UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Sundance Energy Australia Limited
(Exact name of registrant as specified in its charter)

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earliest effective registration statement for the same offering. o

(1): American depositary shares, or ADSs, issuable upon deposit of the ordinary shares registered hereby will be registered under a separate registration statement on Form F-6 (Registration No. 333- ). Each ADS represents ordinary shares.
(2): Includes (i) all ordinary shares represented by ADSs initially offered and sold outside the United States that may be resold from time to time in the United States either as part of the distribution or within 40 days after the later of the effective date of this registration statement and the date the securities are first bona fide offered to the public, and (ii) additional ordinary shares represented by ADSs that are issuable upon the exercise of the underwriters' option to purchase additional shares to cover over-allotments, if any.
(3): Estimated solely for the purpose of determining the amount of the registration fee in accordance with Rule 457(o) under the Securities Act of 1933, as amended.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

This is the initial public offering in the United States of Sundance Energy Australia Limited, an Australian corporation. We are offering American Depositary Shares, or ADSs. Each ADS will represent ordinary shares.

Prior to this offering, there has not been a public market for the ADSs. We have applied for a listing of the ADSs on The NASDAQ Global Select Market under the symbol "SNDE."

Our ordinary shares are listed on the Australian Securities Exchange under the symbol "SEA." On 2013, the closing price of our ordinary shares on the Australian Securities Exchange was A$ per ordinary share, equivalent to $ per ADS based on an exchange rate of A$ to $1.00.

We are an "emerging growth company," as such term is used in the Jumpstart Our Business Startups Act of 2012, and, as such, we have elected to comply with certain reduced public company reporting requirements.

Investing in the ADSs involves risks. See "Risk Factors" beginning on page 19.

We have agreed to reimburse the underwriters for certain FINRA related expenses. See "Underwriting."

We have granted the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional ADSs from us at the public offering price less the underwriting discount to cover overallotments, if any.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Delivery of the ADSs will be made against payment in New York, New York, on or about , 2014.

You may rely only on the information contained in this prospectus. Neither we nor any of the underwriters have authorized anyone to provide information different from that contained in this prospectus. When you make a decision about whether to invest in the ADSs, you should not rely upon any information other than the information in this prospectus. Neither the delivery of this prospectus nor the sale of ADSs means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy the ADSs in any circumstances under which the offer of solicitation is unlawful.

We have not taken any action to permit a public offering of the ADSs outside the United States or to permit the possession or distribution of this prospectus outside the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about and observe any restrictions relating to the offering of the ADSs and the distribution of this prospectus outside of the United States.

Until , 2014 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

We have also provided definitions for certain oil and natural gas terms used in this prospectus in the "Glossary of Oil and Natural Gas Terms" beginning on page A-1 of this prospectus.

Effective July 1, 2011, our reporting and functional currency became the U.S. dollar. Solely for the convenience of the reader, this prospectus contains translations of certain Australian dollar amounts into U.S. dollars at specified rates. Except as otherwise stated in this prospectus, all translations from Australian dollars to U.S. dollars are based on the noon buying rate of the City of New York for cable transfers of Australian dollars, as certified for customs purposes by the Federal Reserve Bank of New York on the date and year indicated. See "Exchange Rate Information." No representation is made that the Australian dollar amounts referred to in this prospectus could have been or could be converted into U.S. dollars at such rate.

Effective July 1, 2012, we changed our fiscal year end from June 30 to December 31. This change resulted in a six-month reporting period for our fiscal period ended December 31, 2012. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and the related notes thereto beginning on page F-1 of this prospectus.

Unless otherwise indicated, the consolidated financial statements and related notes included in this prospectus have been prepared in accordance with Australian Accounting Standards and also comply with International Financial Reporting Standards ("IFRS") and interpretations issued by the International Accounting Standards Board ("IASB"), which differ in certain significant respects from Generally Accepted Accounting Principles in the United States ("GAAP"). See "Management's Discussion and Analysis of Financial Condition and Results of Operations — Certain Differences Between IFRS and GAAP." Our reserve disclosures included in the financial statements have been prepared in accordance with GAAP.

This prospectus includes information with respect to market and industry conditions and market share from third party sources or that is based upon estimates using such sources when available. We believe that such information and estimates are reasonable and reliable. We also believe the information extracted from publications of third party sources has been accurately reproduced. However, we have not independently verified any of the data from third party sources. Similarly, our internal research is based upon the understanding of industry conditions, and such information has not been verified by any independent sources.

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus and is qualified in its entirety by the more detailed information and financial statements included elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in the ADSs. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings "Risk Factors," "Cautionary Note Regarding Forward-Looking Statements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical consolidated financial statements and the related notes to those financial statements included elsewhere in this prospectus. The information presented in this prospectus assumes that the underwriters' option to purchase additional ADSs is not exercised.

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 our current operational activities are focused in south Texas targeting the Eagle Ford formation ("Eagle Ford"), north central Oklahoma targeting the Mississippian and Woodford formations ("Mississippian/Woodford"), the Wattenberg field in central Colorado targeting the Codell and Niobrara formations ("Wattenberg Field") and northwest North Dakota targeting the Bakken and Three Forks formations ("Bakken") in the Williston Basin.

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 September 30, 2013, we operated approximately 80% of our developed acreage with an average working interest of approximately 88% with respect to such operated developed acreage.

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 investment, 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. We believe that the execution of this strategy is best illustrated by the growth in our operated production as compared to total net production as reflected in the following chart:

In line with our business strategy, we have divested several non-core assets, including the sale of our interest in properties located in the South Antelope field of the Williston Basin, North Dakota, in September 2012, which resulted in net proceeds of approximately $172 million. In addition, in October and November 2013 we entered into agreements to sell our interest in the Phoenix prospect of the Williston Basin, which we expect will result in aggregate net proceeds of approximately $39.1 million, subject to customary closing conditions. We have historically used the proceeds from our strategic asset divestitures towards the development of our operated, high working interest projects and to fund potential acquisition opportunities that fit our strict investment guidelines. We intend to continue to use the proceeds from our strategic asset divestitures in this manner to the extent we believe it meets our business and growth objectives.

Our average daily production rate, net of royalties, for the month of September 2013 was approximately 3,855 Boe/d, which consisted of approximately 80% oil. The following table presents summary acreage and production data for each of our operating areas as of September 30, 2013:

	Average Daily Net Production

	(Boe/d)(1)
Eagle Ford		2,119	9,732	7,959
Mississippian/Woodford		514	75,690	44,809
Wattenberg Field		323	5,676	5,023
Bakken		899	100,153	4,778

Total		3,855	191,251	62,569

(1): Represents production (Boe/d) for the month ended September 30, 2013. Average daily net production increased from approximately 1,415 Boe/d for the six-month period ended December 31, 2012, to approximately 3,855 Boe/d for the month ended September 30, 2013, primarily due to additional wells drilled and completed and the acquisition of 7 gross (6.0 net) productive wells in connection with our acquisition of Texon Petroleum Limited discussed below (See "Recent Developments — Acquisitions").
(2): Excludes approximately 35,909 gross (9,789 net) acres located in the greater Denver-Julesburg Basin that are outside the Wattenberg Field to which we do not currently allocate any of our capital expenditure budget.
(3): Does not give effect to the sale of our interest in the Phoenix prospect subsequent to September 30, 2013. See "Recent Developments — Divestitures."

Netherland Sewell estimated our proved reserves to be 14.3 MMBoe as of June 30, 2013, of which approximately 72% were oil and approximately 28% were liquids-rich natural gas, with a PV-10 of approximately $237.6 million. See "Summary Reserve and Operations Data — PV-10." The following table presents summary reserve data for each of our major operating areas as of June 30, 2013:

	Estimated Total Proved Reserves

	Oil		Natural Gas		Total		PV-10
	(MBbls)		(MMcf)		(MBoe)		($ millions)(1)
Eagle Ford		3,585		4,592		4,350	$	77.3
Mississippian/Woodford		1,041		3,183		1,571		18.3
Wattenberg Field		2,401		12,263		4,445		72.6
Bakken		3,231		4,318		3,951		69.4

Total		10,258		24,356		14,317	$	237.6

(1): PV-10 is considered a non-GAAP financial measure under SEC regulations. See "Summary Reserve and Operations Data — PV-10."

Our 2013 capital budget for the drilling and completion of oil and natural gas wells within our major operating areas is approximately $226 million. For the nine-month period ended September 30, 2013, we spent approximately $128 million drilling 70 gross (38.8 net) wells and approximately $12 million towards leasehold acquisitions and seismic surveys. We anticipate that the majority of our remaining 2013 capital expenditure budget will be spent on the drilling and completion of wells in our major operating areas. We plan to finance our ongoing expenditures using internally generated cash flow, borrowings under our credit facilities and the proceeds from this offering. See "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources." The following table presents a summary of our actual capital expenditures for the period beginning January 1, 2013 and ending September 30, 2013, our estimated capital expenditures for the remainder of 2013, total capital expenditures for 2013, and gross and net estimated wells that we expect to be drilled in each of our major operating areas during 2013:

	Capital Expenditures

			Estimate for October 1, 2013 through December 31, 2013				Estimated Wells for 2013
	Actual through September 30, 2013
					Total for 2013
(In $ millions)					Total for 2013		Gross		Net
Eagle Ford	$	81	$	65	$	146		24		20.0
Mississippian/Woodford		46		19		65		24		12.8
Wattenberg Field		7		2		9		29		17.8
Bakken		6		—		6		12		0.8

Total	$	140	$	86	$	226		89		51.4

The following table presents for each of our major operating areas a summary of our identified gross and net drilling locations as of June 30, 2013 and producing well data as of September 30, 2013:

	Identified Drilling Locations as of June 30, 2013(1)

	Proved Undeveloped Drilling Locations(2)				Probable/ Possible Drilling Locations(2)				Total Drilling Locations				Producing Wells as of September 30, 2013
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Eagle Ford		15		15.0		73		52.5		88		67.5		14		12.3
Mississippian/Woodford		13		6.8		948		225.3		961		232.1		12		5.5
Wattenberg Field		105		59.8		104		53.8		209		113.6		83		59.2
Bakken		139		7.2		717		16.1		856		23.3		131		5.1

Total		272		88.8		1,842		347.7		2,114		436.5		240		82.1

(1): The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results, and other factors. For a discussion of the risks associated with our drilling program, see "Risk Factors — Risks Related to the Oil and Natural Gas Industry and Our Business — 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."
(2): Represents identified gross and net drilling locations booked as proved undeveloped in Netherland Sewell's reserve report as of June 30, 2013.

Our Properties

Eagle Ford

Our Eagle Ford properties consist of approximately 9,732 gross (7,959 net) acres that are primarily located in northeastern McMullen County, Texas, in the oil window of the Eagle Ford trend. In March 2013, we acquired the majority of these properties through a merger with Texon Petroleum Limited ("Texon"). The purchase price for Texon was approximately $158.4 million, which involved the issuance of 122,669,678 of our ordinary shares to Texon shareholders. The purchase price includes: $132.1 million in value of ordinary shares, based upon the closing price of our ordinary shares on March 8, 2013, the effective date of the merger; and $26.3 million in cash used to fund capital expenditures between the November 13, 2012 merger announcement and effective date of the merger. In addition the Company assumed $45.4 million of deferred and current tax liabilities recognized primarily due to the difference between the book value of the assets and the fair value of consideration paid by us. As of December 31, 2012, Texon had approximately 7,735 gross (7,336 net) acres in the Eagle Ford, 5 gross (4.5 net) producing wells, and proved reserves of approximately 1.6 MMBoe. During 2013, Texon drilled and completed another 2 gross (1.5 net) wells resulting in 7 gross (6.0 net) producing wells as of March 8, 2013. During March 2013, the Texon properties had average net daily production of approximately 717 Boe/d.

As of September 30, 2013, we were running a two-rig horizontal development program and, during September 2013, we had average net daily production of approximately 2,119 Boe/d from our Eagle Ford properties. Since our acquisition of the Texon properties in March 2013 through September 30, 2013, we have spent $81 million drilling a total of 14 gross (11.8 net) Eagle Ford horizontal wells, of which 7 are producing and 7 are awaiting completion. For the remainder of 2013, we expect to spend a total of

approximately $65 million to complete the wells in progress and to drill and/or complete an additional 10 gross (8.2 net) Eagle Ford horizontal wells at an average gross well cost of $8.5 million.

Mississippian/Woodford

The Mississippian/Woodford formation spans six counties located throughout northeastern Oklahoma and southwestern Kansas. Our properties in the Mississippian/Woodford consist of approximately 75,690 gross (44,809 net) acres that are primarily located in Logan County, Oklahoma along the eastern flank of the Nemaha Ridge. We acquired the majority of these properties through direct mineral leases with the mineral owners. As of September 30, 2013, we were running a two-rig horizontal program to appraise the economic potential of our Mississippian/Woodford properties. From January 1, 2013 to September 30, 2013, we have spent $46 million drilling a total of 20 gross (10.0 net) Mississippian/Woodford wells, of which 9 were producing and 11 were drilling or awaiting completion as of September 30, 2013. During the month of September 2013, we had average net daily production of approximately 514 Boe/d from our Mississippian/Woodford properties. For the nine-month period ended September 30, 2013, we had average net daily production of approximately 389 Boe/d from these properties. For the remainder of 2013, we expect to spend approximately $19 million to complete the wells in progress and to drill and complete an additional 4 gross (2.8 net) Mississippian and Woodford horizontal wells at an average gross well cost of $3.7 and $4.7 million, respectively.

Wattenberg Field

Our Wattenberg Field properties consist of approximately 5,676 gross (5,023 net) acres that are primarily located in Weld County, Colorado. We acquired approximately 48% of these properties through direct mineral leases from mineral owners and approximately 52% of these properties through an acquisition of leases and producing vertical wells in late 2012, in which we acquired 2,686 gross (2,629 net) acres for a purchase price $13.7 million. To date, we have focused the majority of our development activities on drilling vertical wells. From January 1, 2013 to September 30, 2013, we have spent $7 million drilling and/or completing a total of 17 gross (15.3 net) vertical Wattenberg wells and 7 gross (0.9 net) horizontal Niobrara wells, of which 13 were producing and 11 were awaiting completion as of September 30, 2013. During the month of September 2013, we had average net daily production of approximately 323 Boe/d from our Wattenberg Field properties. For the nine-month period ended September 30, 2013, we had average net daily production of approximately 466 Boe/d from these properties.

For the remainder of 2013, we expect to spend approximately $2 million to drill an additional 5 gross (1.6 net) horizontal wells. We currently have no operated rigs drilling horizontal wells in the Wattenberg Field. Capital to be spent throughout the remainder of 2013 will be on horizontal wells being drilled primarily by Encana Corporation at an average gross well cost of $5.3 million per well. We are currently engaged in sub-surface mapping to plan our 2014 horizontal development program for our Wattenberg Field properties.

Bakken

Our Bakken properties consist of approximately 100,153 gross (4,778 net) acres that are primarily located in McKenzie and Williams Counties, North Dakota. The majority of these properties are operated by EOG Resources, Inc. and Hess Corporation. During the month of September 2013, we had average net daily production of approximately 899 Boe/d from our Bakken properties. For the nine-month period ended September 30, 2013, we had average net daily production of approximately 516 Boe/d from our Bakken properties. During 2013, we have spent approximately $6 million to participate in approximately 12 gross (0.8 net) horizontal wells. In October and November 2013, we entered into agreements to sell our interest in our Phoenix prospect located in the Bakken, North

Dakota. See "— Recent Developments — Divestitures." We expect to continue to divest our Bakken assets as we continue to focus on the development of our operated assets in our other major operating areas.

Our Business Strategies

We intend to maximize the value of our core properties through the drilling and development of our undeveloped acreage, which we believe will enable us to increase our production, reserves and cash flows, while generating attractive returns on capital. We intend to accomplish this goal by focusing on the following key strategies:

Increase production through operated development

We intend to maintain an active drilling program to focus on the development of our undeveloped acreage and reserves. As of September 30, 2013, we were running a total of four drilling rigs, with two rigs in the Eagle Ford and two rigs in the Mississippian/Woodford. Upon completion of this offering, we intend to increase our drilling program to five or six rigs, with the additional rigs focused on accelerating the development of our Eagle Ford and Mississippi/Woodford properties. During 2013, we plan to drill 24 gross (20.0 net) horizontal wells in the Eagle Ford, 24 gross (12.8 net) horizontal wells in the Mississippian/Woodford and 12 gross (2.5 net) horizontal wells and 17 gross (15.3 net) vertical wells in the Wattenberg Field and have budgeted approximately $146 million, $65 million and $9 million, respectively, for these drilling and completion expenditures.

Enhance returns through operational efficiencies

As of September 30, 2013, we operated approximately 80% of our developed acreage. This operational control allows us to more efficiently manage the pace of our development activities, leverage efficiencies in the gathering and marketing of our production, and control the pace of our development as well as our operating costs. Our experienced operations team continues to evaluate our operating results against those of other operators in our core areas in order to benchmark our performance relative to other operators to decrease drilling times, optimize completions and increase EURs.

Appraise our current core areas to unlock additional reserve potential

We are testing our Eagle Ford acreage for 60-acre down-spacing potential, which we believe could add 40 incremental net unrisked locations to our drilling inventory. In addition, we expect to have drilled 8 gross (6.0 net) Mississippian and 5 gross (4.2 net) Woodford horizontal operated wells in 2013 to test the economic potential of these formations in our Logan County, Oklahoma, prospect where we hold approximately 59,050 gross (29,691 net) mineral acres as of September 30, 2013.

Pursue accretive acquisition opportunities

We have a history of making acquisitions that have substantial oil-weighted resource potential that we believe can meet our targeted returns on invested capital. We intend to continue to pursue select acquisition opportunities with operational control in areas that are complementary to our existing areas of operations. If returns on our projects fail to meet our expectations in certain areas, we intend to divest those assets and reallocate the capital in our core areas.

Maintain financial flexibility

We seek to maintain a conservative financial position and intend to maintain the financial flexibility to pursue opportunities that fit our operating profile and support our long-term growth strategies.

Our Competitive Strengths

We believe we are well positioned to successfully execute our business strategies and to achieve our business objectives because of the following competitive strengths:

Focus on prolific and liquids-rich resource plays

We have key acreage positions in active areas of the Eagle Ford, the Mississippian/Woodford and the Wattenberg Field. We believe our assets in these plays are characterized by low geological risk and similar repeatable drilling opportunities that we expect will result in a predictable production growth profile. Our portfolio is liquids-focused, with oil representing approximately 78% of our production for the nine-month period ended September 30, 2013, and approximately 72% of our proved reserves as of June 30, 2013.

Extensive, multi-year drilling inventory

We have identified a multi-year inventory of drilling locations in our acreage that we believe provides attractive growth and return opportunities. Pursuant to Netherland Sewell's reserve report as of June 30, 2013, we had identified up to 436.5 net potential drilling locations comprised of 88.8 net proved undeveloped drilling locations and 347.7 net probable and possible drilling locations across our portfolio based on prevailing acre spacing in our core operating areas.

Operating control over the majority of our asset portfolio

Based on our June 30, 2013 reserve report, we operated approximately 66% of our identified proved drilling locations. On a volume basis, we operated approximately 65% of our estimated proved reserves and, excluding the Bakken assets which we intend to divest, held an average working interest of approximately 48% in those reserves. We operated approximately 80% of our developed acreage as of September 30, 2013, approximately 77% of our average daily net production for the nine-month period ended September 30, 2013 and had an average working interest of approximately 91% in those operated wells. We believe that our high level of operational control enables us to develop our resource base in an efficient and cost-effective manner. In addition, our operated positions enable us to better manage the pace of development and allocate our capital expenditures to our highest return projects.

Conservative capital structure

As of September 30, 2013, after giving effect to this offering and the application of the net proceeds therefrom, we expect to have $ million in cash and $ million of available borrowing capacity under our existing credit facilities. We will seek to maintain financial flexibility to allow us to actively develop our drilling, development and exploration activities across our portfolio and maximize the present value of our oil-weighted resource potential.

Experienced executive management and technical teams with proven track record

Our U.S.-based executive management team has an average of over 20 years of oil and natural gas industry experience, most of which has been gained while at Sundance or other public exploration and production companies, including EOG Resources, Inc., Marathon Oil Corporation, Cimarex Energy Company, Baytex Energy, and Key Production Company, Inc. In addition, our technical team has been involved in the development of unconventional assets since 2005 and has extensive experience with vertical and horizontal drilling in the unconventional plays in which we operate. As of the date of this offering, our 11-person technical team consists of operational and exploration geoscientists, drilling, completion, production and reservoir engineers, as well as field personnel dedicated to continually improving our operating and capital efficiency.

Recent Developments

Acquisitions

In March 2013, we completed the merger with Texon, through which we acquired the majority of our assets in the Eagle Ford, consisting of approximately 8,055 gross (7,656 net) acres. Shortly after the acquisition, we changed the name of Texon to Armadillo Petroleum Limited, and we similarly renamed Texon's subsidiaries. The purchase price for the Texon acquisition was approximately $158.4 million, which involved the issuance of approximately 122,669,678 of our ordinary shares to Texon's shareholders. As of December 31, 2012, Texon had approximately 7,735 gross (7,336 net) acres in the Eagle Ford, 5 gross (4.5 net) producing wells and proved reserves of approximately 1.6 MMBoe. During March 2013, Texon had average net daily production of approximately 717 Boe/d.

In December 2012, we acquired approximately 2,686 gross (2,629 net) acres of oil and natural gas properties in the Wattenberg Field for approximately $13.7 million.

Divestitures

In September 2012, we sold our interest in properties located in the South Antelope field of the Williston Basin, North Dakota to a third party for approximately $172 million in net proceeds. At the time of the sale, our interest in properties located in that field included approximately 3,939 net non-operated acres in McKenzie County, North Dakota, with average net daily production of approximately 827 Boe/d during the quarter ended September 30, 2012 and proved reserves of approximately 4.7 MMBoe as of September 2012.

On October 30, 2013, we entered into a purchase and sale agreement to sell our interests in properties located in the Phoenix prospect of the Bakken for $35.5 million. We expect closing to occur in December 2013, subject to customary closing conditions. The assets sold pursuant to the purchase and sale agreement include 77 gross producing wells in McKenzie, Dunn and Mountrail Counties, North Dakota.

On November 1, 2013, we sold our entire interest in an individual operated well and the developed 622 acres, also located in the Phoenix prospect, for gross proceeds of approximately $4.3 million.

In the aggregate, these properties in the Phoenix prospect had an average daily net production of approximately 776 Boe/d for the month ended September 30, 2013. Estimated proved reserves and PV-10 associated with these assets as of June 30, 2013, were 3.1 MMBoe (69% of which were proved undeveloped) and $58.2 million, respectively. We intend to use the net proceeds of $39.1 million from the Phoenix prospect divestitures to fund drilling and/or acquisitions expected in our Eagle Ford, Mississippian/Woodford and Wattenberg properties.

Organizational Structure

The following is the organizational structure of Sundance Energy Australia Limited as of the date of this offering:

All Sundance Energy Australia Limited subsidiaries are wholly owned. Substantially all of our oil and natural gas operations are conducted by our subsidiaries Sundance Energy, Inc. and Armadillo Petroleum Limited and their subsidiaries, Armadillo E&P, Inc., SEA Eagle Ford, LLC and Sundance Energy Oklahoma, LLC. The majority of our corporate general and administrative expenditures are incurred within Sundance Energy, Inc. We completed the divestiture of all of our real property interests located in Australia in 2011.

Credit Facilities

In December 2012, Sundance Energy, Inc. entered into a five-year $300 million credit agreement with Wells Fargo Bank, N.A., as administrative agent, providing for a senior secured revolving credit facility (the "Senior Credit Facility"). The Senior Credit Facility is secured by substantially all of our assets. As of September 30, 2013, the borrowing base was $48 million and there was $15 million outstanding under the Senior Credit Facility.

In August 2013, Sundance Energy, Inc. entered into a five-year $100 million second lien credit agreement with Wells Fargo Energy Capital, Inc., as administrative agent (the "Junior Credit Facility"),

which provides for term loans to be made to us in a series of draws up to the maximum credit amount of $100 million. The Junior Credit Facility has a stated maturity of five years and is secured by a second priority lien on substantially all of our assets. As of September 30, 2013, there was $15 million outstanding under the Junior Credit Facility.

For a description of the material terms of our credit facilities, see "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facilities."

Risk Factors

Investing in the ADSs involves risks that include the speculative nature of oil and natural gas exploration and production, the competitive environment in which we operate, volatile oil and natural gas prices and other material factors. For a discussion of these risks and other considerations that could adversely affect us, including risks related to this offering and the ADSs, see "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

Corporate Information

Sundance Energy Australia Limited was incorporated under the laws of Australia in December 2004. In April 2005, we completed an initial public offering of our ordinary shares and listing of these shares on the Australian Securities Exchange ("ASX").

Our principal office is located at 633 17th Street, Suite 1950, Denver, Colorado 80202. Our telephone number is (303) 543-5700. Our website address is www.sundanceenergy.net. Information on our website and the websites linked to it do not constitute part of this prospectus or the registration statement to which this prospectus forms a part. Our agent for service of process in the United States is Sundance Energy, Inc., which has its principal place of business at 633 17th Street, Suite 1950, Denver, Colorado 80202.

Implications of Being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during our last fiscal year, we qualify as an "emerging growth company" as defined in the Jumpstart Our Business Startups Act of 2012 (the "JOBS Act"). An emerging growth company may avail itself of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we have elected to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002 ("Sarbanes-Oxley Act") relating to internal control over financial reporting, and we will not provide such an attestation from our auditors. We have also elected to rely on an exemption that permits an emerging growth company to include only two years of audited financial statements and only two years of related management's discussion and analysis of financial condition and results of operations disclosure, and we have therefore only included two years of audited financial statements and related management's discussion and analysis of financial condition and results of operations in this prospectus.

We will remain an emerging growth company until the earliest of the following:

•: the end of the fiscal year in which the fifth anniversary of the completion of this offering occurs;
•: the end of the first fiscal year in which the market value of our ordinary shares that are held by non-affiliates is at least $700 million as of the end of the second quarter of such fiscal year;
•: the end of the first fiscal year in which we have total annual gross revenues of at least $1 billion; and
•: the date on which we have issued more than $1 billion in non-convertible debt securities in any rolling three-year period.

Once we cease to be an emerging growth company, we will not be entitled to the exemptions provided for by the JOBS Act.

THE OFFERING


ADSs offered by us		ADSs.
ADSs to be outstanding immediately after this offering		ADSs.
Ordinary shares to be outstanding immediately after this offering		ordinary shares.
Over-allotment option		We have granted the underwriters an option, which is exercisable within 30 days from the date of this prospectus, to purchase up to additional ADSs from us at the public offering price less the underwriting discount to cover overallotments, if any.
The ADSs		Each ADS represents ordinary shares.
		The depositary (as identified below) will be the holder of the ordinary shares underlying the ADSs and you will have the rights of an ADS holder as provided in the deposit agreement among us, the depositary and holders and beneficial owners of ADSs from time to time.
		You may surrender your ADSs to the depositary to withdraw the ordinary shares underlying your ADSs. The depositary will charge you a fee for such an exchange.
		We may amend or terminate the deposit agreement for any reason without your consent. Any amendment that imposes or increases fees or charges or which materially prejudices any substantial existing right you have as an ADS holder will not become effective as to outstanding ADSs until 30 days after notice of the amendment is given to ADS holders. If an amendment becomes effective, you will be bound by the deposit agreement as amended if you continue to hold your ADSs.
		To better understand the terms of the ADSs, you should carefully read the section in this prospectus entitled "Description of American Depositary Shares." We also encourage you to read the deposit agreement, which is an exhibit to the registration statement to which this prospectus forms a part.
Depositary		The Bank of New York Mellon.
Shareholder approval of offering		Under Australian law, certain steps necessary for the consummation of this offering require the approval of our shareholders voting at an extraordinary general meeting of shareholders. We expect to receive all such required approvals from our shareholders prior to the completion of this offering.
Use of proceeds		We intend to use the net proceeds from this offering to accelerate our development program, primarily in the Eagle Ford and the Mississippian/Woodford and for general corporate purposes. See "Use of Proceeds."


Risk factors		You should carefully read and consider the information in this prospectus under the heading "Risk Factors" and all other information included in this prospectus before deciding to invest in the ADSs.
Listing and trading symbol		We have applied for the listing of the ADSs on The NASDAQ Global Select Market under the symbol "SNDE."
Lock-up		We and our directors and executive officers have agreed with the underwriters, subject to specified exceptions, not to sell or transfer any ordinary shares or ADSs or securities convertible into or exercisable for ordinary shares or ADSs, for a period of up to 180 days after the date of this prospectus. See "Underwriting."

The number of ordinary shares that will be outstanding immediately following the completion of this offering:

•: is based on 462,611,982 ordinary shares outstanding as of November 30, 2013;
•: excludes an aggregate of 561,686 ordinary shares issued in connection with the conversion of vested restricted share units during December 2013;
•: excludes an aggregate of 7,396,336 ordinary shares as of November 30, 2013 underlying (i) employee options to purchase an aggregate of 5,051,666 ordinary shares at a weighted average exercise price of A$1.02 and (ii) 2,344,670 restricted share units issued pursuant to our long-term incentive plan (each of which are convertible into one ordinary share); and
•: assumes no exercise by the underwriters of their option to purchase up to additional ADSs.

SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA

The following tables set forth summary historical and pro forma financial data for the periods indicated.

The consolidated statement of operations data for the six-month period ended December 31, 2012 and the fiscal years ended June 30, 2012 and 2011 are derived from the audited consolidated financial statements included in this prospectus. The consolidated balance sheet data as of December 31, 2012 and June 30, 2011 and 2012 are derived from our audited consolidated financial statements included in this prospectus. The consolidated statement of operations and balance sheet data as of and for the nine-month period ended September 30, 2013 and 2012 and the six-month period ended December 31, 2011 are derived from the unaudited consolidated financial statements that are included in this prospectus. In our management's opinion, these financial statements include all adjustments necessary for the fair presentation of our financial condition as of such dates and our results of operations for such periods.

Our financial statements have been prepared in U.S. dollars and in accordance with Australian Accounting Standards and IFRS, as issued by the IASB.

The summary unaudited pro forma statement of profit or loss of Sundance for the year ended December 31, 2012 and for the nine-month period ended September 30, 2013 are derived from the unaudited pro forma condensed consolidated financial statements included in this prospectus and give effect to our acquisition of Texon and our dispositions of interests in properties located in the South Antelope field and the Phoenix prospect as if such transactions had occurred on January 1, 2012. The summary pro forma unaudited balance sheet data as at September 30, 2013 is derived from the unaudited pro forma condensed consolidated financial statements included in this prospectus and gives effect to the disposition of the Phoenix prospect assets as if such transaction had occurred on September 30, 2013. As both the Texon acquisition and the South Antelope divestiture have been reflected in the our statement of financial position as at September 30, 2013, there is no impact to the summary pro forma unaudited balance sheet data as a result of those transactions. The summary unaudited pro forma financial information, while helpful in illustrating our financial characteristics using certain assumptions, does not reflect the impact of possible revenue enhancements, expense efficiencies and asset dispositions, among other factors that may result as a consequence of these pro forma transactions and, accordingly, does not attempt to predict or suggest future results. It also does not necessarily reflect what our historical results would have been had the pro forma transactions occurred during these periods.

You should read the summary consolidated financial data in conjunction with our consolidated financial statements and related notes beginning on page F-1 of this prospectus, "Selected Historical and Pro Forma Consolidated Financial Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus. Our historical results do not necessarily indicate our expected results for any future periods.

	Pro forma nine-month period ended September 30, 2013			Nine-month period ended September 30,									Six-month period ended December 31,						Year ended June 30,

				Nine-month period ended September 30,						Pro forma year ended December 31, 2012(1)			Six-month period ended December 31,						Year ended June 30,
				2013			2012			Pro forma year ended December 31, 2012(1)			2012			2011			2012			2011
	(unaudited)			(unaudited)			(unaudited)			(unaudited)			(audited)			(unaudited)			(audited)			(audited)
(In $ '000s, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	47,046		$	51,792		$	26,955		$	25,106		$	16,790		$	11,012		$	27,965		$	16,706
Natural gas sales		3,472			3,371			1,394			2,342			934			727			1,822			1,470

Total oil and natural gas revenues		50,518			55,163			28,349			27,448			17,724			11,739			29,787			18,176
Lease operating and production tax expenses		10,219			11,302			5,803			8,386			4,082			2,784			6,355			2,858
Depreciation and amortization expense		23,583			23,418			10,707			10,220			6,116			4,358			11,111			6,509
General and administrative expense		13,452			12,785			5,671			14,632			5,810			3,316			6,863			5,338
Finance costs, net of interest income		(283	)		(319	)		247			499			578			(240	)		(111	)		(312	)
Impairment of non-current assets		—			—			—			576			—			357			357			1,273
Exploration and evaluation expenditure		—			—			—			362			—			—			—			—
(Gain) / loss on sale of non-current assets		12			889			(125,755	)		(2,366	)		(122,327	)		(459	)		(3,004	)		(10,940	)
(Gain) / loss on commodity hedging		1,245			1,245			(1,331	)		(1,118	)		639			(188	)		(1,945	)		1,107
Realized currency loss		—			—			—			111			—			1			4			559
Income tax expense (benefit)		868			2,216			51,968			(1,472	)		46,616			659			4,145			4,755

Profit (loss) attributable to owners of Sundance	$	1,422		$	3,627		$	81,039		$	(2,382	)	$	76,210		$	1,151		$	6,012		$	7,029
Other comprehensive income (expense)
Exchange differences arising on translation of foreign operations		(204	)		(204	)		307			(770	)		(154	)		(303	)		(247	)		384

Total comprehensive income (loss) attributable to owners of Sundance	$	1,218		$	3,423		$	81,346		$	(3,152	)	$	76,056		$	848		$	5,765		$	7,413

Basic and diluted earnings (loss) per share	$	0.00		$	0.01		$	0.29		$	(0.01	)	$	0.27		$	0.00		$	0.02		$	0.03
Basic weighted average number of ordinary shares outstanding		428,845,186			399,079,749			277,098,474			399,840,760			277,244,883			276,904,030			277,049,463			260,935,572
Other Supplementary Data:
Adjusted EBITDAX(2)	$	27,873		$	32,103		$	17,970		$	7,819		$	9,223		$	5,622		$	17,093		$	9,993

(1): The audited statement of operations of Armadillo Petroleum Limited (f/k/a Texon Petroleum Limited) for the year ended December 31, 2012 reflects amounts in Australian dollars. The balances reflected in the pro forma statements have been converted to U.S. dollars at a rate of 1.036 U.S. dollar per Australian dollar.
(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."

					December 31,				June 30,

	Pro forma September 30, 2013		September 30, 2013		December 31,				June 30,
	Pro forma September 30, 2013		September 30, 2013		2012		2011		2012		2011
	(unaudited)		(unaudited)		(audited)		(unaudited)		(audited)		(audited)
(In $ '000s)
Balance Sheet Data:
Cash and cash equivalents	$	134,478	$	95,427	$	154,110	$	11,701	$	15,328	$	25,244
Assets held for sale		9,199		36,766		—		—		—		—

Total current assets		174,081		162,597		175,424		19,336		30,691		31,173
Oil and natural gas properties:
Development and production assets		214,567		214,567		79,729		61,842		87,274		45,873
Exploration and evaluation expenditure		178,722		178,722		33,439		6,875		11,436		6,626

Total oil and natural gas properties		393,289		393,289		113,168		68,717		98,710		52,499
Total assets		571,897		560,413		291,435		88,825		130,316		84,080
Current liabilities		110,493		110,493		51,842		12,880		30,393		10,160
Non-current liabilities:
Credit facilities		29,126		29,126		29,570		—		14,655		—
Restoration provision		2,275		2,275		1,228		412		588		349
Deferred tax liabilities		87,987		83,689		56,979		7,263		10,476		6,104

Total non-current liabilities		119,388		115,090		87,777		7,675		25,719		6,453
Total liabilities		229,881		225,583		139,619		20,555		56,112		16,613
Net assets		342,016		334,830		151,816		68,270		74,204		67,467
Issued capital		237,082		237,082		58,694		57,978		57,978		57,831

	Nine-month period ended September 30,					Six-month period ended December 31,					Year ended June 30,

	2013			2012		2012		2011			2012			2011
	(unaudited)			(unaudited)		(audited)		(unaudited)			(audited)			(audited)
(In $ '000s)
Net Cash Data:
Net cash provided by operating activities	$	36,437		$	13,847	$	9,386	$	2,095		$	11,832		$	8,908
Net cash provided by (used in) investing activities		(138,770	)		127,717		114,571		(14,933	)		(36,149	)		(13,465	)
Net cash provided by (used in) financing activities		43,650			9,722		14,846		(81	)		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:

	Pro forma nine-month period ended September 30, 2013			Nine-month period ended September 30,									Six-month period ended December 31,						Year ended June 30,

				Nine-month period ended September 30,						Pro forma year ended December 31, 2012			Six-month period ended December 31,						Year ended June 30,
				2013			2012			Pro forma year ended December 31, 2012			2012			2011			2012			2011
	(unaudited)			(unaudited)			(unaudited)			(unaudited)			(audited)			(unaudited)			(audited)			(audited)
(In $ '000s)
IFRS Profit (Loss) Reconciliation to Adjusted EBITDAX:
Profit (loss) attributable to owners of Sundance	$	1,422		$	3,627		$	81,039		$	(2,382	)	$	76,210		$	1,151		$	6,012		$	7,029
Income tax expense (benefit)		868			2,216			51,968			(1,472	)		46,616			659			4,145			4,755
Finance costs, net of (interest received)		(284	)		(319	)		247			499			578			(240	)		(111	)		(312	)
(Gain)/loss on commodity hedging		1,245			1,245			(1,331	)		(1,118	)		639			(188	)		(1,945	)		1,107
Settlement of commodity hedging		(176	)		(176	)		393			718			551			(464	)		(297	)		(643	)
Depreciation and amortization expense		23,583			23,418			10,707			10,220			6,116			4,358			11,111			6,509
Impairment of non-current assets		—			—			—			576			—			357			357			1,273
Stock compensation, value of services		1,203			1,203			702			3,144			840			448			825			1,215
(Gain)/loss on sale of non-current assets		12			889			(125,755	)		(2,366	)		(122,327	)		(459	)		(3,004	)		(10,940	)

Adjusted EBITDAX	$	27,873		$	32,103		$	17,970		$	7,819		$	9,223		$	5,622		$	17,093		$	9,993

SUMMARY RESERVE AND OPERATIONS DATA

The following table presents summary information regarding our estimated net proved oil and natural gas reserves as of the dates indicated. The estimates of our net proved reserves as of June 30, 2013, December 31, 2012, and June 30, 2012 and 2011 are based on the reserve reports prepared by Netherland Sewell in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") regarding oil and natural gas reserve reporting. For more information about our proved reserves as of June 30, 2013, December 31, 2012 and June 30, 2011 and 2012, please see Netherland Sewell's reserve reports, which have been filed as exhibits to the registration statement of which this prospectus forms a part.

Estimated Proved Reserves

					As of June 30,

	As of June 30, 2013		As of December 31, 2012		As of June 30,
	As of June 30, 2013		As of December 31, 2012		2012		2011
Estimated proved reserves:
Oil (MBbls)		10,258		5,758		7,979		4,788
Natural gas (MMcf)		24,356		16,888		13,052		7,692

Total estimated proved reserves (MBoe)(1)		14,317		8,572		10,154		6,070

Estimated proved developed reserves:
Oil (MBbls)		4,014		1,932		2,565		1,497
Natural gas (MMcf)		8,121		5,242		4,904		2,637

Total estimated proved developed reserves (MBoe)(1)		5,367		2,806		3,382		1,937

Estimated proved undeveloped reserves:
Oil (MBbls)		6,245		3,826		5,415		3,291
Natural gas (MMcf)		16,236		11,646		8,147		5,055

Total estimated proved undeveloped reserves (MBoe)(1)		8,951		5,767		6,773		4,134

PV-10 (in thousands)(2)	$	237,630	$	135,582	$	174,418	$	77,496

Standardized Measure (in thousands)	$	186,119	$	115,547	$	137,285	$	59,444

(1): Certain totals may not add due to rounding.
(2): PV-10 is considered a non-GAAP financial measure under SEC regulations. For a reconciliation of PV-10 to the Standardized Measure, see "— PV-10" below.

The increase in total proved reserves from December 31, 2012 to June 30, 2013 was due primarily to successful development and resulting extensions and discoveries on our Bakken, Eagle Ford and Mississippian/Woodford properties and from acquired Eagle Ford reserves. The decrease in total proved reserves from June 30 to December 31, 2012 was due primarily to the divestiture of our interest in properties in the South Antelope field of the Williston Basin, North Dakota in September 2012. The increase in total proved reserves from June 30, 2011 to June 30, 2012 was due primarily to successful development and resulting extensions and discoveries on our Bakken properties.

Operations Data

The following table sets forth summary data regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas and liquids for the periods indicated.

	Nine-month period ended September 30,				Six-month period ended December 31,				Year ended June 30,

	2013		2012		2012		2011		2012		2011
Net Sales Volumes:
Oil (MBbls)		522.3		322.9		195.5		135.2		337.7		210.1
Natural gas (MMcf)		902.6		389.0		260.4		124.3		370.3		282.5
Oil equivalent (MBoe)		672.7		387.8		238.9		156.0		399.4		257.1
Average daily volumes (Boe/d)		2,464		1,415		1,298		848		1,091		704
Average Sales Price:
Oil (per Bbl)	$	99.16	$	83.47	$	85.88	$	81.43	$	82.82	$	79.53
Natural gas (per Mcf)		3.73		3.58		3.59		5.84		4.92		5.20
Average equivalent price (per Boe)		82.00		73.11		74.19		75.27		74.59		70.69
Expenses (per Boe):
Lease operating expenses	$	10.41	$	6.92	$	9.19	$	9.56	$	7.76	$	3.46
Production tax expense		6.39		8.05		7.90		8.29		8.15		7.65

Lease operating and production tax expenses		16.80		14.97		17.09		17.85		15.91		11.11
Administrative expense, including employee benefits		19.00		14.62		24.32		21.26		17.18		20.76
Depreciation and amortization expense		34.81		27.61		25.60		27.94		27.82		25.31

PV-10

Certain of our oil and natural gas reserve disclosures included in this prospectus are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the "Standardized Measure"). We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies, and that most other companies in the oil and gas industry calculate PV-10 on the same basis. Investors should be cautioned that neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.

The following table provides a reconciliation of PV-10 to the Standardized Measure (in thousands):

							As of June 30,

	As of June 30, 2013			As of December 31, 2012			As of June 30,
	As of June 30, 2013			As of December 31, 2012			2012			2011
PV-10 of proved reserves	$	237,630		$	135,582		$	174,418		$	77,496
Present value of future income tax discounted at 10%		(51,511	)		(20,035	)		(37,133	)		(18,052	)

Standardized Measure	$	186,119		$	115,547		$	137,285		$	59,444

An investment in the ADSs involves significant risks. You should carefully consider the risks described below and the other information in this prospectus, including our consolidated financial statements and related notes included elsewhere in this prospectus, before you decide to invest in the ADSs. If any of the following risks actually occurs, our business, prospects, financial condition and results of operations could be materially affected, the trading price of the ADSs could decline and you could lose all or part of your investment.

Our future revenues are dependent on our ability to successfully replace our proved producing reserves.

Our business strategy is to generate profit through the acquisition, exploration, development and production of oil and natural gas reserves. Future success therefore depends on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Further to this, our proved reserves generally decline when produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.

Exploration and development activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

Even if our drilling efforts are successful, our wells, once completed, may not produce reserves of oil or natural gas that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results described elsewhere in this prospectus.

A decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas heavily affects our revenue, profitability, access to capital and future growth prospects. Oil and natural gas are commodities and, therefore, their prices are

subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and the prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

Further, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 72% of our estimated proved reserves as of June 30, 2013 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. Lower oil and natural gas prices will reduce our cash flows, our borrowing capacity and the present value of our reserves. Lower commodity prices may also reduce the amount of oil and natural gas that we can economically produce and may adversely affect our proved reserves.

As of September 30, 2013, we have commodity price hedging agreements on approximately 29% of our expected Boe production exit rate for 2013. 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. Our capital expenditures for 2013 are estimated at approximately $226 million ($140 million of which was spent as of September 30, 2013), substantially all of which has been allocated for the development of our oil and natural gas properties. 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. We intend to finance our future capital expenditures primarily through our cash flows from operations, borrowings under our credit facilities and the proceeds from this offering. 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:

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.

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, insurance against all operational risks is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.

In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors

that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Our planned exploratory drilling involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to:

The results of our drilling in new or emerging formations, such as the Mississippian/Woodford, are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are less able to predict future drilling results in these areas.

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 final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

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. In addition, our ability to produce oil and natural gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and personnel.

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 September 30, 2013, 49,293 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 during the next two years, approximately 9,237 net acres will expire in 2014, approximately 20,793 net acres will expire in 2015 and approximately 19,263 net acres will expire thereafter.

Approximately 12 gross proved undeveloped locations in our June 30, 2013 reserve report are currently not scheduled to be developed prior to the expiration date of the existing leases. In order for us to be able to develop these proved undeveloped locations prior to lease expiration, we or our partners would be required to change the development schedule or extend or renew the leases with the mineral owners. The reserves associated with these locations represent approximately 1.2% of our proved undeveloped reserves and 0.8% of our total proved reserves and therefore we believe that if we were unable to adjust the development schedule or extend or renew the leases it would not have a material impact on our overall reserves.

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

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:

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 may be subject to loss of interest through foreclosure of operator liens invoked by participating working interest owners and subject us to non-consent penalties.

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 prospectus 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 prospectus.

As of June 30, 2013, approximately 63% of our total proved reserves were proved undeveloped. Moreover, some of the producing wells included in our reserve report as of June 30, 2013 had been producing for a relatively short period of time as of that date.

As of December 31, 2012, approximately 79% of Texon's proved reserves in the Eagle Ford, which we acquired in March 2013, were proved undeveloped. Moreover, some of the producing wells included in Texon's reserve estimates as of December 31, 2012 had produced for a relatively short period of time as of that date. Because most of Texon's reserve estimates were calculated using decline curve analysis, those estimates are less reliable than estimates based on a lengthy production history.

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.

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 prospectus 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:

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 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 decrease, we may be required to write-down the carrying values of our oil and natural gas properties.

We review our proved 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, which may result in a decrease in the amount we can borrow under our credit facilities. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material

adverse effect on our ability to borrow under our credit facilities and adversely impact our results of operations for the periods in which such charges are taken.

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 were unable to market and sustain production from a particular lease for an extended period of time, possibly causing us to lose 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 Senior Credit Facility are limited by our borrowing base, which is subject to periodic redetermination.

Our Senior Credit Facility is a revolving line of credit that had a borrowing base of $48 million as of September 30, 2013. Our Senior Credit Facility has a five-year term and contains both negative and affirmative covenants, including minimum current ratio and maximum leverage ratio compliance requirements. Substantially all of our assets have been pledged as collateral.

The borrowing base under our Senior Credit Facility is redetermined at least semi-annually, but no more than quarterly. 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 Senior Credit 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 Senior Credit Facility and an acceleration of the loans

outstanding under our credit facilities. 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.

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, which could materially and adversely affect our business, results of operations and financial condition. For a description of our credit facilities, please see "Management's Discussion and Analysis of Financial Condition and Results of Operations — 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 the proceeds from this offering, and if necessary, other debt or equity financings. 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 incur additional debt 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:

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 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.

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 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 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 and 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:

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 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.

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.

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 regulation, including measures such as:

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 2014. Despite the existing 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 plans to initiate 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 recently 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.

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.

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.

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 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. In addition, starting in 2011, new sources or modifications of existing sources of significant quantities of greenhouse gas emissions 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. 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, 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, some scientists have concluded that 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 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 the 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.

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.

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:

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:

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.

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

The market price of the ADSs may be highly volatile and subject to wide fluctuations. In addition, the trading volume of the ADSs may fluctuate and cause significant price variations to occur. If the market price of the ADSs declines significantly, you may be unable to resell your ADSs at or above the purchase price, if at all. We cannot assure you that the market price of the ADSs will not fluctuate or significantly decline in the future.

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

An active trading market for the ADSs may not develop and the trading price for our ordinary shares may fluctuate significantly.

Prior to this offering, there has been no public market in the United States for the ADSs. If an active public market in the United States for the ADSs does not develop after this offering, the market price and liquidity of the ADSs may be adversely affected. While we have applied for the listing of the ADSs on The NASDAQ Global Select Market, a liquid public market in the United States for the ADSs may not develop or be sustained after this offering. The initial public offering price for the ADSs will be determined by negotiation among us and the underwriters, and the price at which the ADSs are traded after this offering may decline below the initial public offering price, which means you may experience a decrease in the value of your ADSs regardless of our operating performance or prospects. In the past, following periods of volatility in the market price of a company's securities, shareholders often instituted securities class action litigation against that company. If we were involved in a class action suit, it could divert the attention of senior management and, if adversely determined, could have a material adverse effect on our results of operations and financial condition.

Investors purchasing the ADSs will suffer immediate and substantial dilution.

The public offering price for the ADSs will be substantially higher than the net tangible book value per share of our outstanding ordinary shares immediately after this offering. If you purchase ADSs in this offering, you will incur substantial and immediate dilution in the net tangible book value of your investment. Net tangible book value per ordinary share represents the amount of total tangible assets less total liabilities, divided by the number of ordinary shares, respectively, then outstanding. To the extent that performance rights and options that are currently outstanding are exercised or converted, there will be further dilution in your investment. We may also issue additional ordinary shares, performance rights, options and other securities in the future that may result in further dilution of your ordinary shares. See "Dilution" for a calculation of the extent to which your investment will be diluted.

The dual listing of our ordinary shares and the ADSs following this offering may adversely affect the liquidity and value of the ADSs.

Following this offering and after the ADSs are listed on The NASDAQ Global Select Market, our ordinary shares will continue to be listed on the ASX. We cannot predict the effect of this dual listing on the value of our ordinary shares and ADSs. However, the dual listing of our ordinary shares and

ADSs may dilute the liquidity of these securities in one or both markets and may adversely affect the development of an active trading market for the ADSs in the United States. The price of the ADSs could also be adversely affected by trading in our ordinary shares on the ASX.

Future sales of our ordinary shares or ADSs, or the perception that such sales may occur, could depress our ordinary share price.

After the completion of this offering, we expect to have ordinary shares outstanding, including the shares underlying the ADSs we are selling in this offering, almost all of which may be resold in the public market immediately after this offering. We and all of our directors and executive officers, subject to specified exceptions, have signed lock-up agreements for a period of 180 days following the date of this prospectus, subject to extension in the case of an earnings release, material news or a material event relating to us. See "Underwriting."

The underwriters may, in their sole discretion and without notice, release all or any portion of the ordinary shares subject to lock-up agreements. As restrictions on resale end, the market price of our ordinary shares could drop significantly if the holders of these ordinary shares sell them or are perceived by the market as intending to sell them. These factors could also make it more difficult for us to raise additional funds through future offerings of our ordinary shares, ADSs or other securities.

As a foreign private issuer, we are permitted and expect to follow certain home country corporate governance practices in lieu of certain NASDAQ requirements applicable to domestic issuers.

As a foreign private issuer whose ADSs will be listed on The NASDAQ Global Select Market, we will be permitted to follow certain home country corporate governance practices in lieu of certain NASDAQ Global Market requirements. For example, we may follow home country practice with regard to the composition of the board of directors and quorum requirements applicable to shareholders' meetings. In addition, we may follow home country practice instead of the NASDAQ requirement to hold executive sessions and to obtain shareholder approval prior to the issuance of securities in connection with certain acquisitions, private placements of securities, or the establishment or amendment of certain stock option, purchase or other compensation plans. A foreign private issuer must disclose in its annual reports filed with the SEC and The NASDAQ Global Select Market the requirements with which it does not comply followed by a description of its applicable home country practice. The Australian home country practices described above may afford less protection to holders of the ADSs than that provided under The NASDAQ Global Select Market rules.

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. Accordingly, there may be less information publicly available concerning us than there is for a company that files as a domestic issuer.

We are an emerging growth company and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies may make the ADSs less attractive to investors and, as a result, adversely affect the price of the ADSs and result in a less active trading market for the ADSs.

We are an emerging growth company as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we have elected to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act relating to internal control over financial reporting, and we will not provide such an attestation from our auditors. We have also elected to rely on an exemption that permits an emerging growth company to include only two years of audited financial statements and only two years of related management's discussion and analysis of financial condition and results of operations disclosure, and we have therefore only included two years of audited financial statements and related management's discussion and analysis of financial condition and results of operations in this prospectus.

We may avail ourselves of these disclosure exemptions until we are no longer an emerging growth company. We cannot predict whether investors will find the ADSs less attractive because of our reliance on some or all of these exemptions. If investors find the ADSs less attractive, it may adversely impact the price of the ADSs and there may be a less active trading market for the ADSs.

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.

Section 404(a) of the Sarbanes-Oxley Act requires that, beginning with our annual report for the year ending December 31, 2015, 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 first Section 404(a) assessment will take place beginning with our annual report for the year ending December 31, 2015. 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.

If either we are unable to conclude that we have effective internal controls over financial reporting or, at the appropriate time, our independent auditors are unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of the Sarbanes-Oxley Act, investors may lose confidence in our operating results, the price of the ADSs could decline and we may be subject to litigation or regulatory enforcement actions. In addition, if we are unable to meet the requirements of Section 404 of the Sarbanes-Oxley Act, we may not be able to remain listed on The NASDAQ Global Select Market.

ADS holders may be subject to additional risks related to holding ADSs rather than ordinary shares.

ADS holders do not hold ordinary shares directly and, as such, are subject to, among others, the following additional risks:

You must act through the ADR depositary to exercise your voting rights and, as a result, you may be unable to exercise your voting rights on a timely basis.

As a holder of ADSs (and not the ordinary shares underlying your ADSs), we will not treat you as one of our shareholders, and you will not be able to exercise shareholder rights. The ADR depositary will be the holder of the ordinary shares underlying your ADSs, and ADS holders will be able to exercise voting rights with respect to the ordinary shares represented by the ADSs only in accordance with the deposit agreement relating to the ADSs. There are practical limitations on the ability of ADS holders to exercise their voting rights due to the additional procedural steps involved in communicating with these holders. For example, holders of our ordinary shares will receive notice of shareholders' meetings by mail and will be able to exercise their voting rights by either attending the shareholders meeting in person or voting by proxy. ADS holders, by comparison, will not receive notice directly from us. Instead, in accordance with the deposit agreement, we will provide notice to the ADR depositary of any such shareholders meeting and details concerning the matters to be voted upon at least 30 days in advance of the meeting date. If we so instruct, the ADR depositary will mail to holders of ADSs the notice of the meeting and a statement as to the manner in which voting instructions may be given by holders as soon as practicable after receiving notice from us of any such meeting. To exercise their voting rights, ADS holders must then instruct the ADR depositary as to voting the ordinary shares represented by their ADSs. Due to these procedural steps involving the ADR depositary, the process for exercising voting rights may take longer for ADS holders than for holders of ordinary shares. The ordinary shares represented by ADSs for which the ADR depositary fails to receive timely voting instructions will not be voted.

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 the ADSs.

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, 2012. 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, 2013. 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. The composition of our income and assets will also be affected by how, and how quickly, we spend the cash raised in this offering. Under circumstances where the cash is not deployed for active purposes, our risk of becoming a PFIC may increase. 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 "Taxation — U.S. Federal Income Tax Considerations") holds an ADS or an ordinary share, certain adverse U.S. federal income tax consequences could apply to such U.S. holder. See "Taxation — U.S. Federal Income Tax Considerations — Passive Foreign Investment Company."

Currency fluctuations may adversely affect the price of our ordinary shares.

Our ordinary shares are quoted in Australian dollars on the ASX and the ADSs will be quoted in U.S. dollars on The NASDAQ Global Market. Movements in the Australian dollar/U.S. dollar exchange rate may adversely affect the U.S. dollar price of the ADSs. In the past year the Australian dollar has generally depreciated against the U.S. dollar. Any continuation of this trend may positively affect the U.S. dollar price of the ADSs, even if the price of our ordinary shares in Australian dollars increases or remains unchanged. However, this trend may not continue and may be reversed. If the Australian dollar weakens against the U.S. dollar, the U.S. dollar price of the ADSs could decline, even if the price of our ordinary shares in Australian dollars increases or remains unchanged.

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.

You may not receive distributions on our ordinary shares represented by the ADSs or any value for such distribution if it is illegal or impractical to make them available to holders of ADSs.

While we do not anticipate paying any dividends on our ordinary shares in the foreseeable future, if such a dividend is declared, the depositary for the ADSs has agreed to pay to you the cash dividends

or other distributions it or the custodian receives on our ordinary shares or other deposited securities after deducting its fees and expenses. You will receive these distributions in proportion to the number of our ordinary shares your ADSs represent. However, in accordance with the limitations set forth in the deposit agreement, it may be unlawful or impractical to make a distribution available to holders of ADSs. We have no obligation to take any other action to permit the distribution of the ADSs, ordinary shares, rights or anything else to holders of the ADSs. This means that you may not receive the distributions we make on our ordinary shares or any value from them if it is unlawful or impractical to make them available to you. These restrictions may have a material adverse effect on the value of your ADSs.

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

We are incorporated in Australia and are subject to the takeover laws of Australia. Among other things, we are subject to the Australian 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. See "Description of Share Capital — Change of Control."

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. You should carefully review the summary of these matters set forth under the section entitled, "Description of Share Capital" as well as our Constitution, which is included as an exhibit to this registration statement to which this prospectus forms a part, prior to investing in the ADSs.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this prospectus.

The forward-looking statements made in this prospectus relate only to events or information as of the date on which the statements are made in this prospectus. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events.

We expect to receive approximately $ million of net proceeds from the sale of the ADSs in this offering (i) based on an initial public offering price of $ per ADS and the closing price of our ordinary shares and exchange rate set forth on the cover page of this prospectus after deducting underwriting discounts, commissions and estimated offering expenses payable by us of $ million and (ii) assuming no exercise of the over-allotment option by the underwriters. If the underwriters exercise the over-allotment option in full, we estimate that our net proceeds will be approximately $ million after deducting underwriting discounts and estimated offering expenses payable by us of $ .

We intend to use the net proceeds from this offering to accelerate our development program, primarily in the Eagle Ford and the Mississippian/Woodford and for general corporate purposes. We currently intend to allocate the following amounts for these uses:

The amounts and timing of any expenditures will depend on the amount of cash generated by our operations and competitive and market developments. Accordingly, our management will have significant flexibility in applying the net proceeds of this offering. Pending use of the net proceeds as described above, we intend to invest the net proceeds of this offering in short-term, interest-bearing bank deposits or money market funds.

An increase or decrease in the initial public offering price of $1.00 per ADS would cause the net proceeds that we will receive from the offering (after deducting underwriting discounts, commissions and estimated offering expenses payable by us) to increase or decrease, as applicable, by approximately $ million.

The following tables present, for the periods indicated, the high and low market prices for our ordinary shares reported on the ASX (symbol: "SEA") for the periods indicated. All prices are in Australian dollars.

	High		Low

	A$		A$
Annual:
*Fiscal year ended June 30*
2011		1.10		0.17
2010		0.20		0.08
2009		0.54		0.03
Quarterly:
*Fiscal year ending December 31, 2013*
Fourth Quarter (through December 10, 2013)		1.18		0.96
Third Quarter		1.14		0.84
Second Quarter		1.13		0.77
First Quarter		1.11		0.76
*Fiscal year ended December 31, 2012*
Second Quarter		0.84		0.66
First Quarter		0.85		0.38
*Fiscal year ended June 30, 2012*
Fourth Quarter		0.82		0.46
Third Quarter		0.83		0.40
Second Quarter		0.58		0.36
First Quarter		0.88		0.40
Most Recent Six Months:
November 2013		1.18		1.00
October 2013		1.14		0.96
September 2013		1.14		1.03
August 2013		1.12		0.98
July 2013		1.07		0.84
June 2013		0.94		0.77

On December 10, 2013, the closing price of our ordinary shares as traded on the ASX was A$0.99 per ordinary share ($0.90 per share based on the certified foreign exchange rate of A$0.9091 to $1.00 certified by the Federal Reserve Bank of New York as of December 9, 2013, the most recently available rate).

As of November 30, 2013, we had 462,611,982 ordinary shares outstanding, with 9,159,019 of our ordinary shares being held in the United States by 33 holders of record and 426,626,782 of our ordinary shares being held in Australia by 4,500 holders of record. A large number of our ordinary shares are held in nominee companies so we cannot be certain of the origin of those beneficial owners.

We have not declared or paid any dividends on our ordinary shares, and we do not anticipate paying any dividends in the foreseeable future. Our board of directors presently intends to reinvest all earnings in the continued development and operation of our business.

Payment of dividends in the future, if any, will be at the discretion of our board of directors. If our board of directors elects to pay dividends, the form, frequency and amount will depend upon our future operations and earnings, capital requirements and surplus, general financial conditions, contractual restrictions and other factors that our board of directors may deem relevant.

The Australian dollar is convertible into U.S. dollars at freely floating rates. There are no legal restrictions on the flow of Australian dollars between Australia and the United States. Any remittances of dividends or other payments by Sundance to persons in the United States are not and will not be subject to any exchange controls.

While our financial statements are presented in U.S. dollars, Texon's financial statements for the years ended December 31, 2011 and 2012 (and which have been included elsewhere in this prospectus) have been prepared in Australian dollars. For purposes of the presentation of our pro forma financial data for the year ended December 31, 2012, which are based on such Texon financial statements, we have translated all Australian dollar amounts into U.S. dollar amounts at a rate of 1.036 U.S. dollars per Australian dollar.

The table below sets forth for the periods identified the number of U.S. dollars per Australian dollar at the noon buying rate in the City of New York for cable transfers in Australian dollars as certified for customs purposes by the Federal Reserve Bank of New York (the "noon buying rate"). We make no representation that any Australian dollar or U.S. dollar amounts could have been, or could be, converted into U.S. dollars or Australian dollars, as the case may be, at any particular rate, the rates stated below, or at all.



Year ended December 31,
2011	1.0251	1.0332	1.1026	0.9453
2012	1.0393	1.0359	1.0806	0.9688
Month ended
November 30, 2013	0.9125	0.9324	0.9518	0.9072
October 31, 2013	0.9471	0.9519	0.9705	0.9366
September 30, 2013	0.9342	0.9303	0.9444	0.9055
August 31, 2013	0.8901	0.9037	0.9193	0.8901
July 31, 2013	0.8957	0.9155	0.9259	0.8957
June 30, 2013	0.9165	0.9440	0.9770	0.9165

The following table sets forth our capitalization and cash and cash equivalents as of September 30, 2013:

	As of September 30, 2013

(In $ '000s)	Actual			As Adjusted
Cash and cash equivalents	$	95,427

Non-current liabilities
Credit facilities net of deferred financing fees(1)		29,126

Total debt		29,126

Equity
Issued capital		237,082
Share option reserve		5,248
Foreign currency translation		(1,299	)
Retained earnings		93,799

Total equity		334,830

Total capitalization	$	363,956

An increase or decrease of $1.00 in the assumed initial public offering price per ADS would increase or decrease our total equity and total capitalization (as adjusted basis) by approximately $ million, after deducting the underwriting discounts, commissions and estimated offering expenses payable by us.

If you invest in the ADSs, your interest will be diluted to the extent of the difference between the initial public offering price per ADS and our net tangible book value per ADS after this offering. Dilution results from the fact that the initial public offering price per ordinary share underlying the ADSs is substantially in excess of the net tangible book value per ordinary share. Our net tangible book value as at September 30, 2013 was approximately $334.8 million, or $0.72 per ordinary share and $ per ADS. Net tangible book value per share represents the amount of total tangible assets, minus the amount of total liabilities, divided by the total number of ordinary shares outstanding. Dilution is determined by subtracting net tangible book value per ordinary share from the assumed initial public offering price per ordinary share, which is $ per ADS based on the closing price of our ordinary shares and the exchange rate set forth on the cover page of this prospectus and after deducting underwriting discounts, commissions and estimated offering expenses payable by us.

Without taking into account any other changes in our net tangible book value after September 30, 2013, other than to give effect to our sale of ADSs offered in this offering at the assumed initial public offering price of $ per ADS after deduction of underwriting discounts, commissions and estimated offering expenses payable by us, our adjusted net tangible book value as at September 30, 2013 would have been $ million, or $ per outstanding ordinary share, including ordinary shares underlying our outstanding ADSs, or $ per ADS. This represents an immediate increase in net tangible book value of $ per ordinary share, or $ per ADS, to existing shareholders and an immediate dilution in net tangible book value of $ per ordinary share, or $ per ADS, to purchasers of ADSs in this offering. The following table presents this dilution to new investors purchasing ADSs in the offering:

Each $1.00 increase or decrease in an assumed initial public offering price of $ per ADS after deducting underwriting discounts, commissions and estimated offering expenses payable by us would increase or decrease the net tangible book value after this offering by $ per ordinary share and $ per ADS, assuming no exercise of the overallotment option granted to the underwriters and the dilution to investors in the offering by $ per ordinary share and $ per ADS.

The following table summarizes, on a pro forma basis as at September 30, 2013, the differences between the shareholders as of September 30, 2013 and the new investors with respect to the number of ordinary shares purchased from us, the total consideration paid to us and the average price per ordinary share paid at an assumed initial public offering price of $ per ADS, before deducting underwriting discounts, commissions and estimated offering expenses payable by us. The total number of ordinary

shares does not include ADSs issuable pursuant to the exercise of the overallotment option granted to the underwriters.

Each $1.00 increase or decrease in the assumed public offering price of $ per ADS would increase or decrease total consideration paid by new investors, average price per ordinary share and per ADS paid by all shareholders, by $ million, $ per ordinary share and $ per ADS, respectively, assuming sale of ADSs by us at an assumed initial public offering price of $ per ADS, before deducting underwriting discounts, commissions and estimated offering expenses payable by us.

The following tables set forth summary historical and pro forma financial data for the periods indicated.

The consolidated statement of operations data for the six-month period ended December 31, 2012 and fiscal years ended June 30, 2011 and 2012 are derived from the audited consolidated financial statements included in this prospectus. The consolidated balance sheet data as of December 31, 2012 and June 30, 2011 and 2012 are derived from our audited consolidated financial statements included in this prospectus. The consolidated statement of operations and balance sheet data as of and for the nine-month period ended September 30, 2013 and 2012 and the six-month period ended December 31, 2011 are derived from the unaudited consolidated financial statements that are included in this prospectus. In our management's opinion, these financial statements include all adjustments necessary for the fair presentation of our financial condition as of such dates and our results of operations for such periods.

Our financial statements have been prepared in U.S. dollars and in accordance with Australian Accounting Standards. Our financial statements comply with IFRS, as issued by the IASB.

The summary unaudited pro forma statement of profit or loss for the year ended December 31, 2012 and for the nine-month period ended September 30, 2013 are derived from the unaudited pro forma condensed consolidated financial statements included in the prospectus and give effect to our acquisition of Texon and our dispositions of interests in properties located in the South Antelope field and the Phoenix prospect as if such transactions had occurred on January 1, 2012. The summary pro forma unaudited balance sheet data as at September 30, 2013 is derived from the unaudited pro forma condensed consolidated financial statements included in the prospectus and gives effect to the disposition of the Phoenix prospect assets as if such transaction had occurred on September 30, 2013. As both the Texon acquisition and the South Antelope divestiture have been reflected in the our statement of financial position as at September 30, 2013, there is no impact to the summary pro forma unaudited balance sheet data as a result of those transactions. The summary unaudited pro forma financial information, while helpful in illustrating our financial characteristics using certain assumptions, does not reflect the impact of possible revenue enhancements, expense efficiencies and asset dispositions, among other factors that may result as a consequence of these pro forma transactions and, accordingly, does not attempt to predict or suggest future results. It also does not necessarily reflect what our historical results would have been had the pro forma transactions occurred during these periods.

You should read the selected consolidated financial data in conjunction with our consolidated financial statements and related notes beginning on page F-1 of this prospectus, "Summary Historical and Pro Forma Consolidated Financial Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this prospectus. Our historical results do not necessarily indicate our expected results for any future periods.

	Pro forma nine-month period ended September 30, 2013			Nine-month period ended September 30,									Six-month period ended December 31,						Year ended June 30,

				Nine-month period ended September 30,						Pro forma year ended December 31, 2012(1)			Six-month period ended December 31,						Year ended June 30,
				2013			2012			Pro forma year ended December 31, 2012(1)			2012			2011			2012			2011
	(unaudited)			(unaudited)			(unaudited)			(unaudited)			(audited)			(unaudited)			(audited)			(audited)
(In $ '000s, except per share data)
Statement of Operations Data:
Revenues:
Oil sales	$	47,046		$	51,792		$	26,955		$	25,106		$	16,790		$	11,012		$	27,965		$	16,706
Natural gas sales		3,472			3,371			1,394			2,342			934			727			1,822			1,470

Total oil and natural gas revenues		50,518			55,163			28,349			27,448			17,724			11,739			29,787			18,176
Lease operating and production tax expenses		10,219			11,302			5,803			8,386			4,082			2,784			6,355			2,858
Depreciation and amortization expense		23,583			23,418			10,707			10,220			6,116			4,358			11,111			6,509
General and administrative expense		13,452			12,785			5,671			14,632			5,810			3,316			6,863			5,338
Finance costs, net of interest income		(283	)		(319	)		247			499			578			(240	)		(111	)		(312	)
Impairment of non-current assets		—			—			—			576			—			357			357			1,273
Exploration and evaluation expenditure		—			—			—			362			—			—			—			—
(Gain) / loss on sale of non-current assets		12			889			(125,755	)		(2,366	)		(122,327	)		(459	)		(3,004	)		(10,940	)
(Gain) / loss on commodity hedging		1,245			1,245			(1,331	)		(1,118	)		639			(188	)		(1,945	)		1,107
Realized currency loss		—			—			—			111			—			1			4			559
Income tax expense (benefit)		868			2,216			51,968			(1,472	)		46,616			659			4,145			4,755

Profit (loss) attributable to owners of Sundance	$	1,422		$	3,627		$	81,039		$	(2,382	)	$	76,210		$	1,151		$	6,012		$	7,029
Other comprehensive income (expense)
Exchange differences arising on translation of foreign operations		(204	)		(204	)		307			(770	)		(154	)		(303	)		(247	)		384

Total comprehensive income (loss) attributable to owners of Sundance	$	1,218		$	3,423		$	81,346		$	(3,152	)	$	76,056		$	848		$	5,765		$	7,413

Basic and diluted earnings (loss) per share	$	0.00		$	0.01		$	0.29		$	(0.01	)	$	0.27		$	0.00		$	0.02		$	0.03
Basic weighted average number of ordinary shares outstanding		428,845,186			399,079,749			277,098,474			399,840,760			277,244,883			276,904,030			277,049,463			260,935,572
Other Supplementary Data:
Adjusted EBITDAX(2)	$	27,873		$	32,103		$	17,970		$	7,819		$	9,223		$	5,622		$	17,093		$	9,993

					December 31,				June 30,

	Pro Forma September 30, 2013		September 30, 2013		December 31,				June 30,
	Pro Forma September 30, 2013		September 30, 2013		2012		2011		2012		2011
	(unaudited)		(unaudited)		(audited)		(unaudited)		(audited)		(audited)
(In $ '000s)
Balance Sheet Data:
Cash and cash equivalents	$	134,478	$	95,427	$	154,110	$	11,701	$	15,328	$	25,244
Assets held for sale		9,199		36,766		—		—		—		—

Total current assets		174,081		162,597		175,424		19,336		30,691		31,173
Oil and natural gas properties:
Development and production assets		214,567		214,567		79,729		61,842		87,274		45,873
Exploration and evaluation expenditure		178,722		178,722		33,439		6,875		11,436		6,626

Total oil and natural gas properties		393,289		393,289		113,168		68,717		98,710		52,499
Total assets		571,897		560,413		291,435		88,825		130,316		84,080
Current liabilities		110,493		110,493		51,842		12,880		30,393		10,160
Non-current liabilities:
Credit facilities		29,126		29,126		29,570		—		14,655		—
Restoration provision		2,275		2,275		1,228		412		588		349
Deferred tax liabilities		87,987		83,689		56,979		7,263		10,476		6,104

Total non-current liabilities		119,388		115,090		87,777		7,675		25,719		6,453
Total liabilities		229,881		225,583		139,619		20,555		56,112		16,613
Net assets		342,016		334,830		151,816		68,270		74,204		67,467
Issued capital		237,082		237,082		58,694		57,978		57,978		57,831

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.

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

	Pro forma nine-month period ended September 30, 2013			Nine-month period ended September 30,									Six-month period ended December 31,						Year ended June 30,

				Nine-month period ended September 30,						Pro forma year ended December 31, 2012			Six-month period ended December 31,						Year ended June 30,
				2013			2012			Pro forma year ended December 31, 2012			2012			2011			2012			2011
	(unaudited)			(unaudited)			(unaudited)			(unaudited)			(audited)			(unaudited)			(audited)			(audited)
(In $ '000s)
IFRS Profit (Loss) Reconciliation to Adjusted EBITDAX:
Profit (loss) attributable to owners of Sundance	$	1,422		$	3,627		$	81,039		$	(2,382	)	$	76,210		$	1,151		$	6,012		$	7,029
Income tax expense (benefit)		868			2,216			51,968			(1,472	)		46,616			659			4,145			4,755
Finance costs, net of (interest received)		(284	)		(319	)		247			499			578			(240	)		(111	)		(312	)
(Gain)/loss on commodity hedging		1,245			1,245			(1,331	)		(1,118	)		639			(188	)		(1,945	)		1,107
Settlement of commodity hedging		(176	)		(176	)		393			718			551			(464	)		(297	)		(643	)
Depreciation and amortization expense		23,583			23,418			10,707			10,220			6,116			4,358			11,111			6,509
Impairment of non-current assets		—			—			—			576			—			357			357			1,273
Stock compensation, value of services		1,203			1,203			702			3,144			840			448			825			1,215
(Gain)/loss on sale of non-current assets		12			889			(125,755	)		(2,366	)		(122,327	)		(459	)		(3,004	)		(10,940	)

Adjusted EBITDAX	$	27,873		$	32,103		$	17,970		$	7,819		$	9,223		$	5,622		$	17,093		$	9,993

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations in conjunction with the section entitled "Selected Historical and Pro Forma Consolidated Financial Data" and our consolidated financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results and the timing of selected events could differ materially from those anticipated in these forward-looking statements as a result of various factors, including, but not limited to, those set forth under "Risk Factors" and elsewhere in this prospectus.

Our properties and operations have changed significantly over the past 12 months, with the divestiture of our interest in properties located in the South Antelope field of the Williston Basin, North Dakota for approximately $172 million in September 2012 and the acquisition of Texon in March 2013, through which we acquired the majority of our Eagle Ford assets. The purchase price for the Texon acquisition was approximately $158.4 million, which involved the issuance of approximately 122,669,678 of our ordinary shares to Texon's shareholders. The merger was announced on November 13, 2012, but the purchase price was calculated using our ordinary share price on March 8, 2013, the effective date of the merger. The purchase price includes $132.1 million in value of ordinary shares, $26.3 million in cash used to fund capital expenditures between the announcement and effective date of the merger, and $45.4 million of deferred and current tax liability recognized primarily due to the difference between the book value of the assets and the fair value of consideration paid by Sundance. As of December 31, 2012, Texon had approximately 7,735 gross (7,336 net) acres in the Eagle Ford, 5 gross (4.5 net) producing wells, and proved reserves of approximately 1.6 MMBoe. During 2013, Texon drilled and completed another 2 gross (1.5 net) wells resulting in 7 gross (6 net) producing wells as of March 8, 2013. During March 2013, the Texon properties had average net daily production of approximately 717 Boe/d.

producing wells and percentage of operated production as compared to total net production as of and for the six-month period ended:

Netherland Sewell estimated our proved reserves to be approximately 14.3 MMBoe as of June 30, 2013 of which approximately 72% are oil and approximately 28% are liquids-rich natural gas, with a PV-10 of approximately $237.6 million.

We expect to make capital expenditures in 2013 of approximately $226 million, which is significantly higher than our capital expenditures of $100 million in the 12 months ended December 31, 2012. Through September 30, 2013, we have spent approximately $128 million drilling 70 gross (38.8 net) wells, and approximately $12 million towards leasehold acqusitions and seismic surveys. We continuously evaluate our capital expenditures budget and make adjustments from time to time as our results of operations and other factors dictate.

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 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 "Business — Operating Data — Production and Pricing."

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 to continue. For example, the NYMEX-WTI oil price ranged from a high of $109.39 per Bbl to a low of $77.72 per Bbl during 2012 and from a high of $110.62 per Bbl to a low of $86.65 per Bbl in the first nine months of 2013. 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 volatility to continue. For example, the NYMEX-Henry Hub natural gas price ranged from a high of $3.77 per MMBtu to a low of $1.82 per MMBtu during 2012 and from a high of $4.38 per MMBtu to a low of $3.08 per MMBtu during the first nine months of 2013. 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 up to 80% of forecasted proved developed producing production, but not more than 25% of total estimated production for the next five years. Should we reduce our estimates of future production to amounts that are lower than our commodity derivative volumes, we will reduce our positions as soon as practical. Our credit facilities prohibit us from entering into hedging arrangements for more than 85% of our projected production of oil and natural gas. For more information on our commodity derivative policy, see "— Quantitative and Qualitative Disclosure About Risk — Commodity Price Risk Exposure and Management."

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 and tax of 0.8125% 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 County, Texas assesses an annual ad valorem tax which currently is approximately 1.87% of the gross annual oil and gas sales value.

Colorado imposes production taxes ranging from 2.0% to 5.0% of gross oil and natural gas sales, a conservation tax of 0.07% of oil and gas sales, and an annual ad valorem tax of approximately 7.0% of the assessed net sales from the property. Wyoming oil production taxes are assessed at a rate of 6.0% of

net sales with a conservation tax of 0.04% of the gross income, and ad valorem taxes vary by county and average between 6.5% to 7.5% of net sales.

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. 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.

North Dakota currently imposes a production tax equal to 11.5% (5.0% production tax and 6.5% excise tax) of the market value of the oil sold.

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 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.

Adjusted EBITDAX is a supplemental, non-IFRS 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 "Selected Historical and Pro Forma Consolidated Financial and Operating Data — Adjusted EBITDAX" for a reconciliation between Adjusted EBITDAX and net income before income tax expense.

We believe that oil and natural gas prices may remain volatile for the foreseeable future. While oil and/or natural gas prices are high, drilling and completion activity may increase around our properties. Increased demand for oil field services may result in shortages of these services and an escalation in rig rates, field service costs, material prices and all costs associated with drilling, completing and operating wells in certain of the areas where we operate. If oil prices remain high relative to historical levels, we anticipate that the recent trends toward increasing costs and equipment and personnel shortages will continue. There is no guarantee that we will retain qualified employees during a competitive period in the industry. Any of these situations could have a material adverse effect upon our net sales or revenues, income from continuing operations, profitability, liquidity or capital resources or cause reported financial information not necessarily to be indicative of future operating results or financial condition. While we have identified prospects we intend to drill, our ability to grow could be adversely affected by these shortages and price increases.

The following discussion relates to our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto contained elsewhere in this prospectus. Comparative results of operations for the period indicated are discussed below.

Nine-Month Period Ended September 30, 2013 Compared to Nine-Month Period Ended September 30, 2012

Revenues and Production. The following table provides the components of our revenues for the nine-month periods ended September 30, 2013 and 2012, as well as each period's respective sales volumes:

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Production increased by 284,988 Boe (73.5%) to 672,750 Boe (2,464 Boe/d) for the nine-month period ended September 30, 2013 compared to 387,762 Boe (1,415 Boe/d) for the same period in 2012. The producing well count increased by 86 gross (61.6 net) to 240 gross (82.1 net) from 154 gross (20.5 net). The increase in production was primarily due to these new producing wells. This higher net producing well count was achieved through execution of our strategy to divest lower working interest wells and increase operated drilling activity and production through the Texon merger. Our production is oil-weighted, with oil representing 78% and 83% of total production for the nine-month periods ended September 30, 2013 and 2012, respectively.

Oil sales. Oil sales increased by $24.8 million (92.1%) to $51.8 million for the nine-month period ended September 30, 2013 from $27.0 million for the same period of 2012. The increased revenue was the result of both increased oil production volumes and improved product pricing. Oil production volumes increased 61.7% to 522,312 Bbls for the nine-month period ended September 30, 2013 compared to 322,923 Bbls for the same period in 2012. The average price we realized on the sale of our oil increased by 18.8% to $99.16 per Bbl for the nine-month period ended September 30, 2013 from $83.47 for the same nine-month period in 2012.

Natural gas sales. Natural gas sales increased by $2.0 million (141.9%) to $3.4 million for the nine-month period ended September 30, 2013 from $1.4 million for the same period of 2012. Natural gas production volumes increased 513,587 Mcf (132.0%) to 902,626 Mcf for the nine-month period ended September 30, 2013 compared to 389,039 Mcf for the same period in 2012. The average price we realized

on the sale of our natural gas increased by 4.2% to $3.73 per Mcf for the nine-month period ended September 30, 2013 from $3.58 per Mcf for the same period of 2012.

Lease operating expenses. Our lease operating expenses ("LOE") increased by $4.3 million (161.1%) to $7.0 million for the nine-month period ended September 30, 2013 from $2.7 million for the same period in 2012. This increase was primarily due to additional production (increased 73.5% over the same periods).

Production taxes. Our production taxes for the nine-month period ended September 30, 2013 remained consistent with the same period in 2012; however, production taxes per Boe declined by $1.66 (20.6%) due to divesting the majority of our production in North Dakota which has a 10.8% production tax rate, compared to Texas, Oklahoma and Colorado, which have 7.2%, 1.5% and 10.1% production tax rates, respectively.

Depreciation and amortization expense, including depletion. Our depreciation and amortization expense increased by $12.7 million (118.7%) to $23.4 million for the nine-month period ended September 30, 2013 from $10.7 million for the same period in 2012. The increase reflects our increase in our production (73.5%) and an increase in our asset base, subject to amortization as a result of our drilling acquisition and activity and our Texon acquisition during 2013. Depreciation and amortization per Boe increased by approximately 26.1% to $34.81.

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 $3.2 million (95.7%) to $6.6 million for the nine-month period ended September 30, 2013 from $3.4 million for the same period in 2012. Included in the employee benefits expense for the nine-month period ended September 30, 2013 in accordance with IFRS 2 Share-based Payment is a stock-based compensation charge of $1.2 million for options issued to officers and employees, an increase of $0.7 million (139.2%) compared to $0.5 million for the same period in 2012. Excluding stock-based compensation, employee benefits expense increased by $2.7 million (104.8%) to $5.4 million for the nine-month period ended September 30, 2013 from $2.7 million for the same period in 2012. This increase was primarily driven by an increased number of employees that was necessary to support the execution of our change in strategy. As of September 30, 2013, we had 44 full-time employees, an increase of 22 employees (100.0%) from 22 full time employees as of September 30, 2012.

Administrative expense increased by $3.9 million (168.4%) to $6.2 million for the nine-month period ended September 30, 2013 from $2.3 million for the same period in 2012. Included in administrative expenses were $0.4 million of costs related to the Texon acquisition and $0.9 million of costs related to our proposed initial public offering incurred in the nine-month period ended September 30, 2013. Excluding acquisition and offering-related expenses, administrative expenses increased $2.6 million (111.7%) for the nine-month period ended September 30, 2013. This increase was primarily due to an increase in the level of our activity and number of employees.

General and administrative expense per Boe increased by 29.9% as we increased our staffing levels to support the growth of our drilling program and operated production that we expected and have realized thus far in 2013.

Gain/(loss) on sale of non-current assets. For the six-month period ended September 30, 2013, we experienced a $0.9 million loss on the sale of non-current assets compared to a $125.8 million gain for the same period in 2012. All of the loss on sale for the nine-month period ended September 30, 2013 was the result of the post-closing adjustments related to the sale of our interest in non-operated wells and acreage located in the South Antelope field, which generated a gain on the sale of $125.8 million for the nine-month period ended September 30, 2012.

Finance costs, net of interest income. Finance costs, net of interest income and amounts capitalized, decreased by $0.5 million, resulting in net interest income of $0.3 million for the nine-month period ended September 30, 2013, from a net cost of $0.2 million for the same period in 2012. The change relates to the capitalization of interest to our oil and natural gas properties related to interest charges incurred. Prior to 2013, we deemed these interest amounts subject to capitalization to be insignificant and therefore did not capitalize interest in the comparable period in 2012.

Gain/(loss) on commodity hedging. The gain/(loss) on commodity hedging was a $1.2 million loss for the nine-month period ended September 30, 2013 compared to a $1.3 million gain on commodity hedging for the same period in 2012.

Income tax expense. Income tax expense for the nine-month period ended September 30, 2013 was $2.2 million compared to $52.0 million for the same period in 2012.

Profit attributable to owners of Sundance (or net income). Our net income decreased by $77.4 million (95.5%) to $3.6 million for the nine-month period ended September 30, 2013 from $81.0 million for the same period in 2012.

Adjusted EBITDAX. Adjusted EBITDAX increased by $14.1 million (78.7%) to $32.1 million for the nine-month period ended September 30, 2013 from $18.0 million for the same period in 2012. This increase in profitability was primarily driven by our production and revenue growth.

Six-Month Period Ended December 31, 2012 Compared to Six-Month Period Ended December 31, 2011

Revenues and Production. The following table provides the components of our revenues for the six-month periods ended December 31, 2012 and 2011, as well as each period's respective sales volumes:

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Production increased by 82,952 Boe (53.2%) to 238,904 Boe (1,298 Boe/d) for the six-month period ended December 31, 2012 compared to 155,952 Boe (848 Boe/d) for the same period in 2011. The producing well count increased by 44 gross (35.4 net) to 186 gross (49.4 net) from 142 gross (14.0 net). The increase in production was primarily due to these new producing wells. In September 2012, we disposed of 42 gross (4.5 net) low working interest South Antelope field wells. We also disposed of 4 gross (0.6) low working interest Pawnee wells. This higher net producing well count was achieved through execution of our strategy to divest lower working interest wells and increase operated drilling activity and production. Production was not impacted by the December 2012 acquisition of 22 gross (22.0 net) producing wells in the Wattenberg Field as these were acquired at the end of the period. Our production is oil-concentrated, with oil comprising 82% and 87% of total production for the six months ended December 31, 2012 and 2011, respectively.

Oil sales. Oil sales increased by $5.8 million (52.5%) to $16.8 million for the six-month period ended December 31, 2012 from $11.0 million for the same period of 2011. Favorable revenues were the result of both increased oil production volumes and improved product pricing. Oil production volumes increased 44.6% to 195,498 Bbls for the six-month period ended December 31, 2012 compared to 135,234 Bbls for the same period in 2011. The average price realized on the sale of our oil increased by 5.5% to $85.88 per Bbl for the six-month period ended December 31, 2012 from $81.43 per Bbl for the same six-month period in 2011.

Natural gas sales. Natural gas sales increased by $0.2 million (28.5%) to $0.9 million for the six-month period ended December 31, 2012 from $0.7 million for the same period of 2011. Increased natural gas production volumes more than offset price declines between the periods. Natural gas production volumes increased 136,130 Mcf (109.5%) to 260,435 Mcf for the six-month period ended December 31, 2012 compared to 124,305 Mcf for the same period in 2011. The average price we realized on the sale of our natural gas declined by 38.5% to $3.59 per Mcf for the six-month period ended December 31, 2012 from $5.84 per Mcf for the same period of 2011.

Lease operating expenses. Our LOE increased by $0.7 million (47.2%) to $2.2 million for the six-month period ended December 31, 2012 from $1.5 million for the same period in 2011. This increase was primarily due to additional production, which increased 53.2% over the same periods. LOE per Boe slightly decreased.

Production taxes. The increase in the production tax expense of $0.6 million (45.8%) was consistent with that of the increase in oil and natural gas revenue (51.0%) for the six-month period ended June 30, 2012 compared to same period in 2011. Production tax per Boe slightly decreased.

Depreciation and amortization expense, including depletion. Our depreciation and amortization expense increased by $1.8 million (40.3%) to $6.1 million for the six-month period ended December 31, 2012 from $4.4 million for the same period in 2011. The increase reflects our increase in production (53.2%) and an increase in our asset base subject to amortization as a result of our drilling activity during 2012. Depreciation and amortization per Boe decreased by approximately 8.4% to $25.60.

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 $0.7 million (34.4%) to $2.8 million for the six-month period ended December 31, 2012 from $2.1 million for the same period in 2011. Included in the employee benefits expense for the six-month period ended December 31, 2012 in accordance with IFRS 2 Share-Based Payment is a stock-based compensation charge of $0.8 million for options issued to officers and employees, an increase of $0.4 million (100.0%) compared to $0.4 million for the same period in 2011. Excluding stock-based compensation, employee benefits expense increased by $0.3 million (19.9%) to $2.0 million for the six-month period ended December 31, 2012 from $1.6 million for the same period in 2011. This increase was primarily driven by higher head count that was necessary to support the execution of our change in strategy. As of December 31, 2012, we had 25 employees, an increase of 9 employees (56%) from December 31, 2011.

Administrative expense increased by $1.8 million (150.0%) to $3.0 million for the six-month period ended December 31, 2012 from $1.2 million for the same period in 2011. Included in administrative expenses were $0.7 million of costs related to the Texon acquisition incurred in the six-month period ended December 31, 2012. Excluding acquisition related expenses, administrative expenses increased $1.1 million (86.4%) for the six-month period ended December 31, 2012. This increase was primarily due to an increase in the level of our activity and number of employees.

General and administrative expense per Boe increased by 14.0% as we increased our staffing levels to support the growth of our drilling program and operated production that we expected and have realized thus far in 2013.

Gain on sale of non-current assets. Gain on sale of non-current assets was $122.3 million for the six-month period ended December 31, 2012 compared to $0.5 million for the same period in 2011. Substantially all of the gain on sale for the six-month period ended December 31, 2012 was the result of the sale of non-operated wells and acreage in properties located in the South Antelope field for $172 million.

Finance costs, net of interest income. Finance costs, net of interest income, increased by $0.8 million to $0.6 million for the six-month period ended December 31, 2012 from $0.2 million of interest income for the same period in 2011. The increase related to $0.3 million of interest expense on our outstanding debt under our former Bank of Oklahoma credit facility, and the $0.3 million write-off of capitalized deferred loan costs related to the extinguishment of the Bank of Oklahoma credit facility in December 2012. The write-off was the result of our refinancing such debt with Wells Fargo Bank, N.A.

Gain/(loss) on commodity hedging. The gain/(loss) on commodity hedging changed by $0.8 million to a $0.6 million loss for the six-month period ended December 31, 2012 compared to a $0.2 million gain for the same period in 2011.

Income tax expense. Income tax expense for the six-month period ended December 31, 2012 was $46.6 million compared to $0.7 million for the same period in 2011. Substantially all of the income tax expense in the six-month period ended December 31, 2012 was related to the gain on the sale of our

interest in properties located in the South Antelope field. The income tax expense related to the gain on the South Antelope field sale has been deferred through qualifying Section 1031 like-kind exchanges and the use of income tax credits generated by our intangible drilling costs. Our current portion of our deferred income tax liability is insignificant relative to its total deferred income tax liability.

Profit attributable to owners of Sundance (or net income). Our net income increased by $75.0 million to $76.2 million for the six-month period ended December 31, 2012 from $1.2 million for the same period in 2011. As more fully described above, the increase was primarily related to the gain on sale of certain oil and natural gas properties, net of income tax expense.

Adjusted EBITDAX. Adjusted EBITDAX increased by $3.7 million (64.1%) to $9.2 million for the six-month period ended December 31, 2012 from $5.6 million for the same period in 2011. This increase in profitability was primarily driven by our increased production and improved product pricing.

Fiscal Year Ended June 30, 2012 as Compared to Fiscal Year Ended June 30, 2011

Revenues and Production. The following table provides the components of our revenues for the fiscal years ended June 30, 2012 and 2011, as well as each period's respective sales volumes:

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Production increased by 142,229 Boe (55.3%) to 399,366 Boe (1,091 Boe/d) for the fiscal year ended June 30, 2012 compared to 257,137 Boe (704 Boe/d) for the fiscal year ended June 30, 2011. The increase in production volumes was primarily due to a net increase from 107 gross (10.7 net) producing wells to 184 gross (22.0 net) wells as a result of our successful drilling program in the Bakken and Wattenberg Field during the fiscal year ended June 30, 2012. Our production is oil-concentrated, with oil comprising 85% and 82% of total production for the years ended June 30, 2012 and 2011, respectively.

Oil sales. Oil sales increased by $11.3 million (67.4%) to $28.0 million for the fiscal year ended June 30, 2012 from $16.7 million for the fiscal year ended June 30, 2011. Increase in oil revenues was the result of both increased oil production volumes and improved product pricing. Oil production volumes increased 60.7% to 337,650 Bbls for the fiscal year ended June 30, 2012 compared to 210,060 Bbls for the fiscal year ended June 30, 2011. The average price we realized on the sale of our oil increased by 4.1% to $82.82 per Bbl for the fiscal year ended June 30, 2012 from $79.53 per Bbl for the fiscal year ended June 30, 2011.

Natural gas sales. Natural gas sales increased by $0.4 million (23.9%) to $1.8 million for the fiscal year ended June 30, 2012 from $1.5 million for the fiscal year ended June 30, 2011. Increase in natural gas revenues was primarily the result of increased production volumes, partially offset by lower realized product pricing. Natural gas production volumes increased 87,833 Mcf (31.1%) to 370,296 Mcf for the fiscal year ended June 30, 2012 compared to 282,463 Mcf for the fiscal year ended June 30, 2011. The average price we realized on the sale of our natural gas decreased by 5.4% to $4.92 per Mcf for the fiscal year ended June 30, 2012 from $5.20 per Mcf for the fiscal year ended June 30, 2011.

Lease operating expenses. Our LOE increased by $2.2 million to $3.1 million for the fiscal year ended June 30, 2012 from $0.9 million for the fiscal year ended June 30, 2011. Although partially due to an increase in production, LOE/Boe increased $4.30/Boe (124.3%) to $7.76/Boe for the fiscal year ended June 30, 2012 compared to $3.46/Boe for fiscal year ended June 30, 2011. This increase was due to higher operating expenses related to increased concentration of our production coming from our non-operated wells in the Williston Basin.

Production taxes. The increase in the production tax expense (65.3%) was consistent with that of the increase in oil and natural gas revenue (63.9%) for the fiscal year ended June 30, 2012 compared to fiscal year ended June 30, 2011. Production taxes per Boe increased by 6.5%, which was primarily due to increased production in states with higher severance and ad valorem tax rates.

Depreciation and amortization expense, including depletion. Our depreciation and amortization expense increased by $4.6 million (70.7%) to $11.1 million for the fiscal year ended June 30, 2012 from $6.5 million for the fiscal year ended June 30, 2011. The increase reflects our increase in production (55.3%) and growing number of net producing wells. Depreciation and amortization per Boe increased by approximately 9.9% to $27.82.

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 $0.8 million (21.2%) to $4.3 million for the fiscal year ended June 30, 2012 from $3.6 million for the fiscal year ended June 30, 2011. Included in the employee benefits expense for the fiscal year ended June 30, 2012 in accordance with IFRS 2 Share-based Payment is a stock-based compensation charge of $0.8 million for options issued to officers, management and employees, a decrease of $0.4 million (32.1%) compared to $1.2 million for the fiscal year ended June 30, 2011. Excluding share-based stock compensation, employee benefits increased $1.1 million for fiscal year ended June 30, 2012, as compared to the fiscal year ended June 30, 2011, which was due to an increase in our number of employees and related salary and payroll expense. As of June 30, 2012, we had 18 employees, an increase of 4 employees (29%) from June 30, 2011.

Administrative expense increased by $0.8 million (43.3%) to $2.5 million for the fiscal year ended June 30, 2012 from $1.8 million for the fiscal year ended June 30, 2011. This increase was due to an increase in our level of activity and number of employees. General and administrative expenses per Boe decreased by 17.2%.

Finance costs, net of interest income. Interest income, net of expense, decreased by $0.2 million (64.4%) to $0.1 million of interest income for the fiscal year ended June 30, 2012 from $0.3 million of interest income for the fiscal year ended June 30, 2011. The decrease resulted from interest incurred on debt outstanding under our former Bank of Oklahoma credit facility in the fiscal year ended June 30, 2012 compared to no outstanding debt during the fiscal year ended June 30, 2011.

Gain/(loss) on commodity hedging. The gain/(loss) on commodity hedging changed by $3.0 million to a $1.9 million gain for the fiscal year ended June 30, 2012 compared to a $1.1 million loss for the fiscal year ended June 30, 2011.

Profit attributable to owners of Sundance (or net income). For the reasons discussed above, our profit attributable to owners of Sundance (or net income after tax) decreased by $1.0 million (14.5%) to net income of $6.0 million for the fiscal year ended June 30, 2012 from net income of $7.0 million for the fiscal year ended June 30, 2011.

Adjusted EBITDAX. Adjusted EBITDAX increased by $7.1 million (71.0%) to $17.1 million for the fiscal year ended June 30, 2012 from $10.0 million for the fiscal year ended June 30, 2011. The overall increase in Adjusted EBITDAX is consistent with the increase in production.

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 December 2012, we entered into our $300 million Senior Credit Facility with Wells Fargo Bank, N.A., which currently has a borrowing base of $48 million ($15 million of which was outstanding as of September 30, 2013). In August 2013, we entered into our Junior Credit Facility with Wells Fargo Energy Capital, Inc., under which we may borrow up to $100 million ($15 million of which was outstanding as of September 30, 2013).

Our 2013 capital budget is approximately $226 million, which we intend to use toward the development of our oil and natural gas projects. Through September 30, 2013, we have spent $140.2 million of our capital budget. We believe that our internally generated cash flows and expected future availability under our Senior Credit Facility and Junior Credit Facility, after giving effect to the issuance of the securities offered hereby and the application of the estimated net proceeds from this offering as described under "Use of Proceeds," 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.

Our cash flows for the nine-month periods ended September 30, 2013 and 2012, for the six-month periods ended December 31, 2012 and 2011, and for the years ended June 30, 2012 and 2011 are as follows:

	Nine-month period ended September 30						Six-month period ended December 31,						Year ended June 30,

(In $ '000s)	2013			2012			2012			2011			2012			2011
	(unaudited)			(unaudited)			(audited)			(unaudited)			(audited)			(audited)
Financial Measures:
Net cash provided by operating activities	$	36,437		$	13,847		$	9,386		$	2,095		$	11,832		$	8,908
Net cash provided by (used in) investing activities		(138,770	)		127,717			114,571			(14,933	)		(36,149	)		(13,465	)
Net cash provided by (used in) financing activities		43,650			9,722			14,846			(81	)		14,734			18,869
Cash and cash equivalents		95,427			163,278			154,110			11,701			15,328			25,244
Payments for development expenditure		(94,373	)		(39,720	)		(32,551	)		(14,659	)		(34,833	)		(22,889	)
Payments for exploration expenditure		(16,633	)		(10,844	)		(8,031	)		(601	)		(5,685	)		(1,362	)
Acquisitions, net		(27,073	)		—			—			—			—			—
Sale of non-current assets		(751	)		178,545			173,822			459			4,679			10,647

Net cash provided by operating activities for the nine-month period ended September 30, 2013 was $36.4 million compared to $13.8 million provided by operating activities for the nine-month period ended September 30, 2012, an increase of $22.6 million (163.1%). The increase in cash flows provided by operating activities resulted primarily from an increase in receipts from sales of $28.2 million, offset by an increase in payments to suppliers and employees of $4.6 million and an increase in income taxes paid of $0.5 million.

Net cash provided by operating activities was $9.4 million for the six-month period ended December 31, 2012, compared to $2.1 million provided by operating activities for the six-month period ended December 31, 2011, an increase of $7.3 million (348.0%). The increase in cash flows provided by operating activities resulted primarily from an increase receipts from sales of $3.4 million and decreased payments to suppliers and employees of $2.9 million.

Net cash provided by operating activities was $11.8 million for the year ended June 30, 2012 compared to $8.9 million provided by operating activities for the year ended June 30, 2011, an increase of $2.9 million, or 33.0%. The increase in cash flows provided by operating activities resulted primarily

from an increase receipts from sales of $5.6 million, offset by an increase in payments to suppliers and employees of $1.5 million and a decrease in income taxes (paid)/refunded of $1.5 million.

Net cash used in investing activities for the nine-month period ended September 30, 2013 was $138.8 million compared to $127.7 million provided in investing activities for the nine-month period ended September 30, 2012, a change of $266.5 million (208.7%). Our payments for development and exploration expenditures increased by $54.7 million and $5.8 million, respectively, for the nine-month period ended September 30, 2013 compared to the same period in 2012. Net cash consideration paid for the Texon merger was $27.1 million during the nine-month period ended September 30, 2013; there were no comparable transactions during the nine-month period ended September 30, 2012. Sales of non-current assets for the nine-month period ended September 30, 2012 were $178.5 million; there were no comparable transactions during the nine-month period ended September 30, 2013.

Expenditures for development of oil and natural gas properties are the primary use of our capital resources. Net cash provided by investing activities for the six-month period ended December 31, 2012 was $114.6 million compared to $14.9 million cash used in investing activities for the same period in 2011. Sales of non-current assets for the six-month period ended December 31, 2012 were $173.8 million compared to $0.5 million for the same period in 2011. Excluding sales of non-current assets, net cash used in investing activities for the six-month period ended December 31, 2012 was $59.3 million compared to $15.4 million for the for the same period in 2011, an increase of $43.9 million. Our payments for development and exploration expenditures increased by $17.9 million and $7.4 million, respectively, for the six-month period ended December 31, 2012 compared to the same period in 2011. In addition, we had $11.5 million of payments for the acquisition of oil and natural gas properties in the Wattenberg Field and $6.3 million of related payments to establish escrows for drilling commitments.

Net cash used in investing activities for the year ended June 30, 2012 was $36.1 million compared to $13.5 million cash used in investing activities for the year ended June 30, 2011. Sales of non-current assets for the year ended June 30, 2012 was $4.7 million compared to $10.6 million for the same period in 2011. Excluding sales of non-current assets, net cash used in investing activities for the year ended June 30, 2012 was $40.8 million compared to $24.1 million for the year ended June 30, 2011, an increase of $16.7 million (69.0%). Our payments for development and exploration expenditures increased by $11.9 million and $4.3 million, respectively, for the year ended June 30, 2012 compared to the same period in 2011.

Net cash provided by financing activities for the nine-month period ended September 30, 2013 was $43.7 million compared to $9.7 million provided by financing activities for the nine-month period ended September 30, 2012, an increase of $33.9 million (349.0%). Our primary source of cash provided by financing activities for the nine-month period ended September 30, 2013 was proceeds from the issuance of shares of $48.2 million, reduced by associated capital raising costs of $2.6 million, and by acquisition costs from the Texon merger of $0.4 million and offering costs of $0.3 million from the proposed initial public offering; there were no comparable transactions during the nine-month period ended September 30, 2012. Our primary source of cash provided by financing activities for the nine-month period ended September 30, 2012 was net borrowings on our credit facility with the Bank of Oklahoma in the amount of $10.0 million; there were no comparable transactions during the nine-month period ended September 30, 2013.

Net cash flow provided by financing activities for the six-month period ended December 31, 2012 was $14.8 million compared to net cash flow used in financing activities of $0.1 million for the same period in 2011. Our primary source of the cash provided by financing activities for the six-month period ended December 31, 2012 related to net borrowings on our credit facility with the Bank of Oklahoma in the amount of $15.0 million.

Net cash flow provided by financing activities for the year ended June 30, 2012 was $14.7 million compared to $18.9 million for the same period in 2011. Our primary source of the cash provided by financing activities for the year ended June 30, 2012 related to net borrowings on our credit facility with the Bank of Oklahoma in the amount of $15.0 million. Our primary source of the cash provided by financing activities for the year ended June 30, 2011 related to proceeds from the issue of ordinary shares of $18.9 million ($19.9 million gross proceeds, net of $1.0 million payments for the costs of such equity financing).

Senior Credit Facility. On December 31, 2012, we entered into our Senior Credit Facility with Wells Fargo Bank, N.A. Our Senior Credit Facility provides us with a $300 million facility with a borrowing base of $48.0 million as of September 30, 2013 as determined by our March 2013 oil and natural gas reserves. Upon closing on December 31, 2012, we drew the full $30 million initial borrowing base under our Senior Credit Facility and used $15 million of the proceeds to repay and retire our then-outstanding loan with the Bank of Oklahoma. As of September 30, 2013, there was $15 million outstanding under our Senior Credit Facility. The size of our borrowing base under our Senior Credit Facility is determined at the discretion of the lenders under our Senior Credit Facility and is dependent upon a number of factors, including commodity prices and reserve levels. Our Senior Credit Facility specifies a semi annual borrowing base redetermination, and we can request two additional redeterminations each year. Borrowings under our Senior Credit Facility are secured by substantially all our assets. Our Senior Credit Facility matures in December 2017.

The applicable margin varies depending on the amount drawn. We also pay a commitment that ranges from 37.5 to 50 basis points on the undrawn balance of the borrowing base. The key financial covenants of our Senior Credit Facility require us to (i) maintain a minimum current ratio, which is defined as consolidated total current assets inclusive of undrawn borrowing capacity divided by consolidated total current liabilities, of 1.0 or greater, and (ii) a debt to EBITDAX ratio (as defined in our Senior Credit Facility), determined on a rolling four quarter basis, of 4.0 to 1.0 or less beginning on December 31, 2012. In addition, our Senior Credit Facility contains various covenants that limit our ability to take certain actions, including, but not limited to, the following:

If an event of default exists under our Senior Credit Facility, the lender will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

Junior Credit Facility. In August 2013, we entered into our Junior Credit Facility with Wells Fargo Energy Capital, Inc., as the administrative agent, which provides for term loans to be made to us in a series of draws up to $100 million. Our Junior Credit Facility matures in June 2018. Upon entering into our Junior Credit Facility, we immediately borrowed $15 million pursuant to the terms of our Junior Credit Facility and paid down the outstanding principal of our Senior Credit Facility. As of September 30, 2013, there was $15 million outstanding under our Junior Credit Facility. An intercreditor agreement governs the relationship between the lenders under our Senior Credit Facility and our Junior Credit Facility.

The principal amount of the loans borrowed under our Junior Credit Facility is due in full on the maturity date. Interest on our Junior Credit Facility accrues at a rate equal to the greater of (i) 8.50% and (ii) a base rate (being, at our option, either (a) LIBOR for the applicable interest period (adjusted for Eurodollar Reserve Requirements) or (b) the greatest of (x) the prime rate announced by Wells Fargo Bank, N.A., (y) the federal funds rate plus 0.50% and (z) one-month adjusted LIBOR plus 1.00%), plus a margin of either 6.5% or 7.5%, based on the base rate selected.

We are also required under our Junior Credit Facility to maintain the following financial ratios:

Our Junior Credit Facility contains various restrictive covenants similar to those in our Senior Credit Facility. If an event of default exists under our Junior Credit Facility, the lenders will be able to accelerate the obligations outstanding under our Junior Credit Facility and exercise other rights and

remedies. Our Junior Credit Facility also contains events of default similar to those in our Senior Credit Facility, together with certain cross-defaults with respect to our Senior Credit Facility.

The following table summarizes our contractual obligations as of December 31, 2012:

(1): Includes principal and projected interest payments (based on a 2.18% interest rate in effect as of September 30, 2013) due under our Senior Credit Facility. During August 2013, we borrowed $15 million under our Junior Credit Facility and subsequently used the proceeds to repay $15 million of outstanding loans under our Senior Credit Facility. As of September 30, 2013, there was $15 million outstanding under our Senior Credit Facility. Please read the description of our Senior Credit Facility and our Junior Credit Facility above.
(2): At December 31, 2012, we did not have any outstanding drilling rig contracts to explore and develop our properties. During 2013, we entered into seven drilling rig contracts. The contracts have terms of 1 to 12 months. Should we elect to terminate these, we would incur termination obligations for the rigs. Our maximum outstanding aggregate capital commitment on these early termination obligations was approximately $4.0 million as of September 30, 2013.
(3): As a part of our acquisition agreement for certain Wattenberg assets, we are committed to drilling 15 vertical or five horizontal development wells per year for the years ending December 31, 2013, 2014 and 2015 (collectively 45 vertical or 15 horizontal development wells). We have established an escrow account that will release the funds to us at a rate of $67,000 per vertical or $267,000 per horizontal well drilled, with any shortfall wells (less than 45 cumulative vertical or 15 horizontal wells drilled as of December 31, 2015) to be paid to the seller of the assets from the escrow account. If we complete drilling any of the shortfall wells after the deadline, we are able to recoup up to $67,000 per vertical or $267,000 per horizontal well by obtaining an assignment of a 5% overriding royalty interest from the seller until the shortfall well fee is recouped.
(4): 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, 2012.

The following table summarizes our historical nine-month period ended September 30, 2013, the six-month period ended December 31, 2012 and years ended June 30, 2012 and 2011 and our estimated capital expenditures for the three-month and 12 month periods ending December 31, 2013. We routinely monitor and adjust our estimated capital expenditures in response to changes in oil and natural gas prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of

regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. As a result, actual capital expenditures for 2013 may not be as estimated below. As described above, we plan to finance our ongoing expenditures using internally generated cash flow and availability under our credit facilities.

A summary of estimated capital expenditures by core operating asset for the three-month period ending December 31, 2013 is as follows:

We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a significant effect on our financial condition or results of operations.

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. We analyze our estimates and judgments, including those related to oil and natural gas revenues, oil and natural gas properties, fair value of derivative instruments, contingencies and litigation, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary 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 six-month period ended December 31, 2012.

Development and production assets and plant and equipment are carried at cost less accumulated depreciation, amortization and, where applicable, impairment losses. The recoverable amount is assessed on the basis of the expected net cash flows that will be received from the asset's employment and subsequent disposal. The expected net cash flows have been discounted to their present values in determining recoverable amount. A downward revision in reserves could increase depletion and amortization. A downward revision to the expected discounted future net cash flows, resulting from either a reduction to estimated reserves or sales prices or from an increase to estimated operating or developments costs, could result in a write-down to the carrying value of the underlying properties.

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 the group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the statement of profit or loss during the financial period in which are they are incurred.

Exploration and evaluation expenditure incurred is accumulated in respect of each identifiable area of interest. These costs are only carried forward 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.

Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made. When production commences, the accumulated costs for the relevant area of interest are transferred to production assets and amortized over the life of the area according to the rate of depletion of the economically recoverable reserves.

Our policy for exploration and evaluation (as discussed in Note 1(c) to our consolidated financial statements for the six-month period ended December 31, 2012) requires us to make certain estimates and assumptions as to future events and circumstances. Any such estimates and assumptions may change as new information becomes available. If, after having capitalized an exploration and evaluation expenditure, our board of directors concludes that the capitalized expenditure is unlikely to be recovered by future sale or exploitation, then the relevant capitalized amount will be written off through the statement of profit or loss and other comprehensive income.

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.

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, management prepares reserve estimates that conform to guidelines prepared by the Society of Petroleum Engineers. 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. 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.

A provision for rehabilitation and restoration is provided by us to meet all future obligations for the restoration and rehabilitation of oil and natural gas producing areas when oil and natural gas reserves are exhausted and the oil and natural gas fields are abandoned. Restoration liabilities are discounted to present value and capitalized as a component part of capitalized development expenditure. The capitalized costs are amortized over the life of the assets and the provision is revised at each balance date through the statement of profit or loss as the discounting of the liability unwinds. A provision for rehabilitation and restoration is determined using significant assumptions including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated restoration provision. Because of the subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates. See Note 19 to the Consolidated Financial Statements for the period ended December 31, 2012 for additional information regarding our restoration provision.

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. 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, 2012 and June 30, 2012, 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.

IFRS differs from GAAP in certain respects. Management has not assessed the materiality of differences between IFRS and GAAP. Our significant accounting policies are described in Note 1 of our consolidated financial statements for the six-month period ended December 31, 2012.

We are exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. Our risk management focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. We utilize derivative financial instruments to hedge certain risk exposures. Our 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 our operations.

Financial risk management is carried out by our management. Our board of directors sets financial risk management policies and procedures to which our management is required to adhere. Our management identifies and evaluates financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by our board of directors.

The main risk to which we are exposed through our financial instruments is interest rate risk. We manage interest rate risk with a mixture of fixed and floating rate cash deposits. As of December 31, 2012, none of our deposits were fixed. It is our policy to keep surplus cash in interest-yielding deposits.

We perform a sensitivity analysis relating to our exposure to interest rate risk. The sensitivity analysis demonstrates the effect on results and equity that could result from a change in these risks. The effect on income and equity as a result of changes in the interest rate, with all other variables remaining constant for the six-month period ended December 31, 2012, would be as follows (in $ '000s):

Our board of directors actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of our hedging activity are continually monitored against our policy. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use forward contracts to manage our commodity price risk exposure.

Our current policy is to hedge up to 80% of forecasted proved developed producing production, but not more than 25% of total estimated production for the next five years.

The following table provides a summary of derivative contracts as of December 31, 2012:

			Units per month

			Units per month								Ceiling Price
Description	Commodity	Basis	2013		2014		2015		Floor Price		Ceiling Price		Term
Swap	Oil (Bbls)	NYMEX-WTI		2,000		—		—	$	99.00	$	99.00	Mar '13 - Dec '13
Collar	Oil (Bbls)	NYMEX-WTI		1,000		—		—		90.00		117.50	Jan '13 - Dec '13
Collar	Oil (Bbls)	NYMEX-WTI		1,000		—		—		95.00		112.75	Jan '13 - Dec '13
Swap	Oil (Bbls)	NYMEX-WTI		3,000		—		—		102.95		102.95	Jan '13 - Dec '13

Total Oil/Weighted Average Price				7,000		—		—		98.84		105.30	Jan '13 - Dec '13

Swap	Gas (MMBtu)	NYMEX-HH		10,000		—		—		3.58		3.58	Jan '13 - Dec '13

The following table provides a summary of derivative contracts entered into during 2013:

			Units per month

			Units per month								Ceiling Price
Description	Commodity	Basis	2013		2014		2015		Floor Price		Ceiling Price		Term
Swap	Oil (Bbls)	LLS		3,000		—		—	$	101.75	$	101.75	Jul '13 - Dec '13
Collar	Oil (Bbls)	LLS		3,000		—		—		95.00		104.90	Jul '13 - Dec '13
Swap	Oil (Bbls)	NYMEX-WTI		1,000		—		—		106.55		106.55	Oct '13 - Dec 13
Swap	Oil (Bbls)	LLS		10,000		—		—		110.85		110.85	Oct '13 - Dec '13
Swap	Oil (Bbls)	LLS		5,000		—		—		103.75		103.75	Jul '13 - Dec '13
Swap	Oil (Bbls)	LLS		3,000		3,000		—		101.75		101.75	Jul '13 - Jun '14
Collar	Oil (Bbls)	NYMEX-WTI		3,000		3,000		—		90.00		99.75	Jul '13 - Jun '14
Collar	Oil (Bbls)	LLS		—		2,000		—		90.00		102.00	Jan '14 - Dec '14
Collar	Oil (Bbls)	LLS		—		3,000		—		90.00		101.30	Jan '14 - Dec '14
Swap	Oil (Bbls)	NYMEX-WTI		—		2,000		—		97.40		97.40	Jan '14 - Dec '14
Swap	Oil (Bbls)	LLS		—		3,000		—		102.30		102.30	Jan '14 - Dec '14
Collar	Oil (Bbls)	NYMEX-WTI		—		3,000		—		85.00		94.75	Jan '14 - Dec '14
Swap	Oil (Bbls)	LLS		—		3,000		—		100.15		100.15	Jan '14 - Dec '14
Collar	Oil (Bbls)	LLS		—		2,000		—		85.00		102.00	Jul '14 - Dec '14
Collar	Oil (Bbls)	NYMEX-WTI		—		2,500		—		80.00		98.25	Jul '14 - Dec '14
Collar	Oil (Bbls)	NYMEX-WTI		—		—		2,000		75.00		98.65	Jan '15 - Dec '15
Collar	Oil (Bbls)	LLS		—		—		3,000		85.00		101.05	Jan '15 - Dec '15
Collar	Oil (Bbls)	NYMEX-WTI		—		2,000		—		90.00		102.85	Jan '14 - Dec '14
Collar	Oil (Bbls)	NYMEX-WTI		—		—		2,000		80.00		97.00	Jan '15 - Dec '15

Total Oil/Weighted Average Price				28,000		28,500		7,000		93.27		101.13	Jul '13 - Dec '15

Swap	Gas (MMBtu)	NYMEX-HH		10,000		—		—		4.15		4.15	May '13 - Dec '13
Swap	Gas (MMBtu)	HSC		10,000		—		—		4.01		4.01	Jun '13 - Dec '13
Swap	Gas (MMBtu)	NYMEX-HH		—		20,000		—		4.23		4.23	Jan '14 - Dec '14
Collar	Gas (MMBtu)	HSC		—		10,000		—		3.75		4.60	Jan '14 - Dec '14

Total Gas/Weighted Average Price				20,000		30,000		—		4.08		4.28	Jul '13 - Dec '14

In the above tables, "NYMEX-WTI" refers to NYMEX-West Texas Intermediate and "NYMEX-HH" refers to NYMEX-Henry Hub.

The effect on profit and equity as a result of changes in oil prices with all variables remaining constant for the six-month period ended December 31, 2012 would be as follows (in $ '000s):

Effective July 1, 2011, our functional currency changed from Australian dollars to U.S. dollars. All of our operations are conducted in the United States and in transactions denominated in U.S. dollars. Only a relatively immaterial amount of administrative expense is incurred in Australia and paid in Australian dollars, and cash balances maintained in Australian banks are also relatively immaterial. Therefore, the impact resulting from changes in the value of the U.S. dollar to the Australian dollar would not have a material effect on our income and equity.

In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The counterparties on our derivative instruments currently in place have investment-grade credit ratings. We expect that any future derivative transactions we enter into will be with these counterparties or our lenders under our credit facilities that will carry an investment-grade credit rating.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

In line with our business strategy, we have divested several non-core assets, including the sale of our interest in properties located in the South Antelope field of the Williston Basin, North Dakota, in September 2012, which resulted in net proceeds of approximately $172 million. In addition, in October and November 2013, we entered into agreements to sell our interest in the Phoenix prospect of the Williston Basin, which we expect will result in aggregate net proceeds of approximately $39.1 million, subject to customary closing conditions. We have historically used the proceeds from our strategic asset divestitures towards the development of our operated, high working interest projects and to fund potential acquisition opportunities that fit our strict investment guidelines. We intend to continue to use the proceeds from our strategic asset divestitures in this manner to the extent we believe it meets our business and growth objectives.

Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources." The following table presents a summary of our actual capital expenditures for the period beginning January 1, 2013 and ending September 30, 2013, our estimated capital expenditures for the remainder of 2013, total capital expenditures for 2013 and gross and net estimated wells that we expect to be drilled in each of our major operating areas during 2013:

The following table presents for each of our major operating areas a summary of our identified gross and net drilling locations as of June 30, 2013 and producing well data as of September 30, 2013:

shares to Texon shareholders. The purchase price includes: $132.1 million in value of ordinary shares, based upon the closing price of our ordinary shares on March 8, 2013, the effective date of the merger; and $26.3 million in cash used to fund capital expenditures between the November 13, 2012 merger announcement and effective date of the merger. In addition, we assumed $45.4 million of deferred and current tax liabilities recognized primarily due to the difference between the book value of the assets and the fair value of consideration paid by us. As of December 31, 2012, Texon had approximately 7,735 gross (7,336 net) acres in the Eagle Ford, 5 gross (4.5 net) producing wells, and proved reserves of approximately 1.6 MMBoe. During 2013, Texon drilled and completed another 2 gross (1.5 net) wells resulting in 7 gross (6.0 net) producing wells as of March 8, 2013. During March 2013, the Texon properties had average net daily production of approximately 717 Boe/d.

There continues to be a high level of industry activity in the western portion of the Eagle Ford. The most active operators offsetting our leasehold position in McMullen County include BHP Billiton Ltd. (through the acquisition of Petrohawk Energy Corporation), Chesapeake Energy Corporation, EOG Resources, Inc., Marathon Oil Corporation, Pioneer Natural Resources Company, Swift Energy Company and Talisman Energy Inc. According to Drillinginfo, Inc., there were 5,388 drilling permits filed in the Eagle Ford in 2012 and 4,508 drilling permits filed through the nine-month period ended September 30, 2013. According to estimates prepared by Baker Hughes Incorporated, there were 229 rigs operating in the Eagle Ford as of September 30, 2013.

Based on publicly available information, we believe that average drilling and completion costs for horizontal wells in the Eagle Ford have ranged between $5.5 million and $9.0 million per well with average estimated ultimate recoveries, or EURs, of 200,000 to 694,000 Boe per well and initial 30-day average production of 394 to 787 Boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur of the results we will achieve from our wells.

Through leveraging industry best practices and our in-house technical expertise, we have improved operating efficiencies since commencing our operated drilling program in the Eagle Ford. We have realized a majority of our cost savings through limiting expenditures associated with rig mobilization and demobilization, as well as in the time required to drill and complete our wells. In addition, through a combination of improved well planning and completion design optimization, we believe that additional value can be realized in our ultimate resource recovery.

The Mississippian/Woodford formation spans six counties located throughout northeastern Oklahoma and southwestern Kansas. Our properties in the Mississippian/Woodford consist of approximately 75,690 gross (44,809 net) acres that are primarily located in Logan County, Oklahoma along the eastern flank of the Nemaha Ridge. We acquired the majority of these properties through direct mineral leases with the mineral owners. As of September 30, 2013, we were running a two-rig horizontal program to appraise the economic potential of our Mississippian/Woodford properties. From January 1, 2013 to September 30, 2013, we have spent $46 million drilling a total of 20 gross (10.0 net) Mississippian/Woodford wells, of which 9 are producing and 11 are drilling or awaiting completion as of September 30, 2013. During the month of September 2013, we had average net daily production of approximately 514 Boe/d from our Mississippian/Woodford properties. For the nine-month period ended

September 30, 2013, we had average net daily production of approximately 389 Boe/d from these properties. For the remainder of 2013, we expect to spend approximately $19 million to complete the wells in progress and to drill and complete an additional 4 gross (2.8 net) Mississippian and Woodford horizontal wells at an average gross well cost of $3.7 and $4.7 million, respectively.

Since commencing our horizontal drilling program, our primary objective has been the Mississippian, though we continue to evaluate the upside potential in the Woodford. We believe that the core samples taken on our initial appraisal wells show that our leasehold is in the oil window and possesses several key geologic characteristics supportive of scalable resource play development across both the Mississippian and Woodford formations. Industry activity along the eastern flank of the Nemaha Ridge remains strong with Devon Energy Corporation, Sandridge Energy, Inc. and Slawson Exploration Company, Inc. representing the major operators offsetting our acreage. According to Drillinginfo, Inc., there were 3,549 drilling permits filed in the Mississippian/Woodford in 2012 and 2,193 drilling permits filed through the nine-month period ended September 30, 2013. According to estimates prepared by Baker Hughes Incorporated, there were 123 rigs operating in the Mississippian/Woodford as of September 30, 2013.

Based on publicly available information, we believe that average drilling and completion costs for horizontal wells in the Mississippian/Woodford have ranged between $2.5 million and $3.7 million per well with average EURs of 175,000 to 600,000 Boe per well and initial 30-day average production of 306 to 845 Boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur of the results we will achieve from our wells.

Our Wattenberg Field properties consist of approximately 5,676 gross (5,023 net) acres that are primarily located in Weld County, Colorado. We acquired approximately 48% of these properties through direct mineral leases from mineral owners and approximately 52% of these properties through an acquisition of leases and producing vertical wells in late 2012, in which we acquired approximately 2,868 gross (2,629 net) acres for a purchase price $13.7 million. To date, we have focused the majority of our development activities on drilling vertical wells. From January 1, 2013 to September 30, 2013, we have spent $7 million drilling and/or completing a total of 17 gross (15.3 net) vertical Wattenberg wells and 7 gross (0.9 net) horizontal Niobrara wells, of which 13 were producing and 11 were awaiting completion as of September 30, 2013. During the month of September 2013, we had average net daily production of approximately 323 Boe/d from our Wattenberg Field properties. For the nine-month period ended September 30, 2013, we had average net daily production of approximately 466 Boe/d from these properties.

Offsetting operators to our leasehold position in the Wattenberg Field include Anadarko Petroleum Corporation, Bill Barrett Corporation, Carrizo Oil & Gas, Inc., EOG Resources, Inc. and Noble Energy, Inc., and industry activity in the Wattenberg Field remains strong. According to Drillinginfo, Inc., there were 1,644 drilling permits filed in the Wattenberg Field in 2012 and 1,351 drilling permits filed through the nine-month period ended September 30, 2013. According to estimates prepared by Baker Hughes Incorporated, there were approximately 43 rigs operating in the counties encompassing the Wattenberg Field as of September 30, 2013.

Based on publicly available information, we believe that average drilling and completion costs for vertical wells in the Wattenberg Field have ranged between $0.6 million and $1.0 million per well with average EURs of 48 to 78 Boe per well and initial 30-day average production of 43,000 to 89,000 Boe/d per well. Additionally, we believe that average drilling and completion costs for horizontal wells in the Wattenberg Field have ranged between $3.6 million and $8.3 million per well with average EURs of 235,000 to 750,000 Boe per well and initial 30-day average production of 458 to 1,000 Boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur of the results we will achieve from our wells.

We are testing our Eagle Ford acreage for 60-acre down-spacing potential, which we believe could add 40 incremental net unrisked locations to our drilling inventory. In addition, we expect to have

drilled 8 gross (6.0 net) Mississippian and 5 gross (4.2 net) Woodford horizontal operated wells in 2013 to test the economic potential of these formations in our Logan County, Oklahoma, prospect where we hold approximately 59,050 gross (29,691 net) mineral acres as of September 30, 2013.

We believe we are well positioned to successfully execute our business strategies and to achieve our business objectives because of the following competitive strengths:

Experienced executive management and technical teams with proven track record

In March 2013, we completed the merger with Texon, through which we acquired the majority of our assets in the Eagle Ford, consisting of 8,055 gross (7,656 net) acres. Shortly after the acquisition, we changed the name of Texon to Armadillo Petroleum Limited, and we similarly renamed Texon's subsidiaries. The purchase price for the Texon acquisition was approximately $158.4 million, which involved the issuance of approximately 122,669,678 of our ordinary shares to Texon's shareholders. As of December 31, 2012, Texon had approximately 7,735 gross (7,336 net) acres in the Eagle Ford, 5 gross (4.5 net) producing wells and proved reserves of approximately 1.6 MMBoe. During March 2013, Texon had average net daily production of approximately 717 Boe/d.

In December 2012, we acquired approximately 2,686 gross (2,629 net) acres of oil and natural gas properties in the Wattenberg Field for approximately $13.7 million.

In September 2012, we sold our interest in properties located in the South Antelope field of the Williston Basin, North Dakota to a third party for approximately $172 million in net proceeds. At the time of the sale, the prospect included approximately 3,939 net non-operated acres in McKenzie County, North Dakota, with average net daily production of approximately 827 Boe/d during the quarter ended September 30, 2012 and proved reserves of approximately 4.7 MMBoe as of September 2012.

On October 30, 2013, we entered into a purchase and sale agreement to sell our interests in the Phoenix prospect of the Bakken for $35.5 million. We expect closing to occur in December 2013, subject to customary closing conditions. The assets sold pursuant to the purchase and sale agreement include 77 gross producing wells in McKenzie, Dunn and Mountrail Counties, North Dakota.

On November 1, 2013, we sold our entire interest in an individual operated well and the developed 622 acres, also located in the Phoenix prospect, for gross proceeds of approximately $4.3 million.

In the aggregate, these properties in the Phoenix prospect had an average daily net production of approximately 776 Boe/d for the month ended September 30, 2013. Estimated proved reserves and PV-10 associated with these assets as of June 30, 2013, were 3.1 MMBoe (69% of which were proved undeveloped) and $58.2 million, respectively. We intend to use the expected net proceeds of $39.1 million from the Phoenix prospect divestitures to fund drilling and/or acquisitions in our Eagle Ford, Mississippian/Woodford and Wattenberg properties.

The following table presents summary information regarding our estimated net proved oil and natural gas reserves as of the dates indicated. The estimates of our net proved reserves as of June 30, 2013, December 31, 2012 and June 30, 2012 and 2011 are based on the reserve reports prepared by Netherland Sewell in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting. For more information about our proved reserves as of June 30, 2013, December 31, 2012 and June 30, 2012 and 2011, please see Netherland Sewell's reserve reports, which have been filed as exhibits to the registration statement of which this prospectus forms a part.

					As of June 30,

	As of June 30, 2013		As of December 31, 2012		As of June 30,
	As of June 30, 2013		As of December 31, 2012		2012		2011
Estimated proved reserves:
Oil (MBbls)		10,258		5,758		7,979		4,788
Natural gas (MMcf)		24,356		16,888		13,052		7,692

Total estimated proved reserves (MBoe)(1)		14,317		8,572		10,154		6,070

Estimated proved developed reserves:
Oil (MBbls)		4,014		1,932		2,565		1,497
Natural gas (MMcf)		8,121		5,242		4,904		2,637

Total estimated proved developed reserves (MBoe)(1)		5,367		2,806		3,382		1,937

Estimated proved undeveloped reserves:
Oil (MBbls)		6,245		3,826		5,415		3,291
Natural gas (MMcf)		16,236		11,646		8,147		5,055

Total estimated proved undeveloped reserves (MBoe)(1)		8,951		5,767		6,773		4,134

PV-10 (in thousands)(2)	$	237,630	$	135,582	$	174,418	$	77,496

Standardized Measure (in thousands)	$	186,119	$	115,547	$	137,285	$	59,444

At June 30, 2013, our proved undeveloped reserves were approximately 8,951 MBoe, an increase of approximately 3,184 MBoe over our December 31, 2012 proved undeveloped reserves estimate of approximately 5,767 MBoe. The change consisted of a decrease of approximately 204 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves during the first half of 2013, an increase of approximately 2,713 MBoe attributable to the Eagle Ford acquisition and an increase of approximately 675 MBoe due to the addition of proved undeveloped locations net of revisions to previous estimates. During the six-month period ended June 30, 2013, we incurred capital expenditures of approximately $3.8 million to convert proved undeveloped reserves to proved developed reserves. All proved undeveloped locations are scheduled to be spud within the next five years.

At December 31, 2012, our proved undeveloped reserves were approximately 5,767 MBoe, a decrease of approximately 1,006 MBoe over our June 30, 2012 proved undeveloped reserves estimate of

approximately 6,773 MBoe. The change consisted of a decrease of approximately 461 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves during the second half of 2012, a decrease of approximately 3,193 Mboe sold as part of the South Antelope divestiture, an increase of approximately 1,774 MBoe attributable to the Wattenberg Field acquisition, an increase of approximately 1,443 MBoe due to the addition of new proved undeveloped locations and a reduction for revisions to previous estimates of approximately 569 MBoe. During the six-month period ended December 31, 2012, we incurred capital expenditures of approximately $9.3 million to convert proved undeveloped reserves to proved developed reserves. All proved undeveloped locations are scheduled to be spud within the next five years.

Our proved reserves estimates as of June 30, 2013, December 31, 2012 and June 30, 2012 and 2011, have been independently prepared by Netherland Sewell, which was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland Sewell, the technical person primarily responsible for the estimates set forth in the reserves report incorporated herein is Mr. Joseph J. Spellman. Mr. Spellman is a Licensed Professional Engineer in the State of Texas (No. 73709) with over 30 years of practical experience in petroleum engineering studies and evaluation of reserves and has been practicing consulting petroleum engineering at Netherland Sewell since 1989. He graduated from the University of Wisconsin — Platteville in 1980 with a Bachelor of Science Degree in Civil Engineering. Mr. Spellman meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We believe that he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

As referred to in this prospectus, proved reserves are those quantities of oil and natural gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, Netherland Sewell employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, 3-D seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. The evaluation included an assessment of the beneficial impact of the use of multi-stage hydraulic fracture stimulation treatments on estimated recoverable reserves. In addition to assessing reservoir continuity, geologic data from well logs and core analyses were used to estimate original oil and natural gas in place in certain areas.

Our technical team consists of an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. Historically, we had no formal committee specifically designated to review our reserves reporting and our reserves estimation process, and a preliminary copy of the reserve report was reviewed by our Vice President of Exploration and Development with representatives of our independent reserve engineers and internal technical staff. Prior to release of the reserve report prepared by our independent reserve engineers, the draft of the report is reviewed by our internal petroleum engineers and by management.

We had the following developed, undeveloped and total acres for each of our operating areas as of September 30, 2013:

	Nine-month period ended September 30,				Six-month period ended December 31,				Year ended June 30,

	2013		2012		2012		2011		2012		2011
Net Sales Volumes:
Oil (MBbls)		522.3		322.9		195.5		135.2		337.7		210.1
Natural gas (MMcf)		902.6		389.0		260.4		124.3		370.3		282.5
Oil equivalent (MBoe)		672.7		387.8		238.9		156.0		399.4		257.1
Average daily volumes (Boe/d)		2,464		1,415		1,298		848		1,091		704
Average Sales Price:
Oil (per Bbl)	$	99.16	$	83.47	$	85.88	$	81.43	$	82.82	$	79.53
Natural gas (per Mcf)		3.73		3.58		3.59		5.84		4.92		5.20
Average equivalent price (per Boe)		82.00		73.11		74.19		75.27		74.59		70.69
Expenses (per Boe):
Lease operating expenses	$	10.41	$	6.92	$	9.19	$	9.56	$	7.76	$	3.46
Production tax expense		6.39		8.05		7.90		8.29		8.15		7.65

Lease operating and production tax expenses		16.80		14.97		17.09		17.85		15.91		11.11
Administrative expense, including employee benefits		19.00		14.62		24.32		21.26		17.18		20.76
Depreciation and amortization expense		34.81		27.61		25.60		27.94		27.82		25.31

The following tables set forth information regarding our total production and average daily production for the periods indicated from our operating areas:

We had the following producing wells for each of our operating areas as of September 30, 2013:

The following table summarizes our drilling activity for the nine-month period ended September 30, 2013, the six-month period ended December 31, 2012 and the fiscal years ended June 30, 2012 and 2011.

									Year ended

	Nine-month period ended September 30, 2013				Six-month period ended December 31, 2012				Year ended
	Nine-month period ended September 30, 2013				Six-month period ended December 31, 2012				June 30, 2012				June 30, 2011
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Development wells
Oil		41		20.9		37		12.3		77		11.3		64		5.4
Gas		—		—		—		—		—		—		1		0.1
Dry		—		—		—		—						—		—
Exploratory Wells
Oil		—		—		—		—		—		—		—		—
Gas		—		—		—		—		—		—		—		—
Dry		—		—		—		—		—		—		—		—

Total Wells
Oil		41		20.9		37		12.3		77		11.3		64		5.4
Gas		—		—		—		—		—		—		1		0.1
Dry		—		—		—		—		—		—		—		—

		41		20.9		37		12.3		77		11.3		65		5.5

The following table describes wells being drilled or awaiting completion or production testing as of September 30, 2013.

For the six-month period ended December 31, 2012, purchases by four of our customers accounted for 82% of our total sales revenues. These customers purchase the oil production from us pursuant to existing marketing agreements with terms that are currently on "evergreen" status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal. The oil and natural gas that we sell are commodities for which there are a large number of potential buyers. Because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, the price and quantity of foreign oil and natural gas, the level of global oil and natural gas exploration and production, global oil and gas inventories, weather conditions, governmental regulations, oil and natural gas speculation, actions of OPEC, technological advances, and the price and availability of alternative fuels. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See "Risk Factors."

Our properties are subject to what we believe to be customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we conduct what we believe to be sufficient investigation of title at the time we acquire undeveloped properties and generally make title investigations and receive title opinions of local counsel before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with the operation of our business.

The oil and natural gas industry is highly competitive, and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, and obtaining drilling rigs, completion crews and other services. There is also competition between producers of oil and natural gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States. However, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of

wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission ("FERC") and the courts. We believe that we are in substantial compliance with all applicable laws and regulations and that our continued substantial compliance with existing requirements will not have a material adverse affect on our financial position, cash flows or results of operations. Nor are we currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.

Our sales of oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act of 1887 ("ICA"), the Energy Policy Act of 1992 ("EPAct 1992"), and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport oil and refined products (collectively referred to as "petroleum pipelines"), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as "grandfathered rates." Pursuant to EPAct 1992, FERC also adopted a generally applicable rate-making methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods ("PPI"), plus 1.3 percent. For the five-year period beginning July 1, 2011, the index will be PPI plus 2.65%.

FERC has also established cost-of-service rate-making, market-based rates and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost of service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates vary from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors that are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas, transportation rates and terms and conditions of service, which affect the marketing of natural gas that we produce as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines' traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others that buy and sell natural gas. Although FERC's orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC's pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC's determinations as to the classification of facilities is done on a case-by-case basis. To the extent that FERC issues an order that reclassifies transmission facilities as gathering facilities and, depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, non-discriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Our exploration, development, production and processing operations are subject to various federal, state and local laws and regulations relating to health and safety, the discharge of materials and environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas, such as wetlands, wilderness areas, or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the oil and gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position in the future. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. We maintain insurance against costs of cleanup operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future

may have a material adverse effect on our capital expenditures, results of operations or financial position.

The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. CERCLA exempts "petroleum, including oil or any fraction thereof" from the definition of "hazardous substance" unless specifically listed or designated under CERCLA. While the EPA interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance.

Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes. The RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes. The RCRA regulations specifically exclude from the definition of hazardous waste "drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy." However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. In addition, an environmental group petitioned the EPA in 2010 to remove this exclusion. Under RCRA, the EPA is required to respond to the petition within a reasonable time; however to date, the EPA has not acted on the petition and has not announced a time frame for responding. Any regulatory repeal of the RCRA exclusion would require Congressional approval. If any such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.

Pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages and significant business interruption. The U.S. Department of Transportation ("DOT") has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. In 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act provides additional requirements related to spill and accident reporting, as well as more stringent oversight of pipelines and increased penalties for violations of safety rules. Since enactment, DOT has initiated a series of rulemakings to implement the new law. DOT has also recently promulgated new regulations extending safety rules to certain low-pressure, small-diameter pipelines in rural areas.

The Clean Air Act, as amended ("CAA"), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations, and impose various monitoring and reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects.

In August 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines ("RICE NESHAP"). The rule may require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on a portion of our engines located at major sources of hazardous air pollutants and all our engines over a certain size regardless of location, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On January 14, 2013, the EPA signed final revisions to the 2010 RICE NESHAP to reflect new technical information submitted by stakeholders and in response to lawsuits and administrative petitions. On January 30, 2013 the final RICE NESHAP rule was published in the Federal Register with an effective date of April 1, 2013. Several petitions requesting administrative reconsideration of the 2013 RICE NESHAP were received by the EPA. By means of a letter dated June 28, 2013 from the EPA to petitioners, the EPA stated it intends to initiate a reconsideration process of several issues in the 2013 RICE NESHAP, including timing for compliance for certain engines. While it reconsiders the rule, the EPA has issued guidance on responding to requests for compliance extensions for entities that operate certain compression ignition engines covered by the rule for which the compliance date has already passed.

In June 2010, the EPA formally proposed modifications to existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The EPA finalized the modifications on

June 28, 2011 with an effective date of August 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment on a potentially significant percentage of our natural gas compression engine fleet.

The EPA also issued new CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard for volatile organic chemicals (VOCs) and sulfur dioxide (SO₂) emissions with expanded applicability to natural gas operations, as well as a new air toxics standard. These rules create significant new technology requirements for controlling wellhead emissions from our operations. The EPA is currently considering multiple changes to these rules in response to industry and environmental group legal challenges and administrative petitions. Legal challenges to the rule have been stayed while the EPA considers possible revisions. Several of the challenges to the EPA's initial rule relate to the EPA's decision not to include a performance standard for methane emissions from oil and natural gas operations. In general, there is increasing interest in and focus on regulation of methane emissions from oil and natural gas operations, and hydraulic fracturing operations in particular, under the CAA. We cannot predict future regulatory requirements in this area or the cost to comply with such requirements. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could 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.

The United States is a party to the United Nations Framework Convention on Climate Change ("UNFCCC"), an international treaty focused on stabilizing greenhouse gases ("GHGs") concentrations in the atmosphere at a level that would prevent serious damage to the climate system. The UNFCCC did not establish any substantive obligations for parties to reduce GHGs. The subsequent treaty, the Kyoto Protocol, did establish binding GHG targets for developed countries, but the United States did not ratify it. The current focus is on a new treaty to replace the Kyoto Protocol upon its expiration in 2020. In 2011, parties to the UNFCCC, including the United States, agreed to develop a new treaty with binding GHG targets by 2015 in order for it to be implemented by 2020. This new treaty remains under negotiation, but it could result in new targets or codify existing actions taken by individual countries to reduce GHGs. The United States' involvement in developing the new treaty may create significant political pressure for the United States to take responsive action to reduce GHGs. Both houses of Congress have previously considered legislation to reduce emissions of GHGs, and there are current legislative proposals to regulate GHGs. Any future federal laws, treaties or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

In addition, the EPA has begun to regulate GHG emissions. In December 2009, the EPA published its finding that certain emissions of GHGs presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Consequently, the EPA is requiring a reduction in emissions of GHGs from new motor vehicles beginning with the 2012 model year. Furthermore, the EPA published a final rule on June 3, 2010 to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration ("PSD") and Title V permitting programs. This rule "tailors" these permitting programs to apply to certain stationary sources of GHG emissions, such as power plants and oil refineries. Facilities required to obtain PSD permits for their GHG emissions will be required to meet emissions limits that are based on the "best available control technology," which will be established by the permitting agencies on a case-by-case basis. New facilities with GHG emissions of at least 100,000 tons per year ("tpy") of carbon dioxide equivalent ("CO2e") and existing facilities with at least 100,000 tpy of CO2e making changes that would increase GHG emissions by at least 75,000 tpy of CO2e are required to

obtain PSD permits. Facilities that must obtain a PSD permit anyway (i.e., to cover other regulated pollutants) must also address GHG emission increases greater than 75,000 tpy of CO2e. New and existing sources with GHG emissions above 100,000 tpy of CO2e must obtain Title V operating permits.

In addition, the EPA requires the reporting of GHGs from specified large GHG emission sources, including GHGs from petroleum and natural gas systems that emit more than 25,000 tons of GHGs per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage. The EPA is also proceeding with the first-ever regulation of GHGs from new power plants under the New Source Performance Standard provisions of the CAA. Revisions to the proposed standards were released in September 2013, and a final rule is expected during the fourth quarter of 2013. The release of this rule will trigger a requirement to regulate GHGs from existing power plants. Pursuant to a settlement agreement, the EPA has also committed to regulate GHGs from new petroleum refineries, though no draft rule has yet been released.

Several of the EPA's GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Even if new legislation requiring GHG controls is not adopted at the national level, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHGs, including obligations on utilities to purchase renewable energy and GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

Any one of these climate change regulatory and legislative initiatives could have a material adverse affect on our business, financial condition and results of operations. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.

The Federal Water Pollution Control Act, as amended, or the Clean Water Act ("CWA"), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the United States. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permits issued by the EPA or analogous state agencies. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements

under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. However, a bill pending in the U.S. House of Representatives would remove this exemption, which could have a significant impact on our operations. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The federal Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (the "OSH Act"), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSH Act's hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and citizens. In 2012, the Occupational Safety and Health Administration ("OSHA") issued a hazard alert related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The alert stated that workers at drill sites can be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at drill sites may lead to increased regulation and enforcement or related tort claims by our employees. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The federal Safe Drinking Water Act ("SDWA") and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state's environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control ("UIC") provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of "underground injection." However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for oil and gas activities under U.S. environmental laws. The Fracturing Responsibility and Awareness of Chemicals Act ("FRAC Act"), first introduced in 2011, would amend the SDWA to repeal the exemption from regulation under the UIC program for hydraulic fracturing. This bill has been reintroduced in each congressional session since it was initially proposed but has not yet garnered enough support to be put to a vote. If enacted, the FRAC Act would amend the definition of "underground injection" in the SDWA to encompass hydraulic

fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, to adhere to certain construction specifications, to fulfill monitoring, reporting and recordkeeping obligations, and to meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process. Note that each of the above components of the FRAC Act have become increasingly common in state laws since the FRAC Act was first introduced. Other recent bills in the U.S. House of Representatives would end certain exemptions for oil and natural gas operations related to permitting requirements for multiple commonly owned and adjacent sources of hazardous air pollutants under the CAA and permitting requirements for stormwater discharges under the CWA. If the exemptions for hydraulic fracturing are removed from U.S. environmental laws, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.

Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has recently asserted federal regulatory authority over, and issued draft permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA's UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process could be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has also issued new CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard (NSPS) for VOC and SO₂ emissions with expanded applicability to natural gas operations and new national emission standards for hazardous air pollutants (NESHAP) standards for air toxics, which are discussed in more detail above. These regulatory developments are indicative of increasing federal regulatory activity related to hydraulic fracturing, which has the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business. The EPA is also collecting information as part of a multi-year study into the effects of hydraulic fracturing on drinking water. A draft report is expected to be released for public comment and peer review in 2014. The results of this study could result in additional regulations, which could lead to operational burdens similar to those described above. The U.S. Department of the Interior has likewise proposed comprehensive regulations for hydraulic fracturing on federal land.

Several state governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. For example, the State of Colorado recently approved new rules requiring hydraulic fracturing operators in the state to sample water within a half-mile of a well site before operations can begin, and twice within six years after operations at the site end. Colorado is the first state to specifically include baseline groundwater monitoring in its permitting process, and it is expected that such requirements will be adopted by other states, in particular where fracturing occurs in more populous, developed or otherwise sensitive areas. A number of states around the country, including both Colorado and Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio, have begun to study potential seismic risks related to underground injection of fracturing fluids. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

The Oil Pollution Act of 1990, as amended ("OPA"), establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A "responsible party" under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

The National Environmental Policy Act of 1969, as amended ("NEPA"), requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment before their commencement. Generally, federal agencies must prepare either an environmental assessment or an environmental impact statement, depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the environment. The NEPA process involves significant public input through comments on alternatives to the proposed project or resource-specific mitigation options for the project. NEPA decisions can be and often are appealed through the administrative and federal court systems by process participants. Environmental groups in the United States have increasingly focused on the required public consultation process under NEPA as a forum for voicing concerns over continued development of fossil fuel energy sources in the United States and for seeking expansive environmental reviews of projects that relate to the production, transportation, or combustion of these fuels. Although we believe that our actions do not typically trigger NEPA analysis, should we ever be subject to NEPA, the process could result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and result in certain instances in litigation and/or the cancellation of certain leases.

Our properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission ("COGCC"). The COGCC recently approved new rules governing oil and gas activity that are intended to prevent or mitigate environmental impacts of oil and natural gas development and include the permitting of wells. Depending on how these and any other new rules are applied to our operations, they could add substantial increases in well costs in our Colorado operations. The rules could also impact the ability and extend the time necessary to obtain drilling permits, which creates substantial uncertainty about our ability to meet future drilling plans and thus production and capital expenditure targets.

As of September 30, 2013, we had 44 full-time employees, including 15 in executive, finance and accounting and administration, five in geology, 14 in production and engineering and 10 in land. All of our employees are located in the United States of America. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

We lease approximately 18,600 square feet of office space at 633 17th Street, Denver, Colorado, where our principal offices are located. We do not have any material field office facilities.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. We are not aware of any material pending or overtly threatened legal action against Sundance.

As is common in the oil and gas industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations or cash flows.

The following table lists the names of our directors and executive officers. The directors have served since their respective election or appointment and will serve until the next annual general meeting of shareholders or until a successor is duly appointed.

Eric P. McCrady has been our Chief Executive Officer since April 2011 and Managing Director of our board of directors since November 2011. He also served as our Chief Financial Officer from June 2010 until becoming Chief Executive Officer in 2011. Mr. McCrady has served in numerous positions in the energy, private investment and retail industries. From 2004 to 2010, Mr. McCrady was employed by The Broe Group, a private investment firm, in various financial and executive management positions across a variety of industry investment platforms, including energy, transportation and real estate. From 1997 to 2003, Mr. McCrady was employed by American Coin Merchandising, Inc. in various corporate finance roles. Mr. McCrady holds a degree in Business Administration from the University of Colorado, Boulder.

Cathy L. Anderson has been our Chief Financial Officer since December 2011. Ms. Anderson has over 25 years of experience, primarily in the oil and gas industry, and has extensive experience in budgeting and forecasting, regulatory reporting, corporate controls, and financial analysis and reporting. Prior to joining us in 2011, Ms. Anderson had been a consultant to companies in the oil and gas industry since 2006. Ms. Anderson held various positions, including Chief Financial Officer of Optigas, Inc., a natural gas gathering, processing and marketing company, from 2005 to 2006 and Vice President of Internal Audit and Consulting for TeleTech Holdings, Inc., a NASDAQ-listed global service firm providing outsourced customer management, from 2002 to 2004. From 1993 to 1999, Ms. Anderson was the Controller and Chief Accounting Officer of NYSE-listed Key Production Company, Inc. (predecessor to Cimarex Energy). She began her career in 1985 with Arthur Andersen, LLP. Ms. Anderson holds a Bachelor of Science in Business Administration with High Honors, emphasis in Accounting, from the University of Montana. She is a certified public accountant.

Grace L. Ford has been Vice President of Exploration and Development of our subsidiary, Sundance Energy, Inc., since March 2013 and had previously served as Vice President of Geology of Sundance Energy, Inc. since September 2011. Prior to joining us in 2011, Ms. Ford served in numerous positions in the oil and gas industry, working throughout the United States and in West Africa. Ms. Ford's experience spans both conventional and unconventional resource exploration, development, reservoir characterization and enhanced recovery projects. Ms. Ford has extensive operational experience in multi-rig horizontal development programs. From 2010 to 2011, Ms. Ford was employed as a geologist by Rock Oil, a private equity-backed company with operations in the Eagle Ford in south Texas. From 2007 to 2010, Ms. Ford was employed as a geoscience manager by Baytex Energy, USA, and from 2001 to 2007, Ms. Ford was employed as a geologist by EOG Resources, Inc. Prior to her tenure with EOG Resources, Inc., Ms. Ford served in various geologic or engineering capacities for Marathon Oil

Company, Schlumberger and the U.S. Geological Survey. Ms. Ford received her PhD in Geology from the Colorado School of Mines, a Master's of Science degree in Geology from the University of Arkansas and a Bachelors of Science degree in geology from the University of Wyoming. Ms. Ford is a registered professional geologist in the states of Texas, Wyoming and Utah.

Mike Wolfe has been our Vice President of Land of our subsidiary, Sundance Energy, Inc., since March 2013 and was previously Senior Land Manager from December 2010. He has more than 30 years of senior land experience in the oil and gas industry. His experience encompasses all areas of land management, including field leasing, title, lease records, joint venture contracts and management of multi-rig drilling programs in numerous basins throughout the United States. From 1997 to 2010, Mr. Wolfe was a regional land manager for Cimarex Energy Company, a public oil and gas exploration and production company. From 1996 to 1997, he was a site acquisition agent for PacBell Mobile, a cellular phone service provider. From 1990 to 1996, he was a project landman for Capitol Oil Corporation, an oil and gas exploration and production company. From 1981 to 1990, he was an assistant land manager for TXO Production Corporation, an oil and gas exploration and production company. Prior to his tenure with TXO Production Corporation, he was a land representative for Texaco. Mr. Wolfe holds a Bachelor of Science degree in Business Administration, with a concentration in finance and real estate from Colorado State University.

Michael D. Hannell has been a director of Sundance since March 2006 and chairman of our board of directors since December 2008. He is also the chairman of our Remuneration and Nomination Committee and a member of our Audit and Risk Management Committee. Mr. Hannell has over 45 years of experience in the oil and gas industry, initially in the downstream sector and subsequently in the upstream sector. His extensive experience has been in a wide range of engineering, operations, exploration and development, commercial, financial and corporate areas in the United States, United Kingdom, continental Europe and Australia at the senior executive level with Mobil Oil (now Exxon) and Santos Ltd. Mr. Hannell recently finished his term as the chairman of Rees Operations Pty Ltd (doing business as Milford Industries Pty Ltd), an Australian automotive components and transportation container manufacturer and supplier. He has also held a number of other board appointments including, until recently, the chairman of Sydac Pty Ltd, a designer and producer of simulation training products for industry. Mr. Hannell has also served on a number of not-for-profit boards, with appointments as president of the Adelaide-based Chamber of Mines and Energy, president of Business SA (formerly the South Australian Chamber of Commerce and Industry), chairman of the Investigator Science and Technology Centre, chairman of the Adelaide Graduate School of Business, and a member of the South Australian Legal Practitioners Conduct Board. Mr. Hannell holds a Bachelor of Science degree in Engineering (with Honors) from the University of London and is a Fellow of the Institution of Engineers Australia.

Damien A. Hannes has been a Director since 2009 and is the chairman of our Audit and Risk Management Committee and a member of our Remuneration and Nomination Committee. Mr. Hannes has over 25 years of finance experience. He has served over 15 years as a managing director and a member of the operating committee, among other senior management positions, for Credit Suisse's listed derivatives business in equities, commodities and fixed income in its Asia and Pacific region. From 1986 to 1993, Mr. Hannes was a director for Fay Richwhite Australia, a New Zealand merchant bank. Prior to his tenure with Fay Richwhite, Mr. Hannes was the director of operations and chief financial officer of Donaldson, Lufkin and Jenrette Futures Ltd, a U.S. investment bank. He has successfully raised capital and developed and managed mining, commodities trading and manufacturing businesses in the global market. Mr. Hannes also serves as the chairman of the board of directors of Australia Gold Corporation Ltd, a gold mining company with operations in Peru and South America and as a director of Quill Stationery Manufacturers Limited, a paper products business with operations in China. He holds a Bachelor of Business degree from the NSW University of Technology in Australia. Mr. Hannes is a qualified chartered accountant.

Neville W. Martin has been a Director since January 2012 and is a member of our Audit and Risk Management Committee. Prior to his election, he was an alternate director on our board of directors. Mr. Martin has over 40 years of experience as a lawyer specializing in corporate law and mining, oil and gas law. He is currently a consultant to the Australian law firm, Minter Ellison. Mr. Martin has served as a director on the boards of several Australian companies listed on the Australian Securities Exchange, including Stuart Petroleum Ltd from 1999 to 2002, Austin Exploration Ltd. from 2005 to 2008 and Adelaide Energy Ltd from 2005 to 2011. Mr. Martin holds a Bachelor of Laws degree from Adelaide University.

H. Weldon Holcombe has been a director and a member of our Remuneration and Nomination Committee since December 2012. Mr. Holcombe has over 30 years of onshore and offshore U.S. oil and gas industry experience, including technology, reservoir engineering, drilling and completions, production operations, construction, field development and optimization, Health, Safety and Environmental ("HSE"), and management of office, field and contract personnel. Most recently, Mr. Holcombe served as the Executive Vice President, Mid-Continental Region, for Petrohawk Energy Corporation from 2006 until its acquisition by BHP Billiton in 2011, after which Mr. Holcombe served as Vice President of New Technology Development for BHP Billiton. In his capacity as Executive Vice President for Petrohawk Energy Corporation, Mr. Holcombe managed development of leading unconventional resource plays, including the Haynesville, Fayetteville and Permian areas. In addition, Mr. Holcombe served as President of Big Hawk LLC, a subsidiary of Petrohawk Energy Corporation, a provider of basic oil and gas construction, logistics and rental services. Mr. Holcombe also served as corporate HSE officer for Petrohawk and joint chairperson of the steering committee that managed construction and operation of a gathering system in Petrohawk's Haynesville field with one billion cubic feet of natural gas of production per day. Prior to Petrohawk, Mr. Holcombe served in a variety of senior-level management, operations and engineering roles for KCS Energy and Exxon. Mr. Holcombe holds a Bachelor of Science degree in civil engineering from the University of Auburn.

There are no family relationships among any of our directors or executive officers. The business addresses for each of our directors and executive officers is Sundance Energy, Inc., 633 17th Street, Denver, Colorado 80202.

Our board of directors currently consists of five members, including our Chief Executive Officer. We believe that each of our directors has relevant industry experience. The membership of our board of directors is directed by the following requirements:

Our board of directors has delegated responsibility for the conduct of our businesses to the Managing Director, but remains responsible for overseeing the performance of management. Our board of directors has established delegated limits of authority, which define the matters that are delegated to management and those that require board of directors approval. None of our directors have any service

contracts with Sundance or any of its subsidiaries providing for benefits upon termination of employment.

To assist our board of directors with the effective discharge of its duties, it has established a Remuneration and Nominations Committee and an Audit and Risk Management Committee. Each committee operates under a specific charter approved by our board of directors.

Remuneration and Nominations Committee. The members of our Remuneration and Nominations Committee are Messrs. Hannell (Chairman), Hannes and Holcombe, all of whom are independent, non-executive directors. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes, and maintain a management succession plan. In addition, the committee will oversee, review, act on and report on various remuneration matters to our board of directors.

Audit and Risk Management Committee. The members of our Audit and Risk Management Committee are Messrs. Hannes (Chairman), Hannell and Martin, all of whom are independent, non-executive directors. Mr. McCrady and Ms. Anderson are non-voting management representatives who advise the committee as appropriate. This committee will oversee, review, act on and report on various auditing and accounting matters to our board of directors, including the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the committee will oversee, review, act on and report on various risk management matters to our board of directors.

The effective management of risk is central to our ongoing success. We have adopted a risk management policy to ensure that:

It is our objective to appropriately balance, protect and enhance the interests of all of our shareholders. Proper behavior by our directors, officers, employees and those organizations that we contract to carry out work is essential in achieving this objective.

We have established a code of conduct, which sets out the standards of behavior that apply to every aspect of our dealings and relationships, both within and outside Sundance. The following standards of behavior apply:

Our board of directors recognizes that the attraction and retention of high-calibre directors and executives with appropriate incentives is critical to generating shareholder value. We have designed our compensation program to provide rewards for individual performance and corporate results and to encourage an ownership mentality among our executives and other key employees.

The Australian non-executive directors receive a basic annual fee for board membership and annual fees for committee service and chairmanships, all of which includes the superannuation guarantee contribution required by the Australian government, which was 9.25% as of July 1, 2013. In accordance with ASX corporate governance principles, they do not receive any other retirement benefits or any performance-related incentive payments by means of cash or equity. Some individuals, however, have chosen to forego part of their salary to increase payments toward superannuation. To align directors' interests with shareholder interests, the directors are encouraged to hold our ordinary shares. Our U.S.-based executives receive statutory retirement benefit payments as required under applicable U.S. law. All remuneration paid to directors and executives is valued in accordance with applicable IFRS accounting rules.

The Remuneration and Nomination Committee makes recommendations to our board of directors in relation to total compensation of directors and executives and reviews their remuneration annually. Independent external advice is sought when required. There were no consultants utilized during the most recent fiscal period.

In assessing total compensation, our objective is to be competitive with industry compensation while considering individual and company performance. Base salaries for executives recognize their qualifications, experience and responsibilities as well as their unique value and historical contributions to Sundance. In addition to being important to attracting and retaining executives, setting base salaries at appropriate levels motivates employees to aspire to and accept enlarged opportunities. We do not consider base salaries to be part of performance-based compensation, in setting the amount, the individuals' performance is considered. The majority of each executive's compensation is performance based and "at risk." We believe that equity ownership is an important element of compensation and that, over time, more of the executives' compensation should be equity-based rather than cash-based so as to better align executive compensation with shareholder return. The portion of "at risk" compensation for the most recently concluded fiscal year is set forth in the table below.

In support of this, we recently adopted stock ownership guidelines for certain key executive officers. Our Chief Executive Officer is required to hold ordinary shares with a value equal to five times the amount of his annual base salary. The remaining executive officers are required to hold ordinary shares with a value equal to 2.5 times their respective annual base salaries. The applicable level of ownership is required to be achieved within five years of the later of the date these guidelines were adopted or the date the person first became an executive officer. Unexercised and/or unvested equity awards do not count toward satisfaction of the guidelines.

We have an incentive compensation program, comprised of short and long-term components, to incentivize key executives and employees of Sundance and its subsidiaries. The goal of the incentive compensation program is to motivate management and senior employees to achieve short and long-term goals to improve shareholder value. This plan represents the performance-based, at risk component of each executive's total compensation. The incentive compensation program is designed to:

The incentive compensation program has provisions for an annual cash and equity bonus in addition to the base salary levels. The annual cash bonus Short-Term Incentive ("STI") is established to

reward short-term performance towards our goal of increasing shareholder value. The equity component Long-Term Incentive ("LTI") is intended to reward progress towards our long-term goals and to motivate and retain management to make decisions benefiting long-term value creation.

We have two active equity incentive plans under the LTI component of the incentive compensation program. These are the Sundance Employee Option Plan ("ESOP") and the Sundance Energy Australia Limited Restricted Share Units available only to our U.S. employees under the Incentive Compensation Plan (the "RSU Plan"). Any grants made to employees that also serve as a director are subject to shareholder approval prior to issuance.

The ESOP provides for the issuance of stock options at an exercise price determined at the time of the issue by a committee designated by the board (the "Plan Committee"). Options under the ESOP may be granted to eligible employees, as determined by the Plan Committee, and typically include our executive officers, directors and key employees. Historically, the Plan Committee has granted options in connection with attracting new employees, which grant is made once employment has commenced. It is within the discretion of the Plan Committee, however, to authorize additional option grants during the term of employment. Generally, an option vests 20% on the 90th day following the grant date, with an additional 20% vesting on the first, second, third and fourth anniversaries thereof. Options are valued using the Black-Scholes methodology and recognized as remuneration in accordance with their vesting conditions. In the event of a voluntary winding up of the Company, unvested stock options vest immediately. We may amend the ESOP or any portion thereof, or waive or modify the application of the ESOP rules in relation to a participant, at any time. Certain amendments to the ESOP may require the approval of the holders of the options granted under the ESOP.

The RSU Plan provides for the issuance of restricted stock units ("RSUs") to our U.S. employees. The purpose of issuing RSUs is to reward senior executives and employees for achievement of financial and operational performance targets established by our board. The RSU Plan is administered by our board. RSUs under the RSU Plan may be granted to eligible employees (as determined by our board, which typically include our executive officers, directors and key employees) from a bonus pool established at the sole discretion of our board. The bonus pool is subject to board and management review of performance metrics with respect to both our and the individual employee's performance over a measured period determined by the Renumeration and Nomination Committee and the board as discussed below. The RSUs may be settled in cash or stock at the discretion of our board. Under the RSU Plan, 25% of the RSUs vest on the grant date, and 25% vest on each of the first, second and third anniversaries of the grant date. The RSUs are based on performance targets established and approved by our board. In the event of a corporate take-over or change in control (as defined in the RSU Plan), our board in its discretion may cause all unvested RSUs to vest and be satisfied by the issue of one share each or provide for the cancellation of outstanding RSUs and a cash payment equal to the then-fair market value of the RSUs. We may amend, suspend or terminate the RSU Plan or any portion thereof at any time. Certain amendments to the RSU Plan may require approval of the holders of the RSUs who will be affected by the amendment.

The available bonus pool for both STI and LTI is based on a percentage of each employee's annual base salary. On an annual basis, targets are established and agreed by the Remuneration and Nomination Committee, subject to endorsement by our board of directors. The targets are used to determine the bonus pool, but both the STI and LTI bonuses require approval by the Remuneration and Nomination Committee and are fully discretionary. Bonuses earned under the STI will be paid in cash and those under the LTI by means of awarding RSUs under the RSU Plan.

For the most recent six-month period ended December 31, 2012, the following metrics were adopted as targets:

In addition, certain ceilings and claw-back provisions have been set by our board of directors to ensure that the performance metrics are aligned with the best interests of the shareholders. It is the intention of the Remuneration and Nomination Committee to carefully monitor the incentive compensation program to ensure its ongoing effectiveness.

The following discussion is based upon a remuneration report that we prepared in compliance with listing rules of the Australian Securities Exchange. Ms. Ford and Mr. Wolfe are executive officers of our subsidiary Sundance Energy, Inc. but not of Sundance Energy Australia Limited. As a result, their remuneration is not discussed below.

Details of the remuneration of our directors and executive officers of Sundance Energy Australia Limited for the six-month period ended December 31, 2012 are as follows:

	Fixed Based Remuneration								Share Based		Performance Based

Director	Salary and Fees		Non- monetary Benefits		Post- employment Benefits		Superannuation		Payments- Options		STI-Cash Bonus		LTI-Share Based			Total
E. McCrady	$	137,500	$	3,523	$	4,375	$	—	$	11,904	$	175,000	$	141,332		$	473,635
A.M. Hunter III(1)		22,466		89		337		—		459		—		(1,074	)		22,278
M. Hannell		42,878		—		—		3,859		—		—		—			46,737
D. Hannes		32,158		—		—		2,894		—		—		—			35,053
N. Martin		23,821		—		—		2,144		—		—		—			25,965
W. Holcombe(2)		1,644		—		—		—		—		—		—			1,644

	$	260,468	$	3,612	$	4,712	$	8,897	$	12,363	$	175,000	$	140,259		$	605,312

Executive officers
C. Anderson	$	112,500	$	2,462	$	3,091	$	—	$	39,804	$	105,000	$	70,162		$	333,020
C. Gooden		36,046		—		—		—		—		—		—			36,046

		148,546		2,462		3,091		—		39,804		105,000		70,162			369,066

Total	$	409,014	$	6,074	$	7,803	$	8,897	$	52,167	$	280,000	$	210,421		$	974,377

Remuneration is structured to recognize both an individual's responsibilities, qualifications and experience, as well as to drive performance over the short and long-term. Fixed remuneration is established relative to the market and aligned with responsibilities, qualifications and experience, while

variable remuneration is used to reward and motivate outcomes beyond the standard expected. The relative weightings of "at risk" variable remuneration compared to fixed remuneration is as follows:

No options were issued as part of remuneration to directors or executive officers for the six-month period ended December 31, 2012. In May 2013, Mr. McCrady and Mr. Hunter exercised 1,500,000 and 875,000 options, respectively. The only options awarded in the year ended June 30, 2012 were to attract and retain Cathy L. Anderson. These options vested 20% at grant date and vest 20% equally on each of the first four anniversaries of the grant date.

In April 2013, 247,447, 66,957 and 120,500 of Mr. McCrady, Ms. Anderson and Mr. Hunter's RSUs vested as of December 31, 2012 were converted to ordinary shares respectively.

All RSUs vest 25% on date of grant and 25% vest equally on each of the first three anniversaries of the grant date.

Our Chief Executive Officer, Eric P. McCrady, has an employment agreement with a three-year term commencing May 2011 and base remuneration of $275,000 per year, which is reviewed annually by the Remuneration and Nomination Committee. In the event of a not-for-cause termination or change in control (as described in the employment agreement) in which Mr. McCrady does not remain employed by the acquirer, the employment agreement provides payment of Mr. McCrady's base remuneration through the end of the term of the employment agreement. He is eligible to participate in our incentive compensation program.

Other than Mr. McCrady, none of our executive officers has an employment agreement. Mr. Gooden, our former Company Secretary, provided services to Sundance through a contractual arrangement. Subsequent to Mr Gooden's retirement in August 2013, Damien Connor was appointed our Company Secretary. Mr. Connor provides services to Sundance through a contractual arrangement. None of our directors has any service contracts with Sundance or any of its subsidiaries providing for benefits upon termination of employment.

The following table presents certain information regarding the beneficial ownership of our ordinary shares based on 462,611,982 ordinary shares outstanding as of November 30, 2013 by:

Beneficial ownership is determined according to the rules of the SEC and generally means that a person has beneficial ownership of a security if he or she possesses sole or shared voting or investment power of that security and includes options that are exercisable within 60 days. Information with respect to beneficial ownership has been furnished to us by each director, executive officer, or 5% or more shareholder, as the case may be.

As of November 30, 2013, we had 33 shareholders of record in the United States. These shareholders held an aggregate of 9,159,019 of our outstanding ordinary shares, or approximately 2% of our outstanding ordinary shares.

Unless otherwise indicated, to our knowledge each shareholder possesses sole voting and investment power over the ordinary shares listed subject to community property laws, where applicable. None of our shareholders has different voting rights from other shareholders. Unless otherwise indicated, the address for each of the persons listed in the table below is Sundance Energy, Inc., 633 17th Street, Suite 1950, Denver, Colorado 80202.

	Ordinary Shares Beneficially Owned Prior to Offering						Ordinary Shares Beneficially Owned After the Offering(1)

Shareholder	Number			Percent			Number			Percent
*5% Shareholders*
IOOF Holdings Limited(2)		34,259,557			7.41	%		34,259,557
Acorn Capital Limited(3)		31,141,966			6.73	%		31,141,966
Provident Minerals Pte. Ltd(4)		24,092,076			5.21	%		24,092,076
*Officers and Directors*
Eric P. McCrady		1,353,076	(5)		*			1,353,076	(5)		*
Michael D. Hannell		917,442			*			917,442			*
Damien A. Hannes		5,681,561	(6)		1.23	%		5,681,561	(6)		*
Neville W. Martin		216,858	(7)		*			216,858	(7)		*
H. Weldon Holcombe		220,000			*			220,000			*
Cathy L. Anderson		547,595	(8)		*			547,595	(8)		*

Officers and directors as a group (six persons)		8,936,532			1.93	%		8,936,532

beneficially owned by Provident Minerals Pte. Ltd. The address of Provident Minerals Pte. Ltd is 80 Raffles Place #51-02 UOB Plaza, Singapore 048624.

(5): Includes (i) 1,179,130 ordinary shares, and (ii) 100,446 ordinary shares underlying RSUs vesting during October 2013 and (iii) 73,500 ordinary shares underlying RSUs vesting during December 2013.
(6): Includes (i) 377,858 ordinary shares held by Mr. Hannes individually, and (ii) 5,303,703 ordinary shares held in a trust of which Mr. Hannes serves as a director and shares voting and investment power with respect to such shares.
(7): Includes (i) 212,858 ordinary shares held in trust of which Mr. Martin serves as trustee and is a beneficiary and (ii) 4,000 ordinary shares jointly held with Mr. Martin's spouse.
(8): Includes (i) 80,623 ordinary shares, (ii) options to purchase up to 400,000 ordinary shares, exercisable until March 2019 at an exercise price of A$0.95 per share and (iii) 66,972 ordinary shares underlying RSUs vesting during October 2013.

To our knowledge, there have not been any significant changes in the ownership of our ordinary shares by major shareholders over the past three years, except as follows (which is based upon substantial shareholder notices filed with the ASX):

We note that, with the exception of Mr. Hannes, each of our directors and executive officers owns less than 1% of our outstanding ordinary shares.

Other than as disclosed below, from July 1, 2010 to September 30, 2013 we did not enter into any transactions or loans with any: (i) enterprises that directly or indirectly, through one or more intermediaries, control, are controlled by or are under common control with us; (ii) associates; (iii) individuals owning, directly or indirectly, an interest in our voting power that gives them significant influence over us, and close members of any such individual's family; (iv) key management personnel and close members of such individuals' families; or (v) enterprises in which a substantial interest in our voting power is owned, directly or indirectly, by any person described in (iii) or (iv) or over which such person is able to exercise significant influence.

Neville Martin has been a director of Sundance since March 2012 and was a partner and is now a consultant of Minter Ellison, an Australian law firm. Minter Ellison was paid a total of $216,603, $148,073 and $124,007 for legal services for the nine-month period ended September 30, 2013, the six-month period ended December 31, 2012 and the fiscal year ended June 30, 2012, respectively.

On June 6, 2013, IOOF acquired 6,700,000 of our ordinary shares in a private placement for A$5,762,000.

The following description of our ordinary shares is only a summary. We encourage you to read our Constitution, which is included as an exhibit to this registration statement, of which this prospectus forms a part.

We are a public company limited by shares registered under the Corporations Act by the Australian Securities and Investments Commission ("ASIC"). Our corporate affairs are principally governed by our Constitution, the Corporations Act and the ASX Listing Rules. Our ordinary shares trade on the ASX, and we are applying to list the ADSs on The NASDAQ Global Select Market.

The Australian law applicable to our Constitution is not significantly different than a U.S. company's charter documents except we do not have a limit on our authorized share capital, the concept of par value is not recognized under Australian law and as further discussed under "—Our Constitution."

Subject to restrictions on the issue of securities in our Constitution, the Corporations Act and the ASX Listing Rules of the Australian Securities Exchange and any other applicable law, we may at any time issue shares and grant options or warrants on any terms, with the rights and restrictions and for the consideration that our board of directors determine.

The rights and restrictions attaching to ordinary shares are derived through a combination of our Constitution, the common law applicable to Australia, the ASX Listing Rules, the Corporations Act and other applicable law. A general summary of some of the rights and restrictions attaching to our ordinary shares are summarized below. Each ordinary shareholder is entitled to receive notice of, and to be present, vote and speak at, general meetings.

As of December 31, 2012, we had 278,765,141 ordinary shares outstanding. As of November 30, 2013, we had (i) 462,611,982 ordinary shares outstanding and (ii) outstanding employee options to purchase an aggregate of 5,051,666 ordinary shares at a weighted average exercise price of A$1.02.

During the last three years, the following changes have been made to our ordinary share capital:

In addition, we issued the following ordinary shares upon exercise of employee options over the past three years:

Our Constitution is similar in nature to the bylaws of a U.S. corporation. It does not provide for or prescribe any specific objectives or purposes of Sundance. Our Constitution is subject to the terms of the ASX Listing Rules and the Corporations Act. It may be amended or repealed and replaced by special resolution of shareholders, which is a resolution passed by at least 75% of the votes cast by shareholders entitled to vote on the resolution.

Under Australian law, a company has the legal capacity and powers of an individual both within and outside Australia. The material provisions of our Constitution are summarized below. This summary is not intended to be complete nor to constitute a definitive statement of the rights and liabilities of our shareholders. Our Constitution is filed as an exhibit to the registration statement, of which this prospectus forms a part.

Except where permitted by the Corporations Act, a director may not vote in respect of any contract or arrangement in which the director has, directly or indirectly, any material interest according to our Constitution. Such director must not be counted in a quorum, must not vote on the matter and must not be present at the meeting while the matter is being considered.

Unless a relevant exception applies, the Corporations Act requires our directors to provide disclosure of certain interests and prohibits directors of companies listed on the ASX from voting on matters in which they have a material personal interest and from being present at the meeting while the matter is being considered. In addition, the Corporations Act and the ASX Listing Rules require shareholder approval of any provision of related party benefits to our directors.

Our directors are paid remuneration for their services as directors, which is determined in a general meeting of shareholders. The aggregate, fixed sum for directors' remuneration is to be divided among the directors in such proportion as the directors themselves agree and in accordance with our Constitution. The fixed sum remuneration for directors may not be increased except at a general meeting of shareholders and the particulars of the proposed increase are required to have been provided to shareholders in the notice convening the meeting. In addition, executive directors may be paid remuneration as employees of Sundance.

Pursuant to our Constitution, any director who devotes special attention to our business or who otherwise performs services that in the opinion of our board of directors, are outside the scope of the ordinary duties of a director may be paid extra remuneration, which is determined by our board of directors.

In addition to other remuneration provided in our Constitution, all of our directors are entitled to be paid by us for reasonable travel accommodation and other expenses incurred by the directors in attending company meetings, board meetings, committee meetings or while engaged on our business.

In addition, in accordance with our Constitution, a director may be paid a retirement benefit as determined by our board of directors, subject to the limits set out in the Corporations Act and the ASX Listing Rules.

Pursuant to our Constitution, the management and control of our business affairs are vested in our board of directors. Our board of directors has the power to raise or borrow money, and charge any of our property or business or any uncalled capital, and may issue debentures or give any other security

for any of our debts, liabilities or obligations or of any other person, in each case, in the manner and on terms it deems fit.

Pursuant to our Constitution, one-third of our directors, other than the director who is the Chief Executive Officer, must retire from office at every annual general meeting. If the number of directors is not a multiple of three, then the number nearest, to but not less than, one-third must retire from office. The directors who retire in this manner are required to be the directors or director longest in office since last being elected. A director, other than the director who is the Chief Executive Officer, must retire from office at the conclusion of the third annual general meeting after which the director was elected. Retired directors are eligible for a re-election to the board of directors.

There are currently no requirements for directors to own our ordinary shares in order to qualify as directors.

Subject to the Corporations Act and the ASX Listing Rules, the rights attaching to our ordinary shares are detailed in our Constitution. Our Constitution provides that any of our ordinary shares may be issued with preferred, deferred or other special rights, whether in relation to dividends, voting, return of share capital, payment of calls or otherwise as our board of directors may determine from time to time. Subject to the Corporations Act and the ASX Listing Rules, any rights and restrictions attached to a class of shares, we may issue further shares on such terms and conditions as our board of directors resolve. Currently, our outstanding share capital consists of only one class of ordinary shares.

Our board of directors may from time to time determine to pay dividends to shareholders. All unclaimed dividends may be invested or otherwise made use of by our board of directors for our benefit until claimed or otherwise disposed of in accordance with our Constitution.

Under our Constitution, each shareholder has one vote determined by a show of hands at a meeting of the shareholders. On a poll vote, each shareholder shall have one vote for each fully paid share and a fractional vote for each share that is not fully paid, such fraction being equivalent to the proportion of the amount that has been paid to such date on that share. Shareholders may vote by proxy, but not electronically. Under Australian law, shareholders of a public company are not permitted to approve corporate matters by written consent. Our Constitution does not provide for cumulative voting.

Note that ADS holders may not directly vote at a meeting of the shareholders but may instruct the depositary to vote the number of deposited ordinary shares their ADSs represent.

Subject to the Corporations Act and pursuant to our Constitution, our shareholders are entitled to participate in our profits only by payment of dividends. Our board of directors may from time to time determine to pay dividends to the shareholders; however, no dividend is payable except in accordance with the thresholds set out in the Corporations Act.

Our Constitution provides for the right of shareholders to participate in a surplus in the event of our liquidation.

There are no redemption provisions in our Constitution in relation to ordinary shares. Under our Constitution and subject to the Corporations Act, any preference shares may be issued on the terms that they are, or may at our option be, liable to be redeemed.

There are no sinking fund provisions in our Constitution in relation to ordinary shares.

According to our Constitution, our board of directors may make any calls from time to time upon shareholders in respect of all monies unpaid on partly paid shares, subject to the terms upon which any of the partly paid shares have been issued. Each shareholder is liable to pay the amount of each call in the manner, at the time and at the place specified by our board of directors. Calls may be made payable by instalment.

Provisions Discriminating Against Holders of a Substantial Number of Shares

There are no provisions under our Constitution discriminating against any existing or prospective holders of a substantial number of our ordinary shares.

The rights attached to shares in a class of shares may only be varied or cancelled by a special resolution of Sundance, together with either:

We must give written notice of any variation or cancellation if rights to the members of the class within seven days after the variation or cancellation is made.

General meetings of shareholders may be called by our board of directors. Except as permitted under the Corporations Act, shareholders may not convene a meeting. Under the Corporations Act, shareholders with at least 5% of the votes that may be cast at a general meeting may call and arrange to hold a general meeting. The Corporations Act requires the directors to call and arrange to hold a general meeting on the request of shareholders with at least 5% of the votes that may be cast at a general meeting or at least 100 shareholders who are entitled to vote at the general meeting. Notice of the proposed meeting of our shareholders is required at least 28 days prior to such meeting under the Corporations Act.

According to our Constitution, the chairperson of the general meeting may refuse admission to or exclude from the meeting any person who is in possession of a picture recording or sound recording device, in possession of a placard or banner, in possession of an object considered by the chairperson to be dangerous, offensive or liable to cause disruption, any person who refuses to produce or permit examination of any object, who behaves or threatens to behave in a dangerous, offensive or destructive

manner, or is not a director or one of our auditors, one of our shareholders, or a proxy, attorney or representative of one of our shareholders.

There are no limitations on the rights to own securities imposed by our Constitution. However, acquisitions and proposed acquisitions of shares in Australian companies may be subject to review and approval by the Australian Federal Treasurer under the Foreign Acquisitions and Takeovers Act 1975 (the "FATA"), which generally applies to acquisitions or proposed acquisitions:

The Australian Federal Treasurer may prevent a proposed acquisition in the above categories or impose conditions on such acquisition if the Treasurer is satisfied that the acquisition would be contrary to the national interest. If a foreign person acquires shares or an interest in shares in an Australian company in contravention of the FATA, the Australian Federal Treasurer may order the divestiture of such person's shares or interest in shares in Sundance. The Australian Federal Treasurer may order divestiture pursuant to the FATA if he determines that the acquisition has resulted in that foreign person, either alone or together with other non-associated or associated foreign persons, controlling Sundance and that such control is contrary to the national interest.

There are no provisions in our Constitution that require a shareholder to disclose ownership above a certain threshold. The Corporations Act, however, requires a substantial shareholder to notify us and the Australian Securities Exchange once a 5% interest in our ordinary shares is obtained. Further, once a shareholder owns a 5% interest in us, such shareholder must notify us and the ASX of any increase or decrease of 1% or more in its holding of our ordinary shares. Upon becoming a U.S. public company, our shareholders will also be subject to disclosure requirements under U.S. securities laws.

Subject to our Constitution, the Corporations Act, the ASX Listing Rules and any other applicable law, we may at any time issue shares and grant options or warrants on any terms, with preferred, deferred or other special rights and restrictions and for the consideration and other terms that the directors determine. Our power to issue shares includes the power to issue bonus shares (for which no consideration is payable to Sundance), preference shares and partly paid shares.

Subject to the requirements of our Constitution, the Corporations Act, the ASX Listing Rules and any other applicable law, including relevant shareholder approvals, we may consolidate or divide our share capital into a larger or smaller number by resolution, reduce our share capital (provided that the reduction is fair and reasonable to our shareholders as a whole and does not materially prejudice our ability to pay creditors) or buy back our ordinary shares whether under an equal access buy-back or on a selective basis.

Takeovers of listed Australian public companies, such as Sundance, are regulated by the Corporations Act, which prohibits the acquisition of a "relevant interest" in issued voting shares in a listed company if the acquisition will lead to that person's or someone else's voting power in Sundance

increasing from 20% or below to more than 20% or increasing from a starting point that is above 20% and below 90%, subject to a range of exceptions.

If, at a particular time, a person has a relevant interest in issued securities and the person:

There are a number of exceptions to the above prohibition on acquiring a relevant interest in issued voting shares above 20%. In general terms, some of the more significant exceptions include:

Breaches of the takeovers provisions of the Corporations Act are criminal offenses. ASIC and the Australian Takeover Panel have a wide range of powers relating to breaches of takeover provisions, including the ability to make orders canceling contracts, freezing transfers of, and rights attached to, securities, and forcing a party to dispose of securities. There are certain defenses to breaches of the takeover provisions provided in the Corporations Act.

Inspection of our records is governed by the Corporations Act. Any member of the public has the right to inspect or obtain copies of our registers on the payment of a prescribed fee. Shareholders are not required to pay a fee for inspection of our registers or minute books of the meetings of shareholders. Other corporate records, including minutes of directors' meetings, financial records and other documents, are not open for inspection by shareholders. Where a shareholder is acting in good faith and an inspection is deemed to be made for a proper purpose, a shareholder may apply to the court to make an order for inspection of our books.

The NASDAQ listing rules allow for a foreign private issuer, such as Sundance, to follow its home country practices in lieu of certain of the NASDAQ's corporate governance standards. In connection with our NASDAQ Global Select Market Listing Application, we expect to rely on exemptions from certain corporate governance standards that are contrary to the laws, rules, regulations or generally accepted business practices in Australia. These exemptions being sought are described below:

The Bank of New York Mellon, as depositary, will register and deliver American Depositary Shares, also referred to as ADSs. Each ADS will represent ordinary shares (or a right to receive ordinary shares) deposited with National Australia Bank Limited, as custodian for the depositary. Each ADS will also represent any other securities, cash or other property which may be held by the depositary. The depositary's office at which the ADSs will be administered is located at 101 Barclay Street, New York, New York 10286. The Bank of New York Mellon's principal executive office is located at One Wall Street, New York, New York 10286.

You may hold ADSs either (A) directly (i) by having an American Depositary Receipt, also referred to as an ADR, which is a certificate evidencing a specific number of ADSs, registered in your name, or (ii) by having ADSs registered in your name in the Direct Registration System, or (B) indirectly by holding a security entitlement in ADSs through your broker or other financial institution. If you hold ADSs directly, you are a registered ADS holder ("ADS holder"). This description assumes you are an ADS holder. If you hold the ADSs indirectly, you must rely on the procedures of your broker or other financial institution to assert the rights of ADS holders described in this section. You should consult with your broker or financial institution to find out what those procedures are.

The Direct Registration System ("DRS"), is a system administered by The Depository Trust Company, also referred to as DTC, pursuant to which the depositary may register the ownership of uncertificated ADSs, which ownership is confirmed by periodic statements sent by the depositary to the registered holders of uncertificated ADSs.

As an ADS holder, we will not treat you as one of our shareholders and you will not have shareholder rights. Australian law governs shareholder rights. The depositary will be the holder of the shares underlying your ADSs. As a registered holder of ADSs, you will have ADS holder rights. A deposit agreement among us, the depositary and you, as an ADS holder, and all other persons indirectly holding ADSs sets out ADS holder rights as well as the rights and obligations of the depositary. New York law governs the deposit agreement and the ADSs.

The following is a summary of the material provisions of the deposit agreement. Because it is a summary, it does not contain all the information that may be important to you. For more complete information, you should read the entire deposit agreement and the form of ADR which summarizes certain terms of your ADSs. You can read a copy of the deposit agreement which is filed as an exhibit to the registration statement of which this prospectus forms a part. You may also obtain a copy of the deposit agreement at the SEC's Public Reference Room which is located at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-732-0330. You may also find the registration statement and the attached deposit agreement on the SEC's website at http://www.sec.gov.

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

The depositary is not responsible if it decides that it is unlawful or impractical to make a distribution available to any ADS holders. We have no obligation to register ADSs, shares, rights or other securities under the Securities Act. We also have no obligation to take any other action to permit the distribution of ADSs, shares, rights or anything else to ADS holders. This means that you may not receive the distributions we make on our ordinary shares or any value for them if it is illegal or impractical for us to make them available to you.

The depositary will deliver ADSs if you or your broker deposit shares or evidence of rights to receive shares with the custodian. Upon payment of its fees and expenses and of any taxes or charges, such as stamp taxes or stock transfer taxes or fees, the depositary will register the appropriate number of ADSs in the names you request and will deliver the ADSs to or upon the order of the person or persons that made the deposit.

You may surrender your ADSs at the depositary's office. Upon payment of its fees and expenses and of any taxes or charges, such as stamp taxes or stock transfer taxes or fees, the depositary will deliver the shares and any other deposited securities underlying the ADSs to the ADS holder or a person the ADS holder designates at the office of the custodian. In the alternative, at your request, risk and expense, the depositary will deliver the deposited securities at its office, if feasible.

How do ADS holders interchange between certificated ADSs and uncertificated ADSs?

You may surrender your ADR to the depositary for the purpose of exchanging your ADR for uncertificated ADSs. The depositary will cancel that ADR and will send to the ADS holder a statement confirming that the ADS holder is the registered holder of uncertificated ADSs. Alternatively, upon receipt by the depositary of a proper instruction from a registered holder of uncertificated ADSs requesting the exchange of uncertificated ADSs for certificated ADSs, the depositary will execute and deliver to the ADS holder an ADR evidencing those ADSs.

ADS holders may instruct the depositary to vote the number of deposited ordinary shares their ADSs represent. The depositary will notify ADS holders of shareholders' meetings and arrange to deliver our voting materials to them upon our request. Those materials will describe the matters to be voted on and explain how ADS holders may instruct the depositary how to vote. For instructions to be valid, they much reach the depositary by a date established by the depositary.

Otherwise, you won't be able to exercise your right to vote unless you withdraw the shares. However, you may not know about the meeting with a sufficient amount of advance notice to withdraw the shares.

The depositary will attempt, as far as practical, subject to the laws of the Australia and of our articles of association or similar documents, to vote or to have its agents vote the shares or other deposited securities as instructed by ADS holders. The depositary will only vote or attempt to vote as instructed.

We can not assure you that you will receive the voting materials in time to ensure that you can instruct the depositary to vote your ordinary shares. In addition, the depositary and its agents are not responsible for failing to carry out voting instructions or for the manner of carrying out voting instructions. This means that you may not be able to exercise your right to vote and there may be nothing you can do if your ordinary shares are not voted as you requested.

In order to give you a reasonable opportunity to instruct the depositary as to the exercise of voting rights relating to deposited securities, if we request the depositary to act, we agree to give the depositary notice of any such meeting and details concerning the matters to be voted upon at least 30 days in advance of the meeting date.

Persons depositing or withdrawing ordinary shares or ADS holders must pay the depositary:		For:


$5.00 (or less) per 100 ADSs (or portion of 100 ADSs)				• Issuance of ADSs, including issuances resulting from a distribution of shares or rights or other property
				• Cancellation of ADSs for the purpose of withdrawal, including if the deposit agreement terminates

$.05 (or less) per ADS				• Any cash distribution to ADS holders

A fee equivalent to the fee that would be payable if securities distributed to you had been shares and the shares had been deposited for issuance of ADSs				• Distribution of securities distributed to holders of deposited securities which are distributed by the depositary to ADS holders

$.05 (or less) per ADS per calendar year				• Depositary services

Registration or transfer fees				• Transfer and registration of shares on our share register to or from the name of the depositary or its agent when you deposit or withdraw shares

Expenses of the depositary				• Cable, telex and facsimile transmissions (when expressly provided in the deposit agreement)
				• Converting foreign currency to U.S. dollars

Taxes and other governmental charges the depositary or the custodian have to pay on any ADS or share underlying an ADS, for example, stock transfer taxes, stamp duty or withholding taxes				• As necessary

Any charges incurred by the depositary or its agents for servicing the deposited securities				• As necessary

The depositary collects its fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The depositary may collect its annual fee for depositary services by deduction from cash distributions or by directly billing investors or by charging the book-entry system accounts of participants acting for them. The depositary may generally refuse to provide fee-attracting services until its fees for those services are paid. The depositary may collect any of its fees by deduction from any cash distribution payable to ADS holders that are obligated to pay those fees.

From time to time, the depositary may make payments to Sundance to reimburse or share revenue from the fees collected from ADS holders, or waive fees and expenses for services provided, generally relating to costs and expenses arising out of establishment and maintenance of the ADS program. In performing its duties under the deposit agreement, the depositary may use brokers, dealers or other service providers that are affiliates of the depositary and that may earn or share fees or commissions.

You will be responsible for any taxes or other governmental charges payable on your ADSs or on the deposited securities represented by any of your ADSs. The depositary may refuse to register any transfer of your ADSs or allow you to withdraw the deposited securities represented by your ADSs until such taxes or other charges are paid. It may apply payments owed to you or sell deposited securities represented by your ADSs to pay any taxes owed and you will remain liable for any deficiency. If the depositary sells deposited securities, it will, if appropriate, reduce the number of ADSs to reflect the sale and pay to ADS holders any proceeds, or send to ADS holders any property, remaining after it has paid the taxes.

If we:

Then:

•

Reclassify, split up or consolidate any of the deposited securities

•

Distribute securities in respect of deposited shares that are not distributed to you

•

Recapitalize, reorganize, merge, liquidate, sell all or substantially all of our assets, or take any similar action

The cash, shares or other securities received by the depositary will become deposited securities. Each ADS will automatically represent its equal share of the new deposited securities.

The depositary may distribute new ADSs representing the new deposited securities or ask you to surrender your outstanding ADRs in exchange for new ADRs identifying the new deposited securities.

We may agree with the depositary to amend the deposit agreement and the ADRs without your consent for any reason. If an amendment adds or increases fees or charges, except for taxes and other governmental charges or expenses of the depositary for registration fees, facsimile costs, delivery charges or similar items, or prejudices a substantial right of ADS holders, it will not become effective for outstanding ADSs until 30 days after the depositary notifies ADS holders of the amendment. At the time an amendment becomes effective, you are considered, by continuing to hold your ADSs, to agree to the amendment and to be bound by the ADRs and the deposit agreement as amended.

The depositary will terminate the deposit agreement at our direction by mailing notice of termination to the ADS holders then outstanding at least 30 days prior to the date fixed in such notice for such termination. The depositary may also terminate the deposit agreement by mailing notice of termination to us and the ADS holders if 60 days have passed since the depositary told us it wants to resign but a successor depositary has not been appointed and accepted its appointment.

After termination, the depositary and its agents will do the following under the deposit agreement (but nothing else):

Four months after termination, the depositary may sell any remaining deposited securities by public or private sale. After that, the depositary will hold the money it received on the sale, as well as

any other cash it is holding under the deposit agreement for the pro rata benefit of the ADS holders that have not surrendered their ADSs. It will not invest the money and has no liability for interest. The depositary's only obligations will be to account for the money and other cash. After termination our only obligations will be to indemnify the depositary and to pay fees and expenses of the depositary that we agreed to pay.

Limits on our Obligations and the Obligations of the Depositary; Limits on Liability to Holders of ADSs

The deposit agreement expressly limits our obligations and the obligations of the depositary. It also limits our liability and the liability of the depositary. We and the depositary:

In the deposit agreement, we and the depositary agree to indemnify each other under certain circumstances.

Before the depositary will deliver or register a transfer of an ADS, make a distribution on an ADS, or permit withdrawal of shares, the depositary may require:

The depositary may refuse to deliver ADSs or register transfers of ADSs generally when the transfer books of the depositary or our transfer books are closed or at any time if the depositary or we think it advisable to do so.

ADS holders have the right to cancel their ADSs and withdraw the underlying shares at any time except:

This right of withdrawal may not be limited by any other provision of the deposit agreement.

The deposit agreement permits the depositary to deliver ADSs before deposit of the underlying ordinary shares. This is called a pre-release of the ADSs. The depositary may also deliver shares upon cancellation of pre-released ADSs (even if the ADSs are canceled before the pre-release transaction has been closed out). A pre-release is closed out as soon as the underlying shares are delivered to the depositary. The depositary may receive ADSs instead of shares to close out a pre-release. The depositary may pre-release ADSs only under the following conditions:

In addition, the depositary has agreed to limit the number of ADSs that may be outstanding at any time as a result of pre-release to 30% of the shares deposited under the deposit agreement, although the depositary may disregard the limit from time to time, if it thinks it is reasonably appropriate to do so.

In the deposit agreement, all parties to the deposit agreement acknowledge that the DRS and Profile Modification System ("Profile"), will apply to uncertificated ADSs upon acceptance thereof to DRS by DTC. DRS is the system administered by DTC under which the depositary may register the ownership of uncertificated ADSs, which ownership will be evidenced by periodic statements sent by the depositary to the registered holders of uncertificated ADSs. Profile is a required feature of DRS that allows a DTC participant, claiming to act on behalf of a registered holder of ADSs, to direct the depositary to register a transfer of those ADSs to DTC or its nominee and to deliver those ADSs to the DTC account of that DTC participant without receipt by the depositary of prior authorization from the ADS holder to register that transfer.

In connection with and in accordance with the arrangements and procedures relating to DRS/Profile, the parties to the deposit agreement understand that the depositary will not determine whether the DTC participant that is claiming to be acting on behalf of an ADS holder in requesting registration of transfer and delivery described in the paragraph above has the actual authority to act on behalf of the ADS holder (notwithstanding any requirements under the Uniform Commercial Code). In the deposit agreement, the parties agree that the depositary's reliance on and compliance with instructions received

by the depositary through the DRS/Profile System and in accordance with the deposit agreement will not constitute negligence or bad faith on the part of the depositary.

The depositary will make available for your inspection at its office all communications that it receives from us as a holder of deposited securities that we make generally available to holders of deposited securities. The depositary will send you copies of those communications if we ask it to. You have a right to inspect the register of holders of ADSs, but not for the purpose of contacting those holders about a matter unrelated to our business or the ADSs.

We may from time to time request ADS holders to provide information as to the capacity in they own or owned ADSs and regarding the identity of any other persons then or previously interested in such ADSs and the nature of such interest. Each ADS holder agrees to provide any information of that kind that is requested by us or the depositary. To the extent that provisions of or governing the deposited securities or the rules or regulations of any governmental authority or securities exchange or automated quotation system may require the disclosure of beneficial or other ownership of deposited securities, other shares and other securities to us or other persons and may provide for blocking transfer and voting or other rights to enforce such disclosure or limit such ownership, the depositary has agreed to use its reasonable efforts to comply with our written instructions in respect of any such enforcement or limitation.

Upon completion of this offering, there will be outstanding ADSs, representing approximately % of our outstanding ordinary shares.

Future sales of substantial amounts of our ordinary shares represented by ADSs in the public market in the United States, including ordinary shares issued upon exercise of outstanding options or warrants, or the possibility of such sales, could negatively affect the market price in the United States of the ADSs and our ability to raise equity capital in the future.

Upon the completion of this offering, we will have outstanding ordinary shares (including ordinary shares represented by ADSs), assuming no exercise of the underwriters' option to purchase additional ordinary shares.

All of the ADSs sold in the offering will be freely transferable in the United States by persons other than our "affiliates," as that term is defined in Rule 144 under the Securities Act. As defined in Rule 144, an "affiliate" of an issuer is a person that directly, or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the issuer. Ordinary shares represented by ADSs purchased by one of our affiliates may not be resold, except pursuant to an effective registration statement or an exemption from registration, including Rule 144 under the Securities Act (as described below).

We and our executive officers and directors have agreed not to sell or transfer any ordinary shares, ADSs or other capital stock of Sundance or securities convertible into or exchangeable or exercisable for ordinary shares, ADSs or other capital stock of Sundance, for 180 days after the date of the underwriting agreement without first obtaining the written consent of Wells Fargo Securities, LLC, Canaccord Genuity Inc. and UBS Securities LLC. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly:

whether any such swap or transaction described in the first two bullet points above is to be settled by delivery of ordinary shares, ADSs or other securities, in cash or otherwise or publicly announce any intention to do any of the foregoing.

This lock-up provision applies to ordinary shares, ADSs and other capital stock of Sundance and to securities convertible into or exchangeable or exercisable for or repayable with ordinary shares, ADSs and other capital stock of Sundance. It also applies to ordinary shares, ADSs, and other capital stock owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.

Subject to certain limitations, the lock-up restrictions described above do not apply to:

We have agreed with the underwriters that if Wells Fargo Securities, LLC, Canaccord Genuity Inc. and UBS Securities LLC, in their sole discretion, agree to waive any lock-up restrictions applicable to ordinary shares or ADSs beneficially owned by one of our officers or directors and provide us with notice of the impending waiver at least three business days before the effective date of the waiver, we will announce the waiver by issuing a press release at least two business days before the effective date of the waiver.

In general, under Rule 144 of the Securities Act and beginning 90 days after the date of this prospectus, a person who is not deemed to have been our affiliate at any time during the three months preceding a sale and who has beneficially owned "restricted securities" within the meaning of Rule 144 for more than six months would be entitled to sell an unlimited number of those shares, subject only to the availability of current public information about us. A non-affiliate who has beneficially owned "restricted securities" for at least one year from the later of the date these shares were acquired from us or from our affiliate would be entitled to freely sell those shares. Upon completion of this offering we will have outstanding ordinary shares that are restricted securities.

A person who is deemed to be an affiliate of ours and who has beneficially owned "restricted securities" for at least six months would be entitled to sell, within any three-month period, a number of shares that is not more than the greater of:

Sales under Rule 144 of the Securities Act by persons who are deemed to be our affiliates are also subject to manner-of-sale provisions, notice requirements and the availability of current public information about us as specified in Rule 144. In addition, in each case, these shares would remain subject to lock-up arrangements and would only become eligible for sale when the lock-up period expires.

Regulation S provides generally that sales made in offshore transactions are not subject to the registration or prospectus delivery requirements of the Securities Act.

In general, under Rule 701 of the Securities Act, each of our employees, consultants or advisors who purchases our ordinary shares from us in connection with a compensatory stock plan or other written agreement executed prior to the completion of this offering is eligible to resell such ordinary shares in reliance on Rule 144, but without compliance with some of the restrictions, including the holding period, contained in Rule 144.

We intend to file with the SEC a registration statement on Form S-8 under the Securities Act covering the ordinary shares reserved for issuance under our equity incentive plans. The registration statement is expected to be filed and become effective as soon as practicable after the closing of this offering. Accordingly, shares registered under the Form S-8 registration statement will be available for sale in the open market following the registration statement's effective date, subject to Rule 144 volume limitations and the lock-up agreements described above, if applicable.

The following is a summary of material U.S. federal and Australian income tax considerations to U.S. holders, as defined below, of the acquisition, ownership and disposition of ordinary shares and ADSs. This discussion is based on the laws in force as of the date of this registration statement, and is subject to changes in the relevant income tax law, including changes that could have retroactive effect. The following summary does not take into account or discuss the tax laws of any country or other taxing jurisdiction other than the United States and Australia. Holders are advised to consult their tax advisors concerning the overall tax consequences of the acquisition, ownership and disposition of ordinary shares and ADSs in their particular circumstances. This discussion is not intended, and should not be construed, as legal or professional tax advice.

This summary does not describe U.S. federal estate and gift tax considerations or any state and local tax considerations within the United States, and is not a comprehensive description of all U.S. federal or Australian income tax considerations that may be relevant to a decision to acquire or dispose of ordinary shares or ADSs. Furthermore, this summary does not address U.S. federal or Australian income tax considerations relevant to holders subject to taxing jurisdictions other than, or in addition to, the United States and Australia, and does not address all possible categories of holders, some of which may be subject to special tax rules.

The following summary describes the material U.S. federal income tax consequences to U.S. holders (as defined below) of the acquisition, ownership and disposition of our ordinary shares and ADSs as of the date hereof. Subject to the qualifications, assumptions and limitations set forth herein, this discussion of the material U.S. federal income tax consequences to U.S. holders of our ordinary shares and ADSs represents the opinion of Baker & McKenzie LLP, our U.S. counsel. Except where noted, this summary deals only with ordinary shares or ADSs acquired in the initial offering and held as capital assets within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the "Code"). This section does not discuss the tax consequences to any particular holder, nor any tax considerations that may apply to holders subject to special tax rules, such as:

In this section, a "U.S. holder" means a beneficial owner of ordinary shares or ADSs that is, for U.S. federal income tax purposes:

As used in this section, a "non-U.S. holder" is a beneficial owner of ordinary shares or ADSs that is not a U.S. holder or an entity or arrangement treated as a partnership for U.S. federal income tax purposes.

The discussion below is based upon the provisions of the Code, and the U.S. Treasury regulations, rulings and judicial decisions thereunder as of the date hereof, and such authorities may be replaced, revoked or modified, possibly with retroactive effect, so as to result in U.S. federal income tax consequences different from those discussed below. In addition, this summary is based, in part, upon representations made by the depositary to us and assumes that the deposit agreement, and all other related agreements, will be performed in accordance with their terms.

If an entity or arrangement treated as a partnership for U.S. federal income tax purposes acquires, owns or disposes of ordinary shares or ADSs, the U.S. federal income tax treatment of a partner generally will depend on the status of the partner and the activities of the partnership. Partners of partnerships that acquire, own or dispose of ordinary shares or ADSs should consult their tax advisors.

You are urged to consult your own tax advisor with respect to the U.S. federal, as well as state, local and non-U.S., tax consequences to you of acquiring, owning and disposing of ordinary shares or ADSs in light of your particular circumstances, including the possible effects of changes in U.S. federal and other tax laws.

If you hold ADSs you generally will be treated, for U.S. federal income tax purposes, as the owner of the underlying ordinary shares that are represented by such ADSs. Accordingly, deposits or withdrawals of ordinary shares for ADSs will not be subject to U.S. federal income tax.

Subject to the passive foreign investment company rules discussed below, U.S. holders generally will include as dividend income the U.S. dollar value of the gross amount of any distributions of cash or property (without deduction for any withholding tax), other than certain pro rata distributions of ordinary shares, with respect to ordinary shares to the extent the distributions are made from our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes. A U.S. holder will include the dividend income on the day actually or constructively received by the holder, in the case of ordinary shares, or by the depositary, in the case of ADSs. To the extent, if any, that the amount of any distribution by us exceeds our current and accumulated earnings and profits, as so determined, the excess will be treated first as a tax-free return of the U.S. holder's tax basis in the ordinary shares and thereafter as capital gain. Notwithstanding the foregoing, we do not intend to maintain calculations of earnings and profits, as determined for U.S. federal income tax purposes.

Consequently, any distributions generally will be reported as dividend income for U.S. information reporting purposes. See "Backup Withholding Tax and Information Reporting Requirements" below. Dividends paid by us will not be eligible for the dividends-received deduction generally allowed to U.S. corporate shareholders.

Subject to certain exceptions for short-term and hedged positions, the U.S. dollar amount of dividends received by an individual, trust or estate with respect to the ordinary shares or ADSs will be subject to taxation at a maximum rate of 20% if the dividends are "qualified dividends." Dividends paid on ordinary shares or ADSs will be treated as qualified dividends if either (i) we are eligible for the benefits of a comprehensive income tax treaty with the United States that the Internal Revenue Service (the "IRS") has approved for the purposes of the qualified dividend rules, (ii) the dividends are with respect to ordinary shares or ADSs readily tradable on a U.S. securities market, provided that we are not, in the year prior to the year in which the dividend was paid, and are not, in the year which the dividend is paid, a PFIC and (iii) certain holding period requirements are met. The Agreement between the Government of the United States of America and the Government of Australia for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income (the "Treaty") has been approved for the purposes of the qualified dividend rules, and we expect to qualify for benefits under the Treaty. We have applied to list the ADSs on The NASDAQ. Provided that the listing is approved, U.S. Treasury Department guidance indicates that the ADSs will be readily tradable on an established securities market in the United States. Thus, we believe that dividends we pay on ordinary shares represented by the ADSs will meet conditions (i) and (ii), described above. Accordingly, dividends we pay generally should be eligible for the reduced income tax rate. However, the determination of whether a dividend qualifies for the preferential tax rates must be made at the time the dividend is paid. U.S. holders should consult their own tax advisers.

Includible distributions paid in Australian dollars, including any Australian withholding taxes, will be included in the gross income of a U.S. holder in a U.S. dollar amount calculated by reference to the spot exchange rate in effect on the date of actual or constructive receipt, regardless of whether the Australian dollars are converted into U.S. dollars at that time. If Australian dollars are converted into U.S. dollars on the date of actual or constructive receipt, the tax basis of the U.S. holder in those Australian dollars will be equal to their U.S. dollar value on that date and, as a result, a U.S. holder generally should not be required to recognize any foreign exchange gain or loss.

If Australian dollars so received are not converted into U.S. dollars on the date of receipt, the U.S. holder will have a basis in the Australian dollars equal to their U.S. dollar value on the date of receipt. Any gain or loss on a subsequent conversion or other disposition of the Australian dollars generally will be treated as ordinary income or loss to such U.S. holder and generally will be income or loss from sources within the United States for foreign tax credit limitation purposes.

Dividends received by a U.S. holder with respect to ordinary shares will be treated as foreign source income, which may be relevant in calculating the holder's foreign tax credit limitation. The limitation on foreign taxes eligible for credit is calculated separately with respect to specific classes of income. For these purposes, dividends generally will be categorized as "passive" or "general" income depending on a U.S. holder's circumstance.

Subject to certain complex limitations, a U.S. holder generally will be entitled, at its option, to claim either a credit against its U.S. federal income tax liability or a deduction in computing its U.S. federal taxable income in respect of any Australian taxes withheld. If a U.S. holder elects to claim a deduction, rather than a foreign tax credit, for Australian taxes withheld for a particular taxable year, the election will apply to all foreign taxes paid or accrued by or on behalf of the U.S. holder in the particular taxable year.

You may not be able to claim a foreign tax credit (and instead may claim a deduction) for non-U.S. taxes imposed on dividends paid on the ordinary shares or ADSs if you (i) have held the ordinary shares or ADSs for less than a specified minimum period during which you are not protected from risk

of loss with respect to such shares, or (ii) are obligated to make payments related to the dividends (for example, pursuant to a short sale).

The availability of the foreign tax credit and the application of the limitations on its availability are fact specific and are subject to complex rules. You are urged to consult your own tax advisor as to the consequences of Australian withholding taxes and the availability of a foreign tax credit or deduction. See "Australian Tax Considerations — Taxation of Dividends."

Subject to the passive foreign investment company rules discussed below, a U.S. holder generally will, for U.S. federal income tax purposes, recognize capital gain or loss on a sale, exchange or other disposition of ordinary shares or ADSs equal to the difference between the amount realized on the disposition and the U.S. holder's tax basis (in U.S. dollars) in the ordinary shares or ADSs. This recognized gain or loss will generally be long-term capital gain or loss if the U.S. holder has held the ordinary shares or ADSs for more than one year. Generally, for U.S. holders who are individuals (as well as certain trusts and estates), long-term capital gains are subject to U.S. federal income tax at preferential rates. For foreign tax credit limitation purposes, gain or loss recognized upon a disposition generally will be treated as from sources within the United States. The deductibility of capital losses is subject to limitations for U.S. federal income tax purposes.

You should consult your own tax advisor regarding the availability of a foreign tax credit or deduction in respect of any Australian tax imposed on a sale or other disposition of ordinary shares or ADSs. See "Australian Tax Considerations — Tax on Sales or other Dispositions of Shares."

The Code provides special, generally adverse, rules regarding certain distributions received by U.S. holders with respect to, and sales, exchanges and other dispositions, including pledges, of, shares of stock of a PFIC. A foreign corporation will be treated as a PFIC for any taxable year if at least 75% of its gross income for the taxable year is passive income or at least 50% of its gross assets during the taxable year, based on a quarterly average and generally by value, produce or are held for the production of passive income. Passive income for this purpose generally includes, among other things, dividends, interest, rents, royalties, gains from commodities and securities transactions and gains from assets that produce passive income. In determining whether a foreign corporation is a PFIC, a pro-rata portion of the income and assets of each corporation in which it owns, directly or indirectly, at least a 25% interest (by value) is taken into account.

Based on our business results for the last fiscal year and composition of our assets, we do not believe that we were a PFIC for U.S. federal income tax purposes for the taxable year ended December 31, 2012. 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, 2013. 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. The composition of our income and assets will also be affected by how, and how quickly, we spend the cash raised in this offering. Under circumstances where the cash is not deployed for active purposes, our risk of becoming a PFIC may increase. 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 holds ordinary shares or ADSs, any "excess distribution" that the holder receives and any gain realized from a sale or other disposition (including a pledge) of such ordinary shares or ADSs will be subject to special tax rules, unless the

holder makes a mark-to-market election or qualified electing fund election, as discussed below. Any distribution in a taxable year that is greater than 125% of the average annual distribution received by a U.S. holder during the shorter of the three preceding taxable years or such holder's holding period for the ordinary shares or ADSs will be treated as an excess distribution. Under these special tax rules:

The tax liability for amounts allocated to years prior to the year of disposition or excess distribution cannot be offset by any net operating loss, and gains (but not losses) realized on the transfer of the ordinary shares or ADSs cannot be treated as capital gains, even if the ordinary shares or ADSs are held as capital assets. In addition, non-corporate U.S. holders will not be eligible for reduced rates of taxation on any dividends that we pay if we are a PFIC for either the taxable year in which the dividend is paid or the preceding year. Furthermore, unless otherwise provided by the U.S. Treasury Department, each U.S. holder of a PFIC is required to file an annual report containing such information as the U.S. Department may require.

If we are a PFIC for any taxable year during which any of our non-U.S. subsidiaries is also a PFIC, a U.S. holder of ordinary shares or ADSs during such year would be treated as owning a proportionate amount (by value) of the shares of the lower-tier PFIC for purposes of the application of these rules to such subsidiary. You should consult your tax advisors regarding the tax consequences if the PFIC rules apply to any of our subsidiaries.

In certain circumstances, in lieu of being subject to the excess distribution rules discussed above, you may make an election to include gain on the stock of a PFIC as ordinary income under a mark-to-market method, provided that such stock is regularly traded on a qualified exchange. Under current law, the mark-to-market election may be available to U.S. holders of ADSs if the ADSs are listed on The NASDAQ Global Select Market, which constitutes a qualified exchange, although there can be no assurance that the ADSs will be "regularly traded" for purposes of the mark-to-market election. It should also be noted that it is intended that only the ADSs and not the ordinary shares will be listed on The NASDAQ Global Select Market. Consequently, if you are a U.S. holder of ordinary shares that are not represented by ADSs, you generally will not be eligible to make a mark-to-market election if we are or were to become a PFIC.

If you make an effective mark-to-market election, you will include in each year that we are a PFIC as ordinary income the excess of the fair market value of your ADSs at the end of your taxable year over your adjusted tax basis in the ADSs. You will be entitled to deduct as an ordinary loss in each such year the excess of your adjusted tax basis in the ADSs over their fair market value at the end of the year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. If you make an effective mark-to-market election, any gain you recognize upon the sale or other disposition of your ADSs will be treated as ordinary income and any loss will be treated as ordinary loss, but only to the extent of the net amount previously included in income as a result of the mark-to-market election.

Your adjusted tax basis in the ADSs will be increased by the amount of any income inclusion and decreased by the amount of any deductions under the mark-to-market rules. If you make a mark-to-market election it will be effective for the taxable year for which the election is made and all subsequent taxable years unless the ADSs are no longer regularly traded on a qualified exchange or the IRS consents to the revocation of the election. You are urged to consult your tax advisors about the

availability of the mark-to-market election, and whether making the election would be advisable in your particular circumstances. Any distributions we make would generally be subject to the rules discussed above under "— Taxation of Dividends," except the reduced rates of taxation on any dividends received from us would not apply.

Alternatively, you can sometimes avoid the PFIC rules described above by electing to treat us as a "qualified electing fund" under Section 1295 of the Code. However, this option likely will not be available to you because we do not intend to comply with the requirements necessary to permit you to make this election.

U.S. holders are urged to contact their own tax advisors regarding the determination of whether we are a PFIC and the tax consequences of such status.

A U.S. holder, which is an individual, an estate or a trust that does not fall into a special class of trusts that is exempt from such tax, will be subject to a 3.8% tax (the "Medicare Tax") on the lesser of (i) the U.S. holder's "net investment income" for the relevant taxable year and (ii) the excess of the U.S. holder's modified adjusted gross income for the taxable year over a certain threshold (which in the case of individuals will be between US$125,000 and US$250,000 depending on the individual's circumstances). A U.S. holder's net investment income will generally include dividends received on the ordinary shares or ADSs and net gains from the disposition of ordinary shares or ADSs, unless such dividend income or net gains are derived in the ordinary course of the conduct of a trade or business (other than a trade or business that consists of certain passive or trading activities). A U.S. holder that is an individual, estate or trust should consult the holder's tax advisor regarding the applicability of the Medicare Tax to the holder's dividend income and gains in respect of the holder's investment in the ordinary shares or ADSs.

U.S. backup withholding tax and information reporting requirements generally apply to payments to non-corporate holders of ordinary shares or ADSs. Information reporting will apply to payments of dividends on, and to proceeds from the disposition of, ordinary shares or ADSs by a paying agent within the United States to a U.S. holder, other than an "exempt recipient," including a corporation and certain other persons that, when required, demonstrate their exempt status. A paying agent within the United States will be required to withhold at the applicable statutory rate, currently 28%, in respect of any payments of dividends on, and the proceeds from the disposition of, ordinary shares or ADSs within the United States to a U.S. holder, other than an "exempt recipient," if the holder fails to furnish its correct taxpayer identification number or otherwise fails to comply with applicable backup withholding requirements. U.S. holders who are required to establish their exempt status generally must provide IRS Form W-9 (Request for Taxpayer Identification Number and Certification).

Backup withholding is not an additional tax. Amounts withheld as backup withholding may be credited against a U.S. holder's U.S. federal income tax liability. A U.S. holder generally may obtain a refund of any amounts withheld under the backup withholding rules by filing the appropriate claim for refund with the IRS in a timely manner and furnishing any required information.

Under the Hiring Incentives to Restore Employment Act of 2010 and recently promulgated Treasury Regulations, certain U.S. holders may be required to report information with respect to such holder's interest in "specified foreign financial assets" (as defined in Section 6038D of the Code), including stock of a non-U.S. corporation that is not held in an account maintained by a U.S. "financial institution," if the aggregate value of all such assets exceeds US$50,000 on the last day of the taxable year or US$75,000 at any time during such year. Persons who are required to report specified foreign financial assets and fail to do so may be subject to substantial penalties. U.S. holders are urged to consult their own tax advisors regarding foreign financial asset reporting obligations and their possible application to the holding of ordinary shares or ADSs.

The discussion above is not intended to constitute a complete analysis of all tax considerations applicable to an investment in ordinary shares or ADSs. You should consult with your own tax advisor concerning the tax consequences to you in your particular situation.

In this section, we discuss the material Australian income tax, stamp duty and goods and services tax considerations related to the acquisition, ownership and disposal by the absolute beneficial owners of the ordinary shares or ADSs. This discussion represents the opinion of Baker & McKenzie, Australian counsel to Sundance. It is based upon existing Australian tax law as of the date of this registration statement, which is subject to change, possibly retrospectively. This discussion does not address all aspects of Australian tax law which may be important to particular investors in light of their individual investment circumstances, such as shares held by investors subject to special tax rules (for example, financial institutions, insurance companies or tax exempt organizations). In addition, this summary does not discuss any foreign or state tax considerations, other than stamp duty and goods and services tax. Prospective investors are urged to consult their tax advisors regarding the Australian and foreign income and other tax considerations of the acquisition, ownership and disposition of the shares. This summary is based upon the premise that the holder is not an Australian tax resident and is not carrying on business in Australia through a permanent establishment.

Ordinary shares represented by ADSs held by a U.S. holder will be treated for Australian taxation purposes as held under a "bare trust" for such holder. Consequently, the underlying ordinary shares will be regarded as owned by the ADS holder for Australian income tax and capital gains tax purposes. Dividends paid on the underlying ordinary shares will also be treated as dividends paid to the ADS holder, as the person beneficially entitled to those dividends. Therefore, in the following analysis we discuss the tax consequences to non-Australian resident holders of ordinary shares which, for Australian taxation purposes, will be the same as to U.S. holders of ADSs.

Australia operates a dividend imputation system under which dividends may be declared to be "franked" to the extent of tax paid on company profits. Fully franked dividends are not subject to dividend withholding tax. Dividends payable to non-Australian resident shareholders that are not operating from an Australian permanent establishment ("Foreign Shareholders") will be subject to dividend withholding tax, to the extent the dividends are not foreign sourced and declared to be conduit foreign income ("CFI") and are unfranked. Dividend withholding tax will be imposed at 30%, unless a shareholder is a resident of a country with which Australia has a double taxation agreement and qualifies for the benefits of the treaty. Under the provisions of the current Double Taxation Convention between Australia and the United States, the Australian tax withheld on unfranked dividends that are not CFI paid by us to which a resident of the United States is beneficially entitled is limited to 15%.

If a company that is a non-Australian resident shareholder owns a 10% or more interest, the Australian tax withheld on dividends paid by us to which a resident of the United States is beneficially entitled is limited to 5%. In limited circumstances the rate of withholding can be reduced to zero.

Foreign Shareholders will not be subject to Australian capital gains tax on the gain made on a sale or other disposal of our ordinary shares, unless they, together with associates, hold 10% or more of our issued capital, at the time of disposal or for 12 months of the last 2 years prior to disposal.

Foreign Shareholders who own a 10% or more interest would be subject to Australian capital gains tax if more than 50% of our direct or indirect assets, determined by reference to market value, consists of Australian land, leasehold interests or Australian mining, quarrying or prospecting rights. The Double

Taxation Convention between the United States and Australia is unlikely to limit the amount of this taxable gain. Australian capital gains tax applies to net capital gains at a taxpayer's marginal tax rate but for certain shareholders a discount of the capital gain may apply if the shares have been held for 12 months or more prior to disposal. We note that a bill was passed by both houses of the Australian Parliament in June 2013 to remove the 50% discount for foreign resident individuals on gains accrued after May 8, 2012. Companies are not entitled to a discount on capital gains tax. Net capital gains are calculated after reduction for capital losses, which may only be offset against capital gains.

Tax on Sales or other Dispositions of Shares — Shareholders Holding Shares on Revenue Account

Some Foreign Shareholders may hold shares on revenue rather than on capital account for example, share traders. These shareholders may have the gains made on the sale or other disposal of the shares included in their assessable income under the ordinary income provisions of the income tax law, if the gains are sourced in Australia.

Non-Australian resident shareholders assessable under these ordinary income provisions in respect of gains made on shares held on revenue account would be assessed for such gains at the Australian tax rates for non-Australian residents, which start at a marginal rate of 32.5%. Some relief from Australian income tax may be available to such non-Australian resident shareholders under the Double Taxation Convention between the United States and Australia.

To the extent an amount would be included in a non-Australian resident shareholder's assessable income under both the capital gains tax provisions and the ordinary income provisions, the capital gain amount would generally be reduced, so that the shareholder would not be subject to double tax on any part of the income gain or capital gain.

If a shareholder were a resident of both Australia and the United States under those countries' domestic taxation laws, that shareholder may be subject to tax as an Australian resident. If, however, the shareholder is determined to be a U.S. resident for the purposes of the Double Taxation Convention between the United States and Australia, the Australian tax would be subject to limitation by the Double Taxation Convention. Shareholders should obtain specialist taxation advice in these circumstances.

No stamp duty is payable by Australian residents or foreign residents on the issue and trading of shares that are quoted on the ASX or NASDAQ Global Select Market at all relevant times and the shares do not represent 90% or more of all issued shares in Sundance.

Australia does not have estate or death duties. As a general rule, no capital gains tax liability is realized upon the inheritance of a deceased person's shares. The disposal of inherited shares by beneficiaries may, however, give rise to a capital gains tax liability if the gain falls within the scope of Australia's jurisdiction to tax (as discussed above).

The issue or transfer of shares to a non-Australian resident investor will not incur Australian goods and services tax.

Wells Fargo Securities, LLC, Canaccord Genuity Inc. and UBS Securities LLC are acting as joint book-running managers of the offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated , 2013, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of ADSs set forth opposite the underwriter's name.

The underwriting agreement provides that the obligations of the underwriters to purchase the ADSs included in this offering are subject to approval of legal matters by counsel, including the validity of the ordinary shares and ADSs, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officers' certificates and legal opinions. The underwriters are obligated to purchase all the ADSs (other than those covered by the option to purchase additional ADSs described below) if they purchase any of the ADSs.

ADSs sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover page of this prospectus. Any ADSs sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $ per ADS. If all the ADSs are not sold at the initial public offering price, the underwriters may change the offering price and the other selling terms. The underwriters do not expect any sales to discretionary accounts. The offering of the ADSs by the underwriters is subject to receipt and acceptance and subject to the underwriters' right to reject any order in whole or in part.

If the underwriters sell more ADSs than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional ADSs at the public offering price less the underwriting discount. To the extent the option is exercised, each underwriter must purchase a number of additional ADSs approximately proportionate to that underwriter's initial purchase commitment. Any ADSs issued or sold under the option will be issued and sold on the same terms and conditions as the other ADSs that are the subject of this offering.

We and our executive officers and directors have agreed not to sell or transfer any ordinary shares, ADSs or other capital stock of Sundance or securities convertible into or exchangeable or exercisable for ordinary shares, ADSs or other capital stock of Sundance, for 180 days after the date of the underwriting agreement, without first obtaining the written consent of Wells Fargo Securities, LLC, Canaccord Genuity Inc. and UBS Securities LLC. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly:

This lock-up provision applies to ordinary shares, ADSs and other capital stock of Sundance and to securities convertible into or exchangeable or exercisable for or repayable with ordinary shares, ADSs and other capital stock of Sundance. It also applies to ordinary shares, ADSs and other capital stock owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition.

Subject to certain limitations, the lock-up restrictions described above do not apply to:

Prior to this offering, there has been no public market for the ADSs. Our ordinary shares are listed on the ASX under the symbol "SEA." On , 2013, the closing price of our ordinary shares on the ASX was A$ per ordinary share equivalent to $ per ADS based on an exchange rate of A$ to $1.00. The public offering price of the ADSs will be determined by negotiations between us and the underwriters taking into account the most recent closing price of our ordinary shares on the Australian Stock Exchange prior to the pricing date as well as other factors, including:

Neither we nor the underwriters can assure investors that an active trading market will develop for the ADSs or that such ADSs will trade in the public market at or above the public offering price. See "Risk Factors." The estimated initial public offering price set forth on the cover of this prospectus is subject to change as a result of market conditions and other factors.

We have applied for a listing of the ADSs on The NASDAQ Global Select Market under the symbol "SNDE."

The following table shows the underwriting discounts payable by us that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional ADSs.

We estimate that the total expenses of this offering will be approximately $ million, excluding underwriting discounts and commissions. We will also reimburse the underwriters for filing fees and other reasonable fees or expenses incident to the review of the terms of the sale of the ADSs offered hereby by FINRA.

In connection with the offering, the underwriters may purchase and sell ADSs in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the option to purchase additional ADSs, and stabilizing purchases.

Short sales involve secondary market sales by the underwriters of a greater number of ADSs than they are required to purchase in the offering. "Covered" short sales are sales of ADSs in an amount up to the number of ADSs represented by the underwriters' option to purchase additional ADSs. "Naked" short sales are sales of ADSs in an amount in excess of the number of ADSs represented by the underwriters' option to purchase additional ADSs.

Covering transactions involve purchases of ADSs either pursuant to the option to purchase additional ADSs or in the open market after the distribution has been completed in order to cover short positions. To close a naked short position, the underwriters must purchase ADSs in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the ADSs in the open market after pricing that could adversely affect investors who purchase in the offering.

To close a covered short position, the underwriters must purchase ADSs in the open market after the distribution has been completed or must exercise the option to purchase additional ADSs. In determining the source of ADSs to close the covered short position, the underwriters will consider, among other things, the price of ADSs available for purchase in the open market as compared to the price at which they may purchase ADSs through the option to purchase additional ADSs. Stabilizing transactions involve bids to purchase ADSs so long as the stabilizing bids do not exceed a specified maximum.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the ADSs. They may also cause the price of the ADSs to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may

conduct these transactions on The NASDAQ Global Market, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representative has repurchased ADSs sold by or for the account of such underwriter in stabilizing or short covering transactions.

We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of ADSs for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's website and any information contained in any other website maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for us or our affiliates, for which they received or will receive customary fees and expenses. In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve our securities and instruments (directly, as collateral securing other obligations or otherwise). The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a "Relevant Member State") an offer to the public of any ADSs may not be made in that Relevant Member State, except that an offer to the public in that Relevant Member State of any ADSs may be made at any time:

For the purposes of this provision, the expression an "offer to the public" in relation to any ADSs in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and any ADSs to be offered so as to enable an investor to decide to purchase any ADSs, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State, the expression "Prospectus Directive" means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and the expression "2010 PD Amending Directive" means Directive 2010/73/EU.

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission, in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act, and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the ADSs may only be made to persons (the "Exempt Investors") who are "sophisticated investors" (within the meaning of Section 708(8) of the Corporations Act), "professional investors" (within the meaning of Section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the shares without disclosure to investors under Chapter 6D of the Corporations Act.

The ADSs applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under Section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring shares must observe such Australian on-sale restrictions.

This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors

need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

The ADSs may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (ii) to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a "prospectus" within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the ADSs may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to ADSs which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the ADSs may not be circulated or distributed, nor may the ADSs be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA"), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the ADSs are subscribed or purchased under Section 275 by a relevant person which is: (i) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (ii) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries' rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the ADSs under Section 275 except: (a) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (b) where no consideration is given for the transfer; or (c) by operation of law.

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the "Financial Instruments and Exchange Law") and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

The address of Wells Fargo Securities, LLC is 375 Park Avenue, New York, NY 10152, the address of Canaccord Genuity Inc. is 99 High Street, 12th Floor Boston, MA 02110 and the address of UBS Securities LLC is 299 Park Avenue, 32nd Floor, New York, NY 10171.

Set forth below is an itemization of the estimated expenses, excluding underwriting discounts, that are expected to be incurred in connection with our offer and sale of the ADSs. Expenses for the offering will be borne by us.

The validity of the ordinary shares represented by the ADSs to be issued in this offering will be passed upon for us by Baker & McKenzie, our Australian counsel. Certain matters as to U.S. federal law and New York state law will be passed upon for us by Baker & McKenzie LLP, our U.S. counsel. Certain legal matters as to the U.S. federal law and New York state law in connection with this offering will be passed upon for the underwriters by Mayer Brown LLP.

Our consolidated financial statements of Sundance Energy Australia Limited as of December 31, 2012 and for the six months then ended, appearing in this prospectus and registration statement, have been audited by Ernst & Young, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of the firm as experts in accounting and auditing.

The audited consolidated financial statements of Sundance Energy Australia Limited as of June 30, 2012 and 2011 and for each of the two years in the period ended June 30, 2012 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in giving said report.

KPMG, an independent registered public accounting firm, has audited the consolidated financial statements of Texon Petroleum Limited for our fiscal years ended December 31, 2011 and 2012, as set forth in their report. We have included such financial statements herein in reliance upon the report of KPMG appearing elsewhere herein, and upon the authority of the firm as experts in accounting and auditing.

The liability of Ernst & Young with respect to claims arising out of their reports is subject to the limitations set forth by a scheme approved under professional standards legislation in each state and territory in Australia that may limit the liability of such accounting firm for damages with respect to certain civil claims arising in, or governed by the laws of the relevant Australian state directly or vicariously from anything done or omitted in the performance of their professional services to Sundance, including audits of financial statements to a maximum liability for audit work of A$75 million. The limit does not apply to claims for breach of trust, fraud or dishonesty.

The liability of KPMG, in relation to the performance of their professional services provided to Texon Petroleum Ltd including, without limitation, KPMG's audits of Texon Petroleum Ltd's consolidated financial statements described above, is limited under the Institute of Chartered Accountants in Australia (NSW) Scheme approved by the New South Wales Professional Standards Council or such other applicable scheme approved pursuant to the Professional Standards Act 1994 (NSW), including the Treasury Legislation Amendment (Professional Standards) Act (the "Accountants Scheme").

If the limitation of liability as set forth in the paragraph above does not apply, it is agreed that, to the extent permitted by law, KPMG's liability for any loss, including without limitation liability for any negligent act or omission by KPMG, shall be limited to an amount equal to ten (10) times the reasonable charge for the services up to a maximum amount of AUD20million.

These limitations of liability may limit recovery upon the enforcement in Australian courts of any judgment under U.S. or other foreign laws rendered against Ernst & Young, Grant Thornton South Australian Partnership and KPMG based on or related to their audit reports included in this prospectus. Substantially all of their assets are located in Australia. However, the laws discussed above have not been subject to judicial consideration. It is therefore unclear how the limitation will be applied by the courts and the effect of the limitation on the enforcement of foreign judgments.

In November 2012, Grant Thornton South Australian Partnership tendered its resignation as our independent public accounting firm. Grant Thornton South Australian Partnership's report on our financial statements for the fiscal years ended June 30, 2011 and 2012 did not contain an adverse opinion or a disclaimer of opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles.

Our board of directors and our shareholders approved the resignation of Grant Thornton South Australian Partnership and the appointment on December 14, 2012 of Ernst & Young as our independent public accounting firm.

During the fiscal years ended June 30, 2011 and 2012 and through the effective date of Grant Thornton South Australian Partnership's resignation, there were no disagreements with Grant Thornton South Australian Partnership on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure that would have caused Grant Thornton South Australian Partnership to make reference to the subject matter of the disagreement in its reports. Grant Thornton LLP, the U.S member firm of Grant Thornton International Ltd., has reissued the report on our financial statements for the fiscal years ended June 30, 2012 and 2011.

None of the events described in paragraphs (A) through (D) of Item 16F(a)(1)(v) of Form 20-F occurred in connection with the audits of our financial statements for the fiscal years ended June 30, 2011 and 2012.

The information included in this prospectus regarding estimated quantities of proved reserves, the future net revenues from those reserves and their present value is based on estimates of the proved reserves, and present values of proved reserves as of June 30, 2013, December 31, 2012 and June 30, 2012 and 2011. The reserve estimates are based on reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers. These estimates are included in this prospectus in reliance upon the authority of each such firm as an expert in these matters.

We are a public limited company incorporated under the laws of Australia. Certain of our directors are non-residents of the United States and all or substantially all of their assets are located outside the United States. As a result, it may not be possible for you to:

You may also have difficulties enforcing in courts outside the United States judgments that are obtained in U.S. courts against any of our non-U.S. resident directors or us, including actions under the civil liability provisions of the U.S. securities laws.

With that noted, there are no treaties between Australia and the United States that would affect the recognition or enforcement of foreign judgments in Australia. We also note that investors may be

able to bring an original action in an Australian court against us to enforce liabilities based in part upon U.S. federal securities laws.

We have appointed Sundance Energy, Inc., our wholly-owned U.S. subsidiary, as our agent to receive service of process with respect to any action brought against us in the U.S. District Court for the Southern District of New York under the federal securities laws of the United States or any action brought against us in the Supreme Court of the State of New York in the County of New York under the securities laws of the State of New York.

We have filed with the SEC a registration statement on Form F-1, including relevant exhibits and schedules, under the Securities Act with respect to the ordinary shares to be sold in this offering. This prospectus, which constitutes a part of the registration statement, summarizes material provisions of contracts and other documents that we refer to in this prospectus. Since this prospectus does not contain all of the information contained in the registration statement, you should read the registration statement and its exhibits and schedules for further information with respect to us and our ordinary shares represented by ADSs. Statements contained in this prospectus regarding the contents of any agreement, contract or other document referred to are not necessarily complete and reference is made in each instance to the copy of the contract or document filed as an exhibit to the registration statement. All information we file with the SEC is available through the SEC's Electronic Data Gathering, Analysis and Retrieval system, which may be accessed through the SEC's website at www.sec.gov. Information filed with the SEC may also be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. You can request copies of these documents upon payment of a duplicating fee, by writing to the SEC. Please visit the SEC's website at www.sec.gov for further information on the SEC's public reference room.

Immediately upon completion of this offering, we will become subject to periodic reporting and other informational requirements of the Exchange Act as applicable to foreign private issuers. Our annual reports on Form 20-F for the year ending December 31, 2013 and subsequent years will be due within four months following the fiscal year end. We are not required to disclose certain other information that is required from U.S. domestic issuers. As a foreign private issuer, we are exempt under the Exchange Act from, among other things, the rules prescribing the furnishing and content of proxy statements, and our executive officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act and Regulation FD (Fair Disclosure), which was adopted to ensure that select groups of investors are not privy to specific information about an issuer before other investors.

We are, however, still subject to the anti-fraud and anti-manipulation rules of the SEC, such as Rule 10b-5. Since many of the disclosure obligations required of us as a foreign private issuer are different than those required by companies filing as a domestic issuer, our shareholders, potential shareholders and the investing public in general should not expect to receive information about us in the same amount and at the same time as information is received from, or provided by, companies filing as a domestic issuer. We are liable for violations of the rules and regulations of the SEC, which do apply to us as a foreign private issuer.

We are in the business of exploring for and producing oil and natural gas. Oil and natural gas exploration is a specialized industry. Many of the terms used to describe our business are unique to the oil and natural gas industry. The following is a description of the meanings of some of the oil and natural gas industry terms used in this document.

3-D seismic data. Geophysical data that depicts the subsurface strata in three dimensions.

Analogous reservoir. Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest; (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

Basin. A large natural depression on the earth's surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

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

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas.

Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Economically producible or viable. The term economically producible or economically viable, as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and natural gas producing activities.

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

Exploitation. Optimizing oil and natural gas production from producing properties or establishing additional reserves in producing areas through additional drilling or the application of new technology.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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

Held-by-production acreage. Acreage covered by a mineral lease that perpetuates a company's right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Horizontal well. A well in which a portion of the well has been drilled horizontally within a productive or potentially productive formation. This operation usually results in the ability of the well to produce higher volumes than a vertical well drilled in the same formation.

Hydraulic fracturing or fracking. The technique of improving a well's production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

Injection. A well which is used to place liquids or natural gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

MBoe. Thousand barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

MMBoe. Million barrels of oil equivalent with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Natural gas liquids or NGL. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be. An owner who has 50% interest in 100 acres owns 50 net acres.

Overriding royalty interest. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or natural gas, produced from a specified tract or tracts, which is limited in duration to the terms of an existing lease and which is not subject to any portion of the expense of development, operation or maintenance.

Possible Reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total

quantities ultimately recovered will equal or exceed proved plus probable plus possible reserves estimates.

Probable Reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

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

Productive well. A well that is producing or is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved oil and natural gas reserves or Proved reserves. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation 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 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.

The area of the reservoir considered as proved includes all of the following: (i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and natural gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the 12-month first day of the month historical average price during the twelve-month period prior to the ending date of the period covered by the report,

determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves or PUD. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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

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

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

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

Resource play. These plays develop over long periods of time, well-by-well, in large-scale operations. They typically have lower than average long-term decline rates and lower geological and commercial development risk than conventional plays. Unlike most conventional exploration and development, resource plays are relatively predictable in timing, costs, production rates and reserve additions which can provide steady long-term reserves and production growth.

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

Stratigraphic horizon. A sealed geologic container capable of retaining hydrocarbons that was formed by changes in rock type or pinch-outs, unconformities, or sedimentary features such as reefs.

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

Undeveloped oil and natural gas reserves or Undeveloped reserves. Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

SUNDANCE ENERGY AUSTRALIA LIMITED
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On March 8, 2013, Sundance Energy Australia Limited ("the Company"), acquired 100% of the outstanding shares of Texon Petroleum Ltd ("Texon", whose name was changed to Armadillo Petroleum Ltd ("Armadillo")), an Australian corporation with oil and natural 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, 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 natural 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 $30.3 million and $15.1 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 Company paid $158.4 million for substantially all of the net assets of Armadillo. Due to the complexity and timing of the merger, the fair values are provisional. The following table reflects the assets acquired and the liabilities assumed at their estimated fair value (in thousands). The Company will continue to review the assets acquired and the liabilities assumed for twelve months from the date of the merger.


Estimated fair value of assets acquired:
Trade and other receivables	$	5,641
Other current assets		456
Development and production assets		53,937
Exploration and evaluation assets		145,295
Prepaid drilling and completion costs		3,027

Amount attributable to assets acquired		208,356

Estimated fair value of liabilities assumed:
Trade and other payables		119
Accrued expenses		34,464
Restoration provision		277
Deferred tax liabilities		15,094

Amount attributable to liabilities assumed		49,954

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

In September 2012, the Company sold its interest in properties located in the South Antelope field of the Williston Basin, North Dakota for $172 million. The field included 3,939 non-operated net acres in McKenzie County, North Dakota. In connection with the sale of the South Antelope assets, the Company elected "like-kind exchange" treatment under the U.S. Internal Revenue Code section 1031, which

provides for deferral of the gain if the proceeds are used to acquire "like-kind property" within six months of the closing of the transaction. In March 2013, the Company completed a transaction in which the majority of the funds remaining in its Section 1031 escrow account were used to acquire oil and natural gas properties in connection with the Texon transaction. Management believes the properties acquired qualify as "like-kind property" under Section 1031 and, as a result, the Company has deferred a majority of the gain associated with the South Antelope sale.

On October 30, 2013, the Company entered into a Purchase and Sale Agreement to sell its interest in properties located in the Phoenix prospect of the Bakken, North Dakota for $35.5 million. Closing is scheduled for December 19, 2013. The prospect includes 77 gross producing wells in McKenzie, Dunn and Mountrail Counties, North Dakota. In connection with the sale of the Phoenix prospect assets, the Company intends to elect "like-kind exchange" treatment under U.S. Internal Revenue Code Section 1031, which provides for deferral of the gain if the proceeds are used to acquire "like-kind property" within six months of the closing of the transaction. The Company expects to defer a majority of the gain by investing all or a portion of the proceeds in its Eagle Ford, Mississippian/Woodford and Wattenburg programs. Upon completion of the sale, the Company will deposit the proceeds into a Section 1031 escrow account.

On November 1, 2013, the Company sold its entire interest in an individual operated well and the developed 622 acres, also located in the Phoenix prospect for $4.3 million. Both dispositions are collectively referred to as the Phoenix prospect divestiture. The remainder of the Bakken properties not divested are reflected in assets held for sale.

The following unaudited pro forma condensed consolidated financial statements are presented to give effect to the acquisition of substantially all of Texon (except for those Texon assets that were retained by Talon Petroleum Limited ("Talon") and the disposition of the South Antelope field assets and the Phoenix prospect assets as if these transactions had occurred on January 1, 2012. Upon completion of the sale, the Company deposited the proceeds into a Section 1031 escrow account.

The unaudited pro forma condensed consolidated financial statements are provided for illustrative purposes only, and are not intended to represent or be indicative of the profit or loss of the Company that would have been recorded had the acquisition of the Texon assets, net of the Texon assets retained by Talon, and the dispositions of the South Antelope field and the Phoenix prospect assets been completed as of the dates presented and should not be taken as representative of the future profit or loss of the Company. The unaudited condensed consolidated financial statements do not reflect the impact of any potential operational efficiencies, cost savings or economies of scale that the Company may achieve with respect to the consolidated operations. Additionally, the pro forma statement of profit or loss does not include non-recurring charges or credits and the related tax effects which result directly from the transactions. Furthermore, certain reclassifications have been reflected to Texon's historical financial statements presented herein to conform to the Company's historical presentation.

The unaudited pro forma condensed statement of the profit or loss for the nine month period ended September 30, 2013, which presents our operations as if the acquisition of the Texon assets, net of the Texon assets retained by Talon, and the disposition of the Phoenix prospect assets had occurred on January 1, 2012, has been derived from the following:

The unaudited pro forma condensed statement of profit or loss for the year ended December 31, 2012, which presents our operations as if the acquisition of the Texon assets, net of the Texon assets retained by Talon, and the dispositions of the South Antelope field and the Phoenix prospect assets had occurred on January 1, 2012, has been derived from the following:

The unaudited pro forma condensed statement of financial position as at September 30, 2013, which presents our financial position as if the disposition of the Phoenix prospect assets had occurred on September 30, 2013, has been derived from the following:

As both the Texon acquisition and the South Antelope divestiture have been reflected in the Company's statement of financial position as at September 30, 2013, there is no impact to the pro forma condensed statement of financial position as a result of those transactions.

The assets and liabilities of Texon, net of the Texon assets retained by Talon, have been recorded at their estimated fair value, with no resulting bargain purchase gain or goodwill. The amounts recorded have taken into consideration the cash paid and the fair value of the Company's stock exchanged with the shareholders of Texon and the estimated fair value of the acquired oil and gas properties of Texon.

The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the historical consolidated financial statements and accompanying notes contained in the referenced financial statements.

SUNDANCE ENERGY AUSTRALIA LIMITED
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF PROFIT OR LOSS
FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2013

	Sundance Historical US$'000			Armadillo Historical US$'000			Phoenix Historical US$'000			Pro Forma Adjustments US$'000			Sundance Pro Forma Consolidated As Adjusted US$'000

				(a)			(b)
Oil and gas revenue	$	55,163		$	5,163		$	(9,807	)	$	—		$	50,518
Lease operating and production expenses		(11,302	)		(1,150	)		2,232			—			(10,219	)
Depreciation and amortization expense		(23,418	)		(2,704	)		1,717			822	(c)		(23,583	)
Employee benefits expense		(6,558	)		(359	)					—			(6,917	)
Administrative expense		(6,227	)		(3,540	)					3,232	(d)		(6,535	)
Interest received		84			—						—			84
Finance costs		235			(2,180	)					2,144	(e)		199
(Loss)/gain on sale of non-current assets		(889	)		—						877	(f)		(12	)
(Loss)/gain on commodity hedging		(1,245	)		—						—			(1,245	)

Profit (loss) before income tax		5,843			(4,770	)		(5,858	)		7,075			2,290
Income tax expense		(2,216	)		—			2,222			(874	)(g)		(868	)

Profit (loss) attributable to the owners of the Company	$	3,627		$	(4,770	)		(3,636	)	$	6,201		$	1,422

Earnings per share
Basis earnings	$	0.01											$	0.00

Diluted earnings	$	0.01											$	0.00

Weighted average common shares outstanding
Basic		399,080			29,765									428,845

Diluted		403,539			29,765									433,304

The accompanying notes form part of these pro forma condensed consolidated financial statements.

SUNDANCE ENERGY AUSTRALIA LIMITED
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF PROFIT OR LOSS
FOR THE YEAR ENDED DECEMBER 31, 2012

	Sundance Historical US$ '000			Armadillo Historical US$ '000			Talon Historical US$ '000			South Antelope Historical US$ '000			Phoenix Historical US$ '000			Proforma Adjustments US$ '000			Sundance Pro Forma Consolidated As Adjusted US$ '000

				(h)			(i)			(j)			(k)
Oil and gas revenue	$	35,772		$	15,288		$	(741	)	$	(15,509	)	$	(7,362	)	$	—		$	27,448
Lease operating and production expenses		(7,653	)		(5,464	)		282			2,713			1,736			—			(8,386	)
Depreciation and amortization expense		(12,869	)		(8,348	)		360			4,767			2,190			3,680	(l)		(10,220	)
Employee benefits expense		(5,035	)		(2,003	)		48			—						—			(6,990	)
Administrative expense		(4,322	)		(5,911	)		75			—						2,516	(m)		(7,642	)
Interest received		38			211			(3	)		—						—			246
Finance costs		(745	)		(369	)		—			—						369	(n)		(745	)
Exploration and evaluation expenditure		—			(1,353	)		991			—						—			(362	)
Impairment of non-current assets		—			(576	)		—			—						—			(576	)
Gain on sale of non-current assets		124,872			2,555			(189	)		(124,872	)					—			2,366
(Loss)/gain on commodity hedging		1,118			—			—			—						—			1,118
Realised currency (loss)		(3	)		(108	)		—			—						—			(111	)

Profit (loss) before income tax		131,173			(6,078	)		823			(132,901	)		(3,436	)		6,565			(3,854	)
Income tax (expense) benefit		(50,102	)		(2,462	)		—			50,762			1,312			1,962	(o)		1,472

Profit (loss) attributable to the owners of the Company	$	81,071		$	(8,540	)	$	823		$	(82,139	)	$	(2,124	)	$	8,527		$	(2,382	)

Earnings (loss) per share
Basis earnings (loss)	$	0.29																	$	(0.01	)

Diluted earnings (loss)	$	0.29																	$	(0.01	)

Weighted average common shares outstanding
Basic		277,171			122,670															399,841

Diluted		279,857			122,670															402,526

The accompanying notes form part of these pro forma condensed consolidated financial statements.

SUNDANCE ENERGY AUSTRALIA LIMITED
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT SEPTEMBER 30, 2013

	Sundance Historical US$'000			Pro Forma Adjustments US$'000			Sundance Pro Forma Consolidated As Adjusted US$'000

CURRENT ASSETS
Cash and cash equivalents	$	95,427		$	39,051	(p)	$	134,478
Trade and other receivables		27,722						27,722
Derivative financial instruments		—						—
Other current assets		2,682						2,682

CURRENT ASSETS		125,831			39,051			164,882
Assets held for sale		36,766			(27,567)	(p)		9,199

TOTAL CURRENT ASSETS		162,597			11,484			174,081

NON-CURRENT ASSETS
Development and productions assets		214,567						214,567
Exploration and evaluation expenditure		178,722						178,722
Plant and equipment		885						885
Prepaid drilling and completion costs								—
Derivative financial instruments		—						—
Other non-current assets		3,642						3,642

TOTAL NON-CURRENT ASSETS		397,816			—			397,816

TOTAL ASSETS	$	560,413		$	11,484		$	571,897

CURRENT LIABILITIES
Trade and other payables	$	31,843					$	31,843
Accrued expenses		78,650						78,650
Current tax liabilities								—
Loans and borrowings								—

TOTAL CURRENT LIABILITIES		110,493			—			110,493

NON-CURRENT LIABILITIES
Credit facilities net of deferred financing fees		29,126						29,126
Restoration provision		2,275						2,275
Deferred tax liabilities		83,689			4,298	(p)		87,987

TOTAL NON-CURRENT LIABILITIES		115,090			4,298			119,388

TOTAL LIABILITIES	$	225,583		$	4,298		$	229,881

NET ASSETS	$	334,830		$	7,186		$	342,016

EQUITY
Issued capital	$	237,082		$	—		$	237,082
Share option reserve		5,248						5,248
Foreign currency translation		(1,299	)					(1,299	)
Restructure reserve								—
Retained earnings		93,799			7,186	(p)		100,985

TOTAL EQUITY	$	334,830		$	7,186		$	342,016

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
(In Thousands)

The following pro forma estimated reserve quantities (in thousands) reflect the impact of the acquisition of Texon net of Talon and the disposition of Phoenix as of December 31, 2012. These reserve estimates have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission regarding oil and natural gas reserve reporting:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS (Continued)
(In Thousands)

	Armadillo Historical AU$			Armadillo Historical US$(1)

Oil and gas revenue	$	14,757		$	15,288
Lease operating and production expenses(2)		(5,274	)		(5,464	)
Depreciation and amortization expense(2)		(8,058	)		(8,348	)
Employee benefits expense		(1,933	)		(2,003	)
Administrative expense		(5,706	)		(5,911	)
Interest received		204			211
Finance costs(3)		(356	)		(369	)
Exploration and evaluation expenditure		(1,306	)		(1,353	)
Impairment of non-current assets		(556	)		(576	)
Gain on sale of non-current assets		2,466			2,555
(Loss)/gain on commodity hedging		—			—
Realised currency (loss)(3)		(104	)		(108	)

Profit (loss) before income tax		(5,867	)		(6,078	)
Income tax expense		(2,376	)		(2,462	)

Profit (loss) attributable to the owners of the Company	$	(8,243	)	$	(8,540	)

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS (Continued)
(In Thousands)

SUNDANCE ENERGY AUSTRALIA LIMITED ACN 112 202 883 AND CONTROLLED ENTITIES
STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME
FOR THE NINE-MONTH PERIODS ENDED 30 SEPTEMBER 2013 AND 2012

			Consolidated Group Nine Months Ended 30 September

	Note		2013 US$'000			2012 US$'000
			(unaudited)			(unaudited)
Oil and gas sales revenue		2	$	55,163		$	28,349
Lease operating and production expenses				(11,302	)		(5,803	)
Depreciation and amortisation expense				(23,418	)		(10,707	)
General and administrative expense		3		(12,785	)		(5,671	)
Interest received				84			31
Finance costs				235			(278	)
(Loss)/gain on sale of non-current assets				(889	)		125,755
(Loss)/gain on commodity hedging				(1,245	)		1,331

Profit before income tax				5,843			133,007
Income tax expense				(2,216	)		(51,968	)

Profit attributable to owners of the Company				3,627			81,039
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)				(204	)		307

Other comprehensive income				(204	)		307
Total comprehensive income attributable to owners of the Company			$	3,423		$	81,346

				Dollars			Dollars
Earnings per share
Basic earnings				0.01			0.29
Diluted earnings				0.01			0.29

The accompanying notes form part of these condensed consolidated interim financial statements

SUNDANCE ENERGY AUSTRALIA LIMITED ACN 112 202 883 AND CONTROLLED ENTITIES
STATEMENT OF FINANCIAL POSITION
AS AT 30 SEPTEMBER 2013 AND 31 DECEMBER 2012

			Consolidated Group

	Note		30 September 2013 US$'000			31 December 2012 US$'000
			(unaudited)			(audited)
CURRENT ASSETS
Cash and cash equivalents			$	95,427		$	154,110
Trade and other receivables				27,722			15,672
Derivative financial instruments				—			617
Other current assets				2,682			5,025

CURRENT ASSETS				125,831			175,424
Assets held for sale		5		36,766			—
TOTAL CURRENT ASSETS			$	162,597		$	175,424

NON-CURRENT ASSETS
Development and production assets				214,567			79,729
Exploration and evaluation expenditure				178,722			33,439
Property and equipment				885			423
Other non-current assets		7		3,642			2,420

TOTAL NON-CURRENT ASSETS				397,816			116,011

TOTAL ASSETS			$	560,413		$	291,435

CURRENT LIABILITIES
Trade and other payables				31,843			38,770
Accrued expenses				78,650			13,072

TOTAL CURRENT LIABILITIES				110,493			51,842

NON-CURRENT LIABILITIES
Credit facilities, net of $874 and $430 deferred financing fees, respectively		8		29,126			29,570
Restoration provision				2,275			1,228
Deferred tax liabilities				83,689			56,979

TOTAL NON-CURRENT LIABILITIES				115,090			87,777

TOTAL LIABILITIES			$	225,583		$	139,619

NET ASSETS			$	334,830		$	151,816

EQUITY
Issued capital		9		237,082			58,694
Share option reserve				5,248			4,045
Foreign currency translation				(1,299	)		(1,095	)
Retained earnings				93,799			90,172

TOTAL EQUITY			$	334,830		$	151,816

The accompanying notes form part of these condensed consolidated interim financial statements

SUNDANCE ENERGY AUSTRALIA LIMITED ACN 112 202 883 AND CONTROLLED ENTITIES
STATEMENT OF CHANGES IN EQUITY
FOR THE NINE-MONTH PERIOD ENDED 30 SEPTEMBER 2013

	Issued Capital US$'000			Retained Earnings US$'000		Foreign Currency Translation Reserve US$'000			Share Option Reserve US$'000		Total US$'000

Balance at 31 December 2011	$	57,978		$	9,101	$	(997	)	$	2,828	$	68,910

Stock compensation value of services		—			—		—			455		455
Profit attributable to owners of the Company		—			81,039		—			—		81,039
Other comprehensive income for the period		—			—		307			—		307

Balance at 30 September 2012	$	57,978		$	90,140	$	(690	)	$	3,283	$	150,711

Balance at 31 December 2012	$	58,694		$	90,172	$	(1,095	)	$	4,045	$	151,816
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)		(1,915	)		—		—			—		(1,915	)
Stock compensation value of services		—			—		—			1,203		1,203
Profit attributable to owners of the Company		—			3,627		—			—		3,627
Other comprehensive loss for the period		—			—		(204	)		—		(204	)

Balance at 30 September 2013	$	237,082		$	93,799	$	(1,299	)	$	5,248	$	334,830

The accompanying notes form part of these condensed consolidated interim financial statements

SUNDANCE ENERGY AUSTRALIA LIMITED ACN 112 202 883 AND CONTROLLED ENTITIES
STATEMENT OF CASH FLOWS
FOR THE NINE-MONTH PERIODS ENDED 30 SEPTEMBER 2013 AND 2012

	Consolidated Group

	30 September 2013 US$000			30 September 2012 US$000
	(unaudited)			(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from sales	$	54,215		$	25,988
Payments to suppliers and employees		(17,130	)		(12,485	)
Interest received		84			31
Derivative (payments) proceeds		(176	)		393
Income taxes paid		(556	)		(80	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		36,437			13,847

CASH FLOWS FROM INVESTING ACTIVITIES
Payments for development expenditure		(94,373	)		(39,720	)
Payments for exploration expenditure		(16,633	)		(10,844	)
Payments for acquisition of oil and gas properties		(141,763	)		—
Sale of non-current assets		(751	)		178,545
Transaction costs related to sale of non-current assets		(138	)		—
Payments for plant and equipment		(640	)		(264	)
Cash received from escrow account		837			—
Cash acquired from merger		114,690			—

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(138,770	)		127,717

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issue of shares		48,211			—
Payments for the costs of capital raisings		(2,591	)		—
Payments for the costs of future capital raisings		(279	)		—
Payments for acquisition related costs		(433	)		—
Borrowing costs, including capitalized interest and financing fees		(1,258	)		(278	)
Proceeds from borrowings		15,000			10,000
Repayments on borrowings		(15,000	)		—

NET CASH PROVIDED BY FINANCING ACTIVITIES		43,650			9,722

Net increase/(decrease) in cash held		(58,683	)		151,286

Cash at beginning of period		154,110			11,701
Effect of exchange rates on cash holdings in foreign currencies		—			291

Cash at end of period	$	95,427		$	163,278

The accompanying notes form part of these condensed consolidated interim financial statements

SUNDANCE ENERGY AUSTRALIA LIMITED ACN 112 202 883 AND CONTROLLED ENTITIES
SELECTED EXPLANATORY NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE NINE-MONTH PERIOD ENDED 30 SEPTEMBER 2013

The general purpose financial statements for the interim nine month reporting period ended 30 September 2013 have been prepared in accordance with the Corporations Act 2001 and AASB 134 Interim Financial Reporting. Compliance with AASB 134 ensures that the financial statements and notes also comply with IAS 34 Interim Financial Reporting, as issued by the International Accounting Standards Board (IASB).

The interim consolidated financial statements do not include all the information and disclosures required in the annual financial statements, and should be read in conjunction with the Sundance Energy Australia Limited's (the "Company", "Consolidated Group" or the "Group") annual financial statements as at 31 December 2012 and any public announcements made by the Company during the interim reporting period in accordance with the continuous disclosure requirements of the Corporations Act 2001. Material accounting policies adopted in the preparation of this financial report are included in Note 1 of the Company's 31 December 2012 and the six-month period then ended financial statements. They have been consistently applied unless otherwise stated.

The Company has adopted the applicable new and amended standards from 1 January 2013:

Adoption of these standards did not have any material effect on the financial position or performance of the Company.

Effective 1 July 2012, the Company changed its financial year end from 30 June to 31 December. This change resulted in the reporting period ended 31 December 2012 being a six-month period.

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, 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 $30.3 million and $15.1 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 estimated fair value of trade and other receivables and accrued expenses increased $0.4 million and decreased $0.2 million, respectively, compared to estimates included in the 30 June 2013 financial statements. This change in estimate was due to actual amount received and invoiced subsequently to the date the 30 June 2013 financial statements were issued.

The Company paid $158.4 million for substantially all of the net assets of Armadillo Petroleum Ltd. Due to the complexity and timing of the merger and incremental income tax information to be finalized, the fair values are provisional.

The following table reflects the assets acquired and the liabilities assumed at their estimated fair value (in thousands). The Company will continue to review the assets acquired and the liabilities assumed for twelve months from the date of the merger.


Estimated fair value of assets acquired:
Trade and other receivables	$	5,641
Other current assets		456
Development and production assets		53,937
Exploration and evaluation assets		145,295
Prepaid drilling and completion costs		3,027

Amount attributable to assets acquired		208,356

Estimated fair value of liabilities assumed:
Trade and other payables		119
Accrued expenses		34,464
Restoration provision		277
Deferred tax liabilities		15,094

Amount attributable to liabilities assumed		49,954

Net assets acquired	$	158,402

Purchase price:
Cash and cash equivalents	$	26,310
Issued capital		132,092

Total consideration paid	$	158,402

Since the acquisition date of March 8, 2013, the Company has earned revenue of $26.9 million and generated income of $9.4 million. The following reflects select pro forma information as if the merger had occurred on January 1, 2013 instead of the closing date of March 8, 2013 (in thousands, except per share information):

	Nine Months Ended 30 September 2013

Oil and gas revenue	$	5,163
Lease operating and production expenses		(1,150	)
Depreciation and amortisation expense		(1,882	)
General and administrative expense		(667	)
Finance costs		(35	)

Profit before income tax		1,429
Income tax expense		(542	)

		887
Profit attributable to owners of the Company for the period		3,627
Adjusted profit attributable to the owners of the Company for the period	$	4,514

Adjusted basic and diluted earnings per share	$	0.01

Acquisition related costs of $0.4 million for primarily professional fees are included in general and administrative expense and financing activities in the statements of profit or loss and other comprehensive income and cash flows for the nine month periods ended, respectively. No reduction or impairments to the acquisition date fair values were recognized in the 30 September 2013 financial statements.

As at 30 September 2013, all of the Company's Bakken properties were held for sale. The expected proceeds, net of selling costs, exceed the carrying amount. The following Bakken assets and liabilities were included in assets held for sale in the statement of financial position (in thousands):

As of 30 September 2013, the Company had a significant balance in trade and other receivables and trade and other payables of $11.5 million and $15.5 million, respectively, due from and to one of its joint operating partners. The Company is currently in negotiations to settle the amounts due to and from the joint operating partner. The Company has not reserved any allowances related to either the receivable or payable as it expects to fully receive and pay the amounts currently reflected on its statement of financial position.

During the period ended 30 September 2013, the Company incurred professional fees related to its expected U.S. initial public offering. As the Company's existing ordinary shares are also being registered with the public U.S. equity markets, the Company allocated these fees between existing ordinary shares, which were expensed in general and administrative expense, and expected new ordinary shares, which are included in other assets and will ultimately offset equity raised on the statement of financial position. As at 30 September 2013, approximately $0.3 million of these equity transaction related costs were capitalized to other assets and $0.9 million were included in general and administration expenses.

In August 2013, the Company entered into a five-year Junior Credit Facility Agreement with Well Fargo Energy Capital, Inc. with an initial borrowing base of $15.0 million (the "Junior Credit Facility"). The Company immediately drew on its Junior Credit Facility and used its proceeds to partially paydown its existing revolver with Wells Fargo Bank N.A. (the "Senior Credit Facility"). Subsequent to the paydown, the Senior Credit Facility had an outstanding balance $15.0 million. Collectively, the Senior and Junior Credit Facilities have $30.0 million of principal outstanding as at 30 September 2013. During the nine-month period ended 30 September 2013, the Senior Credit Facility's borrowing based increased from $30.0 million to $48.0 million, with $33.0 million undrawn as at 30 September 2013.

Ordinary shares participate in dividends and the proceeds on winding of the parent entity 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.

During the nine-month period ended 30 September 2013, a total of 2,000,000 options were formally issued to employees pursuant to employment agreements and a total of 2,725,000 previously issued options were exercised. 700,000 of the 2,000,000 issued options had been previously granted and the

Company's employees rendered services during the six month period ended 31 December 2012. This information is summarised below.

The following tables summarise the options formally granted and their related grant date, fair value and vesting conditions for the nine-month period ended 30 September 2013:

Share based payments expense related to options is determined pursuant to IFRS 2: Share Based Payments, and is recognised pursuant to the attached vesting conditions. The weighted average fair value of the options awarded was A$0.55 for the nine-month period ended 30 September 2013, which was calculated using a Black-Sholes options pricing model. Expected volatilities are based upon the historical volatility of the ordinary shares. Historical data is also used to estimate the probability of option exercise and potential forfeitures.

The following table summarises the key assumptions used to calculate the estimated fair value of options formally granted during the nine- month period ended 30 September 2013:

During the nine-month period ended 30 September 2013, the shareholders and Board of Directors awarded 374,248 and 863,746 restricted share units (RSUs) to our CEO and certain other employees,

respectively (total of 1,237,994 RSUs). These awards were made in accordance with the long term equity component of the Company's incentive compensation plan, the details of which are described in more detail in the remuneration section of the Directors' Report. Share based payment expense for RSUs awarded was calculated pursuant to IFRS 2: Share Based Payments. The fair values of RSUs were estimated at the date they were approved by the shareholders and Board of Directors, 28 May 2013 and 19 April 2013 (the measurement dates). The value of the vested portion of these awards has been recognised within the financial statements. This information is summarised for the Consolidated Group for the nine-month period ended 30 September 2013 below:

The following table summarises the RSUs issued and their related grant date, fair value and vesting conditions for the nine-month period ended 30 September 2013:

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

Management has determined, based upon the reports reviewed by the CEO and used to make strategic decisions, that the Group has one reportable segment being oil and gas exploration and production in the United States of America.

The CEO reviews internal management reports on a monthly basis that are consistent with the information provided in the statement of profit or loss and other comprehensive income, statement of financial position and statement of cash flows. As a result no reconciliation is required, because the information as presented is used by the CEO to make strategic decisions.

At the date of signing this report, the Group is not aware of any contingent assets or liabilities that should be disclosed in accordance with IAS 37.

Subsequent to 30 September 2013, the Group entered into a definitive agreement for the sale of its non-operated Phoenix properties and closed on a purchase sale agreement for its operated Phoenix properties in the Bakken, respectively. The combined sales price for the two sales was approximately $39.8 million in cash. The net book value of the Phoenix assets was approximately $27.6 million as at 30 September 2013, which is included in assets held for sale on the statement of financial position. The operated property transaction closed 1 November 2013. The definitive agreement for the sale of its non-operated properties was entered into on 30 October 2013 and the transaction is expected to close in December 2013, subject to customary terms and conditions.

We have audited the accompanying consolidated statement of financial position of Sundance Energy Australia Limited as of December 31, 2012, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity, and cash flows for the half year ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Sundance Energy Australia Limited at December 31, 2012, and the consolidated results of its operations and its cash flows for the half year ended December 31, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We have audited the accompanying consolidated statement of financial position of Sundance Energy Australia Limited and subsidiaries (the "Company") as of June 30, 2012, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity, and cash flows for the year ended June 30, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sundance Energy Australia Limited and subsidiaries as of June 30, 2012, and the results of their operations and their cash flows for the year ended June 30, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2012

			Consolidated Group

	Note		6 months to 31 December 2012 US$'000			12 months to 30 June 2012 US$'000
Oil and gas sales revenue			$	17,724		$	29,787
Lease operating and production expenses		2		(4,082	)		(6,355	)
Depreciation and amortisation expense				(6,116	)		(11,111	)
Employee benefits expense				(2,801	)		(4,318	)
Administrative expense		3		(3,009	)		(2,545	)
Interest received				15			263
Finance costs		18		(593	)		(152	)
Impairment of non-current assets				—			(357	)
Gain on sale of non-current assets		4		122,327			3,004
(Loss)/gain on commodity hedging				(639	)		1,945
Realised currency (loss)				—			(4	)

Profit before income tax				122,826			10,157
Income tax expense		5		(46,616	)		(4,145	)

Profit attributable to owners of the Company				76,210			6,012
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)				(154	)		(247	)

Total comprehensive income attributable to owners of the Company			$	76,056		$	5,765

Earnings per share
Basic earnings		8	$	0.27		$	0.02
Diluted earnings		8	$	0.27		$	0.02

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

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT DECEMBER 31, 2012

			Consolidated Group

	Note		31 December 2012 US$'000			30 June 2012 US$'000
CURRENT ASSETS
Cash and cash equivalents		9	$	154,110		$	15,328
Trade and other receivables		10		15,672			12,352
Derivative financial instruments		11		617			1,331
Other current assets		12		5,025			1,680

TOTAL CURRENT ASSETS				175,424			30,691

NON-CURRENT ASSETS
Development and production assets		13		79,729			87,274
Exploration and evaluation expenditure		14		33,439			11,436
Plant and equipment		15		423			418
Derivative financial instruments		11		—			476
Other non-current assets		16		2,420			21

TOTAL NON-CURRENT ASSETS				116,011			99,625

TOTAL ASSETS			$	291,435		$	130,316

CURRENT LIABILITIES
Trade and other payables		17		38,770			22,056
Accrued expenses		17		13,072			8,337

TOTAL CURRENT LIABILITIES				51,842			30,393

NON-CURRENT LIABILITIES
Credit facility, net of $430 and $345 of deferred financing fees, respectively		18		29,570			14,655
Restoration provision		19		1,228			588
Deferred tax liabilities		20		56,979			10,476

TOTAL NON-CURRENT LIABILITIES				87,777			25,719

TOTAL LIABILITIES			$	139,619		$	56,112

NET ASSETS			$	151,816		$	74,204

EQUITY
Issued capital		21	$	58,694		$	57,978
Share option reserve		22		4,045			3,205
Foreign currency translation		22		(1,095	)		(941	)
Retained earnings				90,172			13,962

TOTAL EQUITY			$	151,816		$	74,204

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

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2012

Consolidated Group	Issued Capital US$'000		Retained Earnings US$'000		Foreign Currency Translation Reserve US$'000			Share Option Reserve US$'000		Total US$'000

Balance at 30 June 2011	$	57,831	$	7,950	$	(694	)	$	2,380	$	67,467
Shares issued during the year		147		—		—			—		147
Stock compensation, value of services		—		—		—			825		825
Profit attributable to owners of the Company		—		6,012		—			—		6,012
Other comprehensive loss for the year		—		—		(247	)		—		(247	)

Balance at 30 June 2012		57,978		13,962		(941	)		3,205		74,204
Shares issued during the period		716		—		—			—		716
Stock compensation, value of services		—		—		—			840		840
Profit attributable to owners of the Company		—		76,210		—			—		76,210
Other comprehensive loss for the period		—		—		(154	)		—		(154	)

Balance at 31 December 2012	$	58,694	$	90,172	$	(1,095	)	$	4,045	$	151,816

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

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2012

		Consolidated Group

	Note	6 months to 31 December 2012 US$'000			12 months to 30 June 2012 US$'000
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from sales		$	11,648		$	20,987
Payments to suppliers and employees			(2,886	)		(8,900	)
Interest received			16			263
Derivative proceeds (payments)			608			(297	)
Income taxes (paid)/refunded			—			(221	)

NET CASH PROVIDED BY OPERATING ACTIVITIES	26		9,386			11,832

CASH FLOWS FROM INVESTING ACTIVITIES
Payments for development expenditure			(32,551	)		(34,833	)
Payments for exploration expenditure			(8,031	)		(5,685	)
Payments for acquisition of oil and gas properties			(11,470	)		—
Sale of non-current assets			173,822			4,679
Transaction costs related to sale of non-current assets			(862	)		—
Payments to establish escrow related to acquisition			(6,230	)		—
Payments for plant and equipment			(107	)		(310	)

NET CASH (USED IN) INVESTING ACTIVITIES			114,571			(36,149	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issue of shares			716			147
Payments for acquisition related costs			(192	)		—
Borrowing costs, including capitalised financing fees			(678	)		(408	)
Proceeds from borrowings			45,000			15,000
Payments of borrowings			(30,000	)		—
Realised currency (loss)			—			(5	)

NET CASH PROVIDED BY FINANCING ACTIVITIES			14,846			14,734

Net (decrease)/increase in cash held			138,803			(9,583	)
Cash at beginning of period			15,328			25,244
Effect of exchange rates on cash			(21	)		(333	)

CASH AT END OF PERIOD	9	$	154,110		$	15,328

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

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED

The financial report includes the consolidated financial statements and notes of Sundance Energy Australia Limited (SEAL) and its wholly owned subsidiary, Sundance Energy, Inc. (collectively, the 'Company,' 'Consolidated Group' or 'Group').

The 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.

Effective 1 July 2012, the Company changed its financial year end from 30 June to 31 December. This change resulted in the current reporting period being a six-month period. The six-month period ended 31 December 2012 is a shorter reporting period than that of the year ended 30 June 2012, which is the previous reporting period shown in these financial statements; therefore, the amounts presented in the financial statements are not entirely comparable.

The Group's cash flows and economic returns are principally denominated in US Dollars. From 1 July 2011, SEAL changed the currency in which it presents its consolidated and parent Company Financial Statements from Australian Dollars to US Dollars.

A controlled entity is any entity over which SEAL has the power to govern the financial and operating policies so as to obtain benefits from its activities. In assessing the power to govern, the existence and effect of holdings of actual and potential voting rights are considered. The consolidated financial statements incorporate the assets and liabilities of all entities controlled by SEAL as at 31 December 2012 and the results of all controlled entities for the financial period then ended.

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

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

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Deferred income tax expense reflects movements in deferred tax asset and deferred tax liability balances during the period as well as unused tax losses. 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.

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 utilised.

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.

Development assets and plant and equipment are carried at cost less where applicable, any accumulated depreciation, amortisation and impairment losses. The initial measurement of development and production assets subject to depreciation and amortisation include developed leasehold costs, intangible and tangible drilling and completion costs, allocated drilling overhead, capitalised finance costs and the estimated fair value of restoration provisions as at the date of each wells' initial production. The initial measurement of development and production assets not subject to depreciation and amoritsation include similar costs of wells that have not had initial production as at the date of the statement of financial position. The initial measurement of plant and equipment assets include primarily office and computer equipment.

The carrying amount of development assets and plant and equipment are reviewed semi-annually to ensure that they are not in excess of the recoverable amount from these assets. The recoverable amount is assessed on the basis of the expected net cash flows that will be received from the assets employment and subsequent disposal. The expected net cash flows have been discounted to their present values in determining recoverable amounts.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

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 statement of profit or loss during the financial period in which are they are incurred.

Fixed assets 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 Group uses the units of production method to amortise costs carried forward in relation to its development assets. For this approach, the calculation is based upon proved developed reserves.

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.

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.

Exploration and evaluation expenditure incurred is accumulated in respect of each identifiable area of interest. The initial measurement of these costs include the acquisition of rights to explore and mineral rights, various topographical, geological, geochemical and geophysical studies and other expenditures associated with finding specific mineral resources. These costs are only carried forward 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.

Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made.

When production commences, the accumulated costs for the relevant area of interest are transferred to production assets and amortised over the life of the area according to the rate of depletion of the economically recoverable reserves.

A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest.

Leases of fixed assets where substantially all the risks and benefits incidental to the ownership of the asset, but not the legal ownership that are transferred to entities in the consolidated group, are classified as finance leases.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Finance leases are capitalised by recording an asset and a liability at the lower of the amounts equal to the fair value of the leased property or the present value of the minimum lease payments, including any guaranteed residual values. Lease payments are allocated between the reduction of the lease liability and the lease interest expense for the period.

Leased assets are depreciated on a straight-line basis over the shorter of their estimated useful lives or the lease term. Lease payments for operating leases, where substantially all the risks and benefits remain with the lessor, are charged as expenses in the periods in which they are incurred.

Lease incentives under operating leases are recognised as a liability and amortised on a straight-line basis over the life of the lease term.

Financial instruments, incorporating financial assets and financial liabilities, are recognised when the entity becomes a party to the contractual provisions of the instrument. Trade date accounting is adopted for financial assets that are delivered within timeframes established by marketplace convention.

Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified as at fair value through profit or loss. Transaction costs related to instruments classified at fair value through profit or loss are expensed to profit or loss immediately. Financial instruments are classified and measured as set out below.

The Group uses derivative financial instruments to hedge its exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity crude oil price swap, option, and costless collar contracts. Their use is subject to policies and procedures as approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. Derivative financial instruments are initially recognised at cost, which approximates fair value. Subsequent to initial recognition, derivate financial instruments are recognised 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 recognised through the statement of comprehensive income.

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.

Financial assets are classified at fair value through profit or loss when they are held for trading for the purpose of short term profit taking, when they are derivatives not held for hedging purposes, or designated as such to avoid an accounting mismatch or to enable performance evaluation where a group

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

of financial assets is managed by key management personnel on a fair value basis in accordance with a documented risk management or investment strategy. Realised and unrealised gains and losses arising from changes in fair value are included in profit or loss in the period in which they arise.

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market and are subsequently measured at amortised cost using the effective interest rate method.

Held-to-maturity investments are non-derivative financial assets that have fixed maturities and fixed or determinable payments, and it is the Group's intention to hold these investments to maturity. They are subsequently measured at amortised cost using the effective interest rate method.

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.

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

At each reporting date, the group reviews the carrying values of its tangible and intangible assets to determine whether there is any indication that those assets have been impaired. If such an indication exists, the recoverable amount of the asset, being the higher of the asset's fair value less costs to sell and value in use, is compared to the asset's carrying value. Any excess of the asset's carrying value over its recoverable amount is expensed to the statement of comprehensive income.

Impairment testing is performed annually for intangible assets with indefinite lives.

Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

The functional currency of each of the Group's entities is measured using the currency of the primary economic environment in which that entity operates. The consolidated financial statements are presented in US dollars.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

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 income statement of comprehensive income.

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

Exchange differences arising on translation of foreign operations are transferred directly to the Group's foreign currency translation reserve in the statement of comprehensive income. These differences are recognised in the statement of comprehensive income in the period in which the operation is disposed.

Provision is made for the Group's liability for employee benefits arising from services rendered by employees to balance 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.

The Group has an employee share option plan. The fair value of the options awarded are amortised as an expense in the statement of comprehensive income over their performance period. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options at the grant date.

The group has a restricted share unit plan (RSU) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Group's long-term goals. The RSUs are based on targets established and approved by the Board. Actual RSUs, awarded annually, are modified according to actual results and vest in four equal tranches beginning on the grant date.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Provisions are recognised when the group has a legal or constructive obligation, as a result of past events, for which it is probable that an outflow of economic benefits will result and that outflow can be reliably measured.

Cash and cash equivalents include cash on hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, unrestricted escrow accounts that management expects to be used to settle current liabilities, capital or operating expenditures, or complete acquisitions and bank overdrafts.

Revenue from the sale of goods is recognised upon the delivery of goods to customer. Interest revenue is recognised on a proportional basis taking into account the interest rates applicable to the financial assets.

Revenue from the rendering of a service is recognised upon the delivery of the service to the customers. All revenue is stated net of the amount of goods and services tax (GST).

Borrowing costs directly attributable to the acquisition, construction or production of assets that necessarily take a substantial period of time to prepare for their intended use or sale are added to the cost of those assets until such time as the assets are substantially ready for their intended use or sale. Borrowings are recognised initially at fair value, net of transaction costs incurred. Subsequent to initial recognition, borrowings are stated as amortised cost with any difference between cost and redemption being recognised in the statement of profit or loss and other comprehensive income over the period of the borrowings on an effective interest basis. No borrowing costs were capitalised in the six month period and year ended 31 December 2012 and 30 June 2012.

All other borrowing costs are recognised in income in the period in which they are incurred.

Revenues, expenses and assets are recognised net of the amount of GST, except where the amount of GST incurred is not recoverable from the Australian Tax Office. In these circumstances the GST is recognised as part of the cost of acquisition of the asset or as part of an item of the expense. Receivables and payables in the statement of financial position are shown inclusive of GST.

Cash flows are presented in the statement of cash flows on a gross basis, except for the GST component of investing and financing activities, which are disclosed as operating cash flows.

The Directors evaluate estimates and judgments 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.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The estimated quantities of hydrocarbon reserves reported by the consolidated entity are integral to the calculation of amortisation (depletion), depreciation expense 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. For purposes of the calculation of amortization (depletion), and depreciation and the assessment of possible impairment of assets, management prepares reserve estimates which conform to guidelines prepared by the Society of Petroleum Engineers. 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. These reserve estimates may differ from estimates prepared in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") regarding oil and natural gas reserve reporting including those presented in Note 33.

The Company's policy for exploration and evaluation is discussed in Note 1 (c). The application of this policy requires the Company to make certain estimates and assumptions as to future events and circumstances. Any such estimates and assumptions may change as new information becomes available. If, after having capitalised exploration and evaluation expenditure, the directors conclude 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 statement of comprehensive income.

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 life of the assets and the provision is revised at each balance date through the statement of profit or loss as the discounting of the liability unwinds.

The same accounting policies and methods of computation have been followed in this financial report as were applied in the 30 June 2012 financial statements.

Certain reclassifications have been made to the prior year financial statements and associated notes to the financial statements to conform to the current year presentation.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The company is of a kind referred to in Class Order 98/100 issued by the Australian Securities and Investment Commission, relating to rounding of amounts in the financial statements. Amounts have been rounded to the nearest thousand.

The financial information for the parent entity, SEAL, discussed in Note 32, has been prepared on the same basis, using the same accounting policies as the consolidated financial statements.

The group presents basic and diluted earnings per share for its ordinary shares. Basic earnings 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 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.

During the current reporting period the Group adopted all of the new and revised International Accounting Standards and Australia Accounting Standards and Interpretations applicable to its operations which became mandatory.

AASB 2011-9 Amendments to Australian Accounting Standards Presentation of Items of Other Comprehensive Income (IAS 1 Amendments)

The IAS 1 Amendments require an entity to group items presented in other comprehensive income into those that, in accordance with other IFRSs: (a) will not be reclassified subsequently to profit or loss and (b) will be reclassified subsequently to profit or loss when specific conditions are met. It is applicable for reporting periods beginning on or after 1 July 2012. The Group's management adopted this change in the current presentation of items in other comprehensive income. This adoption did not affect the measurement or recognition of such items.

Recently issued accounting standards to be applied in future reporting periods:

The following Standards and Interpretations are effective for annual periods beginning on or after 1 January 2013 and have not been applied in preparing these consolidated financial statements. The Group's assessment of the impact of these new standards, amendments to standards, and interpretations is set out below.

IFRS 9 introduces new requirements for the classification, measurement, and derecognition of financial assets and financial liabilities. IFRS 9 is effective for annual periods beginning on or after 1 January 2015, and is available for early adoption.

IFRS 10 replaces the guidance on control and consolidation in IAS 27 — Consolidated and Separate Financial Statements and Interpretation 12 — Consolidation — Special Purpose Entities. IFRS 10 includes a new definition of control that focuses on the need to have both power and rights or exposure to variable returns.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

IFRS 13 establishes a single source of guidance for fair value measurements and disclosures. The standard defines fair value, establishes a framework for measuring fair value, and requires more extensive disclosures than current standards. IFRS 13 is effective for annual periods beginning on or after 1 January 2013.

AASB 2011-4 Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure

This standard removes the requirements to include individual key management personnel disclosures in the notes to and forming part of the Financial Report. AASB 2011-4 is effective for annual periods beginning on or after 1 July 2013.

AASB 2012-5 Amendments to Australian Accounting Standards arising from Annual Improvements 2009-2011 Cycle

AASB 2012-5 makes amendments to several Australian Accounting Standards. These amendments primarily relate to clarification of narrative requirements for comparative information and segment disclosures for interim financial reports. AASB 2012-5 is effective for annual periods beginning on or after 1 January 2013.

The potential effect of these Standards is yet to be fully determined. However, it is not expected that the new or amended standards will significantly affect the Group's financial position or performance.

The financial report was authorised for issue on 28 March 2013, by the Board of Directors.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

On 27 September 2012, the Company sold all of its interest in properties located in the South Antelope field for $172.4 million. Prior to the disposition, the South Antelope development and production properties were part of the Williston Basin depletion base. To determine the carrying costs of the sold properties, the Company used the relative fair value of South Antelope proved developed reserves as compared to the Company's total proved developed reserves in the Williston Basin. As a result, it was determined that approximately $49.4 million of the Company's carrying costs related to its South Antelope development and production properties at the time of the disposal. In addition to the South Antelope development and production properties, the Purchaser acquired approximately $3.9 million of assets and assumed approximately $3.8 million of liabilities, which were removed from the Company's statement of financial position at the time of the sale. The Company incurred approximately $0.9 million of legal and other transaction related costs. This sale resulted in a gain of $122.5 million. The Company also sold all of its properties in the Pawnee prospect for $0.9 million of proceeds, which resulted in a loss of $0.2 million. Both the South Antelope gain and the Pawnee loss on sale are included in the gain on sale of non-current assets in the statement of profit or loss and other comprehensive income for the six month period ended 31 December 2012.

The Company elected to apply Section 1031 "like-kind exchange" treatment of the South Antelope sales proceeds under the US tax rules which allow deferral of the gain if the proceeds are used to acquire "like-kind property" within six months of the closing date of the transaction. In addition, the US tax rules allow the deduction of all intangible drilling costs ("IDCs") in the period incurred. As at 31 December 2012, the Company expected to defer the majority of the taxable gain on the sale by acquiring qualified replacement properties or utilising IDCs from its development program. In March 2013, the Company completed a transaction in which the majority of the funds remaining in its Section 1031 escrow account were used to acquire oil and gas properties in connection with the Texon Scheme of Arrangement transaction discussed in more detail in Note 29. Management believes the properties acquired qualify as "like-kind property" under Section 1031 which will result in deferral of the majority of the gain associated with the South Antelope sale.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

		Consolidated Group

		6 months to 31 December 2012 US$'000			12 months to 30 June 2012 US$'000
a)	The components of income tax expense comprise:
	Current tax benefit/(expense)	$	(11	)	$	242
	Deferred tax expense		(46,605	)		(4,387	)

		$	(46,616	)	$	(4,145	)

b)	The prima facie tax on income from ordinary activities before income tax is reconciled to the income tax as follows:
	Profit before income tax	$	122,826		$	10,157

	Prima facie tax expense on income from ordinary activities before income tax at 30%	$	36,848		$	3,047
	Add:
	Tax effect of:
	— difference of tax rate in US controlled entities		9,417			862
	— employee options		44			276
	— other allowable items		93			4
	— previously unrecognised tax gains used to (reduce)/increase current tax expense		—			(139	)
	— previously unrecognised tax losses used to (reduce)/increase current tax expense		—			—
	— Acquisition related costs		214			—
	— Deferred tax assets associated with capital raising costs recognised direct to equity but not meeting the recognition criteria		—			95

	Income tax attributable to entity	$	46,616		$	4,145

c)	Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30%	$	375		$	375

At December 31, 2012 the Company had U.S. federal and state net operating loss carryforwards for tax purposes of approximately $58.8 million and $54.5 million, respectively which will expire in 2030 through 2032. We believe that it is more likely than not that the carryforward will be utilized before it expires.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

a) Names and positions held of Consolidated Group key management personnel in office at any time during the financial period are:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Included in cash equivalents, the Company has approximately $141.4 million in a Section 1031 escrow account which is 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 balance has been included in the Company's

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

cash and cash equivalents in the statement of financial position and statement of cash flows as at 31 December 2012 and for the six month period then ended.

For the year ended 30 June 2012, the effective interest rate on short term bank deposits was 1.5% for the Group. 94% of deposits were at 24 hours call and the balance of deposits has an average maturity of 49 days. The Groups' exposure to interest rate risk is summarised at Note 31.

At 31 December and 30 June 2012, the Group had receivable balances of $8.6 million and $6.7 million, respectively, which were outside normal trading terms (the receivable was past due but not impaired). Due to the short term nature of these receivables, their carrying amounts are assumed to approximate their fair value.

	Consolidated Group

	6 months to 31 December 2012 US$'000		12 months to 30 June 2012 US$'000
FINANCIAL ASSETS COMPRISE:
Current
Derivative financial instruments — commodity contracts	$	617	$	1,331
Non-current
Derivative financial instruments — commodity contracts		—		476

Total financial assets	$	617	$	1,807

FINANCIAL LIABILITIES COMPRISE:
Current
Derivative financial instruments — commodity contracts	$	—	$	—
Non-current
Derivative financial instruments — commodity contracts		—		—

Total financial liabilities	$	—	$	—

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The following table presents financial assets and liabilities measured at fair value in the 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:

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.

The methods and valuation techniques used for the purpose of measuring fair value are unchanged compared to the previous reporting period.

Where derivatives are traded either on exchanges or liquid over-the-counter markets the Group uses the closing price at the reporting date. Normally, the derivatives entered into by the Group are not traded in active markets. The fair values of these contracts are estimated using a valuation technique that maximises the use of observable market inputs, eg market exchange and interest rates (Level 2). Most derivatives entered into by the Group are included in Level 2 and consist of commodity contracts.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

On 31 December 2012, the Company completed a transaction to acquire certain oil and gas properties in the Wattenberg field of the Denver-Julesburg (DJ) Basin (the "Wattenberg Acquisition"). In connection with the transaction the Company transferred $3.0 million, $2.7 million and $0.5 million to escrow accounts related to a drilling commitment, title defect and environmental remediation, respectively ($6.2 million collectively). Because the use of the Wattenberg Acquisition related escrow accounts are restricted or generally will not be used to settle short-term Company operating costs, they have been excluded from the Company's cash and cash equivalents balance in the statement of financial position and statement of cash flows as at 31 December 2012 and for the six month period then ended. Of this $6.2 million escrow account balance, $3.8 million is classified as other current asset in the statement of financial position as at 31 December 2012.

			Consolidated Group

			31 December 2012 US$'000			30 June 2012 US$'000
Costs carried forward in respect of areas of interest in:
Development and production phase at cost			$	96,663		$	113,830
Accumulated amortisation				(14,619	)		(24,241	)
Provision for impairment				(2,315	)		(2,315	)

Total Development and Production Expenditure			$	79,729		$	87,274

	a)	Movements in carrying amounts:
		Development expenditure
		Balance at the beginning of the period	$	87,274		$	45,873
		Amount transferred from exploration phase		527			2,277
		Amounts capitalised during the period		47,949			50,520
		Amortisation expense		(6,013	)		(10,971	)
		Development assets sold during the period		(50,008	)		(425	)

		Balance at end of period	$	79,729		$	87,274

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

			Consolidated Group

			31 December 2012 US$'000			30 June 2012 US$'000
Costs carried forward in respect of areas of interest in:
Exploration and evaluation phase at cost			$	35,053		$	13,050
Provision for impairment				(1,614	)		(1,614	)

Total Exploration and Evaluation Expenditure			$	33,439		$	11,436

	a)	Movements in carrying amounts:
		Exploration and evaluation
		Balance at the beginning of the period	$	11,436		$	6,626
		Amounts capitalised during the period		23,348			8,670
		Impairment of exploration and expenditure		—			(357	)
		Amount transferred to development phase		(527	)		(2,277	)
		Exploration tenements sold during the period		(818	)		(1,226	)

		Balance at end of period	$	33,439		$	11,436

Included in the amounts capitalised during the six month period ended 31 December 2012, was $12.7 million related the Wattenberg Acquisition, which occurred on 31 December 2012. The remaining $1.0 million of the total consideration paid or liabilities assumed was included in the amount capitalised of the Company's development and production assets.

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

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The $2.4 million of escrow accounts is the long-term portion related to the escrow accounts discussed in Note 12.

On 31 December 2012, Sundance Energy, Inc. ("SEI"), a wholly owned subsidiary of the Company, entered into a credit agreement with Wells Fargo (the "Credit Facility"), pursuant to which up to $300 million is available on a revolving basis. The borrowing base under the Credit Facility is determined by reference to the value of the Company's proved reserves. The agreement specifies a semi-annual borrowing base redetermination and the Company can request two additional redeterminations each year. The borrowing base was originally set at $30 million. Interest on borrowed funds accrues, at the Company's option, of i) LIBOR plus a margin that ranges from 175 to 275 basis points or ii) the Base Rate, defined as a rate equal to the highest of (a) the Federal Funds Rate plus ¹/2 of 1%, (b) the Prime Rate, or (c) LIBOR plus a margin that ranges from 75 to 175 basis points. The applicable margin varies depending on the amount drawn. The Company also pays a commitment that ranges from 37.5 to 50 basis points on the undrawn balance of the borrowing base. The agreement has a five year term and contains both negative and affirmative covenants, including minimum current ratio

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

and maximum leverage ratio requirements. As at 31 December 2012 the Company requested and received a waiver from Wells Fargo regarding compliance with the maximum leverage ratio as at 31 December 2012 as required under the terms of the Credit Facility. Certain development and production assets are pledged as collateral and the facility is guaranteed by the Parent Company. The Company immediately drew on the Credit Facility's full $30 million borrowing base and used $15 million of the proceeds to repay and retire its outstanding loan with the Bank of Oklahoma. As a part of its Bank of Oklahoma debt extinguishment, the Company expensed approximately $0.3 million of unamortised deferred financing costs, which is included in financing costs in the statement of profit or loss and other comprehensive income for the six month period ended 31 December 2012. The Company capitalised $0.4 million of financing costs related to the Wells Fargo credit facility, which will be amortised over the term of the loan. Under the terms of the credit facility, SEI is limited to payment of $2 million in dividends annually to SEAL without prior creditor approval.

The restoration provision represents the present value of restoration costs relating to the Company's oil and gas interests, which are expected to be incurred up to 2042. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. 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 gas prices, which are inherently uncertain.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

As at 31 December 2012, all of the Company's exploration and evaluation and development and production assets are located in the United States of America.

The mineral leases in the exploration prospects in the USA have primary terms ranging from 3 years to 5 years and generally have no specific capital expenditure requirements. However, mineral

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

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.

On 31 December 2012, the Company entered into an agreement to acquire certain oil and gas properties located in the Wattenberg Field and to drill 45 net wells by 31 December 2015 on the acquired properties (the "Drilling Commitment"). As each qualifying well is drilled, approximately $67 thousand is paid from the escrow account to the Company. However, for each required net commitment well not completed by the Company during that prorated commitment year, the Company is to pay the seller of the properties approximately $67 thousand from the escrow account. Certain clawback provisions allow the Company to recoup amounts paid to the sellers if the total 45 wells are drilled by 31 December 2015.

	Consolidated Group

	31 December 2012 US$'000		30 June 2012 US$'000
Operating lease commitments
Commitments for minimum lease payments in relation to non-cancellable operating leases not provided for in the financial statements.
Lease expenditure commitments
— due within one year	$	162	$	202
— due within 1 - 5 years		81		162

	$	243	$	364

Drilling commitments
Commitments for the payment related to drilling not provided for in the financial statements.
Expenditure commitments
due within one year	$	1,000	$	—
due within 1 - 5 years		2,000		—

	$	3,000	$	—

Employment and consultant commitments
Commitments for the payment of salaries and other remuneration under long-term employment and consultant contracts not provided for in the financial statements.
Expenditure commitments
— due within one year	$	275	$	180
— due within 1 - 5 years		104		270

	$	379	$	450

Details relating to the employment contracts are set out in the remuneration report.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

At the date of signing this report, the Group is not aware of any contingent assets or liabilities that should be disclosed in accordance with IAS 37.

		Consolidated Group

		6 months to 31 December 2012 US$'000			12 months to 30 June 2012 US$'000
a)	Reconciliation of cash flows from operations with income from ordinary activities after income tax
	Profit from ordinary activities after income tax	$	76,210		$	6,012
	Non cash flow in operating income
	Depreciation and exploration expenditure written off		6,116			11,468
	Share options expensed		733			930
	Unrealised losses (gains) on derivatives		1,190			(2,242	)
	Net gain on sale of properties		(122,327	)		(3,004	)
	Write-off of Bank of Oklahoma deferred financing fees		349			—
	Changes in assets and liabilities:
	— Increase in current and deferred tax		46,616			3,732
	— (Increase) / decrease in other assets, excluding investing		(381	)		1,517
	— Increase in trade and other receivables		(3,320	)		(8,814	)
	— Increase in trade and other payables		4,200			2,233

	Net cash provided by operating activities	$	9,386		$	11,832

During the six month period and year ended 31 December and 30 June 2012, 1,666,667 and 388,889 shares were issued at A$0.41 and A$0.37 per weighted average share, respectively.

There were no non-cash business combinations in the six month period and year ended 31 December and 30 June 2012.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

During the six month period ended 31 December 2012, a total of nil (year ended 30 June 2012: 2,260,000) options were granted to employees pursuant to employment agreements and a total of 1,666,667 (year ended 30 June 2012: 388,889) previously issued options were exercised. There were 700,000 awarded options that the Company expected to issue in early 2013 for which Company employees rendered services during the six month period ended 31 December 2012. Using the best estimate of fair value on the employees' hire date, the Company began expensing these awards during the six month period ended 31 December 2012. The 700,000 options expected to be issued in early 2013 are excluded from the outstanding options summary below:

The following tables summarise the options issued and awarded and their related grant date, fair value and vesting conditions for the six month period ended 31 December 2012 and the year ended 30 June 2012:

Options awarded, but not yet issued during the six month period ended 31 December 2012:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Share based payments expense related to options is determined pursuant to IFRS 2: Share Based Payments, and is recognised pursuant to the attached vesting conditions. The fair value of the options awarded ranged from A$0.42 to A$0.45 for the period ended 31 December 2012 and A$0.21 to A$0.46 for the year ended 30 June 2012, which was calculated using a Black-Sholes options pricing model. Expected volatilities are based upon the historical volatility of the ordinary shares. Historical data is also used to estimate the probability of option exercise and potential forfeitures. No options were issued in the six month period ended 31 December 2012; however, 700,000 awarded options were expected to be issued in early 2013 and were expensed during the period according to the relevant service period.

The following table summarises the key assumptions used to calculate the estimated fair value awarded or granted during the periods:

During the six month period and year ended 31 December and 30 June 2012, the Board of Directors awarded 1,482,143 and 910,000 restricted share units (RSUs) to certain employees. These awards were made in accordance with the long term equity component of the Company's incentive compensation plan, the details of which are described in more detail in the remuneration section of the Directors' Report. Share based payment expense for RSUs awarded was calculated pursuant to IFRS 2: Share Based Payments. The fair values of RSUs were estimated at the date they were approved by the Board of Directors, 15 October 2012 and 5 December 2011 (the measurement dates). As at 30 June 2012, the 5 December 2011 awards had been approved but not yet issued. All unforfeited awards were issued to employees upon finalisation of the plan documents, which occurred in December 2012. The value of

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

the vested portion of these awards has been recognised within the financial statements. This information is summarised for the Consolidated Group for the six month period ended 31 December 2012 below:

The following tables summarise the RSUs issued and their related grant date, fair value and vesting conditions for the six month period ended 31 December 2012 and the year ended 30 June 2012:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The Group had interests in joint venture operations of 23.34% in oil and gas exploration in the PEL 100 blocks in South Australia. In December 2011, the joint venture interests were sold for $0.5 million. The net book value was nil, as the joint venture interests were impaired in previous years.

The Company paid $158.4 million for substantially all of the net assets of Armadillo Petroleum Ltd. Due to the complexity and timing of the merger, the fair values are provisional. The following table reflects the assets acquired and the liabilities assumed at their estimated fair value (in thousands). The Company will continue to review the assets acquired and the liabilities assumed for twelve months from the date of the merger.


Estimated fair value of assets acquired:
Trade and other receivables	$	5,284
Other current assets		456
Development and production assets		53,937
Exploration and evaluation assets		145,881
Prepaid drilling and completion costs		3,027

Amount attributable to assets acquired		208,585

Estimated fair value of liabilities assumed:
Trade and other payables		119
Accrued expenses		34,693
Restoration provision		277
Deferred tax liabilities		15,094

Amount attributable to liabilities assumed		50,183

Net assets acquired	$	158,402

Purchase price:
Cash and cash equivalents	$	26,310
Issued capital		132,092

Total consideration paid	$	158,402

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Since the acquisition date of March 8, 2013, the Company has earned revenue of $11.3 million and generated income of $5.8 million. The following reflects select pro forma information as if the merger had occurred on July 1, 2012 instead of the closing date of March 8, 2013, and excludes the results of operations for and the disposition of the South Antelope property:

	6 months to 31 December 2012

Oil and gas revenue	$	913
Lease operating and production expenses		(1,689	)
Depreciation and amortisation expense		(3,471	)
Employee benefits expense		(1,085	)
Administrative expense		(2,098	)
Finance income		201
Exploration and evaluation expenditures		(359	)
Impairment of non-current assets		(576	)
Net gain/loss on sale of non-current assets		(122,327	)
Realised currency loss		(108	)

Profit (loss) before income tax		(130,599	)
Income tax benefit (expense)		49,585

		(81,014	)
Profit attributable to owners of the Company for the period		76,210

Adjusted profit (loss) attributable to the owners of the Company for the period	$	(4,804	)

Adjusted basic and diluted earnings (loss) per share	$	(0.01	)

In the six month period ended 31 December 2012, the Company incurred approximately $0.7 million of transaction costs related to the acquisition of Texon. These transaction costs are included in the administrative expenses in the statement of profit or loss and other comprehensive income and are not deductible for US tax purposes. These transaction costs continued through the effective date of the acquisition and were expensed as incurred.

In connection with the sale of its South Antelope assets in September 2012, the Company elected Section 1031 "like-kind exchange" treatment which, under the US tax rules, provides for deferral of the gain if the proceeds are used to acquire "like-kind property" within six months of the closing of the transaction. In March 2013, the Company completed a transaction in which the majority of the funds remaining in its Section 1031 escrow account were used to acquire oil and gas properties in connection with the Texon Scheme of Arrangement transaction discussed above. Management believes the properties acquired qualify as "like-kind property" under Section 1031 which will result in deferral of the majority of the gain associated with the South Antelope sale.

On 6 June 2013, SEAL completed an A$48.1 million placement of 55,984,884 shares priced at A$0.86 per share. Proceeds from the placement will be used primarily to accelerate development of the Company's Eagle Ford and Mississippian/Woodford acreage and for general corporate purposes.

After settlement of the placement, SEAL offered its shareholders with registered addresses in Australia and New Zealand the opportunity to participate in a capital raise pursuant to a Share Purchase

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Plan at the placement price of A$0.86 per share for up to A$15,000 per shareholder of record as at 30 May 2013 and up to a maximum capital raise of A$15.0 million. The Share Purchase Plan was open for a period from 10 June 2013 through 28 June 2013 and raised A$1.3 million from the sale of 1,517,454 shares.

On 30 August 2013, the Company entered into a second lien five-year term loan with Wells Fargo Energy Capital for $15 million and used the proceeds to pay down the balance of the first lien revolving line of credit with Wells Fargo Bank on 3 September 2013. Substantially all of the Company's assets are collateralized by both the first lien revolving line of credit and the second lien term loan. The Company's total outstanding debt remained at $30 million as at 18 October 2013.

The following table provides a summary of derivative contracts entered into during 2013:

Contract Type	Basis		Floor Price		Ceiling Price		Term

Swap	LLS	3,000	$	101.75	$	101.75	Jul 13 - Dec 13
Collar	LLS	3,000		95.00		104.90	Jul 13 - Dec 13
Swap	NYMEX-WTI	1,000		106.55		106.55	Oct 13 - Dec 13
Swap	LLS	10,000		110.85		110.85	Oct 13 - Dec 13
Swap	LLS	5,000		103.75		103.75	Jul 13 - Dec 13
Swap	LLS	3,000		101.75		101.75	Jul 13 - Jun 14
Collar	NYMEX-WTI	3,000		90.00		99.75	Jul 13 - Jun 14
Collar	LLS	2,000		90.00		102.00	Jan 14 - Dec 14
Collar	LLS	3,000		90.00		101.30	Jan 14 - Dec 14
Swap	NYMEX-WTI	2,000		97.40		97.40	Jan 14 - Dec 14
Swap	LLS	3,000		102.30		102.30	Jan 14 - Dec 14
Collar	NYMEX-WTI	3,000		85.00		94.75	Jan 14 - Dec 14
Swap	LLS	3,000		100.15		100.15	Jan 14 - Dec 14
Collar	LLS	2,000		85.00		102.00	Jul 14 - Dec 14
Collar	NYMEX-WTI	2,500		80.00		98.25	Jul 14 - Dec 14
Collar	NYMEX-WTI	2,000		75.00		98.65	Jan 15 - Dec 15
Collar	LLS	3,000		85.00		101.05	Jan 15 - Dec 15

Other than as detailed above, no matters or circumstances have arisen since the end of the financial year which significantly affected or may significantly affect the operations of the Group, the results of those operations, or the state of affairs of the Group in future financial years.

Transactions with related parties: N Martin was a partner and is now a consultant of Minter Ellison Lawyers and has been a Director since 1 March 2012. Minter Ellison Lawyers were paid a total of $148,073 and $124,007 for legal services for the period and year ended 31 December and 30 June 2012, respectively.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

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 focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. The Group utilise derivative financial instruments to hedge certain risk exposures. 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.

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.

The main risk the Group is exposed to through its financial instruments is interest rate risk. The interest rate risk is managed with a mixture of fixed and floating rate cash deposits. At 31 December and 30 June 2012 approximately nil and 6% of Group deposits are fixed, respectively. It is the policy of the Group to keep surplus cash in interest yielding deposits.

The Board actively reviews oil 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 market spot rates reduced for basis differentials in the basins from which the Company produces. Nymex is a light, sweet crude oil delivered to Cushing, Oklahoma, which is used as the benchmark for onshore United States petroleum prices. Forward contracts are used by the Group to manage its forward commodity price risk exposure. The Group's policy is to hedge less than 50% of anticipated future oil production for up to 24 months. The Group may hedge over 50% or beyond 24 months with approval of the Board. 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.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The Group has performed a sensitivity analysis relating to its exposure to interest rate risk at balance date. This sensitivity analysis demonstrates the effect on the current period results and equity which could result from a change in these risks. The balance of debt as at 31 December and 30 June 2012 was $30 million and $15 million and is included in the Interest Rate Sensitivity Analysis below.

The effect on income and equity as a result of changes in the interest rate, with all other variables remaining constant would be as follows:

Effective 1 July 2011, the functional currency was changed from Australian dollars to US dollars. All of the Company's operations are conducted in the US in transactions denominated in US dollars. Only a relatively immaterial amount of administrative expense is incurred in Australia and paid in Australian dollars and cash balances maintained in Australian banks are also relatively immaterial. Therefore, the impact resulting from changes in the value of the US dollar to the Australian dollar would not have a material effect on income and equity.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The effect on profit and equity as a result of changes in oil prices with all variables remaining constant would be as follows:

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. The balances are not materially different from those disclosed in the statement of financial position of the Group.

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.

The Group does not have any material credit risk exposure to any single debtor or group of debtors under financial instruments entered into by the consolidated entity.

For the six-month period ended 31 December 2012, our major customers were Helis Oil & Gas Company LLC ("Helis"), EOG Resources Inc. ("EOG"), Hess Corporation ("Hess") and Suncor Energy Marketing Inc. ("Suncor") and accounted for 29%, 22%, 21% and 10%, respectively, of our consolidated oil and gas sales revenue. For the year period ended 30 June 2012, our major customers were Helis, Hess, and EOG, and accounted for 47%, 20% and 14%, respectively, of our consolidated oil and gas sales revenue.

Helis, Hess and EOG are operators of our properties in the Bakken; they sell crude oil and natural gas to various purchasers in the region and remit our share of the revenue to us. If any of the companies who purchase the crude oil and natural gas from the operators were to discontinue purchasing production from this area, there are a number of other purchasers to whom we could sell our

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

production with little or no delay. If those parties were to discontinue purchasing our product, there would be challenges initially, but ample markets to handle the disruption.

Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and the availability of funding through an adequate committed credit facility. The Company aims to maintain flexibility in funding to meet ongoing operational requirements and exploration and development expenditures by keeping a committed credit facility available. The Company has the following commitments related to its non-derivative financial liabilities:

The Group is exposed to fluctuations in foreign currency arising from transactions in currencies other than the Group's functional currency (US$).

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The Company is exposed to fluctuations in its share price arising from the Texon Acquisition Scheme, in which subsequent to 31 December 2012, the Company used approximately 122.7 million newly issued Sundance shares to acquire Texon ("Acquisition Scheme Consideration"). Immediately preceding the announcement of the Acquisition Scheme, Sundance shares were valued at A$0.82 per share, which would have represented equity consideration of A$100.6 million. As at the Acquisition Date, Sundance shares were valued at A$1.05 per share, which resulted in equity consideration fair value of A$128.8 million. Following the completion of the Acquisition Scheme, the Company will undertake a comprehensive assessment of the fair value of the assets acquired and liabilities assumed as at the acquisition date and record the asset and liability fair values accordingly. Any difference between the fair value of the Acquisition Scheme Consideration and the fair value of the net assets acquired will be accounted for as goodwill or a bargain purchase as appropriate.

	Consolidated Group

	31 December 2012 US$'000			30 June 2012 US$'000
Parent Entity
Assets
Current assets	$	1,490		$	986
Investment in subsidiaries		134,094			57,643

Total assets	$	135,584		$	58,629

Liabilities
Current liabilities	$	127		$	109
Non-current liabilities		—			—

Total liabilities		127			109

Total net assets	$	135,457		$	58,520

Equity
Issued capital		58,694			57,978
Share options reserve		386			386
Retained earnings (loss)		76,377			156

Total equity	$	135,457		$	58,520

Financial Performance
Profit/(loss) for the year	$	(241	)	$	464
Other comprehensive income		—			—

Total profit or loss and other comprehensive income	$	(241	)	$	464

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

	Consolidated Group

	31 December 2012 US$'000			30 June 2012 US$'000
Parent Entity
Assets
Current assets	$	1,490		$	986
Investment in subsidiaries		150,453			73,327

Total assets	$	151,943		$	74,313

Liabilities
Current liabilities	$	127		$	109
Non-current liabilities		—			—

Total liabilities		127			109

Total net assets	$	151,816		$	74,204

Equity
Issued capital	$	58,694		$	57,978
Share options reserve		4,045			3,205
Foreign currency translation		(1,095	)		(941	)
Retained earnings (loss)		90,172			13,962

Total equity	$	151,816		$	74,204

Financial Performance
Profit/(loss) for the period before equity in income of subsidiaries	$	(241	)	$	464
Equity in income of subsidiaries		76,451			5,548
Other comprehensive income		(154	)		(247	)

Total profit or loss and other comprehensive income	$	76,056		$	5,765

Sundance Energy Australia Limited has not entered into a deed of cross guarantee with its' wholly-owned subsidiary, Sundance Energy, Inc. related to the credit facility with Wells Fargo.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Costs Incurred — The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities:

Oil and Gas Reserve Information — Proved reserve quantities are based on estimates prepared by the Company in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC.

Netherland, Sewell & Associates, Inc. ("NSAI"), an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interests owned by the Company as at December 31, 2012, and June 30, 2012 and 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with NSAI and a Registered Professional Engineer in the State of Texas with over 30 years of experience in oil and gas reservoir studies and evaluations.

Proved reserves are those quantities of oil and 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.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The following reserve data represents estimates only and should not be construed as being exact.



Total proved reserves:
June 30, 2011	4,788		7,692		6,070
Revisions of previous estimates	220		170		248
Extensions and discoveries	3,309		5,560		4,236
Production	(338	)	(370	)	(399	)

June 30, 2012	7,979		13,052		10,155
Revisions of previous estimates	(556	)	(1,205	)	(757	)
Extensions and discoveries	1,597		4,322		2,317
Purchases of reserves in-place	827		5,797		1,793
Production	(195	)	(233	)	(234	)
Sales of reserves in-place	(3,894	)	(4,845	)	(4,702	)

December 31, 2012	5,758		16,888		8,572

Proved developed reserves:
June 30, 2011	1,497		2,637		1,936

June 30, 2012	2,564		4,905		3,382

December 31, 2012	1,932		5,242		2,805

Proved undeveloped reserves:
June 30, 2011	3,291		5,055		4,134

June 30, 2012	5,415		8,147		6,773

December 31, 2012	3,826		11,646		5,767

During the year ended June 30, 2012, we added 4,236 MBoe through extensions and discoveries. Of these additions, approximately 1,486 and 2,750 MBoe were attributable to our Wattenberg and Bakken assets, respectively.

During the six-month period ended December 31, 2012, we added 2,317 MBoe through extensions and discoveries. Of these additions, approximately 1,522, 306 and 489 MBoe were attributable to our Wattenberg, Bakken and Mississippian/Woodford assets, respectively. Our purchase of reserves were located in the Machii Ross project of the Wattenberg, and sales of reserves were located in the South Antelope prospect of the Bakken.

Standardized Measure of Future Net Cash Flows — The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves" (Standardized Measure) is calculated in accordance with guidance provided by the FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company's proved oil and 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.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves. 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.

(in thousands)	Six months ended December 31, 2012			Year ended June 30, 2012

Standardized Measure, beginning of period	$	137,285		$	59,444
Sales, net of production costs		(13,642	)		(23,432	)
Net change in sales prices, net of production costs		(4,997	)		23,379
Extensions and discoveries, net of future production and development costs		41,481			63,264
Changes in future development costs		(3,565	)		(13,921	)
Previously estimated development costs incurred during the period		33,714			39,268
Revision of quantity estimates		(15,138	)		5,645
Accretion of discount		17,442			7,750
Change in income taxes		17,098			(19,081	)
Purchases of reserves in-place		7,626			—
Sales of reserves in-place		(87,374	)		—
Change in production rates and other		(14,383	)		(5,031	)

Standardized Measure, end of period	$	115,547		$	137,285

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. 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.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS FOR DECEMBER 31, 2012 AND
THE SIX-MONTH PERIOD THEN ENDED (Continued)

The following average prices were used in determining the Standardized Measure as at:

We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures.

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2011

			Consolidated Group

	Note		31 December 2011 US$'000			31 December 2010 US$'000
			(unaudited)			(unaudited)
REVENUE
Sales		2		11,739			6,989
Interest income				240			67
Net gain on disposal of assets		3		459			10,384
Realised foreign currency gain/(loss)				4			(22	)
Unrealised foreign currency gain/(loss)				(5	)		—
EXPENSES FROM ORDINARY ACTIVITIES
Cost of sales				(2,784	)		(1,112	)
Finance costs				—			(1	)
Loss on commodity transactions				(464	)		(173	)
Unrealised gain/(loss) on commodity transactions				652			(804	)
Depreciation and amortisation				(4,358	)		(1,952	)
Impairment/write off of development and exploration assets				(357	)		(1,239	)
Employee benefit expense				(2,084	)		(1,904	)
Other expense from ordinary activities				(1,232	)		(998	)
PROFIT/(LOSS) BEFORE INCOME TAX EXPENSE				1,810			9,235
Income tax (expense)/benefit				(659	)		(4,014	)
PROFIT/(LOSS) ATTRIBUTABLE TO MEMBERS OF THE PARENT ENTITY				1,151			5,221
OTHER COMPREHENSIVE INCOME
Exchange differences arising on translation of foreign operations				(303	)		95
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO MEMBERS OF THE PARENT ENTITY				848			5,316

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT DECEMBER 31, 2011

			Consolidated Group

	Note		31 December 2011 US$'000			31 December 2010 US$'000
			(unaudited)			(unaudited)
CURRENT ASSETS
Cash and cash equivalents				11,701			25,244
Trade and other receivables				7,341			3,538
Inventory				22			10
Derivative financial instruments				122
Other current assets				150			81

TOTAL CURRENT ASSETS				19,336			28,873

NON-CURRENT ASSETS
Inventory				21			21
Plant and equipment				298			210
Exploration and evaluation expenditure				6,875			6,626
Development and production assets				61,842			48,173
Derivative financial instruments				95			50
Other non-current assets				358			127

TOTAL NON-CURRENT ASSETS				69,489			55,207

TOTAL ASSETS				88,825			84,080

CURRENT LIABILITIES
Trade and other payables				12,826			9,594
Derivative financial instruments							486
Current tax liabilities				54			80

TOTAL CURRENT LIABILITIES				12,880			10,160

NON-CURRENT LIABILITIES
Long-term provision				412			349
Deferred tax liabilities				7,263			6,744

TOTAL NON-CURRENT LIABILTIES				7,675			7,093

TOTAL LIABILITIES				20,555			17,253

NET ASSETS				68,270			66,827

EQUITY
Issued capital		4		57,978			57,831
Share option reserve				2,828			2,380
Foreign currency translation reserve				(997	)		(694	)
Retained earnings				8,461			7,310

TOTAL EQUITY				68,270			66,827

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2011

Consolidated Group

Balance at 30 June 2010	38,962		1,927	(2,724	)	1,165	39,330

Shares issued during the period	19,893		—	—		—	19,893
Cost of capital raising (net of tax)	(749	)	—	—		—	(749	)
Fair value of options issued	—		—	—		663	663
Total comprehensive income for the period	—		5,221	95		—	5,316

Balance at 31 December 2010	58,106		7,148	(2,629	)	1,828	64,453

Balance at 30 June 2011	57,831		7,310	(694	)	2,380	66,827
Shares issued during the period	147		—	—		—	147
Fair value of options issued	—		—	—		448	448
Total comprehensive income for the period	—		1,151	—		—	848

Balance at 31 December 2011	57,978		8,461	(303	)	2,828	68,270

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2011

	Consolidated Group

	31 December 2011 US$'000			31 December 2010 US$'000
	(unaudited)			(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from sales		8,252			5,331
Payments to suppliers and employees		(5,792	)		(2,925	)
Interest received		240			64
Finance costs		—			(4	)
Derivative payments		(464	)		(14	)
Income taxes refunded/(paid)		(141	)		1,150

NET CASH PROVIDED BY OPERATING ACTIVITIES		2,095			3,602

CASH FLOWS FROM INVESTING ACTIVITIES
Payments for exploration expenditure		(601	)		(806	)
Payments for development expenditure		(14,659	)		(9,313	)
Sale of non-current assets		459			10,788
Payments for plant and equipment		(132	)		(28	)

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(14,933	)		641

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issue of shares		147			19,897
Payments for the costs of capital raisings		—			(1,071	)
Borrowing costs		(232	)		—
Realised currency gain/(loss)		4			7

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(81	)		18,833

Net increase/(decrease) in cash held		(12,919	)		23,076

Cash at beginning of financial half-year		25,244			9,770
Effect of exchange rates on cash holdings in foreign currencies		(624	)		(132	)

Cash at end of financial half-year		11,701			32,714

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2011 AND THE SIX-MONTH PERIOD THEN ENDED

These general purpose financial statements for the interim half-year reporting period ended 31 December 2011 have been prepared in accordance with the requirements of the Corporations Act 2001 and International Accounting Standards including IAS 34: Interim Financial Reporting. Compliance with Australian Accounting Standards ensures that the financial statements and notes also comply with International Financial Reporting Standards, as issued by the International Accounting Standards Board (IASB).

This interim financial report is intended to provide users with an update on the latest annual financial statements of Sundance Energy Australia Limited and its controlled entities (the Group). As such, it does not contain information that represents relatively insignificant changes occurring during the half-year within the Group. It is therefore recommended that this financial report be read in conjunction with the annual financial statements of the Group for the year ended 30 June 2011, together with any public announcements made during the half-year.

The same accounting policies and methods of computation have been followed in this interim financial report as were applied in the most recent annual financial statements except as described below.

The amendments clarified certain disclosures relating to events and transactions that are significant to an understanding of changes in the Group's circumstances since the last annual financial statements. The Group's interim financial statements as of 31 December 2011 reflect these amended disclosure requirements, where applicable.

Following a period of sustained international growth, the Group's cash flows and economic returns are now principally denominated in US Dollars. From 1 July 2011, Sundance Energy Australia Ltd changed the currency in which it presents its consolidated and parent Company Financial Statements from Australian Dollars to US Dollars. This change has no impact on the net loss of the Consolidated Entity other than presentation in US Dollars instead of Australian Dollars.

A change in presentation currency is a change in accounting policy which is accounted for retrospectively. Statutory financial information included in this report that had been previously reported in Australian Dollars has been restated into US Dollars using the procedures outlined below:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2011 AND THE SIX-MONTH PERIOD THEN ENDED (Continued)

The exchange rates of US Dollar to Australian Dollars over the periods included in this Annual Report and Accounts are as follows:

	Consolidated Group

	2011 US$000			2010 US$000
Disposal price for undeveloped acreage		507			10,785

Cash consideration		507			10,785

Cost of assets sold and transaction costs		(48	)		(414	)

Net gain/(loss) on disposal		459			10,371

Assets held for resale
Disposal price for tubing inventory		—			72

Cash consideration		—			72

Cost of assets sold and transaction costs		—			(59	)

Net gain/(loss) on disposal		—			13

Total net gain/(loss) recognised in the statement of comprehensive income		459			10,384

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2011 AND THE SIX-MONTH PERIOD THEN ENDED (Continued)

During the half year ended 31 December 2011, a total of 2,260,000 options were granted to employees pursuant to employment agreements and a total of 60,000 options expired. In addition, a total of 388,889 previously issued options were exercised. This information is summarized below:

Share based payments expense related to options is determined pursuant to IFRS 2: Share Based Payments, and is recognised pursuant to the attached vesting conditions. The fair value of the options ranged from A$0.21 to A$0.46 and was calculated as of the grant date using a Black-Scholes options pricing model. Expected volatilities are based on the historical volatility of the ordinary shares. Historical data is also used to estimate the probability of option exercise and potential forfeitures. The following table summarises the key assumptions used to calculate the fair market value of options granted during the period:

During the half year ended 31 December 2011, the Board of Directors awarded 910,000 restricted share units (RSUs) to certain employees. These awards were made in accordance with the long term

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2011 AND THE SIX-MONTH PERIOD THEN ENDED (Continued)

equity component of the Company's incentive compensation plan, the details of which are described in more detail in the Company's 30 June 2011 Annual Report. Share based payment expense for RSUs awarded was calculated pursuant to IFRS 2: Share Based Payments. The fair value of RSUs was estimated at the date they were approved by the Board of Directors (the measurement date). These awards will be issued to employees upon finalisation of the associated plan documents.

	Rocky Mountains USA						Other States USA						Total

	2011 US$000			2010 US$000			2011 US$000			2010 US$000			2011 US$000			2010 US$000
Segment Revenue		11,596			17,345			142			5			11,739			6,989

Total revenue														11,739			6,989
Expenses
Operating expenses		(2,775	)		(1,111	)		(9	)		(1	)		(2,784	)		(1,112	)
Depreciation and depletion		(4,324	)		(1,912	)		(34	)		(41	)		(4,358	)		(1,952	)
Net impairment on oil and gas assets		—			—			(357	)		(1,239	)		(357	)		(1,239	)

Segment results before income tax		4,497			3,960			(258	)		(1,276	)		4,240			2,686

Reconciliation:
Unallocated income and expenses
Parent company other revenue														4			48
Gain/(loss) on sale of assets														459			10,384
Exploration and evaluation expensed														(45	)		—
Interest and currency income														240			44
Derivatives														188			(976	)
Corporate unallocated costs														(3,276	)		(2,951	)

Net income/(loss) before tax														1,810			9,235
Income tax expense														(659	)		(4,014	)

Net income/(loss) for period														1,151			5,221

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2011 AND THE SIX-MONTH PERIOD THEN ENDED (Continued)

There were no contingent liabilities at 31 December 2011 and there has been no material change to commitments since the last annual reporting date.

On 27 February 2011, the Company announced the sale of its Arriba Prospect in the southern Denver-Julesburg Basin for US$4.2M, or US$90 per acre. As announced, this divestiture is part of the Company's continuing strategy of redeploying capital from non-core assets to more prospective liquids rich resource plays.

Subsequent to December 31, 2011, the Company decided to pursue divestiture of its Goliath prospect assets. This decision is consistent with the Company's previously disclosed business strategy of focusing on higher working interest, operated projects. The assets being disposed of are included in the Company's "Rocky Mountain USA" segment.

There have been no other material events subsequent to the half-year ended 31 December 2011.

We have audited the accompanying consolidated statements of financial position of Sundance Energy Australia Limited and subsidiaries (the "Company") as of June 30, 2012 and 2011, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity, and cash flows for each of the two years in the period ended June 30, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sundance Energy Australia Limited and subsidiaries as of June 30, 2012 and 2011, and the results of their operations and their cash flows for each of the two years in the period ended June 30, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME
FOR THE YEARS ENDED JUNE 30, 2012 AND 2011

		Consolidated Group

	Note	2012 US$'000			2011 US$'000
Oil and gas sales revenue		$	29,787		$	18,176
Cost of sales	2		(6,355	)		(2,858	)
Depreciation and amortisation expense			(11,111	)		(6,509	)
Employee benefits expense			(4,318	)		(3,562	)
Administrative expense	3		(2,545	)		(1,776	)
Interest received			263			312
Finance costs			(152	)		—
Impairment of non-current assets			(357	)		(1,273	)
Net profit on sale of non-current assets			3,004			10,926
Net profit on sale of assets held for resale			—			14
Gain/ (loss) on commodity hedging
Realized (loss)			(297	)		(643	)
Unrealized gain / (loss)			2,242			(464	)
Realised currency (loss)			(4	)		(559	)

Profit before income tax			10,157			11,784
Income tax expense	4		(4,145	)		(4,755	)

Profit attributable to owners of the Company			6,012			7,029
Other comprehensive income
Exchange differences arising on translation of foreign operations			(247	)		384

Total comprehensive income attributable to owners of the Company		$	5,765		$	7,413

Earnings per share
Basic earnings	7	$	0.02		$	0.03
Diluted earnings	7	$	0.02		$	0.03

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

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT JUNE 30, 2012

			Consolidated Group

	Note		2012 US$'000			2011 US$'000
CURRENT ASSETS
Cash and cash equivalents		8	$	15,328		$	25,244
Trade and other receivables		9		12,352			3,538
Inventory current		10		46			10
Derivative financial instruments		11		1,331			—
Other current assets		12		1,634			2,381

TOTAL CURRENT ASSETS				30,691			31,173

NON-CURRENT ASSETS
Inventory		10		21			21
Plant and equipment		14		418			210
Exploration and evaluation expenditure		15		11,436			6,626
Development and production assets		16		87,274			45,873
Derivative financial instruments		11		476			50
Other non-current assets				345			127

TOTAL NON-CURRENT ASSETS				99,970			52,907

TOTAL ASSETS			$	130,661		$	84,080

CURRENT LIABILITIES
Trade and other payables				22,056			3,793
Accrued expenses				8,337			5,881
Derivative liabilities		11		—			486

TOTAL CURRENT LIABILITIES				30,393			10,160

NON-CURRENT LIABILITIES
Revolving credit facility		17		15,000			—
Restoration provision				588			349
Deferred tax liabilities		18		10,476			6,104

TOTAL NON-CURRENT LIABILITIES				26,064			6,453

TOTAL LIABILITIES			$	56,457		$	16,613

NET ASSETS			$	74,204		$	67,467

EQUITY
Issued capital		19	$	57,978		$	57,831
Share option reserve		20		3,205			2,380
Foreign currency translation		20		(941	)		(694	)
Retained earnings				13,962			7,950

TOTAL EQUITY			$	74,204		$	67,467

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

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEARS ENDED JUNE 30, 2012 AND 2011

Consolidated Group	Issued Capital US$'000			Retained Earnings US$'000		Foreign Currency Translation Reserve US$'000			Share Option Reserve US$'000		Total US$'000

Balance at 30 June 2010	$	38,962		$	921	$	(1,078	)	$	1,165	$	39,970
Shares issued during the year		19,893			—		—			—		19,893
Cost of capital raising (net of tax)		(1,024	)		—		—			—		(1,024	)
Fair value of options issued		—			—		—			1,215		1,215
Total comprehensive income for the year		—			7,029		384			—		7,413

Balance at 30 June 2011		57,831			7,950		(694	)		2,380		67,467
Shares issued during the year		147			—		—			—		147
Fair value of options issued		—			—		—			825		825
Total comprehensive income for the year		—			6,012		(247	)		—		5,765

Balance at 30 June 2012	$	57,978		$	13,962	$	(941	)	$	3,205	$	74,204

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

SUNDANCE ENERGY AUSTRALIA LIMITED
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED JUNE 30, 2012 AND 2011

		Consolidated Group

	Note	2012 US$'000			2011 US$'000
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from sales		$	20,987		$	15,362
Payments to suppliers and employees			(8,900	)		(7,390	)
Interest received			263			312
Derivative payments			(297	)		(642	)
Income taxes (paid)/refunded			(221	)		1,266

NET CASH PROVIDED BY OPERATING ACTIVITIES	24		11,832			8,908

CASH FLOWS FROM INVESTING ACTIVITIES
Payments for exploration expenditure			(5,685	)		(1,362	)
Payments for development expenditure			(34,833	)		(22,889	)
Sale of assets held for resale			—			345
Sale of non-current assets			4,679			10,647
Payments for plant and equipment			(310	)		(206	)

NET CASH (USED IN) INVESTING ACTIVITIES			(36,149	)		(13,465	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issue of shares			147			19,893
Payments for the costs of capital raisings			—			(1,024	)
Borrowing costs			(408	)		—
Proceeds from borrowings			15,000			—
Realised currency (loss)			(5	)		—

NET CASH PROVIDED BY FINANCING ACTIVITIES			14,734			18,869

Net (decrease)/increase in cash held			(9,583	)		14,312
Cash at beginning of year			25,244			9,685
Effect of exchange rates on cash			(333	)		1,247

CASH AT END OF YEAR	8	$	15,328		$	25,244

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

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED

The financial report includes the consolidated financial statements and notes of Sundance Energy Australia Limited and controlled entities ('Company,' 'Consolidated Group' or 'Group').

Australian Accounting Standards set out accounting policies that the AASB has concluded would result in a financial report containing relevant and reliable information about transactions, events and conditions to which they apply. Compliance with Australian Accounting Standards ensures that the financial statements and notes also comply with International Financial Reporting Standards, 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.

In the current year, the group has adopted all of the new and revised Standards and Interpretations issued by the International Accounting Standards Board and the Australian Accounting Standards Board that are relevant to its operations and effective for the current annual reporting period.

The adoption of these standards did not have any effect on the financial position or performance of the group although it has enabled the removal of certain disclosures in relation to the franking of dividends and commitments.

Following a period of sustained international growth, the Group's cash flows and economic returns are now principally denominated in US Dollars. From 1 July 2011, Sundance Energy Australia Ltd changed the currency in which it presents its consolidated and parent Company Financial Statements from Australian Dollars to US Dollars. This change has no impact on the net income of the Consolidated Entity other than presentation in US Dollars instead of Australian Dollars.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The exchange rates of US Dollar to Australian Dollars over the periods included in this report and Accounts are as follows:

The financial report has been prepared on an accruals basis and is based on historical costs modified, where applicable, by the measurement at fair value of selected non-current assets, financial assets and financial liabilities.

A controlled entity is any entity over which Sundance Energy Australia Limited has the power to govern the financial and operating policies so as to obtain benefits from its activities. In assessing the power to govern, the existence and effect of holdings of actual and potential voting rights are considered.

A list of controlled entities is contained in Note 13 to the financial statements.

As at reporting date, the assets and liabilities of all controlled entities have been incorporated into the consolidated financial statements as well as their results for the year then ended. Where controlled entities have entered/(left) the Group during the year, their operating results have been included/(excluded) from the date control was obtained/(ceased).

All inter-group balances and transactions between entities in the Group, including any recognised profits or losses, have been eliminated on consolidation. Accounting policies of subsidiaries have been changed, where necessary, to ensure consistency with those adopted by the parent entity.

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

Current income tax expense charged to the profit or loss is the tax payable on taxable income calculated using applicable income tax rates enacted, or substantially enacted, as at 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 year as well as unused tax losses. Current and deferred income tax expense/(income) is charged or credited directly to equity instead of the profit or loss when the tax relates to items that are credited or charged directly to equity.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

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 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.

Development assets and plant and equipment are carried at cost less where applicable, any accumulated depreciation, amortisation and impairment losses.

The carrying amount of development assets and plant and equipment are reviewed semi-annually by directors to ensure that they are not in excess of the recoverable amount from these assets. The recoverable amount is assessed on the basis of the expected net cash flows that will be received from the assets employment and subsequent disposal. The expected net cash flows have been discounted to their present values in determining recoverable amounts.

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 statement of comprehensive income during the financial period in which are they are incurred.

The depreciable amount of all fixed assets are depreciated on a straight-line basis over their useful lives to the Group commencing from the time the asset is held ready for use. Leasehold improvements are depreciated over the shorter of either the unexpired period of the lease or the estimated useful lives of the improvements.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The Group uses the units of production method to amortise costs carried forward in relation to its development assets. For this approach, the calculation is based upon proved developed reserves.

The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each statement of financial position date. 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.

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

Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made.

A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest.

Lease incentives under operating leases are recognised as a liability and amortised on a straight-line basis over the life of the lease term.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified as at fair value through profit or loss. Transactions costs related to instruments classified as at fair value through profit or loss are expensed to profit or loss immediately. Financial instruments are classified and measured as set out below.

The Group uses derivative financial instruments to hedge its exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity crude oil price swap and option contracts. Their use is subject to policies and procedures as approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. Derivative financial instruments are initially recognised at cost. Subsequent to initial recognition, derivate financial instruments are recognised 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 recognised through the statement of comprehensive income.

Financial assets are derecognised where the contractual rights 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 where 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.

Financial assets are classified at fair value through profit or loss when they are held for trading for the purpose of short term profit taking, where they are derivatives not held for hedging purposes, or designated as such to avoid an accounting mismatch or to enable performance evaluation where a group of financial assets is managed by key management personnel on a fair value basis in accordance with a documented risk management or investment strategy. Realised and unrealised gains and losses arising from changes in fair value are included in profit or loss in the period in which they arise.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

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

Impairment testing is performed annually for intangible assets with indefinite lives.

Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

The Group's share of assets, liabilities, revenue and expenses of joint ventures are included in the appropriate items of the consolidated financial statements. Details of the Group's interest are shown in Note 26.

Foreign currency transactions are translated into 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 monetary items are recognised in the statement of comprehensive income except where deferred in equity as a qualifying cash flow or net investment hedge.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

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

Exchange differences arising on translation of foreign operations are transferred directly to the group's foreign currency translation reserve in the statement of comprehensive income. These differences are recognised in the statement of comprehensive income in the period in which the operation is disposed.

The Group has an employee share option plan. The bonus element over the exercise price of the employees services rendered in exchange for the grant of shares and options is recognised as an expense in the statement of comprehensive income. The total amount to be expensed over the vesting period is determined by reference to the fair value of the shares of the option granted.

The group has a restricted share unit plan (RSU) to motivate management and senior employees to make decisions benefiting long-term value creation, retain management and senior employees and reward the achievement of the Group's long-term goals. The RSUs are based on targets established and approved by the Board. Actual RSUs, awarded annually, are modified according to actual results and vest in four equal tranches beginning on the grant date.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

Cash and cash equivalents include cash on hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts are shown within short-term borrowings in current liabilities on the Statement of Financial Position.

Revenue from the sale of goods is recognised upon the delivery of goods to customers. Interest revenue is recognised on a proportional basis taking into account the interest rates applicable to the financial assets.

Revenue from the rendering of a service is recognised upon the delivery of the service to the customers. All revenue is stated net of the amount of goods and services tax (GST).

Borrowing costs directly attributable to the acquisition, construction or production of assets that necessarily take a substantial period of time to prepare for their intended use or sale are added to the cost of those assets until such time as the assets are substantially ready for their intended use or sale. Borrowings are recognised initially at fair value, net of transaction costs incurred. Subsequent to initial recognition, borrowings are stated as amortised cost with any difference between cost and redemption being recognised in the statement of comprehensive income over the period of the borrowings on an effective interest basis.

All other borrowing costs are recognised in income in the period in which they are incurred.

Cash flows are presented in the statement of cash flows on a gross basis, except for the GST component of investing and financing activities, which are disclosed as operating cash flows.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

the reserves. Management prepares reserve estimates which conform to guidelines prepared by the Society of Petroleum Engineers. 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.

The Group assesses impairment at each reporting date by evaluating conditions specific to the group that may lead to impairment of assets. Where an impairment trigger exists, the recoverable amount of the asset is determined. Value-in-use calculations performed in assessing recoverable amounts incorporate a number of key estimates.

The Group's policy for exploration and evaluation is discussed in Note 1 (d). The application of this policy requires the directors to make certain estimates and assumptions as to future events and circumstances. Any such estimates and assumptions may change as new information becomes available. If, after having capitalised exploration and evaluation expenditure, the directors conclude 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 statement of comprehensive income.

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/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 life of the assets and the provision revised at each balance date through the statement of comprehensive income as the discounting of the liability unwinds.

At the date of this report the Carbon Tax legislation has passed through parliament, and the commencement date for the scheme is 1 July 2012. As the Group will not fall within the 'Top 500 Australian Polluters,' the impact of the Carbon Scheme will be through indirect effects of increased prices on many production inputs and general business expenses as suppliers subject to the carbon pricing mechanism are likely to pass on their carbon price burden to their customers in the form of increased prices. Directors expect that this will not have a significant impact upon the operating costs within the business, and therefore will not have an impact upon the valuation of assets and/or going concern of the business.

The same accounting policies and methods of computation have been followed in this financial report as were applied in the 2011 annual financial statements.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

Certain reclassifications have been made to the prior year financial statements and associated notes to the financial statements to conform to the current year presentation.

The financial information for the parent entity, Sundance Energy Australia Limited, discussed in Note 30, has been prepared on the same basis, using the same accounting policies as the consolidated financial statements.

During the current year the Group adopted all of the new and revised International Accounting Standards and Australia Accounting Standards and Interpretations applicable to its operations which became mandatory.

A package of consolidation standards are effective for annual periods beginning or after 1 January 2013. Information on these new standards is presented below. The Group's management have yet to assess the impact of these new and revised standards on the Group's consolidated financial statements.

IFRS 10 supersedes the consolidation requirements in IAS 27 Consolidated and Separate Financial Statements (IAS 27) and Interpretation 112 Consolidation — Special Purpose Entities. It revised the definition of control together with accompanying guidance to identify an interest in a subsidiary. However, the requirements and mechanics of consolidation and the accounting for any non-controlling interests and changes in control remain the same.

IFRS 11 supersedes IAS 31 Interests in Joint Ventures (IAS 31). It aligns more closely the accounting by the investors with their rights and obligations relating to the joint arrangement. It

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

introduces two accounting categories (joint operations and joint ventures) whose applicability is determined based on the substance of the joint arrangement. In addition, IAS 31's option of using proportionate consolidation for joint ventures has been eliminated. IFRS 11 now requires the use of the equity accounting method for joint ventures, which is currently used for investments in associates.

IFRS 12 integrates and makes consistent the disclosure requirements for various types of investments, including unconsolidated structured entities. It introduces new disclosure requirements about the risks to which an entity is exposed from its involvement with structured entities.

Consequential amendments to IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures

IAS 27 Consolidated and Separate Financial Statements was amended to IAS 27 Separate Financial Statements which now deals only with separate financial statements. IAS 28 brings investments in joint ventures into its scope. However, IAS 28's equity accounting methodology remains unchanged.

IFRS 13 does not affect which items are required to be fair-valued, but clarifies the definition of fair value and provides related guidance and enhanced disclosures about fair value measurements. It is applicable for annual periods beginning on or after 1 January 2013. The Group's management have yet to assess the impact of this new standard.

AASB 2011-9 Amendments to Australian Accounting Standards Presentation of Items of Other Comprehensive Income s (IAS 1 Amendments)

The IAS 1 Amendments require an entity to group items presented in other comprehensive income into those that, in accordance with other IFRSs: (a) will not be reclassified subsequently to profit or loss and (b) will be reclassified subsequently to profit or loss when specific conditions are met. It is applicable for annual periods beginning on or after 1 July 2012. The Group's management expects this will change the current presentation of items in other comprehensive income; however, it will not affect the measurement or recognition of such items.

AASB 2011-4 Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure Requirements (IAS 24 Amendments)

AASB 2011-4 makes amendments to IAS 24 Related Party Disclosures to remove individual key management personnel disclosure requirements, to achieve consistency with the international equivalent (which includes requirements to disclose aggregate (rather than individual) amounts of KMP compensation), and remove duplication with the Corporations Act 2011. The amendments are applicable for annual periods beginning on or after 1 July 2013. The Group's management have yet to assess the impact of these amendments.

The financial report was authorised for issue on 28 September 2012, by the Board of Directors.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

		Consolidated Group

		2012 US$'000			2011 US$'000
d)	The components of income tax expense comprise:
	Current tax benefit/(expense)	$	242		$	(117	)
	Deferred tax expense		(4,387	)		(4,638	)

		$	(4,145	)	$	(4,755	)

e)	The prima facie tax on income from ordinary activities before income tax is reconciled to the income tax as follows:
	Net profit	$	10,157		$	11,784

	Prima facie tax expense on income from ordinary activities before income tax at 30%	$	3,047		$	3,535
	Add:
	Tax effect of:
	— difference of tax rate in US controlled entities		862			752
	— employee options		276			349
	— other allowable items		4			—
	— previously unrecognised tax gains used to (reduce)/increase current tax expense		(139	)		—
	— previously unrecognised tax losses used to (reduce)/increase current tax expense		—			55
	— Deferred tax assets associated with capital raising costs recognised direct to equity but not meeting the recognition criteria		95			64

	Income tax attributable to entity	$	4,145		$	4,755

f)	Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30%	$	375		$	526

e) Names and positions held of Consolidated Group key management personnel in office at any time during the financial year are:


Mr M Hannell		Chairman Non-executive
Mr E McCrady		Chief Executive Officer & Managing Director
Ms C Anderson		Chief Financial Officer
Mr P Franks		Director — Executive (resigned as a Director on 29 November 2011)
Mr A Hunter III		Director — Executive (resigned as a Director on 13 July 2012)
Mr D Hannes		Director — Non-executive
Mr R Nelson		Director — Non-executive (resigned as a Director 1 March 2012)
Mr N Martin		Director — Non-executive (appointed as Director, previously an alternate, on 1 March 2012)
Mr C Gooden		Company Secretary

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

Other than employees of the Company listed above, there are no additional key management personnel.

Refer to the Remuneration Report contained in the Report of Directors' for details of the remuneration paid or payable to each member of the Group's key management personnel (KMP) for the year ended 30 June 2012.

The total of remuneration paid to KMP of the Group during the year is as follows:

Options granted as compensation were 1,000,000 ($207,700 fair value) and 5,000,000 ($1,704,430 fair value) during the fiscal years 2012 and 2011, respectively, to KMP from the Sundance Energy Employee Stock Option Plan.

Key Management Personnel

Mr A Hunter III*	1,166,666	—	—		—	1,166,666	777,778	777,778	388,888
Mr J McCoy**	388,889	—	(388,889	)	—	—	—	—	—
Mr P Franks	1,166,667	—	—		—	1,166,667	777,778	777,778	388,889
Mr E McCrady	1,500,000	—	—		—	1,500,000	666,000	666,000	834,000
Ms C Anderson	—	1,000,000	—		—	1,000,000	200,000	200,000	800,000
Mr C Gooden	—	—	—		—	—	—	—	—

Total	4,222,222	1,000,000	(388,889	)	—	4,833,333	2,421,556	2,421,556	2,411,777

Key Management Personnel

Mr A Hunter III*	3,300,000	1,166,666	(3,300,000	)	—		1,166,666	388,889	388,889	777,777
Mr J McCoy**	—	1,166,667	—		(777,778	)	388,889	388,889	388,889	—
Mr P Franks	—	1,166,667	—		—		1,166,667	388,889	388,889	777,778
Mr E McCrady	—	1,500,000	—		—		1,500,000	333,333	333,333	1,166,667
Mr C Gooden	200,000	—	(200,000	)	—		—	—	—	—

Total	3,500,000	5,000,000	(3,500,000	)	(777,778	)	4,222,222	1,500,000	1,500,000	2,722,222

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

Key Management Personnel

Mr P Franks	5,845,193	—	—	—		5,845,193
Mr A Hunter III*	3,037,143	—	—	—		3,037,143
Mr D Hannes	5,160,000	—	—	421,561		5,581,561
Mr R Nelson	267,149	—	—	(267,149	)	—
Mr M Hannell	860,398	—	—	12,500		872,898
Mr N Martin***	22,858	—	—	115,000		137,858
Mr C Gooden	143,970	—	—	—		143,970
Ms C Anderson	—	—	—	—		—
Mr E McCrady	—	—	—	165,000		165,000

Total	15,336,711	—	—	446,912		15,783,623

Key Management Personnel

Mr J McCoy**	8,950,498	—	—	(8,950,498	)	—
Mr P Franks	9,345,193	—	—	(3,500,000	)	5,845,193
Mr A Hunter III*	3,037,143	—	3,300,000	(3,300,000	)	3,037,143
Mr D Hannes	5,301,128	—	—	(141,128	)	5,160,000
Mr R Nelson	267,149	—	—	—		267,149
Mr M Hannell	835,398	—	—	25,000		860,398
Mr N Martin***	—	—	—	22,858		22,858
Mr C Gooden	458,969	—	200,000	(514,999	)	143,970
Mr E McCrady	—	—	—	—		—

Total	28,195,478	—	3,500,000	(16,358,767	)	15,336,711

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The effective interest rate on short term bank deposits was 1.5% for the Group. 94% of deposits are at 24 hours call and the balance of deposits has an average maturity of 49 days (2011: 69% of deposits had an average maturity of 102 days). The Groups' exposure to interest rate risk is summarised at Note 29.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

At 30 June 2012 and 2011, the Group did not have any additional receivables which were outside normal trading terms (past due but not impaired). Due to the short term nature of these receivables, their carrying amounts are assumed to approximate their fair value.

	Consolidated Group

	2012 US$'000		2011 US$'000
Financial assets comprise:
CURRENT
Derivative financial instruments — commodity contracts	$	1,331	$	—
NON-CURRENT
Derivative financial instruments — commodity contracts		476		50

Total financial assets	$	1,807	$	50

Financial liabilities comprise:
CURRENT
Derivative financial instruments — commodity contracts	$	—	$	(486	)
NON-CURRENT
Derivative financial instruments — commodity contracts		—		—

Total financial liabilities	$	—	$	(486	)

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

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:

The methods and valuation techniques used for the purpose of measuring fair value are unchanged compared to the previous reporting period.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

	Consolidated Group

	2012 US$'000			2011 US$'000
Costs carried forward in respect of areas of interest in:
Exploration and evaluation phase at cost	$	13,050		$	9,442
Provision for impairment		(1,614	)		(2,816	)

Total Exploration and Evaluation Expenditure	$	11,436		$	6,626

b) Movements in carrying amounts:
Exploration and evaluation
Balance at the beginning of the year	$	6,626		$	7,722
Amounts capitalised during the year		8,670			1,293
Impairment of exploration and expenditure		(357	)		(1,273	)
Amount transferred to development phase		(2,277	)		(621	)
Exploration tenements sold during the year		(1,226	)		(495	)

Balance at end of year	$	11,436		$	6,626

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

	Consolidated Group

	2012 US$'000			2011 US$'000
Costs carried forward in respect of areas of interest in:
Development and production phase at cost	$	113,830		$	63,048
Accumulated amortisation		(24,241	)		(13,779	)
Provision for impairment		(2,315	)		(3,396	)

Total Development and Production Expenditure	$	87,274		$	45,873

b) Movements in carrying amounts:
Development expenditure
Balance at the beginning of the year	$	45,873		$	45,754
Amount transferred from exploration phase		2,277			621
Amounts capitalised during the year		50,520			5,954
Amortisation expense		(10,971	)		(6,456	)
Development assets sold during the year		(425	)		—

Balance at end of year	$	87,274		$	45,873

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

On 21 July 2011, Sundance Energy, Inc., a wholly owned subsidiary of the Company, entered into a credit agreement with the Bank of Oklahoma (the "Credit Facility"), pursuant to which up to $100M is available on a revolving basis. The borrowing base under the Credit Facility is determined by reference to the value of the Company's proved developed reserves. The agreement specifies a semi-annual borrowing base redetermination and the Company can request two additional redeterminations each year. The borrowing base, originally set at $10M, had been increased to $25M as at 30 June 2012. Interest on borrowed funds accrues, at the Company's option, of i) LIBOR plus a margin that ranges from 225 to 300 basis points or ii) the Base Rate, defined as a rate equal to the highest of (a) the Federal Funds Rate plus ¹/2 of 1%, (b) the Prime Rate, or (c) LIBOR plus a margin that ranges from 100 to 175 basis points. The applicable margin varies depending on the amount drawn. The Company also pays a commitment fee of 50 basis points on the undrawn balance of the borrowing base. The agreement has a four year term and contains both negative and affirmative covenants, including minimum current ratio and maximum leverage ratio requirements. Certain development and production assets are pledged as collateral and the facility is guaranteed by the Parent Company.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

As at 30 June 2012, all of the Company's exploration and evaluation and development and production assets are located in the United States of America.

The mineral leases in the exploration prospects in the USA have primary terms ranging from three years to ten years and 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.

	Consolidated Group

	2012 US$'000		2011 US$'000
Operating lease commitments
Commitments for minimum lease payments in relation to non-cancellable operating leases not provided for in the financial statements.
Lease expenditure commitments
— due within one year	$	202	$	172
— due within 1 - 5 years		162		89

	$	364	$	261

Employment and consultant commitments
Commitments for the payment of salaries and other remuneration under long-term employment and consultant contracts not provided for in the financial statements.
Expenditure commitments
— due within one year	$	180	$	270
— due within 1 - 5 years		270		450

	$	450	$	720

Details relating to the employment contracts are set out in the remuneration report.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

At the date of signing this report, the Group is not aware of any contingent assets or liabilities that should be disclosed in accordance with IAS 37.

The CEO reviews internal management reports on a monthly basis that are consistent with the information provided in the statement of comprehensive income, statement of financial position and statement of cash flows. As a result no reconciliation is required, because the information as presented is used by the CEO to make strategic decisions.

		Consolidated Group

		2012 US$'000			2011 US$'000
d)	Reconciliation of cash flows from operations with income from ordinary activities after income tax
	Profit from ordinary activities after income tax	$	6,012		$	7,029
	Non cash flow in operating loss
	Depreciation and exploration expenditure written off		11,468			7,782
	Deferred tax asset written off		—			321
	Share options expensed		930			1,161
	Unrealised gains on derivatives		(2,242	)		(434	)
	Net gain on sale of properties		(3,004	)		(10,926	)
	Changes in assets and liabilities:
	— Increase in inventory		(36	)		(74	)
	— Increase in current and deferred tax		3,732			6,917
	— Decrease in other current assets		1,553			—
	— Increase in trade and other receivables		(8,814	)		(2,458	)
	— Increase in trade and other payables		2,233			(410	)

	Net cash provided by operating activities	$	11,832		$	8,908

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

During the year ended 30 June 2012, a total of 2,260,000 (2011: 6,350,000) options were granted to employees pursuant to employment agreements and a total of 388,889 previously issued options were exercised. This information is summarised below:

	Consolidated Group 2012					Consolidated Group 2011

	Number of Options			Weighted Average Exercise Price $		Number of Options			Weighted Average Exercise Price $
Outstanding at start of year		5,632,222			0.38		9,926,667			0.38
Granted		2,260,000			0.95		6,350,000			0.95
Forfeited		(60,000	)		0.50 - 0.70		(777,778	)		0.50 - 0.70
Exercised		(388,889	)		0.37		(4,500,000	)		0.37
Expired		—			—		(5,366,667	)		—

Outstanding at end of year		7,443,333			0.55		5,632,222			0.38

Exercisable at end of year		3,551,889			0.45		1,952,667			0.39

Share based payments expense related to options is determined pursuant to IFRS 2: Share Based Payments, and is recognised pursuant to the attached vesting conditions. The fair value of the options ranged from A$0.21 to A$0.46 and was calculated using a Black-Sholes options pricing model. Expected volatilities are based upon the historical volatility of the ordinary shares. Historical data is also used to estimate the probability of option exercise and potential forfeitures. The following table summarises the key assumptions used to calculate the fair market value of options granted during the period:

During the year ended 30 June 2012, the Board of Directors awarded 910,000 restricted share units (RSUs) to certain employees. These awards were made in accordance with the long term equity component of the Company's incentive compensation plan, the details of which are described in more detail in the remuneration section of the Directors' Report. Share based payment expense for RSUs awarded was calculated pursuant to IFRS 2: Share Based Payments. The fair value of RSUs was estimated at the date they were approved by the Board of Directors, 5 December 2011 (the measurement date). These awards have been approved but not yet issued. They will be issued to employees upon finalisation of the plan documents. The value of the vested portion of these has been recognised within the financial statements.

The Group had interests in joint venture operations of 23.34% in oil and gas exploration in the PEL 100 blocks in South Australia. In December 2011, the joint venture interests were sold for US$511,155. The net book value was nil, impaired in previous years.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The Group and its partners have accumulated acreage in a number of oil and gas prospects comprising mineral leases in the United States. The mineral leases that have producing wells drilled on them during the primary lease term will be held as producing leases. Mineral leases that are drilled and produce a dry hole, or not drilled at all, will expire at the end of the primary term unless re-leased for a further term. The exploration of the leases is managed by operators who make cash calls, hire contractors and pay all accounts. The contracted operations are not a joint venture, and therefore not presented above.

On 13 July 2012 Mr A Hunter III, Director — Executive, Legal Counsel / Director of Communications resigned from the Company. Mr A Hunter III has been retained on a consulting basis.

On 17 July 2012 the Company sold its oil and gas producing and non-producing assets in the Pawnee Prospect in the Kansas Uplift Basin for US$900,000.

On 23 August 2012 the Company executed a Purchase and Sale Agreement to divest of approximately 3,900 acres of oil and gas non-producing and producing assets in the South Antelope field for approximately US$172.4M. The effective date of the sale is 1 July 2012 and the transaction closed in late September 2012.

Transactions with related parties: Minter Ellison Lawyers were paid a total of US$124,007 and US$73,943 for legal services for the years ended 30 June 2012 and 2011, respectively. (N Martin was a partner and is now a consultant of Minter Ellison Lawyers and has been an alternate director since 18 May 2011 and a Director since 1 March 2012).

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The main risk the Group is exposed to through its financial instruments is interest rate risk. The interest rate risk is managed with a mixture of fixed and floating rate cash deposits. At 30 June 2012 approximately 6% of Group deposits are fixed. It is the policy of the Group to keep surplus cash in interest yielding deposits.

Contract Type	Counterparty	Basis	Quantity/mo	Strike Price	Term

Swap	Shell Trading US	NYMEX	2,000 BBL	$100.00	1-Jan-12 - 31-Dec-12
Collar	Shell Trading US	NYMEX	1,000 BBL	$100.00/$117.50	1-Jan-12 - 31-Dec-12
Collar	Shell Trading US	NYMEX	1,000 BBL	$90.00/$126.00	1-Jan-12 - 31-Dec-12
Swap	Shell Trading US	NYMEX	2,000 BBL	$99.00	1-Mar-12 - 31-Dec-13
Swap	Shell Trading US	NYMEX	3,000 BBL	$104.70	1-May-12 - 31-Dec-12
Collar	Shell Trading US	NYMEX	1,000 BBL	$90.00/$117.50	1-Jan-13 - 31-Dec-13
Collar	Shell Trading US	NYMEX	1,000 BBL	$95.00/$112.75	1-Jan-13 - 31-Dec-13
Swap	Shell Trading US	NYMEX	3,000 BBL	$102.95	1-Jan-13 - 31-Dec-13
Swap	Shell Trading US	NYMEX	10,000 MMBTU	$3.58	1-Jan-13 - 31-Dec-13

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

	Weighted Average Effective Interest Rate						Floating Interest Rate					Non Interest Bearing						Total

	2012 %			2011 %			2012 USD$			2011 USD$		2012 USD$			2011 USD$			2012 USD$			2011 USD$
Financial Assets
Cash at bank		0	%		0	%	$	14,353		$	85	$	—		$	—		$	14,353		$	85
Deposits		0.6	%		1.4	%		975			25,159								975			25,159
Receivables								—			—		12,352			3,538			12,352			3,538
Other current assets								—			—		1,634			2,381			1,634			2,381
Derivatives								—			—		1,807			50			1,807			50

Total Financial Assets							$	15,328		$	25,244	$	15,793		$	5,969		$	31,121		$	31,213

Financial Liabilities
Payables							$	—		$	—	$	(22,056	)	$	(3,793	)	$	(22,056	)	$	(3,793	)
Revolving Credit Facility		2.7	%		—			(15,000	)		—		—			—			(15,000	)		—
Other current liabilities								—			—		(8,337	)		(5,881	)		(8,337	)		(5,881	)
Derivatives								—			—		—			(486	)		—			(486	)

Total Financial liabilities								(15,000	)		—		(30,393	)		(10,160	)		(45,393	)		(10,160	)

Total Net Financial Assets/(Liabilities)							$	328		$	25,244	$	(14,600	)	$	(4,191	)	$	(14,272	)	$	21,053

The Group has performed a sensitivity analysis relating to its exposure to interest rate risk at balance date. This sensitivity analysis demonstrates the effect on the current year results and equity which could result from a change in these risks. It should be noted that the Company did not have borrowings at 30 June 2011 and any impacts would be in relation to deposit yields on cash investments. The balance of debt at 30 June 2012 was $15,000,000 and is included in the 2012 Interest Rate Sensitivity Analysis below.

The effect on income and equity as a result of changes in the interest rate, with all other variables remaining constant would be as follows:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The effect on profit and equity as a result of changes in oil prices with all variables remaining constant would be as follows:

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

	Consolidated Group

	2012 US$'000		2011 US$'000
Parent Entity
Assets
Current assets	$	986	$	8,058
Investment in subsidiaries		57,643		50,255

Total assets	$	58,629	$	58,313

Liabilities
Current liabilities	$	109	$	127
Non-current liabilities		—		36

Total liabilities		109		163

Total net assets	$	58,520	$	58,150

Equity
Issued capital		57,978		57,831
Share options reserve		386		386
Retained earnings (loss)		156		(67	)

Total equity	$	58,520	$	58,150

Financial Performance
Profit/(loss) for the year	$	464	$	(145	)
Other comprehensive income		—		—

Total comprehensive income (loss)	$	464	$	(145	)

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

	Consolidated Group

	2012 US$'000			2011 US$'000
Parent Entity
Assets
Current assets	$	986		$	8,058
Investment in subsidiaries		73,327			59,572

Total assets	$	74,313		$	67,630

Liabilities
Current liabilities	$	109		$	127
Non-current liabilities		—			36

Total liabilities		109			163

Total net assets	$	74,204		$	67,467

Equity
Issued capital	$	57,978		$	57,831
Share options reserve		3,205			2,380
Foreign currency translation		(941	)		(694	)
Retained earnings (loss)		13,962			7,950

Total equity	$	74,204		$	67,467

Financial Performance
Profit/(loss) for the period before equity in income of subsidiaries	$	464		$	(145	)
Equity in income of subsidiaries		5,548			7,174
Other comprehensive income		(247	)		384

Total profit or loss and other comprehensive income	$	5,765		$	7,413

Sundance Energy Australia Limited has not entered into a deed of cross guarantee with its' wholly-owned subsidiary, Sundance Energy, Inc. related to the credit facility with Bank of Oklahoma.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

There are no contractual capital commitments for the acquisition of property, plant or equipment.

Costs Incurred — The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities:

Netherland, Sewell & Associates, Inc. ("NSAI"), an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interests owned by the Company as at June 30, 2012 and 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with NSAI and a Registered Professional Engineer in the State of Texas with over 30 years of experience in oil and gas reservoir studies and evaluations.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

The following reserve data represents estimates only and should not be construed as being exact.



Total proved reserves:
June 30, 2010	3,696		7,896		5,012
Revisions of previous estimates	(449	)	(2,329	)	(838	)
Extensions and discoveries	1,749		2,407		2,151
Production	(208	)	(282	)	(255	)

June 30, 2011	4,788		7,692		6,070
Revisions of previous estimates	220		170		248
Extensions and discoveries	3,309		5,560		4,236
Production	(338	)	(370	)	(399	)

June 30, 2012	7,979		13,052		10,155

Proved developed reserves:
June 30, 2010	758		1,846		1,065

June 30, 2011	1,497		2,637		1,936

June 30, 2012	2,564		4,905		3,382

Proved undeveloped reserves:
June 30, 2010	2,938		6,050		3,947

June 30, 2011	3,291		5,055		4,134

June 30, 2012	5,415		8,147		6,773

During the year ended June 30, 2011, we added 2,151 MBoe through extensions and discoveries. Of these additions, approximately 182 and 1,969 MBoe were attributable to our Wattenberg and Bakken assets, respectively. During the year ended June 30, 2012, we added 4,236 MBoe through extensions and discoveries. Of these additions, approximately 1,486 and 2,750 MBoe were attributable to our Wattenberg and Bakken assets, respectively.

SUNDANCE ENERGY AUSTRALIA LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR JUNE 30, 2012 AND 2011 AND THE YEARS THEN ENDED (Continued)

(in thousands)	Year ended June 30, 2012			Year ended June 30, 2011

Standardized Measure, beginning of period	$	59,444		$	38,419
Sales, net of production costs		(23,432	)		(15,318	)
Net change in sales prices, net of production costs		23,379			10,320
Extensions and discoveries, net of future production and development costs		63,264			30,512
Changes in future development costs		(13,921	)		(2,792	)
Previously estimated development costs incurred during the period		39,268			15,933
Revision of quantity estimates		5,645			(13,848	)
Accretion of discount		7,750			4,932
Change in income taxes		(19,081	)		(7,150	)
Change in production rates and other		(5,031	)		(1,564	)

Standardized Measure, end of period	$	137,285		$	59,444

The following average prices were used in determining the Standardized Measure as at:

We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures.

The Board of Directors
Armadillo Petroleum Limited (formerly Texon Petroleum Limited):

We have audited the accompanying consolidated financial statements of Armadillo Petroleum Limited (formerly Texon Petroleum Limited) and its subsidiaries, which comprise the consolidated statements of financial position as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for the years then ended, and the related notes 1 to 30 of the consolidated financial statements.

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Australian Accounting Standards; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. In note 1, management also states, in accordance with Australian Accounting Standard AASB 101 Presentation of Financial Statements, that the financial statements comply with International Financial Reporting Standards.

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Armadillo Petroleum Limited (formerly Texon Petroleum Limited) and its subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the years then ended in accordance with Australian Accounting Standards. The consolidated financial statements also comply with International Financial Reporting Standards as issued by the International Accounting Standards Board, as disclosed in note 1.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE YEAR ENDED DECEMBER 31, 2012

		Consolidated

	Note	Year ended 31 Dec 2012 A$			Year ended 31 Dec 2011 A$
Revenue	3		14,757,324			20,868,510
Cost of oil and gas sold			(13,332,191	)		(13,601,360	)

Gross profit			1,425,133			7,267,150
Other income	3		2,466,012			—
Employee benefits	4		(1,933,244	)		(2,294,499	)
Administrative and other expenses	4		(5,705,538	)		(2,191,007	)
Exploration and evaluation expenditure	15		(1,306,084	)		(1,084,486	)
Impairment expense	14		(556,299	)		—

Results from operating activities			(5,610,020	)		1,697,158

Finance income	5		203,590			634,149
Finance expense	5		(460,602	)		—

Net finance income / (expense)			(257,012	)		634,149

Profit / (loss) before tax			(5,867,032	)		2,331,307
Income tax (expense) / benefit	6		(2,376,239	)		(336,793	)

Profit / (loss) for the period			(8,243,271	)		1,994,514

Other comprehensive income
Foreign exchange translation differences, net of tax	5		(648,920	)		(298,513	)

Other comprehensive income for the period, net of tax			(648,920	)		(298,513	)

Total comprehensive income attributable to members of the Company			(8,892,191	)		1,696,001

			Cents			Cents
Basic (loss) / earnings per share	8		(3.37	)		0.88
Diluted (loss) / earnings per share	8		(3.37	)		0.88

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
AS AT DECEMBER 31, 2012

			Consolidated

	Note		2012 A$			2011 A$
Current assets
Cash and cash equivalents		9		30,358,291			13,365,634
Trade and other receivables		10		1,185,464			5,042,443
Prepayments		12		114,388			183,407
Assets held for sale		13		—			9,114,878

Total current assets				31,658,143			27,706,362

Non-current assets
Security deposits		11		100,962			53,178
Property, plant and equipment		14		66,471,841			42,498,126
Exploration and evaluation expenditure		15		15,370,553			10,983,859

Total non-current assets				81,943,356			53,535,163

TOTAL ASSETS				113,601,499			81,241,525

Current liabilities
Trade and other payables		16		11,332,721			2,756,765
Loans and borrowings		17		25,000,000			—
Current tax liabilities				282,439			—
Employee benefits				82,651			34,883

Total current liabilities				36,697,811			2,791,648

Non-current liabilities
Provisions		18		2,432,494			344,721
Deferred tax liabilities		19		2,391,665			321,434

Total non-current liabilities				4,824,159			666,155

TOTAL LIABILITIES				41,521,970			3,457,803

NET ASSETS				72,079,529			77,783,722

Equity
Issued capital				85,182,020			83,854,020
Reserves				(686,494	)		(1,897,572	)
Retained earnings / (accumulated losses)				(12,415,997	)		(4,172,726	)

TOTAL EQUITY				72,079,529			77,783,722

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED DECEMBER 31, 2012

Consolidated	Note

Balance at 1 January 2011		42,337,115		234,148	(3,938,009	)	(6,167,240	)	32,466,014

Total comprehensive income for the period
Profit for the period		—		—	—		1,994,514		1,994,514
Other comprehensive income
Foreign exchange translation differences		—		—	(298,513	)	—		(298,513	)

Total comprehensive income for the period		—		—	(298,513	)	1,994,514		1,696,001

Transactions with owners, recorded directly in equity Contributions by and distributions to owners
Shares Issued		43,350,280		—	—		—		43,350,280
Share-based payments	21	—		2,104,802	—		—		2,104,802
Share issue expenses		(1,833,375	)	—	—		—		(1,833,375	)

Balance at 31 December 2011		83,854,020		2,338,950	(4,236,522	)	(4,172,726	)	77,783,722

Balance at 1 January 2012		83,854,020		2,338,950	(4,236,522	)	(4,172,726	)	77,783,722

Total comprehensive income for the period
Loss for the period		—		—	—		(8,243,271	)	(8,243,271	)
Other comprehensive income
Foreign exchange translation differences		—		—	(648,920	)	—		(648,920	)

Total comprehensive (loss) / income for the period		—		—	(648,920	)	(8,243,271	)	(8,892,191	)

Transactions with owners, recorded directly in equity Contributions by and distributions to owners
Shares issued		1,328,000		—	—		—		1,328,000
Share-based payments	21	—		1,859,998	—		—		1,859,998

Balance at 31 December 2012		85,182,020		4,198,948	(4,885,442	)	(12,415,997	)	72,079,529

Amounts are stated net of tax.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2012

		Consolidated

	Note	Year ended 31 Dec 2012 A$			Year ended 31 Dec 2011 A$
Cash flows from operating activities
Cash receipts from customers			18,417,308			16,480,956
Cash paid to suppliers and employees			(10,748,234	)		(4,983,848	)
Interest received			210,098			228,110
Income taxes paid			(21,260	)		(18,157	)

Net cash from operating activities	27		7,857,912			11,707,061

Cash flows used in investing activities
Exploration, evaluation and development expenditure			(29,315,145	)		(53,425,181	)
Acquisition of property, plant and equipment			(24,359	)		(120,521	)
Proceeds from sale of oil and gas properties			12,160,945			—
Payments for security deposits			(48,400	)		—

Net cash used in investing activities			(17,226,959	)		(53,545,702	)

Cash flows from financing activities
Proceeds from borrowings			25,000,000			—
Proceeds from share issues			1,328,000			43,350,280
Share issue expenses			—			(1,833,375	)

Net cash from financing activities			26,328,000			41,516,905

Net increase/(decrease) in cash and cash equivalents			16,958,953			(321,736	)
Effect of exchange rate fluctuations on cash held			33,704			30,489
Cash and cash equivalents at 1 January			13,365,634			13,656,881

Cash and cash equivalents at 31 December	9		30,358,291			13,365,634

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED

Armadillo Petroleum Ltd (the "Company") is a company domiciled in Australia. The address of the Company's registered office is 32 Beulah Road, Norwood, SA 5067, Australia. The consolidated financial statements of the Company as at and for the year ended 31 December 2012 comprise the Company and its subsidiaries (together referred to as the "Group"). The Group is a for-profit entity.

The Company was incorporated on 17 May 2006. The Company changed its name from Texon Petroleum Ltd to Armadillo Petroleum Ltd on 4 April 2013.

The consolidated financial statements are general purpose financial statements which have been prepared in accordance with Australian Accounting Standards ("AASBs") adopted by the Australian Accounting Standards Board ("AASB"). These consolidated financial statements comply with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

The consolidated financial statements were authorised for issue by the directors on 18 October 2013.

The consolidated financial statements are prepared on the historical cost basis.

A number of new standards, amendments to standards and interpretations are effective for annual periods beginning after 1 January 2013, and have not been applied in preparing these consolidated financial statements. None of these is expected to have a significant effect on the consolidated financial statements of the Group, except for AASB 9 Financial Instruments (which becomes mandatory for the Group's 2015 consolidated financial statements), AASB 10 Consolidated Financial Statements, AASB 11 Joint Arrangements and AASB 12 Disclosures of Interests in Other Entities (which becomes mandatory for the Group's 2013 consolidated financial statements) and could change the classification and measurement of financial assets and disclosure of interests in joint ventures and other entities. The Group does not plan to adopt these standards early and the extent of the impact has not been determined.

The preparation of consolidated financial statements in conformity with Australian Accounting Standards requires management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets, liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis of making the judgements about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised and in any future periods affected.

In particular, information about significant areas of estimation uncertainty and critical judgements in applying accounting policies that have the most significant effect on the amount recognised in the financial statements are described in note 1(e) exploration and evaluation expenditure, 1(f) property,

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

plant and equipment, 1(j) impairment, note 1(l) employee benefits (share-based payment transactions) and 1(n) provisions.

The accounting policies set out below have been applied consistently to all periods presented in the consolidated financial statements. The accounting policies have been applied consistently by all entities in the Group.

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power, directly or indirectly, to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that presently are exercisable or convertible are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

Investments in subsidiaries are carried at their cost of acquisition in the Company's financial statements.

Joint ventures are those entities over whose activities the Group has joint control, established by contractual agreement.

The interest of the Group in unincorporated joint ventures and jointly controlled assets are brought to account by recognising in its financial statements the assets it controls, the liabilities that it incurs, the expenses it incurs and its share of income that it earns from the sale of goods or services by the joint venture.

Intragroup balances and any unrealised gains and losses or income and expenses arising from intragroup transactions are eliminated in preparing the consolidated financial statements.

Items included in the financial statements of each subsidiary within the Group are measured using the currency of the primary economic environment in which the entity operated (the "functional currency"). The consolidated financial statements are presented in Australian Dollars, the functional currency of Armadillo Petroleum Ltd.

Transactions in foreign currencies are translated to the respective functional currencies of the Group's subsidiaries at the foreign exchange rate ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies at the balance sheet date are translated to the functional currency at the foreign exchange rate ruling at that date. Foreign exchange differences arising

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

on translation are recognised in the statement of comprehensive income. Non-monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transaction. Non-monetary assets and liabilities denominated in foreign currencies that are stated at fair value are translated to the functional currency at foreign exchange rates ruling at the date the fair value was determined.

The assets and liabilities of foreign operations are translated to Australian dollars at foreign exchange rates ruling at the balance sheet date. The revenues and expenses of foreign operations are translated to Australian dollars at rates approximating the foreign exchange rates ruling at the dates of the transactions. Foreign currency differences are recognised directly in equity in the translation reserve. When a foreign operation is disposed of, the relevant amount in the translation reserve is transferred to profit or loss.

Exchange differences arising from the translation of the net investment in foreign operations are taken to the translation reserve. They are released into the statement of comprehensive income upon disposal.

Exploration and evaluation costs, including the costs of acquiring leases, are intangible assets capitalised as exploration and evaluation assets on an area of interest basis. Costs incurred before the Group has obtained the legal rights to explore an area are recognised in the statement of comprehensive income.

Exploration and evaluation assets are only recognised if the rights of the area of interest are current and either:

When an area of interest is abandoned or the directors decide that it is not commercial, any capitalised costs in respect of that area are written off in the financial period the decision is made.

Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units to which the exploration activity relates. The cash generating unit shall not be larger than the area of interest.

Once the technical feasibility and commercial viability of the extraction of oil and gas reserves relating to a prospect are demonstrable, exploration and evaluation assets attributable to that prospect are first tested for impairment and then reclassified from intangible assets to oil and gas properties within property, plant and equipment.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

Items of property, plant and equipment are measured at cost less accumulated depreciation and accumulated impairment losses. The cost of acquired assets includes (i) the initial estimate at the time of installation and during the period of use, when relevant, of the costs of dismantling and removing the items and restoring the site on which they are located, and (ii) changes in the measurement of existing liabilities recognised for these costs resulting from changes in the timing or outflow of resources required to settle the obligation. Where parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items of property, plant and equipment.

Oil and gas properties include construction, installation or completion of infrastructure facilities such as pipelines and platforms, capitalised borrowing costs, transferred exploration and evaluation costs, costs of direct labour, costs of dismantling and removing the items and restoration of the site on which they are located, the cost of development wells and any other costs directly attributable to bringing the asset to a working condition for its intended use.

The Group recognises in the carrying amount of an item of property, plant and equipment the cost of replacing part of such an item when that cost is incurred if it is probable that the future economic benefits embodied within the item will flow to the Group and the cost of the item can be measured reliably. The carrying amount of the replaced part is derecognised. The costs of day to day servicing of property, plant and equipment are recognised in the statement of comprehensive income as an expense as incurred.

Depreciation is charged to the statement of comprehensive income on a straight-line basis over the estimated useful lives of each part of an item of property, plant and equipment. Oil and gas properties are depreciated from the time production commences on a unit-of-production basis using estimated reserves that are forecast to be produced over the economic life of the property. Leasehold improvements are depreciated over the shorter of the useful life and the lease term. The residual value, the useful life and the depreciation method applied to an asset are reassessed at each balance sheet date.

Non-current assets, or disposal groups comprising assets and liabilities, that are expected to be recovered primarily through sale rather than through continuing use, are classified as held for sale. Immediately before classification as held for sale, the assets, or components of a disposal group, are remeasured in accordance with the Group's accounting policies. Thereafter generally the assets, or disposal group, are measured at the lower of their carrying amount and fair value less cost to sell. Any impairment loss on a disposal group first is allocated to goodwill, and then to remaining assets and liabilities on a pro rata basis, except that no loss is allocated to inventories, financial assets and deferred

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

tax assets which continue to be measured in accordance with the Group's accounting policies. Impairment losses on initial classification as held for sale and subsequent gains or losses on remeasurement are recognised in profit or loss. Gains are not recognised in excess of any cumulative impairment loss. Intangible assets and property, plant and equipment once classified as held for sale or distribution are not amortised or depreciated.

Trade and other receivables are measured at their amortised cost less impairment losses.

Cash and cash equivalents comprise cash balances and call deposits with an original maturity of three months or less.

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortised cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognised. For financial assets measured at amortised cost the reversal is recognised in profit or loss.

The carrying amounts of the Group's non-financial assets, other than deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists then the asset's recoverable amount is estimated. The Group performs an impairment test on capitalised exploration and evaluation costs if there is an impairment indicator such as:

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The recoverable amount of an asset or cash-generating unit is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the 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 asset. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the "cash-generating unit").

An impairment loss is recognised if the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. Impairment losses are recognised in profit or loss. Impairment losses recognised in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit (group of units) on a pro rata basis.

Impairment losses recognised in prior periods are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. 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 amortisation, if no impairment loss had been recognised.

Transaction costs of an equity transaction relating to the raising of new share capital are accounted for as a deduction from equity, net of any recoverable income tax benefit applicable.

Liabilities for employee benefits for wages, salaries and annual leave that are expected to be settled within 12 months of the reporting date represent present obligations resulting from employees' services provided to balance sheet date, calculated at undiscounted amounts based on remuneration wage and salary rates that the Group expects to pay as at balance sheet date, including related on-costs.

Obligations for contributions to defined contribution superannuation funds are recognised as an expense in the statement of comprehensive income as incurred.

The fair value of options granted is recognised as an expense with a corresponding increase in equity (share-based payment reserve). The fair value is measured at grant date and spread over the period during which the employees and vendors become unconditionally entitled to the options. The fair value of the options granted is measured using a valuation technique, taking into account the terms and conditions upon which the options were granted. The amount recognised as an expense is adjusted to reflect the actual number of share options that vest except where forfeiture is only due to market-related conditions.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

A provision is recognised if, as a result of a past event, the Group has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. If the effects of the time value of money are material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability.

The Group records the present value of the estimated cost of legal and constructive obligations to restore operating locations in the period in which the obligation arises. The nature of restoration activities includes the removal of facilities, abandonment of wells and restoration of affected areas.

Typically, the obligation arises when the asset is installed at the production location. When the liability is initially recorded, the estimated cost is capitalised by increasing the carrying amount of the related oil and gas properties. Over time, the liability is increased for the change in the present value based on a risk adjusted pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion charge within finance expense. The carrying amount capitalised in oil and gas properties is depreciated over the useful life of the related asset.

Costs incurred that relate to an existing condition caused by past operations, and do not have future economic benefit, are expensed.

Revenue from the sale of oil and gas is recognised when the significant risks and rewards of ownership have transferred to the buyer and can be measured reliably. Delivery of gas is by pipeline and sales contracts define the point of transfer in ownership.

Income from management services is recognised in the statement of comprehensive income in line with the management agreements and contracts.

The proceeds from the disposal of non-current assets are recognised at the date control of the asset passes to the buyer, usually when an unconditional contract of sale is signed. The gain or loss on disposal is calculated as the difference between the carrying amount of the asset at the time of disposal and the net proceeds on disposal (including incidental costs).

Net finance income/expense comprises interest receivable on funds invested and foreign exchange gains and losses. Interest income is recognised in the statement of comprehensive income as it accrues, using the effective interest method.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

Payments made under operating leases are recognised in the statement of comprehensive income on a straight-line basis over the term of the lease. Lease incentives received are recognised in the statement of comprehensive income as an integral part of the total lease expense and spread over the lease term.

Income tax expense comprises current and deferred tax. Income tax expense is recognised in the statement of comprehensive income except to the extent that it relates to items recognised directly in equity, in which case it is recognised in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantially enacted at the balance sheet date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognised using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognised for the following temporary differences: the initial recognition of goodwill, the initial recognition of assets or liabilities in a transaction that is not a business combination and that affect neither accounting nor taxable profit/loss, and differences relating to investments in subsidiaries to the extent that they will not reverse in the foreseeable future. Deferred tax is measured at the tax rates that are expected to be applied to the temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the balance sheet date.

A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset can be utilised. Deferred tax assets are reviewed at each balance sheet date and are reduced to the extent that it is no longer probable that the related tax benefit will be realised.

Additional income taxes that arise from the distribution of dividends are recognised at the same time as the liability to pay the related dividend is recognised.

The Group determines operating segments based on the information that internally is provided to the CEO, who is the Group's chief operating decision maker.

The Group operates within one business segment (the petroleum exploration and production industry) and one geographical segment (the United States of America).

An operating segment is a component of the Group that engages in business activities from which it may earn revenues and incur expenses, including revenues and expenses that relate to transactions with any of the Group's other components.

The geographical locations of the Group's non-current assets are USA $81,936,574 and Australia $6,782 (2011: USA $53,525,046 and Australia $10,117).

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

Revenues, expenses and assets are recognised net of the amount of goods and services tax (GST), except where the amount of GST incurred is not recoverable from the taxation authority. In these circumstances, the GST is recognised as part of the cost of acquisition of the asset or as part of the expense.

Receivables and payables are stated with the amount of GST included. The net amount of GST recoverable from, or payable to, the Australian Taxation Office (ATO) is included as a current asset or liability in the balance sheet.

Cash flows are included in the statement of cash flows on a gross basis. The GST components of cash flows arising from investing and financing activities which are recoverable from, or payable to, the ATO are classified as operating cash flows.

The Group has exposure to the following risks from its use of financial instruments:

This note presents information about the Group's exposure to each of the above risks, its objectives, policies and processes for measuring and managing risk, and the management of capital. Further quantitative disclosures are included throughout these consolidated financial statements.

The board of directors has overall responsibility for the establishment and oversight of the risk management framework. The board oversees the establishment, implementation and regular review of the Group's risk management system and to this end has adopted risk management policies to protect the assets and undertakings of the Group.

Risk management policies are established to identify and analyse the risks faced by the Group, to set appropriate controls, and to monitor risks and adherence to controls. Risk management policies and systems are reviewed regularly to reflect changes in market conditions and the Group's activities.

The board oversees how management monitors compliance with the Group's risk management policies and procedures and reviews the adequacy of the risk management framework in relation to the risks faced by the Group.

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, as far as possible, that it will always have sufficient cash or liquid assets to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Group's reputation. The Group monitors its cash holdings on a regular basis in relation to actual cash flows, financial obligations and planned activities in order to manage liquidity risk.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates, interest rates and equity prices will affect the Group's income or the value of its holdings of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimising the return.

The Group is exposed to commodity price risk as oil and gas prices fluctuate depending on market conditions. The Group does not presently enter into hedging arrangements to hedge this risk, taking into account the Group's size, current stage of development, financial position and the board's approach to risk management.

The Group is exposed to currency risk on sales, purchases, assets and borrowings that are denominated in a currency other than the respective functional currencies of group entities. The Group's operations are located in the USA and its reported results and financial position can be significantly affected by changes in the USD/AUD exchange rate. The Group seeks to minimise its exposure to currency risk by monitoring exchange rates and entering into foreign currency transactions that maximise cash available for the USA operations. The Group does not presently enter into hedging arrangements to hedge its currency risk. All foreign currency transactions are entered into at spot rates. The board considers this policy appropriate, taking into account the Group's size, current stage of development, financial position and the board's approach to risk management.

Credit risk is the risk of financial loss to the Group if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Group's exposure to credit risk is minimal at present as the majority of its financial assets are held in cash with banks. The exposure with respect to trade receivables is set out in Note 22.

The board's policy is to maintain a suitable capital base so as to maintain investor, creditor and market confidence and to sustain future development of the business. Given the Group's current stage of development and financial position the board is focused on investment of available capital in the Group's USA operations.

There were no changes in the Group's approach to capital management during the year. Neither the Company nor any of its subsidiaries are subject to externally imposed capital requirements.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The net gain on sale resulted from the sale of the Group's interests in the Leighton Field Olmos reservoir and certain Yegua gas wells (2011: $nil).

All oil and gas revenues are from customers in the USA. Revenues from two customers represent $13,663,574 and $1,093,750, respectively (2011: three customers represent $14,221,952, $3,574,073 and $2,419,317, respectively) of the Group's total revenues.

			Consolidated

	Note		Year ended 31 Dec 2012 A$		Year ended 31 Dec 2011 A$
Employee benefits
Wages and salaries				615,097		332,766
Other associated employee costs				77,229		46,055
Increase in annual leave liability				48,007		10,789
Equity-settled share-based payments		21		1,192,911		1,904,889

				1,933,244		2,294,499

Administrative and other expenses
Equity-settled share-based payments		21		667,087		199,913
Transaction costs — merger and demerger schemes				1,752,851		—
Other administrative / other expenses				3,285,600		1,991,094

				5,705,538		2,191,007

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

Finance expense relating to foreign exchange translation differences (net of tax) recognised in comprehensive income is $649,530 (2011: $298,513).

Numerical reconciliation between tax expense and pre-tax net profit / (loss)

	Consolidated

	Year ended 31 Dec 2012 A$			Year ended 31 Dec 2011 A$
Profit / (loss) before tax		(5,867,032	)		2,331,307

Income tax expense/(benefit) using the domestic corporation tax rate of 30%		(1,760,110	)		699,392
Increase/(decrease) in income tax expense due to:
Change in unrecognised temporary differences		1,168,801			(1,390,508	)
Non-deductible expenditure		560,314			637,808
Withholding tax payable		282,439			—
Effect of tax rates in foreign jurisdictions		(72,979	)		205,007
Adjustments for prior periods		1,011,734			18,157
Tax losses not brought to account		1,186,040			166,937

Income tax expense/(benefit) on pre-tax net profit/loss		2,376,239			336,793

Income tax expense consists of current tax expense of $300,286 (2011: $18,157) and deferred tax expense of $2,075,953 (2011: $318,636).

Income tax expense/benefit recognised directly in equity for the Group is $nil (2011: $nil).

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)



Weighted average number of ordinary shares (basic)
Issued ordinary shares at 1 January	242,539,848	175,177,879
Effect of shares issued April 2012	1,787,671	—
Effect of shares issued December 2012	9,041	—
Effect of shares issued February 2011	—	72,548
Effect of shares issued March 2011	—	20,194,076
Effect of shares issued April 2011	—	26,032,260
Effect of shares issued May 2011	—	4,356,000

Weighted average number of ordinary shares used as the denominator in calculating basic earnings per share	244,336,560	225,832,763

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

At 31 December 2012 20,000,000 options (2011: 2,500,000) were excluded from the diluted weighted average number of ordinary share calculation as their effect would have been anti-dilutive.

At 31 December 2012 nil options (2011: 14,500,000) were excluded from the diluted weighted average number of ordinary share calculation as conditions for their exercise had not yet been met.

The Group's exposure to credit risk, foreign exchange risk and interest rate risk and a sensitivity analysis for financial assets and liabilities are disclosed in Note 22.

The amounts consist of security deposits held with entities in the USA and secure obligations in relation to drilling activities in the USA.

The Group's exposure to credit risk, foreign exchange risk and interest rate risk and a sensitivity analysis for financial assets and liabilities are disclosed in Note 22.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The Group's Leighton Olmos and Yegua producing oil and gas properties were presented as assets held for sale at 31 December 2011. A purchase and sale agreement closed on 6 March 2012.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

	Consolidated

	2012 A$			2011 A$
Oil and gas properties
*Cost*
Balance at 1 January		51,066,767			26,845,237
Transferred from exploration and evaluation expenditure		757,873			2,555,172
Additions		33,079,176			35,893,608
Transferred to assets held for sale (refer Note 13)		(702,779	)		(14,100,564	)
Foreign exchange translation		(622,889	)		(126,686	)

Balance at 31 December		83,578,148			51,066,767

*Accumulated depreciation and impairment*
Balance at 1 January		8,673,203			3,864,609
Depreciation expense		8,057,789			9,769,515
Impairment expense		556,299			—
Transferred to assets held for sale (refer Note 13)		—			(4,954,185	)
Foreign exchange translation		(108,671	)		(6,736	)

Balance at 31 December		17,178,620			8,673,203

*Carrying amounts*
At 1 January		42,393,564			22,980,628

At 31 December		66,399,528			42,393,564

Plant, equipment, furniture and fixtures
*Cost*
Balance at 1 January		246,732			127,004
Additions		24,359			120,521
Foreign exchange translation		(2,050	)		(793	)

Balance at 31 December		269,041			246,732

*Accumulated depreciation*
Balance at 1 January		142,170			114,415
Depreciation expense		55,564			28,339
Foreign exchange translation		(1,006	)		(584	)

Balance at 31 December		196,728			142,170

*Carrying amounts*
At 1 January		104,562			12,589

At 31 December		72,313			104,562

Total carrying amounts
At 1 January		42,498,126			22,993,217

At 31 December		66,471,841			42,498,126

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The recoverability of the carrying amounts of exploration and evaluation assets is dependent on the successful development and commercial exploitation or sale of the respective areas of interest.

The Group's exposure to foreign currency and liquidity risks is disclosed in Note 22.

In December 2012 the Group obtained senior secured short term funding of $25 million at an interest rate of 20% p.a. payable six monthly. The funding was provided by a consortium of lenders who were issued non-convertible loan notes with a term of 12 months. The facility was repayable in the event the proposed acquisition scheme of arrangement with Sundance Energy Australia Limited was implemented, and was repaid on 8 March 2013 (refer Note 30). The loan notes were secured over the Group's oil and gas properties and other assets.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The restoration provision represents the present value of the estimated cost of obligations to restore operating locations including the removal of facilities, abandonment of wells and restoration of affected areas.

The deductible temporary differences and tax losses do not expire under current Australian tax legislation. USA tax losses expire after a period of 20 years. Deferred tax assets have not been recognised in respect of these items because it is not probable that future taxable profit will be available against which the Group can utilise the benefits.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

During the period the Company issued 2,500,000 ordinary shares at an exercise price of $0.50 per share and 300,000 ordinary shares at an exercise price of $0.26 per share upon the exercise of options (refer Note 21).

In February 2011 the Company completed a placement issuing 24,166,681 ordinary shares at an issue price of $0.65 per share. The shares were allotted on 1 March 2011. The issue was ratified at an extraordinary general meeting of shareholders on 12 April 2011.

In April 2011 the Company completed a share purchase plan issuing 36,545,288 ordinary shares at an issue price of $0.65 per share.

During 2011 the Company issued 4,400,000 ordinary shares at an exercise price of $0.50 per share and 2,250,000 ordinary shares at an exercise price of $0.75 per share upon the exercise of options.

Effective 1 July 1998, the Company Law Review Act abolished the concept of par value shares and the concept of authorised capital. Accordingly, the Company does not have authorised capital or par value in respect of its issued shares.

The holders of ordinary shares are entitled to receive dividends as declared from time to time and are entitled to one vote per share at meetings of the Company. All shares rank equally with regard to the Company's residual assets.

The share-based payment reserve comprises the increase in equity resulting from the recognition of the grant date fair value of share-based payment awards as an expense over the period that the recipients unconditionally become entitled to the awards.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The foreign currency translation reserve comprises all foreign exchange differences arising from the translation of the financial statements of foreign operations where their functional currency is different to the presentation currency of the reporting entity.

No dividends have been declared, provided for or paid in respect of the year ended 31 December 2012 or the year ended 31 December 2011. In respect to the payment of dividends by the Company in subsequent reporting periods (if any), no franking credits are currently available.

Holder UNLISTED:	Notes

Tranche 1(a)
Seitel Data Ltd	(5)	26/7/06	8/5/12	0.50	2,500,000	—	2,500,000
Tranche 2
Seitel Data Ltd	(5)	26/7/06	8/5/12	1.00	2,500,000	—	2,500,000
2010 issue
CBA	(6)	15/2/10	14/2/13	0.26	300,000	—	300,000
2011 issue
Mr C Foss — Tranche 1	(1)(6)(8)	28/11/11	30/11/16	0.70	1,000,000	1,000,000	1,000,000
Mr C Foss — Tranche 2	(2)(6)(8)	28/11/11	30/11/16	0.70	6,000,000	6,000,000	6,000,000
Dr J Armstrong	(3)(6)(8)	30/5/12	29/5/16	0.70	6,000,000	6,000,000	6,000,000
Mr B Rowley	(3)(6)(8)	30/5/12	29/5/16	0.70	600,000	600,000	600,000
Mr D Olling	(3)(6)(8)	6/12/11	31/12/15	0.70	600,000	600,000	600,000
Contractor	(4)(6)(8)	29/6/11	28/6/15	0.585	100,000	100,000	100,000
Contractor	(4)(6)(8)	26/8/11	29/8/15	0.49	100,000	100,000	100,000
Contractor	(4)(6)(8)	29/8/11	29/8/15	0.585	100,000	100,000	100,000
2012 issue
Mr D Mason	(6)(7)(8)	31/8/12	30/4/19	0.70	2,250,000	2,250,000	—
Other	(6)(7)(8)	31/8/12	30/4/19	0.70	750,000	750,000	—

						17,500,000	19,800,000

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

(1): The options include the following conditions: (i) the options are only exercisable when the volume weighted average price (VWAP) of the shares of the Company on the ASX over a period of 20 consecutive trading days exceeds $1.05 per share (Price Target); (ii) if there is a change in control of the Company or if the Company disposes of more than 50% of its assets then the Tranche 1 options may be exercised without the requirement of the Price Target being met; (iii) unless already exercised, the options will terminate if Mr Foss commits a material breach of his employment contract, the Company terminates Mr Foss' employment for serious misconduct or bankruptcy or if Mr Foss elects to terminate his employment with the Company within six months of commencing employment with the Company (that is, six months from 1 December 2011); (iv) Mr Foss cannot participate in any new issues or bonus issues without exercising the Tranche 1 options.
(2): The options include the following conditions: (i) the Tranche 2 options are only exercisable from 1 January 2013 and only when the Price Target is met; (ii) however, if the Company, either directly or indirectly, disposes of more than 50% of its assets before 1 January 2013 then the Tranche 2 options: (a) may be exercised at a price per option equal to the VWAP of the shares of the company on the ASX over the 20 trading days starting on the 21st day after the sale of the assets has occurred; and (b) may only be exercised when the VWAP of the shares of the Company on the ASX over a period of 20 consecutive trading days exceeds 150% of the exercise price as calculated in (a) above; (iii) if there is a change in control of the Company other than by disposing more than 50% of its assets, the Tranche 2 options are exercisable at a price of $0.70 per option and can be exercised immediately without the requirement of the Price Target being met; (iv) unless already exercised, the Tranche 2 options will terminate if Mr Foss commits a material breach of his employment contract, the Company terminates Mr Foss' employment for serious misconduct or bankruptcy or if Mr Foss elects to terminate his employment with the Company; (v) Mr Foss cannot participate in any new issues or bonus issues without exercising the Tranche 2 options. The options terms originally provided for a re-pricing date of 1 September 2012 if an asset sale occurred, however this date was amended to 1 January 2013 with approval of shareholders at a general meeting on 31 August 2012.
(3): As for (4) above, except that there is no termination of employment clause in the terms of the options. In addition, Dr Armstrong's and Mr Rowley's options were approved by the Board in December 2011, and the grant date was the date of approval by shareholders at the annual general meeting on 30 May 2012. Dr Armstrong's and Mr Rowley's options will expire four years after shareholder approval.
(4): The options include the following conditions: the options may only be exercised after six (6) months of commencement of the contractor's engagement and if the VWAP of the Company's shares exceeds $0.735 to $0.8775; the options may be exercised if there is a change of control of the Company and the directors determine that it is likely that more than 50% of the shares of the Company will held by another party; the options will terminate if the contractor is in breach of his engagement contract or declared bankrupt or is placed into liquidation by a court. If terminated for any other reason the options shall remain outstanding until exercised or lapse upon expiry of the term; that a contractor cannot participate in any new issues or bonus issues without exercising the options.
(5): No value was attributed to options issued at the time the Company was established which was prior to the creation of business opportunities including contractual arrangements relating to exploration leases.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

(7): The options include the following conditions: (i) the options vest immediately and are only exercisable when the VWAP of the shares of the Company on the ASX over a period of 20 consecutive days exceeds A$1.05 per option ("Price Target"); (ii) however, if the Company, either directly or indirectly, disposes of more than 50% of its assets ("Transaction") before 1 January 2013 then the options: (a) may be exercised at a price per option equal to the VWAP of the shares of the company on the ASX over the 20 trading days starting on the 21st day after the sale of the assets has occurred ("Transaction Exercise Price"); and (b) may only be exercised when the VWAP of the shares of the Company on the ASX over a period of 20 consecutive trading days exceeds 150% of the exercise price as calculated in (a) above ("Transaction Price Target"); (iii) if there is a change in control of the Company other than by disposing more than 50% of its assets, the options are exercisable at a price of $0.70 per option and can be exercised immediately without the requirement of the Price Target being met, or are exercisable at the Transaction Exercise Price if a Transaction has occurred at the date of the change of control of the Company and can be exercised without the requirement of the Transaction Price Target being met; and (iv) the option holders cannot participate in any new issues or bonus issues without exercising the Tranche 2 options.
(8): As a condition precedent to the Acquisition Scheme of Arrangement between the Company and Sundance Energy Australia, all existing options were cancelled on the Acquisition Scheme becoming effective on 27 February 2013 (refer Note 30).

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The number and weighted average exercise prices of share options are as follows:

The options outstanding at 31 December 2012 have an exercise price in the range $0.49 to $0.70 and a weighted average contractual life of 4.1 years (2011: 3.5 years).

The weighted average share price at the date of exercise for share options exercised during the year ended 31 December 2012 was $0.56 (2011: $0.75).

Exposure to credit, interest rate and currency risks arises in the normal course of the Group's business.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

At the reporting date, the interest rate profile of the Group's interest-bearing financial instruments was as follows.

A 1 percent decrease in prevailing interest rates during the year would have reduced interest income and increased the loss for the year of the Group by $203,590 (2011: $135,645). This analysis assumes that all other variables remain constant.

A 1 percent increase in prevailing interest rates during the year would have increased interest income and decreased the loss for the year of the Group by $219,149 (2011: $135,645). This analysis assumes that all other variables remain constant. The analysis is performed on the same basis for 2011.

The carrying amount of the Group's financial assets represents the maximum credit exposure. The maximum exposure to credit risk at the reporting date was:

The maximum exposure to credit risk for cash and cash equivalents at the reporting date by geographic region was as set out below. The exposure was partially offset by various government guarantees in place in the jurisdictions, and these guarantees are one of the factors considered by the Group in the allocation its cash resources between regions and financial institutions.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

At reporting date the Group had a significant concentration of credit risk in trade receivables from oil and gas sales with one customer totalling $997,489 for the Group (2011: $4,607,944 for the Group). These receivables are all concentrated in the USA.

None of the Group's receivables are past due (2011: nil). The Group believes that no impairment allowance is necessary in respect of receivables based on customer credit history.

The Group's financial liabilities consist of trade and payables with carrying amounts of $11,332,721 (2011: $2,756,765) and loans and borrowings with carrying amounts of $25,000,000 (2011: $nil). The contractual cash flows equal the carrying amounts and are due in six months or less.

The Group's exposure to foreign currency risk at balance date was as follows, based on notional amounts.

The functional currency of the main operating entities in the Group is US dollars. For the years ended 31 December 2012 and 31 December 2011 the majority of the Groups' operations were located in the USA and the majority of transactions and balances were denominated in US dollars. The Group's presentation currency is Australian dollars. As a result, a change in the value of the Australian dollar against the US dollar at 31 December 2012 and 31 December 2011 would not have a material impact on the profit / loss of the Group.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The fair values of the Group's financial assets and financial liabilities at 31 December 2012 and 2011 approximate their carrying amounts.

The operating lease rentals relate to office and equipment leases with terms ranging from one to five years. During the year $217,453 was recognised by the Group as an expense in the statement of comprehensive income in respect of operating leases (2011: $180,248).

Commitments with respect to natural gas transportation are as follows. Commitments are only payable in the event contractual minimum volumes are not met.

Commitments under non-cancellable employment contracts not provided for in the financial statements and payable:

Mr C Foss is employed by the Group under an executive service agreement for a period of three years from December 2011 which may be terminated after 1 December 2012 without cause by giving 6 months' notice. Mr D Mason was employed by the Group under an executive service agreement for a

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

period of five years from July 2006. The appointment agreements with other directors include provision for 12 months' notice or payment in lieu of notice.

Commitments under a prospect generation agreement with Wandoo Energy LLC, a company controlled by Mr D Mason:

Indemnities have been provided to directors and certain executive officers of the Company in respect of liabilities to third parties arising from their positions, except where the liability arises out of conduct involving a lack of good faith. No monetary limit applies to these agreements and there are no known obligations outstanding at 31 December 2012 and 2011.

The Group has provided guarantees and deposits totaling $96,432 (2011: $48,780) in relation to exploration activities in Texas, USA.

In accordance with normal industry practice the Group has entered into joint ventures with other parties for the purpose of exploring for and developing petroleum interests. If a party to a joint venture defaults and does not contribute its share of joint venture obligations, then the other joint venture participants may be liable to meet those obligations. In this event the interest in the prospect held by the defaulting party may be redistributed to the remaining joint venturers.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

	Country of Incorporation

Parent entity
Armadillo Petroleum Ltd (formerly Texon Petroleum Ltd)
Subsidiaries
Armadillo (Eagle Ford) Pty Ltd (formerly Texon (Eagle Ford) Pty Ltd)	Australia	100	100
Talon Petroleum Limited (formerly Texon III Ltd)	Australia	100	100
Texon I Pty Ltd	Australia	100	100
Armadillo Eagle Ford Holdings, Inc. (formerly Texoz Eagle Ford Holdings, Inc.)	USA	100	100
Texoz E&P I, Inc.	USA	100	100
Armadillo E&P, Inc. (formerly Texoz E&P II, Inc.)	USA	100	100
Texoz E&P III, Inc.	USA	100	100
Texoz E&P Holdings I, Inc.	USA	100	100
Texoz E&P Holdings III, Inc.	USA	100	100

In the financial statements of the Company, investments in controlled entities are measured at cost.

During the 2011 year the Company undertook a restructure which involved the insertion of new entities into the Group. There were no business combinations and all transactions occurred under common control at book carrying values.

The Group holds working interests in joint operating agreements relating to the following projects, whose principal activities are oil and gas exploration and production.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

	Consolidated

	2012 A$			2011 A$
Cash flows from operating activities
Profit / (loss) for the period		(8,243,271	)		1,994,514
Adjustments for non-cash items:
Exploration and evaluation expenditure written-off		1,306,084			1,084,486
Impairment expense		556,299			—
Depreciation — plant and equipment		55,563			28,339
Depreciation — oil and gas properties		8,057,789			9,769,515
Share-based payment expense		1,859,998			2,104,802
Net gain on sale of oil and gas properties		(2,466,012	)		—
Interest expense accrued		356,164			—
Net foreign exchange gain / loss		104,438			(420,940	)
Income tax expense — deferred		2,354,978			318,636

Operating profit/(loss) before changes in working capital and provisions		3,942,030			14,879,352
Changes in operating assets and liabilities:
(Increase)/decrease in receivables		3,645,273			(3,761,109	)
(Increase)/decrease in prepayments		69,019			(95,576	)
(Decrease)/increase in payables		153,822			690,944
(Decrease)/increase in employee benefits		47,768			(6,550	)

Net cash from operating activities		7,857,912			11,707,061

The following were key management personnel of the Group at any time during the reporting period and unless otherwise indicated were key management personnel for the entire period:

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

There were no loans made to key management personnel or their related parties during the reporting period.

Certain directors, or their related parties, hold positions in other entities that result in them having control or significant influence over the financial or operating policies of those entities. Certain of these entities transacted with the Company or its controlled entities in the reporting period.

Wandoo Energy LLC (Wandoo), a company controlled by Mr D Mason, provided the Group with services during the period under a prospect generation agreement. Payments to Wandoo under the agreement are US$50,000 per month for an initial term of eight years commencing 1 May 2006. Amendments to the agreement during the period increased the amount payable in 2013 to US$52,500 per month and in 2014 to US$55,125 per month, and extended the term until April 2019. During the current period US$600,000 (A$579,151) was paid by the Group and its related parties to Wandoo (2011: US$600,000 (A$580,271)) for these services.

Under the prospect generation agreement, Wandoo is entitled to an overriding royalty interest (ORRI) and a carried working interest (CWI) and Dr Armstrong is entitled to an ORRI, being a share of petroleum production, in relation to each prospect accepted by the Group. The entitlements vary depending on the net revenue interest obtained by the Group under leases in respect of the prospect. Wandoo's ORRI entitlement varies from nil to 4.5% and CWI entitlement varies from nil to 5%. Dr Armstrong's ORRI entitlement varies from nil to 0.5%. The Group markets the production associated with any ORRI on behalf of Wandoo and Dr Armstrong.

Wandoo provided the Group during the period with geological and geophysical, operations support, data acquisition and reprocessing, and other services. During the current period US$500,118 (A$482,739) was paid by the Group and its related parties to Wandoo (2011: US$306,023 (A$295,960)) for these services.

Amendments to the prospect generation agreement were proposed in 2011 and were approved by Armadillo Petroleum Ltd shareholders at a general meeting of the Company on 31 August 2012.

During the period, in conjunction with the proposed merger of Armadillo with Sundance Energy Australia Limited, subject to all necessary approvals and to the completion of the proposed demerger of Armadillo's non Eagle Ford shale assets, Armadillo contracted to buy from Wandoo Energy, LLC, its

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

working interest in jointly owned Eagle Ford shale assets in McMullen County, Texas, as of 1 October 2012, for the following consideration:

The consideration is subject to adjustment downwards (to US$1,000,000 and 4,000,000 shares in Talon Petroleum Limited) if binding agreements with certain landowners are not entered into within 12 months. The transaction with Wandoo, involving the removal of the carried working interest on Armadillo's EFS acreage, was a key component of the proposed merger terms with Sundance.

Liabilities arising from the above transactions at 31 December 2012 were $93,350 (2011: $213,613).

The movement during the reporting period in the number of options over ordinary shares in the Company held, directly, indirectly or beneficially, by each key management person, including their related parties, is as follows.

All of the options are vested but were not exercisable at 31 December 2012 and 31 December 2011.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

As a condition precedent to the Acquisition Scheme of Arrangement between the Company and Sundance Energy Australia, all existing options were cancelled on the Acquisition Scheme becoming effective on 27 February 2013 (refer Note 30).

The aggregate number of options held by key management personnel related parties at 31 December 2012 included in the table above is nil (2011: nil).

The movement during the reporting period in the number of ordinary shares in the Company held, directly, indirectly or beneficially, by each key management person, including their related parties, is as follows.

The aggregate number of shares held by key management personnel related parties at 31 December 2012 included in the table above is 483,251 (2011: 483,251).

Changes in key management personnel in the period after the reporting date and prior to the date when the financial report is authorised for issue

On 27 February 2013 Dr Armstrong, Mr Rowley and Mr Mason resigned as directors of the Company and Mr Hannell, Mr McCrady and Mr Hannes were appointed as directors of the Company.

On 8 March 2013 Mr Olling resigned as company secretary and Mr Gooden was appointed as company secretary.

Apart from the above, there were no changes in key management personnel in the period after the reporting date and prior to the date when the financial report is authorised for issue.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The Group has a related party relationship with its subsidiaries (see Note 25) and with its key management personnel (see disclosures for key management personnel on preceding pages).

From time to time, to support the activities of joint ventures, venturers increase their investments in joint ventures.

For details of these transactions refer to key management personnel related disclosures.

As at, and throughout, the financial year ending 31 December 2012 the parent entity of the Group was Armadillo Petroleum Ltd.



Result of the parent entity
Loss for the period	(4,994,802	)	(2,142,357	)
Other comprehensive income for the period	—		—

	(4,994,802	)	(2,142,357	)

Financial position of the parent entity at year end
Current assets	5,395,099		13,134,180
Total assets	76,579,953		77,503,435
Current liabilities	1,157,554		274,230
Total liabilities	1,157,554		274,230
Total equity of the parent entity comprising of:
Share capital	85,182,020		83,854,020
Share-based payment reserve	4,198,948		2,338,950
Accumulated losses	(13,958,569	)	(8,963,765	)

Total Equity	75,422,399		77,229,205

The parent entity has provided guarantees with the effect that the Company guarantees certain obligations of its USA subsidiaries in the ordinary course of business.

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

Costs Incurred — The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities:

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

The following reserve data represents estimates only and should not be construed as being exact.



Total proved reserves:
December 31, 2010	492		6,903		1,642
Revisions of previous estimates	21		44		28
Extensions and discoveries	1,263		1,925		1,584
Production	(192	)	(620	)	(295	)

December 31, 2011	1,584		8,252		2,959
Revisions of previous estimates	21		42		28
Extensions and discoveries	479		598		579
Production	(145	)	(231	)	(183	)
Sales of reserves in-place	(387	)	(6,217	)	(1,423	)

December 31, 2012	1,552		2,444		1,960

Proved developed reserves:
December 31, 2010	492		6,903		1,642

December 31, 2011	699		6,782		1,829

December 31, 2012	282		510		368

Proved undeveloped reserves:
December 31, 2010	—		—		—

December 31, 2011	885		1,470		1,130

December 31, 2012	1,270		1,934		1,592

ARMADILLO PETROLEUM LTD (FORMERLY TEXON PETROLEUM LTD)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR DECEMBER 31, 2012 AND THE YEAR THEN ENDED (Continued)

(in thousands)	Year Ended December 31, 2012			Year ended December 31, 2011

Standardized Measure, beginning of period	$	36,487		$	20,256
Sales, net of production costs		(9,824	)		(17,616	)
Net change in sales prices, net of production costs		(3,567	)		6,080
Extensions and discoveries, net of future production and development costs		7,465			26,574
Previously estimated development costs incurred during the period		839			4,468
Revision of quantity estimates		1,034			535
Accretion of discount		4,063			2,112
Change in income taxes		4,144			(3,280	)
Sales of reserves in-place		(21,377	)		—
Change in production rates and other		(3,726	)		(2,642	)

Standardized Measure, end of period	$	15,538		$	36,487

The following average prices were used in determining the Standardized Measure as at:

We calculate the projected income tax effect using the "year-by-year" method for purposes of the supplemental oil and gas disclosures.

Australian law. Australian law provides that a company or a related body corporate of the company may provide for indemnification of officers and directors, except to the extent of any of the following liabilities incurred as an officer or director of the company:

Constitution. Our Constitution provides, except to the extent prohibited by the law and the Corporations Act, for the indemnification of every person who is or has been an officer or a director of the company against liability (other than legal costs that are unreasonable) incurred by that person as an officer or director. This includes any liability incurred by that person in their capacity as an officer or director of a subsidiary of the company where the company requested that person to accept that appointment.

Indemnification Agreements. Pursuant to Deeds of Access, Insurance and Indemnity, the form of which is filed as Exhibit 10.5 to this registration statement, we have agreed to indemnify our directors and officers against certain liabilities and expenses incurred by such persons in connection with claims made by reason of their being such a director or officer.

SEC Position. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Pursuant to the underwriting agreement for this offering, the form of which is filed as Exhibit 1.1 to this registration statement, the underwriters will agree to indemnify our directors and officers and persons controlling us, within the meaning of the Securities Act, against certain liabilities that might arise out of or are based upon certain information furnished to us by any such underwriter.

Since January 1, 2010, we have issued and sold to third parties the securities listed below without registering the securities under the Securities Act of 1933, as amended (the "Securities Act"). None of these transactions involved any public offering. All our securities were sold through private placement either (i) outside the United States or (ii) in the United States to a limited number of investors in transactions not involving any public offering. As discussed below, we believe that each issuance of these securities was exempt from, or not subject to, registration under the Securities Act.

Since January 1, 2010, we have granted options to employees, directors and consultants under our incentive compensation program covering an aggregate of 10,610,000 ordinary shares, with exercise prices ranging from $0.20 to $1.40 per share. As of November 30, 2013, 4,780,556 of these options have been exercised, while 777,778 of these options have been forfeited and cancelled without being exercised. In addition, since January 1, 2010 we have issued 2,692,057 restricted share units to employees and directors under our incentive compensation program. These restricted share units may be settled in cash or share at the discretion of our board. As of November 30, 2013, 335,642 of these restricted share units had been forfeited and cancelled. We believe that the issuance of these securities were exempt from registration under the Securities Act in reliance upon Regulation S or Rule 701 of the Securities Act as transactions pursuant to written compensatory plans or pursuant to a written contract relating to compensation. No underwriters were employed in connection with the foregoing option grants and restricted share unit awards.

Schedules have been omitted because the information required to be set forth therein is not applicable or is shown in the Consolidated Financial Statements or the Notes thereto.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than payment by a registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

Pursuant to the requirements of the Securities Act of 1933, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-1 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Denver, Colorado on December 19, 2013.

Each person whose signature appears below does hereby constitute and appoint Eric P. McCrady and Cathy L. Anderson, and each of them singly (with full power to act alone), as his true and lawful attorneys-in-fact and agents, each with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, in connection with this registration statement, including to sign and file in the name and on behalf of the undersigned as director or officer of the registrant, any and all amendments and supplements (and any and all prospectus supplements, stickers and post-effective amendments) to this registration statement with all exhibits thereto, and sign any registration statement for the same offering covered by this registration statement that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and all post-effective amendments thereto and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, and any applicable securities exchange, securities self-regulatory body or other regulatory entity, granting unto said attorneys-in-fact and agents, and each of them (with full power to act alone) full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith and in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Pursuant to the Securities Act of 1933, as amended, the undersigned, the duly authorized representative in the United States of Sundance Energy Australia Limited, has signed this registration statement or amendment thereto in Denver, Colorado, on December 19, 2013.

Exhibits			Description

	1.1		Form of Underwriting Agreement*
	3.1		Constitution of Sundance Energy Australia Limited
	4.1		Form of Deposit Agreement between Sundance Energy Australia Limited and The Bank of New York Mellon, as depositary, and Owners and Holders of the American Depositary Shares
	4.2		Form of American Depositary Receipt evidencing American Depositary Shares (included in Exhibit 4.1)
	5.1		Form of Opinion of Baker & McKenzie regarding the validity of the ordinary shares being issued
	8.1		Opinion of Baker & McKenzie LLP regarding material U.S. tax matters
	8.2		Opinion of Baker & McKenzie regarding material Australian tax matters
	10.1		Credit Agreement, dated December 28, 2012, by and among Sundance Energy, Inc., Wells Fargo Bank, N.A., as administrative agent, swing line lender, and LC issuer, and the lender parties thereto
	10.2		Amended and Restated Guaranty, dated as of December 28, 2012, by Sundance Energy Australia Limited in favor of Wells Fargo Bank, N.A., as administrative agent
	10.3		Stock Pledge Agreement, dated as of December 28, 2012, by Sundance Energy Australia Limited in favor of Wells Fargo Bank, N.A., as administrative agent
	10.4		Second-Lien Credit Agreement, dated as of August 30, 2013, by and among Sundance Energy, Inc., Wells Fargo Energy Capital, Inc., as administrative agent, and the lender parties thereto
	10.5		Second-Lien Security Agreement, dated as of August 30, 2013, by Sundance Energy, Inc. and the other guarantor parties thereto, in favor of Wells Fargo Energy Capital, Inc., as administrative agent
	10.6		Second-Lien Stock Pledge Agreement, dated as of August 30, 2013, by Sundance Energy Australia Limited in favor of Wells Fargo Energy Capital, Inc., as administrative agent
	10.7		Second-Lien Guaranty, dated as of August 30, 2013, by the subsidiaries of Sundance Energy, Inc. in favor of Wells Fargo Energy Capital, Inc., as administrative agent
	10.8		Second-Lien Guaranty, dated as of August 30, 2013, by Sundance Energy Australia Limited in favor of Wells Fargo Energy Capital, Inc., as administrative agent
	10.9		Form of Deed of Access, Insurance and Indemnity for Directors and Officers
	10.10		Employment Agreement, dated May 18, 2011, by and between Sundance Energy Inc. and Eric P. McCrady
	21.1		List of significant subsidiaries of Sundance Energy Australia Limited
	23.1		Consent of Baker & McKenzie (see Exhibit 5.1)
	23.2		Consent of Baker & McKenzie LLP (see Exhibit 8.1)
	23.3		Consent of Baker & McKenzie (see Exhibit 8.2)
	23.4		Consent of Ernst & Young
	23.5		Consent of Grant Thornton LLP


Australia	1311	Not Applicable
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)
633 17th Street, Suite 1950 Denver, CO 80202 Tel: (303) 543-5700 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
Eric P. McCrady Sundance Energy, Inc. Chief Executive Officer 633 17th Street, Suite 1950 Denver, CO 80202 Tel: (303) 543-5700 (Name, address, including zip code, and telephone number, including area code, of agent for service)


Andrew S. Reilly Baker & McKenzie 50 Bridge Street, Level 27 Sydney, NSW 2000, Australia Tel: +61 2 9225 0200 Fax: +61 9225 1595		William D. Davis II Baker & McKenzie LLP 700 Louisiana, Suite 3000 Houston, TX 77002 Tel: (713) 427-5000 Fax: (713) 427-5099		Kirk Tucker Mayer Brown LLP 700 Louisiana, Suite 3400 Houston, TX 77002 Tel: (713) 238-3000 Fax: (713) 238-4603		David S. Bakst Mayer Brown LLP 1675 Broadway New York, NY 10019 Tel: (212) 506-2500 Fax: (212) 262-1910

Title of Each Class of Securities to be Registered(1)(2)	Proposed Maximum Aggregate Offering Price(3)	Amount of Registration Fee




Ordinary shares, no par value	$175,000,000	$22,540

	Per ADS	Total

Public offering price	$	$
Underwriting discounts and commissions	$	$
Proceeds, before expenses, to us	$	$

Use of Proceeds		Amount

		(in millions)
Acceleration of development program(1)		$
General corporate purposes(2)

Total		$


Wells Fargo Securities		Canaccord Genuity		UBS Investment Bank

		Page

Prospectus Summary		1
The Offering		11
Summary Historical and Pro Forma Consolidated Financial Data		13
Summary Reserve and Operations Data		17
Risk Factors		19
Cautionary Note Regarding Forward-Looking Statements		41
Use of Proceeds		43
Price Range of Ordinary Shares		44
Dividend Policy		45
Exchange Rate Information		45
Capitalization		46
Dilution		47
Selected Historical and Pro Forma Consolidated Financial Data		49
Management's Discussion and Analysis of Financial Condition and Results of Operations		54
Business		78
Management		103
Principal Shareholders		112
Related Party Transactions		114
Description of Share Capital		115
Description of American Depositary Shares		122
Shares Eligible for Future Sale		130
Taxation		133
Underwriting		141
Expenses Relating to This Offering		147
Legal Matters		148
Experts		148
Enforceability of Civil Liabilities		149
Where You Can Find Additional Information		150
Appendix A — Glossary of Selected Oil and Natural Gas Terms		A-1
Index to Financial Statements		F-1

		As at September 30, 2013

		(per ADS) (unaudited)
Assumed initial public offering price		$

Net tangible book value as at September 30, 2013

Increase in net tangible book value attributable to new investors

As-adjusted net tangible book value immediately after the offering

Dilution to new investors		$

	Ordinary Shares Purchased				Total Consideration

									Average Price Per Ordinary Share
										Average Price Per ADS
(In '000s, except percentages and per share data)	Number	%			Amount	%				Average Price Per ADS
	(unaudited)
Existing shareholders				%				%
New investors				%				%

Total			100	%			100	%



Well count
Gross	228		186	184	142	107	101	37
Net	77.5		49.4	22.0	14.0	10.7	11.9	6.3
Average working interest	34%	(1)	27%	12%	10%	10%	12%	17%
Operated percentage of total production	76%		27%	11%	8%	15%	10%	13%
Average daily net production for six-month period (Boe/d)	1,883		1,298	1,323	848	775	591	295

	Nine-month period ended September 30,

	Nine-month period ended September 30,				Change in $		Change as %
	2013		2012		Change in $		Change as %
	(unaudited)		(unaudited)
Revenues (in $ '000s)
Oil sales	$	51,792	$	26,955	$	24,837		92.1	%
Natural gas sales		3,371		1,394		1,977		141.9	%

Total revenues	$	55,163	$	28,349	$	26,814		94.6	%

	Nine-month period ended September 30,

	Nine-month period ended September 30,				Change in Volume		Change as %
	2013		2012		Change in Volume		Change as %
Net sales volumes:
Oil (Bbl)		522,312		322,923		199,389		61.7	%
Natural gas (Mcf)		902,626		389,039		513,587		132.0	%

Oil equivalent (Boe)		672,750		387,762		284,988		73.5	%

	Nine-month period ended September 30,

Selected Per Boe Metrics	2013		2012		Change			Percent
	(unaudited)		(unaudited)
Total oil and natural gas revenues	$	82.00	$	73.11	$	8.89			12.2	%
Lease operating expenses		10.41		6.92		3.49			50.5	%
Production taxes		6.39		8.05		(1.66	)		(20.6	)%

Lease operating and production tax expenses		16.80		14.97		1.83			12.2	%
Depreciation and amortization expense		34.81		27.61		7.20			26.1	%
General and administrative expense		19.00		14.62		4.38			29.9	%

	Six-month period ended December 31,

	Six-month period ended December 31,				Change in $		Change as %
	2012		2011		Change in $		Change as %
	(audited)		(unaudited)
Revenues (In $ '000s)
Oil sales	$	16,790	$	11,012	$	5,778		52.5	%
Natural gas sales		934		727		207		28.5	%

Total revenues	$	17,724	$	11,739	$	5,985		51.0	%

	For the fiscal year ended June 30,

	For the fiscal year ended June 30,				Change in $		Change as %
	2012		2011		Change in $		Change as %
	(audited)		(audited)
Revenue (In $ '000s)
Oil sales	$	27,965	$	16,706	$	11,259		67.4	%
Natural gas sales		1,822		1,470		352		23.9	%

Product revenue	$	29,787	$	18,176	$	11,611		63.9	%

	For the fiscal year ended June 30,

	For the fiscal year ended June 30,				Change in Volume		Change as %
	2012		2011		Change in Volume		Change as %
Net sales volumes:
Oil (Bbls)		337,650		210,060		127,590		60.7	%
Natural gas (Mcf)		370,296		282,463		87,833		31.1	%

Oil equivalent (Boe)		399,366		257,137		142,229		55.3	%

	Payments due by period

	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
(In $ '000s)
Senior Credit Facility(1)	$	33,275	$	655	$	1,310	$	31,310	$	—
Drilling rig commitments(2)		—		—		—		—		—
Drilling commitments(3)		3,000		1,000		2,000		—		—
Operating lease obligations		243		162		81		—		—
Employment commitments		379		275		104		—		—
Asset retirement obligation(4)		1,228		38		—		255		935

Total	$	38,125	$	2,130	$	3,495	$	31,565	$	935

									Year ended June 30,

	Year ending December 31, 2013		Three-month period ending December 31, 2013		Nine-month period ended September 30, 2013		Six-month period ended December 31, 2012		Year ended June 30,
	Year ending December 31, 2013		Three-month period ending December 31, 2013		Nine-month period ended September 30, 2013		Six-month period ended December 31, 2012		2012		2011
(In $ '000s)	(estimated)		(estimated)		(unaudited)		(audited)		(audited)		(audited)
Development and production assets	$	213,900	$	85,738	$	128,162	$	47,949	$	50,520	$	5,954
Exploration and evaluation expenditure		12,065		—		12,065		23,348		8,670		1,293

Total	$	225,965	$	85,738	$	140,227	$	71,297	$	59,190	$	7,247


Change in profit/(loss)
— increase in interest rates + 2%	$	(157	)
— decrease in interest rates - 2%		157
Change in equity
— increase in interest rates + 2%	$	(157	)
— decrease in interest rates - 2%		157


Change in profit/(loss)
— improvement in oil price of $10 per Bbl	$	1,476
— decline in oil price of $10 per Bbl		(1,424	)
Change in equity
— improvement in oil price of $10 per Bbl	$	1,476
— decline in oil price of $10 per Bbl		(1,424	)

	Identified Drilling Locations as of June 30, 2013(1)

	Identified Drilling Locations as of June 30, 2013(1)												Producing Wells as of September 30, 2013
	Proved Undeveloped Drilling Locations(2)				Probable/ Possible Drilling Locations(2)				Total Drilling Locations				Producing Wells as of September 30, 2013
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Eagle Ford		15		15.0		73		52.5		88		67.5		14		12.3
Mississippian/Woodford		13		6.8		948		225.3		961		232.1		12		5.5
Wattenberg Field		105		59.8		104		53.8		209		113.6		83		59.2
Bakken		139		7.2		717		16.1		856		23.3		131		5.1

Total		272		88.8		1,842		347.7		2,114		436.5		240		82.1

	Nine-month period ended								Six-month period ended

	September 30, 2013								December 31, 2012
	Oil		Natural Gas		Oil Equivalent		Average Daily Volume		Oil		Natural Gas		Oil Equivalent		Average Daily Volume
	(MBbls)		(MMcf)		(MBoe)		(Boe/d)		(MBbls)		(MMcf)		(MBoe)		(Boe/d)
Eagle Ford		246		317		299		1,094		—		—		—		—
Mississippian/Woodford		64		251		106		389		10		28		15		82
Wattenberg Field		83		264		127		466		29		137		52		281
Bakken		129		71		141		516		156		95		172		935

Total		522		903		673		2,465		195		260		239		1,298

Name		Position

Eric P. McCrady		Chief Executive Officer and Managing Director
Cathy L. Anderson		Chief Financial Officer
Grace Ford*		Vice President of Exploration and Development
Mike Wolfe*		Vice President of Land
Michael D. Hannell		Chairman of the Board
Damien A. Hannes		Director
Neville W. Martin		Director
H. Weldon Holcombe		Director

	Six-month period ended December 31, 2012												Year ended June 30, 2012

	Fixed Remuneration			STI			LTI			Actual Performance Related(1)			Fixed Remuneration			STI			LTI			Actual Performance Related(1)
E. McCrady		32	%		19	%		49	%		67	%		32	%		19	%		49	%		28	%
C. Anderson		40	%		20	%		40	%		53	%		41	%		18	%		41	%		N/A
A.M. Hunter III		N/A			N/A			N/A			(5	)%		37	%		17	%		46	%		29	%
P. Franks(2)		N/A			N/A			N/A			—			37	%		17	%		46	%		29	%
Non-executive directors		100	%		—			—			—			100	%		—			—			—

Executive Officer

E. McCrady	294,000	401,785	—		695,785	247,446	448,339
C. Anderson	—	267,857	—		267,857	66,964	200,893
A.M. Hunter III(2)	241,000	—	(120,500	)	120,500	120,500	—

Total	535,000	669,642	(120,500	)	1,084,142	434,910	649,232

Underwriter		Number of ADSs

Wells Fargo Securities, LLC
Canaccord Genuity Inc.
UBS Securities LLC




Total


SEC registration fee		$*
The NASDAQ Global Select Market listing fee		*
Financial Industry Regulatory Authority Inc. filing fee		*
Printing expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Independent reserve engineer fees and expenses		*
Roadshow expenses		*
Other fees and expenses		*

Total		$*

		Page

Sundance Energy Australia Limited
Unaudited Pro Forma Condensed Consolidated Financial Statements:
Introduction		F-2
Unaudited Pro Forma Condensed Consolidated Statement of Profit or Loss for the Nine-Month Period Ended September 30, 2013		F-5
Unaudited Pro Forma Condensed Consolidated Statement of Profit or Loss for the Year Ended December 31, 2012		F-6
Unaudited Pro Forma Condensed Consolidated Statement of Financial Position as at September 30, 2013		F-7
Notes to Pro Forma Condensed Consolidated Financial Statements		F-8
Consolidated Financial Statements for September 30, 2013 and the Nine-Month Period Then Ended (Unaudited):
Consolidated Profit or Loss and Other Comprehensive Income		F-11
Consolidated Statement of Financial Position		F-12
Consolidated Statement of Changes in Equity		F-13
Consolidated Statement of Cash Flows		F-14
Notes to Consolidated Statements		F-15
Consolidated Financial Statements for December 31, 2012 and the Six-Month Period Then Ended:
Reports of Registered Public Accounting Firms		F-23
Consolidated Statement of Profit or Loss and Other Comprehensive Income		F-25
Consolidated Statement of Financial Position		F-26
Consolidated Statement of Changes in Equity		F-27
Consolidated Statement of Cash Flows		F-28
Notes to Consolidated Financial Statements		F-29
Consolidated Financial Statements for December 31, 2011 and the Six-Month Period Then Ended (Unaudited):
Consolidated Statement of Profit or Loss and Other Comprehensive Income		F-69
Consolidated Statement of Financial Position		F-70
Consolidated Statement of Changes in Equity		F-71
Consolidated Statement of Cash Flows		F-72
Notes to Consolidated Financial Statements		F-73
Consolidated Financial Statements for June 30, 2012 and 2011 and the Years Then Ended:
Report of Registered Public Accounting Firm		F-78
Consolidated Statement of Profit or Loss and Other Comprehensive Income		F-79
Consolidated Statement of Financial Position		F-80
Consolidated Statement of Changes in Equity		F-81
Consolidated Statement of Cash Flows		F-82
Notes to Consolidated Financial Statements		F-83
Armadillo Petroleum Ltd (formerly Texon Petroleum Ltd)
Consolidated Financial Statements for December 31, 2012 and the Year Then Ended:
Independent Auditor's Report		F-117
Consolidated Statement of Comprehensive Income		F-118
Consolidated Statement of Financial Position		F-119
Consolidated Statement of Changes in Equity		F-120
Consolidated Statement of Cash Flows		F-121
Notes to Consolidated Financial Statements		F-122



Proved developed and undeveloped:
Oil	5,758	1,552	(315	)	(1,362	)	5,633

Natural gas	16,888	2,444	(331	)	(1,566	)	17,435

Total barrels of oil equivalent	8,573	1,960	(370	)	(4,673	)	8,540

Proved developed:
Oil	1,932	283	(35	)	(708	)	1,472

Natural gas	5,242	510	(36	)	(766	)	4,950

Total barrels of oil equivalent	2,806	368	(41	)	(836	)	2,297


Development and production assets	$	35,791
Exploration and evaluation expenditure		1,174
Restoration provision liability		(199	)

Total assets held for sale, net of restoration provision liability	$	36,766

		Number of Shares

a) Ordinary Shares
Total shares issued at 31 December 2012			278,765,141
Shares issued as merger consideration			122,669,678
Shares issued as placement			57,502,338
Restricted share units converted to shares			949,825
Share options exercised			2,725,000

Total shares issued at 30 September 2013			462,611,982

	30 September 2013 US$'000

b) Issued Capital
Opening balance	$	58,694
Shares issued as merger consideration		132,092
Shares issued as placement, net of costs		45,483
Restricted share units converted to shares		—
Shares options exercised		813

Closing balance at end of period	$	237,082

	30 September 2013

	Number of Options			Weighted Average Exercise Price A$
Outstanding at start of period		5,776,666			0.59
Formally issued		2,000,000			1.28
Forfeited		—			—
Exercised		(2,725,000	)		0.31
Expired		—			—

Outstanding at end of period		5,051,666			1.02

Exercisable at end of period		2,031,666			0.86

Grant Date		Estimated Fair Value (US$'000)		Vesting Conditions

1 November 2012	350,000	$	145	20% issuance date, 20% first four anniversaries
3 December 2012	350,000	$	157	20% issuance date, 20% first four anniversaries
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

	2,000,000	$	994


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