UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 20-F/A

Amendment No. 1

(Mark One)

o	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015

OR

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

OR

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

Commission file number: 000-55246

Sundance Energy Australia Limited

(Exact name of Registrant as specified in its charter)

Australia

(Jurisdiction of incorporation or organization)

633 17th Street, Suite 1950

Denver, CO 80202

Tel: (303) 543-5700

(Address of principal executive offices)

Eric P. McCrady

Sundance Energy, Inc.

Chief Executive Officer

633 17th Street, Suite 1950

Denver, CO 80202

Tel: (303) 543-5700

Fax: (303) 543-5701

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act: None

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Ordinary Shares

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

559,103,562 Ordinary Shares at December 31, 2015

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

o Yes x No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x Yes o 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

o Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP o

International Financial Reporting Standards as issued
by the International Accounting Standards Board x

Other o

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.

o Item 17 o Item 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes x No

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PART I

Item 3. Key Information

A. Selected Financial Data

The following tables set forth summary historical financial data for the periods indicated. The selected consolidated financial data of the Company as at and for the years ended December 31, 2015, 2014 and 2013 have been derived from, and should be read in conjunction with, the audited consolidated financial statements and notes thereto set forth beginning on page F-1 of this annual report. The selected consolidated financial data as at and for the six-month period ended December 31, 2012 and the years ended June 30, 2012 and 2011 are derived from the audited consolidated financial statements not appearing in this Annual Report. This data should be read in conjunction with the financial statements, related notes and other financial information included elsewhere herein. Our historical results do not necessarily indicate our expected results for any future periods.

Our financial statements have been prepared in U.S. dollars and in accordance with Australian Accounting Standards. Our financial statements comply with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”).

	Year ended December 31,									Six-month period ended December 31,			Year ended June 30,
(In $ ‘000s)	2015			2014			2013			2012			2012			2011
	(audited)			(audited)			(audited)			(audited)			(audited)			(audited)
	(Restated)
Statement of Operations Data:
Revenues:
Oil revenue	$	82,949		$	144,994		$	79,365		$	16,790		$	27,965		$	16,706
Natural gas revenue	4,720			6,161			2,774			934			1,822			1,470
Natural gas liquids (NGL) (1)	4,522			8,638			3,206			—			—			—
Total oil and natural gas revenues	92,191			159,793			85,345			17,724			29,787			18,176
Lease operating and production tax expenses	24,498			20,489			18,383			4,082			6,355			2,858
Depreciation and amortization expense	94,584			85,584			36,225			6,116			11,111			6,509
General and administrative expense	17,176			15,527			15,297			5,810			6,863			5,338
Finance costs, net of interest income	9,418			494			(351		)	578			(111		)	(312		)
Loss on debt extinguishment	1,451			—			—			—			—			—
Impairment of non-current assets	321,918			71,212			—			—			357			1,273
Exploration and evaluation expenditure	7,925			10,934			—			—			—			—
Gain on sale of non-current assets	(790		)	(48,604		)	(7,335		)	(122,327		)	(3,004		)	(10,940		)
(Gain) / loss on commodity hedging	(15,256		)	(11,009		)	554			639			(1,945		)	1,107
Realized currency loss	—			—			—			—			4			559

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	Year ended December 31,									Six-month period ended December 31,			Year ended June 30,
(In $ ‘000s)	2015			2014			2013			2012			2012			2011
	(audited)			(audited)			(audited)			(audited)			(audited)			(audited)
Other expense	2,340			686			1,063			—			—			—
Income tax (benefit) expense	(107,138		)	(841		)	5,567			46,616			4,145			4,755
Profit (loss) attributable to owners of Sundance	$	(263,835	)	$	15,321		$	15,942		$	76,210		$	6,012		$	7,029

Other comprehensive income (expense)

Exchange differences arising on translation of foreign operations	(478		)	684			(421		)	(154		)	(247		)	384
Total comprehensive income (loss) attributable to owners of Sundance	$	(264,313	)	$	16,005		$	15,521		$	76,056		$	5,765		$	7,413
Basic and diluted earnings per share	$	(0.48	)	$	0.03		$	0.04		$	0.27		$	0.02		$	0.03
Basic weighted average number of ordinary shares outstanding	552,847,289			531,391,405			413,872,184			277,244,883			277,049,463			260,935,572
Other Supplementary Data:
Adjusted EBITDAX(2)	$	64,781		$	126,373		$	52,594		$	9,223		$	17,093		$	9,993

(1) Prior to the year ended December 31, 2013, our NGL sales were insignificant as compared to our overall gas sales and as such, were included in our natural gas sales.

(2) Adjusted EBITDAX is a supplemental non-IFRS financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our profit (loss) attributable to owners of Sundance, see “—Adjusted EBITDAX” below.

	December 31,								June 30,
(In $ ‘000s)	2015		2014		2013		2012		2012		2011
	(audited)		(audited)		(audited)		(audited)		(audited)		(audited)
	(Restated)
Balance Sheet Data:
Cash and cash equivalents	$	3,468	$	69,217	$	96,871	$	154,110	$	15,328	$	25,244
Assets held for sale	90,632		—		11,484		—		—		—
Total current assets	125,345		114,045		141,141		175,424		30,691		31,173
Oil and natural gas properties:
Development and production assets	250,922		519,013		312,230		79,729		87,274		45,873
Exploration and evaluation expenditure	26,323		155,130		166,144		33,439		11,436		6,626
Total assets	409,835		796,520		625,060		291,435		130,316		84,080
Current liabilities	42,215		119,324		140,862		51,842		30,393		10,160
Credit facilities, net of deferred financing fees	187,743		128,805		29,141		29,570		14,655		—
Restoration provision	3,088		8,866		5,074		1,228		588		349
Deferred tax liabilities	—		102,668		102,711		56,979		10,476		6,104
Total non-current liabilities	191,251		242,190		136,957		87,777		25,719		6,453
Total liabilities	233,466		361,514		277,819		139,619		56,112		16,613
Net assets	176,369		435,006		347,241		151,816		74,204		67,467
Issued capital	308,429		306,853		237,008		58,694		57,978		57,831

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	Year ended December 31,								Six month period ended December 31,		Year ended June 30,
(In $ ‘000s)	2015		2014			2013			2012		2012			2011
	(audited)		(audited)			(audited)			(audited)		(audited)			(audited)
Net Cash Flow Data:
Net cash provided by operating activities	64,469		$	128,087		$	62,646		$	9,386	$	11,832		$	8,908
Net cash (used in) provided by investing activities	(180,771	)	(323,235		)	(164,355		)	114,571		(36,149		)	(13,465		)
Net cash provided by financing activities	50,403		167,595			44,455			14,846		14,734			18,869

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental non-IFRS financial measure that is used by our management and external users of our consolidated financial statements, such as investors, industry analysts and lenders.

We define “Adjusted EBITDAX” as earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain/(loss) on sale of non-current assets, exploration expense, share-based compensation and income and gains and losses on commodity hedging, net of settlements of commodity hedging.

Our management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from profit attributable to owners of Sundance in arriving at Adjusted EBITDAX, because these amounts can vary substantially from company to company within our industry, depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with IFRS, as issued by the IASB, or as an indicator of our operating performance or liquidity.

Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as cost of capital and tax structure, as well as the historic costs of depreciable assets. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following table presents a reconciliation of the profit (loss) attributable to owners of Sundance to Adjusted EBITDAX:

	Year ended December 31,									Six-month period ended December 31,			Year ended June 30,
(In $ ‘000s)	2015			2014			2013			2012			2012			2011
	(audited)			(audited)			(audited)			(audited)			(audited)			(audited)
	(Restated)
IFRS Profit Reconciliation to Adjusted EBITDAX:
Profit (loss) attributable to owners of Sundance	$	(263,835	)	$	15,321		$	15,942		$	76,210		$	6,012		$	7,029
Income tax (benefit) expense	(107,138		)	(841		)	5,567			46,616			4,145			4,755
Finance costs, net of (interest received)	9,418			494			(232		)	578			(111		)	(312		)
Loss on debt extinguishment	1,451			—			—			—			—			—
(Gain) loss on commodity hedging	(15,256		)	(10,792		)	554			639			(1,945		)	1,107
Settlement of commodity hedging	12,404			1,150			283			551			(297		)	(643		)
Depreciation and amortization expense	94,584			85,584			36,225			6,116			11,111			6,509
Impairment of non-current assets	321,918			71,212			—			—			357			1,273
Exploration expense	7,925			10,934			—			—			—			—
Stock compensation, value of services	4,100			1,915			1,590			840			825			1,215
Gain on sale of non-current assets	(790		)	(48,604		)	(7,335		)	(122,327		)	(3,004		)	(10,940		)
Adjusted EBITDAX	$	64,781		$	126,373		$	52,594		$	9,223		$	17,093		$	9,993

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Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and this volatility may continue in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

· general worldwide and regional economic and political conditions;

· the domestic and global supply of, and demand for, oil, natural gas and NGLs;

· the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;

· the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;

· the price and quantity of imports of foreign oil, natural gas and NGLs;

· the level of global oil, natural gas and NGL exploration and production;

· the level of global oil, natural gas and NGL inventories;

· weather conditions and natural disasters;

· domestic and foreign governmental laws, regulations and taxes;

· volatile trading patterns in commodities futures markets;

· price and availability of competitors’ supplies of oil, natural gas and NGLs;

· the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and the ability of OPEC and other producing nations to agree to and maintain production levels;

· technological advances affecting energy consumption; and

· the price and availability of alternative fuels.

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 69% of our estimated proved reserves as of December 31, 2015 was attributed to oil, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices.

Prolonged or substantial declines in oil, natural gas and NGL prices may have the following effects on our business:

· reducing our revenues, operating income and cash flows;

· adversely affecting our financial condition, liquidity, results of operations and our ability to meet our capital expenditure obligations and financial commitments;

· limiting our access to, or increasing the cost of, sources of capital, such as equity and long-term debt (including our borrowing capacity under our existing credit facilities);

· reducing the amount of oil, natural gas and NGLs that we can produce economically;

· reducing the amounts of our estimated proved oil, natural gas and NGLs reserves;

· reducing the standardized measure of discounted future net cash flows relating to oil, natural gas and NGL reserves;

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· causing us to delay or postpone certain of our capital projects; and

· reducing the carrying value of our oil and natural gas properties.

As of December 31, 2015, we have commodity price hedging agreements on approximately 53% of our expected Boe production for 2016. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil and natural gas that could materially and adversely affect our business and results of operations.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. Although we intend to operate within our downcycle development plan in 2016 by financing our capital expenditures with only our cash flows from operations, we may also finance our future capital expenditures through a variety of other sources, including through borrowings under our credit facilities and asset sales. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets.

Our cash flows from operations and access to capital are subject to a number of variables, including:

· our proved reserves;

· the volume of oil and natural gas we are able to produce and sell from existing productive wells;

· the prices at which our oil and natural gas are sold;

· the cost at which our oil and natural gas are extracted;

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

· the ability of our banks to provide us with credit or additional borrowing capacity.

If our revenues or the amounts we can borrow under our credit facilities decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms or at all. If cash generated by operations or cash available under our credit facilities is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our oil and natural gas reserves and production levels, and could adversely affect our business, financial condition and results of operations.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.

The oil and natural gas business involves operating hazards such as:

· well blowouts;

· mechanical failures;

· explosions;

· pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;

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Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise and/or oil and natural gas prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our plan and/or ability to drill any scheduled or budgeted wells,will be dependent on a number of uncertainties, including:

· the results of our exploration efforts;

· review and analysis of geologic and engineering data;

· the availability of sufficient capital resources to us and the other participants for drilling and completing of the prospects;

· the approval of the prospects by other participants once additional data has been compiled;

· economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability and prices of drilling rigs and personnel; and

· the ability to maintain, extend or renew leases and permits on reasonable terms for the prospects.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a prospect rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

Certain of our undeveloped leasehold acreage is subject to leases expiring over the next several years unless production is established on units containing the acreage.

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established. For these properties, if production in commercial quantities has not been established on the leased property or units that include the leased property containing these leases, our leases will expire and we will lose our right to develop the related properties. As of December 31, 2015, 33,887 net acres of our total acreage position was not held by production. For the acreage underlying such properties, if production in paying quantities is not established on units containing these leases, approximately 6,226 net acres will expire in 2016, approximately 12,680 net acres will expire in 2017 and approximately 14,981 net acres will expire thereafter.

Our drilling plans for these areas are subject to change based upon various factors, many of which are beyond our control, including:

· drilling results;

· oil and natural gas prices;

· the availability and cost of capital;

· drilling and production costs;

· the availability of drilling services and equipment;

· gathering system and pipeline transportation constraints; and

· regulatory approvals.

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As a non-operating leaseholder in certain of our properties, we have less control over the timing of drilling and there is a higher risk of lease expirations occurring where we are not the operator. For certain properties in which we are a non-operating leaseholder, we have the right to propose the drilling of wells pursuant to a joint operating agreement. Those properties that are not subject to a joint operating agreement are located in states where state law grants us the right to force pooling.

We have limited control over activities in properties we do not operate, which could reduce our production and revenues.

We utilize joint operating agreements in some of our properties where we have less than 100% working interest. Other companies may be operators under these joint operating agreements and, as a minority working interest owner, we will be dependent to a degree on the efficient and effective management of the operators. The objectives and strategy of those operators may not always be consistent with our objectives and strategy. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues or could create liability for the operator’s failure to properly maintain the well and facilities and to adhere to applicable safety and environmental standards. With respect to properties that we do not operate:

· the operator could refuse to initiate exploration or development projects;

· if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project;

· the operator may initiate exploration or development projects on a different schedule than we would prefer;

· the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build more facilities on a project than we have funds available, which may cause us to not fully participate in those projects or participate in a substantial amount of the revenues from those projects; and

· the operator may not have sufficient expertise or financial resources to develop such projects.

Any of these events could significantly and adversely affect our anticipated exploration and development activities. Under our joint operating agreements, we will be required to pay our percentage interest share of all costs and liabilities incurred by the operator on behalf of the working interest owners in connection with joint venture activities. In common with other working interest owners, if we fail to pay our share of any costs and liabilities, we may be deemed to have elected non-participation with respect to operations affected and we may be subject to loss of interest through foreclosure of operator liens invoked by participating working interest owners which may subject us to non-consent penalties.

We operated 93.3% of our total production for the year ended December 31, 2015.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.

There are uncertainties inherent in estimating oil and natural gas reserves and their estimated value, including many factors beyond our control. The reserve data in this annual report represent only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, oil and natural gas prices, revenue, taxes, operating expenses, expenditures and quantities of recoverable oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report.

As of December 31, 2015, approximately 58% of our total proved reserves were proved undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves. Decreases in future prices, unexpected results from development or downward actual cash flows vs. forecasts may impact the development of our proved undeveloped reserves.

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SEC rules could limit our ability to book additional PUDs in the future.

SEC rules require that, subject to limited exceptions, our PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write-down our PUDs if we do not drill those wells within the required five-year time frame, or if oil and natural gas prices decrease, making the PUDs uneconomic.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and natural gas reserves. As required by the current requirements for oil and natural gas reserve estimation and disclosures, 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. Actual future net cash flows also will be affected by various factors, including:

· the actual prices we receive for oil and natural gas;

· our actual operating costs in producing oil and natural gas;

· the amount and timing of actual production;

· supply and demand for oil and natural gas;

· increases or decreases in consumption of oil and natural gas; and

· changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Our derivative activities could result in financial losses or could reduce our income.

Because oil and natural gas prices are subject to volatility, we may periodically enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in oil and natural gas prices.

These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of oil and natural gas or a sudden, unexpected event that materially impacts oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

If oil and natural gas prices continue to be depressed or decline further, we may be required to write-down the carrying values of our oil and natural gas properties.

We review our development and production and exploration and evaluation expenditure oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings.

The capitalized costs of our oil and natural gas properties, on an area of interest basis, cannot exceed the estimated discounted future net cash flows of that area of interest. If net capitalized costs exceed discounted future net revenues, we generally must write down the costs of each area of interest to the estimated discounted future net cash flows of that area of interest. We incurred impairment of development and production properties expense and impairment of exploration and evaluation expenditures properties expense totaling $184.4 million and $137.2 million, respectively, during 2015 and $71.2 million and nil, respectively, during 2014.

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Commodity prices significantly declined in 2014 and 2015. Continued declines in the prices of crude oil, natural gas, or NGLs or unsuccessful exploration efforts could cause additional development and production and/or exploration and evaluation expenditure property impairments in the future.

Our inability to market our oil and natural gas could adversely affect our business.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial 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 favorable terms could adversely impact our business and results of operations.

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our oil or natural 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 are unable to market and sustain production from a particular lease for an extended period of time, possibly resulting in the loss of a lease due to the lack of commercially established production.

We generally deliver our oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. Due to the lack of available pipeline capacity in certain regions in which we operate, we have entered into firm transportation agreements for a portion of our production in order to secure guaranteed capacity on major pipelines. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

A portion of our oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.

Borrowings under our Revolving Facility are limited by our borrowing base, which is subject to periodic redetermination.

We are parties to a credit agreement with Morgan Stanley Energy Capital Inc. as administrative agent (the “Credit Agreement”), providing for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and term loans of $125 million, with an accordion feature for up to $50 million in additional term loans subject to certain conditions (the “Term Loans”). Our Revolving Facility had a borrowing base of $67 million as of the date of this report, which was fully drawn. Unless we are able to meet the conditions required to access the accordion feature of our Term Loans, as of the date of this report, we did not have any incremental borrowing capacity under our Credit Agreement.

The borrowing base under our Revolving Facility is redetermined at least semi-annually. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of the debt owed under our Revolving Facility to the extent our outstanding borrowings at such time exceeds the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of our Revolving Facility and an acceleration of the loans outstanding under our Credit Agreement. Failure to timely pay these debt obligations when due could cause us to lose our assets through mortgage foreclosure, which would materially and adversely affect our business, results of operations and financial condition.

At December 31, 2015, we had approximately $90.6 million of assets classified held for sale, certain of which were included in the borrowing base value under our Credit Agreement. Upon the sale of these assets, our lenders may elect to reduce the then effective borrowing base by an amount equal to the value attributed to those assets if the value of the remaining assets doesn’t meet the prescribed asset coverage thresholds. At December 31, 2015, 25% of our Eagle Ford assets represented approximately 24% of the borrowing base value so, if the valuation was unchanged at the time of the sale, the lender could elect to require repayment of that pro rata portion of the outstanding debt which equates to approximately $45 million. That being said, there are many variables that affect the lender’s determination of borrowing base value at any point in time and therefore it is difficult for management to estimate the borrowing base value at an undetermined point in the future so the amount that would be required to be repaid, if any, is uncertain.

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Our credit facilities have substantial restrictions and financial covenants that restrict our business and financing activities.

The operating and financial restrictions and covenants in our credit facilities restrict our ability to finance future operations or capital needs and to engage, expand or pursue our business activities. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial condition and events or circumstances beyond our control. If we violate any of the restrictions, covenants, ratios or tests in our credit agreements, our indebtedness may become immediately due and payable, the interest rates under our credit agreements may increase and the lenders’ commitment, if any, to make further loans to us may terminate. In the event that some or all of the amounts outstanding under our credit facilities are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts under our credit facilities, and our lenders could foreclose upon critical assets. As a result, we may be unable to complete any further development of our properties and it may affect our ability to continue as a going concern For a description of our credit facilities, please see Item 5.B. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Credit Facilities.”

Our level of indebtedness may increase, reducing our financial flexibility.

We intend to fund our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities and, if necessary, alternative debt or equity financings. Because at the date of this report, we did not have any incremental borrowing capacity under our Credit Agreement, our ability to make the necessary capital investment to maintain or expand our asset base and develop oil and natural gas reserves will be impaired if cash flow from operations is reduced and external sources of capital become limited or unavailable. If we obtain alternative debt or equity financing for these or other purposes, the related risks that we now face could intensify. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:

· a portion of our cash flow from operations would be used to pay interest on borrowings;

· the covenants contained in our credit facilities limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;

· a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

· a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and

· a debt that we incur under our Revolving Facility will be at variable rates, which could make us vulnerable to an increase in interest rates.

Increased costs of capital could adversely affect our business.

Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.

Competition in the oil and natural gas industry is intense and many of our competitors have resources that are greater than ours.

The oil and natural gas industry is highly competitive. Public integrated and independent oil and natural gas companies, private equity backed and private operators are all active bidders for desirable oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.

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The loss of any of our key personnel could adversely affect our business, financial condition, the results of operations and future growth.

We are reliant on a number of key members of our executive management team. Loss of such personnel may have an adverse effect on our performance. We currently have an employment agreement with our chief executive officer and managing director, however we have not entered into or finalized agreements with any of the other members of our executive management team. Certain areas in which we operate are highly competitive regions and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to sustain current operations or manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow or operate our business profitably.

Our ability to manage growth will have an impact on our business, financial condition and results of operations.

Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

· our ability to obtain leases or options on properties;

· our ability to identify and acquire new exploratory prospects;

· our ability to develop existing prospects;

· our ability to continue to retain and attract skilled personnel;

· our ability to maintain or enter into new relationships with project partners and independent contractors;

· the results of our drilling programs;

· commodity prices; and

· our access to capital.

We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. Our inability to achieve or manage growth may materially and adversely affect our business, results of operations and financial condition.

We may incur losses as a result of title deficiencies.

We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if insufficient funds are available to meet the commitments.

The existence of title differences with respect to our oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not necessarily obtained drilling title opinions on all of our oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

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Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially dangerous working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, emission, waste management or cleanup requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise materially and adversely affect our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance. Federal and state regulators are increasingly targeting greenhouse gas emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.

In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to foreign ownership, access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing.

Hydraulic fracturing, which is the process used for releasing hydrocarbons from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate oil or natural gas production. Currently, hydraulic fracturing is primarily regulated in the United States at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the United States, including states in which we operate, have begun adopting more restrictive regulations, including measures such as:

· required disclosure of chemicals used during the hydraulic fracturing process;

· restrictions on wastewater disposal activities;

· required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;

· new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;

· financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and

· local moratoria or even bans on oil and natural gas development utilizing hydraulic fracturing in some communities.

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At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the United States Congress (“Congress”) has considered and likely will continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. Congressional action will be informed by a study commenced in 2011 by the EPA on the impacts of hydraulic fracturing on drinking water resources, with final results anticipated in 2016. The EPA has also announced that it will develop pre-treatment standards for disposal of wastewater produced from shale gas operations through publicly owned treatment works. The regulations will be developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. On April 7, 2015, the EPA published a proposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process in the Federal Register. If adopted, the new pre-treatment rules will require shale gas operations to pre-treat wastewater before transferring it to publicly-owned treatment facilities. The public comment period for the proposed rule ended on July 17, 2015. If the EPA implements further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

Despite the existing regulatory exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the United States Department of the Interior has proposed comprehensive regulations governing the use of hydraulic fracturing on federally managed lands.

These efforts by Congress, federal regulators, states and local governments could result in additional costs, delay and operational uncertainty that could limit, preclude or add costs to use of hydraulic fracturing in our drilling operations.

Our ability to produce oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions.

Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas.

Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

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On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the United States, including companies in the energy industry, to annually report those emissions. New major sources or significant modifications of existing sources of traditional air pollutants are required to obtain permits and to use best available control technology to control those emissions pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. In addition, sources subject to best available control technology for traditional air pollutants are now also required to use best available control technology to control significant greenhouse gas emissions. While these regulations have not to date materially affected us, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

In addition, as discussed in more detail below, the EPA finalized its New Source Performance Standard (“NSPS”) rule regulating carbon dioxide from new, modified and reconstructed fossil fuel-fired power plants and the Clean Power Plan for existing fossil fuel-fired power plants. While these rules will more negatively impact coal-fired power plants, natural gas-fired power plants may also face liability under the rules and increased costs of operation.

In August 2015, the EPA released proposed regulations intended to reduce methane emissions from the oil and gas sector by 40 to 45 percent by 2025. These actions include a commitment from the EPA to issue new source performance standards for methane emissions from the oil and gas sector. Pursuant to this commitment, in September 2015, the EPA proposed emission standards for methane and VOC for sources in the oil and natural gas sector constructed or modified after September 1, 2015. The proposed rules expand the 2012 NSPS for VOC emissions from the oil and gas sector to include methane emissions. For sources not affected by the 2012 NSPS, the proposed rule imposes both VOC and methane standards. In particular, the proposal would require methane reductions from centrifugal and reciprocating compressors, pneumatic pumps, fugitive emissions from well sites and compressor stations and equipment leaks at natural gas processing plants. The proposal does not extend to existing sources and EPA has not indicated when it will propose existing source standards. The methane regulations, once finalized, could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, these new developments could result in increased costs of operation and exposure to liability.

In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. While comprehensive climate legislation will likely not be passed by either house of Congress in the near future, energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. Certain legislation introduced in Congress, if enacted into law, would make significant changes to U.S. tax laws, including, but not limited to, the elimination of certain key federal income tax incentives currently available to oil and natural gas exploration and production companies. These or any other similar changes in federal tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could materially and adversely affect our business, results of operations and financial condition.

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General economic conditions could adversely affect our business and future growth.

Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect 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. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, it could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.

Also, market conditions could have an impact on our oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for oil and natural gas, or reductions in the prices of oil and natural gas or both, which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.

Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we will use to price our oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.

Recent federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which requires the SEC and the Commodity Futures Trading Commission (“CFTC”) to promulgate rules and regulations implementing the new legislation. The CFTC issued regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are exempt from these limits. The position limits regulation was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has appealed the District Court’s decision and its Chairman has stated that the agency is working on developing a new proposed rulemaking to address position limits. The CFTC has finalized other regulations, including critical rulemakings on the “swap” and “swap dealer” definitions, swap dealer registration, swap data reporting and mandatory clearing, among others. The Dodd-Frank Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. The legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation and any new regulations could:

· significantly increase the cost of some derivative contracts (including through requirements to post collateral that could adversely affect our available liquidity);

· materially alter the terms of some derivative contracts;

· reduce the availability of some derivatives to protect against risks we encounter;

· reduce our ability to monetize or restructure our existing derivative contracts; and

· potentially increase our exposure to less creditworthy counterparties.

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If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our financial condition and results of operations.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

· recoverable reserves;

· future oil and natural gas prices and their appropriate differentials;

· development and operating costs; and

· potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

· diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

· the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

· difficulty associated with coordinating geographically separate organizations; and

· the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

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Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information, acquire cash or other assets through theft or fraud or render data or systems unusable, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, corruption of data or misappropriation of assets. There can be no assurance that the procedures and controls we use to monitor and mitigate these risks will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, assets, critical infrastructure, personnel or capabilities, essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

Risks Related to our Shares

The market price and trading volume of our shares may be volatile and may be affected by economic conditions beyond our control.

Our shares are listed on the ASX under the symbol “SEA.” The market price of our shares on the ASX may be highly volatile and subject to wide fluctuations. In addition, the trading volume of our shares may fluctuate and cause significant price variations to occur. If the market price of our shares declines significantly, you may be unable to resell your shares at or above the purchase price, if at all. We cannot assure you that the market price of our shares will not fluctuate or significantly decline in the future.

Some specific factors that could negatively affect the price of our shares or result in fluctuations in their price and trading volume include:

· actual or expected fluctuations in our operating results or liquidity;

· actual or expected changes in our growth rates or our competitors’ growth rates;

· changes in commodity prices for hydrocarbons we produce;

· changes in market valuations of similar companies;

· changes in our key personnel;

· potential acquisitions and divestitures;

· changes in financial estimates or recommendations by securities analysts;

· changes or proposed changes in laws and regulations affecting the oil and natural gas industry;

· sales of ordinary shares by us, our directors, executive officers or our shareholders in the future;

· conditions in the oil and natural gas industry in general; and

· conditions in the financial markets or changes in general economic conditions.

There is no established public market for our securities in the United States and we cannot assure you that our ordinary shares will be listed on any securities exchange or that an active trading market will ever develop for any of our securities in the United States.

There is currently no established public market in the United States for our ordinary shares. While our ordinary shares are listed for quotation on the OTC Pink marketplace operated by the OTC Markets Group, trading is limited, sporadic and volatile. There is no assurance that an active trading market in our ordinary shares will develop in the United States, or if such a market develops, that it will be sustained. As a result, an investor may find it more difficult to dispose of, or to obtain accurate quotations as to the market value of, our ordinary shares in the United States.

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As a foreign private issuer, we are permitted to file less information with the SEC than a company that is not a foreign private issuer or that files as a domestic issuer.

As a foreign private issuer, we are exempt from certain rules under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that impose disclosure requirements as well as procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as a company that files as a domestic issuer whose securities are registered under the Exchange Act, nor are we generally required to comply with the SEC’s Regulation FD, which restricts the selective disclosure of material non-public information.

If we fail to establish and maintain proper internal controls, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.

Beginning for the year ended December 31, 2015, the Company became subject to Section 404(a) of the Sarbanes-Oxley Act, which requires that our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Although Section 404(b) of the Sarbanes-Oxley Act requires our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting, we have opted to rely on the exemptions provided in the JOBS Act, and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

Our management has concluded that our internal controls over financial reporting were effective as of December 31, 2015. However, if we fail to maintain effective internal controls over financial reporting in the future, the presence of material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report. We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

In addition, if we are unable to conclude that we have effective internal controls over financial reporting, investors may lose confidence in our operating results, the price of our shares could decline and we may be subject to litigation or regulatory enforcement actions.

We could be classified as a “passive foreign investment company,” which could result in adverse U.S. federal income tax consequences to U.S. holders of our shares.

Based on our business results for the last fiscal year and composition of our assets, we do not believe that we were a passive foreign investment company (“PFIC”) for U.S. federal income tax purposes for the taxable year ended December 31, 2015. Similarly, based on our business projections and the anticipated composition of our assets for the current and future years, we do not expect that we will be a PFIC for the taxable year ending December 31, 2016. However, a separate determination is required after the close of each taxable year as to whether we are a PFIC. If our actual business results do not match our projections, it is possible that we may become a PFIC in the current or any future taxable year. A non-U.S. corporation will be considered a PFIC for a taxable year if either (i) at least 75% of its gross income is passive income or (ii) at least 50% of the value of its assets (based on an average of the quarterly values of the assets during the fiscal year) is attributable to assets that produce or are held for the production of passive income. Because the determination of our PFIC status is based on an annual determination that cannot be made until the close of a taxable year, and involves extensive factual investigation, including ascertaining the fair market value of all of our assets on a quarterly basis and the character of each item of income we earn, our U.S. counsel expresses no opinion with respect to our PFIC status. If we are a PFIC for any taxable year during which a U.S. holder (as defined in Item 10.E. “Additional Information—Taxation—U.S. Federal Income Tax Considerations”) holds an ordinary share, certain adverse U.S. federal income tax consequences could apply to such U.S. holder. See Item 10.E. “Additional Information—Taxation—U.S. Federal Income Tax Considerations—Passive Foreign Investment Company.”

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We have never declared or paid dividends on our ordinary shares and we do not anticipate paying dividends in the foreseeable future.

We have never declared or paid cash dividends on our ordinary shares. For the foreseeable future, we currently intend to retain all available funds and any future earnings to support our operations and to finance the growth and development of our business. Any future determination to declare cash dividends will be made at the discretion of our Board of Directors, subject to compliance with applicable laws and covenants under current or future credit facilities, which may restrict or limit our ability to pay dividends, and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our Board of Directors may deem relevant. We do not anticipate paying any cash dividends on our ordinary shares in the foreseeable future. As a result, a return on your investment will only occur if our ordinary share price appreciates.

Australian takeover laws may discourage takeover offers being made for us or may discourage the acquisition of a significant position in our ordinary shares.

We are incorporated in Australia and are subject to the takeover laws of Australia. Among other things, we are subject to the Corporations Act 2001 (“Corporations Act”). Subject to a range of exceptions, the Corporations Act prohibits the acquisition of a direct or indirect interest in our issued voting shares if the acquisition of that interest will lead to a person’s voting power in us increasing to more than 20%, or increasing from a starting point that is above 20%, though below 90%. Australian takeover laws may discourage takeover offers being made for us or may discourage the acquisition of a significant position in our ordinary shares. This may have the ancillary effect of entrenching our Board of Directors and may deprive or limit our shareholders’ opportunity to sell their ordinary shares and may further restrict the ability of our shareholders to obtain a premium from such transactions.

Our Constitution and Australian laws and regulations applicable to us may adversely affect our ability to take actions that could be beneficial to our shareholders.

As an Australian company, we are subject to different corporate requirements than a corporation organized under the laws of the United States. Our Constitution, as well as the Australian Corporations Act, set forth various rights and obligations that are unique to us as an Australian company. These requirements may operate differently than those of many U.S. companies.

Item 5. Operating and Financial Review and Prospects

A. Operating Results

You should read the following discussion and analysis in conjunction with Item 3.A. “Key Information—Selected Financial Data” and our consolidated financial statements and the notes to those consolidated financial statements appearing elsewhere in this annual report.

In addition to historical information, the following discussion contains forward-looking statements that reflect our plans, estimates, intentions, expectations and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. See Item 3.D. “Key Information—Risk Factors” for a discussion of factors that could cause or contribute to such differences.

Overview

We are an onshore oil and natural gas company focused on the exploration, development and production of large, repeatable resource plays in North America. Our oil and natural gas properties are located in premier U.S. oil and natural gas basins, and through the year ended December 31, 2015, our operational activities are focused in the Eagle Ford and Mississippian/Woodford.

We intend to utilize our U.S.-based management and technical team to appraise, develop, produce and grow our portfolio of assets. Our strategy is to develop assets where we are the operator and have high working interests, which positions us to control the pace of our development and the allocation of our capital resources. As of December 31, 2015, we operated approximately 85% of our developed acreage with an average working interest of approximately 82% with respect to such operated developed acreage.

Our properties and operations have changed significantly over the past several years, with the divestiture of our interest in properties located in the South Antelope field of the Williston Basin, North Dakota and our dispositions of Denver-Julesburg assets and the remaining Bakken assets in September 2012 and July 2014, respectively, and the acquisition of Texon in March 2013, through which we acquired the majority of our Eagle Ford assets. In addition, we continued to increase our acreage position in 2015 through the acquisition of New Standard Energy’s Eagle Ford acreage in August 2015 and other lease acquisitions. See Item 4.A. “Information on Sundance - History and Development—Acquisitions” and “—Divestitures.”

Over the past few years, we have shifted our focus from being a primarily low working-interest, non-operating participant to a high working-interest operator. By divesting our low working-interest prospects and realizing significant returns on investments, we have been able to fund a substantial portion of our investments in higher-interest wells while maintaining what we view as a conservative balance sheet.

Ryder Scott estimated our proved reserves to be approximately 25.5 MMBoe as of December 31, 2015, of which approximately 69% are oil, approximately 17% are natural gas and approximately 14% NGLs, with a PV-10 of approximately $182.2 million.

How We Conduct Our Business and Evaluate Our Operations

We employ our capital resources for exploration, acquisitions and development in what we believe to be the most attractive opportunities available to us as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential through exploration, development, production optimization or cost reduction. We intend to continue to focus our efforts on the acquisition of operated properties to the extent we believe they meet our return objectives.

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

· production volumes;

· realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

· lease operating and production expenses;

· general and administrative expenses; and

· Adjusted EBITDAX.

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Production Volumes

Production volumes directly impact our results of operations. Based on the expected timing of our drilling schedule and decline curves, we determine our oil and natural gas production budgets and forecasts. We assess our actual production performance by comparing oil and natural gas production at a prospect level to budgets, forecasts and prior periods. In addition, we compare our initial production rates compared to our peers in each of our operated prospects. For more information about our production volumes, see Item 4.B. “Information on Sundance—Business Overview—Operating Data—Production and Pricing.”

Realized Prices on the Sale of Oil and Natural Gas

Factors Affecting the Sales Price of Oil and Natural Gas. We expect to market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as geopolitical events, economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Oil. The New York Mercantile Exchange—West Texas Intermediate (NYMEX-WTI) futures price is a widely used benchmark in the pricing of domestic crude oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that oil differs in its molecular makeup, which plays an important part in refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (i) the American Petroleum Institute (“API”) gravity of the oil; and (ii) the percentage of sulfur content by weight of the oil. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, depending on supply and demand fundamentals, normally sell at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur content oil (“sour” oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the proximity to the major consuming and refining markets. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

Oil prices have historically been extremely volatile, and we expect this volatility and overall price depression to continue into 2016. For example, the NYMEX-WTI oil price ranged from a high of $61.36 per Bbl to a low of $26.19 per Bbl during 2015 and through the first quarter of 2016. Our realized price per Bbl varies by basin and is based upon transportation costs, mainly trucking costs and pipeline tariffs, and regional basis differentials.

Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (i) the Btu content of natural gas, which measures its heating value; and (ii) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas is processed in third-party natural gas plants, and residue natural gas as well as NGLs are recovered and sold. Dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the proximity to the major consuming markets. The processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds also affects the differential. Generally, these index prices have historically been at a discount to NYMEX- Henry Hub natural gas prices.

Natural gas prices have historically been extremely volatile, and we expect this gas prices to remain depressed into 2016. The NYMEX-Henry Hub natural gas price ranged from a high of $3.32 per MMBtu to a low of $1.49 per MMBtu during 2015 and through the first quarter of 2016. Our realized gas price per MMBtu varies by basin based upon transportation costs, mainly pipeline tariffs, as well as liquids premiums and regional basis differentials.

Commodity Derivative Contracts. We have adopted a commodity derivative policy designed to minimize volatility in our cash flows from changes in commodity prices. Our current policy is to hedge at least 50% of our proved developed reserves through 2019 and for a rolling 36 month period thereafter, as required by our Credit Agreement. For more information on our commodity derivative policy, see Item 11 “Quantitative and Qualitative Disclosure About Risk.”

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Lease Operating Expenses We strive to increase our production levels to maximize our revenue. We evaluate operating costs to determine reserves, rates of return, and current and long-term profitability of our wells. We expect expenses for utilities, direct labor, water injection and disposal, and materials and supplies to comprise the most significant portion of our oil and natural gas production expenses. Oil and natural gas production expenses do not include general and administrative costs or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities may result in increased oil and natural gas production expenses during periods the repairs are performed.

A majority of our operating cost components are variable and may increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production. Over the life of hydrocarbon fields, the amount of water produced may increase and, as pressure declines in natural gas wells that also produce water, more power will be needed for artificial lift systems that help to remove water produced from the wells. Thus, production of a given volume of hydrocarbons may become more expensive each year as the cumulative oil and natural gas produced from a field increases until additional production becomes uneconomic. Our lease operating and production expense are both included in lease operating expenses.

Production and Ad Valorem Taxes. Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes. The state currently imposes a production tax equal to 4.6% of the market value of oil sold, and a regulatory fee of 0.625% per barrel of oil sold. The State of Texas also imposes a production tax equal to 7.5% of the market value of the natural gas sold, and a regulatory fee of 0.0667% per Mcf of gas sold. In addition to the state taxes, McMullen, Dimmit and Atascosa Counties, Texas assesses an annual ad valorem tax which currently is approximately 1.58%, 1.87%, and 1.62% (respectively) of the gross annual oil and gas sales value.

Oklahoma currently has a production tax rate of 7.0% of the market value of the oil and gas sold. However, we have qualified for a horizontal well incentive tax rate of 1.0% which is imposed during the earlier of the first 48 months of sales or until the well has achieved payout (available for wells spud prior to July 1, 2015). There is an additional excise tax of 0.095% on the value of oil and gas sold. Oklahoma ad valorem taxes are imposed on personal property, specifically well equipment, at a rate of approximately 12.0% of the value of the equipment.

Generally, production taxes include taxes calculated on production volumes and sales values. Lease operating expenses including taxes which are calculated on asset values.

General and Administrative Expenses

General and administrative expenses are comprised of employee benefits expense (including salaries and wages) and administrative expenses. Employee benefits expense includes salaries, wages and related benefits for our corporate personnel. Stock compensation, including stock options and restricted share units, are expensed in the statement of comprehensive income over their vesting period. The total amount expensed over the vesting period is determined by reference to the fair value of the options and restricted share units at the grant date. Administrative expenses include overhead costs, such as maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services, and legal compliance.

We capitalize overhead costs, including salaries, wages, benefits and consulting fees, directly attributable to the exploration, acquisition and development of oil and gas properties.

Adjusted EBITDAX

Adjusted EBITDAX is a supplemental, non-IFRS financial measure and is defined as our earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain/(loss) on sale of non-current assets, exploration expense, share-based compensation and income and gains and losses on commodity hedging, net of settlements of commodity hedging. We use this non-IFRS measure primarily to compare our results with other companies in the industry that make a similar disclosure. We believe that this measure may also be useful to investors for the same purpose. Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining our operating performance that is calculated in accordance with IFRS. In addition, because Adjusted EBITDAX is not an IFRS measure, it may not necessarily be comparable to similarly titled measures employed by other companies. See Item 3.A. “Key Information—Selected Financial Data— Adjusted EBITDAX” for a reconciliation between Adjusted EBITDAX and net income before income tax expense.

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Critical Accounting Policies and Estimates

The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. Significant estimates include volumes of proved and probably oil, natural gas and NGL reserves, which are used in calculating depreciation, depletion and amortization of development and production assets’ costs, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying restoration provisions. Oil, natural gas and NGL reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title, drilling requirements and royalty obligations. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil, natural gas and NGL reserves, commodity prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in our estimates. Other significant estimates are involved in determining impairments of exploration and evaluation expenditures, fair values of derivative assets and liabilities, stock-based compensation expense, collectability of receivables, and in evaluating disputed claims, interpreting contractual arrangements and contingencies. Estimates are based on current assumptions that may be materially affected by the results of subsequent drilling and completion, testing and production as well as subsequent changes in oil, natural gas and NGL prices, counterparty creditworthiness, interest rates and the market value and volatility of the Company’s common shares. Actual results may vary materially from our estimates. We have outlined below policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management.

In addition, we note that our significant accounting policies are detailed in Note 1 to our consolidated financial statements for the fiscal year ended December 31, 2015.

Development and Production Assets and Plant and Equipment

Development and production assets, and property and equipment are carried at cost less, where applicable, any accumulated depreciation, amortization and impairment losses. The costs of assets constructed within Sundance includes the cost of materials, direct labor, borrowing costs and an appropriate proportion of fixed and variable overheads directly attributable to the acquisition or development of oil and gas properties and facilities necessary for the extraction of resources.

The carrying amount of development and production assets and property and equipment are reviewed at each reporting date to ensure that they are not in excess of the recoverable amount from these assets. The recoverable amount of an asset is the greater of its fair value less costs to sell and its value-in-use. Development and production assets are assessed for impairment on a cash- generating unit basis. A cash-generating unit (“CGU”) is the smallest grouping of assets that generates independent cash inflows. Management has assessed its CGUs as being an individual basin, which is the lowest level for which cash inflows are largely independent of those of other assets. Impairment losses recognized in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit on a pro-rata basis.

Where an indicator of impairment exists, the recoverable amount of the CGU to which the assets belong is then estimated based on the present value of future discounted cash flows using management’s view of estimates reserve quantities as opposed to estimated reserve quantities prepared to conform to definitions contained in Rule 4-10(a) of Regulations S-X. For development and production assets, the expected future cash flow estimation is always based on a number of factors, variables and assumptions, the most important of which are estimates of reserves, future production profiles, commodity prices and costs. In most cases, the present value of future cash flows is most sensitive to estimates of future oil price and discount rates. A change in the modeled assumptions in isolation could materially change the recoverable amount. However, due to the interrelated nature of the assumptions, movements in any one variable can have an indirect impact on others and individual variables rarely change in isolation. Additionally, management can be expected to respond to some movements, to mitigate downsides and take advantage of upsides, as circumstances allow. Consequently, it is impracticable to estimate the indirect impact that a change in one assumption has on other variables and therefore, on the extent of impairments under different sets of assumptions in subsequent reporting periods. In the event that future circumstances vary from these assumptions, the recoverable amount of our development and production assets could change materially and result in impairment losses or the reversal of previous impairment losses.

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Due to the change in the oil pricing environment as of December 31, 2015 and 2014, management performed an impairment analysis for development and production assets, which resulted in impairment charges of $184.4 million and $71.2 million, respectively.

For our analysis at December 31, 2015, we estimated the price/Bbl to be $40 in 2016, $50 in 2017 and $60 for 2018 and $70/bbl in 2019 and thereafter. The discount rates applied to the future forecasted cash flows are based on a third party participant’s post-tax weighted average cost of capital, which was 9% and 10% for proved developed and proved undeveloped, respectively. We also applied further risk adjustments for risk associated with our proved undeveloped reserves of 20%. See Note 19 to the consolidated financial statements for additional information.

Subsequent costs are included in the asset’s carrying amount or recognized as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to us and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the consolidated statement of profit or loss and comprehensive income during the financial period in which are they are incurred.

Exploration and Evaluation Expenditure

Exploration and evaluation expenditures incurred are accumulated in respect of each identifiable area of interest. These costs are capitalized to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. Any such estimates and assumptions may change as new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, for example a dry hole, the relevant capitalized amount is written off in the consolidated statement of profit or loss and other comprehensive income in the period in which new information becomes available. The costs of assets constructed within Sundance includes the leasehold cost, geological and geophysical costs, and an appropriate proportion of fixed and variable overheads directly attributable to the exploration and acquisition of undeveloped oil and gas properties.

When approval of commercial development of a discovered oil or gas field occurs, the accumulated costs for the relevant area of interest are transferred to development and production assets. The costs of developed and producing assets are amortized over the life of the area according to the rate of depletion of the proved and probable developed reserves. The costs associated with the undeveloped acreage are not subject to depletion.

The carrying amounts of our exploration and evaluation assets are reviewed at each reporting date, in conjunction with the impairment review process referred to in Note 1(f) to our consolidated financial statements for the year ended December 31, 2015 to determine whether any of impairment indicators exists. Impairment indicators could include i) tenure over the license area has expired during the period or will expire in the near future, and is not expected to be renewed, ii) substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is not budgeted or planned, iii) exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of resources, and management has decided to discontinue activities in the specific area, or iv) sufficient data exist to indicate that although a development is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or from sale. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made and any resulting impairment loss is recognized in the income statement.

In assessing value-in-use, an asset’s estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the assets/CGUs. In addition, we consider market data related to recent transactions for similar assets.

Due to the change in the oil pricing environment as of December 31, 2015 management performed an impairment analysis for its exploration and evaluation expenditures, which resulted in an impairment charge of $137.2 million. We did not record any impairment expense related to our exploration and evaluation expenditures for the year ended December 31, 2014.

For our analysis at December 31, 2015, we estimated the price/Bbl to be $40 in 2016, $50 in 2017 and $60 for 2018 and

$70/bbl in 2019 and thereafter. The discount rates applied to the future forecasted cash flows were 15% and 20% for our probable and possible reserves, respectively. We also applied further risk adjustments for risk associated with our probable and possible reserves of 30% and 40%, respectively. See Note 19 to the consolidated financial statements for additional information.

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Derivative Financial Instruments

We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our board directors. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the statement of profit or loss and other comprehensive income. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. The effect on profit and equity as a result of changes in oil prices is included in “Quantitative and Qualitative Disclosures About Risk, Oil Prices Risk Sensitivity Analysis.”

Estimates of Reserve Quantities

The estimated quantities of hydrocarbon reserves reported by the consolidated entity are integral to the calculation of amortization (depletion), and depreciation expense and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessments of the technical feasibility and commercial viability of producing the reserves. For purposes of the calculation of amortization (depletion), and depreciation expense and the assessment of possible impairment of assets, other than pricing assumptions discussed in Note 19 to the Consolidated Financial Statements, management prepares reserve estimates that conform to the definitions contained in Rule 4-10(a) of Regulation S-X. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates, development plans and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period and as additional geological data is generated during the course of operations. These reserve estimates may differ from estimates prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting.

Income taxes

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not, including judgements and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices). For the year ended December 31, 2015, we did not recognize tax assets of $29.7 million (restated) as the recovery was not determined to be more likely than not. As a result, we expect our effective tax rate to be significantly lower than the statutory rate in 2016. Some or all of these deferred tax assets could be recognized in future periods against future taxable income.

Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared. Therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carryforwards and carrybacks. Adjustments related to differences between the estimates we use and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations. Revisions to our estimated effective tax rate could increase or decrease our reported income tax expense or benefit.

Because our Australian operations are not significant to the consolidated profit or loss, foreign income taxes are not significant to consolidated income tax expense. Our effective and statutory income tax rates could be impacted by the state income tax rates in which we operate, and the effective and statutory income tax rates are not significantly different as the amount of permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of temporary differences, primarily development and production assets and exploration and evaluation expenditures, is reflected in deferred income taxes. At December 31, 2015 and 2014, we had no unrecognized tax benefits that would impact our effective tax rate and we have not provided for interest or penalties related to uncertain tax positions. See Note 7 to the consolidated financial statements.

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Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Revenues and Sales Volume. The following table provides the components of our revenues for the years ended December 31, 2015 and 2014, as well as each period’s respective sales volumes:

	Year ended December 31,
	2015		2014		Change in $			Change as %
	(audited)		(audited)
Revenue (In $ ‘000s)
Oil sales	$	82,949	$	144,994	$	(62,045	)	(42.8	)
Natural gas sales	4,720		6,161		(1,441		)	(23.4	)
NGL sales	4,522		8,638		(4,116		)	(47.6	)
Product revenue	$	92,191	$	159,793	$	(67,602	)	(42.3	)

	Year ended December 31,		Change in
	2015	2014	Volume	Change as %
	(audited)	(audited)
Net sales volumes:
Oil (Bbls)	1,828,955	1,675,078	153,877	9.2
Natural gas (Mcf)	2,580,682	1,803,000	777,682	43.1
NGL (Bbls)	393,211	267,952	125,259	46.7
Oil equivalent (Boe)	2,652,280	2,243,529	408,750	18.2
Average daily production (Boe/d)	7,267	6,147	1,120	18.2

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Sales volume increased by 408,750 Boe (18.2%) to 2,652,280 Boe (7,267 Boe/d) for the year ended December 31, 2015 compared to 2,243,529 Boe (6,147 Boe/d) for the prior year due to the Company’s back-loaded 2014 development in which 20.9 of the 26.1 net Eagle Ford wells brought into production in 2014 had initial product in the second half of 2014. Production in 2015 included a full year of production for these wells which had less than a half year of production in 2014.

The Eagle Ford contributed 6,167 Boe/d (85%) of total sales volume during the year ended December 31, 2015 compared to 4,187 Boe/d (68%) during the prior year. Mississippian/Woodford contributed 1,100 Boe/d (15%) of total sales volume during the year ended December 31, 2014 compared to 1,433 Boe/d (23%) during the prior year. Our sales volume is oil-weighted, with oil representing 69% and 75% of total sales volume for the year ended December 31, 2015 and 2014, respectively.

Oil sales. Oil sales decreased by $62.0 million (42.8%) to $82.9 million for the year ended December 31, 2015 from $145.0 million for the prior year. The decrease in oil revenues was the result of the decrease in product pricing ($75.4 million), offset by increased oil production ($13.3 million). Oil production volumes increased 9.2% to 1,828,955 Bbls for the year ended December 31, 2015 compared to 1,675,078 Bbls for the prior year. The average price we realized on the sale of our oil decreased by 47.6% to $45.35 per Bbl for the year ended December 31, 2015 from $86.56 per Bbl for the prior year.

Natural gas sales. Natural gas sales decreased by $1.4 million (30.7%) to $4.7 million for the year ended December 31, 2015 from $6.2 million for the prior year. The decrease in natural gas revenues was primarily the result of worse product pricing ($4.6 million), offset by increased production volumes ($2.7 million). Natural gas production volumes increased 777,862 Mcf (43.1%) to 2,580,682 Mcf for the year ended December 31, 2015 compared to 1,803,000 Mcf for the prior year. The average price we realized on the sale of our natural gas decreased by 52% to $1.83 per Mcf for the year ended December 31, 2015 from $3.42 per Mcf for the prior year.

NGL sales. NGL sales decreased by $4.1 million (47.6%) to $4.5 million for the year ended December 31, 2015 from $8.6 million for the same period in prior year. The decrease in NGL revenues was primarily the result of worse product pricing ($8.2 million), offset by increased production volumes ($4.0 million). NGL production volumes increased 125,259 Bbls (46.7%) to 393,211 Bbls for the year ended December 31, 2015 compared to 267,952 Bbls for the prior year. The average price we realized on the sale of our natural gas liquids decreased by 60.5% to $11.50 per Bbl for the year ended December 31, 2015 from $32.24 per Bbl for the prior year.

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	Year ended December 31,
Selected per Boe metrics	2015			2014			Change			Percent
	(audited)			(audited)
Total oil and natural gas revenues, before derivative settlements	$	34.76		$	71.22		$	(36.46	)	(51.2	)
Lease operating expenses	(6.96		)	(6.03		)	0.93			15.4
Production taxes	(2.33		)	(3.10		)	(0.78		)	(25.1	)
Lease operating and production tax expenses	(9.29		)	(9.13		)	0.15			1.6
Depreciation and amortization	(35.66		)	(38.15		)	(2.49		)	(6.5	)
General and administrative expense	(6.48		)	(6.92		)	(0.45		)	(6.4	)

Lease operating expenses. Our lease operating expenses (LOE) increased by $4.9 million (36.4%) to $18.4 million for the year ended 31 December 2015 from $13.5 million in the prior year and increased $0.93 per Boe to $6.96 per Boe from $6.03 per Boe. During 2015, certain operational changes were implemented to begin treating natural gas from a significant number of our wells in Texas so that it meets pipeline specifications and can be sold. This gas had previously been flared. The increase in LOE per BOE is primarily due to costs associated with treating the gas.

Production taxes. Our production taxes decreased by $0.9 million (13.2%) to $6.0 million for the year ended 31 December 2015 from $7.0 million for the prior year but as a percent of revenue increased to 6.7% from 4.4%. The decrease in production taxes is due to the decrease in revenue. The increase in production taxes as a percentage of revenue is primarily the result of ad valorem tax as a percentage of revenue. Texas ad valorem amounts are assessed by the counties based on estimated value of developed reserves as at 1 January of each year. To the extent that realized revenue pricing varies from beginning of year product prices used to assess the ad valorem amounts, the effective ad valorem rate can fluctuate significantly.

Depreciation and amortization expense, including depletion. Our depreciation and amortisation expense increased by $9.0 million (10.5%) to $94.6 million for the year ended 31 December 2015 from $85.6 million for the prior year, but decreased $2.49 per Boe to $35.66 per Boe from $38.15 per Boe. The increase reflects our increase in production, offset by a lower depletable asset base due to prior-year and mid-year impairments.

General and administrative expenses. General and administrative expenses are comprised of employee benefits expense, including salaries and wages, and administrative expenses. Employee benefits expense increased by $4.0 million (80%) to $8.9 million for the year ended December 31, 2015 from $5.0 million for the year ended December 31, 2014. This increase is primarily the result of higher stock-based compensation expense (non-cash) for restricted stock and options issued to directors, management and employees of $2.2 million. In addition, the amount of overhead costs capitalized decreased $7.0 million during 2015 due to the decrease in drilling activity.

Administrative expense decreased by $2.3 million (22%) to $8.2 million for the year ended December 31, 2015 from $10.5 million for the year ended December 31, 2014. This decrease was primarily due to a decrease in general legal and professional fees.

Impairment expense. We recorded impairment expense of $321.9 million for the year ended December 31, 2015 on the Company’s oil and gas assets that are located in the Mississippian/Williston and the Eagle Ford as the recoverable amount was less than the carrying value primarily as a result of lower commodity pricing. See Note 19 of the Notes to the Consolidated Financial Statements for further discussion.

Exploration expense. The Company incurred exploration expense of $7.9 million for the year ended 31 December 2015 on two unsuccessful exploratory wells. The Company incurred exploratory expense of $10.9 million in 2014 related to three unsuccessful exploratory wells.

Finance costs, net of interest income and amounts capitalized. Finance costs, net of amounts capitalised to exploration and development, increased by $8.7 million to $9.4 million for the year ended 31 December 2015 as compared to $0.7 million in the prior year. The increase primarily relates to additional interest incurred on a larger average outstanding debt balance and lower capitalised interest as a result of less drilling and completion activity throughout 2015.

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Gain/(loss) on commodity hedging. The net gain (loss) on derivative financial instruments changed by $4.3 million to a $15.3 million gain for the year ended December 31, 2015 as compared to the prior year. The gain on commodity hedging consisted of $2.9 million of unrealized gains on commodity derivative contracts and $12.4 million of realized gains on commodity derivative contracts.

The following is a summary of the Company’s open oil and natural gas derivative contracts at December 31, 2015:

	Oil Contracts (Weighted Average)					Natural Gas Contracts (Weighted Average)
Contract	Units (Bbl)	Floor		Ceiling		Units (MMbtu)	Floor		Ceiling
2016	1,037,063	$	50.63	$	76.14	2,040,000	$	2.54	$	3.58
2017	624,000	$	47.53	$	79.92	1,320,000	$	2.85	$	3.91
2018	444,000	$	51.47	$	81.53	930,000	$	3.00	$	4.32
2019	168,000	$	52.51	$	87.71	360,000	$	3.27	$	4.65
Total	2,273,063	$	50.08	$	80.49	4,650,000	$	2.78	$	4.01

Income taxes. The components of our provision for income taxes are as follows:

	Year ended December 31,
(in US$000s)	2015			2014
	(audited)			(audited)
	(Restated)
Current tax (expense)/benefit	$	6,191		$	(17	)
Deferred tax benefit	100,947			858
Total income tax benefit	$	107,138		$	841
Combined federal and state effective tax rate	28.9		%	(5.8		)%

Our combined federal and state effective tax rates differ from our statutory tax rate of 30% primarily due to an increase in unrecognised tax losses, offset by US federal and state tax rates. We expect that our effective tax rate will continue to be less than the statutory rate in 2016. See Note 7 in the Notes to the Consolidated Financial Statements of this report for further information regarding our income taxes.

Loss attributable to owners of Sundance (or net loss). Loss attributable to our owners (or net income after tax) was a net loss of $263.8 million (restated) for the year ended December 31, 2015 a decrease from net income of $15.3 million for the year ended December 31, 2014, for the reasons discussed above.

Adjusted EBITDAX. For the year ended December 31, 2015, adjusted EBITDAX was $64.8 million, or 70% of revenue, compared to $126.4 million, or 79% of revenue, from the prior year.The overall decrease in Adjusted EBITDAX was primarily driven by the decline in commodity prices.

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

Revenues and Sales Volume. The following table provides the components of our revenues for the years ended December 31, 2014 and 2013, as well as each period’s respective sales volumes:

	Year ended December 31,
	2014		2013		Change in $		Change as %
	(audited)		(audited)
Revenue (In $ ‘000s)
Oil sales	$	144,994	$	79,365	$	65,629	82.7
Natural gas sales	6,161		2,774		3,387		122.1
NGL sales	8,638		3,206		5,432		169.5
Product revenue	$	159,793	$	85,345	$	74,448	87.2

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	Year ended December 31,
	2014	2013	Change in Volume	Change as %
	(audited)	(audited)
Net sales volumes:
Oil (Bbls)	1,675,078	827,432	847,646	102.4
Natural gas (Mcf)	1,803,000	934,200	868,800	93.0
NGL (Bbls)	267,952	95,821	172,131	179.6
Oil equivalent (Boe)	2,243,529	1,078,953	1,164,576	107.9
Average daily production (Boe/d)	6,147	2,956	3,191	107.9

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Sales volume increased by 1,164,576 Boe (107.9%) to 2,243,529 Boe (6,147 Boe/d) for the year ended December 31, 2014 compared to 1,078,953 Boe (2,956 Boe/d) for the prior year due to successfully bringing online 88 gross (50.1 net) producing wells primarily in the Eagle Ford and Mississippian/Woodford Formations.

The Eagle Ford contributed 4,187 Boe/d (68.1%) of total sales volume during the year ended December 31, 2014 compared to 1,371 Boe/d (46.4%) during 2013. Mississippian/Woodford contributed 1,433 Boe/d (23.2%) of total sales volume during the year ended December 31, 2014 compared to 503 Boe/d (17.0%) during 2013. Our sales volume is oil-weighted, with oil representing 75% and 77% of total sales volume for the year ended December 31, 2014 and 2013, respectively.

Oil sales. Oil sales increased by $65.6 million (82.7%) to $145.0 million for the year ended December 31, 2014 from $79.4 million for 2013. The increase in oil revenues was the result of increased oil production volumes ($81.3 million) offset by a decrease in product pricing ($15.7 million). Oil production volumes increased 102.4% to 1,675,078 Bbls for the year ended December 31, 2014 compared to 827,432 Bbls for 2013. The average price we realized on the sale of our oil decreased by 9.8% to $86.56 per Bbl for the year ended December 31, 2014 from $95.92 per Bbl for the prior year.

Natural gas sales. Natural gas sales increased by $3.4 million (122.1%) to $6.2 million for the year ended December 31, 2014 from $2.8 million for 2013. The increase in natural gas revenues was primarily the result of increased production volumes ($2.6 million) and improved product pricing ($0.8 million). Natural gas production volumes increased 868,800 Mcf (93.0%) to 1,803,000 Mcf for the year ended December 31, 2014 compared to 934,200 Mcf for 2013. The average price we realized on the sale of our natural gas increased by 15.1% to $3.42 per Mcf for the year ended December 31, 2014 from $2.97 per Mcf for 2013.

NGL sales. NGL sales increased by $5.4 million (169.5%) to $8.6 million for the year ended December 31, 2014 from $3.2 million for the same period in 2013. The increase in NGL revenues was primarily the result of increased production volumes in the Eagle Ford and the Mississippian/Williston. NGL production volumes increased 172,131 Bbls (179.6%) to 267,952 Bbls for the year ended December 31, 2014 compared to 95,821 Bbls for 2013. The average price we realized on the sale of our natural gas liquids decreased by 3.6% to $32.24 per Bbl for the year ended December 31, 2014 from $33.45 per Bbl for 2013.

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	Year ended December 31,
Selected per Boe metrics	2014			2013			Change			Percent
	(audited)			(audited)
Total oil and natural gas revenues, before derivative settlements	$	71.22		$	79.10		$	(7.88	)	(10.0	)
Lease operating expenses	(6.03		)	(11.23		)	(5.21		)	(46.4	)
Production taxes	(3.10		)	(5.80		)	(2.70		)	(46.5	)
Lease operating and production tax expenses	(9.13		)	(17.03		)	(7.90		)	(46.4	)
Depreciation and amortization	(38.15		)	(33.57		)	4.58			13.6
General and administrative expense	(6.92		)	(14.18		)	(7.26		)	(51.2	)
Total profit margin	17.02			14.32			2.70			18.9

Lease operating expenses. Our lease operating expenses (LOE) increased by $1.4 million (11.6%) to $13.5 million for the year ended December 31, 2014 from $12.1 million for the same period in the prior year but decreased $5.21 per Boe to $6.03 per Boe from $11.23 per Boe. The decrease in LOE per Boe is primarily due to economies of scale and the implementation of several cost saving initiatives in our field operations such as replacing contract lease operators with Company employees and reducing total field head count per well.

Production taxes. Our production taxes increased by $0.7 million (11.2%) to $7.0 million for the year ended December 31, 2014 from $6.3 million for 2013 but as a percent of revenue decreased 290 basis points to 4.4% from 7.3%. The decrease in production taxes as a percent of revenue is the result of the sale of our North Dakota and Colorado assets, which are higher production tax rate jurisdictions, and increasing our investment in Texas and Oklahoma, which are lower production tax rate jurisdictions, as well as an adjustment for lower than anticipated ad valorem taxes.

Depreciation and amortization expense, including depletion. Our depreciation and amortization expense increased by $49.4 million (136.3%) to $85.6 million for the year ended December 31, 2014 from $36.2 million for 2013 and increased $4.58 per Boe to $38.15 per Boe from $33.57 per Boe. The increase reflects our increase in production (107.9%), an increase in our asset base subject to amortization as a result of our acquisition and development activity, and increased completion costs caused by high-demand for completion services and a shortage of trucks able to transport frac sand and resultant higher trucking rates.

General and administrative expenses. General and administrative expenses are comprised of employee benefits expense, including salaries and wages, and administrative expenses. Employee benefits expense decreased by $1.1 million (19.0%) to $5.0 million for the year ended December 31, 2014 from $6.1 million for the year ended December 31, 2013. This decrease is primarily a result of the capitalization of $4.5 million, an increase of amounts capitalized in 2013 by $1.6 million, in overhead costs, including salaries and wages, directly attributable to the exploration, acquisition and development of oil and gas properties. Included in the employee benefits expense for the fiscal year ended December 31, 2014 is stock-based compensation expense of $1.9 million for options issued to officers, management and employees, an increase of $0.3 million (20.4%) compared to $1.6 million for the twelve-month period ended December 31, 2013.

Administrative expense increased by $1.3 million (15.2%) to $10.5 million for the year ended December 31, 2014 from $9.2 million for the year ended December 31, 2013. This increase was primarily due to an increase in general legal and professional fees.

General and administrative expenses per Boe decreased by 51.2% to $6.92 for the year ended December 31, 2014 as compared to $14.18 per Boe for 2013. The decrease in general and administrative expenses per Boe is driven by increased production levels diluting fixed general and administrative costs.

Impairment expense. We recorded impairment expense of $71.2 million for the year ended December 31, 2014 on the Company’s development and production assets that are located in the Mississippian/Williston and the Eagle Ford as the recoverable amount was less than the carrying value primarily as a result of lower commodity pricing. No impairment was necessary on the Company’s exploration and evaluation assets. See Note 17 of the Notes to the Consolidated Financial Statements for further discussion. No impairment expense was recognized in 2013.

Exploration expense. We incurred exploration expense of $10.9 million for the year ended December 31, 2014 on three gross (and net) unsuccessful exploratory wells in the Mississippian/Williston. The Company did not drill any unsuccessful exploratory wells in 2013.

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Finance costs, net of interest income and amounts capitalized. Finance costs, net of amounts capitalized to exploration and development, increased by $0.7 million to $0.5 million for the year ended December 31, 2014 as compared to net interest income of $0.2 million in 2013. The increase primarily relates to an increase in amortization of deferred financing fees and additional interest incurred on undrawn funds.

Gain/(loss) on commodity hedging. The net gain (loss) on derivative financial instruments changed by $11.6 million to an $11.0 million gain for the year ended December 31, 2014 as compared to 2013. The gain on commodity hedging consisted of $9.7 million of unrealized gains on commodity derivative contracts and $1.3 million of realized gains on commodity derivative contracts.

Income taxes. The components of our provision for income taxes are as follows:

	Year ended December 31,
(in US$000s)	2014			2013
	(audited)			(audited)
Current tax (expense)/benefit	$	(17	)	$	21,398
Deferred tax benefit/(expense)	858			(26,965		)
Total income tax benefit/(expense)	$	841		$	(5,567	)
Combined federal and state effective tax rate	(5.8		)%	25.9		%

Our combined federal and state effective tax rates differ from our statutory tax rate of 30% primarily due to U.S. federal and state tax rates, non-deductible expenses and the recognition of previously unrecognized tax losses. See Note 7 in the Notes to the Consolidated Financial Statements of this report for further information regarding our income taxes.

Profit attributable to owners of Sundance (or net income). Profit attributable to our owners (or net income after tax) decreased slightly by $0.6 million (3.9%) to net income of $15.3 million for the year ended December 31, 2014 from net income of $15.9 million for the year ended December 31, 2013, for the reason discussed above.

Adjusted EBITDAX. Adjusted EBITDAX increased by $73.8 million (140.3%) to $126.4 million for the year ended December 31, 2014 from $52.6 million for the year ended December 31, 2013. The overall increase in Adjusted EBITDAX was primarily driven by our production and revenue growth, while decreasing our per Boe amounts for LOE and production taxes.

B. Liquidity and Capital Resources

Our primary sources of liquidity to date have been proceeds from strategic dispositions of low-interest non-operated oil and natural gas properties, private placements of ordinary shares, borrowings under our credit facilities and cash flows from operations. Our primary use of capital has been for the acquisition and development of oil and natural gas properties. Our future ability to grow our reserves and production will be highly dependent on the capital resources available to us.

In May 2015, we refinanced our previous Credit Facilities with Wells Fargo to new Credit Facilities with Morgan Stanley, increasing its total borrowing capacity from an aggregate of $135 million to $250 million; comprised of a $125 million term loan, a reserve based revolver of up to $75 million and a $50 million accordion feature. Throughout 2015, the Company increased its borrowings to $192 million ($125 million term loan and $67 million outstanding on the reserve based revolver). On December 30, 2015, the reserve based revolver borrowing capacity was reduced from $75 million to $67 million. At year-end, the Company was fully drawn on its term loan and reserve based revolver. The $50 million accordion was available to the Company at year end, subject to certain restrictions, such as maintaining adequate proved reserve value to total debt ratio. At December 31, 2015, we were in compliance with all of our covenants and are forecasting to remain compliant for the remainder of 2016.

The Revolving Facility matures on May 14, 2020 and the Term Loans mature on November 14, 2020.

In late 2015, management committed to a plan to sell approximately 25% non-operated working interest in our Eagle Ford assets (representing $85.4 million of the assets held for sale balance as of December 31, 2015). Certain of the Eagle Ford assets were included in the borrowing base value under the Company’s Credit Agreement. Upon the sale of these assets, the lender may elect to reduce the then effective borrowing base by an amount equal to the value attributed to those assets if the value of the remaining assets doesn’t meet the prescribed asset coverage thresholds. At December 31, 2015, 25% of our Eagle Ford assets represented approximately 24% of the borrowing base value so, if the valuation was unchanged at the time of the sale, the lender could elect to require repayment of that pro rata portion of the outstanding debt which equates to approximately $45 million. That being said, there many variables that affect the lender’s determination of borrowing base value at any point in time and therefore it is difficult for management to estimate the borrowing base value at an undetermined point in the future so the amount that would be required to be repaid, if any, is uncertain. Accordingly, no portion of the outstanding debt has been classified as current as of December 31, 2015.

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Our 2016 capital budget is based on our operating cash flows, which we intend to use toward the development of our oil and natural gas projects, with no planned expenditures toward exploration and evaluation. We believe that our internally generated operating cash flows will be sufficient to fund our operations and planned capital expenditures for at least the next 12 months. We may also use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.

The amount, timing and allocation of these and other future expenditures is largely discretionary. As a result, the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities, timing of projects and market conditions. We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. However, should commodity prices decline for an extended period of time or the capital/credit markets become constrained, the borrowing capacity under our credit agreements could be adversely affected. In the event of a reduction in the borrowing base under our credit agreements, we may be required to prepay some or all of our indebtedness, which would adversely affect our capital expenditure program.

Cash Flows

Our cash flows for the years ended December 31, 2015, 2014 and 2013 are as follows:

	Year ended December 31,
(In $ ‘000s)	2015			2014			2013
	(audited)			(audited)			(audited)
Financial Measures:
Net cash provided by operating activities	$	64,469		$	128,087		$	62,646
Net cash (used in) provided by investing activities	(180,771		)	(323,235		)	(164,355		)
Net cash provided by financing activities	50,403			167,595			44,455
Cash and cash equivalents	3,468			69,217			96,871
Payments for development expenditure	(144,316		)	(361,950		)	(154,700		)
Payments for exploration expenditure	(20,339		)	(39,616		)	(20,006		)
Acquisitions, net of acquired cash	(15,023		)	(35,606		)	(27,273		)
Proceeds from the sale of non-current assets	41			115,284			37,848

Cash flows provided by operating activities

Net cash provided by operating activities for the year ended December 31, 2015 decreased 50% to $64.5 million compared to the prior year. This decrease was primarily due to receipts from sales decreasing $71.0 million, or 42%, to $99.4 million primarily due to the decrease in commodity prices. This was partially offset by an increase in payments to suppliers and employees of $19.7 million.

Net cash provided by operating activities for the year ended December 31, 2014 increased 104.5% to $128.1 million compared to $62.6 million provided by operating activities for the year ended December 31, 2013. This increase was primarily due to receipts from sales increasing $85.7 million, or 101.2%, to $170.4 million, while keeping payments to suppliers and employees relatively stable with an increase of $8.2 million, or 37.7%, to $30 million.

Cash flows provided by (used in) investing activities

Net cash used in investing activities for the year ended December 31, 2015 decreased significantly to $180.8 million (including $66 million of payments related to 2014 development) as compared to $323.2 million in prior year (net of $115.3 million cash source from sale of non-current assets). This decrease is due to the Company’s down-cycle development plan to drill and complete within operating cash flow. Due to the continued depressed crude oil prices, the Company expects to maintain its down- cycle development program through much of 2016.

Net cash used in investing activities for the year ended December 31, 2014 increased $158.9 million, or 96.7%, to $323.2 million. This increase is due to successful implementation of the Company’s strategy to develop and grow the reserves from our high working interest, repeatable resource plays, primarily in the Eagle Ford. Due to funding available to the Company through asset sales, capital raises and credit facilities, the Company was able to accelerate a portion of its 2015 drilling program into 2014. However, due to the reduction in crude oil prices in the fourth quarter of 2014 that continued into 2015, we scaled back our drilling program to concentrate on our limited drilling obligations to hold Eagle Ford acreage during 2015.

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Cash flows provided by (used in) financing activities

Net cash provided by financing activities for the year ended December 31, 2015 decreased to $50.4 million. This decrease is a result of the lower net draws on the Company’s credit facilities ($62.0 million in 2015 compared to $100.0 million in prior year) and no equity raises in 2015 (compared to a net of $68.7 million in prior year).

Net cash provided by financing activities for the year ended December 31, 2014 increased $123.1 million, or 277%, to $167.6 million. This increase is a result of the increased availability and draws under the Company’s credit facilities and proceeds received in a private placement of shares. In February 2014, the Company completed a private placement in which we sold 84.2 million ordinary shares at A$0.95 per share, resulting in net proceeds of approximately $68.4 million. The first tranche of 63.7 million shares was issued in March 2014 and the second tranche of 20.5 million shares was issued in April 2014.

Credit Facilities

Credit Facilities. On May 14, 2015, we and our wholly-owned subsidiary Sundance Energy, Inc. entered into the Credit Agreement with Morgan Stanley Energy Capital, Inc., as administrative agent and the lenders from time to time party thereto, which provides for our $300 million Revolving Facility and $125 million Term Loans, with an accordion feature providing for additional term loans of up to $50 million, subject to certain conditions The Revolving Facility is subject to a borrowing base, which was set initially at $75 million and reduced to $67 million on December 30, 2015. At December 31, 2015, we had $125 million outstanding on the Term Loans and $67 million outstanding on the Revolving Facility.

Interest on the Revolving Facility accrues at LIBOR plus a margin that ranges from 2.0% to 3.0% based upon the amount drawn. Interest on the Term Loans accrues at LIBOR (with a LIBOR floor of 1.0%) plus 7.0%.

The key financial covenants of our Credit Agreement require us to (i) maintain a minimum current ratio, which is defined as consolidated current assets inclusive of undrawn borrowing capacity divided by consolidated current liabilities, of 1.00 or greater, (ii) a revolving debt to EBITDAX ratio (as defined in our Credit Agreement), determined on a rolling four quarter basis, of 4.00 to 1.1 or less, (iii) maintain a minimum EBITDAX to consolidated interest expense ratio of 2.00 to 1.00 or greater, and (iv) maintain a minimum Total Proved PV-9 (as defined in our Credit Agreement) to Total Debt (as defined in our Credit Agreement) ratio of not less than 1.25 to 1.00 for the 18 month period commencing on May 14, 2015 and 1.50 to 1.00 at any time thereafter, in each case beginning on June 30, 2015. The Credit Agreement requires the Company to hedge 50% of its proved developed producing forecasted volumes. In addition, our Credit Agreement contains various covenants that limit our ability to take certain actions, including, but not limited to, the following:

· incur indebtedness or grant liens on any of our assets;

· enter into certain commodity hedging agreements;

· sell, transfer, assign or convey assets, including a sale of all or substantially all of our assets, or engage in certain mergers or acquisitions;

· make certain distributions;

· make certain loans, advances and investments; and

· engage in transactions with affiliates.

If an event of default exists under our Credit Agreement, the Agent will be able to terminate the commitments under the Credit agreement and accelerate the maturity of all loans made pursuant to the Credit Agreement and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

· failure to pay any principal when due under the credit agreement;

· failure to pay any other obligation when due and payable within three business days after same becomes due;

· failure to observe or perform any covenant, condition or agreement in the Credit Agreement or other loan documents, subject, in certain instances, to certain cure periods;

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· failure of any representation and warranty made in connection with the loan documents to be true and correct in all material respects;

· bankruptcy or insolvency events involving us or our subsidiaries;

· cross-default to other indebtedness in excess of $2 million;

· certain ERISA events involving us or our subsidiaries;

· bankruptcy or insolvency; and

· a change of control (as defined in our Credit Agreement).

We and Sundance Energy, Inc. and their respective subsidiaries have also executed and delivered certain other related agreements and documents pursuant to the Credit Agreement, including a guarantee and collateral agreement and mortgages. The obligations of the Company, Sundance Energy, Inc. and their respective subsidiaries under the Credit Agreement are secured by a first priority security interest in favor of the Agent for the benefit of the lenders, in the Company, Sundance Energy, Inc. and their respective subsidiaries’ tangible and intangible assets, and proved reserves, among other things.

Capital Expenditures

The following table summarizes our capital expenditures (excluding acquisitions) for the years ending December 31, 2015 and 2014.

	Year ending December 31
(In $ ‘000s)	2015		2014
	(audited)		(audited)
Development and production assets	$	76,831	$	350,196
Exploration and evaluation expenditure	22,501		39,670
Total	$	99,332	$	389,866

C. Research and Development

Not applicable.

D. Trend Information

We believe that oil and natural gas prices may remain volatile for the foreseeable future. While oil and/or natural gas prices are low, our future drilling and completion activity will decrease as operating cashflows decrease relative to recent historical levels. While we anticipate reductions in field service costs, material prices and all costs associated with drilling, completing and operating wells, maintaining an effective cost structure to maintain positive cashflow could be challenging. This could have a material adverse effect upon our net sales or revenues, profitability, liquidity or capital resources or cause less predictable future operating results or financial condition as compared to reported financial information. While we have identified prospects we intend to drill, our ability to grow could be adversely affected by these commodity price declines.

E. Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a significant effect on our financial condition, revenues or expenses, liquidity, capital expenditures, capital resources material to investors or results of operations.

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F. Tabular disclosure of contractual obligations

The following table summarizes our contractual obligations as of December 31, 2015.

	Payments due by period
			Less than						More than
Contractual Obligations (In $ ‘000s)	Total		1 year		1 - 3 years		3 - 5 years		5 years
Credit Facilities(1)	$	247,259	$	12,420	$	24,773	$	210,066	$	—
Cooper Basin capital commitments (2)	5,098		2,549		2,549		—		—
Operating lease obligations	5,892		1,372		2,785		1,735		—
Employment commitments	372		372		—		—		—
Restoration provision (3)	3,088		—		—		—		3,088
Total	$	261,709	$	16,713	$	30,107	$	211,801	$	3,088

(1) Includes principal and projected interest payments due under our Revolving Facility and Term Loans. Projected interest payments are based on a 3.3% and 8.0% interest rate for the Revolving Credit Facility and the Term Loans, respectively, in effect as of December 31, 2015. Timing above assumes credit facilities are held to maturity and that there are no subsequent changes to the borrowing base. However, if we sell the Eagle Ford assets, currently classified as Assets Held for Sale, we may be required to repay a portion of the credit facilities from the proceeds. Please read the description of our Revolving Credit Facility and our Term Loans above.

(2) The Company has capital commitments to fund exploratory drilling in the Cooper Basin (Australia) of up to approximately A$10.6 million through 2019 of which A$3.9 milion (US$2.8 million) had been incurred through December 31, 2015 (commitment amounts in table shown in USD translated at December 31, 2015). Timing of commitment may vary based on drilling activity by the operator.

(3) We have established a restoration provision liability for the reclamation of oil and natural gas properties at the end of their economic lives. Based on our current projections, we believe the majority of our reclamation obligations will be incurred beyond five years from December 31, 2015. The amount shown does not include 25% of our Eagle Ford restoration provision liability, which we intend to dispose of in 2016.

PART III

Item 18. Financial Statements

The financial statements are included as the “F” pages to this annual report.

Item 19. Exhibits

See Exhibit Index.

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CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

For the year ended 31 December	Note	2015			2014			2013
		US$’000			US$’000			US$’000
		(Restated)
Oil and natural gas revenue	3	$	92,191		$	159,793		$	85,345
Lease operating and production tax expense	4	(24,498		)	(20,489		)	(18,383		)
General and administrative expense	5	(17,176		)	(15,527		)	(15,297		)
Depreciation and amortisation expense	17, 20	(94,584		)	(85,584		)	(36,225		)
Impairment expense	19	(321,918		)	(71,212		)	—
Exploration expense	18	(7,925		)	(10,934		)	—
Finance costs, net of amounts capitalized		(9,418		)	(699		)	232
Loss on debt extinguishment		(1,451		)	—			—
Gain on sale of non-current assets	6	790			48,604			7,335
Gain on derivative financial instruments		15,256			11,009			(554		)
Other income (loss)		(2,240		)	(481		)	(944		)
Profit (loss) before income tax		(370,973		)	14,480			21,509

Income tax recovery (expense)	7	107,138			841			(5,567		)

Profit (loss) attributable to owners of the Company		(263,835		)	15,321			15,942

Other comprehensive income

Items that may be reclassified subsequently to profit or loss:
Exchange differences arising on translation of foreign operations (no income tax effect)		(478		)	684			(421		)
Other comprehensive income (loss)		(478		)	648			(421		)
Total comprehensive income (loss) attributable to owners of the Company		$	(264,313	)	$	16,005		$	15,521

Earnings (loss) per share (cents)
Basic earnings	10	(47.7		)	2.9			3.9
Diluted earnings	10	(47.7		)	2.9			3.8

The accompanying notes are an integral part of these consolidated financial statements

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CONSOLIDATED STATEMENT OF FINANCIAL POSITION

		2015
		US$’000			2014
For the year ended 31 December	Note	(Restated)			US$’000

CURRENT ASSETS
Cash and cash equivalents	11	$	3,468		$	69,217
Trade and other receivables	12	11,508			25,994
Derivative financial instruments	13	9,967			7,801
Income tax receivable		5,616			2,697
Other current assets	16	4,154			8,336
Assets held for sale	14	90,632			—
TOTAL CURRENT ASSETS		125,345			114,045

NON-CURRENT ASSETS
Development and production assets	16	250,922			519,013
Exploration and evaluation expenditure	18	26,323			155,130
Property and equipment	19	1,382			1,554
Derivative financial instruments	13	3,950			1,782
Deferred tax assets	24	1,913			3,998
Other non-current assets	20	—			998
TOTAL NON-CURRENT ASSETS		284,490			682,475

TOTAL ASSETS		$	409,835		$	796,520

CURRENT LIABILITIES
Trade and other payables	21	21,588			46,861
Accrued expenses	21	19,883			72,333
Derivative financial instruments	13	—			130
Liabilities held for sale	14	744			—
TOTAL CURRENT LIABILITIES		42,215			119,324
NON-CURRENT LIABILITIES

Credit facilities, net of deferred financing fees	22	187,743			128,805
Restoration provision	23	3,088			8,866
Deferred tax liabilities	24	—			102,668
Other non-current liabilities		420			1,851
TOTAL NON-CURRENT LIABILITIES		191,251			242,190
TOTAL LIABILITIES		$	233,466		$	361,514

NET ASSETS		$	176,369		$	435,006

EQUITY
Issued capital	25	308,429			306,853
Share option reserve	26	11,650			7,550
Foreign currency translation	26	(1,310		)	(832		)
Retained earnings (accumulated deficit)		(142,400		)	121,435
TOTAL EQUITY		$	176,369		$	435,006

The accompanying notes are an integral part of these consolidated financial statements

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

						Foreign			Retained
				Share		Currency			Earnings
	Issued			Option		Translation			(Accumulated
	Capital			Reserve		Reserve			Deficit)			Total
	US$’000			US$’000		US$’000			US$’000			US$’000
Balance at 31 December 2012	58,694			4,045		(1,095		)	90,172			151,816
Profit attributable to owners of the Company	—			—		—			15,942			15,942
Other comprehensive loss for the year	—			—		(421		)	—			(421		)
Total comprehensive income	—			—		(421		)	15,942			15,521
Shares issued in connection with:
a) Merger with Texon	132,092			—		—			—			132,092
b) Private placement	47,398			—		—			—			47,398
c) Exercise of stock options	813			—		—			—			813
Cost of capital raising, net of tax	(1,989		)									(1,989
Share based payments	—			1,590		—			—			1,590
Balance at 31 December 2013	237,008			5,635		(1,516		)	106,114			347,241
Profit attributable to owners of the Company	—			—		—			15,321			15,321
Other comprehensive loss for the year	—			—		684			—			684
Total comprehensive loss	—			—		684			15,321			16,005
Shares issued in connection with:
a) Private placement	72,178			—		—			—			72,178
b) Exercise of stock options	260			—		—			—			260
Cost of capital raising, net of tax	(2,593		)	—		—			—			(2,593		)
Stock compensation value of services	—			1,915		—			—			1,915
Balance at 31 December 2014	306,853			7,550		(832		)	121,435			435,006
Loss attributable to owners of the Company (Restated)	—			—		—			(263,835		)	(263,835		)
Other comprehensive loss for the year	—			—		(478		)	—			(478		)
Total comprehensive loss (Restated)	—			—		(478		)	(263,835		)	(264,313		)
Shares issued in connection with:
a) business combinations	1,576			—		—			—			1,576
Stock compensation value of services	—			4,100		—			—			4,100
Balance at 31 December 2015 (Restated)	$	308,429		$	11,650	$	(1,310	)	$	(142,400	)	$	176,369

The accompanying notes are an integral part of these consolidated financial statements

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CONSOLIDATED STATEMENT OF CASH FLOWS

		2015			2014			2013
For the year ended 31 December	Note	US$’000			US$’000			US$’000

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from sales		$	99,423		$	170,442		$	84,703
Payments to suppliers and employees		(49,639		)	(29,967		)	(21,765		)
Settlements of restoration provision		(71		)	—			—
-Interest received		107			201			126
Receipts from commodity derivatives, net		11,736			(3		)	253
Payments to acquire commodity derivatives		(690		)	—			—
Income taxes received (paid), net		3,603			(12,586		)	(671		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	30	64,469			128,087			62,646

CASH FLOWS FROM INVESTING ACTIVITIES
Payments for development expenditure		(144,316		)	(361,950		)	(154,700		)
Payments for exploration expenditure		(20,339		)	(39,616		)	(20,006		)
Payments for acquisition of oil and gas properties		(15,023		)	(35,606		)	(141,963		)
Payments to acquire available-for-sale financial assets		(185		)	—			—
Sale of non-current assets		41			115,284			37,848
Transaction costs related to sale of non-current assets		—			(278		)	(161		)
Payments for acquisition related costs		(578		)	—			—
Cash acquired from merger		—			—			114,690
Cash (paid) received from escrow and deposit accounts, net		—			(102		)	837
Payments for property and equipment		(371		)	(967		)	(900		)
NET CASH USED IN INVESTING ACTIVITIES		(180,771		)	(323,235		)	(164,355		)
CASH FLOWS FROM FINANCING ACTIVITIES

Proceeds from the issuance of shares		—			72,438			48,211
Payments for costs of capital raisings		—			(3,778		)	(2,654		)
Payments for acquisition related costs		—			—			(533		)
Borrow costs paid, net of capitalized portion		(6,889		)	(1,065		)	(569		)
Deferred financing fees capitalized		(4,708		)	—			—
Proceeds from borrowings		207,000			165,000			15,000
Repayments from borrowings		(145,000		)	(65,000		)	(15,000		)
NET CASH PROVIDED BY FINANCING ACTIVITIES		50,403			167,595			44,455
Net decrease in cash held		(65,899		)	(27,553		)	(57,254		)

Cash at beginning of period		69,217			96,871			154,110

Effect of exchange rates on cash		150			(101		)	15
CASH AT END OF PERIOD		$	3,468		$	69,217		$	96,871

The accompanying notes are an integral part of these consolidated financial statements

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial report of Sundance Energy Australia Limited (“SEAL”) and its wholly owned subsidiaries, (collectively, the “Company”, “Consolidated Group” or “Group”), for the year ended 31 December 2015 was authorised for issuance in accordance with a resolution of the Board of Directors on 31 March 2016.

The Group is a for-profit entity for the purpose of preparing the financial report. The principal activities of the Group during the financial year are the exploration for, development and production of oil and natural gas in the United States of America, and the continued expansion of its mineral acreage portfolio in the United States of America.

Basis of Preparation

The consolidated financial report is a general purpose financial report that has been prepared in accordance with Australian Accounting Standards, Australian Accounting Interpretations, other authoritative pronouncements of the Australian Accounting Standards Board (“AASB”) and the Corporations Act 2001.

These consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Material accounting policies adopted in the preparation of this financial report are presented below. They have been consistently applied unless otherwise stated.

The consolidated financial statements are prepared on a historical basis, except for the revaluation of certain non-current assets and financial instruments, as explained in the accounting policies below. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$’000), except where stated otherwise.

Principles of Consolidation

A controlled entity is any entity over which Sundance Energy Australia Limited (SEAL) is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The consolidated financial statements incorporate the assets and liabilities of all entities controlled by SEAL as at 31 December 2015 and 2014 and the results of all controlled entities for the years ended 31 December 2015, 2014 and 2013.

All inter-group balances and transactions between entities in the Group, including any recognised profits or losses, are eliminated on consolidation.

a) Income Tax

The income tax expense for the period comprises current income tax expense/(income) and deferred income tax expense/(income).

Current income tax expense charged to the statement of profit or loss is the tax payable on taxable income calculated using applicable income tax rates enacted, or substantially enacted, as at the reporting date. Current tax liabilities/(assets) are therefore measured at the amounts expected to be paid to/(recovered from) the relevant taxation authority.

Deferred income tax expense reflects movements in deferred tax asset and deferred tax liability balances during the period. Current and deferred income tax expense/(income) is charged or credited directly to equity instead of the statement of profit or loss when the tax relates to items that are credited or charged directly to equity.

Deferred tax assets and liabilities are ascertained based on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax assets also result where amounts have been fully expensed but future tax deductions are available. No deferred income tax will be recognised from the initial recognition of an asset or liability, excluding a business combination, where there is no effect on accounting or taxable profit or loss.

Deferred tax assets and liabilities are calculated at the tax rates that are expected to apply to the period when the asset recognised or the liability is settled, based on tax rates enacted or substantively enacted at the reporting date. Their measurement also reflects the manner in which management expects to recover or settle the carrying amount of the related asset or liability.

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Deferred tax assets relating to temporary differences and unused tax losses are recognised only to the extent that it is probable that future taxable profit will be available against which the benefits of the deferred tax asset can be utilized. Where temporary differences exist in relation to investments in subsidiaries, branches, associates, and joint ventures, deferred tax assets and liabilities are not recognised where the timing of the reversal of the temporary difference can be controlled and it is not probable that the reversal will occur in the foreseeable future.

Current tax assets and liabilities are offset where a legally enforceable right of set-off exists and it is intended that net settlement or simultaneous realisation and settlement of the respective asset and liability will occur. Deferred tax assets and liabilities are offset where a legally enforceable right of set-off exists, the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where it is intended that net settlement or simultaneous realisation and settlement of the respective asset and liability will occur in future periods in which significant amounts of deferred tax assets or liabilities are expected to be recovered or settled.

Tax Consolidation

Sundance Energy Australia Limited and its wholly-owned Australian controlled entities have implemented the income tax consolidation regime, with Sundance Energy Australia Limited being the head company of the newly consolidated group. Under this regime the group entities are taxed as a single taxpayer.

The head entity of the income tax consolidated group and the controlled entities in the tax consolidated group account for their own current and deferred tax amounts. These tax amounts are measured as if each entity in the tax consolidated group continues to be a standalone taxpayer in its own right.

In addition to its own current and deferred tax amounts, Sundance Energy Australia Limited, as head company, also recognises the current tax liabilities (or assets) and the deferred tax assets arising from unused tax losses and unused tax credits assumed from controlled entities in the tax consolidated group.

b) Exploration and Evaluation Expenditure

Exploration and evaluation expenditures incurred are accumulated in respect of each identifiable area of interest. These costs are capitalised to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. Any such estimates and assumptions may change as new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, for example a dry hole, the relevant capitalized amount is written off in the consolidated statement of profit or loss and other comprehensive income in the period in which new information becomes available. The costs of assets constructed within the Group includes the leasehold cost, geological and geophysical costs, and an appropriate proportion of fixed and variable overheads directly attributable to the exploration and acquisition of undeveloped oil and gas properties.

When approval of commercial development of a discovered oil or gas field occurs, the accumulated costs for the relevant area of interest are transferred to development and production assets. The costs of developed and producing assets are amortised over the life of the area according to the rate of depletion of the proved and probable developed reserves. The costs associated with the undeveloped acreage are not subject to depletion.

The carrying amounts of the Group’s exploration and evaluation assets are reviewed at each reporting date, in conjunction with the impairment review process referred to in Note 1(f), to determine whether any of impairment indicators exists. Impairment indicators could include i) tenure over the license area has expired during the period or will expire in the near future, and is not expected to be renewed, ii) substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is not budgeted or planned, iii) exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of resources, and the Group has decided to discontinue activities in the specific area, or iv) sufficient data exist to indicate that although a development is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or from sale. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made and any resulting impairment loss is recognized in the consolidated statement of profit or loss and other comprehensive income

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c) Development and Production Assets and Property and Equipment

Development and production assets, and property and equipment are carried at cost less, where applicable, any accumulated depreciation, amortisation and impairment losses. The costs of assets constructed within the Group includes the cost of materials, direct labor, borrowing costs and an appropriate proportion of fixed and variable overheads directly attributable to the acquisition or development of oil and gas properties and facilities necessary for the extraction of resources.

The carrying amount of development and production assets and property and equipment are reviewed at each reporting date to ensure that they are not in excess of the recoverable amount from these assets. Development and production assets are assessed for impairment on a cash-generating unit basis. A cash-generating unit is the smallest grouping of assets that generates independent cash inflows. Management has assessed its CGUs as being an individual basin, which is the lowest level for which cash inflows are largely independent of those of other assets. Impairment losses recognised in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit on a pro-rata basis.

An impairment loss is recognized in the consolidated statement of profit or loss and other comprehensive income whenever the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount.

The recoverable amount of an asset is the greater of its fair value less costs to sell and its value-in-use. In assessing value-in-use, an asset’s estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the assets/CGUs. In addition, the Group considers market data related to recent transactions for similar assets.

Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the consolidated statement of profit or loss and comprehensive income during the financial period in which are they are incurred.

Depreciation and Amortisation Expense

Property and equipment are depreciated on a straight-line basis over their useful lives from the time the asset is held and ready for use. Leasehold improvements are depreciated over the shorter of either the unexpired period of the lease or the estimated useful life of the improvement.

The depreciation rates used for each class of depreciable assets are:

Class of Non-Current		Asset Depreciation		Rate Basis of Depreciation
Plant and Equipment		10 – 33%		Straight Line

The Group uses the units-of-production method to amortise costs carried forward in relation to its development and production assets. For this approach, the calculation is based upon economically recoverable reserves over the life of an asset or group of assets.

The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each reporting period. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount, and recorded as impairment expense within the consolidated statement of profit or loss and other comprehensive income.

Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These gains and losses are included in the statement of profit or loss.

d) Leases

The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at date of inception. The arrangement is assessed to determine whether its fulfillment is dependent on the use of a specific asset or assets and whether the arrangement conveys a right to use the asset, even if that right is not explicitly specified in an arrangement.

Leases are classified as finance leases when the terms of the lease transfer substantially all the risks and benefits incidental to the ownership of the asset, but not the legal ownership to the entities in the Group. All other leases are classified as operating leases.

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iv) Available-for-sale financial assets

Available-for-sale financial assets are non-derivative financial assets that are either designated as such or that are not classified in any of the other categories. They comprise investments in the equity of other entities where there is neither a fixed maturity nor fixed determinable payments.

v) Financial liabilities

Non-derivative financial liabilities (excluding financial guarantees) are subsequently measured at amortised cost using the effective interest rate method.

Derecognition

Financial assets are derecognised when the contractual right to receipt of cash flows expires or the asset is transferred to another party whereby the entity no longer has any significant continuing involvement in the risks and benefits associated with the asset. Financial liabilities are derecognised when the related obligations are either discharged, cancelled or expire. The difference between the carrying value of the financial liability extinguished or transferred to another party and the fair value of consideration paid, including the transfer of non-cash assets or liabilities assumed, is recognised in profit or loss.

Classification

The Group has classified its debt as non-current based on the terms of the credit facilities agreement and the definitions of current and non-current as defined under IAS 1 rather than classifying a portion of its non-current debt as current debt based on the Group’s expectations regarding the timing of a possible repayment should the Group’s assets held for sale be sold within one year of the balance sheet date. See further discussion in Note 14 Assets Held for Sale.

f) Impairment of Non-Financial Assets

The carrying amounts of the Group’s assets are reviewed at each reporting date to determine whether there is any indication of impairment. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made.

Exploration and evaluation assets are assessed for impairment in accordance with Note 1(b).

Development and production assets are assessed for impairment on a cash-generating unit basis. A cash-generating unit is the smallest grouping of assets that generates independent cash inflows. Management has assessed its CGUs as being an individual basin, which is the lowest level for which cash inflows are largely independent of those of other assets. Impairment losses recognised in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit on a pro-rata basis.

An impairment loss is recognized in the income statement whenever the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount.

The recoverable amount of an asset is the greater of its fair value less costs to sell (FVLCS) and its value-in-use (VIU). In assessing VIU, an asset’s estimated future cash flows are discounted to their present value using an appropriate discount rate that reflects current market assessments of the time value of money and the risks specific to the assets/CGUs. In addition, the Group considers market data related to recent transactions for similar assets. In determining the fair value of the Group’s investment in shale properties, the Group considers a variety of valuation metrics from recent comparable transactions in the market. These metrics include price per flowing barrel of oil equivalent and undeveloped land values per net acre held. Where an asset does not generate cash flows that are largely independent from other assets or groups of assets, the recoverable amount is determined for the cash-generating unit to which the asset belongs.

For development and production assets, the estimated future cash flows for the VIU calculation are based on estimates, the most significant of which are hydrocarbon reserves, future production profiles, commodity prices, operating costs and any future development costs necessary to produce the reserves. Under a FVLCS calculation, future cash flows are based on estimates of hydrocarbon reserves in addition to other relevant factors such as value attributable to additional reserves based on production plans.

Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. At 31 December 2015, the Company estimated the price/Bbl to be $40 in 2016, $50 in 2017 and $60 for 2018 and then gradually increased up to $70/bbl in 2019 and thereafter.

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The discount rates applied to the future forecast cash flows are based on a third party participant’s post-tax weighted average cost of capital, adjusted for the risk profile of the asset. The range of pre-tax discounts applied were between 9% and 20%.

An impairment loss is reversed if there has been an increase in the estimated recoverable amount of a previously impaired assets. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or depletion if no impairment loss had been recognized. The Company has not reversed an impairment loss during the years ended 31 December 2015, 2014 or 2013.

g) Foreign Currency Transactions and Balances

Functional and presentation currency

Both the functional currency and the presentation currency of the Group is US dollars. Some subsidiaries have Australian dollar functional currencies which are translated to the presentation currency. All operations of the Group are incurred at subsidiaries where the functional currency is the US dollar as all oil and gas properties are located in North America.

Transactions and Balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the date of the transaction. Foreign currency monetary items are translated at the year-end exchange rate. Non-monetary items measured at historical cost continue to be carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at the exchange rate at the date when fair values were determined.

Exchange differences arising on the translation of non-monetary items are recognised directly in equity to the extent that the gain or loss is directly recognised in equity, otherwise the exchange difference is recognised in the consolidated statement of profit or loss and other comprehensive income.

Group Companies

The financial results and position of foreign subsidiaries whose functional currency is different from the Group’s presentation currency are translated as follows:

· assets and liabilities are translated at year-end exchange rates prevailing at that reporting date;

· income and expenses are translated at average exchange rates for the period; and

· retained profits, issued capital and paid-in-capital are translated at the exchange rates prevailing at the date of the transaction.

Exchange differences arising on translation of foreign operations are transferred directly to the Group’s foreign currency translation reserve. These differences are recognised in the statement of profit or loss and other comprehensive income upon disposal of the foreign operation.

h) Employee Benefits

A provision is made for the Group’s liability for employee benefits arising from services rendered by employees to the balance sheet date. Employee benefits that are expected to be settled within one year have been measured at the amounts expected to be paid when the liability is settled, plus related on-costs. Employee benefits payable later than one year have been measured at the present value of the estimated future cash outflows to be made for these benefits. Those cash flows are discounted using market yields on national government bonds with terms to maturity that match the expected timing of cash flows.

Equity - Settled Compensation

The Group has an incentive compensation plan where employees may be issued shares and/or options. The fair value of the equity to which employees become entitled is measured at grant date and recognized as an expense over the vesting period with a corresponding increase in equity. The fair value of shares issued is determined with reference to the latest ASX share price. Options are fair valued using an appropriate valuation technique which takes into account the vesting conditions.

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The excess of the consideration transferred, the amount of any non-controlling interest in the acquiree and the acquisition-date fair value of any previous equity interest in the acquiree over the fair value of the net identifiable asset acquired, if any, is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the subsidiary acquired and the measurement of all amounts has been reviewed, the difference is recognised directly in the consolidated statement of profit or loss and other comprehensive income as a gain on bargain purchase. Adjustments to the purchase price and excess on consideration transferred may be made up to one year from the acquisition date.

o) Assets Held for Sale

The Company classifies property as held for sale when management commits to a plan to sell the property, the plan has appropriate approvals, the sale of the property is highly probable within the next twelve months, and certain other criteria are met. At such time, the respective assets and liabilities are presented separately on the Company’s consolidated statement of financial position and amortisation is no longer recognized. Assets held for sale are reported at the lower of their carrying amount or their estimated fair value, less the costs to sell the assets. The Company recognizes an impairment loss if the current net book value of the property exceeds its fair value, less selling costs. As at 31 December 2015, based upon the Company’s intent and anticipated ability to sell an interest in these properties, the Company had classified 25% of its Eagle Ford assets and 100% of its Cooper Basin assets as held for sale. The Company did not have any assets classified as held for sale as at 31 December 2014. The Company has elected not to reclassify the portion of debt related to the collateralised assets held for sale to current debt, but has appropriately disclosed in Note 14.

p) Critical Accounting Estimates and Judgements

The Directors evaluate estimates and judgements incorporated into the financial report based on historical knowledge and best available current information. Estimates assume a reasonable expectation of future events and are based on current trends and economic data obtained both externally and within the Group. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

Management has made the following judgements, which have the most significant effect on the amounts recognised in the consolidated financial statements.

Estimates of reserve quantities

The estimated quantities of hydrocarbon reserves reported by the Group are integral to the calculation of amortisation (depletion) and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessment of the technical feasibility and commercial viability of producing the reserves. Management prepares reserve estimates which conform to guidelines prepared by the Society of Petroleum Engineers. Management also prepares reserve estimates under SEC guidelines. Reserve estimates conforming to the guidelines prepared by the Society of Petroleum Engineers are utilized for accounting purposes. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period, and as additional geological data is generated during the course of operations.

Impairment of Non-Financial Assets

The Group assesses impairment at each reporting date by evaluating conditions specific to the Group that may lead to impairment of assets. Where an indicator of impairment exists, the recoverable amount of the cash-generating unit to which the assets belong is then estimated based on the present value of future discounted cash flows. For development and production assets, the expected future cash flow estimation is always based on a number of factors, variables and assumptions, the most important of which are estimates of reserves, future production profiles, commodity prices and costs. In most cases, the present value of future cash flows is most sensitive to estimates of future oil price and discount rates. A change in the modeled assumptions in isolation could materially change the recoverable amount. However, due to the interrelated nature of the assumptions, movements in any one variable can have an indirect impact on others and individual variables rarely change in isolation. Additional, management can be expected to respond to some movements, to mitigate downsides and take advantage of upsides, as circumstances allow. Consequently, it is impracticable to estimate the indirect impact that a change in one assumption has on other variables and therefore, on the extent of impairments under different sets of assumptions in subsequent reporting periods. In the event that future circumstances vary from these assumptions, the recoverable amount of the Group’s development and production assets could change materially and result in impairment losses or the reversal of previous impairment losses.

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Exploration and Evaluation

The Company’s policy for exploration and evaluation is discussed in Note 1 (b). The application of this policy requires the Company to make certain estimates and assumptions as to future events and circumstances, particularly in relation to the assessment of whether economic quantities of reserves have been found. Any such estimates and assumptions may change as new information becomes available. If, after having capitalised exploration and evaluation expenditure, management concludes that the capitalised expenditure is unlikely to be recovered by future sale or exploitation, then the relevant capitalised amount will be written off through the consolidated statement of profit or loss and other comprehensive income.

Restoration Provision

A provision for rehabilitation and restoration is provided by the Group to meet all future obligations for the restoration and rehabilitation of oil and gas producing areas when oil and gas reserves are exhausted and the oil and gas fields are abandoned. Restoration liabilities are discounted to present value and capitalised as a component part of capitalised development expenditure. The capitalised costs are amortised over the units of production and the provision is revised at each balance sheet date through the consolidated statement of profit or loss and other comprehensive income as the discounting of the liability unwinds.

In most instances, the removal of the assets associated with these oil and gas producing areas will occur many years in the future. The estimate of future removal costs therefore requires management to make significant judgements regarding removal date or well lives, the extent of restoration activities required, discount and inflation rates.

Units of Production Depreciation

Development and production assets are depleted using the units of production method over economically recoverable reserves representing total proved and probable developed reserves. This results in a depletion or amortisation charge proportional to the depletion of the anticipated remaining production from the area of interest.

The life of each item has regard to both its physical life limitations and present assessments of economically recoverable reserves of the field at which the asset is located. Economically recoverable reserves are defined as proved developed and probable developed reserves. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the units of production rate of depletion or amortisation could be impacted to the extent that actual production in the future is different from current forecast production based on total economically recoverable reserves, or future capital expenditure estimates change. Changes to economically recoverable reserves could arise due to change in the factors or assumptions used in estimating reserves, including the effect on economically recoverable reserves of differences between actual commodity prices and commodity price assumptions and unforeseen operational issues. Changes in estimates are accounted for prospectively.

Share-based Compensation

The Group’s policy for share-based compensation is discussed in Note 1 (h). The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances. Share-based compensation related to options use estimates for expected volatility of the Company’s ordinary share price and expected term, including a forfeiture rate, if appropriate. Certain of the Company’s restricted share units vest based on the Company’s 3-year total shareholder return as compared to its peer group, as defined. Share-based compensation related to these awards use estimates for the expected volatility of both the Company’s ordinary share price and each of its peer’s ordinary share price.

q) Change in Accounting Estimate

Effective 1 July 2013, the Company had a change in accounting estimate related to the economically recoverable reserves in its Eagle Ford formation used in the units-of-production depletion calculation. Subsequent to the change, the Company began to include management’s best estimate of economically recoverable reserves associated with developed properties, which include both proved developed and probable developed reserves. Prior to the change, the Company used economically recoverable reserves associated only with proved developed reserves as probable developed reserves were not significant.

r) Rounding Amounts

In accordance with Class Order 98/100 issued by the Australian Securities and Investment Commission, amounts in the financial statements have been rounded to the nearest thousand.

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s) Parent Entity Financial Information

The financial information for the parent entity, SEAL (“Parent Company”), also the ultimate parent, discussed in Note 34, has been prepared on the same basis, using the same accounting policies as the consolidated financial statements, except for its investments in subsidiaries which are accounted for at cost in the individual financial statements of the parent entity less any impairment.

t) Earnings (loss) Per Share

The group presents basic and diluted earnings (loss) per share for its ordinary shares. Basic earnings (loss) per share is calculated by dividing the profit or loss attributable to ordinary shareholders of the Company by the weighted average number of ordinary shares outstanding during the year. Diluted earnings (loss) per share is determined by adjusting the profit or loss attributable to ordinary shareholders and the weighted average number of ordinary shares for the dilutive effect, if any, of outstanding share rights and share options which have been issued to employees.

u) Recently Issued Accounting Standards to be Applied in Future Reporting Periods

The following Standards and Interpretations have been issued but are not yet effective. These are the standards that the Group reasonably expects will have an impact on its disclosures, financial position or performance with applied at a future date. The Group’s assessment of the impact of these new standards, amendments to standards, and interpretations is set out below.

AASB 9/IFRS 9 — Financial Instruments

AASB 9/IFRS 9 introduces new requirements for the classification, measurement, and derecognition of financial assets and financial liabilities. The final version of IFRS 9 supersedes all previous versions of the standard. However, for annual periods beginning before 1 January 2018, an entity may elect to apply those earlier versions of IFRS 9 if the entity’s relevant date of initial application is before 1 February 2015. The effective date of this standard is for fiscal years beginning on or after 1 January 2018. Management is currently assessing the impact of the new standard but it is not expected to have a material impact on the Group’s consolidated financial statements.

AASB 15/IFRS 15 — Revenue from Contracts with Customers

In May 2014, AASB 15/IFRS 15 was issued which establishes a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. Specifically, the standard introduces a 5-step approach to revenue recognition:

· Step 1: Identify the contract(s) with a customer

· Step 2: Identify the performance obligations in the contracts.

· Step 3: Determine the transaction price.

· Step 4: Allocate the transaction price to the performance obligations in the contract.

· Step 5: Recognise revenue when (or as) the entity satisfies a performance obligation.

Under AASB 15/IFRS 15, an entity recognizes revenue when (or as) a performance obligation is satisfied, i.e. when ‘control’ of the goods or services underlying the particular performance obligation is transferred to the customer. The effective date of this standard is for fiscal years beginning on or after 1 January 2018. Management is currently assessing the impact of the new standard and plans to adopt the new standard on the required effective date.

AASB 16/IFRS 16 — Leases

In January 2016, AASB 16/IFRS 16 was issued which changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the balance sheet, initially recorded at the fair value of unavoidable lease payments. The entity will then recognize depreciation of the lease assets and interest on the income statement.

The effective date of this standard is for fiscal years beginning on or after 1 January 2019. Management is currently assessing the impact of the new standard and plans to adopt the standard on the required effective date.

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NOTE 2 — BUSINESS COMBINATIONS

Acquisitions in 2015

On 7 August 2015, the Company completed its acquisition of New Standard Energy Ltd’s (“NSE”) U.S. (Eagle Ford) and Cooper Basin (Australia PEL570) assets for an aggregate purchase price of $16.4 million. The Eagle Ford assets acquired included approximately 5,500 net acres in Atascosa County, 7 gross producing wells and 2 wells that had been drilled, but not yet completed (one of which was subsequently completed by the Company). The Cooper Basin asset acquired included a 17.5% working interest in the Petroleum Exploration License (PEL) 570 concession, with drilling commitments of up to approximately AUD$10.6 million, of which AUD$3.9 million has been incurred through 31 December 2015. The Company plans to sell 100% of its acquired interest in PEL570 and 25% of the Eagle Ford assets within the next twelve months. These assets are included in assets held for sale as of 31 December 2015.

Consideration paid for the assets included payment of $15.0 million to repay NSE’s outstanding debt and the issuance of 6 million new fully paid ordinary Company shares, offset by cash acquired of $0.2 million. Approximately 1.5 million of the 6 million Company shares were held in escrow and are expected to be returned to the Company in satisfaction of certain unresolved working capital adjustments and were not valued as part of consideration paid.

The following table reflects the fair value of the assets acquired and the liabilities as at the date of acquisition (in thousands):

Fair value of assets acquired:
Trade and other receivables	$	119
Other current assets	686
Development and production assets	13,170
PEL 570 concession (1)	4,586
Other non-current assets	213
Amount attributable to assets acquired	18,774
Fair value of liabilities assumed:
Trade and other payables	1,511
Accrued expenses	518
Restoration provision	334
Amount attributable to liabilities assumed	2,363
Net assets acquired	$	16,411
Purchase price:
Cash consideration to payoff NSE’s outstanding debt, net of cash acquired	$	14,835
Issued capital	1,576
Total consideration paid	$	16,411

(1) As at the acquisition date, the Company planned to sell the Cooper Basin assets, and therefore it was classified as held for sale.

Revenues of $0.4 million and net income of $31 thousand before impairment and income taxes were generated from the acquired properties from 7 August 2015 through 31 December 2015. Impairment expense is booked at the CGU basis and cannot be attributed to specific wells.

The Company incurred $0.5 million for the year ended 31 December 2015 in acquisition related costs primarily for professional fees and services. These amounts are included in general and administrative expense and financing activities in the consolidated statements of profit or loss and other comprehensive income and the consolidated statement of cash flows, respectively.

Acquisition in 2014

There were no business acquisitions for the year ended 31 December 2014.

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Acquistions in 2013

On 8 March 2013, the Company acquired 100% of the outstanding shares of Texon Petroleum Ltd (“Texon”, whose name was changed to Armadillo Petroleum Ltd), an Australian corporation with oil and gas assets in the Eagle Ford formation in the United States. The Company acquired Texon to gain access to its existing production and drilling inventory in the Eagle Ford formation. As consideration for substantially all of the net assets of Texon, the Company issued 122.7 million ordinary shares (approximately 30.6% of the total outstanding shares immediately subsequent to the acquisition), which had a fair value of $132.1 million on the acquisition date and net cash consideration of $26.3 million for a total purchase price of $158.4 million. The net cash consideration includes a $141.0 million pre-merger purchase by the Company of certain Texon oil and gas properties, offset by $114.7 million of cash acquired at the time of the merger. The current income tax liability, included in accrued expenses, and deferred tax liability of $33.4 million and $16.9 million, respectively, are comprised of tax liabilities assumed as at the acquisition date and an increase in the tax liability related to the incremental acquisition date fair value of the acquired development and production and exploration and evaluation assets as compared to Texon’s historical basis.

The following table reflects the final adjusted assets acquired and the liabilities assumed at their fair value or otherwise where specified by AASB 3/IFRS 3 — Business Combinations (in thousands):

Fair value of assets acquired:
Trade and other receivables		5,604
Other current assets		456
Development and production assets		53,937
Exploration and evaluation assets		150,474
Prepaid drilling and completion costs		3,027
Amount attributable to assets acquired		213,498
Fair value of liabilities assumed:
Trade and other payables		119
Accrued expenses		37,816
Restoration provision		277
Deferred tax liabilities		16,884
Amount attributable to liabilities assumed		55,096
Net assets acquired		158,402
Purchase price:
Cash and cash equivalents, net of cash acquired		26,310
Issued capital		132,092
Total consideration paid		158,402

From the acquisition date of 8 March 2013 through 31 December 2013, the Company has earned revenue of $42.3 million and generated net income of $12.6 million. The following reflects the acquisition’s contribution to the Group as if the merger had occurred on 1 January 2013 instead of the closing date of 8 March 2013 (in thousands, except per share information):

	Year ended
	31 December 2013

Oil and natural gas revenue	5,163
Lease operating and production expenses	(1,150	)
Depreciation and amortization expense	(1,882	)
General and administrative expense	(667	)
Finance costs	(35	)
Profit before income tax	1,429
Income tax expense	(542	)
Proforma profit attributable to the period 1 January to 7 March 2013	887
Profit attributable to owners of the Company for the year	15,942
Adjusted profit attributable to the owners of the Company for the year	16,829
Adjusted basic earnings per ordinary share	4.1
Adjusted diluted earnings per ordinary share	4.0

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The Company incurred $0.2 and $0.5 million for the years ended 31 December 2014 and 2013, respectively, for professional fees and services related to the Texon acquisition. These amounts are included in general and administrative expense in the consolidated statements of profit or loss, and other comprehensive income and financing activities in the consolidated statemtn of cash flows, respectively.

NOTE 3 — REVENUE

	2015	2014	2013
Year ended 31 December	US$’000	US$’000	US$’000

Oil revenue	82,949	144,994	79,365
Natural gas revenue	4,720	6,161	2,774
2,774Natural gas liquid (NGL) revenue	4,522	8,638	3,206
Total revenue (net of royalties and transportation costs)	92,191	159,793	85,345

NOTE 4 — LEASE OPERATING AND PRODUCTION TAX EXPENSE

	2015		2014		2013
Year ended 31 December	US$’000		US$’000		US$’000

Lease operating expense	(16,667	)	(12,466	)	(11,378	)
Workover expense	(1,788	)	(1,058	)	(743	)
Production tax expense	(6,043	)	(6,965	)	(6,262	)
Total lease operating and production tax expense	(24,498	)	(20,489	)	(18,383	)

NOTE 5 — GENERAL AND ADMINISTRATIVE EXPENSES

	2015		2014		2013
Year ended 31 December	US$’000		US$’000		US$’000

Employee benefits expense, including salaries and wages, net of capitalised overhead	(4,849	)	(3,064	)	(4,553	)
Share based payments expense	(4,100	)	(1,915	)	(1,590	)
General legal and professional fees	(3,347	)	(4,661	)	(3,307	)
Corporate fees	(1,986	)	(2,526	))	(1,811	)
Rent	(993	)	(631	)	(234	)
Regulatory expenses	(203	)	(1,374	)	(2,313	)
Acquisition related costs	(540	)	(150	)	(533	)
Other expenses	(1,158	)	(1,206	)	(956	)
Total general and administrative expenses	(17,176	)	(15,527	)	(15,297	)

The Company capitalised overhead costs, including salaries, wages benefits and consulting fees, directly attributable to the exploration, acquisition and development of oil and gas properties of $3.0 million, $4.5 million and $2.9 million for the years ended 31 December 2015, 2014 and 2013 respectively.

NOTE 6 — GAIN ON SALE OF NON-CURRENT ASSETS

Disposals in 2014

In July 2014, the Company sold its remaining Denver-Julesburg Basin assets for net proceeds of $108.8 million in cash, which includes the reimbursement of capital expenditures incurred on 8 gross (3.1 net) non-operated horizontal wells. The sale resulted in a pre-tax gain of $47.7 million, which is included in the gain on sale of non-current assets in the consolidated statement of profit or loss and other comprehensive income for the year ended 31 December 2014.

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NOTE 7 — INCOME TAX EXPENSE

The Company identified an error in its 31 December 2015 income tax accounting, which resulted in a $6.3 million overstatement of its deferred tax liabilities and a $0.4 million overstatement of income tax receivable as at 31 December 2015 and a $6.0 million understatement of its income tax benefit for the year then ended. No period prior to the year ended 31 December 2015 was affected. The 2015 prior period error related to the push down allocation of the Company’s consolidated impairment to the Company’s separate subsidiaries. As a result of this error, the Company’s consolidated deferred income tax liabilities, income tax receivable and income tax benefit were misstated. As the adjustment is the direct result of the 2015 impairment charge, the Company believes that the correction should be retrospectively restated for more meaningful and comparative financial information.

The effect of this correction is shown in the table below. There is no impact to the consolidated statement of cash flows. The correction to the consolidated statements of loss and other comprehensive loss and consolidated statement of financial position will be reflected in the Company’s year ended 31 December 2015 comparative information included in its 2016 annual report.

	As Stated in 2015 31 December Annual Report US$’000			Correction US$’000			2015 Restated US$’000
Consolidated Statement of Financial Position (As at 31 December 2015)
Income tax receivable	$	5,997		$	(381	)	$	5,616
Total current assets	125,726			(381		)	125,345
Deferred tax liabilities	6,341			(6,341		)	Nil
Total non-current liabilities	197,592			(6,341		)	191,251
Net assets	170,409			5,960			176,369
Accumulated deficit	(148,360		)	5,960			(142,400		)
Total equity	170,409			5,960			176,369

Consolidated Statement of Loss and Other

Comprehensive Loss (Year-ended 31 December 2015)
Income tax benefit	$	101,178		$	5,960		$	107,138
Loss attributable to owners of the company	(269,795		)	5,960			(263,835		)
Total comprehensive loss	(270,273		)	5,960			(264,313		)
Basic and diluted loss per share (cents)	(48.8		)	1.1			(47.7		)

Year ended 31 December	2015 US$’000		2014 US$’000		2013 US$’000
a) The components of income tax expense comprise:
Current tax benefit/(expense)	6,191		(17	)	21,398
Deferred tax benefit	100,947		858		(26,965	)
Total income tax benefit	107,138		841		(5,567	)
b) The prima facie tax on income (loss) from ordinary activities before income tax is reconciled to the income tax as follows:
Profit (loss) before income tax	(370,973	)	14,480		21,509
Prima facie tax expense (benefit) at the Group’s statutory income tax rate of 30% (2014:30%)	(111,292	)	4,344		6,453
Increase (decrease) in tax expense resulting from:
- Difference of tax rate in US controlled entities	(20,447	)	220		1,607
- Impact of direct accounting from US controlled entities (1)	(3,165	)	(3,044	)	72
- Share based compensation	747		428		—
- Excess depletion	—		(489	)	—
- Other allowable items	77		295		144
- Tax adjustments relating to prior years	—		(1,063	)	(984	)
- Change in apportioned state tax rates in US controlled entities (2)	(84	)	(992	)	(1,520	)
- Tax consolidation election (3)	—		(3,058	)	—
- Current year tax losses not recognised	27,026		2,518		(205	)
Total Income tax benefit	(107,138	)	(841	)	5,567
c) Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30%	29,714		2,685		170
d) Deferred tax charged directly to equity:
- Equity raising costs	—		1,147		665
- Currency translation adjustment	(362	)	(268	)	—

(1) The Oklahoma US state tax jurisdiction computes income taxes on a direct accounting basis. A significant portion of the 2015 and 2014 impairments related to this jurisdiction resulting in a deferred tax benefit of $3,165 creating deferred tax assets, all of which were unrecognized.

(2) In 2014, the change in apportioned state tax rate in US controlled entities is a result of the Company disposing of its property in Colorado (income tax rate of 4.63%). In 2013, the change in apportioned state tax rate in US controlled entities is a result of disposing of propery in North Dakota (income tax rate of 4.53%). As the Texas margin tax computation is similar in nature to an income tax computation, it is treated as an income tax for financial reporting purposes.

(3) In 2014, the this income tax benefit resulted from the election to consolidate certain Australian subsidiaries for income tax purposes effective 1 January 2014, making previously unrecognized deferred tax assets of one of these Australian subsidiaries available for utilization against future income of the consolidated Australian entities. These deferred tax assets were previously unrecognized due to the lack of evidence of future taxable income for these Australian subsidiaries on a stand-alone basis.

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NOTE 9 — AUDITORS’ REMUNERATION

Year ended 31 December	2015 US$	2014 US$	2013 US$
Cash remuneration of the auditor for:
Auditing or review of the financial report	462,950	428,888	90,941
Professional services related to filing of various Forms with the US Securities and Exchange Commission	13,000	244,754	430,055
Taxation services provided by the practice of auditor	61,535	68,815	47,783
Non-audit services related to Texon acquisition	—	—	76,708
Total remuneration of the auditor	537,485	742,457	645,487

NOTE 10 — EARNINGS (LOSS) PER SHARE (EPS)

Year ended 31 December		2015 US$’000		2014 US$’000		2013 US$’000
Profit/(loss) for periods used to calculate basic and diluted EPS		(263,835	)	15,321		15,942

	Number of shares	Number of shares	Number of shares
-Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS(1)	552,847,289	531,391,405	413,872,184
-Incremental shares related to options and restricted share units	—	3,208,214	2,685,150
-Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS	552,847,289	534,599,619	416,557,334

(1) Calculation excludes approximately 1.5 million ordinary shares held in escrow as at 31 December 2015. The shares were issued as part of the NSE acquisition and are expected to be returned to the Company in satisfaction of certain working capital adjustments.

Incremental shares related to options and restricted share units were excluded from 31 December 2015 weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS as the outstanding shares would be anti-dilutive to the loss per share calculation for the period then ended.

NOTE 11 — CASH AND CASH EQUIVALENTS

Year ended 31 December	2015 US$’000	2014 US$’000
Cash at bank and on hand	3,468	18,222
Cash equivalents in escrow accounts (1)	—	50,995
Total cash and cash equivalents	3,468	69,217

(1) As at 31 December 2014, the Company had approximately $51.0 million in Section 1031 escrow accounts which are not limited in use, except that the timing of tax payments will be accelerated if not used on qualified “like-kind property.” As such, the balances were included in the Company’s cash and cash equivalents in the consolidated statement of financial position and consolidated statement of cash flows as at 31 December 2014.

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NOTE 12 — TRADE AND OTHER RECEIVABLES

	2015	2014
Year ended 31 December	US$’000	US$’000
Oil, natural gas and NGL sales	5,684	13,246
Joint interest billing receivables	4,108	11,587
Commodity hedge contract receivables	1,653	1,153
Other	63	8
Total trade and other receivables	11,508	25,994

Due to the short-term nature of trade and other receivables, their carrying amounts are assumed to approximate fair value. No receivables were outside of normal trading terms as at 31 December 2015 and 2014.

NOTE 13 — DERIVATIVE FINANCIAL INSTRUMENTS

	2015	2014
Year ended 31 December	US$’000	US$’000
FINANCIAL ASSETS:
Current
Derivative financial instruments — commodity contracts	9,967	7,801
Non-current
Derivative financial instruments — commodity contracts	3,950	1,675
Derivative financial instruments — interest rate swaps	—	107
Total financial assets	13,917	9,583

FINANCIAL LIABILITIES:
Current
Derivative financial instruments — interest rate swaps	—	(130	)
Total financial liabilities	—	(130	)

NOTE 14 — ASSETS HELD FOR SALE

As at 31 December 2015, the consolidated statement of financial position includes $90.6 million of assets and $0.7 million of liabilities as held for sale, respectively, comprised of the following:

	2015
Year ended 31 December	US$
Eagle Ford
Development and production assets (25%)	$	77,021
Exploration and evaluation expenditure (25%)	8,377
Cooper Basin
Exploration and evaluation expenditure (100%)	5,234
Total assets held for sale	$	90,632

Restoration provision for Eagle Ford developed assets (25%)	$	(744	)
Total liabilities held for sale	$	(744	)

In late 2015, the Company’s management committed to a plan to sell a minimum of a 25% non-operated working interest in its Eagle Ford assets. The Company acquired the Cooper Basin assets, which fall outside the Company’s strategic focus, as part of the NSE acquisition in 2015. The Company believes the sale of the aforementioned assets is highly probably in 2016.

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As at 31 December 2015, certain of the Company’s assets held for sale were included in the Borrowing Base Value under the Company’s Credit Agreement. Upon the sale of these assets, the Lender may elect to reduce the then effective Borrowing Base by an amount equal to the value attributed to those assets if the value of the remaining assets doesn’t meet the prescribed asset coverage thresholds. As at 31 December 2015, 25% of the Company’s Eagle Ford assets represented approximately 24% of the Borrowing Base Value so, if the valuation was unchanged at the time of the sale, the lender could elect to require repayment of that pro rata portion of the outstanding debt which equates to approximately $45 million. That being said, there are many variables that affect the Lender’s determination of Borrowing Base Value at any point in time and therefore it is difficult for the Company to estimate the Borrowing Base Value at an undetermined point in the future so the amount that would be required to be repaid, if any, is uncertain.

NOTE 15 — FAIR VALUE MEASUREMENT

The following table presents financial assets and liabilities measured at fair value in the consolidated statement of financial position in accordance with the fair value hierarchy. This hierarchy groups financial assets and liabilities into three levels based on the significance of inputs used in measuring the fair value of the financial assets and liabilities. The fair value hierarchy has the following levels:

Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities;

Level 2: inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices); and

Level 3: inputs for the asset or liability that are not based on observable market data (unobservable inputs).

The Level within which the financial asset or liability is classified is determined based on the lowest level of significant input to the fair value measurement. The financial assets and liabilities measured at fair value in the statement of financial position are grouped into the fair value hierarchy as follows:

Consolidated 31 December 2015 (US$’000)	Level 1	Level 2	Level 3	Total
Assets measured at fair value
Derivative commodity contracts	—	13,917	—	13,917
Available-for-sale securities (included in other current assets)	89	—	—	89
Assets held for sale	—	—	90,632	90,632
Development and production assets	—	—	250,922	250,922
Exploration and evaluation assets	—	—	26,323	26,323
Net fair value	89	13,917	367,877	381,883

Consolidated 31 December 2014 (US$’000)	Level 1	Level 2		Level 3	Total
Assets measured at fair value
Derivative commodity contracts	—	9,476		—	9,476
Interest rate swap contract — current	—	107		—	107
Development and production assets (1)	—	—		455,084	455,084
Liabilities measured at fair value
Interest rate swap contracts — long term	—	(130	)	—	(130	)
Net fair value	—	9,453		455,084	464,537

(1) Excludes work-in-progress and restoration provision assets totaling $63.9 million.

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During the years ended 31 December 2015 and 2014, respectively, there were no transfers between level 1 and level 2 fair value measurements, and no transfer into or out of level 3 fair value measurements.

Measurement of Fair Value

a) Derivatives

Derivatives entered into by the Company consist of commodity contracts and interest rate swaps. The Company utilises present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy.

b) Available-for-sale securities

The Company purchased 122 million shares of Elixer Petroleum (ASX: EXR) in conjunction with its purchase of NSE. The fair value of the securities was determined using ASX trade data, which is directly observable by the Company, and has been included with the Level 1 fair value hierarchy.

c) Development and Production Assets, Exploration and Evaluation Assets and Assets Held for Sale

At 31 December 2015, the Company recorded impairment expense to present all of its exploration and evaluation expenditures and its development and production assets, including its assets held for sale, at the estimated recoverable amount. The estimate of the recoverable amount includes Level 3 inputs described in detail in Note 19.

d) Credit Facilities

As at 31 December 2015, the Company had $125 million and $67 million of principal debt outstanding on its Term Loan and Revolving Facility, respectively. The estimated fair value of the Term Loan was approximately $179 million, based on indirect, observable inputs (Level 2) regarding interest rates available to the Company. The fair value of the Term Loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period. The estimated fair value of the Revolving Facility approximated its carrying amount due to the floating interest rate paid on such debt to be set for a period of three months or less.

e) Other Financial Instruments

The carrying amounts of cash, accounts receivable, accounts payable and accrued liabilities approximate fair value due to their short- term nature.

NOTE 16 — OTHER CURRENT ASSETS

Year ended 31 December	2015 US$’000	2014 US$’000
Cash advances to other operators	27	3,270
Escrow accounts	—	1,000
Oil inventory on hand, lesser of cost or market	632	1,331
Equipment inventory, lesser of cost or market	783	1,315
Prepaid expenses	2,578	1,401
Available-for-sale securities	89	—
Other	45	19
Total other current assets	4,154	8,336

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NOTE 17 — DEVELOPMENT AND PRODUCTION ASSETS

	2015		2014
Year ended 31 December	US$’000		US$’000
Costs carried forward in respect of areas of interest in:
Development and production assets, at cost:
Producing assets	694,111		652,035
Wells-in-progress	38,210		56,043
Undeveloped assets	62,781		—
-Development and production assets, at cost:	795,102		708,078
Accumulated depletion	(211,123	)	(117,613	)
Accumulated impairment	(256,036	)	(71,452	)
Total development and production expenditure	327,943		519,013
Less amount classified as asset held for sale	(77,021	)	—
Total Development and Production Expenditure, net of assets held for sale	250,922		519,013

a) Movements in carrying amounts:
Development expenditure
Balance at the beginning of the period	519,013		312,230
Amounts capitalised during the period	76,831		350,196
Amounts transferred from exploration phase	4,898		59,209
Fair value of assets acquired	13,170		—
Allocation of working interest assets acquired	—		2,244
Exploratory dry hole costs previously included in wells-in progress	(2,416	)	—
Revision to restoration provision	(5,715	)	—
Depletion expense	(93,429	)	(85,357	)
Impairment expense	(184,408	)	(71,212	)
Development and production assets, net of accumulated amortization, sold during the period	—		(48,297	)
Reclassifications to assets held for sale	(77,021	)	—
Balance at end of period	250,922		519,013

Borrowing costs relating to drilling of development wells that have been capitalized as part of oil and gas properties during the year ended 31 December 2014 was $1.6 million (2014: $3.4 million). The interest capitalized as a percent of bank interest for years ended 31 December 2015 and 2014 was 14.1% and 100%, respectively.

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NOTE 18 — EXPLORATION AND EVALUATION EXPENDITURE

Year ended 31 December		2015 US$’000		2014 US$’000

Costs carried forward in respect of areas of interest in:
Exploration and evaluation phase, at cost		178,693		156,680
Provision for impairment		(138,759	)	(1,550	)
Total exploration and evaluation expenditures		39,934		155,130
Less amount classified as asset held for sale		(13,611	)	—
Total Exploration and Evaluation Expenditure, net of assets held for sale		26,323		155,130

a)	Movements in carrying amounts: Exploration and evaluation
	Balance at the beginning of the period	155,130		166,144
	Amounts capitalised during the period	22,508		39,670
	Fair value of assets acquired (1)	4,586		—
	Allocation of working interest assets acquired(2)	—		34,184
	Exploration costs expensed (3)	(183	)	(10,934	)
	Amounts transferred to development phase	(4,898	)	(59,209	)
	Exploration tenements sold during the period	—		(14,725	)
	Impairment expense	(137,209	)	—
	Reclassifications to assets held for sale (4)	(13,611	)	—
	Balance at end of period	26,323		155,130

(1) As part of the Company’s acquisition of NSE in August 2015, the Company acquired a 17.5% WI in the PEL570 concession in the Cooper Basin.

(2) In July 2014, the Company acquired the working interest in approximately 9,200 gross (5,700 net) in Dimmit County, Texas. The purchase price included an initial cash payment of $35.5 million and a commitment to drill four Eagle Ford wells. The purchase price was allocated between exploration and evaluation and development and production assets based on discounted cash flows of developed producing wells.

(3) In 2015, the Company expensed costs associated with two exploratory wells located in the Eagle Ford that did not have economically recoverable reserves (i.e. dry hole wells). In 2014, the Company drilled three exploratory wells in the Anadarko Basin that did not have economically recoverable reserves and as such, all associated costs were expensed as exploration expense on the consolidated statement of profit or loss.

(4) The Company has committed to a plan to sell its interest in the Cooper Basin and 25% of its Eagle Ford assets in 2016. As of 31 December 2015, the fair value of the exploration and evaluation expenditure assets held for sale were $13.6 million.

The ultimate recoupment of costs carried forward for exploration phase is dependent on the successful development and commercial exploitation or sale of respective areas.

NOTE 19 — IMPAIRMENT OF NON-CURRENT ASSETS

At 31 December 2015, the Group reviewed its non-current assets for indicators of impairment in accordance with the Group’s accounting policy. Due to the further decline in the oil pricing environment at year-end, the Company determined that there was an indication of impairment for all of its exploration and evaluation expenditures and its development and production assets.

Each of the Group’s development and production asset CGUs include all of its developed producing properties, shared infrastructure supporting its production and undeveloped acreage that the Group considers technically feasible and commercially viable.

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Estimates of recoverable amounts are based on the higher of an asset’s value-in-use or fair value less costs to sell (level 3 fair value hierarchy), using a discounted cash flow method, and are most sensitive to the key assumptions such as pricing, discount rates, and reserve risk factors. For its development and production assets, the Group has used the FVLCS calculation whereby future cash flows are based on estimates of hydrocarbon reserves in addition to other relevant factors such as value attributable to additional reserves based on production plans. For its exploration and evaluation expenditures, the Group has used the FVLCS calculation determined by the probability weighted combination of a discounted cash flow method and market transactions for comparable undeveloped acreage.

Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. Future prices ($/bbl) used for the 31 December 2015 FVLCS calculation were as follows:

2016		2017		2018		2019 and thereafter
$	40.00	$	50.00	$	60.00	$	70.00

As at 31 December 2015, the post-tax discount rate that has been applied to the above non-current assets were 9.0% and 10.0% for proved developed producing and proved undeveloped properties, respectively. As at 31 December 2015, the Group also applied further risk-adjustments appropriate for risks associated with its proved undeveloped reserves using a risk-adjustment rate of 20% based on the risk associated with the undeveloped reserve category.

As at 31 December 2015, the post-tax discount rate that has been applied to the exploration and evaluation expenditures was 15.0% and 20.0% for its probable and possible reserves, respectively. As at 31 December 2015, the Group also applied further risk- adjustments appropriate for risks associated with its probable and possible reserves using a risk-adjustment rate of 30% and 40%, respectively, based on the risk associated with each reserve category.

Recoverable amounts and resulting impairment recognized in the Consolidated Statements of Profit or Loss and Other Comprehensive Income as at 31 December 2015 and 2014 and recorded in the years then ended are presented in the table below. In the first half of the year ended 31 December 2015, the Company impaired its Mississippian/Woodford development and production assets and exploration and evaluation by $2.6 million and $13.4 million for a total of $16.0 million. The total impairment expense for the year ended 31 December 2015 was $321.6 million.

		Recoverable
31 December 2015	Carrying costs	amount (1)	Impairment
Cash-generating unit	US$’000	US$’000	US$’000
Exploration and evaluation expenditures:
Eagle Ford	151,171	33,511	(117,660	)
Mississippian/Woodford	5,164	1,190	(3,974	)
Cooper Basin	7,436	5,234	(2,202	)
Total exploration and evaluation	163,771	39,935	(123,836	)
Development and production assets:
Eagle Ford	431,796	308,083	(123,713	)
Mississippian/Woodford	77,940	19,859	(58,081	)
Total development and production assets	509,736	327,942	(181,794	)

(1) Before reclassification of assets held for sale

		Recoverable
31 December 2014	Carrying costs (1)	amount	Impairment
Cash-generating unit	US$’000	US$’000	US$’000
Development and production assets:
Eagle Ford	400,761	389,764	10,997
Mississippian/Woodford	125,535	65,320	60,215
Total development and production assets	526,296	455,084	71,212

(1) Carrying costs exclude work-in-progress that was not subject to impairment analysis.

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The impairment charges of $321.9 million and $71.2 million for the years ended 31 December 2015 and 2014, respectively, were primarily the result of the lower oil price environment. No impairment was recorded for the year ended 31 December 2013. Any further adverse changes in any of the key assumptions may result in future impairments.

NOTE 20 — PROPERTY AND EQUIPMENT

	2015		2014
Year ended 31 December	US$’000		US$’000
Property and equipment, at cost	2,942		2,570
Accumulated depreciation	(1,560	)	(1,016	)
Total Property and Equipment	1,382		1,554

a) Movements in carrying amounts:

Balance at the beginning of the period	1,554		1,047
Amounts capitalised during the period	372		967
Depreciation expense	(544	)	(460	)
Balance at end of period	1,382		1,554

NOTE 21 — TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES

Year ended 31 December	2015 US$’000	2014 US$’000

Oil and natural gas property and operating related	37,167	117,117
Administrative expenses, including salaries and wages	1,253	1,689
Accrued interest payable	3,051	388
Total trade, other payables and accrued expenses	41,471	119,194

NOTE 22 — CREDIT FACILITIES

	2015 US$000		2014 US$000
Morgan Stanley Revolving Facility	67,000		—
Morgan Stanley Term Loan	125,000		—
Wells Fargo Senior Credit Facility	—		95,000
Wells Fargo Junior Credit Facility	—		35,000
Total Credit Facilities	192,000		130,000
Deferred financing fees, net of accumulated amortisation	(4,257	)	(1,195	)
Total credit facilities, net of deferred financing fees	187,743		128,805

On May 14, 2015, Sundance Energy Australia Limited and Sundance Energy, Inc. entered into a Credit Agreement (the “Credit Agreement”) with Morgan Stanley Energy Capital, Inc., as administrative agent (“Agent”) and the lenders from time to time party thereto, which provides for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and term loans of $125 million (the “Term Loans), with an accordion feature providing for additional term loans of up to $50 million, subject to certain conditions. The Revolving Facility is subject to a borrowing base, which was set initially at $75 million and was subsequently reduced to $67 million, as a result of its 4th quarter borrowing base redetermination. The Revolving Facility has a five year term (matures in May 2020) and the Term Loan has a 5 ½ year term (matures in November 2020).

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The Revolving Facility and Term Loans refinanced the Company’s credit facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively. At closing, the Company used $145.0 million of the proceeds to pay off its previous credit facilities, which are fully paid-off. Approximately $1.1 million of deferred financing fees related to the previous credit facilities were written off due to the refinance. In addition, the Company paid Wells Fargo et al $0.4 million of early termination fees at closing, for a total of $1.5 million of loss on debt extinguishment recorded in the statement of profit or loss and other comprehensive income.

The Company is required under our Credit Agreement to maintain the following financial ratios:

· a minimum current ratio, consisting of consolidated current assets including undrawn borrowing capacity to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;

· a maximum leverage ratio, consisting of consolidated Revolving Facility Debt to adjusted consolidated EBITDAX (as defined in the Credit Facility), of not greater than 4.0 to 1.0 as of the last day of any fiscal quarter;

· a minimum interest coverage ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Credit Facility), of not less than 2.0 to 1.0 as of the last day of any fiscal quarter; and

· An asset coverage ratio, consisting of PV9% to Total Debt (as defined in the Credit Facility), of not less than 1.25 to 1.0, through 30 September 2016 and not less than 1.50 to 1.0 thereafter.

As at 31 December 2015, the Company was in compliance with all financial and other covenants under the Credit Agreement.

NOTE 23 — RESTORATION PROVISION

The restoration provision represents the best estimate of the present value of restoration costs relating to the Company’s oil and natural gas interests, which are expected to be incurred up to 2044. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. The estimate of future removal costs requires management to make significant judgments regarding removal date or well lives, the extent of restoration activities required, discount and inflation rates. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual restoration costs will reflect market conditions at the relevant time. Furthermore, the timing of restoration is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend on future oil and natural gas prices, which are inherently uncertain.

	2015		2014
Year ended 31 December	US$’000		US$’000
Balance at the beginning of the period	8,866		5,074
New provisions	560		3,677
Changes in estimates (1)	(5,661	)	1,541
Disposals	—		(2,314	)
Settlements	(290	)	—
New provisions assumed from acquisition	334		822
Unwinding of discount	23		66
Reclassification to liabilities held for sale	(744	)	—
Balance at end of period	3,088		8,866

(1) The change in estimates is primarily the result of lower estimated third-party service provider costs to perform restoration work.

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NOTE 24 — DEFERRED TAX ASSETS AND LIABILITIES

Deferred tax assets and liabilities are attributable to the following:

	2015		2014
Year ended 31 December	US$’000		US$’000
Net deferred tax assets:
Share issuance costs	1,342		2,172
Net operating loss carried forward	3,659		1,826
Accrued interest	(2,847	)	—
Development and production expenditure	(241	)	—
Total net deferred tax assets	1,913		3,998
Deferred tax liabilities:
Development and production expenditure	1,509		(106,343	)
Derivatives	(4,371	)	(3,351	)
Other	(32	)	—
Offset by deferred tax assets with legally enforceable right of set-off: Net operating loss carried forward	—		5,943
Credits	150		1,070
Accrued interest	2,744		—
Other	—		12
Total net deferred tax liabilities	—		(102,668	)

NOTE 25 — ISSUED CAPITAL

Total ordinary shares issued and outstanding at each period end are fully paid. All shares issued are authorized. Shares have no par

value.

		Number of Shares
a) Ordinary Shares
Total shares issued and outstanding at 31 December 2013		463,173,668
Shares issued during the year		86,122,171
Total shares issued and outstanding at 31 December 2014		549,295,839
Shares issued during the year (1)		9,807,723
Total shares issued and outstanding at 31 December 2015		559,103,562

(1) Includes 1.5 million shares held in escrow related to the Company’s acquisition of NSE. The shares are expected to be returned to the Company in satisfaction of certain unresolved due diligence defects.

Ordinary shares participate in dividends and the proceeds on winding up of the Parent Company in proportion to the number of shares held. At shareholders’ meetings each ordinary share is entitled to one vote when a poll is called, otherwise each shareholder has one vote on a show of hands.

	2015	2014
Year ended 31 December	US$’000	US$’000

b) Issued Capital
Beginning of the period	306,853	237,008
Shares issued in connection with:
Share consideration paid in business combination	1,576	—
Private placement	—	72,178
Exercise of stock options	—	260
Total shares issued during the period	1,576	72,438
Cost of capital raising during the period, net of tax benefit	—	(2,593	)
Closing balance at end of period	308,429	306,853

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c) Options on Issue

In 2015, the holders of all of the outstanding options (2,730,000) were notified the options would be converted to 1,275,000 restricted share units (RSUs), which vest in accordance with the original options’ terms. Refer to Note 31 for additional information regarding this conversion.

d) Restricted Share Units on Issue

Details of the restricted share units issued or issuable as at 31 December:

	2015	2014
Grant Date	No. of RSUs	No. of RSUs

15 Oct 2012 (1)	352,676	352,676
19 April 2013	204,914	411,769
28 May 2013	93,562	187,124
15 April 2014	658,080	1,291,951
5 May 2014	45,000	90,000
12 May 2014	63,332	126,666
30 May 2014	503,991	503,991
27 April 2015(3)	28,874	—
28 May 2015	1,545,113	—
28 May 2015 (2)	1,545,113	—
24 June 2015(3)	4,267,002	—
24 June 2015(2) (3)	2,815,681	—
17 July 2015(4)	1,275,000	—
1 August 2015(3)	321,000	—
Total RSUs outstanding	13,719,338	2,964,177

(1) RSUs vested in 2015 and ordinary shares were issued in early 2016.

(2) TSR RSUs are described in more detail in Part I, Item 6.

(3) RSUs were granted during 2015 and will be formally issued in early 2016. The Company began expensing the award at its grant date in 2015.

(4) RSUs issuable from option conversion described above. 1,087,367 vested during 2015 and ordinary shares were issued in early 2016.

e) Capital Management

Management controls the capital of the Group in order to maintain an appropriate debt to equity ratio, provide the shareholders with adequate returns and ensure that the Group can fund its operations and continue as a going concern.

The Group’s debt and capital includes ordinary share capital and financial liabilities, supported by financial assets. Other than the covenants described in Note 21, the Group has no externally imposed capital requirements.

Management effectively manages the Group’s capital by assessing the Group’s financial risks and adjusting its capital structure in response to changes in these risks and in the market. These responses include the management of debt levels, distributions to shareholders and shareholder issues.

There have been no changes in the strategy adopted by management to control the capital of the Group since the prior period. The strategy is to ensure that any significant increases to the Group’s debt or equity through additional draws or raises have minimal impact to its gearing ratio. As at 31 December 2015 and 2014, the Company had $192 million and $130 million of outstanding debt, respectively.

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NOTE 26 — RESERVES

a) Share Option Reserve

The share option reserve records items recognised as expenses on valuation of employee share options and restricted share units.

b) Foreign Currency Translation Reserve

The foreign currency translation reserve records exchange differences arising on translation of the Parent Company.

NOTE 27 — CAPITAL AND OTHER EXPENDITURE COMMITMENTS

Capital commitments relating to tenements

As at 31 December 2015, all of the Company’s core exploration and evaluation and development and production assets are located in the United States of America (“US”). In addition, the Company has exploration and evaluation assets located in Australia. The Australian assets are currently classified as held for sale.

The mineral leases in the exploration prospects in the US have primary terms ranging from 3 years to 5 years and generally have no specific capital expenditure requirements. However, mineral leases that are not successfully drilled and included within a spacing unit for a producing well within the primary term will expire at the end of the primary term unless re-leased.

The Company is committed to fund exploratory drilling in the Cooper Basin (Australia) of up to approximately A$10.6 million through 2019, of which A$3.9 million (US$2.8 million) had been incurred as at 31 December 2015.

The following tables summarize the Group’s contractual commitments not provided for in the consolidated financial statements:

As at 31 December 2015	Total US$’000	Less than 1 year	1 – 5 years	More than 5 years
Cooper Basin capital commitments (1)	5,098	2,549	2,549	—
Operating lease commitments (2)	5,892	1,372	4,520	—
Employment commitments (3)	372	372	—	—
Total expenditure commitments	11,362	4,293	7,069	—

As at 31 December 2014	Total US$’000	Less than 1 year	1 – 5 years	More than 5 years
Drilling rig commitments (4)	1,460	1,460	—	—
Operating lease commitments (2)	2,363	430	1,933	—
Employment commitments (3)	742	370	372	—
Total expenditure commitments	4,565	2,260	2,305	—

(1) The Company has capital commitments to fund exploratory drilling in the Cooper Basin (Australia) of up to approximately A$10.6 million through 2019 (commitment amounts in table shown in USD translated at 31 December 2015). Timing of commitment may vary based on drilling activity by the operator.

(2) Represents commitments for minimum lease payments in relation to non-cancellable operating leases for office space and the Company’s amine treatment facility not provided for in the consolidated financial statements.

(3) Represents commitments for the payment of salaries and other remuneration under long-term employment and consultant contracts not provided for in the consolidated financial statements. Details relating to the employment contracts are set out in the Company’s Remuneration Report.

(4) As at 31 December 2014 the Company had one outstanding drilling rig contracts to explore and develop the Company’s properties. The contracts historically have had terms of 6 months. Amounts represent minimum expenditure commitments should the Company have elected to terminate these contracts prior to term.

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NOTE 30 — CASH FLOW INFORMATION

Year ended 31 December		2015 US$’000		2014 US$’000		2013 US$’000

a)	Reconciliation of cash flows from operations with income from ordinary activities after income tax
Profit from ordinary activities after income tax		(263,835	)	15,321		15,942
Adjustments to reconcile net profit to net operating cash flows:
Depreciation and amortisation expense		94,584		85,584		36,225
Share options expensed		4,100		1,915		1,590
Unrealised (gains) losses on derivatives		(3,444	)	(9,642	)	837
Net gain on sale of properties		(790	)	(48,604	)	(7,335		)
Decrease in fair value of securities available for sale		90		—		—
Impairment of development and production assets		321,918		71,212		—
Unsuccessful exploration and evaluation expense		—		10,934		—
Loss on debt extinguishment		1,151		316		140
Add: Interest expense and financing costs(disclosed in investing and financing activities)		9,418		383		—
Recognition of DTA on items directly within equity		—		879		665
Other		2,240		126		(153		)
Changes in assets and liabilities:
- (Decrease) increase in current and deferred income tax		(100,583	)	(14,606	)	5,147
- Decrease in other current assets		2,742		28		2,155
- Decrease (increase) in trade and other receivables		7,007		8,679		(3,541		)
- Increase (decrease) in trade and other payables		(2,177	)	5,562		10,974
- Increase in tax receivable		(6,522	)	—		—
- Decrease in non-current liability		(1,430	)	—		—
Net cash provided by operating activities		64,469		128,087		62,646

b)	Non Cash Financing and Investing Activities
- During the year ended 31 December 2015, the net gain on sale of properties primarily related to an ad valorem tax true-up related to properties sold in 2014.
- During the year ended 31 December 2014 the net gain on sale of properties for the disposition of the Company’s remaining Williston assets included the relief of a net payable due to the buyer of $4.0 million ($17.1 million payable and $13.1 million receivable).
- During the year ended 31 December 2013 $132.1 million in shares were issued in connection with the Texon acquisition.							—

NOTE 31 — SHARE BASED PAYMENTS

Options

For the years ended 31 December 2015, 2014 and 2013, a total of nil, nil and 2,000,000 options were granted to employees pursuant to employment agreements and a total of nil, 431,666 and 2,725,000 previously issued options were exercised, respectively. There were also 700,000 awarded options that the Company issue in early 2013 for which Company employees rendered services during the six month period ended 31 December 2012.

During 2015, all Option holders were notified that the conversion of all outstanding options would be converted into 1,275,000 RSUs, which vest in accordance with the original options’ terms.

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	2015		2014			2013
Year ended 31 December	Number of Options		Weighted Average Exercise Price A$	Number of Options		Weighted Average Exercise Price A$	Number of Options		Weighted Average Exercise Price A$
Outstanding at start of period	2,730,000		0.90	5,051,666		1.02	5,776,666		0.59
Formally issued	—		—	—		—	2,000,000		1.29
Forfeited	—		—	(1,890,000	)	1.29	—		—
Exercised	—		—	(431,666	)	0.62	(2,725,000	)	0.31
Converted to RSUs (1)	(2,730,000	)	0.90	—		—	—		—
Outstanding at end of period	—		—	2,730,000		0.90	5,051,666		1.02
Exercisable at end of period	—		—	1,930,000		0.87	2,241,666		0.87

(1) Conversion of the options was approved in 2015; the associated RSUs were issued in early 2016.

Share based payments expense related to options is determined pursuant to AASB 2 - Share Based Payments (“AASB 2”) / IFRS 2 — Share Based Payments (“IFRS 2”), and is recognised pursuant to the attached vesting conditions.

The incremental fair value of the 2015 award conversion was calculated as the difference between the original stock option valued using the Black Scholes option pricing model as at the date of conversion, and the RSU value on the conversion date. The incremental fair value attributed to the conversion was $0.3 million, of which $0.2 million was recognized during 2015 and the remaining incremental fair value will be recognized over the remaining term of the RSU awards.

Options issued during the year ended 31 December 2013:

	Number of	Estimated Fair
Grant Date	Options	Value (US$’000)		Vesting Conditions
1 April 2013	350,000	$	217	20% issuance date, 20% first four anniversaries
24 September 2013	950,000	$	475	20% issuance date, 20% first four anniversaries
Total	1,300,000	$	692

The following table summarises the key assumptions used to calculate the estimated fair value awarded or granted during the year ended 31 December 2013:

		2013
Share price:		A$1.06 — A$1.10
Exercise price:		A$1.25 — 1.40
Expected volatility:		60%
Option term:		5.75 years
Risk free interest rate:		2.82 to 3.10%

Restricted Share Units

During the years ended 31 December 2015, 2014 and 2013, the Board of Directors awarded 13,322,262, 2,839,626 and 1,237,994 RSUs, respectively, to certain employees (of which 3,090,000, 671,988, and 374,248 respectively, granted to the Company’s Managing Director were approved by shareholders). These awards were made in accordance with the long-term equity component of the Company’s incentive compensation plan. Share based payment expense for RSUs awarded was calculated pursuant to AASB 2 / IFRS 2. The fair values of RSUs were estimated at the date they were approved by the Board of Directors (the measurement dates) based on the Company’s share price at the date of grant. The value of the vested portion of these awards has been recognised within the financial statements. This information is summarised for the Group for the years ended 31 December 2015 and 2014, respectively, below:

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The following tables summarise the RSUs issued and their related grant date, fair value and vesting conditions:

RSUs awarded during the year ended 31 December 2015:

Grant Date	Number of RSUs	Estimated Fair Value (US$’000)	Vesting Conditions
27 April 2015	28,874	15	25% on 27 April 2016, 2017, 2018 and 2019
28 May 2015	1,545,113	693	33% on 31 January 2016, 2017 and 2018
28 May 2015	1,545,113	1,039	0% - 200% based on 3 year total shareholder return as compared to peers
24 June 2015	4,267,002	1,713	33% on 31 January 2016, 2017 and 2018
24 June 2015	2,815,681	1,609	0% - 200% based on 3 year total shareholder return as compared to peers
24 June 2015	2,809,479	1,128	100% vested upon issuance
1 September 2015	321,000	82	33% on 31 January 2016, 2017 and 2018
	13,332,262	6,279

RSUs awarded during the year ended 31 December 2014:

Grant Date	Number of RSUs	Estimated Fair Value (US$’000)		Vesting Conditions
15 April 2014	1,842,638	$	1,611	25% issuance date, 25% first three anniversaries
5 May 2014	135,000	123		33% issuance date, 33% on 1 January 2015 and 2016
12 May 2014	190,000	172		33% issuance date, 33% first two anniversaries
30 May 2014	671,988	680		25% issuance date, 25% first three anniversaries
	2,839,626	$	2,586

RSUs awarded during the year ended 31 December 2013:

		Estimated Fair
Grant Date	Number of RSUs	Value (US$’000)		Vesting Conditions
19 April 2013	863,746	$	789	25 % issuance date, 25% first three anniversaries
28 May 2013	374,248	354		25 % issuance date, 25% first three anniversaries
	1,237,994	$	1,143

Upon vesting, and after a certain administrative period, the RSUs are converted to ordinary shares of the Company. Once converted to ordinary shares, the RSUs are no longer restricted. As the daily closing price of the Company’s ordinary shares approximates its estimated fair value at that time, the Company used the grant date closing price to estimate the fair value of the RSUs.

The total share based compensation expense for the years ended 31 December 2015, 2014 and 2013 was $4.1 million, $1.9 million and $1.6 million respectively.

Subsequent to 31 December 2015, the Board granted 9,136,047 RSUs that vest between 0% and 133% based on Company’s three year absolute total shareholder return.

NOTE 32 — RELATED PARTY TRANSACTIONS

N Martin was previously a partner of Minter Ellison Lawyers and is now a consultant for Minter Ellison Lawyers as well as a Director of the Company. Minter Ellison Lawyers were paid an immaterial amount for legal services for the years ended 31 December 2015 and 2014. Legal fees paid to Minter Ellison for the year ended 31 December 2013 totaled $0.2 million.

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NOTE 33 — FINANCIAL RISK MANAGEMENT

a) Financial Risk Management Policies

The Group is exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. The Group’s risk management strategy focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. The Group has historically used derivative financial instruments to hedge exposure to fluctuations in interest rates and commodity prices. The Group’s financial instruments consist mainly of deposits with banks, short term investments, accounts receivable, derivative financial instruments, finance facility, and payables. The main purpose of non-derivative financial instruments is to raise finance for the Group operations.

i) Treasury Risk Management

Financial risk management is carried out by Management. The Board sets financial risk management policies and procedures by which Management are to adhere. Management identifies and evaluates all financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by the Board.

ii) Financial Risk Exposure and Management

The Group’s interest rate risk arises from its borrowings. Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Group’s exposure to the risk of changes in market interest rates relates primarily to the Group’s long-term debt obligations with floating interest rates.

The Company did not have any interest rate swaps in place as at 31 December 2015. As at 31 December 2014, the Group had interest rate swaps with a notional contract amount of $15.0 million. The net fair value of interest rate swaps at 31 December 2014 was relatively immaterial, comprising long-term assets of $0.1 million and current liabilities of $0.1 million. These amounts were recognised as Level 2 fair value derivatives. (See Note 14)

iii) Commodity Price Risk Exposure and Management

The Board actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of the Group’s hedging activity are continually monitored against Group policy. The Group sells its oil on market using Nymex West Texas Intermediary (WTI) and Louisiana Light Sweet (LLS) market spot rates reduced for basis differentials in the basins from which the Company produces. Gas is sold using Henry Hub (HH) and Houston Ship Channel (HSC) market spot prices. Forward contracts are used by the Group to manage its forward commodity price risk exposure. The Group’s policy is to hedge at least 50% of its proved developed reserves through 2019 and for a rolling 36 month period thereafter, as required by its Credit Agreement. The Group has not elected to utilise hedge accounting treatment and changes in fair value are recognised in the statement of profit or loss and other comprehensive income.

A summary of the Company’s outstanding hedge positions as at 31 December 2015 is below:

Oil Derivatives Year	Units (Bbls)	Floor (1)		Weighted Average Ceiling
2016	1,037,063	$	50.63	$	76.14
2017	624,000	$	47.53	$	79.92
2018	444,000	$	51.47	$	81.53
2019	168,000	$	52.51	$	87.71
Total	2,273,063	$	50.08	$	80.49

Gas Derivatives Year	Units (MMbtu)	Floor (1)		Weighted Average Ceiling
2016	2,040,000	$	2.54	$	3.58
2017	1,320,000	$	2.85	$	3.91
2018	930,000	$	3.00	$	4.32
2019	360,000	$	3.27	$	4.65
Total	4,650,000	$	2.78	$	4.01

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(1) The Company’s outstanding derivative positions include swaps totaling 1,491,063Bbls and 2,610,000 Mcf, which are included in the weighted average floor value, but have no corresponding ceiling.

b) Net Fair Value of Financial Assets and Liabilities

The net fair value of cash and cash equivalent and non-interest bearing monetary financial assets and financial liabilities of the consolidated entity approximate their carrying value.

The net fair value of other monetary financial assets and financial liabilities is based on discounting future cash flows by the current interest rates for assets and liabilities with similar risk profiles. Other than the Junior Credit Facility, the balances are not materially different from those disclosed in the consolidated statement of financial position of the Group.

c) Credit Risk

Credit risk for the Group arises from investments in cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers including outstanding receivables and committed transactions, and represents the potential financial loss if counterparties fail to perform as contracted. The Group trades only with recognised, creditworthy third parties.

The maximum exposure to credit risk, excluding the value of any collateral or other security, at balance date to recognise the financial assets, is the carrying amount, net of any impairment of those assets, as disclosed in the balance sheet and notes to the financial statements. Receivable balances are monitored on an ongoing basis at the individual customer level.

At 31 December 2015, the Group had one customer that owed the Group approximately $4.8 million and accounted for approximately 83% of total accrued revenue receivables. For joint interest billing receivables, if payment is not made, the Group can withhold future payments of revenue, as such, there is minimal to no credit risk associated with these receivables.

d) Liquidity Risk

Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The Group’s approach to managing liquidity is to ensure that it will have sufficient liquidity to meet its liabilities as they become due, without incurring unacceptable losses or risking damage to the Group’s reputation. The Group manages liquidity risk by maintaining adequate reserves and banking facilities by continuously monitoring forecast and actual cash flows, and by matching the maturity profiles of financial assets and liabilities.

Year ended 31 December 2015	Total	Less than 1 year	1 – 5 years	More than 5 years

Trade and other payable	21,588	21,588	—	—
Accrued expenses	19,883	19,883	—	—
Credit facilities payments, including interest (1)	247,259	12,420	234,839	—
Total	288,730	53,891	234,839	—

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Year ended 31 December 2014	Total	Less than 1 year	1 – 5 years	More than 5 years

Trade and other payable	46,861	46,861	—	—
Accrued expenses	72,333	72,333	—	—
Derivative financial liabilities	130	130	—	—
Credit facilities payments, including interest	147,994	5,502	142,492	—
Total	267,318	124,826	142,492	—

(1) Assumes credit facilities are held to maturity. However, if the Company sells its assets held for sale, it may be required to repay a portion of the credit facilities from the sales proceeds.

e) Market Risk

Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments affected by market risk include loans and borrowings, deposits, trade receivables, trade payables, accrued liabilities and derivative financial instruments.

Commodity Price Risk

The Group is exposed to the risk of fluctuations in prevailing market commodity prices on the mix of oil and gas products it produce.

Commodity Price Risk Sensitivity Analysis

The table below summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are and therefore adjusted to fair value through profit and loss. The analysis assumes that the crude oil and natural gas price moves $10 per barrel and $0.50 per mcf, with all other variables remaining constant, respectively.

	2015		2014
Year ended 31 December	US$’000		US$’000

Effect on profit before tax
Increase / (Decrease)
Oil
- improvement in US$ oil price of $10 per barrel	(22,731	)	(2,400	)
- decline in US$ oil price of $10 per barrel	22,731		3,041
Gas
- improvement in US$ gas price of $0.50 per mcf	(2,325	)	(120	)
- decline in US$ gas price of $0.50 per mcf	2,325		120

Interest Rate Risk

Interest rate risk is the risk that the fair value of the future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Group’s exposure to the risk of changes in market interest rates relates primarily to the Group’s long- term debt obligations with floating interest rates.

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Interest Rate Sensitivity Analysis

Based on the net debt position as at 31 December 2015 and 2014 (taking into account the 2014 interest rate swap) with all other variables remaining constant, the following table represents the effect on income as a result of changes in the interest rate. The impact on equity is the same as the impact on profit before tax.

Year ended 31 December	2015 US$’000		2014 US$’000
Effect on profit before tax
Increase / (Decrease)
- increase in interest rates + 2%	(1,140	)	(906	)
- decrease in interest rates - 2%	112		184

This assumes that the change in interest rates is effective from the beginning of the financial year and the net debt position and fixed/floating mix is constant over the year. However, interest rates and the debt profile of the Group are unlikely to remain constant and therefore the above sensitivity analysis will be subject to change.

NOTE 34—PARENT COMPANY INFORMATION

a) Cost Basis

	2015		2014
Year ended 31 December	US$’000		US$’000
Parent Entity
Assets
Current assets	18,131		9,108
Investment in subsidiaries	37,937		159,606
Deferred tax assets	1,913		3,998
Related party note receivable	112,481		112,481
Total assets	170,463		285,193
Liabilities
Current liabilities	54		34
Non-current liabilities	—		—
Total Liabilities	54		34
Total net assets	170,409		285,159
Equity
Issued capital	308,430		306,853
Share options reserve	386		386
Foreign currency translation	(48,215	)	(30,539	)
Retained earnings (loss)	(90,192	)	8,459
Total equity	170,409		285,159

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Year ended 31 December	2015 US$’000		2014 US$’000		2013 US$’000
Financial Performance
Profit/(loss) for the period before equity in income of subsidiaries	(98,651	)	7,334		275
Other comprehensive income	(17,675	)	(10,030	)	(31,307	)
Total profit or loss and other comprehensive income	(116,326	)	(2,696	)	(31,032	)

b) Equity Basis

Year ended 31 December	2015 US$’000		2014 US$’000
Parent Entity
Assets
Current assets	18,132		9,108
Investment in subsidiaries	37,937		309,453
Deferred tax assets	1,913		3,998
Related party note receivable	112,481		112,481
Total assets	170,463		435,040
Liabilities
Current liabilities	54		34
Non-current liabilities	—		—
Total Liabilities	54		34
Total net assets	170,409		435,006
Equity
Issued capital	308,429		306,853
Share options reserve	11,650		7,550
Foreign currency translation	(1,310	)	(832	)
Retained earnings (loss)	(148,360	)	121,435
Total equity	170,409		435,006

	2015		2014	2013
Year ended 31 December	US$’000		US$’000	US$’000
Financial Performance
Profit/(loss) for the period before equity in income of subsidiaries	6,225		7,334	275
Equity in income of subsidiaries	(276,020	)	7,987	15,667
Other comprehensive income	(478	)	684	(421	)
Total profit or loss and other comprehensive income	(270,273	)	16,005	15,521

c) Cash Flow

	2015		2014		2013
Year ended 31 December	US$’000		US$’000		US$’000
Cash flow from operating activities	(17,772	)	(70,216	)	(42,934	)
Cash flow from investing activities	1,243		9,415		(136,890	)
Cash flow from financing activities	5,676		71,761		179,904

NOTE 35 — DEED OF CROSS GUARANTEE

Pursuant to Class Order 98/1418, the wholly-owned subsidiary, Armadillo Petroleum Limited (“APL”), is relieved from the Corporations Act 2001 requirements for preparation, audit and lodgement of its financial reports.

As a condition of the Class Order, SEAL and APL (“the Closed Group”) have entered into a Deed of Cross Guarantee (“Deed”). The effect of the Deed is that SEAL has guaranteed to pay any deficiency in the event of the winding up of APL under certain provision of the Corporations Act 2001. APL has also given a similar guarantee in the event that SEAL is wound up.

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Set out below is a condensed consolidated statement of financial position of the Closed Group:

	2015		2014
Year ended 31 December	US$’000		US$’000

Current assets
Cash and cash equivalents	245		11,506
Trade and other receivables	3,426		—
Other current assets	10,001		185
Assets held for sale	5,234
Total current assets	18,906		11,691

Non-current assets
Exploration and evaluation expenditure	40		45
Related party note receivable	112,481		112,481
Deferred tax assets	1,913		3,998
Investment in subsidiaries	36,543		158,047
Total non-current assets	150,977		274,571

Total assets	169,883		286,262

Current liabilities
Trade and other payables	31		988
Accrued expenses	1,542		13
Total current liabilities	1,573		1,001

Non-current liabilities
Deferred tax liabilities	3		3
Total non-current liabilities	3		3

Total liabilities	1,576		1,004

Net assets	168,307		285,258

Equity
Issued capital	308,429		306,853
Share option reserve	386		386
Foreign currency translation	(48,224	)	(30,553	)
Retained earnings (accumulated deficit)	(92,284	)	8,572
Total equity	168,307		285,258

NOTE 36 — EVENTS AFTER THE BALANCE SHEET DATE

No significant matters occurred subsequent to 31 December 2015, but prior to the issuance of this Report.

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NOTE 37—UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES

Costs Incurred

The following table sets forth the capitalised costs incurred in our oil and gas production, exploration, and development activities:

(in thousands)	Year ended 31 December 2015		Year ended 31 December 2014		Year ended 31 December 2013
Property acquisition costs
Proved(1)	$	13,170	$	2,244	158,116
Unproved(1)	15,495		34,184		60,690
Exploration costs	10,353		2,929		1,338
Development costs (1)	76,831		350,196		219,121
	$	115,859	$	389,554	439,265

(1) 2013 property acquisition costs include acquisition date fair value of $157.2 million and $47.3 million for proved and unproved assets acquired related to the Texon merger, which was primarily a non-cash business combination.

(2) 2015, 2014 and 2013 development costs include $16.6 million, $49.2 million and $55.6 million of costs associated with non-producing wells in progress as at 31 December 2015, 2014 and 2013 respectively. These 7wells in progress were either drilling, waiting on hydraulic fracturing or production testing at year-end.

SEC Oil and Gas Reserve Information

Ryder Scott Company, L.P., an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interest owned by the Company as of December 31, 2015. The technical person primarily responsible for the estimates set forth in the reserves report is Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado and Texas with over 10 years of practical experience in estimation and evaluation of petroleum reserves.

Netherland, Sewell & Associates, Inc., an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interest owned by the Company as of December 31, 2014 and 2013. The technical person primarily responsible for the estimates set forth in the reserves report is Mr. Neil H. Little. Mr. Little is a Licensed Professional Engineer in the State of Texas with over 12 years of practical experience in petroleum engineering studies and over 5 years of practical experience in evaluation of reserves.

Proved reserves are those quantities of oil and natural gas, which, by analysis of geosciences 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.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process.

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The following reserve data represents estimates only and should not be construed as being exact. All such reserves are located in the continental United States.

	Oil (MBbl)		Natural Gas (MMcf)		NGL (MBbl)		Total Oil Equivalents (MBbl)
Total proved reserves:
31 December 2012	5,758		16,888		—		8,572
Revisions of previous estimates	(1,160	)	(4,091	)	74		(1,767
Extensions and discoveries	7,081		16,270		1,946		11,739
Purchases of reserves in-place	3,857		4,674		758		5,393
Production	(827	)	(934	)	(96	)	(1,079
Sales of reserves in-place	(1,753	)	(2,152	)	—		(2,111
31 December 2013	12,956		30,655		2,683		20,747
Revisions of previous estimates	(143	)	(1,395	)	(580	)	(955	)
Extensions and discoveries	9,275		16,003		2,330		14,272
Purchases of reserves in-place	64		28		1		70
Production	(1,675	)	(1,803	)	(268	)	(2,244	)
Sales of reserves in-place	(3,451	)	(14,754	)	—		(5,910	)
31 December 2014	17,026		28,733		4,166		25,981
Revisions of previous estimates	(3,491	)	(8,152	)	(1,218	)	(6,068	)
Extensions and discoveries	1,950		4,122		699		3,336
Purchases of reserves in-place	3,896		4,454		238		4,876
Production	(1,829	)	(2,581	)	(393	)	(2,652	)
Sales of reserves in-place	—		—		—		—
31 December 2015	17,552		26,576		3,492		25,473
Proved developed reserves:
31 December 2013	4,140		10,765		1,087		7,021
31 December 2014	6,124		12,364		1,801		9,985
31 December 2015	6,379		13,205		1,998		10,578
Proved undeveloped reserves
31 December 2013	8,816		19,890		1,596		13,726
31 December 2014	10,903		16,369		2,365		15,996
31 December 2015	11,173		13,371		1,494		14,895

Proved Undeveloped Reserves

At December 31, 2015, the Company’s proved undeveloped reserves were approximately 14,895 MBoe, a decrease of approximately 1,101 MBoe over its December 31, 2014 proved undeveloped reserves estimate of approximately 15,996 MBoe. The change primarily consisted of downward revisions to previous estimates of approximately 6,836 MBoe and a decrease of 1,494 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves during 2015, offset by extensions and discoveries of 2,540 MBoe (Eagle Ford) and purchases of reserves of 4,690 MBoe (Eagle Ford, primarily from the Company’s acquisition of NSE’s Eagle Ford assets in August 2015). The revisions to previous estimates were attributable to the Mississippian/Woodford, which decreased by 4,757 Mboe, and Eagle Ford, which decreased 2,079 MBoe.

Over the next five years, the Company expects to fund its future development costs associated with proved undeveloped reserves of $291.5 million with operating cash flows from its existing proved developed reserves and proved undeveloped reserves that are expected to be converted to proved developed reserves. Using the December 31, 2015 SEC price assumptions, the Company’s proved reserves operating cash flows are expected to be approximately $393.7 million (undiscounted, before income taxes (if any)). As such, the Company expects all proved undeveloped locations that are scheduled and included in the Company’s reserves will be spud within the next five years.

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Standardized Measure of Future Net Cash Flow

The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and natural gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves which are based on SEC-defined pricing as discussed further below. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth our Standardized Measure:

(in thousands)	Year ended 31 December 2015			Year ended 31 December 2014			Year ended 31 December 2013
Cash inflows	$	936,041		$	1,822,997		$	1,407,871
Production costs	(246,277		)	(444,369		)	(393,300		)
Development costs	(308,253		)	(411,110		)	(382,259		)
Income tax expense	(1,602		)	(182,999		)	(137,994		)
Net cash flow	379,909			784,520			494,318
10% annual discount rate	(198,142		)	(349,014		)	(226,155		)
Standardized measure of discounted future net cash flow	$	181,767		$	435,506		$	268,163

The following are the principal sources of change in the Standardized Measure:

(in thousands)	Year ended 31 December 2015			Year ended 31 December 2014			Year ended 31 December 2013
Standardized Measure, beginning of period	$	435,506		$	268,163		$	115,547
Sales, net of production costs	(67,693		)	(139,304		)	(66,962		)
Net change in sales prices, net of production costs	(369,770		)	37,325			6,450
Extensions and discoveries, net of future production and development costs	11,609			252,527			182,267
Changes in future development costs	28,092			21,115			16,222
Previously estimated development costs incurred during the period	31,007			119,164			13,854
Revision of quantity estimates	(91,440		)	(27,495		)	(33,809		)
Accretion of discount	53,173			33,698			13,558
Change in income taxes	95,827			(27,408		)	(48,786		)
Purchases of reserves in-place	442			2,863			131,043
Sales of reserves in-place	—			(67,754		)	(36,935		)
Change in production rates and other	55,014			(37,388		)	(24,286		)
Standardized Measure, end of period	$	181,767		$	435,506		$	268,163

Impact of Pricing

The estimates of cash flows and reserve quantities shown above are based upon the unweighted average first-day-of-the- month prices for the previous twelve months. If future gas sales are covered by contracts at specified prices, the contract prices would be used. Fluctuations in prices are due to supply and demand and are beyond our control.

F-50

Table of Contents

EXHIBIT INDEX

Exhibit
Number		Description of Exhibit

1.1		Constitution of Sundance Energy Australia Limited (incorporated by reference from Exhibit 4.10 of the Company’s 20-F filing dated July 11, 2014)

4.1		Credit Agreement, dated as of May 14, 2015, among Sundance Energy Australia Limited, Sundance Energy, Inc., as borrower, Morgan Stanley Energy Capital, Inc., as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 4.1 of the Company’s 20-F dated May 15, 2015)

4.2		Guarantee and Collateral Agreement, dated as of May 14, 2015, by Sundance Energy Australia Limited, Sundance Energy Inc. and other guarantor party thereto, in favor of Morgan Stanley Energy Capital Inc., as administrative agent (incorporated by reference from Exhibit 4.2 of the Company’s 20-F dated May 15, 2015)

4.3		Form of Deed of Access, Insurance and Indemnity for Directors and Officers (incorporated by reference from Exhibit 4.9 of the Company’s 20-F filing dated July 11, 2014)

4.4		Form of Employment Agreement, by and between Sundance Energy Inc. and Eric P. McCrady*

8.1		List of significant subsidiaries of Sundance Energy Australia Limited (incorporated by reference from Exhibit 8.1 of the Company’s 20-F filing dated July 11, 2014)

12.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**

12.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002**

13.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

13.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

15.1		Consent of Ernst and Young.**

15.2		Consent of Ryder Scott Company to use its report. *

15.3		Consent of Netherland, Sewell & Associates, Inc. to use its reports. *

15.4		Report of Ryder Scott Company regarding the Company’s estimated proved reserves as of December 31, 2015 dated April 30, 2016*

15.5		Report of Netherland, Sewell & Associates, Inc. regarding the Company’s estimated proved reserves as of December 31, 2014 dated April 27, 2015 (incorporated by reference from Exhibit 15.2 of the Company’s 20-F dated May 15, 2015)

15.6		Report of Netherland, Sewell & Associates, Inc. regarding the Company’s estimated proved reserves as of December 31, 2013 dated July 3, 2014 (incorporated by reference from Exhibit 15.10 of the Company’s 20-F filing dated July 11, 2014)

*		Previously filed with the Annual Report on Form 20-F on May 2, 2016.
**		Filed herewith.

Year ended 31 December	2015 US$000	2014 US$000	2013 US$000
Short term wages and benefits	1,467	1,465	1,539
Share based payments (1)	2,271	1,208	625
Post-employment benefit	52	57	55
	3,790	2,730	2,220

	Page
Part I

Item 3. Key Information	2
Item 5. Operating and Financial Review and Prospects	22

Part III

Item 18. Financial Statements	38
Item 19. Exhibits	38

Sundance Energy Australia Limited
	Report of Registered Public Accounting Firm	F-2
	Consolidated Statement of Profit or Loss and Other Comprehensive Income (Loss) for the Years Ended December
	31, 2015, 2014 and 2013	F-3
	Consolidated Statement of Financial Position, December 31, 2015 and 2014	F-4
	Consolidated Statement of Changes in Equity for the Years Ended December 31, 2015, 2014 and 2013	F-5
	Consolidated Statement of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	F-6
	Notes to the Consolidated Financial Statements	F-7

	Number		Weighted Average Fair Value at Measurement
	of RSUs		Date A$
Outstanding at 31 December 2013	1,704,307		0.83
Issued	2,839,626		0.97
Converted to ordinary shares	(1,479,978	)	0.89
Forfeited	(99,778	)	0.92
Outstanding at 31 December 2014	2,964,177		0.93
Issued or Issuable	13,322,262		0.53
Converted to ordinary shares	(3,805,789	)	0.63
Forfeited	(46,312	)	0.93
Outstanding at 31 December 2015	12,434,338		0.55

	SUNDANCE ENERGY AUSTRALIA LIMITED


	By:	/s/ Eric P. McCrady
		Name:	Eric P. McCrady
		Title:	Chief Executive Officer

Date: February 24, 2017