the ASX was A$0.005.

	ASX Ordinary Share Price (in AUD)
	Fiscal 2016				Fiscal 2015
	High		Low		High		Low
First Quarter (July 1 – September 30)	$	.007	$	.004	$	.024	$	.019
Second Quarter (October 1 – December 31)	$	.007	$	.003	$	.019	$	.011
Third Quarter (January 1 – March 31)	$	.008	$	.003	$	.016	$	.008
Fourth Quarter (April 1 – June 30)	$	.006	$	.004	$	.010	$	.007

NYSE MKT Corporate Governance Requirements

Our ADSs are listed on the NYSE MKT. Section 110 of the NYSE MKT company guide permits the NYSE MKT to consider the laws, customs and practices of foreign issuers in relaxing certain of its listing criteria, and to grant exemptions from NYSE MKT listing criteria based on these considerations. Any listed company seeking relief under these provisions is required to provide written certification from independent local counsel that the non-complying practice is not prohibited by home country law.

One significant manner in which our governance practices differ from those followed by U.S. domestic companies pursuant to NYSE MKT standards is that in January 2009, with the approval of our Board of Directors, we asked the NYSE MKT for exemptive relief from Section 711 of the NYSE MKT rules, which normally requires shareholder approval of any issuances of equity securities to officers or directors of a listed company, or of a plan like the Samson Oil & Gas Limited Stock Option Plan (the “2009 Plan”).  Such approval is not required under Australian law or the ASX listing rules, and this difference in law was certified to NYSE MKT by the Company’s Australian legal counsel at that time, Minter & Ellison. Under Australian law, approval of the plan by Samson’s Board of Directors is sufficient to adopt the plan under Australian law. Australian law does require shareholder approval for options grants to directors, regardless of whether a Board-approved plan is in place. Therefore, in the event we issue options to directors under the 2009 Plan, we will be required to obtain shareholder approval of the grants.

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The NYSE MKT granted approval for exemption from Section 711 in April 2009. However, we did not receive shareholder approval in connection with the establishment of the 2009 Plan.

On March 14, 2016, we received notification from NYSE MKT that we were not in compliance with certain NYSE MKT continued listing standards relating to stockholders equity as of December 31, 2015.  On May 26, 2016, we received notification from NYSE MKT it had accepted our plan to regain compliance with the applicable listing standards, and we have until September 14, 2017 to do so. The plan includes maximizing production and minimizing costs associated with our operated assets to increase the profitability of the Company.

B.  Holders

As of September 26, 2016, there were approximately 3,905 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 approximately 14,084 beneficial holders of our ADS as of September 26, 2016.

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 2016 Annual General Meeting of Shareholders.

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.

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 at 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:

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· 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.  Therefore there should be no tax payable on any gain on the sale of the 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 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

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· 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.

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 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.

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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.

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.

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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.”

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.

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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 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, 2016 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.

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 includes 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 MKT, 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.

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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 under the excess distribution regime described above, on 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.

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 39.6%. 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).

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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 the 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

The table below contains selected consolidated financial data. The statement of operations, cash flow, balance sheet and other financial data for each year has been derived from our consolidated financial statements. You should read this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and our consolidated financial statements and the related notes included elsewhere in this report.

	Fiscal Year Ended June 30
	2016		2015		2014		2013		2012
Revenues and Other Income
Oil sales	$	8,240,529	$	12,460,171	$	9,616,660	$	5,028,050	$	7,352,494
Gas sales		714,103		834,835		1,001,341		772,073		1,020,945
Other liquids		47,723		-		627		3,985		12,360
Interest income		2,569		30,759		118,076		253,150		355,357
Gain on derivative instruments		-		3,112,268		-		-		0
Gain on sale of oil and gas properties		-		-		2,937,010		-		-
Bargain purchase on acquisition of assets		10,775,231		-		-		-		0
Other		897,448		137,857		66,893		211,736		58,598
Total Revenues and Other Income		20,677,603		16,575,890		13,740,607		6,268,994		8,799,754

	Fiscal Year Ended June 30
	2016			2015			2014			2013			2012
Expenses
Lease operating expense	$	(5,427,752	)	$	(6,117,217	)	$	(4,105,809	)	$	(3,466,339	)	$	(2,789,902	)
Depletion, depreciation and amortization		(4,766,949	)		(6,920,945	)		(2,992,649	)		(1,975,932	)		(2,776,005	)
Impairment of oil and natural gas properties		(11,029,442	)		(21,475,450	)		(83,121	)		(259,529	)		(635,464	)
Exploration and evaluation expenditure		(4,216,077	)		(12,686,943	)		(368,469	)		(7,929,204	)		(30,559,458	)
Accretion of asset retirement obligations		(125,078	)		(40,159	)		(9,236	)		(55,326	)		(23,603	)
General and administrative		(3,685,673	)		(4,812,668	)		(6,457,812	)		(6,313,993	)		(7,880,966	)
Abandonment expense		-			(404,485	)		(726,427	)		-			--
Loss on derivative instruments		(2,657,963	)		-			(504,592	)		-			-
Borrowing Costs		(185,138	)		(135,694	)		(33,632	)		-			-
Interest expense, net of capitalized costs		(1,217,440	)		(598,940	)		(91,422	)		-			-
Total Expenses		(33,311,512	)		(53,192,501	)		(15,373,169	)		(20,000,323	)		(44,665,398	)
Income (loss) from continuing operations		(12,633,909	)		(36,616,611	)		(1,632,562	)		(13,731,329	)		(35,865,644	)
Income tax (provision)/ benefit		-			(3,021	)		(780,611	)		2,010,280			4,629,193
Earnings from continuing operations		(12,633,909	)		(36,619,632	)		(2,413,173	)		(11,721,049	)		(31,236,451	)
Total income (loss) from discontinued operations, net of income taxes		-			-			-			-			-
Net Income (Loss)	$	(12,633,909	)	$	(36,619,632	)	$	(2,413,173	)	$	(11,721,049	)	$	(31,236,451	)
Basic – cents per share	$	(0.43	)	$	(1.29	)	$	(0.21	)	$	(0.61	)	$	(1.78	)
Diluted – cents per share	$	(0.43	)	$	(1.29	)	$	(0.21	)	$	(0.61	)	$	(1.78	)
Net earnings per common share from discontinued operations:
Basic – cents per share	$	-		$	-		$	-		$	-		$	0.00
Diluted – cents per share	$	-		$	-		$	-		$	-		$	0.00
Weighted average common shares outstanding:
Basic		2,919,426,154			2,837,777,322			2,558,418,209			1,935,438,970			1,752,408,357
Diluted		2,919,426,154			2,837,777,322			2,558,418,209			1,935,438,970			1,752,408,357

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Assets held for sale

The assets held for sale have not been treated as discontinued operations as their sale does not represent a material change in the direction of the company, nor do they represent a significant value in the forward looking reserves of the Company.

	Fiscal Year Ended June 30
	2016			2015			2014			2013			2012
Cash flow data:
Cash flow provided by/(used in) operations	$	1,931,977		$	3,044,439		$	(1,527,263	)	$	2,182,311		$	2,820,481
Cash flow provided by /(used in) investing activities		(18,003,433	)		(20,097,069	)		(21,575,457	)		(17,405,124	)		(42,732,283	)
Cash flow provided by/(used in) financing activities	$	16,733,259		$	12,571,190		$	23,455,009		$	9,050,000		$	632,101
Other financial data:
Capital expenditure – oil and gas properties	$	(31,332,473	)	$	(18,339,362	)	$	(17,276,219	)	$	(8,371,024	)	$	(3,384,858	)
Capitalized exploration expenditure and undeveloped acreage		(178,254	)		(1,472,880	)		(1,080,925	)		(6,263,316	)		(5,172,706	)
Balance sheet data:
Cash and cash equivalents	$	2,654,812		$	2,062,720		$	6,846,394		$	13,170,627		$	18,845,894
Property, plant and equipment, net of depletion and impairment		31,830,797			29,964,061			34,796,359			20,359,675			14,338,441
Total assets		52,042,990			40,976,857			68,841,229			52,806,665			55,723,239
Borrowings		(19,000,000	)		(18,699,000	)		(6,000,000	)		-			(7,322	)
Total shareholders’ equity	$	5,191,473		$	16,666,510		$	53,636,102		$	44,907,319		$	48,173,079

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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 & Gas Limited and its subsidiaries collectively.

Overview

We are an independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties. Our principal business is the exploration and development of oil and natural gas properties in the United States.  

During the year, we underwent two transformative transactions. In April 2016, we closed on the acquisition of the Foreman Butte project, 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 for the seller of the assets.

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 is $15 million, and the purchaser has provided a deposit of $1 million. The transaction was initially scheduled to close on August 31, 2016. Under the terms of the purchase and sale agreement, the purchaser could extend the closing date to September 30, 2016 through the payment of $50,000. The purchaser exercised this option on August 31, 2016. The terms of the agreement allow another extension to October 31, 2016 upon payment of an additional $50,000, which the purchaser has also exercised. If the transaction has not closed by October 31, 2016, the agreement will be terminated. The $1 million deposit is not refundable unless environmental or title issues are identified by the purchaser during their due diligence. This asset consists of 22 producing Bakken and Three Forks wells. The effective date of the transaction is the day after the transaction closes. $11.5 million of the proceeds from this transaction will be used to pay down our credit facility with Mutual of Omaha Bank. The remaining proceeds will be used to rebalance our hedge book, following the sale of a portion of our production and for working capital.

Our net oil production was 240,424 barrels of oil for the year ended June 30, 2016 compared to 233,646 barrels of oil for the year ended June 30, 2015. Our net gas production was 569,008 Mcf for the year ended June 30, 2016 compared to 226,707 Mcf for the year ended June 30, 2015.

Recent Developments

Operations

In March 2016 we closed on our Foreman Butte acquisition. We were awarded operatorship of wells located in Montana by the Montana Board of Oil and Gas on April 2, 2016 and we were awarded operatorship of wells located in North Dakota by the North Dakota Industrial Commission on June 3, 2016. After we were awarded operatorship we commenced a workover program to return 32 wells that were non producing to production prior to June 30, 2016.

During August and September 2016, we commenced a second workover program.

The sale of the North Stockyard project is expected to close October 20, 2016. The effective date of the transaction is the day after the sale closes. This project has a written down value of $13.8 million at June 30, 2016. This sale has not been disclosed as a discontinued operation as we do not believe it meets the criteria for this accounting treatment. It is disclosed as an asset held for sale on the Balance Sheet as at June 30, 2016.

During the years ended June 30, 2015 and 2014 we drilled twenty wells in our North Stockyard project in Williams County, North Dakota and one well in our Rainbow project, also in Williams County, North Dakota. All of these wells have all been completed, fracture stimulated and were producing as at June 30, 2016.

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Following the significant fall in the oil price and the below expectation drilling results seen in our exploration properties, we did not complete any significant exploration operations during the year ended June 30, 2016.

During the fiscal year ended June 30, 2016 we wrote off $4.2 million in previously capitalized exploration costs with respect to our Hawk Springs and South Prairie project areas.

During the year ended June 30, 2015 we wrote off $0.7 million with respect to our Hawk Springs project area following lease expirations. We also wrote off $0.9 million with respect to our previously capitalized 3-D seismic in the Hawk Springs Project.

During the year ended June 30, 2014, we entered into a farm-out agreement with Momentus Energy (“Momentus”) with respect to this project. Momentus shot and processed a 3D seismic survey over the acreage at no cost to us. They were also required to drill a Bakken well in the project area. Due to the recent significant uncertainty in the oil markets, Momentus declined to drill this well within the required time frame and thus the farm-out agreement is no longer valid. As a result $8.1 million in previously capitalized exploration costs was written off to the Income Statement during the year ended June 30, 2015. Given the lack of drilling success in this area, we have also opted to let acreage in this project area expire as delay rentals become due.

At South Prairie, the first well drilled was plugged and abandoned based on the logging and show results.  Our second well in our South Prairie project, the York #3-9 was drilled in September 2014, and this was also a dry hole. Following the lack of success of these two wells, $2.6 million in previously capitalized exploration expenditure was written off to the Income Statement during the year ended June 30, 2015. We elected to participate in a third well in this project area, the Badger #1 at a cost of approximately $0.2 million net to us. This well, which tested the Wayne zone of the Mississippian formation spud in August 2015 and was a dry hole. As a result we have written off all previously capitalized cost relating to our South Prairie project.

Capital Raising

In April 2016, we raised $1.4 million in the U.S. through the sale of ordinary shares (represented by American Depositary Shares) via a registered direct offering.

Results of Operations

Net income (loss)

The result for the fiscal year ended June 30, 2016 was a net loss of $12.7 million, compared to a net loss of $36.7 million for the year ended June 30, 2015.  The net loss in 2016 was due to significant write offs in relation to previously capitalized exploration expenditure and impairment losses. The net loss for 2016 also includes $2.7 million in losses on derivative instruments. The loss was offset by $10.7 million recognized in bargain purchase gain with respect to our Foreman Butte transaction.

The loss in 2015 was due to significant write offs in relation to previously capitalized exploration expenditure and impairment losses.

During the year ended June 30, 2016 we wrote off $4.2 million in exploration expenditure in the Statement of Operations. $4.0 million was in relation to our Hawk Springs project and $0.2 million was in relation to our South Prairie project. $2.4 million related to acreage acquisition costs and $1.8 million related to drilling exploration wells. Following the significant decrease in oil prices, and our below expectation drilling results, leases in our exploration properties have not been renewed as they expire.

During the year ended June 30, 2015 we wrote off $8.1 million in exploration expenditure in the Statement of Operations in relation to our Roosevelt project, following the lack of performance of our farm out partner with respect to drilling a well in this area and $2.6 million with respect to our South Prairie project following poor drilling results in that project area. We also wrote off $0.7 million with respect to our Hawk Springs project following lease expirations. We also wrote off $0.9 million in previously capitalized 3-D seismic costs over the Hawk Springs project area.

During the year ended June 30, 2015 we recognized $17.6 in impairment losses with respect to our North Stockyard property, $2.7 million in impairment losses with respect to our Rainbow field, $0.8 million with respect to our asset retirement obligation (“ ARO”) asset following the increase in the associated ARO liability as a result of a change in the amount and timing of estimated costs, and $0.4 million with respect to other smaller fields.

The following table reflects the components of our oil and natural gas production and sales prices, and our operating revenues, costs and expenses, for the periods indicated.

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	Fiscal Year ended June 30,
	2016		2015
Production Volume:
Oil (Bbls)		240,424		233,646
Natural gas (Mcf)		569,008		226,707
BOE		335,259		271,431
Oil Price per Bbl Produced (in dollars):
Realized price	$	34.27	$	53.33
Impact of settled derivative instruments		2.11		10.44
Derivative adjusted price		36.38		63.77
Natural Gas Price per Mcf Produced (in dollars):
Realized price	$	1.25	$	3.68

	Fiscal Year ended June 30,
	2016		2015
Expense per BOE:
Lease operating expenses	$	12.95	$	17.23
Production and property taxes	$	3.40	$	5.68
Depletion, depreciation and amortization	$	14.22	$	25.50
General and administrative expense	$	10.99	$	17.73
Interest expense, net of amounts capitalised	$	3.63	$	2.21

Comparison of Year Ended June 30, 2016 to year ended June 30, 2015

	Year ended
Item	June 30, 2016			June 30, 2015			Variance			% Change
Continuing Operations
Oil and gas revenues	$	9,002,355		$	13,295,006		$	(4,292,651	)		-32	%
Interest income		2,569			30,759			(28,190	)		-92	%
Gain on derivative instruments		-			3,112,268			(3,112,268	)		100	%
Gain on bargain purchase gain on acquisition		10,775,231			-			10,775,231			-100	%
Other income		897,448			137,857			759,591			551	%
Lease operating expense		(5,427,752	)		(6,117,217	)		689,465			-11	%
Depletion, depreciation and amortization		(4,766,949	)		(6,920,945	)		2,153,996			-31	%
Impairment of oil and gas properties		(11,029,442	)		(21,475,450	)		10,446,008			-49	%
Exploration and evaluation expenditure		(4,216,077	)		(12,686,943	)		8,470,866			-67	%
Accretion of Asset Retirement Obligations		(125,078	)		(40,159	)		(84,919	)		211	%
General and administrative cost		(3,685,673	)		(4,812,668	)		1,126,995			-23	%
Abandonment expense		-			(404,485	)		404,485			0	%
Loss on derivative instruments		(2,657,963	)		-			(2,657,963	)		0	%
Borrowing Costs		(185,138	)		(135,694	)		(49,444	)		0	%
Interest expense, net of capitalised costs		(1,217,440	)		(598,940	)		(618,500	)		0	%
Income tax (expense)/benefit		-			(3,021	)		3,021			-100	%
Net income (loss)	$	(12,633,909	)	$	(36,619,632	)	$	23,985,723

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Oil and gas revenues

Oil and gas revenues decreased from the year ended June 30, 2015 to the year ended June 30, 2016, from $13.3 million to $9.0 million.  Oil production increased from 233,646 Bbls for the year ended June 30, 2015 to 240,424 Bbls for the year ended June 30, 2016. The increase in oil produced is a result of our Foreman Butte acquisition. This project added 47,928 barrels of oil from acquisition date of March 31, 2016. The average oil sale price received however, decreased in line with global oil prices to $34.27 per barrel for the year ended June 30, 2016 compared to $53.33 per barrel for the year ended June 30, 2015 (excluding the impact of derivative instruments).  

Our natural gas production increased for the year ended June 30, 2016 to 569,008 Mcf from 226,707 Mcf for the year ended June 30, 2015.  The increase is a result of all of North Stockyard wells being connected to a gas gathering system. The final connections to the gas gathering system occurred at the beginning of the year. Prior to all wells being hooked up to the gathering system, the gas was flared. The realized gas price decreased from $3.69 per Mcf for the year ended June 30, 2015 to $1.25 per Mcf for the year ended June 30, 2016.  

Gain on bargain purchase

During the year ended June 30, 2016 we recognized a gain from bargain purchase of $10.7 million, following the acquisition of our Foreman Butte project for $16.6 million in cash (following post closing adjustments). We determined the fair market value on acquisition date of March 31, 2016 was $29.2 million, resulting in a gain on bargain purchase of $10.7 million after allowing for $1.8 million in asset retirement obligation recognized with respect to this project. The fair value of the project was calculated with reference to the risked PDP and PDNP reserve value using the forward price curve at March 31, 2016.

We did not have a similar transaction in the prior year.

Impairment

Included in the loss for fiscal year ended June 30, 2016 is $11.0 million of impairment expense of oil and gas properties compared to $21.5 million for fiscal year ended June 30, 2015.

The impairment expense in fiscal year 2016 is directly attributable to the decline in the oil price. In December 2016, we recognized impairment expense of $9.8 million: $8.9 million in relation to our North Stockyard property, $0.2 million in relation to our State GC property, and $0.6 million in relation to our Rainbow property. The remaining $0.1 million was in relation to a variety of smaller properties. The impairment recognized was a direct result of the falling oil price. In June 2016, we recognized an additional impairment of $1.2 million; this all relates to the State GC project and is related to the continued depression in the oil price.

During the year ended June 30, 2015, we recognized $17.6 million in relation to the carrying value of our North Stockyard properties. This is directly attributable to the decrease in the oil price. We also recognized $0.8 million in relation to additional asset retirement obligation recognized due to the change in the expected timing of cashflows following the decrease in the oil price. The remaining $0.4 million in impairment expense relates to other fields in our portfolio. $2.7 million of the prior year impairment was a result of the poor production results from our Gladys well in our Rainbow project, combined with the decrease in the oil price. This impairment was recognized at December 31, 2014. Subsequent to that date, an electrical submersible pump was installed on the Gladys well, and its performance has improved. No additional impairment expense was recognized in relation to this well at June 30, 2016.

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Exploration and evaluation expenditures

Exploration expenditures decreased significantly for the year ended June 30, 2016, to $4.2 million from $12.7 million for the year ended June 30, 2015.

During the current year, we wrote off $4.2 million in previously capitalized exploration costs relating to acreage acquisition costs for our Hawk Springs project and additional completion costs associated with exploration wells in this project area. Following the decline in the oil price and below expectations drilling results in these project areas, we have no further exploration plans for these projects.

In the prior year we wrote off $8.1 million in relation to our Roosevelt project and $2.6 million in relation to our South Prairie project – both of which had unsatisfactory drilling results. We have also written off $0.7 million in previously capitalized costs with respect to our leasehold in our Hawk Springs project and associated seismic costs due to lease expirations in the project area. We also wrote off the remaining $0.9 million in previously capitalized 3-D seismic over the Hawk Springs project area. Other exploration expenditure included delay rentals to keep exploration leases active and general exploration expenditure on properties that are yet to meet the criteria for capitalization.

Lease operating expenses

Lease operating expenses decreased from $6.1 million for fiscal year 2015 to $5.4 million in fiscal year 2016.   Although production increased in the period, costs have decreased. Service providers and operators have made concerted efforts to decrease operating costs given the significant and sustained oil price decrease. In addition, we have become operator of a significant portion of our wells and therefore we are able to better control our costs. Lease operating expense per BOE decreased from $17.23 for fiscal year 2015 to $12.95 for fiscal year 2016. 

Our production taxes and handling expenses decreased from $5.68 per BOE for fiscal year 2015 to $3.40 per BOE for fiscal year 2016 due to a decrease in the percentage charged for certain production taxes following the sustained drop in the oil price.

Depletion, depreciation and amortization

Depletion, depreciation and amortization expense decreased from $6.9 million for fiscal year 2015 to $4.8 million in fiscal year 2016.   Depreciation and depletion per BOE for fiscal year 2016 decreased as result of lower capitalized costs (following significant impairments) and higher reserve values in the case of our newly acquired Foreman Butte project, to $14.22 for fiscal 2016 compared to $25.50 for fiscal 2015.

General and administrative expense

General and administrative expense decreased from $4.8 million for the year ended June 30, 2015 to $3.7 million for the year ended June 30, 2016. A change in service providers as well as other cost saving initiatives led to the decrease. Management intends to continue its tight cost control discipline with respect to general and administrative costs in the future.

Gain/(Loss) on derivative instruments

During the year ended June 30, 2015 we recognized a gain of $3.1 million in the change in the fair value of our derivative instruments compared to a loss of $2.7 million in the year ended June 30, 2016. Of the loss recognized in the current year, $3.2 million is unrealized, which was offset by a realized gain of $0.5 million.

Of the gain recognized in the prior year $2.4 million was realized and $0.7 was unrealized.

Interest expense

Interest expense increased in the current to year to $1.2 million compared to $0.7 million for the year ended June 30, 2015. The interest rate associated with our credit facility with Mutual of Omaha increased to three month LIBOR plus 6%, or around 6.8% following the increase in the facility to partially fund the Foreman Butte acquisition. The balance outstanding increased from $18.7 million at June 30, 2015 to $30.5 million at June 30, 2016.

$0.1 million in interest expense was also recognized with respect to the $3.9 million promissory note provided by us to the seller of the Foreman Butte transaction. The promissory note has a face value of $4 million and a 10% cash interest rate, all to be paid in one balloon payment on April 1, 2017. The effective interest rate of the note is 12% to take into account its fair value at inception.

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Liquidity and Capital Resources

Cash flows

	Year ended June 30
	2016			2015
Cash provided by operating activities	$	1,931,977		$	3,044,439
Cash used in investing activities		(18,003,433	)		(20,097,069	)
Cash provided by financing activities		16,733,259			12,571,190

Capital Resources

During the year ended June 30, 2016, our main source of liquidity was cash on hand, cash from operations, proceeds from our credit facility with Mutual of Omaha Bank, financing from the seller of the Foreman Butte transaction and a capital raising completed in April 2016.

We drew down $11.8 million from our Mutual of Omaha credit facility to contribute toward funding the acquisition of our Foreman Butte project. We also delivered a $4 million promissory note to the seller of the Foreman Butte project. In April 2016, we raised $1.3 million, after costs, through the issue of ordinary shares in the form of American Depositary receipts in a registered direct offering. We offered 378,020,400 ordinary shares to U.S. investors at 72 cents (U.S.) per ADS through a registered direct offering.

During the fiscal year ended June 30, 2015 our main source of liquidity was cash on hand, cash from operations, proceeds from our credit facility with Mutual of Omaha Bank and the liquidation of a portion of our derivative instruments.

During the year ended June 30, 2015 we drew down $13.0 million from our credit facility with Mutual of Omaha Bank and repaid $0.3 million.

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

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

· Increases in the interest rate and unused facility fee;

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

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

· A requirement to raise $5 million in equity on or before September 30, 2016 (which was extended to November 15, 2016);

· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 following the agreement to sell our interest in the North Stockyard field for $15 million); and

· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement.

The current borrowing base is $30.5 million and is fully drawn as at September 28, 2016.

As at June 30, 2016 we were in compliance with all of these quarterly covenants.

We have raised $1.4 million in equity towards the total of $5.0 million required under the facility. We expect that Mutual of Omaha Bank will apply the excess proceeds over the $11.5 million required to be paid to Mutual of Omaha Bank to also be applied towards this total, however there can be no guarantee that they will do this. We have received an extension from Mutual of Omaha Bank to raise the remaining funds by November 15, 2016.

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In April 2015, we liquidated a portion of our derivative instruments due for settlement during 2015 for proceeds of $1.2 million.

Our current borrowing base is $30.5 million and we are drawn to $30.5 million as at June 30, 2016. We intend to continue borrowing under our credit facility in the future as is allowable. The borrowing base is subject to periodic redetermination and is based in part on oil and natural gas prices and the value of properties owned, which could be reduced in the case of asset disposition. A negative adjustment could also occur if the estimates of future prices used by the banks in calculating the borrowing base remain significantly lower than those used in the last redetermination, including as a result of the recent decline in oil prices or an expectation that such reduced prices will continue. Any significant reduction in our borrowing base as a result of such redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations. Further, if the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of such redetermination, we would be required to repay indebtedness in excess of the newly established borrowing base, or we might need to further secure the debt with additional collateral. Our ability to meet any debt obligations in the future depends on our future performance. Our borrowing base will automatically be reduced to $19 million on October 31, 2016, following the extension in the facility to partially fund the Foreman Butte acquisition and an agreement from Mutual of Omaha Bank with respect to the sale of the North Stockyard properties. We currently expect the credit line to be paid down with $11.5 million of the total proceeds from the close of the North Stockyard assets. However, there can be no assurance that this transaction will close or that we may successfully pay down our credit line. We expect our next determination in October 2016 based our reserves as of June 30, 2016.

2015 and 2016 Capital Expenditures

During the year ended June 30, 2016 we spent $16.0 million on our Foreman Butte acquisition and $1.5 million on other oil and gas properties, including recompletion activities associated with wells that were categorized as PDNP at acquisition date.

During the fiscal year ended June 30, 2015 we spent $17.6 million drilling and fracture stimulating 10 wells in our North Stockyard project and 1 well in our Rainbow project. We also spent $2.4 million continuing to work on the Bluff exploration well in our Hawk Springs project.

Estimated 2017 Capital Expenditures

Our capital expenditure budget for the year ending June 30, 2017 is estimated at $1.0 million.

We plan to deploy these funds to maximize production in our Foreman Butte project area. We plan to fund this activity through cash on hand, future cash flows and possible asset sales.

Any capital expenditure remains dependent on us having the capital required to meet the expenditure. We will not be able to fund all of the planned expenditure from our existing working capital and there is no guarantee we will be able to raise the funds through the debt or equity markets.

Off-Balance Sheet Arrangements

At June 30, 2016, 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

In March 2016 we closed on our Foreman Butte acquisition. We were awarded operatorship of wells located in Montana by the Montana Board of Oil and Gas on April 2, 2016 and we were awarded operatorship of wells located in North Dakota by the North Dakota Industrial Commission on June 3, 2016. After we were awarded operatorship, we commenced a workover program to return 32 wells that were non producing to production prior to June 30, 2016. On the date of acquisition the PDP value of this property was $22.1 million (based on the forward curve at acquisition date of March 31, 2016). On June 30, 2016 the PDP value of this property (based on the forward curve on June 30, 2016) was $46 million. The total proved value of the property (based on the forward curve at June 30, 2016) was $109 million.

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On November 5, 2014, we entered into an Other Business Arrangement (“OBA”) with the Utah School and Institutional Trust Lands Administration (“SITLA”) covering approximately 8,080 gross/net acres located in Grand and San Juan Counties, Utah, all of which are administered by SITLA. We were granted an option period for two years in order to enter into a Multiple Mineral Development Agreement (“MMDA”) with another company that holds leases to extract potash in an acreage position situated within our project area. The MMDA is largely finalized however has not yet been executed by either party. Upon entering into the MMDA, SITLA is obligated to deliver oil and gas leases covering our project area at a cost of $75 an acre to us. We are currently seeking farm out partners to move this project forward.

This acreage is located in the heart of the Cane Creek Clastic Play of the Paradox Formation along the Cane Creek anticline. The primary drilling objective is the overpressured and oil saturated Cane Creek Clastic interval. Keys to the play to date include positioning along the axis of the Cane Creek anticline and exposure to open natural fractures. The 3-D seismic is currently being designed to image these natural fractures. This project displays very robust economics in a low priced oil environment using the evidence obtained from a nearby competitor well. Initial production rates from a competitor wells are around 1,500 BOPD and decline rates experienced by a competitor wells are very modest. We have not drilled a well in this project area to date.

Divestitures

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 is $15 million; the purchaser has provided a deposit of $1 million. The transaction was initially scheduled to close on August 31, 2016, although under the terms of the purchase and sale agreement, the purchaser could extend the closing date to September 30, 2016 through the payment of $50,000. The purchaser exercised this option on August 31, 2016. The terms of the agreement allow another extension to October 31, 2016 upon payment of an additional $50,000. The purchaser exercised this option on September 28, 2016. If the transaction has not closed by October 31, 2016, the agreement will be terminated. The $1 million deposit is not refundable unless environmental or title issues are identified by the purchaser during their due diligence. This asset consists of 22 producing Bakken and Three Forks wells. The effective date of the transaction is the day after the transaction closes. $11.5 million of the proceeds from this transaction will be used to pay down our credit facility with Mutual of Omaha Bank. The remaining proceeds will be used to rebalance our hedge book, following the sale of a portion of our production and for working capital.

In August 2013, we divested half our equity position in the undeveloped acreage in the North Stockyard project to Slawson Exploration Company Inc. for $5.6 million in cash and other consideration. We retained our full interest in the currently producing wells in the North Stockyard field. As a consequence of the transaction we have terminated our rig contract with Frontier, with no penalty payment. Slawson is now the operator of the project going forward for the development of the undeveloped acreage. Along with the undeveloped acreage, we have also transferred our 25% working interest in the Billabong and Sail and Anchor wells, which were drilled but not completed at the time of the sale. The cash portion of the purchase price was subject to the delivery of a useable well bore in Billabong, valued in the agreement at $0.9 million and other customary post-closing adjustments. The workover operation was completed on the Billabong well during the year ended June 30, 2014, and Slawson has agreed to take over the well bore. This well commenced production during the year ended June 30, 2015.

Trends Affecting Our Results of Operation

Lease Operating Expenses

Following the decrease in global oil prices, lease operating expenses have also shown a downward trend. There can be no guarantee this will continue. Following the Foreman Butte acquisition, we are now the operator of the majority of our wells. Our focus in the coming 12 months will be to continue to lower operating costs while continuing to operate safely and efficiently. 

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon financial statements that have been prepared in accordance with U.S. GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain accounting policies as being of particular importance to the presentation of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and natural gas revenues, oil and natural gas properties, exploration and valuation expenditure, share based payments, income taxes and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies and estimates affect our more significant judgments and estimates used in the preparation of our financial statements.

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Reserves Estimates

Our estimates of proved reserves are based on the quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, Samson must estimate the amount and timing of future operating costs, production, and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, we use the units–of–production method to amortize our oil and gas properties, which means that the quantity of reserves could significantly impact our depletion, depreciation and amortization expense.  The value of our reserves also impacts any impairment expense recognized. 

Successful efforts

The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method.  Under this method, all property acquisition costs and costs of drilling exploratory wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Costs of drilling development wells are capitalized regardless of the success of the well.  Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred.  Upon surrender of undeveloped properties, the original cost of such properties is charged against income.

Exploration and Evaluation Expense

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 we are 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 year ended June 30, 2016 we expensed $4.1 million in exploration expenditure written off in relation to acreage acquisition and additional completion costs incurred with respect to our Hawk Springs project in Wyoming.

During the year ended June 30, 2015 we expensed $8.1 million in exploration expenditure written off in relation to our Roosevelt project in Montana, $2.6 million in relation to our South Prairie project in North Dakota and $1.6 million in relation to our Hawk Springs project in Wyoming.

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense, so revisions in such estimates may alter the rate of future expense.  Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit–of–production method.  The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties.  With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves.  Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.  Certain other assets are depreciated on a straight–line basis.

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Amortization rates are updated four times a year to reflect: the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions or dispositions, and impairments.

Impairments

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.

We recorded impairment charges of $11.0 million and $21.5 million for the years ended June 30, 2016 and 2015 respectively. 

The charges in the fiscal year ended June 30, 2016 related to the impact of the decrease in the oil price and its impact on the future expected value from our North Stockyard, State GC and Rainbow fields.

The charges in the fiscal year ended June 30, 2015, related to the poor performance in comparison to the high drilling costs of our Gladys well in our Rainbow project and a decrease in the value of our North Stockyard property as a direct result of the significant decrease in the oil price.

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.

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 a binomial option pricing model.  The use of the binomial 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.

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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

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.

Recently Adopted Accounting Standards

There have been no recently adopted accounting standards that would impact our business.

Recently Issued Accounting Pronouncements

ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Update (ASU) 2014-09 provides a new framework for addressing revenue recognition issues and upon its effective date, replaces almost all existing revenue recognition guidance. While the revenue recognition policies of all entities will be impacted by this standards, we do not expect the impact to be significant. For public business entities, the guidance is effective for annual reporting periods beginning after December 15, 2017, including interim period’s within that reporting period.

ASU 2015-01 Income Statement – Extraordinary and Unusual Items (Subtopic 225-20): Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. The amendments in ASU 2015-01 eliminate from U.S. GAAP the concept of extraordinary items. The amendments are effective for fiscal years, and interim periods within those fiscal years, for all entities beginning after December 15, 2015.

ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendments in ASU 2015-03 are intended to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this ASU. These amendments are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

ASU 2015-15, Presentation of Financial Statements – Going Concern (Subtopic 205 -40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendments in ASU 201-15 require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Until issuance of this pronouncement, the requirement to perform a going concern evaluation existed only in auditing standards. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when it plans to alleviate substantial doubt about the Company’s ability to continue as a going concern. The amendments are effective for annual periods of all entities ending after December 15, 2016 and for interim periods within those fiscal years.

52

ASU 2016-02, Leases (Topic 842) This ASU, among other provisions, requires lessees to recognize right of use assets and leases liabilities for all leases not considered short term leases. The ASU is effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.

We have not yet begun to assess the impact of these standards on our financial reporting. However, we do not expect these changes to have a significant impact on our financial statements with the exception of additional disclosures.

Item 8. Financial Statements and Supplementary Data

See “Index to Consolidated Financial Statements” on page 59 of this report.

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure 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, 2016. 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 Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on such evaluation, our CEO and CFO concluded that, as of the evaluation date, our disclosure controls and procedures were effective.

Management’s Annual Report on Internal Control over Financial Reporting.   Our management is 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 CEO and CFO, we assessed the effectiveness of our internal control over financial reporting as of June 30, 2016, 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, management has concluded that, as of June 30, 2016, our internal control over financial reporting is effective based upon these criteria.

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.

53

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

54

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2016 annual shareholders’ meeting and is incorporated by reference in this report.

Item 11. Executive Compensation

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2016 annual shareholders meeting and is incorporated by reference in this report.

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

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2016 annual shareholders’ meeting and is incorporated by reference in this report.

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

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2016 annual shareholders’ meeting and is incorporated by reference in this report.

Item 14. Principal Accounting Fees and Services

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2016 annual shareholders’ meeting and is incorporated by reference in 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 59.

Exhibits

Number	Description
3.1	Constitution of Samson Oil & Gas Limited (incorporated by reference to Exhibit 1 to the Registration Statement on Form 20-F filed on July 6, 2007, as amended by Form 20-F/A).
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).+

55

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).
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).

56

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 May 9, 2016).
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 Hein & Associates LLP.
23.2	Consent of Ryder Scott Company, L.P.
23.3	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. **
99.1	Report of Netherland, Sewell & Associates Inc. Regarding the Registrant’s Reserves as of June 30, 2016.
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

** Furnished herewith

+ Management contract or compensatory plan or arrangement

57

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:	September 28, 2016

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)	September 28, 2016
Terence Barr
/s/ Robyn Lamont	Chief Financial Officer (Principal Financial Officer)	September 28, 2016
Robyn Lamont
/s/ Peter Hill	Director	September 28, 2016
Peter Hill
/s/ Greg Channon	Director	September 28, 2016
Greg Channon
/s/ Denis Rakich	Director	September 28, 2016
Denis Rakich

58

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	60
Consolidated Balance Sheets as of June 30, 2016 and 2015	61
Consolidated Statements of Operations and Comprehensive Income for the Fiscal Years Ended June 30, 2016 and 2015	62
Consolidated Statements of Changes in Stockholders’ Equity for the Fiscal Years Ended June 30, 2016 and 2015	63
Consolidated Statements of Cash Flows for the Fiscal Years Ended 2016 and 2015	64
Notes to Consolidated Financial Statements	65

59

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

Samson Oil & Gas Limited

We have audited the accompanying consolidated balance sheets of Samson Oil & Gas Limited and subsidiaries as of June 30, 2016, and 2015 and the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Samson Oil & Gas Limited and subsidiaries as of June 30, 2016 and 2015 and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

/s/ Hein & Associates LLP

Hein & Associates LLP

Denver, Colorado

September 28, 2016

60

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	June 30
	2016			2015
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,654,812		$	2,062,720
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively		1,996,415			3,645,223
Oil Inventory		463,768			0
Prepayments		183,305			372,079
Fair value of derivative instruments		-			159,216
Oil and gas properties held for sale		13,768,865			-
Total current assets		19,067,165			6,239,238
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment  of $15,049,015 and $44,273,976 at June 30, 2016 and June 30, 2015, respectively		31,522,323			29,715,540
Other property and equipment, net of accumulated depreciation and amortization of $573,995 and $553,428 at June 30, 2016 and June 30, 2015, respectively		308,474			248,521
Net property, plant and equipment		31,830,797			29,964,061
OTHER ASSETS
Unproved capitalized acreage		220,703			2,941,422
Capitalized exploration expense		-			1,388,798
Fair value of derivative instruments		-			101,269
Restricted cash - collateral for bonds		450,000			-
Other		474,325			342,069
TOTAL ASSETS	$	52,042,990		$	40,976,857
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	4,125,643		$	1,678,915
Accrued liabilities		1,629,975			1,999,344
Provision for annual leave		194,497			219,414
Amounts due for current repayment from the credit facility		11,500,000			-
Promissory Note, net of discount, including accrued interest		4,046,428			-
Fair value of derivative instruments		1,671,653			-
Total current liabilities		23,168,196			3,897,673
Fair value of derivative instruments		1,233,076			-
Asset retirement obligations		3,450,245			1,263,674
Credit facility		19,000,000			18,699,000
Total liabilities		46,851,517			23,860,347
Commitments and contingencies (Note 12)
STOCKHOLDERS’ EQUITY
Common stock, 3,215,854,701 and 2,837,782,022 shares issued and outstanding at June 30, 2016 and 2015, respectively		105,719,184			104,491,774
Accumulated other comprehensive income		927,718			996,256
Accumulated deficit		(101,455,429	)		(88,821,520	)
Total stockholders’ equity		5,191,473			16,666,510
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	52,042,990		$	40,526,857

See accompanying Notes to Consolidated Financial Statements.

61

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

	Fiscal year ended June 30,
	2016			2015
REVENUES AND OTHER INCOME:
Oil sales	$	8,240,529		$	12,460,171
Gas sales		714,103			834,835
Other liquids		47,723			-
Interest income		2,569			30,759
Gain on derivative instruments		-			3,112,268
Gain on bargain purchase of oil and gas properties		10,775,231			-
Other		897,448			137,857
TOTAL REVENUE AND OTHER INCOME		20,677,603			16,575,890
EXPENSES:
Lease operating expense		(5,427,752	)		(6,117,217	)
Depletion, depreciation and amortization		(4,766,949	)		(6,920,945	)
Impairment of oil and natural gas properties		(11,029,442	)		(21,475,450	)
Exploration and evaluation expenditure		(4,216,077	)		(12,686,943	)
Accretion of asset retirement obligations		(125,078	)		(40,159	)
General and administrative		(3,685,673	)		(4,812,668	)
Abandonment Expense		-			(404,485	)
Loss on derivative instruments		(2,657,963	)		-
Borrowing costs		(185,138	)		(135,694	)
Interest expense		(1,217,440	)		(598,940	)
TOTAL EXPENSES		(33,311,512	)		(53,192,501	)
Loss before income tax		(12,633,909	)		(36,616,611	)
Income tax (provision)/ benefit		-			(3,021	)
Net loss	$	(12,633,909	)	$	(36,619,632	)
OTHER COMPREHENSIVE LOSS
Foreign Currency Translation loss		(68,538	)		(305,840	)
Total comprehensive loss for the period	$	(12,702,447	)	$	(36,925,472	)
Net loss per common share:
Basic – cents per share		(0.43	)		(1.29	)
Diluted – cents per share		(0.43	)		(1.29	)
Weighted average common shares outstanding:
Basic		2,919,426,154			2,837,777,322
Diluted		2,919,426,154			2,837,777,322

See accompanying Notes to Consolidated Financial Statements.

62

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

				Retained			Other
	Issued			Earnings/(Accumulated			Comprehensive
	Capital			Deficit)			Loss			Total Equity
Balance at July 1, 2014	$	104,535,894		$	(52,201,888	)	$	1,302,096		$	53,636,102
Net loss		-			(36,619,632	)		-			(36,619,632	)
Foreign currency translation		-			-			(305,840	)		(305,840	)
Total comprehensive loss for the period		-			(36,619,632	)		(305,840	)		(36,925,472	)
Issue of share capital		880			-			-			880
Share issue costs		(45,000	)		-			-			(45,000	)
Balance at June 30, 2015	$	104,491,774		$	(88,821,520	)	$	996,256		$	16,666,510
Net loss		-			(12,633,909	)		-			(12,633,909	)
Foreign currency translation		-			-			(68,538	)		(68,538	)
Total comprehensive loss for the period		-			(12,633,909	)		(68,538	)		(12,702,447	)
Issue of share capital		1,400,150			-			-			1,400,150
Share issue costs		(172,740	)		-			-			(172,740	)
Balance at June 30, 2016	$	105,719,184		$	(101,455,429	)	$	927,718		$	5,191,473

See accompanying Notes to Consolidated Financial Statements.

63

SAMSON OIL & GAS LIMITED AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Fiscal year ended June 30,
	2016			2015
Cash flows from operating activities
Receipts from customers	$	10,443,411		$	13,177,704
Net cash received from commodity derivative financial instruments		637,980			2,275,026
Payments to suppliers & employees		(9,015,060	)		(11,172,887	)
Interest received		2,573			31,061
Interest paid		(808,144	)		(481,714	)
Income taxes paid		-			(107,135	)
Payments for abandonment costs		(53,783	)		(677,616	)
Proceeds from legal settlement		725,000			-
Net cash flows provided by operating activities		1,931,977			3,044,439
Cash flows from investing activities
Proceeds from sale of oil and gas properties		1,000,000			-
Payments for operating bonds		(450,000	)		-
Payments for plant & equipment		(183,266	)		(20,249	)
Payments for exploration and evaluation		(749,731	)		(2,406,192	)
Payments of business combination		(16,089,029	)		-
Payments for oil and gas properties		(1,531,407	)		(17,670,628	)
Net cash flows used in investing activities		(18,003,433	)		(20,097,069	)
Cash flows from financing activities
Proceeds from issue of share capital		1,400,150			880
Proceeds from short term borrowings		4,000,000			-
Proceeds from borrowings		11,801,000			13,000,000
Repayments of borrowings		-			(301,000	)
Payments for costs associated with borrowings		(295,151	)		(83,690	)
Payments for costs associated with capital raising		(172,740	)		(45,000	)
Net cash flows provided by financing activities		16,733,259			12,571,190
Net change in cash and cash equivalents		661,803			(4,481,440	)
Cash and cash equivalents at the beginning of the year		2,062,720			6,846,394
Effects of exchange rate changes on cash and cash equivalents		(69,711	)		(302,234	)
Cash and cash equivalents at end of year	$	2,654,812		$	2,062,720

See accompanying Notes to Consolidated Financial Statements.

64

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, Montana and Wyoming.

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. All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates.   The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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; (4) asset retirement obligations; (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 expenditure. 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. 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.   Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of completed deliveries where title has transferred. Title to oil sold is typically transferred at the wellhead.

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, 2016 or 2015.

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.

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

	June 30
	2016		2015
Oil and natural gas sales	$	1,717,110	$	3,224,595
Cost recovery from drilling partners		275,018		275,148
Other		4,287		145,480
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015	$	1,996,415	$	3,645,223

65

The Company's accounts receivable result from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are primarily from the operators of our various projects, who negotiate the sale of oil and gas to third parties on our behalf.

The cost recovery from drilling partners relates to the partners share of drilling costs associated with the current drilling program in our North Stockyard infill project and Hawk Springs project.

Accruals.   The components of accrued liabilities for the years ended June 30, 2016 and 2015 are as follows:

	2016		2015
Bonus accrual		-		-
Other accruals		629,975		1,999,344
Deposit received for asset sale		1,000,000		0
	$	1,629,975	$	1,999,344

Other accruals includes an estimate of the costs expected to be incurred with respect to the asset retirement obligation in the next twelve months.

The deposit received from the asset sale is non-refundable (subject to the identification of certain title or environmental defects for the deadline for providing notification to the Company has passed) deposit received from the purchaser of our North Stockyard assets.

The majority of other accruals in the prior year relate to expenses incurred in relation to our exploratory well, Bluff, in our Hawk Springs project and other general accruals.

Oil and Gas Properties.

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

	2016			2015
Proved properties	$	45,177,047		$	61,724,561
Lease and well equipment		1,394,291			12,264,955
Less accumulated depreciation, depletion and impairment		(15,049,015	)		(44,273,976	)
	$	31,522,323		$	29,715,540
Assets held for sale		13,768,865			-
Unproved acreage	$	220,703		$	2,941,422
Capitalized exploration expense	$	-		$	1,388,798

The Company accounts for its oil and 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.

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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 cost 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.

Assets held for sale

On June 30, 2016, the Company signed a Purchase and Sale Agreement for the sale of its interests in the North Stockyard field. The purchase price of the acquisition is $15 million and the acquisition is expected to settle on October 20, 2016. The effective date of the acquisition is the day after the closing date. The Company received a $1 million deposit from the purchaser on the date of signing, recorded in current liabilities. This deposit is only refundable if certain title or environmental defects are identified during the purchaser’s due diligence. The date by which the purchaser was required to notify the Company of any title or environmental defects has passed and the Company was not advised of any environmental or title defects.

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;

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· 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 year ended June 30, 2016, we expensed $4.2 million in deferred exploration expense in relation to our Hawk Springs project area.

During the fiscal year ended June 30, 2015 the Company expensed $8.1 million in relation to our Roosevelt project in Montana. During the year ended June 30, 2014 the Company entered into a farm out arrangement with respect to this property however due to the falling oil prices, the farm out partner failed to meet its obligations under the agreement. The Company does not plan to spend any additional capital in this project area and therefore we have written off the previously capitalized exploration expenditure. The Company also wrote off $2.5 million with respect to its South Prairie project in North Dakota. A second dry hole was drilled in the area during the year ended June 30, 2015 and the decision was made to write off the costs capitalized with respect to this project. The Company also expensed $1.6 million with respect to its Hawk Springs project in Wyoming. These costs were associated with leases expiring during the year. The Company also expensed $0.4 million of general exploration expenditure, which was never capitalized to the Balance Sheet.

Impairment 

The Company recorded impairment charges of $11.0 million and $21.5 million for the years ended June 30, 2016 and 2015 respectively.

The charges in the fiscal year ended June 30, 2016 related to the impact of the drop in the oil price on our North Stockyard, Rainbow and State GC project areas.

The charges in the fiscal year ended June 30, 2015 related to the impact of the drop in the oil price on our Rainbow and North Stockyard projects in North Dakota.

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, 2016 and 2015 was $0.1 million and $0.1 million, respectively.

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

	2016			2015
Furniture, fittings and equipment	$	882,469		$	801,949
Less accumulated depreciation		(573,995	)		(553,428	)
	$	308,474		$	248,521

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.

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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.

Earnings per Share.   Basic earnings (loss) per share are calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares. 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.

The following potential common shares relating to options and warrants have been excluded from the calculation of diluted earnings per share as the related impact was anti-dilutive.

	Year ended June 30,
	2016		2015
Dilutive		-		-
Anti–dilutive		321,955,194		357,099,676

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.

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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 Consolidated Entity 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 exceeds the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately.

In the current period, the Company recognized a gain on bargain purchase of $10.9 million with respect to its acquisition of certain producing and non producing assets, known as the Foreman Butte project.

Impact of Recently Adopted Accounting Standards.   

There have been no recently adopted accounting standards that would impact our business.

Recently Issued Accounting Pronouncements

In August 2014, the FASB issued new guidance related to the disclosures around going concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

In November 2014, the FASB issued ASU No. 2014-16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity.  This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted.  The Company is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its consolidated financial statements.

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

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2. BUSINESS COMBINATION

On March 31, 2016, the Company closed on the acquisition of producing and non producing wells in the Madison and Ratcliffe formations in North Dakota and Montana. The acquisition had an effective date of October 31, 2015 and closed on March 31, 2016.

	USD
Amount Settled in Cash	$	1,391,874
Extension of credit facility		11,500,000
Fair value of promissory note provided		3,928,571
Fair value of consideration transferred		16,820,445
		-
Recognised amounts of identifiable assets and liabilities:
Oil and gas properties		29,350,256
Oil inventory acquired		463,768
Trade receivables		53,540
Revenue in suspense assumed		(403,612	)
Asset retirement obligation assumed		(1,868,276	)
Net identifiable assets and liabilities		27,595,676
Gain on bargain purchase		10,775,231

Consideration Transferred

The cost of the acquisition was settled in cash and the promissory note in the amount of $16.6 million (including post closing settlement payments). $1.2 million was settled from the Company’s cash reserves, $11.5 million came from an extension of the Company’s credit facility with Mutual of Omaha Bank and $3.9 million was provided by a promissory note provided to the seller of the assets. The fair value of the promissory note was determined to be $3.9 million on acquisition date based on an effective interest rate of 12%. The face value of the note is $4 million. The note accrues 10% interest per annum, and is due for repayment on April 1, 2017. The interest is payable in a balloon payment at maturity. The note is secured by a second lien over all the assets acquired.

Identifiable net assets

The assets, collectively known as the Foreman Butte acquisition, consist of interests in a number wells, both operated and non operated in the Madison and Ratcliffe formations in Montana and North Dakota. The fair value of the assets acquired was determined with reference to the reserve value of those assets at acquisition date, the Company’s cost of capital and other comparable transactions.

The trade receivables, oil inventory and revenue in suspense were recognized at face value as this approximates fair value.

The Company incurred acquisition costs of $0.2 million which have been expensed.

Proforma Contribution to Results (unaudited)

Contribution of Business Combination to Company Results

The following represents the amount of the Company's revenue and losses for the years ended June 30, 2016 and June 30, 2015, assuming the business combination occurred on July 1, 2014.

	2016			2015
Revenues	$	25,579,347		$	19,849,812
Losses		(15,762,744	)		(35,982,244	)

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These results do not necessarily reflect the results that would have been incurred if the Company did own the assets as of July 1, 2014.

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, 2016, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below:

Collar	Collars contain a fixed floor price (put) and fixed ceiling price (call).  If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price 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 Mutual of Omaha Bank, the provider of the Company’s credit facility. As such no collateral is required by the counterparty.

At June 30, 2016 the Company’s open derivative contracts consisted of the following:

Collar

Product	Start Date	End Date	Volume (BO/Mmbtu)		Floor		Ceiling
WTI	1-Jul-16	30-Apr-18		133,032		41.50		63.00
Henry Hub	1-Jul-16	31-Oct-16		127,229		1.90		2.40
Henry Hub	1-Nov-16	31-Mar-17		134,088		2.60		3.35
Henry Hub	1-Apr-17	31-Oct-17		167,682		2.40		2.91
Henry Hub	1-Nov-17	30-Apr-18		127,030		2.80		3.60

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Fixed price swap
Product	Start	End	Volume (BO)		Swap
WTI	1-Jul-16	31-Dec-16		83,730		41.20
WTI	1-Jan-17	31-Dec-17		141,255		44.09
WTI	1-Jan-18	30-Apr-18		39,720		45.55

At June 30, 2015 the Company’s open derivative contracts consisted of the following:

Oil Price Collars – WTI	Volumes (bbls)		Floor US$		Ceiling US$
January 2016 - February 2016		2,788		85.00		89.85

Oil Price Swaps – WTI	Volumes (bbls)		Price US$
July 2015 - December 2015		8,765		105.00
January 2016 - February 2016		2,788		105.00

Oil Price Three Way Swaps - WTI	Volumes (bbls)		Ceiling US$		Sub Floor US$		Floor US$
July 2015- December 2015		55,200		70.25		32.50		45.00
January 2016 - December 2016		27,450		80.00		40.00		55.00
January 2016 – December 2016		36,600		-		67.50		82.50

During the year ended June 30, 2016, the Company recognized $2.7 million in the Statement of Operations in loss in derivative instruments. As of June 30, 2016, the derivative instruments were valued at a unrealized loss of $2.8 million of which, $1.6 million is recorded as a current liability and $1.2 million is recorded as a non-current liability.

During the year ended June 30, 2015, the Company recognized $3.1 million in the Statement of Operations in gain on derivative instruments. As of June 30, 2015, its derivative instruments were valued at $159,216 recorded as current asset and $101,269 recorded as a non-current asset.

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

Price risk

Price risk arises from the Company’s exposure to oil and gas prices. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  Sustained weakness in oil and natural gas prices may adversely affect the Company’s financial condition.

The Company manages this risk by continually monitoring the oil and gas price and the external factors that may affect it.  The Board reviews the risk profile associated with commodity price risk periodically to ensure that it is appropriately managing this risk.  Derivatives are used to manage this risk where appropriate.  The Board must approve any derivative contracts that are entered into by the Company.

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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, 2016 and 2015.

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

	Fair Value at June 30, 2015
	Level 1		Level 2		Level 3		Netting (1)			Total
Current Assets:
Cash and cash equivalents	$	2,062,720	$	-	$	-	$	-		$	2,062,720
Derivative Instruments		-		379,540		-		(220,324	)		159,216
Non Current Assets:
Derivative Instruments		-		298,703		-		(197,434	)		101,269
Current Liabilities
Derivative Instruments		-		220,324		-		(220,324	)		-
Non Current Liabilities:
Derivative Instruments				197,434				(197,434	)		-

(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. 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, 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, including the Foreman Butte acquistion, 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, 2016 and 2015:

	2016			2015
Asset retirement obligations at beginning of period	$	1,810,674		$	1,775,792
Liabilities incurred or acquired		1,868,276			672,339
Liabilities settled		(53,783	)		(677,616	)
Disposition of properties		-			-
Accretion expense		125,078			40,159
Asset retirement obligations at end of period		3,750,245			1,810,674
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		(300,000	)		(547,000	)
Long-term asset retirement obligations	$	3,450,245		$	1,263,674

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

The liabilities incurred in the current year relate to the liabilities acquired in relation to the Foreman Butte acquisition.

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
	2016		2015
Current:
Federal	$	-	$	2,821
State		-		200
		-		3,021
Deferred:
Federal		-		-
State		-		-
Total income tax provision (benefit)	$	-	$	3,021

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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 (in thousands):

	June 30
	2016			2015
Income tax expense (benefit) at federal statutory rate	$	(3,790,398	)	$	(10,984,983	)
State income taxes		(228,568	)		(472,583	)
Alternative minimum tax		-			2,821
Other adjustments - true up of deferred balances		(498,257	)		(1,101,884	)
Other - change in deferred tax rate		(188,080	)		60,666
Other		(550,957	)		(1,562,773	)
Valuation allowance		5,256,260			14,061,757
	$	-		$	3,021

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

	June 30
	2016			2015
Deferred income tax assets:
Net operating losses	$	33,548,583		$	25,995,717
Asset retirement obligation		1,395,262			458,869
Annual leave		60,826			71,309
Abandonment limitation		446,543			145,000
Accrued bonus		-			64,789
Charitable contributions		876			862
AMT credit		780,443			780,443
Share based compensation		500,844			500,844
Oil and Gas Property		-			157,481
Derivative liability		1,071,109			-
Valuation allowance		(33,337,136	)		(28,080,876	)
Deferred income tax liabilities:
Commodity liability		-			(94,588	)
Amortization  - loan costs		-			-
Oil and gas property		(4,467,350	)		-
Net deferred income tax assets (liabilities)		-			-
Net current deferred tax asset		-			-
Noncurrent deferred tax liability	$	-		$	-

The following table summarizes the activities for the Company’s valuation allowance for the years ended:

	June 30
	2016		2015
Deferred Income Tax Valuation Allowance
Balance at July 1		28,080,876		14,019,119
Additions (reductions) to deferred income tax expense		5,256,260		14,061,757
Balance at June 30		33,337,136		28,080,876

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The income tax expense recognized in the prior year is a result of a change in the estimated amount of AMT receivable from the IRS.

The Company has tax losses carried forward arising in Australia of $ 15,621,491 (2015: $13,316,288).  The benefit of these losses of $4,686,447 (2015: $3,994,887) 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 $79,987,858 (2015: $61,688,535).  The current year utilization carried back to prior years, is approximately $nil (2015: $nil). 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. NOL’s 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 2036.

In addition to the above mentioned Federal carried forward losses in the United States, the Company also has approximately $ 46,216,143 (2015: $29,217,044) of State carried forward tax losses, with expiry dates between June 2015 and June 2033.  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 realizeability 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 realizeablity of the deferred tax assets to be more likely than not. As such, the company has a full valuation allowance offsetting the deferred tax asset.

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. A reconciliation of the beginning and ending amount of gross uncertain tax positions is as follows:

	2016		2015
Total gross uncertain tax positions at beginning of year	$	-	$	107,524
Additions / Reductions for tax positions of prior years		-		-
Additions / Reductions for tax positions of current year		-		-
Reductions due to settlements with taxing authorities		-		(107,524	)
Reductions due to lapse of statute of limitations		-		-
Total amount of gross uncertain tax positions at end of year	$	-	$	-

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The State of North Dakota has made a claim against our wholly owned subsidiary, Samson Oil and Gas USA, Inc. relating to additional corporate income tax allegedly due for the years ended June 30, 2007 through June 30, 2011 in an amount of $597,852. We have reached a settlement with the State of North Dakota for a payment of $107,524, which was paid in July 2014.

7. COMMON STOCK

	Consolidated Entity
	2016		2015
3,215,854,701 ordinary fully paid shares including shares to be issued	$	105,719,184	$	104,491,774
(2015 –2,837,782,022 ordinary fully paid shares including shares to be issued)

	2016					2015
Movements in contributed equity for the year	No. of shares		$			No. of shares		$
Opening balance		2,837,782,022		104,491,774			2,837,756,933		104,535,894
Capital raising (i)		378,020,400		1,398,675			-		-
Shares issued upon exercise of options (ii)		52,279		1,475			25,089		880
Stock based compensation (options issued)		-		-			-		-
Transaction costs incurred		-		(172,740	)		-		(45,000	)
Shares on issue at balance date		3,215,854,701		105,719,184			2,837,782,022		104,491,774

i) Equity raised during the fiscal year ended June 30, 2016

In April 2016, we issued 378,020,400 ordinary shares at a purchase price of $0.0036 per share to raise $1.4 million in a private placement to certain institutional investors.

(ii) During the course of the year the Company issued 52,279 (2015: 25,089) ordinary shares upon the exercise of 52,279 (2015: 25,089) options.

The exercise price of 52,279 (2015: 25,089) of the options exercised was A$0.038 cents per share/US$0.028 cents per shares (average price based on the exchange rate on the date of exercise) (2015:A$0.038/US$0.035 cents per share) to raise US$1,475 (2015: US$880).

8. CASH FLOW STATEMENT

	Year ended June 30
	2016			2015
A reconciliation of the net loss to the net cash provided by operations is as follows:
Net loss after tax	$	(12,633,909	)	$	(36,619,632	)
Depreciation		4,766,949			6,920,945
Accretion of asset retirement obligations		125,078			40,159
Exploration and evaluation expenditures		4,216,077			12,686,943
Impairment losses of oil and gas properties		11,029,442			21,475,450
Borrowing costs		185,138			135,694
Change in fair value of derivative instruments		2,644,244			(673,859	)
Bargain purchase on acquistion		(10,775,231	)		-
Abandonment costs		-			404,485
Changes in assets and liabilities:
Decrease in receivables		1,648,678			667,223
Decrease in employee benefits		(24,917	)		(10,897	)
Increase/(decrease) in payables		750,428			(1,982,072	)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	1,931,977		$	3,044,439

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9. CREDIT FACILITY

	June 30,
	2016			2015
Credit facility at beginning of period	$	18,699,000		$	6,000,000
Cash advanced under facility		11,801,000			13,000,000
Repayments		-			(301,000	)
Credit facility at end of period	$	30,500,000		$	18,699,000
Less fund due for repayment in the next 12 months		(11,500,000	)		-
Total amount outstanding in long term credit facility	$	19,000,000		$	18,699,000
Funds available for drawdown under the facility		-			-

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

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

· Increases in the interest rate and unused facility fee;

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

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

· A requirement to raise $5 million in equity on or before September 30, 2016 (which was extended to November 15, 2016);

· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 following the agreement to sell our interest in the North Stockyard field for $15 million); and

· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement.

The current borrowing base is $30.5 million and is fully drawn as at September 28, 2016.

We intend to repay $11.5 million of the facility from proceeds from the sale of our interest in the North Stockyard field. This sale is anticipated to close October 20, 2016. Should this sale not close as anticipated we will be required to ask Mutual of Omaha bank for an extension on the debt pay down.

In January 2014, we entered into a $25.0 million credit facility with Mutual of Omaha Bank. The current borrowing base is $30.5 million, of which $30.5 million is drawn at June 30, 2016. The next borrowing base redetermination is expected to be completed in October 2016 based on June 30, 2016 reserves information. The facility matures October 31, 2017. Following the increase in the facility the interest rate is LIBOR plus 6.00% or approximately 6.3% at June 30, 2016.

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All of our assets are pledged as collateral under this facility.

As at June 30, 2016 we were in compliance with all of these quarterly covenants.

We raised $1.4 million in equity, in April 2016, towards the total of $5.0 million of equity to be raised that is required under the facility by September 30, 2016. Mutual of Omaha Bank has agreed to extend this deadline to November 15, 2016. We expect that Mutual of Omaha Bank will apply the excess proceeds over the $11.5 million required to be paid to Mutual of Omaha Bank to also be applied towards this total, however there can be no guarantee that they will do this.

We incurred $0.4 million in borrowing costs which have been deferred and will expensed through the effective interest rate charge.

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

To convert June 30, 2016 balances denominated in Australian dollars to U.S. dollars, we used the June 30, 2016 and 2015 Federal Reserve Bank of Australia (www.rba.gov.au) closing exchange rates of 0.768 and 0.942. U.S. dollars per Australian dollar, respectively. All dollars in this footnote are Australian dollars, except where stated 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 year ended June 30, 2016 as share based payments.

No options were issued during the year ended June 30, 2015 as share based payments.

As of June 30, 2016, there was US$Nil unrecognized compensation cost related to stock options.  

The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 2016 and 2015 (all values in AUD unless otherwise noted):

	2016								2015
						Aggregate
						Intrinsic
				Weighted		Value of						Weighted
				Average		Options/Warrants						Average
				Exercise		cents						Exercise
				Price – cents		(AUD)						Price – cents
	Number			(AUD)		(1)			Number			(AUD)
Outstanding, start of period		324,667,765			0.038					389,192,854			0.046
Granted		-			-					-			-
Exercised		(52,279	)		0.038					(25,089	)		0.038
Cancelled/expired		(4,000,000	)		0.155					(64,500,000	)		0.090
Outstanding, end of period		320,615,486			0.038		(0.03	)		324,667,765			0.038
Exercisable, end of period		320,615,486			0.038					324,667,765			0.038

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(1) The intrinsic value of a stock option is the amount by which the market value is (less than)/exceeds the exercise price at the Balance Date.

All warrants are immediately exercisable upon grant.

The aggregate intrinsic value of options exercised in 2016 and 2015 was (AUD1,731) and (AUD592), respectively.

Additional information related to options and warrants outstanding at June 30, 2016 is as follows (outstanding):

	Options/Warrants Outstanding and Exercisable
			Weighted
			Average		Weighted
Range of			Remaining		Average
Exercise	Number		Contractual		Exercise
Prices	Outstanding		Life - years		Prices
3.8 cents		229,582,240		0.75		0.038
3.3 cents		87,033,246		1.83		0.033
3.9 cents		4,000,000		1.42		0.039
		320,615,486

11. RELATED PARTY TRANSACTIONS

There were no related party transactions during the years ended June 30, 2016 and 2015.

12. COMMITMENTS

Contractual Obligations	Total		2017		2018		2019		2020		2021		Thereafter
Asset retirement obligations (1)	$	3,750,245	$	300,000	$	-	$	-	$	-	$	-	$	3,450,245
Leases (2)		484,246		68,253		96,199		100,152		103,616		107,079		8,947
Credit Facility (3)		30,500,000		11,500,000		19,000,000		-		-		-		-
Promissory Note (4)		4,400,000		4,400,000		-		-		-		-		-
Total		39,134,491		16,268,253		19,096,199		100,152		103,616		107,079		3,459,192

(1) Asset retirement obligations represent the estimated fair value at June 30, 2016 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors.

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(2) Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia.

(3) Excludes variable rate debt interest payments related to the Company’s credit facility. The interest rate is LIBOR plus 3.75% or approximately 6.3% at June 30, 2016.

(4) Includes fixed interest costs payable at the promissory notes maturity date on April 1, 2017. The interest rate is 10% per annum.

Leases –The Company has entered into lease agreements for office space in Denver, Colorado and Perth, Western Australia. As of June 30, 2016, future minimum lease payments under operating leases that have initial or remaining non–cancelable terms in excess of one year are $68,253 in 2017, $96,199 in 2018, $100,152 in 2019, $103,616 in 2020, $107,079 in 2021 and $8,947 thereafter. Net rent expense incurred for office space was $157,094 and $139,599 in 2016 and 2015, respectively.

13. CONTINGENCIES

There are no unrecorded contingent assets or liabilities in place for the Company at June 30, 2016 (2015: Nil).

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.

During the year ended June 30, 2016 the Company recognized a gain in other income of $0.8 million with respect to a settlement from litigation with Haliburton Company. Haliburton paid the Company $0.7 million and forgave revenue owing of $0.1 million. A contingent receivable was not recognized prior to the settlement as the amount of the settlement was not reasonably estimable.

Liquidity

Following the sustained decline in oil prices, the Company became out of compliance with its loan to value ratio with Mutual of Omaha Bank. The Company is required to pay down $11.5 million of the proceeds from the pending sale of North Stockyard to Mutual of Omaha Bank. The Company is also required to raise $5 million in equity prior to September 30, 2016. The Company raised $1.4 million in equity in April 2016 and we have been granted an extension in this deadline to November 15, 2016. It is expected that Mutual of Omaha will also apply the remaining proceeds from the North Stockyard sale to this equity raise, however that is not certain. Following the pay down of the facility from the proceeds from the pending North Stockyard sale, the Company intends to enter into negotiations with Mutual of Omaha Bank to renegotiate the term and conditions of its credit facility, including the current maturity date and covenants. While the new borrowing based is currently being determined by Mutual of Omaha Bank, based on the Company’s proved reserves the Company expects the borrowing base will be in excess of the current drawdown creating additional liquidity in the facility.

Should the Company not be able to renegotiate the credit facility to its satisfaction the Company may need to consider further asset sales or capital raises to provide the Company with ongoing liquidity to repay its long and short term debts as and when they fall due.

14. SUBSEQUENT EVENTS

There have been no material subsequent events through the date of filing.

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15. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following is a summary of the unaudited financial data for each quarter for the years ended June 30, 2016 and 2015 (except per share data):

	Three Months Ended
	June 30, 2016		March 31, 2016			Dec 31, 2015			Sep 30, 2015
Year ended June 30, 2015:
Revenues	$	8,576,792	$	3,041,563		$	5,009,633		$	4,049,615
(Loss)/income from operations		2,822,938		(1,944,025	)		(2,538,571	)		(10,974,251	)
Tax (expense)/benefit		-		-			-			-
Net (loss)/income		2,822,938		(1,944,025	)		(2,538,571	)		(10,974,251	)
Basic (loss)/earnings per common share – cents per share		0.16		(0.07	)		(0.09	)		(0.43	)
Diluted (loss)/earnings per common share – cents per share		0.16		(0.07	)		(0.09	)		(0.43	)

	Three Months Ended
	June 30, 2015			March 31, 2015			Dec 31, 2014			Sep 30, 2014
Year ended June 30, 2015:
Revenues	$	4,475,079		$	3,041,563		$	5,009,633		$	4,049,615
Loss from operations		(21,159,764	)		(1,944,025	)		(2,538,571	)		(10,974,251	)
Tax (expense)/benefit		(3,021	)		-			-			-
Net (loss)/income		(21,162,785	)		(1,944,025	)		(2,538,571	)		(10,974,251	)
Basic loss per common share – cents per share		(0.70	)		(0.07	)		(0.09	)		(0.43	)
Diluted loss per common share – cents per share		(0.70	)		(0.07	)		(0.09	)		(0.43	)

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

Oil and Gas Reserves

The information set forth below regarding the Company’s oil and gas reserves, for the year ended June 30, 2016 was prepared by Netherland, Sewell & Associates Inc. and the reserves for the years ended June 30, 2015 were prepared by Ryder Scott Company L.P., both independent reserve engineering firms. The CEO reviews all reserve reports. All reserves are located within the continental United States.

Estimated Proved Reserves

Proved reserves are those quantities of hydrocarbons which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations. As commodity prices decline, the commercially viability of wells change and reserve quantities may decrease. Proved reserves can be categorized as developed or undeveloped.

Capitalized Costs Incurred

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

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	Year ended June 30,
	2016		2015
Work in progress		-		-
Development		31,332,473		18,339,362
Exploration costs		-		1,449,750
Undeveloped capitalized acreage		178,254		23,130
Total costs incurred	$	31,510,727	$	19,812,242

Estimated Proved Reserves

Proved reserves are those quantities of hydrocarbons which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations.  As commodity prices decline, the commercially viability of wells change and reserve quantities may decrease.  Proved reserves can be categorized as developed or undeveloped.

	Year ended June 30, 2016									Year ended June 30, 2015
	Oil			Gas			Total			Oil			Gas			Total
	Mbbls			MMcf			MBOE			Mbbls			MMcf			MBOE
Beginning of year		1,285			1,183			1,483			1,478			1,763			1,773
Revisions of previous quantity estimates		2,597			2,662			3,041			(376	)		(547	)		(467	)
Extensions and discoveries		-			-			-			414			193			446
Sale of reserves in place		-			-			-			-			-			-
Acquisitions		6,340			5,317			7,226			-			-			-
Production		(240	)		(569	)		(335	)		(231	)		(226	)		(269	)
End of year		9,982			8,593			11,415			1,285			1,183			1,483
Proved developed producing reserves		3,724			3,092			4,240			1,285			1,183			1,483
Proved developed non producing		970			1,800			1,270			-			-			-
Proved undeveloped reserves		5,288			3,701			5,905			-			-			-
Total proved reserves		9,982			8,593			11,415			1,285			1,183			1,483

During the year ended June 30, 2016 the acquisition of reserves relates to our Foreman Butte acquisition. The revisions to previous quantity estimates relates to workovers performed on wells associated with the Foreman Butte acquisition.

During the year ended June 30, 2015 the increase in extensions and discoveries relates to the drilling of our wells which were not previously PUD locations.

Developed Reserves

Developed reserves are those reserves expected to be recovered from existing wells, with existing equipment and operating methods.  Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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Standardized Measure of Discounted Future Net Cash Flows

Future hydrocarbon sales and production and development costs have been estimated using a 12 month average price for the commodity prices for June 30, 2016 and 2015 and costs in effect at the end of the periods indicated.  The average 12 month historical average of the first of the month prices used for natural gas for June 30, 2016 and 2015 were $0.37 and $4.30 per Mcf, respectively.  The 12 month historical average of the first of the month prices used for oil for June 30, 2016 and 2015 were $37.12 and $59.64 per barrel of oil, respectively.  Future cash flows were reduced by estimated future development, abandonment and production costs based on period–end costs.  No deductions were made for general overhead, depletion, depreciation and amortization or any indirect costs.  All cash flows are discounted at 10%.

Changes in demand for hydrocarbons, inflation and other factors make such estimates inherently imprecise and subject to substantial revisions.  This table should not be construed to be an estimate of current market value of the proved reserves attributable to Samson.

During the year ended June 30, 2015 we converted two PUD locations to PDP locations. We also drilled and completed eight other wells that were not recorded as PUD’s at June 30, 2014. At June 30, 2015 we have no PUD locations in our reserve value.

Samson has not disclosed the impact of taxes in the future cash flows for the years ended June 30, 2015 and 2016 as given Samson’s extensive net operating losses carried forward, its history of loss making and the significant value of intangible costs incurred when developing its proved undeveloped locations, for which an immediate tax deduction is currently available, it is unlikely Samson will pay tax in the future based on current commodity pricing.

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,
	2016			2015			2014			2013			2012
Future cash inflows	$	373,740		$	72,900		$	148,975		$	133,589		$	71,655
Future production costs		(184,691	)		(22,403	)		(43,009	)		(44,672	)		(29,321	)
Future development costs		(50,752	)		(38	)		(12,461	)		(29,012	)		(10,198	)
Future income taxes		-			-			(21,819	)		(12,050	)		(5,524	)
Future net cashflows		138,297			50,459			71,686			47,855			26,612
10 % discount		(71,550	)		(16,206	)		(29,093	)		(26,012	)		(13,274	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	66,747		$	34,253		$	42,593		$	21,843		$	13,338

The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2016 and June 30, 2015 are as follows (in US$’000’s):

	Fiscal Year Ended June 30
	2016			2015
Beginning of year	$	34,253		$	42,593
Sales of oil and gas produced during the period, net of production costs		(3,575	)		(7,178	)
Net changes in prices and production costs		(15,705	)		(22,610	)
Previously estimated development costs incurred during the period		-			1,898
Changes in estimates of future development costs		(14,545	)		-
Extensions and discoveries		-			11,266
Revisions of previous quantity estimates and other		18,074			(6,197	)
Sale of reserves in place		-			-
Purchase of reserves in place		41,564			-
Change in future income taxes		-			11,809
Accretion of discount		3,452			5,440
Other		3,229			(2,768	)
Balance at end of year	$	66,747		$	34,253

86

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 cashflows.

For the year ended June 30, 2015 the impact of changes in estimates of future development costs have been included in revisions of previous quantity estimates as they relate to the loss of PUD’s in the current pricing environment.

87

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements on Form S-3 (No. 333-183327 and No. 333-207306) and Form S-8 (No. 333-173647) of Samson Oil & Gas Limited of our report dated September 28, 2016, relating to our audit of the consolidated financial statements, which appear in this Annual Report on Form 10-K of Samson Oil & Gas Limited for the year ended June 30, 2016.

/s/ Hein & Associates LLP

Denver, Colorado

September 28, 2016

EX-23.2

Exhibit 23.2

    FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147

Samson Oil & Gas Limited

Level 16, AMP Building

140 St. Georges Terrace

Perth, Western Australia 6000

Ladies and Gentlemen:

We hereby consent to the use of the name Ryder Scott Company, to the inclusion of information taken from the reserve report prepared by us relating to the estimated quantities of Samson Oil & Gas Limited’s proved reserves of oil and gas for the year ended June 30, 2015 in this Form 10-K. We also consent to the incorporation by reference of information from our report in Samson Oil & Gas Limited’s Registration Statements on Form S-3 (No. 333-183327 and No. 333-207306) and Form S-8 (No. 333-173647) and related prospectuses.

Very truly yours,

/S/ RYDER SCOTT COMPANY, L.P.

Denver, Colorado

September 28, 2016

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use of the name Netherland, Sewell & Associates, Inc., to the inclusion of our Report dated September 15, 2016, as attached as Exhibit 99.1 to the Annual Report on Form 10-K for the year ended June 30, 2016 of Samson Oil & Gas Limited, and to the inclusion of information taken from the reserves report prepared by us relating to the estimated quantities of Samson Oil & Gas Limited’s proved reserves of oil and gas for the year ended June 30, 2016 in this Form 10-K. We also consent to the incorporation by reference of information from our report in Samson Oil & Gas Limited’s Registration Statements on Form S-3 (No. 333-183327 and No. 333-207306) and Form S-8 (No. 333-173647) and related prospectuses.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III, P.E.
	C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer

Dallas, Texas

September 28, 2016

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 Barr

Terence M. Barr

President, Chief Executive Officer and Managing Director

September 28, 2016

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

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

I, Robyn Lamont, 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/ Robyn Lamont

Robyn Lamont

Chief Financial Officer

September 28, 2016

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, 2016 (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

September 28, 2016

/s/ Robyn Lamont

Robyn Lamont

Chief Financial Officer

September 28, 2016

EX-99.1

 

Exhibit 99.1

September 15, 2016

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, 2016, to the Samson Oil & Gas Limited (Samson) interest in certain oil and gas properties located in Montana, New Mexico, North Dakota, Texas, 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'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, 2016, to be:

	Net Reserves				Future Net Revenue (M$)
	Oil		Gas				Present Worth
Category	(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		3,724.5		3,092.6		67,128.8		40,439.7
Proved Developed Non-Producing		970.0		1,799.6		11,684.8		8,141.5
Proved Undeveloped		5,288.1		3,701.7		59,481.5		18,165.6
Total Proved		9,982.6		8,593.9		138,295.1		66,746.8

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.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

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, capital costs, 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 2015 through June 2016. For oil volumes, the average West Texas Intermediate spot price of $43.12 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.237 per MMBTU is adjusted for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $37.12 per barrel of oil and $0.371 per MCF of gas.

Operating costs used in this report were provided by Samson and appear reasonable based on our knowledge of similar wells in the area. These costs are intended to 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. Operating costs have been divided into per-well costs and per-unit-of-production costs. It is also intended that headquarters general and administrative overhead expenses of Samson are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Samson and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs 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.

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 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. Dan Paul Smith, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1980 and has over 7 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
		By:	/s/ C.H. (Scott) Rees III
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
By:	/s/ Dan Paul Smith	By:	/s/ John G. Hattner
	Dan Paul Smith, P.E. 49093		John G. Hattner, P.G. 559
	Senior Vice President		Senior Vice President
Date Signed: September 15, 2016		Date Signed: September 15, 2016

BWJ:AHA

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

 

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 2007 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 2007 Petroleum Resources Management System:

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

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which 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 which will require additional completion work or future recompletion prior to start of production. 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 7

 

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.

Definitions - Page 2 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

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

(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.

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.

Definitions - Page 3 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

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

(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.

(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.

Definitions - Page 4 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

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

(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:

(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.

Definitions - Page 5 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

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

(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.

(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.

Definitions - Page 6 of 7

 

DEFINITIONS OF OIL AND GAS RESERVES

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

(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:

Ÿ 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);

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

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

Ÿ 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

Ÿ 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 7 of 7

XML

Document And Entity Information - USD ($) $ in Thousands	12 Months Ended
	Jun. 30, 2016	Sep. 26, 2016	Dec. 31, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Trading Symbol	SSN
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	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		3,215,854,791
Entity Public Float			$ 5,200

XML

Consolidated Balance Sheets - USD ($)	Jun. 30, 2016	Jun. 30, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 2,654,812	$ 2,062,720
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively	1,996,415	3,645,223
Energy Related Inventory, Crude Oil and Natural Gas Liquids	463,768
Prepayments	183,305	372,079
Fair value of derivative instruments		159,216
Assets Held-for-sale, Not Part of Disposal Group, Current	13,768,865
Total current assets	19,067,165	6,239,238
PROPERTY, PLANT AND EQUIPMENT, AT COST
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $44,273,976 and $21,219,361 at June 30, 2015 and June 30, 2014, respectively	31,522,323	29,715,540
Other property and equipment, net of accumulated depreciation and amortization of $553,428 and $421,443 at June 30, 2015 and June 30, 2014, respectively	308,474	248,521
Net property, plant and equipment	31,830,797	29,964,061
OTHER ASSETS
Undeveloped capitalized acreage	220,703	2,491,422
Capitalized exploration expense		1,388,798
Fair value of derivative instruments		101,269
Malpractice Loss Contingency, Letters of Credit and Surety Bonds	450,000
Other	474,325	342,069
TOTAL ASSETS	52,042,990	40,526,857
CURRENT LIABILITIES
Accounts payable	4,125,643	1,678,915
Accrued liabilities	1,629,975	1,999,344
Provision for annual leave	194,497	219,414
Fair value of derivative instruments	1,671,653
Short-term Debt	4,046,428
Short term repayment of long term debt	11,500,000
Total current liabilities	23,168,196	3,897,673
Fair value of derivative instruments	1,233,076
Asset retirement obligations	3,450,245	1,263,674
Credit Facility	19,000,000	18,699,000
Total liabilities	46,851,517	23,860,347
Commitments and Contingencies
STOCKHOLDERS' EQUITY - nil par value
Common stock, 2,837,756,933 (equivalent to 141,887,847 ADRs) and 2,229,165,163 (equivalent to 111,458,258 ADRs) shares issued and outstanding at June 30, 2014 and 2013, respectively)	105,719,184	104,491,774
Other comprehensive income	927,718	996,256
Retained earnings (accumulated deficit)	(101,455,429)	(88,821,520)
Total stockholders' equity	5,191,473	16,666,510
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 52,042,990	$ 40,526,857

XML

Consolidated Balance Sheets (Parenthetical) - USD ($)	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Consolidated Balance Sheets [Abstract]
Accounts receivable, allowance for doubtful accounts
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion Amortization and Impairment	$ 15,049,015	$ 44,273,976
Other property and equipment, accumulated depreciation and amortization	$ 573,995	$ 553,428
Common stock, par value
Common stock, shares issued	3,215,854,701	2,837,782,022
Common stock, shares outstanding	2,837,782,022	3,215,854,701

XML

Consolidated Statements Of Operations - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
REVENUES AND OTHER INCOME:
Interest income	$ 2,569	$ 30,759
Gain on derivative instruments		3,112,268
Business Combination, Bargain Purchase, Gain Recognized, Amount	10,775,231
Other	897,448	137,857
TOTAL REVENUE AND OTHER INCOME	20,677,603	16,575,890
EXPENSES:
Lease operating expense	(5,427,752)	(6,117,217)
Depletion, depreciation and amortization	(4,766,949)	(6,920,945)
Impairment of oil and natural gas properties	(11,029,442)	(21,475,450)
Exploration and evaluation expenditure	(4,216,077)	(12,686,943)
Accretion of asset retirement obligations	(125,078)	(40,159)
General and administrative	(3,685,673)	(4,812,668)
Abandonment Expense		(404,485)
Loss on derivative instruments	(2,657,963)
Borrowing costs	(185,138)	(135,694)
Interest expense	(1,217,440)	(598,940)
TOTAL EXPENSES	(33,311,512)	(53,192,501)
Loss before income tax	(12,633,909)	(36,616,611)
Income tax (provision)/benefit		(3,021)
Net loss	(12,633,909)	(36,619,632)
OTHER COMPREHENSIVE LOSS
Foreign currency translation	(68,538)	(305,840)
Total comprehensive loss for the period	$ (12,702,447)	$ (36,925,472)
Net earnings per common share from continuing operations:
Basic loss per common share - cents per share	$ (0.43)	$ (1.29)
Diluted earnings per common share - cents per share	$ (0.43)	$ (1.29)
Weighted average common shares outstanding:
Basic	2,919,426,154	2,837,777,322
Diluted	2,919,426,154	2,837,777,322
Oil [Member]
REVENUES AND OTHER INCOME:
Sales revenue	$ 8,240,529	$ 12,460,171
Natural Gas [Member]
REVENUES AND OTHER INCOME:
Sales revenue	714,103	$ 834,835
Other Liquids [Member]
REVENUES AND OTHER INCOME:
Sales revenue	$ 47,723

XML

Consolidated Statements Of Changes In Stockholders' Equity - USD ($)	Issued Capital [Member]	Retained Earnings/(Accumulated Deficit) [Member]	Other Comprehensive Income (Loss) [Member]	Total
Beginning Balance, value at Jun. 30, 2014	$ 104,535,894	$ (52,201,888)	$ 1,302,096	$ 53,636,102
Net loss		(36,619,632)		(36,619,632)
Foreign currency translation			(305,840)	(305,840)
Total comprehensive loss for the period		(36,619,632)	(305,840)	(36,925,472)
Issue of share capital	880			880
Share issue costs	(45,000)			(45,000)
Ending Balance, value at Jun. 30, 2015	104,491,774	(88,821,520)	996,256	16,666,510
Net loss		(12,633,909)		(12,633,909)
Foreign currency translation			(68,538)	(68,538)
Total comprehensive loss for the period		(12,633,909)	(68,538)	(12,702,447)
Issue of share capital	1,400,150			1,400,150
Share issue costs	(172,740)			(172,740)
Ending Balance, value at Jun. 30, 2016	$ 105,719,184	$ (101,455,429)	$ 927,718	$ 5,191,473

XML

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities
Receipts from customers	$ 10,443,411	$ 13,177,704
Cash received from commodity derivative financial instruments	637,980	2,275,026
Payments to suppliers & employees	(9,015,060)	(11,172,887)
Interest received	2,573	31,061
Interest paid	(808,144)	(481,714)
Income taxes paid		(107,135)
Payments for abandonment costs	(53,783)	(677,616)
Proceeds from Legal Settlements	725,000
Net Cash Provided by (Used in) Operating Activities, Continuing Operations, Total	1,931,977	3,044,439
Cash flows from investing activities
Proceeds from sale of oil and gas properties	1,000,000
Payments for operating bonds	(450,000)
Payments for plant & equipment	(183,266)	(20,249)
Payments for exploration and evaluation	(749,731)	(2,406,192)
Payments of business combination	(16,089,029)
Payments for oil and gas properties	(1,531,407)	(17,670,628)
Net cash flows (used in)/ provided by investing activities	(18,003,433)	(20,097,069)
Cash flows from financing activities
Proceeds from issue of share capital	1,400,150	880
Proceeds from borrowings	11,801,000	13,000,000
Proceeds from short term borrowings	4,000,000
Repayment of borrowings		(301,000)
Payments for costs associated with borrowings	(295,151)	(83,690)
Payments for costs associated with capital raising	(172,740)	(45,000)
Net cash flows (used in)/ provided by financing activities	16,733,259	12,571,190
Net (decrease)/increase in cash and cash equivalents	661,803	(4,481,440)
Cash and cash equivalents at the beginning of the year	2,062,720	6,846,394
Effects of exchange rate changes on cash and cash equivalents	(69,711)	(302,234)
Cash and cash equivalents at end of year	$ 2,654,812	$ 2,062,720

XML

Summary Of Significant Accounting Policies

12 Months Ended

Jun. 30, 2016

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, Montana and Wyoming.

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. All intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates.   The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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; (4) asset retirement obligations; (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 expenditure. 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. 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.   Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of completed deliveries where title has transferred. Title to oil sold is typically transferred at the wellhead.

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, 2016 or 2015.

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.  

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

	June 30
	2016		2015
Oil and natural gas sales	$	1,717,110	$	3,224,595
Cost recovery from drilling partners		275,018		275,148
Other		4,287		145,480
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015	$	1,996,415	$	3,645,223

The Company's accounts receivable result from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are primarily from the operators of our various projects, who negotiate the sale of oil and gas to third parties on our behalf.

The cost recovery from drilling partners relates to the partners share of drilling costs associated with the current drilling program in our North Stockyard infill project and Hawk Springs project.

Accruals.   The components of accrued liabilities for the years ended June 30, 2016 and 2015 are as follows:

	2016		2015
Bonus accrual		-		-
Other accruals		629,975		1,999,344
Deposit received for asset sale		1,000,000		0
	$	1,629,975	$	1,999,344

Other accruals includes an estimate of the costs expected to be incurred with respect to the asset retirement obligation in the next twelve months.

The deposit received from the asset sale is non-refundable (subject to the identification of certain title or environmental defects for the deadline for providing notification to the Company has passed) deposit received from the purchaser of our North Stockyard assets.

The majority of other accruals in the prior year relate to expenses incurred in relation to our exploratory well, Bluff, in our Hawk Springs project and other general accruals.

Oil and Gas Properties.

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

	2016		2015
Proved properties	$	45,177,047	$	61,724,561
Lease and well equipment		1,394,291		12,264,955
Less accumulated depreciation, depletion and impairment		(15,049,015)		(44,273,976)
	$	31,522,323	$	29,715,540
Assets held for sale		13,768,865		-
Unproved acreage	$	220,703	$	2,491,422
Capitalized exploration expense	$	-	$	1,388,798

The Company accounts for its oil and 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 cost 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.

Assets held for sale

On June 30, 2016, the Company signed a Purchase and Sale Agreement for the sale of its interests in the North Stockyard field.  The purchase price of the acquisition is $15 million and the acquisition is expected to settle on October 20, 2016.  The effective date of the acquisition is the day after the closing date.  The Company received a $1 million deposit from the purchaser on the date of signing, recorded in current liabilities.  This deposit is only refundable if certain title or environmental defects are identified during the purchasers due diligence. The date by which the purchaser was required to notify the Company of any title or environmental defects has passed and the Company was not advised of any environmental or title defects.

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 itis 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 year ended June 30, 2016, we expensed $4.2 million in deferred exploration expense in relation to our Hawk Springs project area.

During the fiscal year ended June 30, 2015 the Company expensed $8.1 million in relation to our Roosevelt project in Montana.  During the year ended June 30, 2014 the Company entered into a farm out arrangement with respect to this property however due to the falling oil prices, the farm out partner failed to meet it’s obligations under the agreement.  The Company does not plan to spend any additional capital in this project area and therefore we have written off the previously capitalized exploration expenditure.  The Company also wrote off $2.5 million with respect to its South Prairie project in North Dakota. A second dry hole was drilled in the area during the year ended June 30, 2015 and the decision was made to write off the costs capitalized with respect to this project.  The Company also expensed $1.6 million with respect to its Hawk Springs project in Wyoming. These costs were associated with leases expiring during the year. The Company also expensed $0.4 million of general exploration expenditure, which was never capitalized to the Balance Sheet.

Impairment

The Company recorded impairment charges of $11.0 million and$21.5 million for the years ended June 30, 2016 and 2015 respectively.

The charges in the fiscal year ended June 30, 2016 related to the impact of the drop in the oil price on our North Stockyard, Rainbow and State GC project areas.

The charges in the fiscal year ended June 30, 2015 related to the impact of the drop in the oil price on our Rainbow and North Stockyard projects in North Dakota.

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, 2016and 2015 was $0.1 million and $0.1 million, respectively.

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

	2016		2015
Furniture, fittings and equipment	$	882,469	$	801,949
Less accumulated depreciation		(573,995)		(553,428)
	$	308,474	$	248,521

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.

Earnings per Share.   Basic earnings (loss) per share are calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares. 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.

The following potential common shares relating to options and warrants have been excluded from the calculation of diluted earnings per share as the related impact was anti-dilutive.

	Year ended June 30,
	2016		2015
Dilutive		-	-
Anti–dilutive		321,955,194	357,099,676

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 Consolidated Entity 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 exceeds the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. 

In the current period, the Company recognized a gain on bargain purchase of $10.7 million with respect to its acquisition of certain producing and non producing assets, known as the Foreman Butte project.

Impact of Recently Adopted Accounting Standards.

There have been no recently adopted accounting standards that would impact our business.

Recently Issued Accounting Pronouncements

In August 2014, the FASB issued new guidance related to the disclosures around going concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

In November 2014, the FASB issued ASU No. 2014-16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity.  This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted.  The Company is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its consolidated financial statements.

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

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Business Combination

12 Months Ended

Jun. 30, 2016

Business Combination [Abstract]

Business Combination

2. BUSINESS COMBINATION

On March 31, 2016, the Company closed on the acquisition of producing and non producing wells in the Madison and Ratcliffe formations in North Dakota and Montana.  The acquisition had an effective date of October 31, 2015 and closed on March 31, 2016. 

	USD
Amount Settled in Cash	$	1,391,874
Extension of credit facility		11,500,000
Fair value of promissory note provided		3,928,571
Fair value of consideration transferred		16,820,445
		-
Recognised amounts of identifiable assets and liabilities:
Oil and gas properties		29,350,256
Oil inventory acquired		463,768
Trade receivables		53,540
Revenue in suspense assumed		(403,612)
Asset retirement obligation assumed		(1,868,276)
Net identifiable assets and liabilities		27,595,676
Gain on bargain purchase		10,775,231

Consideration Transferred

The cost of the acquisition was settled in cash and the promissory note in the amount of $16.6 million (including post closing settlement payments). $1.2 million was settled from the Company’s cash reserves, $11.5 million came from an extension of the Company’s credit facility with Mutual of Omaha Bank and $3.9 million was provided by a promissory note provided to the seller of the assets.  The fair value of the promissory note was determined to be $3.9 million on acquisition date based on an effective interest rate of 12%.  The face value of the note is $4 million.  The note accrues 10% interest per annum, and is due for repayment on April 1, 2017.  The interest is payable in a balloon payment at maturity.  The note is secured by a second lien over all the assets acquired.

Identifiable net assets

The assets, collectively known as the Foreman Butte acquisition, consist of interests in a number wells, both operated and non operated in the Madison and Ratcliffe formations in Montana and North Dakota.  The fair value of the assets acquired was determined with reference to the reserve value of those assets at acquisition date, the Company’s cost of capital and other comparable transactions.

The trade receivables, oil inventory and revenue in suspense were recognized at face value as this approximates fair value.

The Company incurred acquisition costs of $0.2 million which have been expensed.

Proforma Contribution to Results (unaudited)

Contribution of Business Combination to Company Results
The following represents the amount of the Company's revenue and losses for the years ended June 30, 2016 and June 30, 2015, assuming the business combination occurred on July 1, 2014.
	2016		2015
Revenues	$	25,579,347	$	19,849,812
Losses		(15,762,744)		(35,982,244)

These results do not necessarily reflect the results that would have been incurred if the Company did own the assets as of July 1, 2014.

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Hedging And Derivative Financial Instruments

12 Months Ended

Jun. 30, 2016

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, 2016, 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 Mutual of Omaha Bank, the provider of the Company’s credit facility. As such no collateral is required by the counterparty.

At June 30, 2016 the Company’s open derivative contracts consisted of the following:

Collar

Product	Start Date	End Date	Volume (BO/Mmbtu)	Floor	Ceiling
WTI	1-Jul-16	30-Apr-18	133,032	41.50	63.00
Henry Hub	1-Jul-16	31-Oct-16	127,229	1.90	2.40
Henry Hub	1-Nov-16	31-Mar-17	134,088	2.60	3.35
Henry Hub	1-Apr-17	31-Oct-17	167,682	2.40	2.91
Henry Hub	1-Nov-17	30-Apr-18	127,030	2.80	3.60
Fixed price swap
Product	Start	End	Volume (BO)	Swap
WTI	1-Jul-16	31-Dec-16	83,730	41.20
WTI	1-Jan-17	31-Dec-17	141,255	44.09
WTI	1-Jan-18	30-Apr-18	39,720	45.55

At June 30, 2015 the Company’s open derivative contracts consisted of the following:

Oil Price Collars – WTI	Volumes (bbls)	Floor US$	Ceiling US$
January 2016 - February 2016	2,788	85.00	89.85
Oil Price Swaps – WTI	Volumes (bbls)	Price US$
July 2015 - December 2015	8,765	105.00
January 2016 - February 2016	2,788	105.00
Oil Price Three Way Swaps - WTI	Volumes (bbls)	Ceiling US$	Sub Floor US$	Floor US$
July 2015-  December 2015	55,200	70.25	32.50	45.00
January 2016 - December 2016	27,450	80.00	40.00	55.00
January 2016 – December 2016	36,600	-	67.50	82.50

During the year ended June 30, 2016, the Company recognized $2.7 million in the Statement of Operations in loss in derivative instruments.  As of June 30, 2016, the derivative instruments were valued at a unrealized loss of $2.8 million of which, $1.6 million is recorded as a current liability and $1.2 million is recorded as a non-current liability.

During the year ended June 30, 2015, the Company recognized $3.1 million in the Statement of Operations in gain on derivative instruments. As of June 30, 2015, its derivative instruments were valued at $159,216 recorded as current asset and $101,269 recorded as a non-current asset. 

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

Price risk

Price risk arises from the Company’s exposure to oil and gas prices. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  Sustained weakness in oil and natural gas prices may adversely affect the Company’s financial condition.

The Company manages this risk by continually monitoring the oil and gas price and the external factors that may affect it.  The Board reviews the risk profile associated with commodity price risk periodically to ensure that it is appropriately managing this risk.  Derivatives are used to manage this risk where appropriate.  The Board must approve any derivative contracts that are entered into by the Company.

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Fair Value Measurements

12 Months Ended

Jun. 30, 2016

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, 2016 and 2015.

	Fair Value at June 30, 2016
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash and cash equivalents	$	2,654,812	$	-	$	-	$	-	$	2,654,812
Derivative Instruments		-		136,727		-		(136,727)		-
Non Current Assets:
Derivative Instruments		-		220,317		-		(220,317)		-
Current Liabilities
Derivative Instruments		-		1,808,380		-		(136,727)		1,671,653
Non Current Liabilities:
Derivative Instruments				1,453,393				(220,317)		1,233,076
	Fair Value at June 30, 2015
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash and cash equivalents	$	2,062,720	$	-	$	-	$	-	$	2,062,720
Derivative Instruments		-		379,540		-		(220,324)		159,216
Non Current Assets:
Derivative Instruments		-		298,703		-		(197,434)		101,269
Current Liabilities
Derivative Instruments		-		220,324		-		(220,324)		-
Non Current Liabilities:
Derivative Instruments				197,434				(197,434)		-

(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. 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, 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, including the Foreman Butte acquistion, 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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Asset Retirement Obligations

12 Months Ended

Jun. 30, 2016

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, 2016 and 2015:

	2016		2015
Asset retirement obligations at beginning of period	$	1,810,674	$	1,775,792
Liabilities incurred or acquired		1,868,276		672,339
Liabilities settled		(53,783)		(677,616)
Disposition of properties		-		-
Accretion expense		125,078		40,159
Asset retirement obligations at end of period		3,750,245		1,810,674
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		(300,000)		(547,000)
Long-term asset retirement obligations	$	3,450,245	$	1,263,674

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

The liabilities incurred in the current year relate to the liabilities acquired in relation to the Foreman Butte acquisition.

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Income Taxes

12 Months Ended

Jun. 30, 2016

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
	2016		2015
Current:
Federal	$	-	$	2,821
State		-		200
		-		3,021
Deferred:
Federal		-		-
State		-		-
Total income tax provision (benefit)	$	-	$	3,021

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 (in thousands):

		June 30
	2016		2015
Income tax expense (benefit) at federal statutory rate	$	(3,790,398)	$	(10,984,983)
State income taxes		(228,568)		(472,583)
Alternative minimum tax		-		2,821
Other adjustments - true up of deferred balances		(498,257)		(1,101,884)
Other - change in deferred tax rate		(188,080)		60,666
Other		(550,957)		(1,562,773)
Valuation allowance		5,256,260		14,061,757
	$	-	$	3,021

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

	June 30
	2016		2015
Deferred income tax assets:
Net operating losses	$	33,548,583	$	25,995,717
Asset retirement obligation		1,395,262		458,869
Annual leave		60,826		71,309
Abandonment limitation		446,543		145,000
Accrued bonus		-		64,789
Charitable contributions		876		862
AMT credit		780,443		780,443
Share based compensation		500,844		500,844
Oil and Gas Property		-		157,481
Derivative liability		1,071,109		-
Valuation allowance		(33,337,136)		(28,080,876)
Deferred income tax liabilities:
Commodity liability		-		(94,588)
Amortization  - loan costs		-		-
Oil and gas property		(4,467,350)		-
Net deferred income tax assets (liabilities)		-		-
Net current deferred tax asset		-		-
Noncurrent deferred tax liability	$	-	$	-

The following table summarizes the activities for the Company’s valuation allowance for the years ended:

		June 30
	2016		2015
Deferred Income Tax Valuation Allowance
Balance at July 1		28,080,876		14,019,119
Additions (reductions) to deferred income tax expense		5,256,260		14,061,757
Balance at June 30		33,337,136		28,080,876

The income tax expense recognized in the prior year is a result of a change in the estimated amount of AMT receivable from the IRS. 

The Company has tax losses carried forward arising in Australia of $ 15,621,491 (2015: $13,316,288).  The benefit of these losses of $4,686,447(2015:  $3,994,887) 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 $79,987,858 (2015:  $61,688,535).  The current year utilization carried back to prior years, is approximately $nil (2015: $nil). 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. NOL’s 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 2036.

In addition to the above mentioned Federal carried forward losses in the United States, the Company also has approximately $ 46,216,143 (2015: $29,217,044) of State carried forward tax losses, with expiry dates between June 2015 and June 2033.  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 realizeability 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 realizeablity of the deferred tax assets to be more likely than not.  As such, the company has a full valuation allowance offsetting the deferred tax asset.

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. A reconciliation of the beginning and ending amount of gross uncertain tax positions is as follows:

		2016		2015
Total gross uncertain tax positions at beginning of year	$	-	$	107,524
Additions / Reductions for tax positions of prior years		-		-
Additions / Reductions for tax positions of current year		-		-
Reductions due to settlements with taxing authorities		-		(107,524)
Reductions due to lapse of statute of limitations		-		-
Total amount of gross uncertain tax positions at end of year	$	-	$	-

The State of North Dakota has made a claim against our wholly owned subsidiary, Samson Oil and Gas USA, Inc. relating to additional corporate income tax allegedly due for the years ended June 30, 2007 through June 30, 2011 in an amount of $597,852. We have reached a settlement with the State of North Dakota for a payment of $107,524, which was paid in July 2014.

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Capital Stock Contributed Equity

12 Months Ended

Jun. 30, 2016

Capital Stock Contributed Equity [Abstract]

Capital Stock Contributed Equity

7. COMMON STOCK

	Consolidated Entity
	2016		2015
3,215,854,701 ordinary fully paid shares including shares to be issued	$	105,719,184	$	104,491,774
(2015 –2,837,782,022 ordinary fully paid shares including shares to be issued)

Movements in contributed equity for the year	2016				2015
	No. of shares		$		No. of shares		$
Opening balance		2,837,782,022		104,491,774		2,837,756,933		104,535,894
Capital raising (i)		378,020,400		1,398,675		-		-
Shares issued upon exercise of options (ii)		52,279		1,475		25,089		880
Stock based compensation (options issued)		-		-		-		-
Transaction costs incurred		-		(172,740)		-		(45,000)
Shares on issue at balance date		3,215,854,701		105,719,184		2,837,782,022		104,491,774

	318,452,166 ordinary shares at $0.02 cents each to raise $6,700,000 in a private placement to certain institutional investors. 290,110,820 ordinary shares at $0.02 cents to raise $5,400,000 in a private placement to certain investors. 114,335,711 ordinary shares to raise $2,716,701. 19,182,812 ordinary shares at 0.026 cents to raise $500,000 in a private placement to certain institutional investors. 109,752,575 ordinary shares at 0.0259 cents to raise $2,850,000 in a private placement to certain institutional investors.
i)	Equity raised during the fiscal year ended June 30, 2016 In April 2016, we issued 378,020,400 ordinary shares at a purchase price of $0.0036 per share to raise $1.4 million in a  private placement to certain institutional investors.
(ii)		During the course of the year the Company issued  52,279(2015:  25,089) ordinary shares upon the exercise of 52,279 (2015:  25,089) options.

The exercise price of 52,279 (2015:  25,089) of the options exercised was A$0.038 cents per share/US$0.028 cents per shares (average price based on the exchange rate on the date of exercise) (2015:A$0.038/US$0.035 cents per share) to raise US$1,475(2015:  US$880).

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Cash Flow Statement

12 Months Ended

Jun. 30, 2016

Cash Flow Statement [Abstract]

Cash Flow Statement

8. CASH FLOW STATEMENT

	Year ended June 30
	2016		2015
A reconciliation of the net loss to the net cash provided by operations is as follows:
Net loss after tax	$	(12,633,909)	$	(36,619,632)
Depreciation		4,766,949		6,920,945
Accretion of asset retirement obligations		125,078		40,159
Exploration and evaluation expenditures		4,216,077		12,686,943
Impairment losses of oil and gas properties		11,029,442		21,475,450
Borrowing costs		185,138		135,694
Change in fair value of derivative instruments		2,644,244		(673,859)
Bargain purchase on acquistion		(10,775,231)		-
Abandonment costs		-		404,485
Changes in assets and liabilities:
Decrease in receivables		1,648,678		667,223
Decrease in employee benefits		(24,917)		(10,897)
Increase/(decrease) in payables		750,428		(1,982,072)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	1,931,977	$	3,044,439

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Credit Facility

12 Months Ended

Jun. 30, 2016

Credit Facility [Abstract]

Credit Facility

9.CREDIT FACILITY

	June 30,
	2016		2015
Credit facility at beginning of period	$	18,699,000	$	6,000,000
Cash advanced under facility		11,801,000		13,000,000
Repayments		-		(301,000)
Credit facility at end of period	$	30,500,000	$	18,699,000
Less fund due for repayment in the next 12 months		(11,500,000)		-
Total amount outstanding in long term credit facility	$	19,000,000	$	18,699,000
Funds available for drawdown under the facility		-		-

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

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

· Increases in the interest rate and unused facility fee;

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

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

· A requirement to raise $5 million in equity on or before September 30, 2016 (which was extended to November 15, 2016);

· A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to October 31, 2016 following the agreement to sell our interest in the North Stockyard field for $15 million); and

· The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement.

The current borrowing base is $30.5 million and is fully drawn as at September 28, 2016.

We intend to repay $11.5 million of the facility from proceeds from the sale of our interest in the North Stockyard field.  This sale is anticipated to close October 20, 2016.  Should this sale not close as anticipated we will be required to ask Mutual of Omaha bank for an extension on the debt pay down.

In January 2014, we entered into a $25.0 million credit facility with Mutual of Omaha Bank. The current borrowing base is $30.5 million, of which $30.5 million is drawn at June 30, 2016.  The next borrowing base redetermination is expected to be completed in October 2016 based on June 30, 2016 reserves information. The facility matures October 31, 2017. Following the increase in the facility the interest rate is LIBOR plus 6.00% or approximately 6.3% at June 30, 2016.

All of our assets are pledged as collateral under this facility.

As at June 30, 2016 we were in compliance with all of these quarterly covenants.

We raised $1.4 million in equity, in April 2016, towards the total of $5.0 million of equity to be raised that is required under the facility by September 30, 2016. Mutual of Omaha Bank has agreed to extend this deadline to November 15, 2016.  Mutual of Omaha Bank have also agreed to apply the excess proceeds over the $11.5 million required to be paid to Mutual of Omaha Bank to this total. 

We incurred $0.4 million in borrowing costs which have been deferred and will expensed through the effective interest rate charge.  

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Share-Based Payments

12 Months Ended

Jun. 30, 2016

Share-Based Payments [Abstract]

Share-Based Payments

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

To convert June 30, 2016 balances denominated in Australian dollars to U.S. dollars, we used the June 30, 2016 and 2015 Federal Reserve Bank of Australia (www.rba.gov.au) closing exchange rates of 0.768 and 0.942. U.S. dollars per Australian dollar, respectively. All dollars in this footnote are Australian dollars, except where stated 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 year ended June 30, 2016 as share based payments.

No options were issued during the year ended June 30, 2015 as share based payments.

As of June 30, 2016, there was US$Nil unrecognized compensation cost related to stock options.   

The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 2016 and 2015  (all values in AUD unless otherwise noted):

	2016			2015
	Number	Weighted	Aggregate	Number	Weighted
		Average	Intrinsic		Average
		Exercise	Value of		Exercise
		Price – cents	Options/Warrants		Price – cents
		(AUD)	cents		(AUD)
			(AUD)
			(1)
Outstanding, start of period	324,667,765	0.038		389,192,854	0.046
Granted	-	-		-	-
Exercised	(52,279)	0.038		(25,089)	0.038
Cancelled/expired	(4,000,000)	0.155		(64,500,000)	0.090
Outstanding, end of period	320,615,486	0.038	(0.03)	324,667,765	0.038
Exercisable, end of period	320,615,486	0.038		324,667,765	0.038

(1) The intrinsic value of a stock option is the amount by which the market value is (less than)/exceeds the exercise price at the Balance Date.

All warrants are immediately exercisable upon grant.

The aggregate intrinsic value of options exercised in 2016 and 2015 was (AUD1,731) and(AUD592), respectively.

Additional information related to options and warrants outstanding at June 30, 2016 is as follows (outstanding):

	Options/Warrants Outstanding and Exercisable
Range of	Number	Weighted		Weighted
Exercise	Outstanding	Average		Average
Prices		Remaining		Exercise
		Contractual		Prices
		Life - years
3.8 cents	229,582,240		0.75		0.038
3.3 cents	87,033,246		1.83		0.033
3.9 cents	4,000,000		1.42		0.039
	320,615,486

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Related Party Transactions

12 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Related Party Transactions

11. RELATED PARTY TRANSACTIONS

There were no related party transactions during the years ended June 30, 2016 and 2015.

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Commitments

12 Months Ended

Jun. 30, 2016

Commitments [Abstract]

Commitments

12. COMMITMENTS

Contractual Obligations				Total	2017		2018		2019		2020		2021		Thereafter
Asset retirement obligations (1)	$			3,750,245	$	300,000	$	-	$	-	$	-	$	-	$	3,450,245
Leases (2)				484,246		68,253		96,199		100,152		103,616		107,079		8,947
Credit Facility (3)		30,500,000				11,500,000		19,000,000		-		-		-		-
Promissory Note (4)				4,400,000		4,400,000		-		-		-		-		-
Total			39,134,491			16,268,253		19,096,199		100,152		103,616		107,079		3,459,192

(1)	Asset retirement obligations represent the estimated fair value at June 30, 2016 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors.
(2) (3)	Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Excludes variable rate debt interest payments related to the Company’s credit facility.  The interest rate is LIBOR plus 3.75% or approximately 6.3% at June 30, 2016.
(4)	Includes fixed interest costs payable at the promissory notes maturity date on April 1, 2017.  The interest rate is 10% per annum.

Leases –The Company has entered into lease agreements for office space in Denver, Colorado and Perth, Western Australia. As of June 30, 2016, future minimum lease payments under operating leases that have initial or remaining non–cancelable terms in excess of one year are $68,253 in 2017, $96,199 in 2018,$100,152 in 2019, $103,616 in 2020, $107,079 in 2021 and $8,947 thereafter. Net rent expense incurred for office space was $157,094 and$139,599 in 2016 and 2015, respectively.

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Contingencies

12 Months Ended

Jun. 30, 2016

Contingencies [Abstract]

Contingencies

13. CONTINGENCIES

There are no unrecorded contingent assets or liabilities in place for the Company at June 30, 2016 (2015: Nil).

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.

During the year ended June 30, 2016 the Company recognized a gain in other income of $0.8 million with respect to a settlement from litigation with Haliburton Company.  Haliburton paid the Company $0.7 million and forgave revenue owing of $0.1 million. A contingent receivable was not recognized prior to the settlement as the amount of the settlement was not reasonably estimable.

Liquidity

Following the sustained decline in oil prices, the Company became out of compliance with its loan to value ratio with Mutual of Omaha Bank. The Company is required to pay down $11.5 million of the proceeds from the pending sale of North Stockyard to Mutual of Omaha Bank.  The Company is also required to raise $5 million in equity prior to September 30, 2016.  The Company raised $1.4 million in equity in April 2016 and we have been granted an extension in this deadline to November 15, 2016. It is expected that Mutual of Omaha will also apply the remaining proceeds from the North Stockyard sale to this equity raise, however that is not certain.  The Company intends to meet its obligation to raise equity by September 30, 2016 and has not asked for a waiver from this requirement.  Following the pay down of the facility from the proceeds from the pending North Stockyard sale, the Company intends to enter into negotiations with Mutual of Omaha Bank to renegotiate the term and conditions of its credit facility, including the current maturity date and covenants.  While the new borrowing based is currently being determined by Mutual of Omaha Bank, based on the Company’s proved reserves the Company expects the borrowing base will be in excess of the current drawdown creating additional liquidity in the facility.

Should the Company not be able to renegotiate the credit facility to its satisfaction the Company may need to consider further asset sales or capital raises to provide the Company with ongoing liquidity to repay its long and short term debts as and when they fall due.

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Subsequent Events

12 Months Ended

Jun. 30, 2016

Subsequent Events [Abstract]

Subsequent Events

14.  SUBSEQUENT EVENTS

There have been no material subsequent events through the date of filing.

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Quarterly Financial Data

12 Months Ended

Jun. 30, 2016

Quarterly Financial Data [Abstract]

Quarterly Financial Data

15. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following is a summary of the unaudited financial data for each quarter for the years ended June 30, 2016 and 2015 (except per share data):

	Three Months Ended
	June 30, 2016		March 31, 2016		Dec 31, 2015		Sep 30, 2015
Year ended June 30, 2015:
Revenues	$	8,576,792	$	3,041,563	$	5,009,633	$	4,049,615
(Loss)/income from operations		2,822,938		(1,944,025)		(2,538,571)		(10,974,251)
Tax (expense)/benefit		-		-		-		-
Net (loss)/income		2,822,938		(1,944,025)		(2,538,571)		(10,974,251)
Basic (loss)/earnings per common share – cents per share		0.16		(0.07)		(0.09)		(0.43)
Diluted (loss)/earnings per common share – cents per share		0.16		(0.07)		(0.09)		(0.43)

		Three Months Ended
	June 30, 2015		March 31, 2015		Dec 31, 2014		Sep 30, 2014
Year ended June 30, 2015:
Revenues	$	4,475,079	$	3,041,563	$	5,009,633	$	4,049,615
Loss from operations		(21,159,764)		(1,944,025)		(2,538,571)		(10,974,251)
Tax (expense)/benefit		(3,021)		-		-		-
Net (loss)/income		(21,162,785)		(1,944,025)		(2,538,571)		(10,974,251)
Basic loss per common share – cents per share		(0.70)		(0.07)		(0.09)		(0.43)
Diluted loss per common share – cents per share		(0.70)		(0.07)		(0.09)		(0.43)

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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, 2016

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

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

Oil and Gas Reserves

The information set forth below regarding the Company’s oil and gas reserves, for the year ended June 30, 2016 was prepared by Netherland, Sewell, & Associates Inc and the reserves for the years ended June 30, 2015were prepared by Ryder Scott Company L.P., both independent reserve engineering firms.  The CEO reviews all reserve reports. All reserves are located within the continental United States.

Estimated Proved Reserves

Proved reserves are those quantities of hydrocarbons which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations.  As commodity prices decline, the commercially viability of wells change and reserve quantities may decrease.  Proved reserves can be categorized as developed or undeveloped.

Capitalized Costs Incurred

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

	Year ended June 30,
	2016		2015
Work in progress		-		-
Development		31,332,473		18,339,362
Exploration costs		-		1,449,750
Undeveloped capitalized acreage		178,254		23,130
Total costs incurred	$	31,510,727	$	19,812,242

Estimated Proved Reserves

Proved reserves are those quantities of hydrocarbons which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations.  As commodity prices decline, the commercially viability of wells change and reserve quantities may decrease.  Proved reserves can be categorized as developed or undeveloped.

	Year ended June 30, 2016			Year ended June 30, 2015
	Oil	Gas	Total	Oil	Gas	Total
	Mbbls	MMcf	MBOE	Mbbls	MMcf	MBOE
Beginning of year	1,285	1,183	1,483	1,478	1,763	1,773
Revisions of previous quantity estimates	2,597	2,662	3,041	(376)	(547)	(467)
Extensions and discoveries	-	-	-	414	193	446
Sale of reserves in place	-	-	-	-	-	-
Acquisitions	6,340	5,317	7,226	-	-	-
Production	(240)	(569)	(335)	(231)	(226)	(269)
End of year	9,982	8,593	11,415	1,285	1,183	1,483
Proved developed producing reserves	3,724	3,092	4,240	1,285	1,183	1,483
Proved developed non producing	970	1,800	1,270	-	-	-
Proved undeveloped reserves	5,288	3,701	5,905	-	-	-
Total proved reserves	9,982	8,593	11,415	1,285	1,183	1,483

During the year ended June 30, 2016 the acquisition of reserves relates to our Foreman Butte acquisition. The revisions to previous quantity estimates relates to workovers performed on wells associated with the Foreman Butte acquisition.

During the year ended June 30, 2015 the increase in extensions and discoveries relates to the drilling of our wells which were not previously PUD locations.

Developed Reserves

Developed reserves are those reserves expected to be recovered from existing wells, with existing equipment and operating methods.  Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Standardized Measure of Discounted Future Net Cash Flows

Future hydrocarbon sales and production and development costs have been estimated using a 12 month average price for the commodity prices for June 30, 2016 and 2015 and costs in effect at the end of the periods indicated.  The average 12 month historical average of the first of the month prices used for natural gas for June 30, 2016 and 2015 were $0.37 and$4.30 per Mcf, respectively.  The 12 month historical average of the first of the month prices used for oil for June 30, 2016 and 2015 were $37.12 and  $59.64 per barrel of oil, respectively.  Future cash flows were reduced by estimated future development, abandonment and production costs based on period–end costs.  No deductions were made for general overhead, depletion, depreciation and amortization or any indirect costs.  All cash flows are discounted at 10%.

Changes in demand for hydrocarbons, inflation and other factors make such estimates inherently imprecise and subject to substantial revisions.  This table should not be construed to be an estimate of current market value of the proved reserves attributable to Samson.

During the year ended June 30, 2015 we converted two PUD locations to PDP locations.  We also drilled and completed eight other wells that were not recorded as PUD’s at June 30, 2014.  At June 30, 2015 we have no PUD locations in our reserve value.

Samson has not disclosed the impact of taxes in the future cash flows for the years ended June 30, 2015 and 2016 as given Samson’s extensive net operating losses carried forward, its history of loss making and the significant value of intangible costs incurred when developing its proved undeveloped locations, for which an immediate tax deduction is currently available, it is unlikely Samson will pay tax in the future based on current commodity pricing.

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,
	2016		2015		2014		2013		2012
Future cash inflows	$	373,740	$	72,900	$	148,975	$	133,589	$	71,655
Future production costs		(184,691)		(22,403)		(43,009)		(44,672)		(29,321)
Future development costs		(50,752)		(38)		(12,461)		(29,012)		(10,198)
Future income taxes		-		-		(21,819)		(12,050)		(5,524)
Future net cashflows		138,297		50,459		71,686		47,855		26,612
10 % discount		(71,550)		(16,206)		(29,093)		(26,012)		(13,274)
Standardized measure of discounted future net cash flows relating to proved reserves	$	66,747	$	34,253	$	42,593	$	21,843	$	13,338

The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2016 and June 30, 2015 are as follows (in US$’000’s):

	Fiscal Year Ended June 30
	2016		2015
Beginning of year	$	34,253	$	42,593
Sales of oil and gas produced during the period, net of production costs		(3,575)		(7,178)
Net changes in prices and production costs		(15,705)		(22,610)
Previously estimated development costs incurred during the period		-		1,898
Changes in estimates of future development costs		(14,545)		-
Extensions and discoveries		-		11,266
Revisions of previous quantity estimates and other		18,074		(6,197)
Sale of reserves in place		-		-
Purchase of reserves in place		41,564		-
Change in future income taxes		-		11,809
Accretion of discount		3,452		5,440
Other		3,229		(2,768)
Balance at end of year	$	66,747	$	34,253

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 cashflows.

For the year ended June 30, 2015 the impact of changes in estimates of future development costs have been included in revisions of previous quantity estimates as they relate to the loss of PUD’s in the current pricing environment.

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Jun. 30, 2016

Jun. 30, 2015

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, Montana and Wyoming.

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. All intercompany balances and transactions have been eliminated in consolidation.

Use Of Estimates

Use of Estimates.   The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (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; (4) asset retirement obligations; (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 expenditure. 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. 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.   Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of completed deliveries where title has transferred. Title to oil sold is typically transferred at the wellhead.

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, 2016 or 2015.

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.  

Accounts Receivable

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

	June 30
	2016		2015
Oil and natural gas sales	$	1,717,110	$	3,224,595
Cost recovery from drilling partners		275,018		275,148
Other		4,287		145,480
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015	$	1,996,415	$	3,645,223

The Company's accounts receivable result from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are primarily from the operators of our various projects, who negotiate the sale of oil and gas to third parties on our behalf.

The cost recovery from drilling partners relates to the partners share of drilling costs associated with the current drilling program in our North Stockyard infill project and Hawk Springs project.

Accruals

Accruals.   The components of accrued liabilities for the years ended June 30, 2016 and 2015 are as follows:

	2016		2015
Bonus accrual		-		-
Other accruals		629,975		1,999,344
Deposit received for asset sale		1,000,000		0
	$	1,629,975	$	1,999,344

Other accruals includes an estimate of the costs expected to be incurred with respect to the asset retirement obligation in the next twelve months.

The deposit received from the asset sale is non-refundable (subject to the identification of certain title or environmental defects for the deadline for providing notification to the Company has passed) deposit received from the purchaser of our North Stockyard assets.

The majority of other accruals in the prior year relate to expenses incurred in relation to our exploratory well, Bluff, in our Hawk Springs project and other general accruals.

Oil And Natural Gas Properties

Oil and Gas Properties.

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

	2016		2015
Proved properties	$	45,177,047	$	61,724,561
Lease and well equipment		1,394,291		12,264,955
Less accumulated depreciation, depletion and impairment		(15,049,015)		(44,273,976)
	$	31,522,323	$	29,715,540
Assets held for sale		13,768,865		-
Unproved acreage	$	220,703	$	2,491,422
Capitalized exploration expense	$	-	$	1,388,798

The Company accounts for its oil and 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 cost 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.

Assets held for sale

On June 30, 2016, the Company signed a Purchase and Sale Agreement for the sale of its interests in the North Stockyard field.  The purchase price of the acquisition is $15 million and the acquisition is expected to settle on October 20, 2016.  The effective date of the acquisition is the day after the closing date.  The Company received a $1 million deposit from the purchaser on the date of signing, recorded in current liabilities.  This deposit is only refundable if certain title or environmental defects are identified during the purchasers due diligence. The date by which the purchaser was required to notify the Company of any title or environmental defects has passed and the Company was not advised of any environmental or title defects.

Exploration Written Off, Including Dry Hole Expenses

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 itis 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 year ended June 30, 2016, we expensed $4.2 million in deferred exploration expense in relation to our Hawk Springs project area.

During the fiscal year ended June 30, 2015 the Company expensed $8.1 million in relation to our Roosevelt project in Montana.  During the year ended June 30, 2014 the Company entered into a farm out arrangement with respect to this property however due to the falling oil prices, the farm out partner failed to meet it’s obligations under the agreement.  The Company does not plan to spend any additional capital in this project area and therefore we have written off the previously capitalized exploration expenditure.  The Company also wrote off $2.5 million with respect to its South Prairie project in North Dakota. A second dry hole was drilled in the area during the year ended June 30, 2015 and the decision was made to write off the costs capitalized with respect to this project.  The Company also expensed $1.6 million with respect to its Hawk Springs project in Wyoming. These costs were associated with leases expiring during the year. The Company also expensed $0.4 million of general exploration expenditure, which was never capitalized to the Balance Sheet.

Impairment

Impairment

The Company recorded impairment charges of $11.0 million and$21.5 million for the years ended June 30, 2016 and 2015 respectively.

The charges in the fiscal year ended June 30, 2016 related to the impact of the drop in the oil price on our North Stockyard, Rainbow and State GC project areas.

The charges in the fiscal year ended June 30, 2015 related to the impact of the drop in the oil price on our Rainbow and North Stockyard projects in North Dakota.

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, 2016and 2015 was $0.1 million and $0.1 million, respectively.

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

	2016		2015
Furniture, fittings and equipment	$	882,469	$	801,949
Less accumulated depreciation		(573,995)		(553,428)
	$	308,474	$	248,521

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.

Earnings Per Share

Earnings per Share.   Basic earnings (loss) per share are calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares. 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.

The following potential common shares relating to options and warrants have been excluded from the calculation of diluted earnings per share as the related impact was anti-dilutive.

	Year ended June 30,
	2016		2015
Dilutive		-	-
Anti–dilutive		321,955,194	357,099,676

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 Consolidated Entity 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.

New Accounting Pronouncements, Policy [Policy Text Block]

Impact of Recently Adopted Accounting Standards.

There have been no recently adopted accounting standards that would impact our business.

Recently Issued Accounting Pronouncements

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Jun. 30, 2016

Summary Of Significant Accounting Policies [Abstract]

Schedule Of Components Of Accounts Receivable

	June 30
	2016		2015
Oil and natural gas sales	$	1,717,110	$	3,224,595
Cost recovery from drilling partners		275,018		275,148
Other		4,287		145,480
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015	$	1,996,415	$	3,645,223

Schedule Of Components Of Accrued Liabilities

	2016		2015
Bonus accrual		-		-
Other accruals		629,975		1,999,344
Deposit received for asset sale		1,000,000		0
	$	1,629,975	$	1,999,344

Schedule Of Other Property And Equipment

	2016		2015
Furniture, fittings and equipment	$	882,469	$	801,949
Less accumulated depreciation		(573,995)		(553,428)
	$	308,474	$	248,521

Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities

	Year ended June 30,
	2016		2015
Dilutive		-	-
Anti–dilutive		321,955,194	357,099,676

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Business Combination (Tables)

12 Months Ended

Jun. 30, 2016

Business Combination [Abstract]

Schedule Of Business Acquisition

	USD
Amount Settled in Cash	$	1,391,874
Extension of credit facility		11,500,000
Fair value of promissory note provided		3,928,571
Fair value of consideration transferred		16,820,445
		-
Recognised amounts of identifiable assets and liabilities:
Oil and gas properties		29,350,256
Oil inventory acquired		463,768
Trade receivables		53,540
Revenue in suspense assumed		(403,612)
Asset retirement obligation assumed		(1,868,276)
Net identifiable assets and liabilities		27,595,676
Gain on bargain purchase		10,775,231

Schedule Of Pro Forma Information

Contribution of Business Combination to Company Results
The following represents the amount of the Company's revenue and losses for the years ended June 30, 2016 and June 30, 2015, assuming the business combination occurred on July 1, 2014.
	2016		2015
Revenues	$	25,579,347	$	19,849,812
Losses		(15,762,744)		(35,982,244)

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Hedging And Derivative Financial Instruments (Tables)

12 Months Ended

Jun. 30, 2015

Hedging And Derivative Financial Instruments [Abstract]

Schedule Of Open Derivative Contracts

At June 30, 2015 the Company’s open derivative contracts consisted of the following:

Oil Price Collars – WTI	Volumes (bbls)	Floor US$	Ceiling US$
January 2016 - February 2016	2,788	85.00	89.85
Oil Price Swaps – WTI	Volumes (bbls)	Price US$
July 2015 - December 2015	8,765	105.00
January 2016 - February 2016	2,788	105.00
Oil Price Three Way Swaps - WTI	Volumes (bbls)	Ceiling US$	Sub Floor US$	Floor US$
July 2015-  December 2015	55,200	70.25	32.50	45.00
January 2016 - December 2016	27,450	80.00	40.00	55.00
January 2016 – December 2016	36,600	-	67.50	82.50

During the year ended June 30, 2016, the Company recognized $2.7 million in the Statement of Operations in loss in derivative instruments.  As of June 30, 2016, the derivative instruments were valued at a unrealized loss of $2.8 million of which, $1.6 million is recorded as a current liability and $1.2 million is recorded as a non-current liability.

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Fair Value Measurements (Tables)

12 Months Ended

Jun. 30, 2016

Fair Value Measurements [Abstract]

Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis

	Fair Value at June 30, 2016
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash and cash equivalents	$	2,654,812	$	-	$	-	$	-	$	2,654,812
Derivative Instruments		-		136,727		-		(136,727)		-
Non Current Assets:
Derivative Instruments		-		220,317		-		(220,317)		-
Current Liabilities
Derivative Instruments		-		1,808,380		-		(136,727)		1,671,653
Non Current Liabilities:
Derivative Instruments				1,453,393				(220,317)		1,233,076
	Fair Value at June 30, 2015
	Level 1		Level 2		Level 3		Netting (1)		Total
Current Assets:
Cash and cash equivalents	$	2,062,720	$	-	$	-	$	-	$	2,062,720
Derivative Instruments		-		379,540		-		(220,324)		159,216
Non Current Assets:
Derivative Instruments		-		298,703		-		(197,434)		101,269
Current Liabilities
Derivative Instruments		-		220,324		-		(220,324)		-
Non Current Liabilities:
Derivative Instruments				197,434				(197,434)		-

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Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2016

Asset Retirement Obligations [Abstract]

Summary Of Activities Of Asset Retirement Obligations

	2016		2015
Asset retirement obligations at beginning of period	$	1,810,674	$	1,775,792
Liabilities incurred or acquired		1,868,276		672,339
Liabilities settled		(53,783)		(677,616)
Disposition of properties		-		-
Accretion expense		125,078		40,159
Asset retirement obligations at end of period		3,750,245		1,810,674
Less: current asset retirement obligations (classified with accounts payable and accrued liabilities)		(300,000)		(547,000)
Long-term asset retirement obligations	$	3,450,245	$	1,263,674

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Income Taxes (Tables)

12 Months Ended

Jun. 30, 2016

Income Taxes [Abstract]

Schedule Of Components Of Income Tax Provision (Benefit)

	June 30
	2016		2015
Current:
Federal	$	-	$	2,821
State		-		200
		-		3,021
Deferred:
Federal		-		-
State		-		-
Total income tax provision (benefit)	$	-	$	3,021

Schedule Of Effective Income tax Rate Reconciliation

		June 30
	2016		2015
Income tax expense (benefit) at federal statutory rate	$	(3,790,398)	$	(10,984,983)
State income taxes		(228,568)		(472,583)
Alternative minimum tax		-		2,821
Other adjustments - true up of deferred balances		(498,257)		(1,101,884)
Other - change in deferred tax rate		(188,080)		60,666
Other		(550,957)		(1,562,773)
Valuation allowance		5,256,260		14,061,757
	$	-	$	3,021

Schedule Of Components Of Deferred Tax Assets and (Liabilities)

	June 30
	2016		2015
Deferred income tax assets:
Net operating losses	$	33,548,583	$	25,995,717
Asset retirement obligation		1,395,262		458,869
Annual leave		60,826		71,309
Abandonment limitation		446,543		145,000
Accrued bonus		-		64,789
Charitable contributions		876		862
AMT credit		780,443		780,443
Share based compensation		500,844		500,844
Oil and Gas Property		-		157,481
Derivative liability		1,071,109		-
Valuation allowance		(33,337,136)		(28,080,876)
Deferred income tax liabilities:
Commodity liability		-		(94,588)
Amortization  - loan costs		-		-
Oil and gas property		(4,467,350)		-
Net deferred income tax assets (liabilities)		-		-
Net current deferred tax asset		-		-
Noncurrent deferred tax liability	$	-	$	-

Summary Of Valuation Allowance

		June 30
	2016		2015
Deferred Income Tax Valuation Allowance
Balance at July 1		28,080,876		14,019,119
Additions (reductions) to deferred income tax expense		5,256,260		14,061,757
Balance at June 30		33,337,136		28,080,876

Reconciliation Of Gross Uncertain Tax Positions

		2016		2015
Total gross uncertain tax positions at beginning of year	$	-	$	107,524
Additions / Reductions for tax positions of prior years		-		-
Additions / Reductions for tax positions of current year		-		-
Reductions due to settlements with taxing authorities		-		(107,524)
Reductions due to lapse of statute of limitations		-		-
Total amount of gross uncertain tax positions at end of year	$	-	$	-

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Capital Stock Contributed Equity (Tables)

12 Months Ended

Jun. 30, 2016

Capital Stock Contributed Equity [Abstract]

Contributed Equity

	Consolidated Entity
	2016		2015
3,215,854,701 ordinary fully paid shares including shares to be issued	$	105,719,184	$	104,491,774
(2015 –2,837,782,022 ordinary fully paid shares including shares to be issued)

Movements In Contributed Equity For The Year

Movements in contributed equity for the year	2016				2015
	No. of shares		$		No. of shares		$
Opening balance		2,837,782,022		104,491,774		2,837,756,933		104,535,894
Capital raising (i)		378,020,400		1,398,675		-		-
Shares issued upon exercise of options (ii)		52,279		1,475		25,089		880
Stock based compensation (options issued)		-		-		-		-
Transaction costs incurred		-		(172,740)		-		(45,000)
Shares on issue at balance date		3,215,854,701		105,719,184		2,837,782,022		104,491,774

	318,452,166 ordinary shares at $0.02 cents each to raise $6,700,000 in a private placement to certain institutional investors. 290,110,820 ordinary shares at $0.02 cents to raise $5,400,000 in a private placement to certain investors. 114,335,711 ordinary shares to raise $2,716,701. 19,182,812 ordinary shares at 0.026 cents to raise $500,000 in a private placement to certain institutional investors. 109,752,575 ordinary shares at 0.0259 cents to raise $2,850,000 in a private placement to certain institutional investors.
i)	Equity raised during the fiscal year ended June 30, 2016 In April 2016, we issued 378,020,400 ordinary shares at a purchase price of $0.0036 per share to raise $1.4 million in a  private placement to certain institutional investors.
(ii)		During the course of the year the Company issued  52,279(2015:  25,089) ordinary shares upon the exercise of 52,279 (2015:  25,089) options.

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Cash Flow Statement (Tables)

12 Months Ended

Jun. 30, 2016

Cash Flow Statement [Abstract]

Schedule Of Cash Flow Statement

	Year ended June 30
	2016		2015
A reconciliation of the net loss to the net cash provided by operations is as follows:
Net loss after tax	$	(12,633,909)	$	(36,619,632)
Depreciation		4,766,949		6,920,945
Accretion of asset retirement obligations		125,078		40,159
Exploration and evaluation expenditures		4,216,077		12,686,943
Impairment losses of oil and gas properties		11,029,442		21,475,450
Borrowing costs		185,138		135,694
Change in fair value of derivative instruments		2,644,244		(673,859)
Bargain purchase on acquistion		(10,775,231)		-
Abandonment costs		-		404,485
Changes in assets and liabilities:
Decrease in receivables		1,648,678		667,223
Decrease in employee benefits		(24,917)		(10,897)
Increase/(decrease) in payables		750,428		(1,982,072)
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	1,931,977	$	3,044,439

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Credit Facility (Tables)

12 Months Ended

Jun. 30, 2016

Credit Facility [Abstract]

Schedule of Credit Facilities

	June 30,
	2016		2015
Credit facility at beginning of period	$	18,699,000	$	6,000,000
Cash advanced under facility		11,801,000		13,000,000
Repayments		-		(301,000)
Credit facility at end of period	$	30,500,000	$	18,699,000
Less fund due for repayment in the next 12 months		(11,500,000)		-
Total amount outstanding in long term credit facility	$	19,000,000	$	18,699,000
Funds available for drawdown under the facility		-		-

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Share-Based Payments (Tables)

12 Months Ended

Jun. 30, 2016

Share-Based Payments [Abstract]

Schedule Of Additional Information Related To Options Outstanding

	Options/Warrants Outstanding and Exercisable
Range of	Number	Weighted		Weighted
Exercise	Outstanding	Average		Average
Prices		Remaining		Exercise
		Contractual		Prices
		Life - years
3.8 cents	229,582,240		0.75		0.038
3.3 cents	87,033,246		1.83		0.033
3.9 cents	4,000,000		1.42		0.039
	320,615,486

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Commitments (Tables)

12 Months Ended

Jun. 30, 2015

Commitments [Abstract]

Contractual Obligations

Contractual Obligations				Total	2017		2018		2019		2020		2021		Thereafter
Asset retirement obligations (1)	$			3,750,245	$	300,000	$	-	$	-	$	-	$	-	$	3,450,245
Leases (2)				484,246		68,253		96,199		100,152		103,616		107,079		8,947
Credit Facility (3)		30,500,000				11,500,000		19,000,000		-		-		-		-
Promissory Note (4)				4,400,000		4,400,000		-		-		-		-		-
Total			39,134,491			16,268,253		19,096,199		100,152		103,616		107,079		3,459,192

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Quarterly Financial Data (Tables)

12 Months Ended

Jun. 30, 2016

Quarterly Financial Data [Abstract]

Schedule Of Quarterly Financial Data

	Three Months Ended
	June 30, 2016		March 31, 2016		Dec 31, 2015		Sep 30, 2015
Year ended June 30, 2015:
Revenues	$	8,576,792	$	3,041,563	$	5,009,633	$	4,049,615
(Loss)/income from operations		2,822,938		(1,944,025)		(2,538,571)		(10,974,251)
Tax (expense)/benefit		-		-		-		-
Net (loss)/income		2,822,938		(1,944,025)		(2,538,571)		(10,974,251)
Basic (loss)/earnings per common share – cents per share		0.16		(0.07)		(0.09)		(0.43)
Diluted (loss)/earnings per common share – cents per share		0.16		(0.07)		(0.09)		(0.43)

		Three Months Ended
	June 30, 2015		March 31, 2015		Dec 31, 2014		Sep 30, 2014
Year ended June 30, 2015:
Revenues	$	4,475,079	$	3,041,563	$	5,009,633	$	4,049,615
Loss from operations		(21,159,764)		(1,944,025)		(2,538,571)		(10,974,251)
Tax (expense)/benefit		(3,021)		-		-		-
Net (loss)/income		(21,162,785)		(1,944,025)		(2,538,571)		(10,974,251)
Basic loss per common share – cents per share		(0.70)		(0.07)		(0.09)		(0.43)
Diluted loss per common share – cents per share		(0.70)		(0.07)		(0.09)		(0.43)

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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, 2016

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,
	2016		2015
Work in progress		-		-
Development		31,332,473		18,339,362
Exploration costs		-		1,449,750
Undeveloped capitalized acreage		178,254		23,130
Total costs incurred	$	31,510,727	$	19,812,242

Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities

	Year ended June 30, 2016			Year ended June 30, 2015
	Oil	Gas	Total	Oil	Gas	Total
	Mbbls	MMcf	MBOE	Mbbls	MMcf	MBOE
Beginning of year	1,285	1,183	1,483	1,478	1,763	1,773
Revisions of previous quantity estimates	2,597	2,662	3,041	(376)	(547)	(467)
Extensions and discoveries	-	-	-	414	193	446
Sale of reserves in place	-	-	-	-	-	-
Acquisitions	6,340	5,317	7,226	-	-	-
Production	(240)	(569)	(335)	(231)	(226)	(269)
End of year	9,982	8,593	11,415	1,285	1,183	1,483
Proved developed producing reserves	3,724	3,092	4,240	1,285	1,183	1,483
Proved developed non producing	970	1,800	1,270	-	-	-
Proved undeveloped reserves	5,288	3,701	5,905	-	-	-
Total proved reserves	9,982	8,593	11,415	1,285	1,183	1,483

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

	As at June 30,
	2016		2015		2014		2013		2012
Future cash inflows	$	373,740	$	72,900	$	148,975	$	133,589	$	71,655
Future production costs		(184,691)		(22,403)		(43,009)		(44,672)		(29,321)
Future development costs		(50,752)		(38)		(12,461)		(29,012)		(10,198)
Future income taxes		-		-		(21,819)		(12,050)		(5,524)
Future net cashflows		138,297		50,459		71,686		47,855		26,612
10 % discount		(71,550)		(16,206)		(29,093)		(26,012)		(13,274)
Standardized measure of discounted future net cash flows relating to proved reserves	$	66,747	$	34,253	$	42,593	$	21,843	$	13,338

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

	Fiscal Year Ended June 30
	2016		2015
Beginning of year	$	34,253	$	42,593
Sales of oil and gas produced during the period, net of production costs		(3,575)		(7,178)
Net changes in prices and production costs		(15,705)		(22,610)
Previously estimated development costs incurred during the period		-		1,898
Changes in estimates of future development costs		(14,545)		-
Extensions and discoveries		-		11,266
Revisions of previous quantity estimates and other		18,074		(6,197)
Sale of reserves in place		-		-
Purchase of reserves in place		41,564		-
Change in future income taxes		-		11,809
Accretion of discount		3,452		5,440
Other		3,229		(2,768)
Balance at end of year	$	66,747	$	34,253

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Summary Of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($) segment	Jun. 30, 2014 USD ($)
Significant Accounting Policies [Line Items]
Number of operating segments | segment		1
Impairment of oil and natural gas properties	$ 11,029,442	$ 21,475,450
Depreciation and amortization	4,766,949	6,920,945
Minimum percentage of likelihood tax benefits recognized from uncertain tax position, reasonably possible upon settlement			50.00%
Proved properties	45,177,047	61,724,561
Roosevelt project [Member]
Significant Accounting Policies [Line Items]
Capiltalized exploration expense written off		8,100,000
South Prairie Project [Member]
Significant Accounting Policies [Line Items]
Capiltalized exploration expense written off		2,500,000
Hawk Springs Project [Member]
Significant Accounting Policies [Line Items]
Capiltalized exploration expense written off		$ 1,600,000
Other Property And Equipment [Member]
Significant Accounting Policies [Line Items]
Depreciation and amortization	$ 100,000		$ 100,000
Other Property And Equipment [Member] | Minimum [Member]
Significant Accounting Policies [Line Items]
Estimated useful life		3 years
Other Property And Equipment [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Estimated useful life		25 years

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Summary Of Significant Accounting Policies (Schedule Of Components Of Accounts Receivable) (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 1,996,415	$ 3,645,223
Accounts receivable, allowance for doubtful accounts
Oil And Natural Gas Sales Related Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	1,717,110	3,224,595
Cost Recovery From JV Partner Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	275,018	275,148
Other Receivable [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 4,287	$ 145,480

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Summary Of Significant Accounting Policies (Schedule Of Components Of Accrued Liabilities) (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Summary Of Significant Accounting Policies [Abstract]
Other accruals	$ 629,975	$ 1,999,344
Deposit Received for asset sale	1,000,000
Total accrued liabilities	$ 1,629,975	$ 1,999,344

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Summary Of Significant Accounting Policies (Schedule Of Oil And Gas Properties And Equipment) (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Summary Of Significant Accounting Policies [Abstract]
Proved properties	$ 45,177,047	$ 61,724,561
Lease and well equipment	1,394,291	12,264,955
Less accumulated depreciation, depletion and impairment	(15,049,015)	(44,273,976)
Total oil and gas properties and equipment	31,522,323	29,715,540
Undeveloped capitalized acreage	$ 220,703	2,491,422
Capitalized exploration expense		$ 1,388,798

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Summary Of Significant Accounting Policies (Schedule Of Other Property And Equipment) (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Summary Of Significant Accounting Policies [Abstract]
Furniture, fittings and equipment	$ 882,469	$ 801,949
Less accumulated depreciation	(573,995)	(553,428)
Total other property and equipment	$ 308,474	$ 248,521

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Summary Of Significant Accounting Policies (Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities) (Details) - shares	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Diluted weighted average common shares outstanding	2,919,426,154	2,837,777,322
Options And Warrants [Member]
Anit-dilutive weighted average common shares outstanding	321,955,194	357,099,676

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Summary Of Significant Accounting Policies (Schedule Of Earnings Per Share, Basic And Diluted) (Details) - $ / shares	3 Months Ended								12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2016	Jun. 30, 2015
Summary Of Significant Accounting Policies [Abstract]
Basic weighted average common shares outstanding									2,919,426,154	2,837,777,322
Diluted weighted average common shares outstanding									2,919,426,154	2,837,777,322
Continuing operations, basic earnings per common share - cents per share	$ 0.16	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.70)	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.43)	$ (1.29)
Diluted earnings per common share - cents per share	$ 0.16	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.70)	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.43)	$ (1.29)

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Business Combination (Narrative) (Details)	12 Months Ended
	Jun. 30, 2016 USD ($)
Business Acquisition [Line Items]
Acquisition cost settled in cash and promissory note	$ 16,600,000
Extension of credit facility	11,500,000
Fair value of promissory note provided	$ 3,928,571
Effective interest rate	6.30%
Acquisition costs	$ 200,000
Promissory Note [Member]
Business Acquisition [Line Items]
Effective interest rate	12.00%
Face amount	$ 4,000,000
Interest rate	10.00%

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Business Combination (Schedule Of Business Acquisition) (Details)	12 Months Ended
	Jun. 30, 2016 USD ($)
Business Combination [Abstract]
Amount Settled in Cash	$ 1,391,874
Extension of credit facility	11,500,000
Fair value of promissory note provided	3,928,571
Fair value of consideration transferred	16,820,445
Oil and gas properties	29,350,256
Oil inventory acquired	463,768
Trade receivables	53,540
Revenue in suspense assumed	(403,612)
Asset retirement obligation assumed	(1,868,276)
Net identifiable assets and liabilities	27,595,676
Gain on bargain purchase	$ 10,775,231

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Business Combination (Schedule Of Pro Forma Information) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Business Combination [Abstract]
Revenues	$ 25,579,347	$ 19,849,812
Losses	$ (15,762,744)	$ (35,982,244)

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Hedging And Derivative Financial Instruments (Narrative) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Hedging And Derivative Financial Instruments [Abstract]
Fair value of derivative instruments		$ 101,269
Fair value of derivative instruments		159,216
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value	$ 1,233,076
Derivative Liability, Current	1,671,653
Derivative Liability, Noncurrent	1,233,076
Loss on Derivative Instruments, Pretax	$ 2,657,963
Gain on derivative instruments		$ 3,112,268

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Hedging And Derivative Financial Instruments (Schedule Of Open Derivative Contracts) (Details)	3 Months Ended	12 Months Ended
	Sep. 30, 2016 bbl / MMBTU $ / bbl bbl	Jun. 30, 2015 USD ($) $ / bbl bbl
Derivative Contract One [Member]
Derivative [Line Items]
Derivative inception		Jan. 01, 2016
Derivative maturity		Feb. 01, 2016
Volumes | bbl		2,788
Floor price		85.00
Ceiling price		89.85
Derivative Contract Two [Member]
Derivative [Line Items]
Derivative inception		Jul. 01, 2015
Derivative maturity		Dec. 01, 2015
Volumes | bbl		8,765
Price		105.00
Derivative Contract Three [Member]
Derivative [Line Items]
Derivative inception		Jan. 01, 2016
Derivative maturity		Feb. 01, 2016
Volumes | bbl		2,788
Price		105.00
Derivative Contract Four [Member]
Derivative [Line Items]
Derivative inception		Jul. 01, 2015
Derivative maturity		Dec. 01, 2015
Volumes | bbl		55,200
Sub floor | $		$ 32.50
Floor price		45.00
Ceiling price		70.25
Derivative Contract Five [Member]
Derivative [Line Items]
Derivative inception		Jan. 01, 2016
Derivative maturity		Dec. 01, 2016
Volumes | bbl		27,450
Sub floor | $		$ 40.00
Floor price		55.00
Ceiling price		80.00
Derivative Contract Six [Member]
Derivative [Line Items]
Derivative inception		Jan. 01, 2016
Derivative maturity		Dec. 01, 2016
Volumes | bbl		36,600
Sub floor | $		$ 67.50
Floor price		82.50
Derivative Contract Seven [Member]
Derivative [Line Items]
Derivative inception	Jul. 01, 2016
Derivative maturity	Apr. 30, 2018
Volume (BO/Mmbtu) | bbl / MMBTU	133,032
Floor price	41.50
Ceiling price	63.00
Derivative Contract Eight [Member]
Derivative [Line Items]
Derivative inception	Jul. 01, 2016
Derivative maturity	Oct. 31, 2016
Volume (BO/Mmbtu) | bbl / MMBTU	127,229
Floor price	1.90
Ceiling price	2.40
Derivative Contract Nine [Member]
Derivative [Line Items]
Derivative inception	Nov. 01, 2016
Derivative maturity	Mar. 31, 2017
Volume (BO/Mmbtu) | bbl / MMBTU	134,088
Floor price	2.60
Ceiling price	3.35
Derivative Contract Ten [Member]
Derivative [Line Items]
Derivative inception	Apr. 01, 2017
Derivative maturity	Oct. 31, 2017
Volume (BO/Mmbtu) | bbl / MMBTU	167,682
Floor price	2.40
Ceiling price	2.91
Derivative Contract Eleven [Member]
Derivative [Line Items]
Derivative inception	Nov. 01, 2017
Derivative maturity	Apr. 30, 2018
Volume (BO/Mmbtu) | bbl / MMBTU	127,030
Floor price	2.80
Ceiling price	3.60
Derivative Contract Twelve [Member]
Derivative [Line Items]
Derivative inception	Jul. 01, 2016
Derivative maturity	Dec. 31, 2016
Volumes | bbl	83,730
Floor price	41.20
Derivative Contract Thirteen [Member]
Derivative [Line Items]
Derivative inception	Jan. 01, 2017
Derivative maturity	Dec. 31, 2017
Volumes | bbl	141,255
Floor price	44.09
Derivative Contract Fourteen [Member]
Derivative [Line Items]
Derivative inception	Jan. 01, 2018
Derivative maturity	Apr. 30, 2018
Volumes | bbl	39,720
Floor price	45.55

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Fair Value Measurements (Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis) (Details) - USD ($)		Jun. 30, 2016	Jun. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents		$ 2,654,812	$ 2,062,720
Current Assets, Derivative Instruments			159,216
Non Current Assets, Derivative Instruments			101,269
Current Liabilities, Derivative Instruments		1,671,653
Non Current Liabilities, Derivative Instruments		1,233,076
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents		2,654,812	2,062,720
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and cash equivalents
Current Assets, Derivative Instruments		136,727	379,540
Non Current Assets, Derivative Instruments		220,317	298,703
Current Liabilities, Derivative Instruments		1,808,380	220,324
Non Current Liabilities, Derivative Instruments		1,453,393	197,434
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]	(136,727)	(220,324)
Non Current Assets, Derivative Instruments	[1]	(220,317)	(197,434)
Current Liabilities, Derivative Instruments	[1]	(136,727)	(220,324)
Non Current Liabilities, Derivative Instruments	[1]	$ (220,317)	$ (197,434)

[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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Asset Retirement Obligations (Details) - USD ($)	12 Months Ended			24 Months Ended
	Jun. 30, 2016		Jun. 30, 2015	Jun. 30, 2016
Asset Retirement Obligations [Line Items]
Asset retirement obligations at beginning of period	$ 1,810,674		$ 1,775,792	$ 1,775,792
Liabilities incurred or acquired	1,868,276		672,339
Liabilities settled	(53,783)		(677,616)
Accretion expense	125,078		40,159
Asset retirement obligations at end of period	3,750,245	[1]	1,810,674	3,750,245	[1]
Less: current asset retirement obligation (classified with accounts payable and accrued liabilities)	(300,000)		(547,000)	(300,000)
Long-term asset retirement obligations	$ 3,450,245		$ 1,263,674	$ 3,450,245
Minimum [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligations, Discount Rate				4.00%
Maximum [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligations, Discount Rate				13.00%

[1] Asset retirement obligations represent the estimated fair value at June 30, 2016 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors.

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Income Taxes (Narrative) (Details)	12 Months Ended
	Jun. 30, 2016 AUD	Jun. 30, 2015 USD ($)	Jun. 30, 2014	Jun. 30, 2016 USD ($)	Jun. 30, 2015 AUD	Jun. 30, 2015 USD ($)	Jun. 30, 2011 USD ($)
Income Taxes [Line Items]
Tax losses carried forward	AUD 15,621,491			$ 4,686,447	AUD 13,316,288	$ 3,994,887
Net operating tax losses						61,688,535
Tax expense (benefit)		$ 3,021
Income tax allegedly due							$ 597,852
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Net operating tax losses				79,987,858
Limitation per year				403,194
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Net operating tax losses				$ 46,216,143		$ 29,217,044
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		Jun. 01, 2015
Maximum [Member] | Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Net operating losses, expiration year			Dec. 31, 2033
Maximum [Member] | State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Net operating losses, expiration year	Jun. 01, 2033

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Income Taxes (Schedule Of Components Of Income Tax Provision (Benefit)) (Details)	12 Months Ended
	Jun. 30, 2015 USD ($)
Income Taxes [Abstract]
Current Federal	$ 2,821
Current State	200
Current	3,021
Total income tax provision (benefit)	$ 3,021

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Income Taxes (Schedule Of Effective Income tax Rate Reconciliation) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Income Taxes [Abstract]
Federal statutory rate				30.00%
Income tax expense (benefit) at federal statutory rate		$ (3,790,398)	$ (10,984,983)
State income taxes		(228,568)	(472,583)
Alternative minimum tax			2,821
Other adjustments - true up deferred balances		(498,257)	(1,101,884)
Other - change in deferred tax rate		(188,080)	60,666
Other		(550,957)	(1,562,773)
Valuation allowance		$ 5,256,260	14,061,757
Income Tax Expense (Benefit), Total	$ 3,021		$ 3,021

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Income Taxes (Schedule Of Components Of Deferred Tax Assets and (Liabilities)) (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Income Taxes [Abstract]
Net operating losses	$ 33,548,583	$ 25,995,717
Asset retirement obligation	1,395,262	458,869
Annual leave	60,826	71,309
Abandonment limitation	446,543	145,000
Accrued bonus		64,789
Charitable contributions	876	862
AMT Credit	780,443	780,443
Share based compensation	500,844	500,844
Derivative liability	1,071,109
Valuation allowance	(33,337,136)	(28,080,876)	$ (28,080,876)	$ (14,019,119)
Commodity liability		(94,588)
Amortization - loan costs
Oil and gas property	(4,467,350)
Net deferred income tax assets (liabilities)
Net current deferred tax asset
Noncurrent deferred tax liability

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Income Taxes (Summary Of Valuation Allowance) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Income Taxes [Abstract]
Balance	$ 28,080,876	$ 28,080,876
Additions (reductions) to deferred income tax expense	5,256,260	14,061,757
Balance	$ 33,337,136	$ 28,080,876

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Income Taxes (Reconciliation Of Gross Uncertain Tax Positions) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Income Taxes [Abstract]
Total gross uncertain tax positions at beginning of year		$ 107,524
Additions / Reductions for tax positions of prior years
Additions / Reductions for tax positions of current year
Reductions due to settlements with taxing authorities		(107,524)
Reductions due to lapse of statute of limitations
Total amount of gross uncertain tax positions at end of year

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Capital Stock Contributed Equity (Narrative) (Details)	12 Months Ended
	Jun. 30, 2016 USD ($) AUD / shares $ / shares shares	Jun. 30, 2015 AUD AUD / shares shares	Jun. 30, 2015 $ / shares	Jun. 30, 2014 AUD shares	Jun. 30, 2013 USD ($) $ / shares	Jun. 30, 2012 AUD / shares
Ordinary shares issued, shares	378,020,400
Ordinary shares issued, price per share | $ / shares	$ 0.0036
Ordinary shares issued, amount | $	$ 1,400,000
Shares issued upon exercise of options, shares	52,279	25,089
Weighted average exercise price - cents (AUD), exercised | (per share)	$ 0.038	AUD 0.038	$ 0.028		$ 0.035	AUD 0.038
Aggregate intrinsic value of options exercised		AUD (1,731)		AUD (592)	$ 880
1.5 Cents [Member]
Shares issued upon exercise of options, shares		52,279		25,089

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Capital Stock Contributed Equity (Contributed Equity) (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Capital Stock Contributed Equity [Abstract]
2,837,756,933 ordinary fully paid shares including shares to be issued (2013 - 2,229,165,163 ordinary fully paid shares including shares to be issued)	$ 105,719,184	$ 104,491,774
Common stock outstanding and to be issued		3,215,854,701	2,837,782,022

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Capital Stock Contributed Equity (Movements In Contributed Equity For The Year) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Capital Stock Contributed Equity [Abstract]
Beginning Balance, shares	2,837,782,022	2,837,756,933
Opening balance, value	$ 104,491,774	$ 104,535,894
Capital raising, shares	378,020,400
Capital raising	$ 1,398,675
Shares issued upon exercise of options, shares	52,279	25,089
Shares issued upon exercise of options, value	$ 1,475	$ 880
Transaction costs incurred, value	$ (172,740)	$ (45,000)
Ending Balance, shares	3,215,854,701	2,837,782,022
Shares on issue at balance date, value	$ 105,719,184	$ 104,491,774

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Cash Flow Statement (Details) - USD ($)	3 Months Ended								12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2016	Jun. 30, 2015
Cash Flow Statement [Abstract]
Net loss after tax	$ 2,822,938	$ (1,944,025)	$ (2,538,571)	$ (10,974,251)	$ (21,162,785)	$ (1,944,025)	$ (2,538,571)	$ (10,974,251)	$ (12,633,909)	$ (36,619,632)
Net (gain)/loss recognized on re-measurement to fair-value of investments held for trading									2,644,244	(673,859)
Depreciation									4,766,949	6,920,945
Accretion of asset retirement obligations									125,078	40,159
Borrowing costs									185,138	135,694
Exploration expense									4,216,077	12,686,943
Impairment losses of oil and gas properties									11,029,442	21,475,450
Abandonment expense										404,485
Gain on bargain purchase on acquisition									(10,775,231)
(Increase)/decrease in receivables									1,648,678	667,223
Increase/(decrease) in employee benefits									(24,917)	(10,897)
Increase/(decrease) in payables									750,428	(1,982,072)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations, Total									$ 1,931,977	$ 3,044,439

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Credit Facility (Narrative) (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	Jan. 31, 2014
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity					$ 25,000,000
Line of credit facility, current borrowing capacity		$ 30,500,000
Line of credit facility, amount outstanding		$ 30,500,000	$ 18,699,000	$ 6,000,000
Line of credit facility, expiration date		Oct. 31, 2017
Debt instrument, interest rate at period end		6.30%
Line of credity facility, cap on general and administrative expenditure		$ 3,000,000	$ 6
Minimum hedging		75
Equity to be raised	$ 5	5,000,000
Debt paydown required	$ 11,500,000	$ 10,000,000
London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			6.00%

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Credit Facility (Schedule of Credit Facilities) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Credit Facility [Abstract]
Credit facility at beginning of period	$ 18,699,000	$ 6,000,000
Cash advanced under facility	11,801,000	13,000,000
Proceeds from Issuance of Debt	4,000,000
Repayments		(301,000)
Credit facility at end of period	30,500,000	$ 18,699,000
Funds available for drawdown under the facility

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Share-Based Payments (Narrative) (Details)	12 Months Ended
	Jun. 30, 2016 AUD / shares shares	Jun. 30, 2015 AUD AUD / shares shares	Jun. 30, 2015 $ / shares	Jun. 30, 2014 AUD shares	Jun. 30, 2013 USD ($) $ / shares	Jun. 30, 2012 AUD / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exchange rate				0.7680	0.9420
Exercise price (Australian cents) | (per share)	AUD 0.038	AUD 0.038	$ 0.028		$ 0.035	AUD 0.038
Options exercised	52,279	25,089
Aggregate intrinsic value of options exercised		AUD (1,731)		AUD (592)	$ 880
1.5 Cents [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options exercised		52,279		25,089

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Share-Based Payments (Schedule Of Assumption Used In Black-Scholes Model) (Details)	12 Months Ended
	Jun. 30, 2016 AUD / shares	Jun. 30, 2015 AUD / shares	Jun. 30, 2015 $ / shares	Jun. 30, 2013 $ / shares	Jun. 30, 2012 AUD / shares
Share-Based Payments [Abstract]
Exercise price (Australian cents) | (per share)	AUD 0.038	AUD 0.038	$ 0.028	$ 0.035	AUD 0.038

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Share-Based Payments (Summary Of Stock Option Activity) (Details)		12 Months Ended
		Jun. 30, 2016 AUD AUD / shares shares	Jun. 30, 2015 AUD / shares shares	Jun. 30, 2015 $ / shares shares	Jun. 30, 2013 $ / shares	Jun. 30, 2012 AUD / shares
Share-Based Payments [Abstract]
Outstanding, start of period		324,667,765	389,192,854	389,192,854
Exercised		(52,279)	(25,089)	(25,089)
Cancelled/expired		(4,000,000)	(64,500,000)	(64,500,000)
Outstanding, end of period		320,615,486	324,667,765	324,667,765
Exercisable, end of period		320,615,486	324,667,765	324,667,765
Weighted average exercise price - cents (AUD), outstanding, start of period | AUD / shares		AUD 0.038	AUD 0.046
Weighted average exercise price - cents (AUD), exercised | (per share)		0.038	0.038	$ 0.028	$ 0.035	AUD 0.038
Weighted average exercise price - cents (AUD), cancelled/expired | AUD / shares		0.155	0.090
Weighted average exercise price - cents (AUD), outstanding, end of period | AUD / shares		0.038	0.038
Weighted average exercise price - cents (AUD), exercisable, end of period | AUD / shares		AUD 0.038	AUD 0.038
Aggregate intrinsic value of options - cents (AUD) | AUD	[1]	AUD (0.03)

[1] The intrinsic value of a stock option is the amount by which the market value is (less than)/exceeds the exercise price at the Balance Date.

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Share-Based Payments (Schedule Of Additional Information Related To Options Outstanding) (Details)	12 Months Ended
	Jun. 30, 2016 AUD / shares shares	Jun. 30, 2015 AUD / shares shares	Jun. 30, 2015 AUD / shares $ / shares shares	Jun. 30, 2013 AUD / shares	Jun. 30, 2013 $ / shares	Jun. 30, 2012 AUD / shares	Jun. 30, 2014 AUD / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price (Australian cents) | (per share)	AUD 0.038	AUD 0.038	$ 0.028		$ 0.035	AUD 0.038
Options outstanding, number outstanding | shares	320,615,486	324,667,765	324,667,765				389,192,854
Options outstanding, weighted average exercise prices	AUD 0.038	AUD 0.038	$ 0.038				AUD 0.046
Options exercisable, number exercisable | shares	320,615,486	324,667,765	324,667,765
Options exercisable, weighted average exercise prices	AUD 0.038	AUD 0.038	$ 0.038
3.8 Cents [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price (Australian cents)				AUD 0.038
Options outstanding, number outstanding | shares	229,582,240
Options outstanding, weighted average remaining contractual life - years	9 months
Options outstanding, weighted average exercise prices	AUD 0.038
3.3 Cents [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price (Australian cents)				0.033
Options outstanding, number outstanding | shares	87,033,246
Options outstanding, weighted average remaining contractual life - years	1 year 9 months 29 days
Options outstanding, weighted average exercise prices	AUD 0.033
3.9 Cents [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise price (Australian cents)				AUD 0.039
Options outstanding, number outstanding | shares	4,000,000
Options outstanding, weighted average remaining contractual life - years	1 year 5 months 1 day
Options outstanding, weighted average exercise prices	AUD 0.039

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Commitments (Narrative) (Details) - USD ($)		12 Months Ended
		Jun. 30, 2016		Jun. 30, 2015	Jun. 30, 2014
Commitments [Abstract]
Operating leases, 2017	[1]	$ 68,253
Operating leases, 2018	[1]	96,199
Operating leases, 2019	[1]	100,152
Operating Leases, 2020	[1]	103,616
Operating Leases, 2021	[1]	107,079
Operating leases, Thereafter		8,947	[1]
Net rent expense		$ 157,094		$ 139,599

[1] Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Excludes variable rate debt interest payments related to the Company's credit facility. The interest rate is LIBOR plus 3.75% or approximately 6.3% at June 30, 2016.

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Commitments (Contractual Obligations) (Details) - USD ($)		Jun. 30, 2016		Jun. 30, 2015	Jun. 30, 2014
Commitments [Abstract]
Asset retirement obligations, Total		$ 3,750,245	[1]	$ 1,810,674	$ 1,775,792
Asset retirement obligations, 2017	[1]	300,000
Asset retirement obligations, 2020	[1]
Asset retirement obligations, 2021	[1]
Asset retirement obligations, Thereafter	[1]	3,450,245
Operating leases, Total	[2]	484,246
Operating leases, 2017	[2]	68,253
Operating leases, 2018	[2]	96,199
Operating leases, 2019	[2]	100,152
Operating leases, 2020	[2]	103,616
Operating leases, 2021	[2]	107,079
Operating leases, Thereafter		8,947	[2]
Credit Facility, Total		30,500,000
Credit Facility, 2017		11,500,000
Credit Facility, 2018		19,000,000
Credit Facility, 2020
Credit Facility, 2021
Payment of promissory note		4,400,000
Payment of Promissory Note TOTAL		4,400,000
Contractual Obligations, Total		39,134,491
Contractual Obligations, 2017		16,268,253
Contractual Obligations, 2018		19,096,199
Contractual Obligations, 2019		100,152
Contractual Obligations, 2020		103,616
Contractual Obligations, 2021		107,079
Contractual Obligations, Thereafter		$ 3,459,192

[1] Asset retirement obligations represent the estimated fair value at June 30, 2016 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors.

[2] Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Excludes variable rate debt interest payments related to the Company's credit facility. The interest rate is LIBOR plus 3.75% or approximately 6.3% at June 30, 2016.

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Contingencies (Details)	Jun. 30, 2013 USD ($)
Contingencies [Abstract]
Contingent assets
Contingent liabilities

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Quarterly Financial Data (Details) - USD ($)	3 Months Ended								12 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2016	Jun. 30, 2015
Quarterly Financial Data [Abstract]
Revenues	$ 8,576,792	$ 3,041,563	$ 5,009,633	$ 4,049,615	$ 4,475,079	$ 3,041,563	$ 5,009,633	$ 4,049,615	$ 20,677,603	$ 16,575,890
Income (loss) from continuing operations	2,822,938	(1,944,025)	(2,538,571)	(10,974,251)	(21,159,764)	(1,944,025)	(2,538,571)	(10,974,251)	(12,633,909)	(36,616,611)
Income tax (provision)/benefit					(3,021)					(3,021)
Net loss	$ 2,822,938	$ (1,944,025)	$ (2,538,571)	$ (10,974,251)	$ (21,162,785)	$ (1,944,025)	$ (2,538,571)	$ (10,974,251)	$ (12,633,909)	$ (36,619,632)
Basic loss per common share - cents per share	$ 0.16	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.70)	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.43)	$ (1.29)
Diluted earnings per common share - cents per share	$ 0.16	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.70)	$ (0.07)	$ (0.09)	$ (0.43)	$ (0.43)	$ (1.29)

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Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Narrative) (Details)	12 Months Ended
	Jun. 30, 2015 $ / bbl $ / Mcf	Jun. 30, 2014 $ / bbl $ / Mcf
Discount factor of future net cash flows		10.00%
Oil [Member]
12 month historical average price per barrel of oil | $ / bbl	37.12	59.64
Natural Gas [Member]
12 month historical average price per Mcf | $ / Mcf	0.37	4.30

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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, 2016	Jun. 30, 2015
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]
Development costs	$ 31,332,473	$ 18,339,362
Exploration costs		1,449,750
Undeveloped capitalized acreage	178,254	23,130
Total costs incurred	$ 31,510,727	$ 19,812,242

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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, 2016 MBoe MBbls bbl MMcf	Jun. 30, 2015 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Proved Developed Reserves ProductionBOE | MBoe	(335)	(269)
Beginning of year (BOE) | MBoe	1,483	1,773
Revisions of previous quantity estimates (BOE) | MBoe	3,041	(467)
Extensions, discoveries and improved estimates (BOE) | MBoe		446
Acquisitions (BOE) | MBoe	7,226
End of year (BOE) | MBoe	11,415	1,483
Proved developed producing reserves (BOE) | MBoe	4,240	1,483
Proved undeveloped reserves (BOE) | MBoe	5,905
Proved Developed Non Producing (BOE) | MBoe	1,270
Proved reserves (BOE) | MBoe	11,415	1,483
Oil [Member]
Reserve Quantities [Line Items]
Beginning of year (Volume) | MBbls	1,285	1,478
Revisions of previous quantity estimates (Volume) | MBbls	2,597	(376)
Extensions, discoveries and improved recovery (Volume) | MBbls		414
Acquisitions (Volume) | MBbls	6,340
Production (Volume) | MBbls	(240)	(231)
End of year (Volume) | MBbls	9,982	1,285
Proved developed producing reserves (Volume) | MBbls	3,724	1,285
Proved Developed Non Producing (Volume) | bbl	970
Proved undeveloped reserves (Volume) | MBbls	5,288
Proved reserves (Volume) | MBbls	9,982	1,285
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning of year (Volume) | MMcf	1,183	1,763
Revisions of previous quantity estimates (Volume) | MMcf	2,662	(547)
Extensions, discoveries and improved recovery (Volume) | MMcf		193
Acquisitions (Volume) | MMcf	5,317
Production (Volume) | MMcf	(569)	(226)
End of year (Volume) | MMcf	8,593	1,183
Proved developed producing reserves (Volume) | MMcf	3,092	1,183
Proved Developed Non Producing (Volume) | MMcf	1,800
Proved undeveloped reserves (Volume) | MMcf	3,701
Proved reserves (Volume) | MMcf	8,593	1,183

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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, 2016	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]
Future cash inflows	$ 373,740	$ 72,900	$ 148,975	$ 133,589	$ 71,655
Future production costs	(184,691)	(22,403)	(43,009)	(44,672)	(29,321)
Future development costs	(50,752)	(38)	(12,461)	(29,012)	(10,198)
Future income taxes			(21,819)	(12,050)	(5,524)
Future net cashflows	138,297	50,459	71,686	47,855	26,612
10% discount	(71,550)	(16,206)	(29,093)	(26,012)	(13,274)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 66,747	$ 34,253	$ 42,593	$ 21,843	$ 13,338

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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, 2016	Jun. 30, 2015
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract]
Beginning of year	$ 34,253	$ 42,593
Sales of oil and gas produced during the period, net of production costs	(3,575)	(7,178)
Net changes in prices and production costs	(15,705)	(22,610)
Previously estimated development costs incurred during the period		(1,898)
Changes in estimates of future development costs	(14,545)
Extensions, discoveries and improved recovery		11,266
Revisions of previous quantity estimates and other	18,074	(6,197)
Purchase of reserves in place	41,564
Change in future income taxes		11,809
Accretion of discount	3,452	5,440
Other	3,229	(2,768)
Balance at end of year	$ 66,747	$ 34,253