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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

 

**FORM 20-F**

 

**(Mark One)**

 

| **o**      | **REGISTRATION STATEMENT PURSUANT   TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                |
|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** ** | ** **                                                                                                                                                                                                                                         |
| **OR**     |
| ** ** | ** **                                                                                                                                                                                                                                         |
| **x**      | **ANNUAL REPORT PURSUANT TO   SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934   For the fiscal year ended December 31, 2016                ** |
| ** ** | ** **                                                                                                                                                                                                                                         |
| **OR**     |
| ** ** | ** **                                                                                                                                                                                                                                         |
| **o**      | **TRANSITION REPORT PURSUANT TO   SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                           |
| ** ** | ** **                                                                                                                                                                                                                                         |
| **OR**     |
| ** ** | ** **                                                                                                                                                                                                                                         |
| **o**      | **SHELL COMPANY REPORT PURSUANT   TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934**                                                                                                                                        |

 

Commission file number: 001-36302

 
| **Sundance   Energy Australia Limited**                                                                                                                                              |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| (Exact name of Registrant as specified in its charter)                                                                                                                               |
|                                                                                                                                                                                 |
| **Australia**                                                                                                                                                                        |
| (Jurisdiction of incorporation or organization)                                                                                                                                      |
|                                                                                                                                                                                 |
| **633 17th Street, Suite 1950**

**Denver, CO 80202**

**Tel: (303) 543-5700**                                                                                                       |
| (Address of principal executive offices)                                                                                                                                             |
|                                                                                                                                                                                 |
| **Eric P. McCrady**

**Sundance Energy, Inc.**

**Chief Executive Officer**

**633 17th Street, Suite 1950**

**Denver, CO 80202**

**Tel: (303) 543-5700**

**Fax: (303) 543-5701** |
| (Name, Telephone, E-mail and/or Facsimile number and Address of   Company Contact Person)                                                                                            |

 

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

 

| Title of each   class                                              |   | Name of each   exchange on which registered |
|--------------------------------------------------------------------|--------|---------------------------------------------|
| American Depositary Shares, each representing 100

Ordinary Shares |   | The NASDAQ Stock Market LLC                 |
| Ordinary Shares, no par value*                                     |   | The NASDAQ Stock Market LLC                 |

 

***Not for trading, but only in connection with the listing of American Depositary Shares on The NASDAQ Stock Market LLC.**

 

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

 
| **None**         |
|------------------|
| (Title of Class) |

 

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Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

 
| **None**         |
|------------------|
| (Title of Class) |

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
|   | 1,249,351,617   Ordinary Shares at December 31, 2016 |
|--------|------------------------------------------------------|

 

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

o Yes   x No

 

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

o Yes   x No

 

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

x Yes   o No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

o Yes   o No

 

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

 

| Large accelerated filer o |   | Accelerated filer o |   | Non-accelerated filer o |   | Emerging growth company x |
|---------------------------|--------|---------------------|--------|-------------------------|--------|--------------------------------|

 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards* provided pursuant to Section 13(a) of the Exchange Act. o

 

*The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 

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

 

| U.S. GAAP o |   | International Financial Reporting Standards as issued   by the International Accounting Standards Board x |   | Other o |
|-------------|--------|-----------------------------------------------------------------------------------------------------------|--------|---------|

 

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

o Item 17   o Item 18

 

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

o Yes   x No

 

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**Table of Contents**

 
| ** **                                                                                   | ** ** | **Page** | ** ** |
|----------------------------------------------------------------------------------------------|------------|----------|------------|
| Part I                                                                                  |       |     |       |
| Item 1. Identity of Directors,   Senior Management and Advisers                         |       | 3        |       |
| Item 2. Offer Statistics and   Expected Timetable                                       |       | 3        |       |
| Item 3. Key Information                                                                 |       | 3        |       |
| Item 4. Information on Sundance                                                         |       | 28       |       |
| Item 4A. Unresolved Staff Comments                                                      |       | 44       |       |
| Item 5. Operating and Financial   Review and Prospects                                  |       | 45       |       |
| Item 6. Directors, Senior Management   and Employees                                    |       | 60       |       |
| Item 7. Major Shareholders and   Related Party Transactions                             |       | 68       |       |
| Item 8. Financial Information                                                           |       | 70       |       |
| Item 9. The Offer and Listing                                                           |       | 71       |       |
| Item 10. Additional Information                                                         |       | 73       |       |
| Item 11. Quantitative and   Qualitative Disclosures about Market Risk                   |       | 81       |       |
| Item 12. Description of Securities   Other than Equity Securities                       |       | 82       |       |
| Part II                                                                                 |       |     |       |
| Item 13. Defaults, Dividend   Arrearages and Delinquencies                              |       | 84       |       |
| Item 14. Material Modifications to   the Rights of Security Holders and Use of Proceeds |       | 84       |       |
| Item 15. Controls and Procedures                                                        |       | 84       |       |
| Item 16A. Audit Committee Financial   Expert                                            |       | 84       |       |
| Item 16B. Code of Ethics                                                                |       | 85       |       |
| Item 16C. Principal Accountant Fees   and Services                                      |       | 85       |       |
| Item 16D. Exemptions from the   Listing Standards for Audit Committees                  |       | 85       |       |
| Item 16E. Purchases of Equity Securities   by the Issuer and Affiliated Purchasers      |       | 85       |       |
| Item 16F. Change in Registrant’s   Certifying Accountant                           |       | 85       |       |
| Item 16G. Corporate Governance                                                          |       | 85       |       |
| Item 16H. Mine Safety Disclosure                                                        |       | 86       |       |
| Part III                                                                                |       |     |       |
| Item 17. Financial Statements                                                           |       | 86       |       |
| Item 18. Financial Statements                                                           |       | 86       |       |
| Item 19. Exhibits                                                                       |       | 86       |       |

 

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** **

**EXPLANATORY NOTES**

 

Unless otherwise indicated or the context implies otherwise:

 

·                  “we,” “us,” “our” or “Sundance” refers to Sundance Energy Australia Limited, an Australian corporation, and its subsidiaries;

 

·      “ADSs” refers to our American Depositary Shares, each of which represents 100 ordinary shares;

 

·      “ADRs” refers to American Depositary Receipts, which evidence the ADSs;

 

·                  “SEC” refers to the Securities and Exchange Commission;

 

·                  “shares” or “ordinary shares” refers to our ordinary shares;

 

·                  “Netherland Sewell” refers to Netherland, Sewell & Associates, Inc., the independent engineering firm, that provided the estimates of proved oil and natural gas reserves as of December 31, 2014; and

 

·                  “Ryder Scott” refers to Ryder Scott Company L.P., the independent engineering firm, that provided the estimates of proved oil and natural gas reserves as of December 31, 2016 and 2015.

 

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 annual report.

 

All references herein to “$” and “U.S. dollar” are to United States dollars. Except as otherwise stated, all monetary amounts in this annual report are presented in United States dollars.

 

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.

 

The disclosures in this annual report are based on the statutory financial information filed with the Australian Securities Exchange (the “ASX”) and the Australian Securities & Investments Commission. These annual report disclosures can be reconciled to those Australian filings with information contained in this annual report, however certain differences may exist as a result of the disclosure requirements under applicable U.S. and Australian rules. We do not believe that any of these differences are material.

 

**FORWARD-LOOKING STATEMENTS**

 

Certain statements in this annual report may constitute “forward-looking statements.” Such forward-looking statements are based on the beliefs of our management as well as assumptions based on information available to us. When used in this annual report, the words “anticipate,” “believe,” “estimate,” “project,” “intend” and “expect” and similar expressions, as they relate to us or our management, are intended to identify forward-looking statements. Such forward-looking statements reflect our current views with respect to future events and are subject to certain known and unknown risks, uncertainties and assumptions. Many factors could cause our actual results, performance or achievements to be materially different from any future results, performance or achievements that may be expressed or implied by such forward-looking statements. These include, but are not limited to, risks or uncertainties associated with the discovery and development of oil and natural gas reserves, cash flows and liquidity, business and financial strategy, budget, projections and operating results, oil and natural gas prices, amount, nature and timing of capital expenditures, including future development costs, availability and terms of capital, general economic and business conditions, environmental and other liability and other factors identified under Item 3.D. “Key Information—Risk Factors” of this annual report. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described in this annual report as anticipated, believed, estimated or expected. Accordingly, you should not place undue reliance on these forward-looking statements. These statements speak only as of the date of this annual report and will not be revised or updated to reflect events after the date of annual report.

 

**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 (the “Sarbanes Oxley Act”) relating to internal control over financial reporting, and we will not provide such an attestation from our auditors.

 

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

 

·                  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 $1.07 billion;

 

·                  the date on which we have issued more than $1 billion in non-convertible debt securities in any rolling three year period; or 

 

·                  December 31, 2020.

 

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

 

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**PART I**

 

**Item 1.  Identity of Directors, Senior Management and Advisers**

 

Not applicable.

 

**Item 2.  Offer Statistics and Expected Timetable**

 

Not applicable.

 

**Item 3.  Key Information**

 

**A.**                                    **Selected Financial Data**

 

The following tables set forth summary historical financial data for the periods indicated. The consolidated statement of operations data for the years ended December 31, 2016, 2015 and 2014 and the balance sheet information as of December 31, 2016 and 2015 have been derived from, and should be read in conjunction with, the audited consolidated financial statements and notes thereto set forth beginning on page F-1 of this annual report. The selected consolidated statement of operations data for the year ended December 31, 2013, the six-month period ended December 31, 2012 and the year ended June 30, 2012 and the consolidated balance sheet information as at December 31, 2014, 2013, 2012 and June 30, 2012 are derived from the audited consolidated financial statements not appearing in this Annual Report. This data should be read in conjunction with the financial statements, related notes and other financial information included elsewhere herein. Our historical results do not necessarily indicate our expected results for any future periods.

 

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

 
| ** **                                    | ** ** | **Year ended December 31,** | ** ** | **Six-month   period ended   December 31,** | ** ** | **Year ended   June 30,** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------|------------|-------------------------------------|------------|
| **(In $ ‘000s)**               | ** ** | **2016**                                   | ** ** | **2015**                                              | ** ** | **2014**                            | ** ** | **2013** | ** ** | **2012** | ** ** | **2012** | ** ** |
| ** **                                    | ** ** | ** **                                 | ** ** | **Restated(1)**                                       | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Statement of Profit   or Loss:**            |       |                                       |       |                                                  |       |                                |       |   |   |   |   |   |   |
| Revenues:                                     |       |                                       |       |                                                  |       |                                |       |   |   |   |   |   |   |
| Oil revenue                                   |       | $                                          | 57,296     |                                                  | $          | 82,949                              |       | $ | 144,994 |   | $ | 79,365 |   | $ | 16,790 |   | $ | 27,965 |   |
| Natural gas revenue                           |       | 4,937                                      |       | 4,720                                                 |       | 6,161                               |       | 2,774 |   | 934 |   | 1,822 |   |
| Natural gas liquids (NGL) (2)                 |       | 4,376                                      |       | 4,522                                                 |       | 8,638                               |       | 3,206 |   | — |   | — |   |
| **Total oil and   natural gas revenues**      |       | 66,609                                     |       | 92,191                                                |       | 159,793                             |       | 85,345 |   | 17,724 |   | 29,787 |   |
| Lease operating and production   tax expenses |       | 17,137                                     |       | 24,498                                                |       | 20,489                              |       | 18,383 |   | 4,082 |   | 6,355 |   |
| Depreciation and amortization   expense       |       | 48,147                                     |       | 94,584                                                |       | 85,584                              |       | 36,225 |   | 6,116 |   | 11,111 |   |
| General and administrative   expense          |       | 12,110                                     |       | 17,176                                                |       | 15,527                              |       | 15,297 |   | 5,810 |   | 6,863 |   |
| Finance costs, net of interest   income       |       | 12,219                                     |       | 9,418                                                 |       | (494                                | )          | (351 | ) | 578 |   | (111 | ) |
| Loss on debt extinguishment                   |       | —                                     |       | 1,451                                                 |       | —                              |       | — |   | — |   | — |   |
| Impairment of non-current assets              |       | 10,203                                     |       | 321,918                                               |       | 71,212                              |       | — |   | — |   | 357 |   |
| Exploration and evaluation   expenditure      |       | 30                                         |       | 7,925                                                 |       | 10,934                              |       | — |   | — |   | — |   |
| Gain on sale of non-current   assets          |       | —                                     |       | (790                                                  | )          | (48,604                             | )          | (7,335 | ) | (122,327 | ) | (3,004 | ) |
| (Gain) / loss on commodity   hedging          |       | 12,761                                     |       | (15,256                                               | )          | (11,009                             | )          | 554 |   | (639 | ) | (1,945 | ) |
| Realized currency loss                        |       | —                                     |       | —                                                |       | —                              |       | — |   | — |   | 4 |   |
|                                               |            |                                            |            |                                                       |            |                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

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| ** **                                                             | ** ** | **Year ended December 31,** | ** ** | **Six-month   period ended   December 31,** | ** ** | **Year ended   June 30,** | ** ** |
|------------------------------------------------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------|------------|-------------------------------------|------------|
| **(In $ ‘000s)**                                        | ** ** | **2016**                                   | ** ** | **2015**                                              | ** ** | **2014**                            | ** ** | **2013** | ** ** | **2012** | ** ** | **2012** | ** ** |
| ** **                                                             | ** ** | ** **                                 | ** ** | **Restated (1)**                                 | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Other (income) expense                                                 |       | (2,009                                     | )          | —                                                |       | 686                                 |       | 1,063 |   | — |   | — |   |
| Income tax expense (benefit)                                           |       | 1,705                                      |       | (107,138                                              | )          | (841                                | )          | 5,567 |   | 46,616 |   | 4,145 |   |
| **Profit (loss)   attributable to owners of Sundance**                 |       | $                                          | (45,694    | )                                                     | $          | (263,835                            | )          | $ | 15,321 |   | $ | 15,942 |   | $ | 76,210 |   | $ | 6012 |   |
|                                                                   |       |                                       |       |                                                  |       |                                |       |   |   |   |   |   |   |
| **Other comprehensive   income (loss)**                                |       |                                       |       |                                                  |       |                                |       |   |   |   |   |   |   |
| Exchange differences arising on   translation of foreign operations    |       | (532                                       | )          | (478                                                  | )          | 684                                 |       | (421 | ) | (154 | ) | (274 | ) |
| Total comprehensive income (loss)   attributable to owners of Sundance |       | $                                          | (46,226    | )                                                     | $          | (264,313                            | )          | $ | 16,005 |   | $ | 15,521 |   | $ | 76,056 |   | $ | 5,765 |   |
| Basic and diluted earnings (loss)   per share                          |       | $                                          | (0.05      | )                                                     | $          | (0.48                               | )          | $ | 0.03 |   | $ | 0.04 |   | $ | 0.27 |   | $ | 0.02 |   |
| Basic weighted average number of   ordinary shares outstanding         |       | 870,582,898                                |       | 552,847,289                                           |       | 531,391,405                         |       | 413,872,184 |   | 277,244,883 |   | 277,049,463 |   |
| **Other Supplementary   Data:**                                        |       |                                       |       |                                                  |       |                                |       |   |   |   |   |   |   |
| **Adjusted EBITDAX(3)**                                                |       | $                                          | 47,863     |                                                  | $          | 64,781                              |       | $ | 126,373 |   | $ | 52,594 |   | $ | 9,223 |   | $ | 17,093 |   |

 

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(1)           The Company filed an amendment to its Form 20-F for the fiscal year ended December 31, 2015 to correct an identified accounting error related to its income tax benefit and deferred tax liabilities.  The restated amounts are reflected in the table above.  Refer to Item 18, Note 7 for additional discussion.

 

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

 

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

 
| ** **                                          | ** ** | **December 31,** | ** ** | **Six month********period ended   December 31** | ** ** | **Year ended********June 30** | ** ** |
|-----------------------------------------------------|------------|-----------------------|------------|----------------------------------------------------------------|------------|-----------------------------------------|------------|
| **(In $ ‘000s)**                     | ** ** | **2016**              | ** ** | **2015**                                                       | ** ** | **2014**                                | ** ** | **2013** | ** ** | **2012** | ** ** | **2012** | ** ** |
| ** **                                          | ** ** | ** **            | ** ** | **Restated(1)**                                                | ** ** | ** **                              | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Statement of   Financial Position Data:**         |       |                  |       |                                                           |       |                                    |       |   |   |   |   |   |   |
| Cash and cash equivalents                           |       | $                     | 17,463     |                                                           | $          | 3,468                                   |       | $ | 69,217 |   | $ | 96,871 |   | $ | 154,110 |   | $ | 15,328 |   |
| Assets held for sale                                |       | 18,309                |       | 90,632                                                         |       | —                                  |       | 11,484 |   | — |   | — |   |
| Total current assets                                |       | 58,840                |       | 125,345                                                        |       | 114,045                                 |       | 141,141 |   | 175,424 |   | 30,691 |   |
| Oil and natural gas properties:                     |       |                  |       |                                                           |       |                                    |       |   |   |   |   |   |   |
| Development and production assets                   |       | 338,709               |       | 250,922                                                        |       | 519,013                                 |       | 312,230 |   | 79,729 |   | 87,274 |   |
| Exploration and evaluation   expenditure            |       | 34,366                |       | 26,323                                                         |       | 155,130                                 |       | 166,144 |   | 33,439 |   | 11,436 |   |
| Total assets                                        |       | 432,088               |       | 409,835                                                        |       | 796,520                                 |       | 625,060 |   | 291,435 |   | 130,316 |   |
| Current liabilities                                 |       | 31,820                |       | 42,215                                                         |       | 119,324                                 |       | 140,862 |   | 51,842 |   | 30,393 |   |
| Credit facilities, net of   deferred financing fees |       | 188,249               |       | 187,743                                                        |       | 128,805                                 |       | 29,141 |   | 29,570 |   | 14,655 |   |
| Restoration provision                               |       | 7,072                 |       | 3,088                                                          |       | 8,866                                   |       | 5,074 |   | 1,228 |   | 588 |   |
| Deferred tax liabilities                            |       | —                |       | —                                                         |       | 102,668                                 |       | 102,711 |   | 56,979 |   | 10,476 |   |
| Total non-current liabilities                       |       | 202,445               |       | 191,251                                                        |       | 242,190                                 |       | 136,957 |   | 87,777 |   | 25,719 |   |
| Total liabilities                                   |       | 234,265               |       | 233,466                                                        |       | 361,514                                 |       | 277,819 |   | 139,619 |   | 56,112 |   |
| Net assets                                          |       | 197,823               |       | 176,369                                                        |       | 435,006                                 |       | 347,241 |   | 151,816 |   | 74,204 |   |
| Issued capital                                      |       | 373,585               |       | 308,429                                                        |       | 306,853                                 |       | 237,008 |   | 58,694 |   | 57,978 |   |
|                                                     |            |                       |            |                                                                |            |                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)           The Company filed an amendment to its Form 20-F for the fiscal year ended December 31, 2015 to correct an identified accounting error related to its income tax benefit and deferred tax liabilities.  The restated amounts are reflected in the table above.  Refer to Item 18, Note 7 for additional discussion.

 

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| ** **                                            | ** ** | **Year ended December 31,,** | ** ** | **Six month   period ended   December 31,** | ** ** | **Year ended   June 30,** | ** ** |
|-------------------------------------------------------|------------|---------------------------------------------|------------|------------------------------------------------------------|------------|-------------------------------------|------------|
| **(In $ ‘000s)**                       | ** ** | **2016**                                    | ** ** | **2015**                                                   | ** ** | **2014**                            | ** ** | **2013** | ** ** | **2012** | ** ** | **2012** | ** ** |
|                                                  |       |                                        |       |                                                       |       |                                |       |   |   |   |   |   |   |
| **Net Cash Flow Data:**                               |       |                                        |       |                                                       |       |                                |       |   |   |   |   |   |   |
| Net cash provided by operating   activities           |       | $                                           | 42,660     |                                                       | $          | 64,469                              |       | $ | 128,087 |   | $ | 62,646 |   | $ | 9,386 |   | $ | 11,832 |   |
| Net cash (used in) provided by   investing activities |       | (79,991                                     | )          | (180,771                                                   | )          | (323,235                            | )          | (164,355 | ) | 114,571 |   | (36,149 | ) |
| Net cash provided by financing   activities           |       | 51,776                                      |       | 50,403                                                     |       | 167,595                             |       | 44,455 |   | 14,846 |   | 14,734 |   |
|                                                       |            |                                             |            |                                                            |            |                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

***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, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring income/expense items.

 

Our management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance, identify operating trends (which may otherwise be masked by the excluded items) and compare the results of our operations from period to period without regard to our financing policies and 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 policies and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with IFRS, as issued by the IASB, or as an indicator of our operating performance or liquidity.

 

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

 

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

 
| ** **                                                | ** ** | **Year ended December 31,** | ** ** | **Six month   period ended   Decmber 31,** | ** ** | **Year ended   June 30,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|-----------------------------------------------------------|------------|-------------------------------------|------------|
| **(In $ ‘000s)**                           | ** ** | **2016**                                   | ** ** | **2015**                                                  | ** ** | **2014**                            | ** ** | **2013** | ** ** | **2012** | ** ** | **2012** | ** ** |
| ** **                                                | ** ** | ** **                                 | ** ** | **Restated (1)**                                     | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **IFRS Net Profit   Reconciliation to Adjusted EBITDAX:** |       |                                       |       |                                                      |       |                                |       |   |   |   |   |   |   |
| Profit (loss) attributable to   owners of Sundance        |       | $                                          | (45,694    | )                                                         | $          | (263,835                            | )          | $ | 15,321 |   | $ | 15,942 |   | $ | 76,210 |   | $ | 6,012 |   |
| Income tax (benefit) expense                              |       | 1,705                                      |       | (107,138                                                  | )          | (841                                | )          | 5,567 |   | 46,616 |   | 4,145 |   |
| Finance costs, net of (interest   received)               |       | 12,219                                     |       | 9,418                                                     |       | 494                                 |       | (232 | ) | 578 |   | (111 | ) |
| Loss on debt extinguishment                               |       | —                                     |       | 1,451                                                     |       | —                              |       | — |   | — |   | — |   |
| Loss (gain) on commodity hedging                          |       | 12,761                                     |       | (15,256                                                   | )          | (10,792                             | )          | 554 |   | 639 |   | (1,945 | ) |
| Settlement of commodity hedging                           |       | 8,672                                      |       | 12,404                                                    |       | 1,150                               |       | 283 |   | 551 |   | (297 | ) |
| Depreciation and amortization   expense                   |       | 48,147                                     |       | 94,584                                                    |       | 85,584                              |       | 36,225 |   | 6,116 |   | 11,111 |   |
| Impairment of non-current assets                          |       | 10,203                                     |       | 321,918                                                   |       | 71,212                              |       | — |   | — |   | 357 |   |
| Exploration expense                                       |       | 30                                         |       | 7,925                                                     |       | 10,934                              |       | — |   | — |   | — |   |
| Share based compensation, value   of services             |       | 2,524                                      |       | 4,100                                                     |       | 1,915                               |       | 1,590 |   | 840 |   | 825 |   |
| Gain on sale of non-current   assets                      |       | —                                     |       | (790                                                      | )          | (48,604                             | )          | (7,335 | ) | (122,327 | ) | (3,004 | ) |
| Other income, net (2)                                     |       | (2,704                                     | )          | —                                                    |       | —                              |       | — |   | — |   | — |   |
| **Adjusted EBITDAX**                                      |       | $                                          | 47,863     |                                                      | $          | 64,781                              |       | $ | 126,373 |   | $ | 52,594 |   | $ | 9,223 |   | $ | 17,903 |   |

 

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(1) The Company filed an amendment to its Form 20-F for the fiscal year ended December 31, 2015 to correct an identified accounting error related to its income tax benefit and deferred tax liabilities. The restated amounts are reflected in the table above. Refer to Item 18, Note 7 for additional discussion.

 

(2) Includes non-recurring proceeds from an insurance settlement of $2.4 million and a litigation settlement of $1.2 million, offset by restructuring charges of $(0.8) million and other $(0.1) million for the year ended December 31, 2016.

 

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**B.**                                    **Capitalization and Indebtedness**

 

Not applicable.

 

**C.**                                    **Reasons for Offer and Use of Proceeds**

 

Not applicable.

 

**D.**                                    **Risk Factors**

 

**Risks Related to the Oil and Natural Gas Industry and Our Business**

*** ***

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

 

Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the markets for oil, natural gas and NGLs have been volatile, and we expect this volatility to continue.  For example, average daily prices for NYMEX-WTI crude oil ranged from a high of $54.01 per barrel to a low of $26.19 per barrel during 2016. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include:

 

·                  general worldwide and regional economic and political conditions;

 

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

 

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

 

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

 

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

 

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

 

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

 

·                  weather conditions and natural disasters;

 

·                  domestic and foreign governmental laws, regulations and taxes;

 

·                  volatile trading patterns in commodities futures markets;

 

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

 

·                  shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas and related infrastructure;

 

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

 

·                  technological advances affecting energy consumption; and

 

·                  the price and availability of alternative fuels.

 

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 63% and 17% of our estimated proved reserves as of December 31, 2016 were attributed to oil and NGLs, 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.

 

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

 

·                  reducing our revenues, operating income and cash flows;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

As of December 31, 2016, we have commodity price hedging agreements on approximately 40% of our expected Boe production for 2017. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil, natural gas and NGLs that could materially and adversely affect our business and results of operations.

 

***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. 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.

 

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

 

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:

 

·                  lack of prospective acreage available on acceptable terms;

 

·                  unexpected or adverse drilling conditions;

 

·                  elevated pressure or irregularities in geologic formations;

 

·                  equipment failures or accidents;

 

·                  adverse weather conditions;

 

·                  title problems;

 

·                  limited availability of financing upon acceptable terms;

 

·                  reductions in oil, natural gas and NGL prices;

 

·                  compliance with governmental requirements; and

 

·                  shortages or delays in the availability of drilling rigs, equipment and personnel.

 

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Even if our exploration, development and drilling efforts are successful, our wells, once completed, may not produce reserves of oil, natural gas or NGLs 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 annual report.

 

***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, natural gas and NGL reserves. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We intend to finance our development plan in 2017 primarily with cash flows from operations and our previously announced Mississippian/Anadarko asset sale, but we may also finance our future capital expenditures through a variety of other sources, including through borrowings under available credit facilities, additional asset sales, or through the issuance of debt and/or equity, which may alter or increase our capitalization substantially.

 

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

 

·                  our proved reserves;

 

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

 

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

 

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

 

·                  global credit and securities markets;

 

·                  our ability to acquire, locate and produce new reserves and the cost of such reserves; and

 

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

 

If our revenues or the amounts we can borrow under available 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 terms acceptable to us, 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.

 

***Our level of indebtedness may reduce our financial flexibility.***

 

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

 

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

 

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

 

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

 

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

 

·                  any debt that we incur under our existing senior secured revolving credit facility will be at variable rates, which could make us vulnerable to an increase in interest rates.

 

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

 

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

 

·                  well blowouts;

 

·                  mechanical failures;

 

·                  fires and explosions;

 

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

 

·                  uncontrollable flows of oil, natural gas or well fluids;

 

·                  geologic formations with abnormal pressures;

 

·                  handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;

 

·                  pipeline ruptures or spills;

 

·                  inclement weather;

 

·                  releases of toxic gases; and

 

·                  other environmental hazards and risks (including groundwater contamination).

 

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims, regulatory investigation, penalties and suspension of operation 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.

 

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

 

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

 

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frame, or if oil and natural gas prices decrease, making the PUDs uneconomic.  Lower PV-10 value, resulting from fewer PUDs  may negatively impact investor perception of our Company.

 

***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:

 

·                  landing our well bore in the desired formation;

 

·                  staying in the desired formation while drilling horizontally through the formation;

 

·                  running our casing the entire length of the well bore; and

 

·                  being able to run tools and other equipment consistently through the well bore.

 

Risks that we face while completing our wells include, but are not limited to:

 

·                  being able to fracture stimulate the planned number of stages;

 

·                  being able to run tools the entire length of the well bore during completion operations; and

 

·                  successfully cleaning out the well bore after completion of the final fracture stimulation stage.

 

The results of our drilling in new or emerging formations 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 does not meet our anticipated results 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:

 

·                  ongoing review and analysis of geologic and engineering data;

 

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

 

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

 

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

 

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

 

·                  additional due diligence;

 

·                  regulatory requirements and restrictions; and

 

·                  the opportunity to divert our drilling budget to preferred prospects.

 

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

 

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing properties. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

 

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

 

***The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.***

 

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

 

***Development of our PUDs may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.***

 

As of December 31, 2016, approximately 58% of our total proved reserves were proved undeveloped.  These reserve estimates reflected our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves.  Our approximately 17.0 MMBoe of estimated proved undeveloped reserves will require an estimated $247.4 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves as unproved reserves.

 

Further, our reserves data assumes that we can and will make these expenditures and that these operations will be conducted successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write them off. Any such write-offs of our reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.

 

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

 

Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established. For these properties, if production in commercial quantities has not been established on the leased property or units that include the leased property containing these leases, our leases will expire and we will lose our right to develop the related properties. As of December 31, 2016, 24,740 net acres of our total acreage position were not held by production. For the acreage underlying such properties, if production in paying quantities is not established on units containing these leases, approximately 5,726 net acres will expire in 2017, and approximately 19,014 net acres will expire in 2018.

 

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.

 

***Our producing properties are located primarily in Eagle Ford, making us vulnerable to risks associated with operating in a limited number of geographic areas.***

 

Following the completion of the previously announced dispositions of our assets located in the Anadarko basin and  Mississippian/Woodford formations, all of our producing properties will be geographically concentrated in the Eagle Ford area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs, any of which could adversely affect our business, results of operations and financial condition.

 

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

 

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

 

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

 

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

 

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

 

·                  the operator may not approve of other participants in drilling wells;

 

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

 

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

 

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Any of these events could significantly and adversely affect our anticipated exploration and development activities. Under our joint operating agreements, we will be required to pay our percentage interest share of all costs and liabilities incurred by the operator on behalf of the working interest owners in connection with joint venture activities. In common with other working interest owners, if we fail to pay our share of any costs and liabilities, we may be deemed to have elected non-participation with respect to operations affected and we may be subject to loss of interest through foreclosure of operator liens invoked by participating working interest owners which may subject us to non-consent penalties. We operated 87.1% of our total production for the year ended December 31, 2016.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The capitalized costs of our oil and natural gas properties, on an area of interest basis, cannot exceed the estimated discounted future net cash flows of that area of interest. If net capitalized costs exceed discounted future net revenues, we generally must write down the costs of each area of interest to the estimated discounted future net cash flows of that area of interest. We incurred impairment of development and production properties expense and impairment of exploration and evaluation expenditures properties expense totaling $2.3 million and $7.9 million, respectively, during 2016 and $184.4 million and $137.2 million, respectively, during 2015.

 

Commodity prices significantly declined in 2015 and 2016. Continued declines in the prices of crude oil, natural gas, or NGLs or unsuccessful exploration efforts could cause additional development and production and/or exploration and evaluation expenditure property impairments in the future.

 

 

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

 

The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and natural gas reserves. As required by the current requirements for oil and natural gas reserve estimation and disclosures, the estimated discounted future net cash flows from proved reserves are based on the average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:

 

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

 

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

 

·                  the amount and timing of actual production;

 

·                  supply and demand for oil and natural gas;

 

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

 

·                  changes in governmental regulations or taxation.

 

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

 

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

 

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

 

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we are unable to market and sustain production from a particular lease for an extended period of time, possibly resulting in the loss of a lease due to the lack of commercially established production.

 

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

 

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

 

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

 

Our Credit Agreement provides for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and a term loan of $125 million (the “Term Loan”).  Our Revolving Facility had a borrowing base of $67 million as of the date of this report, which was fully drawn.  As of the date of this report, we did not have any incremental borrowing capacity under our Credit Agreement.

 

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

 

At December 31, 2016, we had approximately $18.3 million of assets classified held for sale, certain of which were included in the borrowing base value under our Credit Agreement.  Upon the sale of these assets, our lenders may elect to reduce the then effective borrowing base by an amount equal to the value attributed to those assets if the value of the remaining assets doesn’t meet the prescribed asset coverage thresholds.  If the valuation was unchanged at the time of the sale, the lender could elect to require repayment of that pro rata portion of the outstanding debt.  That being said, there are many variables that affect the lender’s determination of borrowing base value at any point in time and therefore it is difficult for management to estimate the borrowing base value in the future so the amount that would be required to be repaid, if any, is uncertain.

 

***Our Credit Agreement has substantial restrictions and financial covenants that restrict our business and financing activities.***

 

The operating and financial restrictions and covenants in our Credit Agreement 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 Agreement, our indebtedness may become immediately due and payable, the interest rates under our Credit Agreement 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 Agreement are accelerated and become immediately due and payable, we may not have the funds to repay, or the ability to refinance, such outstanding amounts and our lenders could foreclose upon critical assets.  As a result, we may be unable to complete any further development of our properties and it may affect our ability to continue as a going concern. For a description of our credit facilities, please see Item 5.B. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—*Credit Facilities*.”

 

***Increased costs of capital could adversely affect our business.***

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·                  our ability to obtain leases or options on properties;

 

·                  our ability to identify and acquire new exploratory prospects;

 

·                  our ability to develop existing prospects;

 

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

 

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

 

·                  the results of our drilling programs;

 

·                  commodity prices; and

 

·                  our access to capital.

 

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

 

***We may incur losses as a result of title deficiencies.***

 

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

 

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

 

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

 

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially dangerous working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. In March 2016, the Occupational Safety and Health Administration (“OSHA”) issued a final rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. Compliance with the rule may require significant investment in engineering and workplace controls.  If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

 

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

 

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

 

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

 

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

 

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

 

·                  restrictions on wastewater disposal activities;

 

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

 

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

 

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

 

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

 

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On March 20, 2015, the Bureau of Land Management (“BLM”) issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. On June 21, 2016, however, the U.S. District Court for the District of Wyoming enjoined BLM from enforcing the regulations, concluding that the agency lacked the authority to issue them. BLM appealed that decision to the U.S. Court of Appeals for the Tenth Circuit. The appeal is pending.

 

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 may 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. On June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on shore unconventional oil and gas extraction facilities to publicly owned treatment works.  EPA’s regulation of hydraulic fracturing may result in our incurring additional costs to comply with such requirements that may be significant in nature.  Such regulation may result in our experiencing delays or curtailment in the pursuit of exploration, development, or production activities, and we could even be prohibited from drilling and/or completing certain wells.

 

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

 

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

 

***Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.***

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGL services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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

 

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

 

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

 

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

 

 

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

 

In addition, as discussed in more detail below, the EPA finalized its New Source Performance Standard (“NSPS”) rule regulating carbon dioxide from new, modified and reconstructed fossil fuel-fired power plants and the Clean Power Plan for existing fossil fuel-fired power plants.  While these rules will more negatively impact coal-fired power plants, natural gas-fired power plants may also face liability under the rules and increased costs of operation. The Trump Administration is currently reviewing the Obama era climate regulations, and the President has stated an interest in easing the regulations.

 

In May 2016, the EPA issued final regulations intended to reduce methane emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025.   On October 20, 2016, EPA issued final Control Techniques Guidelines for reducing smog-forming VOC emissions from existing oil and natural gas equipment and processes in certain states and areas with smog problems. The methane regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, these new developments could result in increased costs of operation and exposure to liability.

 

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

 

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

 

***Terrorist attacks aimed at energy operations could adversely affect our business.***

 

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, customer facilities, the infrastructure depended upon for transportation of products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

 

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

 

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

 

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

 

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

 

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

 

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

 

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), which requires the SEC and the Commodity Futures Trading Commission (“CFTC”) to promulgate rules and regulations implementing the legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed new regulations to set position limits for certain futures, options and swap contracts in designated physical commodities, including, among others, oil and natural gas. Certain bona fide hedging transactions positions would be exempt from the position limits as currently proposed. It is not possible at this time to predict when the CFTC will finalize these regulations or whether the proposed rules will be modified prior to becoming effective, so the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and CFTC rules have also designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent that we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with the clearing and exchange trading requirements or to take steps to qualify for an exemption to such requirements. In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, we could be required to post initial or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows.

 

Other regulations to be promulgated under the Dodd-Frank Act also remain to be finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act 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. Further, to the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows. In addition, non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

 

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*** ***

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

 

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

 

·                  recoverable reserves;

 

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

 

·                  development and operating costs; and

 

·                  potential environmental and other liabilities.

 

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

 

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

 

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

 

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

 

·                  difficulty associated with coordinating geographically separate organizations; and

 

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

 

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

 

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

 

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

 

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, as well as conduct reservoir modeling and reserve estimation for compliance reporting.

 

We are dependent on digital technologies including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees, business partners, and shareholders, analyze seismic and drilling information, estimate quantities of oil and natural gas reserves as well as other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology. The technologies needed to conduct oil and natural gas exploration, development and production activities make certain information the target of theft or misappropriation.

 

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As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for the purposes of misappropriating assets or sensitive information, corrupting data, causing operational disruption, or result in denial-of-service on websites.

 

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period of time. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations.

 

***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.***

 

In past years, legislation has been proposed from time to time that contains proposals to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These proposals include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. The Trump Administration has called for a comprehensive tax reform that would significantly change U.S. tax laws. It is unclear whether any of the foregoing proposals will actually be considered and enacted as part of tax reform legislation or how soon any such changes in law could become effective. The passage of any legislation as a result of these proposals or any other similar change in U.S. federal income tax law could eliminate and/or defer certain tax deductions that are currently available with respect to oil and natural gas exploration and production. Any such change could materially adversely affect our business, financial condition and results of operations by increasing the after-tax costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

 

**Risks Related to our Shares and ADSs**

 

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

 

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

 

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

 

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

 

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

 

·                  changes in commodity prices for oil, natural gas and NGLs we produce;

 

·                  changes in market valuations of similar companies;

 

·                  changes in our key personnel;

 

·                  changes in financial estimates or recommendations by securities analysts;

 

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

 

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

 

·                  announcements by us or competitors of significant acquisitions, strategic partnerships, joint ventures, or capital commitments;

 

·                  actions taken by our lenders;

 

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

 

·                  conditions in the financial markets or changes in general economic conditions; and

 

·                  the other factors described in this “Risk Factors” section.

 

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

 

Our ADSs are traded on NASDAQ, and the underlying ordinary shares are traded on the ASX. 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 maintenance of an active trading market for ADSs in the United States. The price of our ADSs could also be adversely affected by trading in our ordinary shares on the ASX. Although our ordinary shares are currently listed on the ASX, we may decide at some point in the future to delist our ordinary shares from the ASX, and our shareholders may approve such delisting. We cannot predict the effect such delisting of our ordinary shares on the ASX would have on the market price of our ADSs on NASDAQ.

 

***The sale or availability for sale of substantial amounts******of our ordinary shares or ADSs could adversely affect their market price.***

 

Sales of our ordinary shares or ADSs in the public market, or the perception that these sales could occur, could cause the market price of our ordinary shares or ADSs to decline. As of April 10, 2017, we had 1,249,351,617 ordinary shares outstanding, with 7,917,988 of our ordinary shares being held in the United States by 65 holders of record and 1,204,317,759 of our ordinary shares being held in Australia by 4,211 holders of record. Among these shares, 52,969,100 ordinary shares are in the form of ADSs, which are freely transferable without restriction or additional registration under the Securities Act. The remaining ordinary shares and ADSs outstanding are, subject to the applicable requirements of Rule 144 under the Securities Act, available for sale. Sales, or perceived potential sales, by our existing shareholders and ADSs might make it more difficult for us to issue new equity or equity-related securities in the future at such a time and place as we deem appropriate.

 

While our ADSs are listed on NASDAQ, trading is limited, sporadic and volatile.  There is no assurance that an active trading market in our ADSs will develop in the United States, or if such a market develops, that it will be sustained. As a result, an investor may find it more difficult to dispose of, or to obtain accurate quotations as to the market value of, our ADSs in the United States.

 

***ADSs represent only a relatively small percentage of our ordinary shares,  which may limit the liquidity of the ADSs and have a negative impact on the price of the ADSs.***

 

ADSs represent only a relatively small number of our ordinary shares actively traded in public markets. Limited liquidity may increase the volatility of the prices of our ADSs and the underlying ordinary shares.

 

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***Future sales and issuances of our ADSs or rights to purchase ADSs and any equity financing that we pursue, could result in significant dilution of the percentage ownership of our shareholders and could cause our ADS price to fall.***

 

To the extent we raise additional capital by issuing equity securities, our shareholders may experience substantial dilution. In any financing transaction, we may sell ordinary shares or ADSs, convertible securities or other equity securities. If we sell ordinary shares or ADSs, convertible securities or other equity securities, our shareholders and ADS holders investment in our ordinary shares or ADSs will be diluted. These sales may also result in material dilution to our existing shareholders and ADS holders, and new investors could gain rights superior to our existing shareholders and ADS holders.

 

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

 

The Bank of New York Mellon, as depositary, executes and delivers ADSs on our behalf. Each ADS is a certificate evidencing a specific number of ADSs. ADS holders will not be treated as shareholders and do not have the rights of shareholders. The depositary will be the holder of the shares underlying the ADSs. Holders of our ADSs will have ADS holder rights. A deposit agreement among us, the depositary and the ADS holders, and the beneficial owners of 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 and Australian law and our Constitution govern shareholder rights.

 

ADS holders do not have the same rights to receive dividends or other distributions as our shareholders. Subject to any special rights or restrictions attached to a share, the directors may determine that a dividend will be payable on a share and fix the amount, the time for payment and the method for payment (although we have never declared or paid any cash dividends on our ordinary shares and we do not anticipate paying any cash dividends in the foreseeable future). Dividends and other distributions payable to our shareholders with respect to our ordinary shares generally will be payable directly to them. Any dividends or distributions payable with respect to ordinary shares underlying ADSs will be paid to the depositary, which has agreed to pay to the 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. The ADS holders will receive these distributions in proportion to the number of shares their ADSs represent. In addition, there may be certain circumstances in which the depositary may not pay to the ADS holders amounts distributed by us as a dividend or distribution.

 

***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.***

 

Holders of our ADSs (and not the ordinary shares underlying ADSs) will not be treated as one of our shareholders and will not have shareholder rights. The ADR depositary will be the holder of the ordinary shares underlying ADSs, and ADS holders will only be able to exercise voting rights with respect to the ordinary shares represented by ADSs in accordance with the deposit agreement relating to our 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.

 

***You may be subject to limitations on transfer of our ADSs.***

 

Our ADSs are transferable on the books of the depositary. However, the depositary may close its books at any time or from time to time when it deems expedient in connection with the performance of its duties. The depositary may close its books from time to time for a number of reasons, including in connection with corporate events such as a rights offering, during which time the depositary needs to maintain an exact number of ADS holders on its books for a specified period. The depositary may also close its books in emergencies, and on weekends and public holidays. The depositary may refuse to deliver, transfer or register transfers of our ADSs generally when our share register or the books of the depositary are closed, or at any time if we or the depositary thinks it is advisable to do so because of any requirement of law or of any government or governmental body, or under any provision of the deposit agreement, or for any other reason.

 

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***Your rights to pursue claims against the depositary as a holder of ADSs are limited by the terms of the deposit agreement.***

 

Under the deposit agreement, any action or proceeding against or involving the depositary, arising out of or based upon the deposit agreement or the transactions contemplated thereby may only be instituted in a state or federal court in New York, New York, and pursuant to the deposit agreement, holders of our ADSs have irrevocably waived any objection which they may have to the laying of venue of any such proceeding, and irrevocably submitted to the exclusive jurisdiction of such courts in any such suit, action or proceeding. Notwithstanding the foregoing, however, the depositary may, in its sole discretion, require that any such action, controversy, claim, dispute, legal suit or proceeding be referred to and finally settled by an arbitration conducted under the terms described in the deposit agreement subject to certain exceptions solely related to the aspects of such claims that are related to U.S. securities law, in which case the resolution of such aspects may, at the option of such registered holder of the ADSs, remain in state or federal court in New York, New York. The deposit agreement may also be amended without the consent of the ADS holders without their consent. Holders of our ADSs will be bound to any such amendment to the deposit agreement.

 

***Fluctuations in the exchange rate between the U.S. dollar and the Australian dollar may increase the risk of holding our ADSs.***

 

Our ordinary shares currently trade on the ASX in Australian dollars, while our ADSs trade on NASDAQ in U.S. dollars. Fluctuations in the exchange rate between the U.S. dollar and the Australian dollar may result in differences between the value of our ADSs and the value of our ordinary shares, which may result in heavy trading by investors seeking to exploit such differences. In addition, as a result of fluctuations in the exchange rate between the U.S. dollar and the Australian dollar, the U.S. dollar equivalent of the proceeds that a holder of ADSs would receive upon the sale in Australia of any ordinary shares withdrawn from the depositary upon calculation of the corresponding ADSs and the U.S. dollar equivalent of any cash dividends paid in Australian dollars on our ordinary shares represented by ADSs could also decline.

 

***As a foreign private issuer whose ADSs are listed on NASDAQ, we may follow certain home country corporate governance practices instead of certain NASDAQ requirements.***

 

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. This allows us to follow certain corporate governance practices that differ in certain respects from the corporate governance requirements applicable to U.S. companies listed on NASDAQ. For example, we are exempt from regulations of NASDAQ that require listed companies organized in the United States to:

 

·                  have a majority of the board of directors consist of independent directors;

 

·                  require non-management directors to meet on a regular basis without management present;

 

·                  require an issuer to provide for a quorum in its by-laws for any meeting of shareholders that is not less than 33 1/3% of the outstanding shares of the company’s common voting stock; and

 

·                  seek shareholder approval for the implementation of certain equity compensation plans and issuances of ordinary shares.

 

As a foreign private issuer, we are permitted to, and do follow home country practices in lieu of the above requirements. Accordingly, our holders of ADSs and ordinary shares may not have the same protections afforded to shareholders of companies that are subject to these NASDAQ requirements.

 

***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.***

 

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

 

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Our management has concluded that our internal controls over financial reporting were effective as of December 31, 2016.  However, if we fail to maintain effective internal controls over financial reporting in the future, the presence of material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report. We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

 

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

 

***We may lose our foreign private issuer status in the future, which could result in significant additional costs and expenses.***

 

As a “foreign private issuer” we are not required to comply with all the periodic disclosure and current reporting requirements of the Securities Exchange Act of 1934, as amended (“Exchange Act”) and related rules and regulations. Under SEC rules, the determination of foreign private issuer status is made annually on the last business day of an issuer’s most recently completed second fiscal quarter and, accordingly, the next determination will be made with respect to us on June 30, 2017.

 

Since our operations are located in the U.S., we would lose our foreign private issuer status in the future if a majority of our ordinary shares (including those represented by ADSs) are owned by U.S. shareholders and a majority of our shareholders, directors or management are U.S. citizens or residents.  The regulatory and compliance costs to us under applicable U.S. securities laws as a U.S. domestic issuer may be significantly higher than our current regulatory and compliance costs. If we are not a foreign private issuer, we will be required to file periodic reports and registration statements on U.S. domestic issuer forms with the SEC, which are more detailed and extensive than the forms available to a foreign private issuer. For example, the annual report on Form 10-K requires domestic issuers to disclose executive compensation information on an individual basis with specific disclosure regarding the domestic compensation philosophy, objectives, annual total compensation (base salary, bonus, equity compensation) and potential payments in connection with change in control, retirement, death or disability, while the annual report on Form 20-F permits foreign private issuers to disclose compensation information on an aggregate basis. We will also have to report our results under U.S. Generally Accepted Accounting Principles, rather than under IFRS, as a domestic registrant. We will also have to mandatorily comply with U.S. federal proxy requirements, and our officers, directors and principal shareholders will become subject to the short-swing profit disclosure and recovery provisions of Section 16 of the Exchange Act. We may also be required to modify certain of our policies to comply with corporate governance practices required for U.S. domestic issuers. Such conversion and modifications will involve additional costs. In addition, we may lose our ability to rely upon exemptions from certain corporate governance requirements of the NASDAQ Stock Market that are available to foreign private issuers.

 

***We are an emerging growth company, and we cannot be certain if the reduced reporting requirements applicable to emerging growth companies will make our ordinary shares less attractive to investors.***

 

We are an emerging growth company, as defined in the JOBS Act. For as long as we continue to be an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We expect to continue to take advantage of some or all of the available exemptions. We cannot predict whether investors will find our ADSs less attractive if we rely on these exemptions. If some investors find our ADSs less attractive as a result, there may be a less active trading market for our ADSs and the market price of the ADSs may be more volatile.

 

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***We incur increased costs as a result of operating as a company with ADSs that are publicly traded in the United States, and our management is now required to devote substantial time to new compliance initiatives.***

 

As a company with ADSs that are publicly traded in the United States, and particularly after we are no longer an “emerging growth company,” we have incurred and will continue to incur significant legal, accounting and other expenses that we did not previously incur prior to our listing on NASDAQ. In addition, the Sarbanes-Oxley Act, the Dodd-Frank Act, the listing requirements of the NASDAQ Stock Market and other applicable securities rules and regulations impose various requirements on public companies, including establishment and maintenance of effective disclosure and financial controls and corporate governance practices. Our management and other personnel devote a substantial amount of time to these compliance initiatives. Moreover, these rules and regulations increase our legal and financial compliance costs and make some activities more time-consuming and costly.

 

However, for as long as we remain an emerging growth company, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. We may remain an emerging growth company until:

 

·                  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 $1.07 billion;

 

·                  the date on which we have issued more than $1 billion in non-convertible debt securities in any rolling three year period; or 

 

·                  December 31, 2020.

 

***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 ordinary shares or 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, 2016. 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, 2017. However, a separate determination is required after the close of each taxable year as to whether we are a PFIC. If our actual business results do not match our projections, it is possible that we may become a PFIC in the current or any future taxable year. A non-U.S. corporation will be considered a PFIC for a taxable year if either (i) at least 75% of its gross income is passive income or (ii) at least 50% of the value of its assets (based on an average of the quarterly values of the assets during the fiscal year) is attributable to assets that produce or are held for the production of passive income. If we are a PFIC for any taxable year during which a U.S. holder (as defined in Item 10.E. “Additional Information—Taxation—U.S. Federal Income Tax Considerations”) holds an ADS or an ordinary share, certain adverse U.S. federal income tax consequences could apply to such U.S. holder. See Item 10.E. “Additional Information—Taxation—U.S. Federal Income Tax Considerations—*Passive Foreign Investment Company*.”

 

***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 the price of our ordinary shares or ADSs appreciates.

 

***U.S. investors may have difficulty enforcing civil liabilities against us and our non-U.S. resident directors.***

 

We are a public limited company incorporated under the laws of Australia. Certain of our directors are non-residents of the United States and substantially all of their assets are located outside the United States.  As a result, it may not be possible to serve process on such persons or us in the United States or to enforce judgments obtained in U.S. courts against them or us based on civil liability provisions of the securities laws of the United States.

 

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

 

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

 

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

 

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

 

***We have broad discretion in the use of our cash and cash equivalents and may not use them effectively.***

 

Our management has broad discretion in the use of our cash and cash equivalents and could spend our funds in ways that do not improve our results of operations or enhance the value of our ADSs and ordinary shares. The failure by our management to apply these funds effectively could result in financial losses that could have a material adverse effect on our business, cause the market price of our ADSs and ordinary shares to decline and delay the development of our properties.

 

**Item 4.  Information on Sundance**

 

**A.**                                    **History and Development**

 

Sundance Energy Australia Limited, a public onshore oil and natural gas company, 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 ASX under the symbol “SEA.”  In September 2016, we implemented a sponsored ADR program with The Bank of New York Mellon. Our ADSs are listed on NASDAQ under the symbol “SNDE.”  Eash ADR represents 100 of our ordinary shares.

 

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 annual report. 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.

 

We are an onshore oil and natural gas company focused on the exploration, development and production of large, repeatable resource plays, primarily in south Texas targeting the Eagle Ford formation (“Eagle Ford”).

 

***Acquisitions***

 

In December 2016, we acquired approximately 130 net acres in McMullen County, Texas, which included 23 gross (1.5 net) producing wells (primarily Sundance-operated), for consideration of $7.2 million.

 

In July 2016, we acquired approximately 5,050 net acres in McMullen County, Texas, which included 26 gross (9.1 net) producing wells (primarily Sundance-operated), for consideration of $15.9 million.

 

In August 2015, we acquired approximately 5,500 net acres in Atascosa County, Texas, which included 7 gross producing wells and 2 wells that had been drilled but not yet completed (one of such wells was subsequently completed by the Company) for consideration of $16.4 million. The acquisition also included a 17.5 percent working interest in the PEL 570 concession in the Cooper Basin in Australia.  We plan to dispose of the PEL570 assets as these assets are not core to our business.

 

In January 2015, we acquired three leases totaling approximately 14,180 net acres in the Eagle Ford for approximately $13.4 million.

 

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In July 2014, we acquired the working interests in approximately 9,200 gross (5,700 net) and 18,000 gross (5,400 net) mineral acres in Dimmit and Maverick Counties, Texas, respectively for a purchase price of approximately $36 million.

 

In April 2014, we acquired approximately 4,800 net acres in the Eagle Ford for an initial purchase price of approximately $10.5 million.

 

***Divestitures***

 

On March 1, 2017, we executed a Purchase and Sale Agreement (PSA) to divest of our Mississippian/Woodford assets for the sale price of $18.5 million.  The PSA is subject to customary closing conditions and the transaction is expected to close in May 2017.

 

In December 2016, we divested an acreage block containing 3,336 gross (2,709 net) acres located in Atascosa County, Texas, which was undeveloped and outside our core development project area, for consideration of $7.1 million.

 

In July 2014, we divested our remaining assets located in the Denver-Julesburg basin. The sale price of approximately $108.8 million in cash included the reimbursement of capital expenditures incurred on 8 gross (3.1 net) non-operated horizontal wells.

 

In July 2014, we divested our remaining assets located in northwest North Dakota targeting the Bakken and Three-Forks formations (“Bakken”). The sale price of approximately $14.5 million included $10.0 million in cash and relief from a net liability owed to the buyer of approximately $4.5 million.

 

**B.**                                    **Business Overview**

 

We are an onshore oil and natural gas company focused on the exploration, development and production of large, repeatable resource plays in North America. Our oil and natural gas properties are located in premier U.S. oil and natural gas basins, and through the year ended December 31, 2016 our operational activities were conducted in the Eagle Ford and Mississippian/Woodford.

 

We intend to utilize our U.S.-based management and technical team to appraise, develop, produce and grow our portfolio of assets. Our strategy is to develop assets where we are the operator and have high working interests, which positions us to control the pace of our development and the allocation of our capital resources. As of December 31, 2016, we operated approximately 74% of our developed acreage with an average working interest of approximately 92% for Eagle Ford and 89% for Mississippian/Woodford with respect to such operated developed acreage.

 

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**Our Operations**

 

***Estimated Proved Reserves***

 

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 December 31, 2016 and 2015 are based on the reserve reports prepared by Ryder Scott, 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 December 31, 2016 and 2015, please see the reports to management prepared by Ryder Scott, which have been filed or incorporated by reference, as exhibits to this annual report.

 
| ** **                                                 | ** ** | **As of December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                 | ** ** | **2016**                              | ** ** | **2015** | ** ** |
| **Estimated proved   reserves:**                           |       |                                  |       |   |   |
| Oil (MBbls)                                                |       | 18,441                                |       | 17,552 |   |
| Natural gas (MMcf)                                         |       | 35,730                                |       | 26,576 |   |
| NGL (MBbls)                                                |       | 5,094                                 |       | 3,492 |   |
| Total estimated proved reserves   (MBoe)(1)                |       | 29,490                                |       | 25,473 |   |
| **Estimated proved   developed reserves:**                 |       |                                  |       |   |   |
| Oil (MBbls)                                                |       | 7,440                                 |       | 6,379 |   |
| Natural gas (MMcf)                                         |       | 16,704                                |       | 13,205 |   |
| NGL (MBbls)                                                |       | 2,269                                 |       | 1,998 |   |
| Total estimated proved developed   reserves (MBoe)(1)      |       | 12,493                                |       | 10,578 |   |
| **Estimated proved undeveloped   reserves:**               |       |                                  |       |   |   |
| Oil (MBbls)                                                |       | 11,001                                |       | 11,173 |   |
| Natural gas (MMcf)                                         |       | 19,026                                |       | 13,371 |   |
| NGL (MBbls)                                                |       | 2,825                                 |       | 1,494 |   |
| Total estimated proved   undeveloped reserves (MBoe)(1)(2) |       | 16,997                                |       | 14,895 |   |
| PV-10 (in thousands)(3)                                    |       | $                                     | 159,139    |   | $ | 182,169 |   |
| Standardized Measure (in   thousands)                      |       | $                                     | 159,139    |   | $ | 181,767 |   |

 

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(1)                                 Certain totals may not add due to rounding.

 

(2)                                 Reserves disclosed as of December 31, 2016 and 2015 are not the same reserves that are used to calculate depletion, depreciation and amortization.  See Note 39 — Unaudited Supplemental Oil and Gas Disclosures within the Notes to the Consolidated Financial Statements for additional information.

 

(3)                                PV-10 may be considered a non-IFRS financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows.  For a reconciliation of PV-10 to the Standardized Measure, see the following section.

 

***PV-10***

 

Certain of our oil and natural gas reserve disclosures included in this annual report 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 may be considered a non-IFRS financial measure as defined by the SEC 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 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.

 

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

 
| ** **                                             | ** ** | **As of December 31,** | ** ** |
|--------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                             | ** ** | **2016**                              | ** ** | **2015** | ** ** |
| PV-10 of proved reserves                               |       | $                                     | 159,139    |   | $ | 182,169 |   |
| Present value of future income   tax discounted at 10% |       | —                                |       | (402 | ) |
| Standardized Measure                                   |       | $                                     | 159,139    |   | $ | 181,767 |   |

 

***Proved Undeveloped Reserves***

 

At December 31, 2016, our proved undeveloped reserves were approximately 16,997 MBoe, an increase of 2,102 MBoe over our December 31, 2015 proved undeveloped reserves estimate of approximately 14,895 MBoe. The change primarily consisted of extensions and discoveries of 7,500 MBoe (Eagle Ford) and purchases of reserves of 845 MBoe (Eagle Ford, from its acquisitions in July and December 2016), partially offset by downward revisions to previous estimates of approximately 863 MBoe, sales of reserves of 2,242 Mboe and a decrease of 3,138 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves.   The revisions to previous estimates were attributable solely to the Eagle Ford.  During the year ended December 31, 2016, we incurred capital expenditures of approximately $37.8 million to convert proved undeveloped reserves to proved developed reserves. The remainder of capital expenditures for our development and production assets for the period were related to pumping unit installations on proved developed producing reserves or for unproved undeveloped reserves or resources. All proved undeveloped locations are scheduled to be spud within the next five years.

 

***Independent Reserve Engineers***

 

The Company’s reserve estimates are calculated by Ryder Scott as of December 31, 2016 in accordance with SEC guidelines.  The reserve estimates are based on, and fairly represent, information, supporting documentation prepared by, or under supervision of, Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado (Colorado No. 44720) and Texas (Texas No. 100578) with over 10 years of practical experience in estimation and evaluation of petroleum reserves.  Mr. Gardner 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. Mr. Gardner consents to the inclusion in this report of the information and context in which it appears.

 

***Internal Controls Over Reserves Estimation Process***

 

The primary inputs into the reserve estimation process are comprised of technical information, financial data, ownership interests and production data.  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. Current revenue and expense information is obtained from our accounting records, which are subject to our internal controls over financial reporting.  Internal controls over financial reporting are assessed for effectiveness annually by management using the criteria set forth in *Internal Control — Integrated Framework (2013)*issued by the Committee of Sponsoring Organizations of the Treadway Commission. All current financial data such as lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then reviewed and analyzed to ensure that they have been entered accurately and that all updates are complete. Our current ownership in mineral interests and well production data are also verified to ensure their accuracy and completeness.

 

In July 2014, the Board of Directors established the Reserves Committee to assist with monitoring (i) the integrity of our oil, natural gas, and natural gas liquids reserves, (ii) the independence, qualifications and performance of our independent reservoir engineers, and (iii) our compliance with legal and regulatory requirements. Prior to release of the reserve report prepared by our independent reserve engineers, the draft of the report is reviewed by the Reserves Committee, our internal petroleum engineers and by management.

 

Ms. Trina Medina, Vice President of Reservoir Engineering, is responsible for oversight of the internal reservoir engineering department and preparation of the reserve estimates.  Ms. Medina’s biography and qualifications can be found on page 61.

 

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***Acreage***

 

We had the following developed, undeveloped and total acres for each of our operating areas as of December 31, 2016:

 
| ** **             | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|------------------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| ** **             | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Eagle Ford (1)         |       | 12,219        |       | 10,267          |       | 38,411    |       | 32,509 |   | 50,630 |   | 42,776 |   |
| Mississippian/Woodford |       | 22,713        |       | 15,568          |       | 7,047     |       | 2,940 |   | 29,760 |   | 18,508 |   |
| All properties         |       | 34,932        |       | 25,835          |       | 45,458    |       | 35,449 |   | 80,390 |   | 61,284 |   |

 

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(1)         Includes 1,566 net acres located in Texas, targeting non-Eagle Ford formations.

 

***Production and Pricing***

 
| ** **                                                        | ** ** | **Year ended December 31,** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                        | ** ** | **2016**                                   | ** ** | **2015** | ** ** | **2014(1)** | ** ** |
| **Net Sales Volumes:**                                            |       |                                       |       |   |   |   |   |
| Oil (MBbls)                                                       |       | 1,412.5                                    |       | 1,829.0 |   | 1,675.1 |   |
| Natural gas (MMcf)                                                |       | 2,940.7                                    |       | 2,580.7 |   | 1,803.0 |   |
| NGL (MBbls)                                                       |       | 331.6                                      |       | 393.2 |   | 268.0 |   |
| Oil equivalent (MBoe)                                             |       | 2,234.2                                    |       | 2,652.3 |   | 2,244.0 |   |
| Average daily volumes (Boe/d)                                     |       | 6,104                                      |       | 7,267 |   | 6,147 |   |
| **Average Sales   Price, before derivative settlements:**         |       |                                       |       |   |   |   |   |
| Oil (per Bbl)                                                     |       | $                                          | 40.56      |   | $ | 45.35 |   | 85.56 |   |
| Natural gas (per Mcf)                                             |       | 1.68                                       |       | 1.83 |   | 3.42 |   |
| NGL (per MBbls)                                                   |       | 13.20                                      |       | 11.50 |   | 32.24 |   |
| Average equivalent price (per   Boe)                              |       | 29.81                                      |       | 34.76 |   | 71.22 |   |
| **Expenses (per Boe):**                                           |       |                                       |       |   |   |   |   |
| Lease operating expenses                                          |       | $                                          | 5.79       |   | $ | 6.96 |   | 6.03 |   |
| Production tax expense                                            |       | 1.88                                       |       | 2.28 |   | 3.10 |   |
| Lease operating and production   tax expenses                     |       | 7.67                                       |       | 9.24 |   | 9.13 |   |
| General and administrative   expense, including employee benefits |       | 5.42                                       |       | 6.48 |   | 6.92 |   |
| Depreciation and amortization   expense                           |       | 21.55                                      |       | 35.66 |   | 38.15 |   |

 

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(1)                                 Production volumes for the year ended December 31, 2014 included 104.4 MBbls of oil, 247.7 MMcf of natural gas, and 20.2 MBbls of NGL production, for a total of 165.9 MBoe (average daily volumes of 454 Boe/d), from the Denver-Julesburg. We sold our entire interest in Denver-Julesburg in July 2014. See Item 4.A. “Information on Sundance — History and Development — *Disvestitures*.”

 

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

 
| ** **              | ** ** | **Year ended**             | ** ** | **Year ended**             | ** ** |
|-------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **              | ** ** | **December 31, 2016** | ** ** | **December 31, 2015** | ** ** |
| ** **              | ** ** | **Oil**                         | ** ** | **Natural   Gas**               | ** ** | **NGL** | ** ** | **Oil   Equivalent** | ** ** | **Average   Daily   Volume** | ** ** | **Oil** | ** ** | **Natural   Gas** | ** ** | **NGL** | ** ** | **Oil   Equivalent** | ** ** | **Average   Daily   Volume** | ** ** |
| ** **              | ** ** | **(MBbls)**                     | ** ** | **(MMcf)**                      | ** ** | **(MBbls)** | ** ** | **(MBoe)** | ** ** | **(Boe/d)** | ** ** | **(MBbls)** | ** ** | **(MMcf)** | ** ** | **(MBbls)** | ** ** | **(MBoe)** | ** ** | **(Boe/d)** | ** ** |
| Eagle Ford              |       | 1,329                           |       | 2,344                           |       | 252 |   | 1,972 |   | 5,388 |   | 1,673 |   | 1,795 |   | 278 |   | 2,251 |   | 6,167 |   |
| Mississippian/ Woodford |       | 83                              |       | 597                             |       | 80 |   | 262 |   | 716 |   | 155 |   | 786 |   | 115 |   | 401 |   | 1,100 |   |
| Total                   |       | 1,412                           |       | 2,941                           |       | 332 |   | 2,234 |   | 6,104 |   | 1,828 |   | 2,581 |   | 393 |   | 2,652 |   | 7,267 |   |

 

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| ** **                 | ** ** | **Year ended**             | ** ** |
|----------------------------|------------|---------------------------------|------------|
| ** **                 | ** ** | **December 31, 2014** | ** ** |
| ** **                 | ** ** | **Oil**                         | ** ** | **Natural   Gas** | ** ** | **NGL** | ** ** | **Oil   Equivalent** | ** ** | **Average   Daily   Volume** | ** ** |
| ** **                 | ** ** | **(MBbls)**                     | ** ** | **(MMcf)** | ** ** | **(MBbls)** | ** ** | **(MBoe)** | ** ** | **(Boe/d)** | ** ** |
| Eagle Ford                 |       | 1,280                           |       | 866 |   | 104 |   | 1,528 |   | 4,187 |   |
| Mississippian/ Woodford(1) |       | 268                             |       | 678 |   | 142 |   | 523 |   | 1,434 |   |
| Denver-Julesburg(2)        |       | 104                             |       | 248 |   | 20 |   | 166 |   | 454 |   |
| Bakken(3)                  |       | 23                              |       | 11 |   | 2 |   | 27 |   | 72 |   |
| Total                      |       | 1,675                           |       | 1,803 |   | 268 |   | 2,244 |   | 6,147 |   |

 

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(1)                                 In March 2017, we announced that we exprect to divest our Mississippian/Woodford assets by May 2017.  See Item 4.A. “Information on Sundance — History and Development — *Divestitures*.”

 

(2)                                 In July 2014, we divested our remaining Denver-Julesburg assets. See Item 4.A. “Information on Sundance - History and Development—*Divestitures*.”

 

(3)                                 In July 2014, we divested our remaining Bakken assets. See Item 4.A. “Information on Sundance - History and Development—*Divestitures*.”

 

***Producing Wells***

 

We had the following producing wells for each of our operating areas as of December 31, 2016:

 
| ** **             | ** ** | **Oil Wells** | ** ** | **Natural Gas   Wells** | ** ** | **Total Wells** | ** ** |
|------------------------|------------|--------------------|------------|------------------------------|------------|----------------------|------------|
| ** **             | ** ** | **Gross**          | ** ** | **Net**                      | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Eagle Ford             |       | 115.0              |       | 87.4                         |       | —               |       | — |   | 115.0 |   | 87.4 |   |
| Mississippian/Woodford |       | 68.0               |       | 29.3                         |       | —               |       | — |   | 68.0 |   | 29.3 |   |
| Total                  |       | 183.0              |       | 116.7                        |       | —               |       | — |   | 183.0 |   | 116.7 |   |

 

***Drilling Activity***

 

The following table summarizes our drilling activity for the fiscal years ended December 31, 2016, 2015 and 2014.

 
| ** **        | ** ** | **Year ended December 31,** | ** ** |
|-------------------|------------|--------------------------------------------|------------|
| ** **        | ** ** | **2016**                                   | ** ** | **2015** | ** ** | **2014** | ** ** |
| ** **        | ** ** | **Gross**                                  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Development wells |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Oil               |       | 19                                         |       | 11.52 |   | 11 |   | 10.0 |   | 88 |   | 50.1 |   |
| Natural Gas       |       | —                                     |       | — |   | — |   | — |   | — |   | — |   |
| Dry               |       | —                                     |       | — |   | — |   | — |   | 2 |   | 2.0 |   |
| Exploratory Wells |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Oil               |       | —                                     |       | — |   | — |   | — |   | — |   | — |   |
| Natural Gas       |       | —                                     |       | — |   | — |   | — |   | — |   | — |   |
| Dry               |       | —                                     |       | — |   | 2 |   | 2.0 |   | 3 |   | 3.0 |   |
| Total Wells       |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Oil               |       | 19                                         |       | 11.52 |   | 11 |   | 10.0 |   | 88 |   | 50.1 |   |
| Natural Gas       |       | —                                     |       | — |   | — |   | — |   | — |   | — |   |
| Dry               |       | —                                     |       | — |   | 2 |   | 2.0 |   | 5 |   | 5.0 |   |
|              |       | 19                                         |       | 11.52 |   | 13 |   | 12.0 |   | 93 |   | 55.1 |   |

 

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***Present Activities***

 

The following table describes wells being drilled or awaiting completion or production testing as of December 31, 2016.

 
| ** **             | ** ** | **Development   Wells** | ** ** | **Exploratory   Wells** | ** ** | **Total Wells** | ** ** |
|------------------------|------------|-------------------------|------------|-------------------------|------------|----------------------|------------|
| ** **             | ** ** | **Gross**               | ** ** | **Net**                 | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Eagle Ford             |       | 1                       |       | 1.0                     |       | —               |       | — |   | 1 |   | 1.0 |   |
| Mississippian/Woodford |       | 1                       |       | 0.9                     |       | —               |       | — |   | 1 |   | 0.9 |   |
| Total                  |       | 2                       |       | 1.9                     |       | —               |       | — |   | 2 |   | 1.9 |   |

 

**Principal Customers and Marketing**

 

For the year ended December 31, 2016, purchases by one customer accounted for over 10% of our total sales revenues: Trafigura Group PTE. LTD (69%).  This customer purchases 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. To partially mitigate our exposure to credit risk, the customer has a letter of credit in place for our benefit.  In the event that the customer defaults, we could draw upon the letter of credit.  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 imports of foreign oil and natural gas, the level of global oil and natural gas exploration and production, global oil and gas inventories, weather conditions and natural disasters, 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 Item 3.D. “Key Information—Risk Factors.”

 

**Competition**

 

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.

 

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**Regulation of the Oil and Natural Gas Industry**

 

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 producing oil and natural gas properties 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, storing, treating, transporting and disposing of water and other materials used in the drilling and completion process, the disposal of waste generated through the drilling, operating and development of wells 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 effect 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.

 

***Regulation of Transportation of Oil***

 

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%. 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.

 

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***Regulation of Transportation and Sales of Natural Gas***

 

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the 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.

 

Onshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states.  Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case-by-case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory 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 is also subject to regulation by state regulatory agencies. 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 varies 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.

 

***Regulation of Production***

 

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.

 

We own interests in properties located onshore in Texas and Oklahoma. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.

 

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.

 

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**Environmental, Health and Safety Regulation**

 

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 emissions control, 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.

 

***Hazardous Substances and Waste***

 

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. 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. 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. No such effort has been successful to date.

 

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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.

 

***Pipeline Safety and Maintenance***

 

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. The 2011 reauthorization of DOT’s Pipeline and Hazardous Materials Safety Administration’s (“PHMSA”) pipeline safety program expired in 2015.   The Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act was signed into law on June 22, 2016.  The PIPES Act strengthens the DOT’s safety authority and provides authorization for PHMSA to finish the requirements under the 2011 law. DOT has also recently promulgated new regulations extending safety rules to certain low-pressure, small-diameter pipelines in rural areas. Improving pipeline safety, which has the effect of reducing methane leaks, has been proposed as part of the Obama Administration’s methane strategy.

 

***Air Emissions***

 

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 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. On August 15, 2014, EPA published its final decision on reconsideration and determined that it would not propose any changes to the regulation based on the petitions.

 

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 29, 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.

 

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The EPA also issued 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 has made several changes to these rules in response to industry and environmental group legal challenges and administrative petitions, including, most recently, a decision to include a specific performance standard for methane in the rules (discussed further below). 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. We further note that states are authorized to regulate methane emissions within their boundaries provided their requirements are not weaker than federal rules.

 

***Climate Change***

 

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. In December 2015 the international community agreed upon a new climate change treaty, known as the Paris Agreement.  The U.S. committed to  a 26-28% reduction in its greenhouse gas emissions by 2025 against a 2005 baseline.  This new agreement, which was ratified in November 2016 and would be effective beginning 2020, incorporates actions taken by individual countries to reduce GHGs on the national level. The United States’ involvement in developing the new agreement creates significant political pressure for the United States to take responsive action to reduce GHGs.  President Trump stated during the presidential campaign that he would withdraw the U.S. from the Paris Agreement, but whether this will occur is unclear.  The Trump Administration may allow the U.S. to remain in the Paris Agreement, but soften the emission reductions that the U.S. implements to comply with the Paris Agreement.   In general, implementation of the Paris Agreement would encourage a shift away from higher greenhouse gas emitting power sources like coal-fired power plants.  In the absence of comprehensive climate change legislation, significant regulatory action to regulate GHGs under the federal Clean Air Act has occurred over the past several years.  In particular, the Clean Power Plan regulation under the Clean Air Act, which regulates carbon pollution from existing fossil fuel-fired power plants represents a significant portion of the United States’ reductions proposed under the Paris Agreement. This, and any future federal laws, agreements 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, as stated previously, the EPA has begun to regulate GHG emissions from stationary and mobile sources.  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. This rule was subject to legal challenge that went to the Supreme Court. On June 23, 2014, the Supreme Court issued its decision in *Utility Air Regulatory Group v. EPA* (No. 12-1146). The Court held that the EPA may not require a major source to obtain a PSD or Title V permit on the basis of greenhouse gas emissions alone. The Court further held that PSD permits that are otherwise required (based on emissions of other pollutants) may continue to require limitations on GHGs based on the application of Best Available Control Technology (“BACT”).

 

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. 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.

 

On August 3, 2015, the EPA finalized its NSPS rule regulating greenhouse emissions from new, modified and restructured fossil fuel-fired power plants. In the proposed NSPS, the EPA establishes emission standards for coal plants and for natural gas-fired stationary combustion turbines. The EPA determined that partial carbon capture and sequestration constituted the “best system of emission reduction” (“BSER”) for coal plants. For natural gas plants, the EPA determined that modern, efficient natural gas combined cycle technology constituted the BSER. The NSPS applies to new fossil-fuel fired electric utility generating units over 25 MW and that generate electricity for sale. The NSPS for new sources triggers the need to set standards for existing fossil fuel-fired power plants. On August 3, 2015, the EPA released the final Clean Power Plan, which is a regulation designed to reduce carbon pollution from existing fossil fuel-fired power plants.  In the Clean Power Plan, the EPA sets forth state-specific emission targets and gives states significant flexibility in determining how they would meet the standards. Limits set by the state to meet the state-specific goals can either apply directly to the power plant or be met through reductions in power plant emissions through implementation of energy efficiency or renewable energy measures in the state. Each state can choose to include measures that the EPA determines constitute BSER or may choose additional measures, as long as such measures achieve the emission reduction necessary to meet that state’s goal set by the EPA. Throughout the Clean Power Plan, the EPA emphasizes the flexibility of the states to decide how to reduce emissions to meet the state goals, including the use of cap-and-trade programs. While these rules will more negatively impact coal-fired power plants, natural gas-fired power plants may also face liability under the rules and increased costs of operation. Upon finalization of the Clean Power Plan in October 2015, over twenty states and industry groups challenged the rule in the D.C. Circuit court and requested a stay of the rule. The D.C. Circuit denied the stay request, but, on appeal, the U.S. Supreme Court granted the stay. Oral arguments were heard in the D.C. Circuit in September 2016; a decision is expected in 2017 although the EPA has requested the court not rule and allow it to revise the rule. The Supreme Court stay was granted until the D.C. Circuit’s review of the rule is complete. Despite the stay, many states are continuing their work to implement the Clean Power Plan.

 

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On March 28, 2017, President Trump signed an executive order to rescind President Obama’s climate-related executive orders and climate action plans and direct the EPA to review and revise the Clean Power Plan, the standards for new power plants and other climate regulations.   The executive order also orders the Secretary of Interior to take action to lift the moratorium on coal leases on public lands. The executive order sets in motion a process that will take several years to fully enact.  Because the Clean Power Plan and other climate regulations are final regulations, the EPA will have to go through a public and comment rulemaking process to modify or revoke them and such actions will be litigated by environmental groups and states supportive of the regulations. Even if the carbon regulations are ultimately revoked or weakened under the Trump Administration, the imposition of carbon regulations affecting existing power plants, especially coal-fired power plants, is likely in the midterm.

 

On May 12, 2016, the EPA issued a suite of proposed regulations that would reduce methane emissions from the oil and gas industry, including proposed updates to the NSPS for new and modified sources in the oil and gas industry, a clarification of the source determination rule as applied to the oil and natural gas industry and a proposed Federal Implementation Plan for new oil and gas sources in Indian Country.  The rules were prompted by the Obama Administration’s commitment to reduce methane emissions from the oil and gas sector by 40-45% from 2012 levels by 2025.  The NSPS update would require methane and VOC reductions from hydraulically fractured oil wells, which would complement the 2012 NSPS described above.  The new proposals would also extend emission reduction requirements “downstream”, covering equipment in the natural gas transmission segment that was not regulated by the 2012 NSPS.  The regulations address leaks of methane and final guidelines for the states to reduce VOC emissions from existing oil and gas sources in areas with smog issues were issued in October 2016.  These regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result.

 

The EPA’s GHG rules are being reviewed pursuant to President Trump’s executive order and many are being challenged in court proceedings. Depending on the outcome of such proceedings, the 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.

 

While new legislation requiring GHG controls is not expected at the national level in the near term, 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 effect 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, 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, droughts, 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.

 

***Water Discharges***

 

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. 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.

 

***Endangered Species Act***

 

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.

 

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***Employee Health and Safety***

 

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 March 2016, OSHA issued a final rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids.  The key provisions of the rule require the following: (i) reduces the permissible exposure limit (PEL) for respirable crystalline silica to 50 micrograms per cubic meter of air, averaged over an 8-hour shift; (ii) requires employers to: use engineering controls (such as water or ventilation) to limit worker exposure to the PEL; provide respirators when engineering controls cannot adequately limit exposure; limit worker access to high exposure areas; develop a written exposure control plan, offer medical exams to highly exposed workers, and train workers on silica risks and how to limit exposures; (iii) provides medical exams to monitor highly exposed workers and gives them information about their lung health; and (iv) provides flexibility to help employers protect workers from silica exposure.  The compliance schedule for hydraulic fracturing is June 23, 2018 (i.e., two years after the effective date) for all provisions except engineering controls, which have a compliance date of June 23, 2021.  Aspects of the rule are being litigated by affected industry.  The Trump Administration has signaled an intent to delay enforcement of the rule.   Workers at drill sites may 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. Implementation of engineering and workplace controls to comply with the rule may require significant investment.

 

***Hydraulic Fracturing***

 

The 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 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 are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. On June 28, 2016, the EPA promulgated pretreatment standards for oil and gas extraction category that prohibit the discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works.  The EPA is also conducting a study of private wastewater treatment facilities accepting oil and gas extraction wastewater.  The EPA is collecting data and information related to the extent to which such wastewater is accepted, available treatment technologies, discharge characteristics and other information. The use of surface impoundments (i.e., pits or surface storage tanks) for the temporary storage of hydrualic fracturing fluids for re-use or prior to disposal may also be regulated. The EPA has also issued new CAA regulations relevant to hydraulic fracturing in 2012, including the NSPS for VOC and SO2 emissions with expanded applicability to natural gas operations and new national emission standards for hazardous air pollutants 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. 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 developed 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, several states, including Colorado, have implemented rules requiring hydraulic fracturing operators to sample ground-and surface waters near proposed well sites before operations can begin, and to sample the same sites again after fracturing operations are complete. A majority 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 and Texas, 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.

 

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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.

 

***Other Laws***

 

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, including evaluating the impacts of projects on climate change. 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.

 

**Insurance Matters**

 

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.

 

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**C.**                                    **Organizational Structure**

 

The following is the organizational structure of Sundance Energy Australia Limited:

 

 

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, New Standard Energy Texas, 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. However in 2015, we acquired a 17.5% non-operated working interest in the Petroleum Exploration License 570, which we intend to divest.

 

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**D.**                                    **Property, Plant and Equipment**

 

**Our Properties**

 

***Eagle Ford***

 

As of December 31, 2016, our Eagle Ford properties consisted of approximately 50,630 gross (42,776 net) acres that are primarily located in McMullen, Dimmit and Atascosa County, Texas, in the volatile oil window of the Eagle Ford trend.

 

For the year ended December 31, 2016, we had average net daily production of approximately 5,389 Boe/d (including flared natural gas) from these properties, with an exit rate of 6,601 Boe/d.  During 2016, we spent $33.2 million on drilling and completion activities, completing a total of 17 gross (9.2 net) Eagle Ford wells, and $4.3 million on facilities and infrastructure.   As of December 31, 2016, we had 1.0 net well awaiting completion. Our 2017 capital program is expected to be funded with cash on hand, cash flow from operations and proceeds from the expected Mississippian/Woodford disposition.

 

***Mississippian/Woodford***

 

The Mississippian/Woodford formation spans six counties located throughout northeastern Oklahoma and southwestern Kansas. As of December 31, 2016, our properties in the Mississippian/Woodford consisted of approximately 29,760 gross (18,508 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.

 

For the year ended December 31, 2016, we had average net daily production of approximately 715 Boe/d from these properties.  During 2016, we spent $2.5 million on completion activities, completing 2.0 gross (1.8 net) wells.  As of December 31, 2016, we had 1 gross (0.9 net) well waiting on completion.  Our 2017 capital program does include any drilling or completion activities in this area.

 

On March 1, 2017, we announced the divestiture of our Mississippian/Woodford assets to focus on the development of our operated assets in the Eagle Ford.  See Item 4.A. “Information on Sundance — History and Development — *Divestitures*.”

 

***Denver-Julesburg***

 

In July 2014, we divested our remaining Denver-Julesburg assets to focus on the development of our operated assets in our other major operating areas. See Item 4.A. “Information on Sundance — History and Development—*Divestitures.*”

 

***Bakken***

 

In July 2014, we divested our remaining Bakken assets. See Item 4.A. “Information on Sundance - History and Development—*Divestitures*.”

 

**Title to Properties**

 

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.

 

**Facilities**

 

We lease approximately 27,600 square feet of office space at 633 17th Street, Denver, Colorado, where our principal offices are located.  As of the date of this report, approximately 8,200 square feet are not utilized as a result of the Company’s reduction-in-force in early 2016.  We do not have any material field office facilities.

 

**Item 4A.  Unresolved Staff Comments**

 

None.

 

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**Item 5.  Operating and Financial Review and Prospects**

 

**A.**                                    **Operating Results**

 

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

 

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

 

**Overview**

 

We are an onshore oil and natural gas company focused on the exploration, development and production of large, repeatable resource plays in North America. Our oil and natural gas properties are located in premier U.S. oil and natural gas basins, and through the year ended December 31, 2016, our operational activities were focused in the Eagle Ford and Mississippian/Woodford.

 

We intend to utilize our U.S.-based management and technical team to appraise, develop, produce and grow our portfolio of assets. Our strategy is to develop assets where we are the operator and have high working interests, which positions us to control the pace of our development and the allocation of our capital resources. As of December 31, 2016, we operated approximately 74% of our developed acreage with an average working interest of approximately 92% for Eagle Ford and 88% for Mississippian/Woodford with respect to such operated developed acreage.

 

Our properties and operations have changed significantly over the past several years, with the divestiture of our Denver-Julesburg assets and remaining Bakken assets in July 2014, as well as the anticipated divestiture of our Mississippian/Woodford assets, expected to close in May 2017.  In addition, we have continued to increase our Eagle Ford acreage position, including two acquisitions of Eagle Ford acreage in 2016.  See Item 4.A. “Information on Sundance — History and Development—*Acquisitions”* and “—*Divestitures*.”

 

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

 

Ryder Scott estimated our proved reserves to be approximately 29.5 MMBoe as of December 31, 2016, of which approximately 63% are oil, approximately 20% are natural gas and approximately 17% NGLs, with a PV-10 of approximately $159.1 million.

 

**How We Conduct Our Business and Evaluate Our Operations**

 

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

 

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

 

·                  production volumes;

 

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

 

·                  lease operating and production expenses;

 

·                  general and administrative expenses; and

 

·                  Adjusted EBITDAX.

 

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***Production Volumes***

 

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

 

***Realized Prices on the Sale of Oil and Natural Gas***

 

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

 

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

 

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

 

Oil prices have historically been extremely volatile, and we expect this volatility and overall price depression to continue into 2017. For example, the NYMEX-WTI oil price ranged from a high of $54.01 per Bbl to a low of $26.19 per Bbl during 2016. Our realized price per Bbl varies by basin primarily due to 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 gas prices to remain depressed into 2017. The NYMEX-Henry Hub natural gas price ranged from a high of $3.80 per MMBtu to a low of $1.49 per MMBtu during 2016 and through the first quarter of 2017. 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.

 

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

 

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

 

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

 

***Production and Ad Valorem Taxes.***  Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes. The state currently imposes a production tax equal to 4.6% of the market value of oil sold, and a regulatory fee of 0.625% per barrel of oil sold. The State of Texas also imposes a production tax equal to 7.5% of the market value of the natural gas sold, and a regulatory fee of 0.0667% per Mcf of gas sold. In addition to the state taxes, McMullen, Dimmit and Atascosa Counties, Texas assesses an annual ad valorem tax which currently is approximately 1.63%, 1.30%, and 1.73% (respectively) of the gross annual oil and gas sales value.

 

Oklahoma currently has a production tax rate of 7.0% of the market value of the oil and gas sold. However, we have qualified for a horizontal well incentive tax rate of 1.0% which is available for the first 48 months of sales (applicable to wells spud prior to July 1, 2015). For vertical and horizontal wells completed after July 1, 2015 the tax rate is 2% for the first 36 months. 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 only, specifically well equipment, at a rate of approximately 12.0% of the value of the equipment.

 

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

 

***General and Administrative Expenses***

 

General and administrative expenses are comprised of employee benefits expense (including salaries and wages) and administrative expenses. Employee benefits expense includes salaries, wages and related benefits for our corporate personnel. Share based compensation expense, including restricted share units, deferred cash awards and stock options 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 units at the grant date. Administrative expenses include overhead costs, such as maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services, and legal compliance.

 

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

 

***Adjusted EBITDAX***

 

Adjusted EBITDAX is a supplemental, non-IFRS financial measure and is defined as our earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain/(loss) on sale of non-current assets, exploration expense, share-based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non-cash or non-recurring items of income(loss). We use this non-IFRS measure primarily to compare our results with other companies in the industry that make a similar disclosure, evaluate our operating performance and identify operating trends (which may otherwise be masked by the excluded items).  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.  See Item 3.A. “Key Information—Selected Financial Data—*Adjusted EBITDAX*” for a reconciliation between Adjusted EBITDAX and net income before income tax expense.

 

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**Critical Accounting Policies and Estimates**

 

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

 

In addition, we note that our significant accounting policies are detailed in Note 1 to our consolidated financial statements for the fiscal year ended December 31, 2016.

 

***Development and Production Assets and Plant and Equipment***

 

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

 

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

 

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

 

Due to the Company writing down its Mississippian/Woodford assets to the expected net proceeds from the sale expected to close in May 2017 and the change in the oil pricing environment as of December 31, 2016 and 2015 respectively, management performed an impairment analysis for development and production assets (limited to Mississippian/Woodford assets in 2016), which resulted in impairment charges of $3.4 million and $184.4 million, respectively.

 

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

 

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

 

***Exploration and Evaluation Expenditure***s

 

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

 

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

 

The carrying amounts of our exploration and evaluation assets are reviewed at each reporting date, in conjunction with the impairment review process referred to in Note 1 to our consolidated financial statements for the year ended December 31, 2016 to determine whether any of impairment indicators exists. Impairment indicators could include i) tenure over the license area has expired during the period or will expire in the near future, and is not expected to be renewed, ii) substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is not budgeted or planned, iii) exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of resources, and management has decided to discontinue activities in the specific area, or iv) sufficient data exist to indicate that although a development is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or from sale. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made and any resulting impairment loss is recognized in the income statement.

 

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

 

Due to the Company writing down its Mississippi/Woodford assets to the expected net proceeds from the sale expected to close in May 2017 and lack of operational information indicating the recovery of the Company’s carrying costs in the Cooper Basin is likely as of December 31, 2016 management performed an impairment analysis for its exploration and evaluation expenditures, which resulted in an impairment charge of $7.9 million.  We recorded a $137.2 million impairment expense as a result of the change in the oil pricing environment related to our exploration and evaluation expenditures for the year ended December 31, 2015.

 

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*** ***

***Derivative Financial Instruments***

 

We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our Board of 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 Market Risk, Oil Prices Risk Sensitivity Analysis.”

 

***Estimates of Reserve Quantities***

 

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

 

***Income taxes***

 

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in predicting when these events may occur and whether recovery of an asset is more likely than not, including judgments and assumptions about future taxable income and future operating conditions (particularly as related to prevailing oil and natural gas prices).  For the year ended December 31, 2016, we did not recognize tax assets of $46.0 million as the recovery was not determined to be more likely than not.  As a result, we expect our effective tax rate to be significantly lower than the statutory rate in 2017.  Some or all of these deferred tax assets could be recognized in future periods against future taxable income.

 

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

 

Because our Australian operations are not significant to the consolidated profit or loss, foreign income taxes are not significant to consolidated income tax expense. Our effective and statutory income tax rates could be impacted by the state income tax rates in which we operate, and the effective and statutory income tax rates are not significantly different as the amount of permanent differences resulting from treatment that differs for assets and liabilities for financial and tax reporting purposes is not significant. The tax impact of temporary differences, primarily development and production assets and exploration and evaluation expenditures, is reflected in deferred income taxes. At December 31, 2016 and 2015, we had no unrecognized tax benefits that would impact our effective tax rate and we have not provided for interest or penalties related to uncertain tax positions.  See Note 7 to the consolidated financial statements.

 

***Revenue Recognition***

 

Our revenue is derived from the sale of produced oil, natural gas and NGLs. Revenue is recorded in the month the product is delivered to the purchaser, while payment is received 15 to 90 days after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received. However, differences have been and are insignificant.

 

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**Recently Issued Accounting Standards**

 

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to “Note 1- Statement of Significant Accounting Policies” footnote in the notes to consolidated financial statements.

 

**Certain Differences Between IFRS and US GAAP**

 

IFRS differs from US GAAP in certain respects. Management has not assessed the materiality of differences between IFRS and US GAAP. Our significant accounting policies are described in Note 1 of our consolidated financial statements for the year ended December 31, 2016.

 

**Comparison of Results of Operations**

 

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 annual report. Comparative results of operations for the period indicated are discussed below.

 

***Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015***

 

***Revenues and Sales Volume.***  The following table provides the components of our revenues for the years ended December 31, 2016 and 2015, as well as each period’s respective sales volumes:

 
| ** **                           | ** ** | **Year ended   December 31,** | ** ** | ** ** |
|--------------------------------------|------------|-----------------------------------------|------------|------------|
| ** **                           | ** ** | **2016**                                | ** ** | **2015**   | ** ** | **Change in $** | ** ** | **Change as %** | ** ** |
| **Revenue (In   $ ‘000s)** |       |                                    |       |       |   |   |   |   |   |
| Oil sales                            |       | $                                       | 57,296     |       | $ | 82,949 |   | $ | (25,653 | ) | (30.9 | ) |
| Natural gas sales                    |       | 4,937                                   |       | 4,720      |   | 217 |   | 4.6 |   |
| NGL sales                            |       | 4,376                                   |       | 4,522      |   | (146 | ) | (3.2 | ) |
| Product revenue                      |       | $                                       | 66,609     |       | $ | 92,191 |   | $ | (25,582 | ) | (27.7 | ) |

 
| ** **                       | ** ** | **Year ended   December 31,** | ** ** | ** ** | ** ** | ** **                     | ** ** |
|----------------------------------|------------|-----------------------------------------|------------|------------|------------|--------------------------------|------------|
| ** **                       | ** ** | **2016**                                | ** ** | **2015**   | ** ** | **Change in Volume** | ** ** | **Change as %** | ** ** |
| **Net sales volumes:**           |       |                                    |       |       |       |                           |       |   |   |
| Oil (Bbls)                       |       | 1,412,475                               |       | 1,828,955  |       | (416,480                       | )          | (22.8 | ) |
| Natural gas (Mcf)                |       | 2,940,715                               |       | 2,580,682  |       | 360,033                        |       | 14.0 |   |
| NGL (Bbls)                       |       | 331,622                                 |       | 393,211    |       | (61,589                        | )          | (15.7 | ) |
| Oil equivalent (Boe)             |       | 2,234,216                               |       | 2,652,280  |       | (418,064                       | )          | (15.8 | ) |
| Average daily production (Boe/d) |       | 6,104                                   |       | 7,267      |       | (1,163                         | )          | (16.0 | ) |

 

***Barrel of oil equivalent (Boe) and average net daily production (Boe/d).***  Sales volume decreased by 418,064 Boe (16%) to 2,234,216 Boe (6,104 Boe/d) for the year ended December 31, 2016 compared to 2,652,280  Boe (7,267 Boe/d) for the prior year primarily due to flush production in early 2015 as a result of the Company’s back-loaded 2014 development program.  All of the Company’s 2016 completions were in the second half of the year, resulting in less than a full year of production from those wells.

 

The Eagle Ford contributed 5,389 Boe/d (88%) of total sales volume during the year ended December 31, 2016 compared to 6,167 Boe/d (85%) during the prior year. Mississippian/Woodford contributed 715 Boe/d (12%) of total sales volume during the year ended December 31, 2015 compared to 1,100 Boe/d (15%) during the prior year. Our sales volume is oil-weighted, with oil representing 63% and 69% of total sales volume for the year ended December 31, 2016 and 2015, respectively.

 

***Oil sales.***  Oil sales decreased by $25.7 million (31%) to $57.3 million for the year ended December 31, 2016 from $82.9 million for the prior year. The decrease in oil revenues was the result of the decrease in product pricing ($6.8 million), with an additional decrease due to oil production ($18.9 million).  The average price we realised on the sale of our oil decreased by 11% to $40.56 per Bbl for the year ended December 31, 2016 from $45.35 per Bbl for the prior year.  Oil production volumes decreased 22.8% to 1,412,475 Bbls for the year ended December 31, 2016 compared to 1,828,955 Bbls for the prior year.

 

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***Natural gas sales.***  Natural gas sales increased by $0.2 million (5%) to $4.9 million for the year ended December 31, 2016 from $4.7 million for the prior year. The increase in natural gas revenues was primarily the result of increased production volumes ($0.7 million), offset by lower product pricing ($0.4 million).  Natural gas production volumes increased 360,033 Mcf (14%) to 2,940,715 Mcf for the year ended December 31, 2016 compared to 2,580,682 Mcf for the prior year due to slightly higher gas-oil ratios on wells completed during the year. The average price we realised on the sale of our natural gas decreased by 8% to $1.68 per Mcf (net of transportation and marketing) for the year ended December 31, 2016 from $1.83 per Mcf for the prior year.

 

***NGL sales.*** NGL sales decreased by $0.1 million (3%) to $4.4 million for the year ended December 31, 2016 from $4.5 million for the prior year. The decrease in NGL revenues was primarily the result of decreased production volumes ($0.7 million), offset by better product pricing ($0.6 million). The average price we realised on the sale of our natural gas liquids increased by 15% to $13.20 per Bbl for the year ended December 31, 2016 from $11.50 per Bbl for the prior year.  NGL production volumes decreased 61,589 Bbls (16%) to 331,622 Bbls for the year ended December 31, 2016 compared to 393,211 Bbls for the prior year.

 
| ** **                                                               | ** ** | **Year ended December 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------|------------|--------------------------------------------|------------|------------|------------|------------|------------|
| **Selected per Boe metrics**                              | ** ** | **2016**                                   | ** ** | **2015**   | ** ** | **Change** | ** ** | **Change as %** | ** ** |
|                                                                     |       |                                       |       |       |       |       |       |   |   |
| Total oil, natural gas and NGL   revenues, before derivative settlements |       | $                                          | 29.81      |       | $          | 34.76      |       | $ | (4.96 | ) | (14.2 | ) |
| Lease operating expenses                                                 |       | (5.79                                      | )          | (6.96      | )          | 1.17       |       | 16.8 |   |
| Production taxes                                                         |       | (1.88                                      | )          | (2.28      | )          | 0.40       |       | 17.5 |   |
| Lease operating and production   tax expenses                            |       | (7.67                                      | )          | (9.24      | )          | 1.57       |       | 17.0 |   |
| Depreciation and amortization                                            |       | (21.55                                     | )          | (35.66     | )          | 14.11      |       | 39.6 |   |
| General and administrative   expense                                     |       | (5.42                                      | )          | (6.48      | )          | 1.06       |       | 16.3 |   |
|                                                                          |            |                                            |            |            |            |            |            |  |  |  |  |  |

 

***Lease operating expenses******.***  Our lease operating expenses (LOE) decreased by $5.5 million (30%) to $12.9 million for the year ended December 31, 2016 from $18.5 million in the prior year, and decreased $1.17 per Boe to $5.79 per Boe from $6.96 per Boe.  During 2016, the Company was able to negotiate discounts and improved pricing with a significant number of LOE vendors, which resulted in lower LOE.

 

***Production taxes. ***Our production taxes decreased by $1.8 million (31%) to $4.2 million for the year ended December 31, 2016 from $6.0 million for the prior year but stayed relatively flat as a percent of revenue. The decrease in production tax expense is consistent with the decrease in revenue.

 

***Depreciation and amortisation expense, including depletion (DD&A).*** Our DD&A expense decreased by $46.4 million (49%) to $48.1 million for the year ended December 31, 2016 from $94.6 million for the prior year and decreased $14.11 per Boe to $21.55 per Boe from $35.66 per Boe.  The decrease is a result of decreased production levels and a lower depletable asset base due to prior-year’s impairment.

 

***General and administrative expenses.***  General and administrative expenses decreased by $5.1 million (29.5%) to $12.1 million for the year ended December 31, 2016 as compared to $17.2 million for the prior year. The decrease in general and administrative expenses is primarily due to G&A cost saving initiatives implemented by the Company in 2016, including a restructuring that resulted in the lay-off of approximately 30% of the Company’s employees in January 2016 as well as a decrease in share based compensation.

 

***Impairment expense.*** The Company recorded impairment expense of $10.2 million for the year ended December 31, 2016 on the Company’s oil and gas assets which includes reducing the carrying value of its Greater Anadarko Basin assets by $4.6 to the expected proceeds from the sale of those assets.  These assets were reclassified as “Assets Held for Sale” on the Company’s balance sheet as of June 30, 2016.  Under the applicable IFRS accounting rules, recording of amortisation expense ceases at the time the assets are reclassified, which resulted in impairment expense as the assets depleted over time. Impairment expense also included the write-down of its Cooper Basin exploration and evaluation asset ($6.7 million) and a partially offsetting adjustment to prior year impairment expense related to a vendor discount received on 2015 capital expenditures subsequent to the issuance of the 2015 annual report ($1.1 million).  The Company had impairment expense of $321.9 million in the year ended December 31, 2015.

 

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***Exploration expense.*** The Company did not incur any material exploration expenses for the year ended December 31, 2016.  The Company incurred exploration expense of $7.9 million in 2015 related to two unsuccessful exploratory wells.

 

***Finance costs.***  Finance costs, net of amounts capitalised to exploration and development, increased by $2.8 million to $12.2 million for the year ended December 31, 2016 as compared to $9.4 million in the prior year. The increase primarily relates to additional interest incurred on a larger average outstanding debt balance throughout 2016.

 

***(Loss) Gain on derivative financial instruments. ***The Company had a loss on derivative financial instruments of $12.8 million for the year ended December 31, 2016 as compared to $15.3 million gain in the prior year.  The loss on commodity hedging consisted of $21.4 million of unrealized losses on commodity derivative contracts, offset by $8.7 million of realized gains on commodity derivative contracts for the year ended December 31, 2016.  The prior year gain on commodity hedging consisted of $12.4 million and $2.9 million of realised and unrealised gains on commodity derivative contracts, respectively.

 

The following is a summary of the Company’s open oil and natural gas derivative contracts at December 31, 2016:

 
| ** **             | ** ** | **Oil Contracts (Weighted Average)(1)** | ** ** | **Natural Gas Contracts (Weighted Average) (1)** | ** ** |
|------------------------|------------|--------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|
| **Contract Year** | ** ** | **Units (Bbl)**                                   | ** ** | **Floor**                                                                 | ** ** | **Ceiling** | ** ** | **Units (Mmbtu)** | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| 2017                   |       | 930,000                                                |       | $                                                                         | 49.12      |   | $ | 58.78 |   | 1,680,000 |   | $ | 2.86 |   | $ | 3.21 |   |
| 2018                   |       | 612,000                                                |       | $                                                                         | 49.88      |   | $ | 58.92 |   | 1,290,000 |   | $ | 2.95 |   | $ | 3.36 |   |
| 2019                   |       | 300,000                                                |       | $                                                                         | 52.51      |   | $ | 54.31 |   | 720,000 |   | $ | 2.95 |   | $ | 3.78 |   |
| Total                  |       | 1,842,000                                              |       | $                                                                         | 49.87      |   | $ | 58.10 |   | 3,690,000 |   | $ | 2.91 |   | $ | 3.37 |   |

 

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

 
| ** **                                      | ** ** | **Year ended 31 December** | ** ** | ** ** | ** ** | ** **                | ** ** |
|-------------------------------------------------|------------|-------------------------------------------|------------|------------|------------|---------------------------|------------|
| **(In US$’000s)**                     | ** ** | **2016**                                  | ** ** | **2015**   | ** ** | **Change in $** | ** ** | **Change as %** | ** ** |
|                                            |       |                                      |       |       |       |                      |       |   |   |
| Current tax expense/(benefit)                   |       | 1,563                                     |       | (6,191     | )          | 7,754                     |       | (125.2 | ) |
| Deferred tax   expense/(benefit)                |       | 142                                       |       | (100,947   | )          | 101,189                   |       | (100.1 | ) |
| Total income tax   expense/(benefit)            |       | 1,705                                     |       | (107,138   | )          | 108,843                   |       | (101.6 | ) |
| Combined Federal   and state effective tax rate |       | (3.9                                      | )%         | 28.9       | %          | 33                        | %          | (113.5 | ) |

 

Our combined Federal and state effective tax rates differ from the Group’s statutory tax rate (Australia) of 30% primarily due to an increase in unrecognised tax losses, partially offset by US federal and state tax rates. The effective tax rate in 2015 was higher due to its deferred tax liabilities, which were fully utilised in the period.  See Note 7 in the Notes to the Consolidated Financial Statements of this report for further information regarding our income taxes.

 

***Loss attributable to owners of Sundance (or net loss).***  Loss attributable to our owners (or net loss after tax)  was a net loss of $45.7  million for the year ended December 31, 2016 a decrease from net loss of $263.8 million for the year ended December 31, 2015, for the reasons discussed above.

 

***Adjusted EBITDAX.***  For the year ended December 31, 2016, adjusted EBITDAX was $47.9 million, or 72% of revenue, compared to $64.8 million, or 70% of revenue, from the prior year. The overall decrease in Adjusted EBITDAX was primarily driven by the decline in commodity prices and lower production volumes.

 

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

 

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

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

 
| ** **

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

 

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

 

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

 

***Oil sales.***  Oil sales decreased by $62.0 million (42.8%) to $82.9 million for the year ended December 31, 2015 from $145.0 million for 2014. The decrease in oil revenues was the result of the decrease in product pricing ($75.4 million), offset by increased oil production ($13.3 million).   Oil production volumes increased 9.2% to 1,828,955 Bbls for the year ended December 31, 2015 compared to 1,675,078 Bbls for 2014. The average price we realized on the sale of our oil decreased by 47.6% to $45.35 per Bbl for the year ended December 31, 2015 from $86.56 per Bbl for the year ended December 31, 2014.

 

***Natural gas sales.***  Natural gas sales decreased by $1.4 million (30.7%) to $4.7 million for the year ended December 31, 2015 from $6.2 million for 2014. The decrease in natural gas revenues was primarily the result of worse product pricing ($4.6 million), offset by increased production volumes ($2.7 million).  Natural gas production volumes increased 777,862 Mcf (43.1%) to 2,580,682  Mcf for the year ended December 31, 2015 compared to 1,803,000 Mcf for the year ended December 31. 2014. The average price we realized on the sale of our natural gas decreased by 52% to $1.83 per Mcf for the year ended December 31, 2015 from $3.42 per Mcf for 2014.

 

***NGL sales.***  NGL sales decreased by $4.1 million (47.6%) to $4.5 million for the year ended December 31, 2015 from $8.6 million for the same period in 2014. The decrease in NGL revenues was primarily the result of worse product pricing ($8.2 million), offset by increased production volumes ($4.0 million). NGL production volumes increased 125,259  Bbls (46.7%) to 393,211  Bbls for the year ended December 31, 2015 compared to 267,952 Bbls in 2014. The average price we realized on the sale of our natural gas liquids decreased by 60.5% to $11.50 per Bbl for the year ended December 31, 2015 from $32.24 per Bbl for the year ended December 31, 2014.

 

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| ** **                                                          | ** ** | **Year ended   December 31,** | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------|------------|-----------------------------------------|------------|------------|------------|------------|------------|
| **Selected per Boe metrics**                         | ** ** | **2015**                                | ** ** | **2014**   | ** ** | **Change** | ** ** | **Change as %** | ** ** |
|                                                                |       |                                    |       |       |       |       |       |   |   |
| Total oil and natural gas   revenues, before derivative settlements |       | $                                       | 34.76      |       | $          | 71.22      |       | $ | (36.46 | ) | (51.2 | ) |
| Lease operating expenses                                            |       | (6.96                                   | )          | (6.03      | )          | 0.93       |       | 15.4 |   |
| Production taxes                                                    |       | (2.28                                   | )          | (3.10      | )          | (0.82      | )          | (26.5 | ) |
| Lease operating and production   tax expenses                       |       | (9.24                                   | )          | (9.13      | )          | 0.11       |       | 0.1 |   |
| Depreciation and amortization                                       |       | (35.66                                  | )          | (38.15     | )          | (2.49      | )          | (6.5 | ) |
| General and administrative   expense                                |       | (6.48                                   | )          | (6.92      | )          | (0.45      | )          | (6.4 | ) |
|                                                                     |            |                                         |            |            |            |            |            |  |  |  |  |  |

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

 

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

 

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

 

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

 

**B.**                                    **Liquidity and Capital Resources**

 

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

 

In May 2015, we refinanced our previous credit facilities with Wells Fargo to new credit facilities with Morgan Stanley, increasing our total borrowing capacity from an aggregate of $135 million to $200 million; comprised of a $125 million Term Loan, and a reserve based revolver of up to $75 million.  Throughout 2015, the Company increased its borrowings to $192 million ($125 million Term Loan and $67 million outstanding on the Revolving Facility).  On December 30, 2015, the Revolving Facility borrowing capacity was reduced from $75 million to $67 million. As of December 31, 2016, we were fully drawn on our Term Loan and Revolving Facility.  At December 31, 2016, we were in compliance with all of our covenants and believe we will remain compliant for the remainder of 2017.

 

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

 

In June 2016, management committed to a plan to sell its interest in our Mississippian/Woodford assets.  In March 2017, the Company entered into a purchase and sale agreement and expects to close on the transaction in May 2017.  Certain of the Mississippian/Woodford assets were included in the borrowing base value under the Company’s Credit Agreement.  Upon the sale of these assets, the lender may elect to reduce the then effective borrowing base by an amount equal to the value attributed to those assets if the value of the remaining assets doesn’t meet the prescribed asset coverage thresholds.  There are many variables that affect the lender’s determination of borrowing base value at any point in time and therefore it is difficult for management to estimate the borrowing base value in the future so the amount that would be required to be repaid, if any, is uncertain.  Accordingly, no portion of the outstanding debt has been classified as current as of December 31, 2016.

 

Our 2017 capital budget is based on our operating cash flows which we intend to use toward the development of our oil and natural gas projects, with relatively insignificant planned expenditures toward exploration and evaluation. We believe that our cash on hand, internally generated operating cash flows and the aforementioned asset sale, will be sufficient to fund our operations and planned capital expenditures through 2017. We may also use other sources of capital, including the issuance of debt or equity securities, to fund acquisitions or maintain our financial flexibility.

 

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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 further decline for an extended period of time or the capital/credit markets become constrained, the borrowing capacity under our Credit Agreement could be adversely affected. In the event of a reduction in the borrowing base under our Credit Agreement, we may be required to prepay some or all of our indebtedness, which would adversely affect our capital expenditure program.

 

***Cash Flows***

 

Our cash flows for the years ended December 31, 2016, 2015 and 2014 are as follows:

 
| ** **                                     | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------|------------|--------------------------------------------|------------|
| **(In $ ‘000s)**                | ** ** | **2016**                                   | ** ** | **2015** | ** ** | **2014** | ** ** |
| ** **                                     | ** ** | **(audited)**                              | ** ** | **(audited)** | ** ** | **(audited)** | ** ** |
| Financial Measures:                            |       |                                       |       |   |   |   |   |
| Net cash provided by operating   activities    |       | $                                          | 42,660     |   | $ | 64,469 |   | $ | 128,087 |   |
| Net cash used in investing   activities        |       | (79,991                                    | )          | (180,771 | ) | (323,235 | ) |
| Net cash provided by financing activities      |       | 51,776                                     |       | 50,403 |   | 167,595 |   |
| Cash and cash equivalents                      |       | 17,463                                     |       | 3,468 |   | 69,217 |   |
| Payments for development   expenditure         |       | (64,130                                    | )          | (144,316 | ) | (361,950 | ) |
| Payments for exploration   expenditure         |       | (2,852                                     | )          | (20,339 | ) | (39,616 | ) |
| Acquisitions, net of acquired   cash           |       | (23,506                                    | )          | (15,023 | ) | (35,606 | ) |
| Proceeds from the sale of   non-current assets |       | 7,141                                      |       | 41 |   | 115,284 |   |
|                                                |            |                                            |            |  |  |  |  |  |  |  |

 

***Cash flows provided by operating activities***

 

Cash provided by operating activities for the year ended December 31, 2016 was $42.7 million, a decrease of $21.8 million compared to the prior year ($64.5 million).  This decrease was primarily due to receipts from sales decreasing $34.7 million, to $64.7 million and pay down of 2015 accounts payables and accrued expense balances.  See Item 4.B. “Information on Sundance — Business Overview” for more information.

 

Net cash provided by operating activities for the year ended December 31, 2015 decreased 50% to $64.5 million compared to 2014. This decrease was primarily due to receipts from sales decreasing $71.0 million, or 42%, to $99.4 million primarily due to the decrease in commodity prices.  This was partially offset by an increase in payments to suppliers and employees of $19.7 million.

 

***Cash flows used investing activities***

 

Cash used in investing activities for the year ended December 31, 2016 decreased significantly to $80.0 million (including a net paydown of $9.4 million related to 2015 development and exploration costs) as compared to $180.8 million in prior year.  This decrease was primarily due to the Company’s down-cycle development plan to drill and complete within operating cash flow, with the exception of some accelerated development subsequent to the capital raise in the second half of 2016.

 

Net cash used in investing activities for the year ended December 31, 2015 decreased significantly to $180.8 million (including a net paydown of $74.0 million related to 2014 development and exploration costs) as compared to $323.2 million in 2014 (net of $115.3 million cash source from sale of non-current assets).  This decrease was primarily due to the Company’s down-cycle development plan to drill and complete within operating cash flow.

 

***Cash flows provided by (used in) financing activities***

Cash provided by financing activities for the year ended December 31, 2016 increased slightly to $51.8 million.  This increase is a result of the $64.2 million capital raise, offset by borrowing costs paid of $11.8 million.  There were no additional draws on the Company’s credit facilities compared to last year’s $62.0 million net draw and no equity raised in 2015.

 

Net cash provided by financing activities for the year ended December 31, 2015 decreased to $50.4 million.  This decrease is a result of the lower net draws on the Company’s credit facilities ($62.0 million in 2015 compared to $100.0 million in prior year) and no equity raises in 2015 (compared to a net of $68.7 million in 2014).

 

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***Credit Facilities***

 

***Credit Facilities.***  On May 14, 2015, we and our wholly-owned subsidiary Sundance Energy, Inc. entered into the Credit Agreement with Morgan Stanley Energy Capital, Inc., as administrative agent and the lenders from time to time party thereto, which provides for our $300 million Revolving Facility and $125 million Term Loan.  The Revolving Facility is subject to a borrowing base, which was set initially at $75 million and reduced to $67 million on December 30, 2015.  At December 31, 2016, we had $125 million outstanding on the Term Loan and $67 million outstanding on the Revolving Facility.

 

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

 

The key financial covenants of our Credit Agreement require us to (i) maintain a minimum current ratio, which is defined as consolidated current assets inclusive of undrawn borrowing capacity divided by consolidated current liabilities, of 1.00 or greater, (ii) a revolving debt to EBITDAX ratio, determined on a rolling four quarter basis, of 4.00 to 1.00 or less, (iii) maintain a minimum EBITDAX to consolidated interest expense ratio of 2.00 to 1.00 or greater,  and (iv) maintain a minimum Total Proved PV-9 (as defined in our Credit Agreement) to Total Debt (as defined in our Credit Agreement) ratio of not less than 1.50 to 1.00. The Credit Agreement requires the Company to hedge 50% of its proved developed producing forecasted volumes.  EBITDAX, as defined in the Credit Agreement, is calculated as consolidated net income (loss) less the impact of interest, income taxes, depreciation, depletion, amortization, exploration expensese and other noncash charges and income (including share based compensation, unrealized gains and loss on derivative instruments).

 

In addition, our Credit Agreement contains various covenants that limit our ability to take certain actions, including, but not limited to, the following:

 

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

 

·                  enter into certain commodity hedging agreements;

 

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

 

·                  make certain distributions (including payments of dividends);

 

·                  make certain loans, advances and investments; and

 

·                  engage in transactions with affiliates.

 

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

 

·                  failure to pay any principal when due under the Credit Agreement;

 

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

 

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

 

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

 

·                  bankruptcy or insolvency events involving us or our subsidiaries;

 

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

 

·                  certain ERISA events involving us or our subsidiaries;

 

·                  bankruptcy or insolvency; and

 

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

 

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

 

***Capital Expenditures***

 

The following table summarizes our capital expenditures incurred (excluding acquisitions and changes related to its restoration provision) for the years ending December 31, 2016 and 2015.

 
| ** **                               | ** ** | **Year ending December 31** | ** ** | ** **    | ** ** | ** **                | ** ** |
|------------------------------------------|------------|--------------------------------------------|------------|---------------|------------|---------------------------|------------|
| **(In $ ‘000s)**          | ** ** | **2016**                                   | ** ** | **2015**      | ** ** | **Change in $** | ** ** | **Change in %** | ** ** |
| ** **                               | ** ** | **(audited)**                              | ** ** | **(audited)** | ** ** | ** **                | ** ** | ** ** | ** ** |
| Development and production assets        |       | $                                          | 57,893     |          | $          | 76,831                    |       | (18,938 | ) | (24.6 | ) |
| Exploration and evaluation   expenditure |       | 4,429                                      |       | 22,501        |       | (18,072                   | )          | (80.3 | ) |
| **Total**                                |       | $                                          | 62,322     |          | $          | 99,332                    |       | (37,010 | ) | (37.3 | ) |

 

**C.**                                    **Research and Development**

 

Not applicable.

 

**D.**                                    **Trend Information**

 

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

 

**E.**                                    **Off-Balance Sheet Arrangements**

 

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

 

**F.**                                     **Tabular disclosure of contractual obligations**

 

The following table summarizes our contractual obligations as of December 31, 2016.

 
| ** **                                                        | ** ** | **Payments due by period** | ** ** |
|-------------------------------------------------------------------|------------|-------------------------------------------|------------|
| **Contractual Obligations (In $ ‘000s)** | ** ** | **Total**                                 | ** ** | **Less than   1 year** | ** ** | **1 - 3 years** | ** ** | **3 - 5 years** | ** ** | **More than   5 years** | ** ** |
| Credit Facilities(1)                                              |       | $                                         | 235,441    |   | $ | 12,606 |   | $ | 25,213 |   | $ | 197,622 |   | $ | — |   |
| Cooper Basin capital commitments   (2)                            |       | 3,373                                     |       | 1,687 |   | 1,686 |   | — |   | — |   |
| Drilling rig commitments (3)                                      |       | 1,085                                     |       | 1,085 |   | — |   | — |   | — |   |
| Operating lease obligations(4)                                    |       | 4,123                                     |       | 1,353 |   | 2,267 |   | 503 |   | — |   |
| Employment commitments(5)                                         |       | 740                                       |       | 370 |   | 370 |   | — |   | — |   |
| Restoration provision (6)                                         |       | 7,072                                     |       | — |   | — |   | — |   | 7,072 |   |
| Total                                                             |       | $                                         | 251,834    |   | $ | 17,101 |   | $ | 29,536 |   | $ | 198,125 |   | $ | 7,072 |   |

 

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(1)         Includes principal and projected interest payments due under our Revolving Facility and Term Loan.  Projected interest payments are based on a 3.7% and 8.0% interest rate for the Revolving Credit Facility and the Term Loan, respectively, in effect as of December 31, 2016. Timing above assumes credit facilities are held to maturity and that there are no subsequent changes to the borrowing base.

 

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(2)         The Company has capital commitments of up to approximately A$10.6 million through 2019 of which A$5.9 milion (US$4.3 million) had been incurred through December 31, 2016 (commitment amounts in table shown in USD translated at December 31, 2016).  Timing of commitment may vary.

 

(3)  As of December 31, 2016 the Company had one rig contracted to drill seven wells during 2017.  The amount represents minimum expenditure commitments should the Company elect to terminate this contract prior to term. Subsequent to December 31, 2016, the Company commenced drilling (and therefore is not subject to the termination fee).

 

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

 

(5)  Represents commitments for the payment of salaries and other remuneration under long-term employment contracts not provided for in the consolidated financial statements.

 

(6)         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, 2016.  The amount shown does not include our Mississippian/Woodward restoration provision liability, which we expect to dispose of in 2017.

 

Subsequent to December 31, 2016, the Company contracted two additional drilling rigs with minimum expenditure commitments of $0.6 million during 2017.

 

**Item 6.  Directors, Senior Management and Employees**

 

**A.**                                    **Directors and Senior Management**

 

The following table lists the names of our directors and executive officers.

 
| **Name**           | ** ** | **Position**                                  | ** ** |
|--------------------|------------|-----------------------------------------------|------------|
| Eric P. McCrady    |       | Chief Executive Officer and Managing Director |       |
| Cathy L. Anderson  |       | Chief Financial Officer                       |       |
| Grace Ford*        |       | Chief Operating Officer                       |       |
| Mike Wolfe*        |       | Vice President of Land                        |       |
| Trina Medina*      |       | Vice President of Reservoir Engineering       |       |
| Michael D. Hannell |       | Chairman of the Board                         |       |
| Damien A. Hannes   |       | Director                                      |       |
| Neville W. Martin  |       | Director                                      |       |
| H. Weldon Holcombe |       | Director                                      |       |

 

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*                                         Officers only of Sundance Energy, Inc.

 

***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.

 

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***Cathy L. Anderson*** has been our Chief Financial Officer since December 2011. Ms. Anderson has over 30 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 served as the Chief Operating Officer of our subsidiary Sundance Energy, Inc. since August 2015 and had previously served as our Vice President of Exploration and Development of our subsidiary, Sundance Energy, Inc. (March 2013 through August 2015), and as Vice President of Geology of Sundance Energy, Inc. (September 2011 through March 2013). 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, and reservoir characterization. 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 in various geologic and team leader positions 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 of Science degree in Geology from the University of Arkansas and a Bachelor’s 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 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.

 

***Trina Medina***has served as Vice President of Reservoir Engineering of our subsidiary, Sundance Energy, Inc., since September 2015.  She has more than 20 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional, unconventional and secondary recovery evaluation and development projects, including corporate reserves and budgeting with companies such as Newfield Exploration (2007-2015), Stone Energy Corporation (2005-2007), INTEVEP and PDVSA.  Ms. Medina received a Master of Science degree in Reservoir Engineering from Texas A&M University, a Master of Science degree in Reservoir Geoscience from the Institut Francais du Petrole, and a Bachelors of Science degree in Petroleum Engineering from the Universidad Central de Venezuela.  Ms. Medina is a member of the Society of Petroleum Engineers (SPE) and a member for the Society of Petroleum Evaluation Engineers (SPEE).

 

***Michael D. Hannell*** has been a Director of Sundance since March 2006 and chairman of our board of directors since December 2008. Mr. Hannell has wide experience in the oil and gas industry, spanning some 50 years, initially in the downstream sector and subsequently in the upstream sector. His extensive experience has been in a wide range of design and construction, engineering, operations, exploration and development, marketing and 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 has previously held a number of board appointments the most recent being the chairman of Rees Operations Pty Ltd (doing business as Milford Industries Pty Ltd), an Australian automotive components and transportation container manufacturer and supplier; and  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 Mechanical Engineering (with Honours) from the University of London and is a Fellow of the Institution of Engineers Australia.  Mr. Hannell may not hold office without re-election past the annual general meeting (“AGM”) in 2018.

 

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***Damien A. Hannes*** has been a Director since August 2009. Mr. Hannes has over 25 years of finance, operations, sales and management experience. He has most recently 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, Damien 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. He holds a Bachelor of Business degree from the NSW University of Technology in Australia and subsequently completed the Institute of Chartered Accounts Professional Year before being seconded into the commercial sector. Mr. Hannes also serves as chairman of the board of directors of Australia Gold Corporation Ltd.  Mr. Hannes may not hold office without re-election past the AGM in 2019.

 

***Neville W. Martin*** has been a Director since January 2012. 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 is the former state president of the Australian Resource and Energy Law Association. Mr. Martin holds a Bachelor of Laws degree from Adelaide University. Mr. Martin also serves on the board of directors of Woomera Exploration Limited, Pawnee Energy Limited, Numedico Technologies Pty, Ltd, Anglo Russian Energy Pty, Ltd, Newklar Asset Management Pty. Ltd, Houmar Nominees Pty, Ltd and Stansbury Petroleum Investments Pty, Ltd.  Mr. Martin may not hold office without re-election past the AGM in 2019.

 

***H. Weldon Holcombe*** has been a Director 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. Mr. Holcombe may not hold office without re-election past the AGM in 2018.

 

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.

 

**Employment Agreements with Executive Officers**

 

On April 26, 2016, the Company entered into a new employment agreement (“Employment Agreement”) with our Chief Executive Officer, Eric P. McCrady, with a three-year term effective January 2016 and base remuneration of $370,000 per year, which is reviewed annually by the Remuneration and Nomination Committee.  The Employment Agreement replaces his previous agreement with the Company.  There were no material changes to the contract terms.  In January 2016, Mr. McCrady, along with our CFO, COO, VP of Land, VP of Reservoir Engineering and Non-executive Directors, voluntarily agreed to reduce their base salaries to help the Company reduce expenses and improve its cash flow during this time of low commodity prices.  In January 2017, their base salaries were restored.  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, at the date of this report, we had not entered into or finalized employment agreements with any of our other executive officers.  In August 2013, Damien Connor was appointed our Company Secretary. Mr. Connor provides services to Sundance through a contractual arrangement. None of our directors have any service contracts with Sundance or any of its subsidiaries providing for benefits upon termination of employment.

 

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**B.**                                    **Compensation**

 

Our Board of Directors recognizes that the attraction and retention of high-caliber 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 Remuneration and Nominations 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. The Remuneration and Nominations Committee retained Meridian Compensation Partners, LLC (“Meridian”), as its independent remuneration consultant for the 2016 fiscal year. Meridian was retained to provide executive and director remuneration consulting services to the Committee, including advice regarding the design and implementation of remuneration programs that are competitive and common among the U.S. oil and gas exploration and production industry, competitive market information, comparison advice with Australian companies and practice, regulatory updates and analyses and trends on executive base salary, short-term incentives, long-term incentives, benefits and perquisites.  All remuneration paid to directors and executives is valued in accordance with applicable IFRS accounting rules.

 

***Executives*** 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. For the year ended December 31, 2016, the targeted “at risk” remuneration relating to performance variability with Short-Term Incentive (“STI”) bonuses and Long-Term Incentive (“LTI”) awards represents approximately 81% for the Managing Director and approximately 75% for all other executives.

 

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:

 

·      Attract and retain highly trained, experienced, and committed executives who have the skills, education, business acumen, and background to lead a mid-tier oil and gas business;

 

·      Motivate and reward executives to drive and achieve our goal of increasing shareholder value;

 

·      Provide balanced incentives for the achievement of near-term and long-term objectives, without motivating executives to take excessive risk; and

 

·      Track and respond to developments such as the tightening in the labor market or changes in competitive pay practices.

 

The incentive compensation program has provisions for an annual cash and equity bonus in addition to the base salary levels. The annual cash bonus STI is established to reward short-term performance towards our goal of increasing shareholder value. The equity component 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.

 

During 2016, the LTI component of our incentive compensation program comprised awards made pursuant to the Sundance Energy Australia Limited Long Term Incentive Plan, as amended (the “RSU Plan”). Any grants made to employees that also serve as a director are subject to shareholder approval prior to issuance.

 

The RSU Plan provides for the issuance of restricted share units (“RSUs”) to our U.S. employees.  The RSU Plan is administered by the Board. RSUs may be granted to eligible employees from a bonus pool established at the sole discretion of our Board. The bonus pool is subject to Board and management review of both the Company and the individual employee’s performance over a measured period determined by the Remuneration and Nominations Committee and the Board. The RSUs may be settled in cash or shares at the discretion of the Board.  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.

 

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*LTI Award in 2017*

 

For the 2016 fiscal year (granted in 2017), the LTI incentives granted to executives were comprised of:

 

1)             50% of award value granted in RSUs which vest based upon the movement in Sundance ordinary share price over a three-year period (“Absolute Total Shareholder Return” or “A-TSR”).  Absolute total shareholder return (A-TSR) is calculated by the change in the Company’s ordinary share price plus dividends paid, if any, over the specified time period.  The number of shares that can be earned under the A-TSR component of the award, ranges from 0% to 150% of the target share grant, based on A-TSR calculated at the end of the three-year assessment period according to the following multiples:

 
| **Absolute TSR Goal** | ** ** | **Payout % of    Target** | ** ** |
|---------------------------------|------------|------------------------------------------|------------|
| 25% preferred return            |       | 150                                      | %          |
| 15% preferred   return          |       | 100                                      | %          |
| 8% preferred   return           |       | 50                                       | %          |
| < 8%   preferred return      |       | 0                                        | %          |

 

2)             50% of award value granted as three tranches of deferred cash, earned through appreciation in the price of Sundance’s ordinary shares during 2017, 2018 and 2019.  The base deferred cash target awards are paid only after achieving the following share performance targets:

 
| ** **                 | ** ** | **Target Share Price (Annual VWAP)** | ** ** |
|----------------------------|------------|----------------------------------------------------------|------------|
| **Payout Percentage** | ** ** | **2017**                                                 | ** ** | **2018** | ** ** | **2019** | ** ** |
| 50%                        |       | $                                                        | 0.2182     |   | $ | 0.2356 |   | $ | 0.2525 |   |
| 100%                       |       | $                                                        | 0.2323     |   | $ | 0.2671 |   | $ | 0.3072 |   |
| 150%                       |       | $                                                        | 0.2525     |   | $ | 0.3156 |   | $ | 0.3945 |   |
| 300%                       |       | $                                                        | 0.5050     |   | $ | 0.6313 |   | $ | 0.7891 |   |

 

*LTI Award in 2016*

 

For the 2015 fiscal year (granted in 2016), the LTI incentives granted to executives were comprised of:

 

1)             50% of award value granted in RSUs which vest based upon the movement in Sundance ordinary share price over a three-year period (“Absolute Total Shareholder Return” or “A-TSR”).  Absolute total shareholder return (A-TSR) is calculated by the change in the Company’s ordinary share price plus dividends paid, if any, over the specified time period.  The number of shares that can be earned under the A-TSR component of the award, ranges from 0% to 133% of the target share grant, based on A-TSR calculated at the end of the three-year assessment period according to the following multiples:

 
| **Absolute TSR Goal**                    | ** ** | **Payout % of   Target** | ** ** |
|----------------------------------------------------|------------|------------------------------------|------------|
| **1.95x (equivalent   to a 25% preferred return)** |       | 133                                | %          |
| **1.52x (equivalent   to a 15% preferred return)** |       | 100                                | %          |
| **1.26x (equivalent   to a 8% preferred return)**  |       | 50                                 | %          |
| **< 1.26x**                                     |       | 0                                  | %          |

 

2)             50% of award value granted as two tranches of deferred cash, earned through appreciation in the price of Sundance’s ordinary shares during 2017 and 2018.  The base deferred cash target awards are paid only after achieving the following share performance targets:

 

·                  Tranche 1- A 20 day volume weighted average (20-day VWAP) of A$0.297 per share for the last 20-day period in the year ending December 31, 2017.  This equates to a 25% preferred return over a two-year period.

 

·                  Tranche 2- A 20 day volume weighted average (20-day VWAP) of A$0.371 per share for the last 20-day period in the year ending December 31, 2018. This equates to a 25% preferred return over a three-year period.

 

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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 Nominations 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 Nominations Committee and are fully discretionary. Bonuses earned under the STI are typically paid in cash.  However, no STI bonuses were paid for 2016 and 2015 performance.

 

In addition, certain ceiling 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 Nominations Committee to carefully monitor the incentive compensation program to ensure its ongoing effectiveness.

 

Our U.S.-based executives receive statutory retirement benefit payments as required under applicable U.S. law and receive contributions into their retirement account at a level commensurate with all other employees.

 

***Non-executive Directors***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 9.50% as of July 1, 2014. 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.

 

The following discussion is based upon a remuneration report that we prepared in compliance with listing rules of the ASX. Mr. Wolfe and Ms. Medina are not considered key management personnel as defined under listing rules of the ASX. As a result, their remuneration is not discussed below.

 

Details of the cash remuneration, as prescribed by our home country jurisdiction, of our directors and executive officers for the year ended December 31, 2016 are as follows:

 
| ** **                   | ** ** | **Fixed Based Remuneration** | ** **    | **Share Based    Payments**   | ** ** | **Performance Based**        | ** ** |
|------------------------------|------------|----------------------------------------|---------------|-----------------------------------------|------------|-----------------------------------|------------|
| **Director**                 | ** ** | **Cash   Salary   and    Fees**   | ** **    | **Non-   monetary   Benefits (1)** | ** ** | **Post-   employment   Benefits** | ** ** | **Superannuation** | ** ** | **RSU** | ** ** | **STI-   Bonus** | ** ** | **LTI —   Share    Based (2)** | ** ** | **LTI —   Deferred    Cash (3)** | ** ** | **Total** | ** ** |
| E McCrady                    |       | $                                      | 335,846       |                                    | $          | 21,144                            |       | $ | 7,950 |   | $ | — |   | $ | — |   | $ | — |   | $ | 837,888 |   | $ | 62,032 |   | $ | 1,264,860 |   |
| M Hannell                    |       | 105,121                                |          | —                                  |       | —                            |       | 9,987 |   | — |   | — |   | — |   | — |   | 115,108 |   |
| D Hannes                     |       | 85,869                                 |          | —                                  |       | —                            |       | 8,158 |   | — |   | — |   | — |   | — |   | 94,027 |   |
| N Martin                     |       | 72,882                                 |          | —                                  |       | —                            |       | 6,924 |   | — |   | — |   | — |   | — |   | 79,806 |   |
| W Holcombe                   |       | 116,721                                |          | —                                  |       | —                            |       | — |   | — |   | — |   | — |   | — |   | 116,721 |   |
|                         |       | **$**                                  | **716,439**   |                                    | **$**      | **21,144**                        |       | **$** | **7,950** |   | **$** | **25,069** |   | **$** | **—** |   | **$** | **—** |   | **$** | **837,888** |   | **$** | **62,032** |   | **$** | **1,670,522** |   |
| **Key Management Personnel** |       |                                   |          |                                    |       |                              |       |   |   |   |   |   |   |   |   |   |   |   |   |
| C Anderson                   |       | $                                      | 267,769       |                                    | $          | 14,471                            |       | $ | 7,950 |   | $ | — |   | $ | 5,492 |   | $ | — |   | $ | 465,600 |   | 41,038 |   | $ | 802,320 |   |
| G Ford                       |       | 267,769                                |          | 10,253                                  |       | 7,950                             |       | — |   | 13,392 |   | — |   | 466,597 |   | 41,038 |   | 806,999 |   |
|                         |       | $                                      | 535,538       |                                    | $          | 24,724                            |       | $ | 15,900 |   | $ | — |   | $ | 18,884 |   | $ | — |   | $ | 932,197 |   | $ | 82,076 |   | $ | 1,609,319 |   |
|                         |       | **$**                                  | **1,251,977** |                                    | **$**      | **45,868**                        |       | **$** | **23,850** |   | **$** | **25,069** |   | **$** | **18,884** |   | **$** | — |   | **$** | **1,770,085** |   | **$** | **144,108** |   | **$** | **3,279,841** |   |

 

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| (1)    |   | Non-monetary benefits   includes car parking and payment of healthcare premiums.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (2)    |   | The fair value of the   services received in return for the LTI share based awards is based on the   allocable portion of aggregate fair value expense recognized under IFRS 2 for   the year. The fair value of the services received in return for the   time-based RSUs was determined by multiplying the number of shares granted by   the closing price of the shares on the grant date. The fair value of the   A-TSR and R-TSR shares has determined using a Monte Carlo simulation model,   as further discussed in Note 1 to the Financial Report. The amount included   in remuneration is not related to or indicative of the benefit (if any) the   individuals may ultimately realize should the RSUs vest. |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (3)    |   | The fair value of the   services received in return for the LTI deferred cash awards is based on the   allocable portion of aggregate fair value expense recognized under IFRS 2 for   the year. The fair value of the deferred cash awards has been determined   using a Monte Carlo simulation model and is remeasured at the end of each   reporting period until the award is settled. The amount included in   remuneration is not related to or indicative of the benefit (if any) the   individuals may ultimately realize should the deferred cash vest.                                                                                                                                                         |

 

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***At risk remuneration***

 

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:

 
| ** **              | ** ** | **Year ended December 31, 2016** | ** ** |
|-------------------------|------------|------------------------------------------------------|------------|
| ** **              | ** ** | **Fixed   Remuneration**                             | ** ** | **STI** | ** ** | **LTI** | ** ** | **Target   Performance   Related** | ** ** |
| E. McCrady              |       | 19                                                   | %          | 19 | % | 62 | % | 81 | % |
| C. Anderson             |       | 25                                                   | %          | 19 | % | 56 | % | 75 | % |
| G. Ford                 |       | 25                                                   | %          | 19 | % | 56 | % | 75 | % |
| Non-executive directors |       | 100                                                  | %          | — |   | — |   | — |   |

 

**C.**            **Board Practices**

 

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 Constitution specifies that there must be a minimum of three directors and a maximum of 10, and our Board of Directors may determine the number of directors within those limits;

 

·                  it is the intention of our Board of Directors that its membership consists of a majority of independent directors who satisfy the criteria recommended by the ASX Principles and Recommendations;

 

·                  the chairperson of our Board of Directors should be an independent director who satisfies the criteria for independence recommended by the ASX Principles and Recommendations; and

 

·                  our Board of Directors should, collectively, have the appropriate level of personal qualities, skills, experience, and time commitment to properly fulfill its responsibilities or have ready access to such skills where they are not available.

 

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.

 

***Committees***

 

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, 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, including for purposes of Rule 10A-3 of the Exchange Act. 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.

 

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

 

·                  appropriate systems are in place to identify, to the extent that is reasonably practical, all material risks that we face in conducting our business;

 

·                  the financial impact of those risks is understood and appropriate controls are in place to limit exposures to them;

 

·                  appropriate responsibilities are delegated to control the risks; and

 

·                  any material changes to our risk profile are disclosed in accordance with our continuous disclosure policy.

 

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:

 

·                  comply with all laws that govern us and our operations;

 

·                  act honestly and with integrity and fairness in all dealings with others and each other;

 

·                  avoid or manage conflicts of interest;

 

·                  use our assets properly and efficiently for the benefit of all of our shareholders; and

 

·                  seek to be an exemplary corporate citizen.

 

***Reserves Committee.***  The members of our Reserves Committee are Messrs. Holcombe (Chairman), Hannell and Martin, all of whom are independent, non-executive directors. This committee will assist the Board of Directors in monitoring:

 

·      the integrity of the Company’s oil, natural gas, and natural gas liquid reserves (Reserves);

 

·      the independence, qualifications and performance of the Company’s independent reservoir engineers; and

 

·      the compliance by the Company with legal and regulatory requirements.

 

**Compliance with NASDAQ Rules**

 

NASDAQ listing rules allow for a foreign private issuer, such as Sundance, to follow its home country practices in lieu of certain of NASDAQ’s corporate governance rules. NASDAQ listing rules require that we disclose the home country practices that we will follow in lieu of compliance with NASDAQ corporate governance rules.  The following describes the home country practices and the related NASDAQ rule:

 

***Majority of Independent Directors****.** ***We follow home country practice rather than NASDAQ’s requirement that the majority of the board of directors of each issuer be comprised of independent directors.  While ASX listing rules do not require us to have a majority of independent directors, as noted above it is the intention of our Board of Directors that its membership consist of a majority of independent directors who satisfy the criteria recommended by the ASX Principles and Recommendations. As of the date of this annual report, our Board of Directors comprises a majority of independent directors.

 

***Executive Sessions****. *We follow home country practice rather than NASDAQ’s requirement that our independent directors meet regularly in executive sessions. ASX listing rules and the Corporations Act do not require the independent directors of an Australian company to have such executive sessions.

 

***Quorum****. *We follow home country practice rather than NASDAQ’s requirement that each issuer provide in its by-laws for a quorum of at least 33 1/3 percent of the outstanding shares of the issuer’s voting common stock for any meeting of shareholders. In compliance with Australian law, our Constitution provides that three shareholders present shall constitute a quorum for a general meeting.

 

***Shareholder Approval for Capital Issuances****. *We follow home country practice rather than NASDAQ’s requirement that issuers 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. Applicable Australian law and rules differ from NASDAQ requirements, with the ASX listing rules providing generally for prior shareholder approval in numerous circumstances, including (i) issuance of equity securities exceeding 15% of our issued share capital in any 12-month period (but, in determining the 15% limit, securities issued under an exception to the rule or with shareholder approval are not counted), (ii) issuance of equity securities to related parties (as defined in the ASX listing rules), and (iii) directors or their associates acquiring securities under an employee incentive plan.

 

**D.**                                    **Employees**

 

As of December 31, 2016, we had 54 full-time employees, including 16 in executive, finance and accounting and administration, 3 in geology, 27 in production and engineering and 8 in land.  In January 2016, we had a head count reduction of approximately 30% related to a reduction in force. All of our employees are located in the United States. 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.

 

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**E.**                                    **Share Ownership**

 

**Number of Restricted Shares Units Held by Executive Officers**

 
| **Key   Management   Personnel** | ** ** | **Balance   12/31/2015** | ** ** | **Issued as   Compensation** | ** ** | **Forfeited   RSUs** | ** ** | **RSUs   converted to   ordinary   shares** | ** ** | **Balance at   12/31/2016** | ** ** | **Market Value   of Unvested   RSUs   12/31/2016 (1)** | ** **    |
|----------------------------------|------------|--------------------------|------------|-----------------------------------|------------|----------------------|------------|--------------------------------------------------|------------|----------------------------------|------------|-----------------------------------------------------------------------|---------------|
| E McCrady (2)                    |       | 3,620,228                |       | 5,113,281                         |       | —               |       | (1,647,993                                       | )          | 7,085,516                        |       | $                                                                     | 1,121,894     |   |
| C Anderson                       |       | 2,496,670                |       | 2,396,858                         |       | —               |       | (978,866                                         | )          | 3,914,662                        |       | 619,833                                                               |          |
| G Ford                           |       | 2,595,756                |       | 2,396,858                         |       | —               |       | (1,075,698                                       | )          | 3,916,916                        |       | 620,190                                                               |          |
| **Total**                        |       | **8,712,654**            |       | **9,906,997**                     |       | **—**           |       | **(3,702,557**                                   | **)**      | **14,917,094**                   |       | **$**                                                                 | **2,361,917** |   |

 

----

(1)         Market value based on the Company’s closing share price on December 31, 2016 or USD $0.158 based on the foreign currency exchange spot rate published by the Reserve Bank of Australia.

(2)         Mr. McCrady’s RSUs were approved by the shareholders at the AGM held on May 27, 2016.

 

**Item 7.  Major Shareholders and Related Party Transactions**

 

**A.**                                    **Major Shareholders**

 

The following table presents certain information regarding the beneficial ownership of our ordinary shares based on 1,249,351,617 ordinary shares outstanding as of April 10, 2017, by:

 

·                  each person known by us (through substantial shareholder notices filed with the ASX) to be the beneficial owner of 5% or more of our ordinary shares;

 

·                  each of our directors and executive officers individually; and

 

·                  each of our directors and executive officers as a group.

 

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 April 10, 2017, we had 65 shareholders of record in the United States. These shareholders held an aggregate of 7,917,988 of our outstanding ordinary shares, or less than 1% of our outstanding ordinary shares.  The Bank of New York Mellon, which is the depositary of our ADS program, held approximately 4.2% of our total outstanding ordinary shares.  The number of beneficial owners of our ADSs in the United States is likely to be much larger than the number of record holders of our ordinary shares in the United States.

 

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.

 

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| ** **                                          | ** ** | **Ordinary Shares   Beneficially Owned** | ** ** |
|-----------------------------------------------------|------------|----------------------------------------------------|------------|
| **Shareholder**                                     | ** ** | **Number**                                         | ** ** | **Percent** | ** ** |
| ***5% Shareholders***                               |       |                                               |       |   |   |
| Gaffwick Pty Ltd (1)                                |       | 140,769,646                                        |       | 11.93 | % |
| James Taylor (2)                                    |       | 64,804,045                                         |       | 5.19 | % |
| Advisory Research, Inc. (3)                    |       | 56,024,156                                         |       | 10.02 | % |
| ***Officers and Directors***                        |       |                                               |       |   |   |
| Eric P. McCrady(4)                                  |       | 4,766,169                                          |       | * |   |
| Michael D. Hannell                                  |       | 1,148,500                                          |       | * |   |
| Damien A. Hannes(5)                                 |       | 6,247,716                                          |       | * |   |
| Neville W. Martin(6)                                |       | 695,109                                            |       | * |   |
| H. Weldon Holcombe                                  |       | 746,700                                            |       | * |   |
| Cathy L. Anderson(7)                                |       | 1,648,104                                          |       | * |   |
| Grace Ford(8)                                       |       | 1,444,706                                          |       | * |   |
| Officers and directors as a group   (seven persons) |       | 16,697,004                                         |       | 1.3 | % |

 

----

*                                         Represents beneficial ownership of less than 1% of the outstanding ordinary shares of Sundance.

 

(1)           This information is based on a Form 604 filed with the ASX on July 22, 2016. The address for Gaffwick Pty Ltd is Level 9, 20 Hunter Street, Sydney, NSW, 2000.

 

(2)           This information is based on a Form 603 filed with the ASX on March 3, 2017. The mailing address for James Taylor is PO Box 656, Bondi Junction, NSW, 1355.

 

(3)           This information is based on a Form 604 filed with the ASX on December 17, 2015. The address for Advisory Research Inc is 180 North Stenson Ave , Suite 5500 Chicago, Illinois, 60601.

 

(4)                                 Includes restricted share units that are issuable or scheduled to vest within 60 days of April 10, 2017 totaling 683,035 shares.

 

(5)                                 Includes (i) 493,243 ordinary shares held by Mr. Hannes individually and (ii) 5,754,473 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.

 

(6)                                 Includes (i) 96,924 ordinary shares held by Mr. Martin individually, and (ii) 598,185 ordinary shares held in trust of which Mr. Martin serves as trustee and is a beneficiary.

 

(7)                                 Includes restricted share units that are issuable or scheduled to vest within 60 days of April 10, 2017 totaling 380,652 shares.

 

(8)                                 Includes restricted share units that are issuable or scheduled to vest within 60 days of April 10, 2017 totaling 382,906 shares.

 

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):

 

·                  IOOF Holdings Limited (“IOOF”) became a substantial shareholder on August 15, 2012, when it reported that it held 13,970,252 ordinary shares, or 5.042%, of the total voting power as of that date. Between August 2012 and March 27, 2015, IOOF acquired an aggregate of 69,370,881 ordinary shares for A$55,792,006 and sold an aggregate of 40,549,307 ordinary shares for A$37,780,387. On March 18, 2016, IOOF reported that as of March 16, 2016, it was no longer a substantial shareholder.

 

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

 

**B.**                                    **Related Party Transactions**

 

From January 1, 2016 through the date of this report, 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.

 

There were no material related party transactions for the year ended December 31, 2016, 2015 and 2014.

 

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**C.**                                    **Interest of Experts and Counsel**

 

Not applicable.

 

**Item 8.  Financial Information**

 

**A.**                                    **Consolidated Financial Statements and Other Financial Information**

 

Our financial statements are included in Item 18 “Financial Statements.”

 

**Legal Proceedings**

 

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 or its directors of senior management, except as noted below.

 

In August 2015, the Company received notice from the buyer of its non-operated Phoenix properties sold in December 2013 that they filed a lawsuit against the Company.  The claim of $0.9 million relates to costs not included by the buyer on the final post-closing settlement, for which it seeks reimbursement from the Company.  The Company does not believe the case has merit and intends to vigorously defend itself.

 

**Dividends**

 

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.

 

**B.**                                    **Significant Changes**

 

On March 1, 2017, the Company entered into a binding sale and purchase agreement to divest of its assets located in the Anadarko Basin of Oklahoma for cash of $18.5 million.  The assets being sold include all of the Oklahoma wells and acreage owned by the Company.  The transaction is subject to several common closing conditions such as confirmatory due diligence but is not subject to any financing contingencies.  The Company expects the transaction to close by May 2017.

 

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**Item 9.  The Offer and Listing**

 

**A.**                                    **Offer and Listing Details**

 

**Pricing History**

 

***The NASDAQ Stock Market***

 

Since September 7, 2016, our ordinary shares in the form of ADSs have been trading on NASDAQ under the symbol “SNDE.” The following table sets forth the high and low market prices for our ADSs for the periods indicated as reported on NASDAQ. All prices are in U.S. dollars.

 
| ** **                                       | ** ** | **US$ High** | ** ** | **US$ Low** | ** ** |
|--------------------------------------------------|------------|-------------------|------------|------------------|------------|
| **Annual:**                                      |       |              |       |             |       |
| ***Fiscal   year ended December 31***       |       |              |       |             |       |
| 2016                                             |       | 16.00             |       | 9.75             |       |
| **Quarterly:**                                   |       |              |       |             |       |
| ***Fiscal   year ended December 31, 2017*** |       |              |       |             |       |
| First quarter                                    |       | 17.99             |       | 8.75             |       |
| ***Fiscal   year ended December 31, 2016*** |       |              |       |             |       |
| Fourth quarter                                   |       | 16.25             |       | 10.52            |       |
| Third quarter                                    |       | 17.60             |       | 9.75             |       |
| **Most Recent   Six Months:**                    |       |              |       |             |       |
| March 2017                                  |       | 10.76             |       | 8.75             |       |
| February 2017                               |       | 12.78             |       | 9.03             |       |
| January 2017                                |       | 17.99             |       | 14.00            |       |
| December 2016                               |       | 15.92             |       | 14.50            |       |
| November 2016                               |       | 14.25             |       | 11.56            |       |
| October 2016                                |       | 15.04             |       | 13.20            |       |

 

On April 17, 2017, the closing price of our ADSs as traded on the NASDAQ was $8.50 per ADS.

 

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***Australian Securities Exchange***

 

The following table presents, for the periods indicated, the high and low market prices for our ordinary shares reported on the ASX, under the symbol “SEA.” All prices are in Australian dollars.

 
| ** **                                        | ** ** | **High** | ** ** | **Low** | ** ** |
|---------------------------------------------------|------------|----------|------------|---------|------------|
| ** **                                        | ** ** | **A$**   | ** ** | **A$**  | ** ** |
| **Annual:**                                       |       |     |       |    |       |
| ***Fiscal year ended December 31***          |       |     |       |    |       |
| 2016                                              |       | 0.27     |       | 0.06    |       |
| 2015                                              |       | 0.71     |       | 0.16    |       |
| 2014                                              |       | 1.42     |       | 0.38    |       |
| 2013                                              |       | 1.18     |       | 0.76    |       |
| ***Six-month period ended   December 31***   |       |     |       |    |       |
| 2012                                              |       | 0.85     |       | 0.38    |       |
| ***Fiscal year ended   June 30***            |       |     |       |    |       |
| 2012                                              |       | 0.88     |       | 0.36    |       |
| **Quarterly:**                                    |       |     |       |    |       |
| ***Fiscal year ending   December 31, 2017*** |       |     |       |    |       |
| First Quarter                                     |       | 0.24     |       | 0.11    |       |
| ***Fiscal year ended   December 31, 2016***  |       |     |       |    |       |
| Fourth Quarter                                    |       | 0.22     |       | 0.15    |       |
| Third Quarter                                     |       | 0.18     |       | 0.10    |       |
| Second Quarter                                    |       | 0.22     |       | 0.10    |       |
| First Quarter                                     |       | 0.27     |       | 0.06    |       |
| ***Fiscal year ended   December 31, 2015***  |       |     |       |    |       |
| Fourth Quarter                                    |       | 0.39     |       | 0.16    |       |
| Third Quarter                                     |       | 0.53     |       | 0.24    |       |
| Second Quarter                                    |       | 0.71     |       | 0.45    |       |
| First Quarter                                     |       | 0.63     |       | 0.45    |       |
| **Most Recent Six   Months:**                     |       |     |       |    |       |
| March 2017                                   |       | 0.15     |       | 0.11    |       |
| February 2017                                |       | 0.16     |       | 0.11    |       |
| January 2017                                 |       | 0.24     |       | 0.20    |       |
| December 2016                                |       | 0.22     |       | 0.19    |       |
| November 2016                                |       | 0.19     |       | 0.15    |       |
| October 2016                                 |       | 0.20     |       | 0.17    |       |

 

On April 17, 2017 the closing price of our ordinary shares as traded on the ASX was A$0.105 per ordinary share (U.S.$0.08 per share based on the foreign exchange rate of A$1.00 to $0.7590 as published by the Reserve Bank of Australia as of April 17, 2017.

 

As of April 10, 2017, we had 1,249,351,617 ordinary shares outstanding, with 7,917,988 of our ordinary shares being held in the United States by 65 holders of record and 1,204,317,759 of our ordinary shares being held in Australia by 4,211 holders of record. Among these shares, 52,969,100 ordinary shares are in the form of ADSs. A large number of our ordinary shares are held in nominee companies so we cannot be certain of the origin of those beneficial owners.

 

**B.**                                   **Plan of Distribution**

 

Not applicable.

 

**C.**                                    **Markets**

 

Our ordinary shares trade on the ASX under the symbol “SEA.”  Since September 7, 2016, our ordinary shares in the form of ADSs have been trading on NASDAQ under the symbol “SNDE.”

 

**D.**                                    **Selling Shareholders**

 

Not applicable.

 

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**E.**                                    **Dilution**

 

Not applicable.

 

**F.**                                     **Expenses of the Issue**

 

Not applicable.

 

**Item 10.  Additional Information**

 

**A.**                                    **Share Capital**

 

Not applicable.

 

**B.**                                    **Our Constitution**

 

The information called for by this Item 10.B. has been reported previously in our registration statement on form 20-F (File No. 000-55246) filed with the SEC on July 11, 2014 as amended on Form 20-F/A on August 26, 2014, under the heading “Additional Information—Our Constitution” and is incorporated by reference into this annual report.

 

**C.**                                    **Material Contracts**

 

***Credit Facilities***

 

On May 14, 2015, Sundance Energy Australia Limited and Sundance Energy, Inc. entered into the Credit Agreement with Morgan Stanley Energy Capital, Inc., as administrative agent, and the lenders from time to time party thereto, which provides for our $300 million Revolving Facility and $125 million Term Loan. The Revolving Facility is subject to a borrowing base, which was set initially at $75 million.  The borrowing base was reduced to $67 million on December 30, 2015, which was the amount outstanding.  The Revolving Facility matures May 14, 2020 and the Term Loan matures November 14, 2020.

 

The Revolving Facility and Term Loan refinanced the Company’s credit facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively.

 

For a description of the material terms of our credit facilities, see Item 5.B. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—*Credit Facilities*.”

 

**D.**                                    **Exchange Controls**

 

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.

 

**E.**                                    **Taxation**

 

*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 tax laws in force as of the date of this annual report, and is subject to changes in the relevant 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.*

 

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*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, hold 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.*

 

**U.S. Federal Income Tax Considerations**

 

The following summary describes the material U.S. federal income tax consequences to U.S. holders of the acquisition, ownership and disposition of our ordinary shares and ADSs as of the date hereof. Except where noted, this summary deals only with ordinary shares or ADSs 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:

 

·                  insurance companies;

 

·                  financial institutions;

 

·                  individual retirement and other tax-deferred accounts;

 

·                  regulated investment companies;

 

·                  real estate investment trusts;

 

·                  individuals who are former U.S. citizens or former long-term U.S. residents;

 

·                  brokers or dealers in securities or currencies;

 

·                  traders that elect to use a mark-to-market method of accounting;

 

·                  investors in pass-through entities for U.S. federal income tax purposes;

 

·                  tax-exempt entities;

 

·                  persons subject to the alternative minimum tax;

 

·                  persons that hold ordinary shares or ADSs as a position in a straddle or as part of a hedging, wash sale, constructive sale or conversion transaction for U.S. federal income tax purposes;

 

·                  persons that have a functional currency other than the U.S. dollar;

 

·                  persons that own (directly, indirectly or constructively) 10% or more of our equity; or

 

·                  persons that are not U.S. holders.

 

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:

 

·                  an individual who is a citizen or resident of the United States;

 

·                  a corporation, or other entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States or any state thereof or the District of Columbia;

 

·                  an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

 

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·                  a trust (i) the administration of which is subject to the primary supervision of a court in the United States and for which one or more U.S. persons have the authority to control all substantial decisions or (ii) that has an election in effect under applicable income tax regulations to be treated as a U.S. person.

 

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.

 

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.**

 

***ADSs***

 

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.

 

**Distributions**

 

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 or ADSs, with respect to ordinary shares or ADSs 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 depository, 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 or ADSs 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 (i) either (a) 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, or (b) the dividends are with respect to ordinary shares or ADSs readily tradable on a U.S. securities market, (ii) 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. 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 advisors.

 

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.

 

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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 or ADSs 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*.”

 

**Sale, Exchange or other Disposition of Ordinary Shares or ADSs**

 

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.*”

 

**Passive Foreign Investment Company**

 

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, 2016. 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, 2017. 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.

 

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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 excess distribution or gain will be allocated ratably over the U.S. holder’s holding period for the ordinary shares or ADSs;

 

·                  the amount allocated to the current taxable year, and any taxable year prior to the first taxable year in which we are a PFIC, will be treated as ordinary income; and

 

·                  the amount allocated to each other year will be subject to income tax at the highest rate in effect for that year and the interest charge generally applicable to underpayments of tax will be imposed on the resulting tax attributable to each such year.

 

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. Treasury 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 advisor 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. A class of stock is “regularly traded” on an exchange or market for any calendar year during which that class of stock is traded, other than in de minimis quantities, on at least 15 days during each calendar quarter.  Under current law, the mark-to-market election may be available to U.S. holders of ordinary shares and ADSs because the ordinary shares and ADSs are listed on the ASX and NASDAQ, respectively, both of which constitute a qualified exchange.  There there can be no assurance, however, that the ordinary shares or ADSs will be “regularly traded” for purposes of the mark-to-market election.

 

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 ordinary shares or ADSs at the end of your taxable year over your adjusted tax basis in the ordinary shares or ADSs. You will be entitled to deduct as an ordinary loss in each such year the excess of your adjusted tax basis in the ordinary shares or 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 ordinary shares or 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 ordinary shares or 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 ordinary shares or 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 advisor 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.

 

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

 

**Medicare Tax**

 

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.

 

**Backup Withholding Tax and Information Reporting Requirements**

 

U.S. backup withholding tax and information reporting requirements may 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 a result of 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 associated 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 U.S. federal or other 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.**

 

**Australian Tax Considerations**

 

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 our ordinary shares or ADSs. This discussion is based upon existing Australian tax law as of the date of this annual report, 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 or ADSs 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 our shares or ADSs. As used in this summary a “Non-Australian Shareholder” is a holder that is not an Australian tax resident and is not carrying on business in Australia through a permanent establishment.

 

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***Nature of ADSs for Australian Taxation Purposes***

 

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 Shareholders of ordinary shares for Australian taxation purposes. We note that the holder of an ADS will be treated for Australian tax purposes as the owner of the underlying ordinary shares that are represented by such ADSs.

 

***Taxation of Dividends***

 

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. An exemption for dividend withholding tax can also apply to unfranked dividends that are declared to be conduit foreign income (“CFI”), and paid to Non-Australian Shareholders. 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 declared to be CFI paid by us to a resident of the United States which is beneficially entitled to that dividend is limited to 15% where that resident is a qualified person for the purposes of the Double Taxation Convention between Australia and the United States.

 

If a Non-Australian Shareholder is a company and 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.

 

***Tax on Sales or other Dispositions of Shares—Capital gains tax***

 

Non-Australian 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.

 

Non-Australian 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. 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 Non-Australian 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 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%. This rate does not include the Temporary Budget Repair Levy of 2% that applies in certain circumstances. Some relief from Australian income tax may be available to Non-Australian Shareholders under the Double Taxation Convention between the United States and Australia.

 

To the extent an amount would be included in a Non-Australian 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.

 

***Tax on Sales or other Dispositions of Shares—Foreign Resident Capital Gains Withholding Tax***

 

Provided that the sale of shares occur on an approved stock exchange such as NASDAQ or the ASX, Non-Australian Shareholder should not be subject to foreign resident capital gains withholding tax in Australia.

 

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***Dual Residency***

 

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.

 

***Stamp Duty***

 

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

 

***Australian Death Duty***

 

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).

 

***Goods and Services Tax***

 

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

 

**F.**                                     **Dividends and Paying Agents**

 

Not applicable.

 

**G.**                                   **Statement by Experts**

 

Not applicable.

 

**H.**                                   **Documents on Display**

 

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.

 

We are subject to periodic reporting and other informational requirements of the Exchange Act as applicable to foreign private issuers. Specifically, we are required to file annually a Form 20-F no later than four months after the close of each fiscal year. Copies of reports and other information, when so filed, may be inspected without charge and may be obtained at prescribed rates at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information regarding the Washington, D.C. Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a web site at *www.sec.gov* that contains reports, proxy and information statements, and other information regarding registrants that make electronic filings with the SEC using its EDGAR system. As a foreign private issuer, we are exempt from the rules under the Exchange Act prescribing the furnishing and content of quarterly reports and proxy statements, and officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act.

 

We are subject to the informational requirements of the ASX. Our public filings with the ASX are electronically available from the ASX website (www.asx.com.au).

 

We will also furnish The Bank of New York Mellon, the depositary of our ADSs, with all notices of shareholder meetings and other reports and communications that are made generally available to our shareholders. The depositary, to the extent permitted by law, shall arrange for the transmittal to the registered holders of ADRs of all notices, reports and communications, together with the governing instruments affecting our shares and any amendments thereto. Such documents are also available for inspection by registered holders of ADRs at the principal office of the depositary.

 

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**I.**                                        **Subsidiary Information**

 

Not applicable.

 

**Item 11.  Quantitative and Qualitative Disclosures about Market Risk**

 

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.

 

See to Note 34 of our December 31, 2016 financial statements included in this annual report for detailed information on our financial risk management.

 

**Treasury Risk Management**

 

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.

 

***Financial Risk Exposure and Management***

 

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, 2016, none of our deposits were fixed. It is our policy to keep surplus cash in interest-yielding deposits.

 

***Interest Rate Sensitivity Analysis***

 

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 impact on equity is the same as the impact on income. The effect on income as a result of changes in the interest rate, based on net debt position as of December 31, 2016, with all other variables remaining constant for the year ended December 31, 2016, would be as follows (in $ ‘000s):

 
| Effect on profit before tax   Increase/(decrease) |   |   |   |
|---------------------------------------------------|--------|--------|--------|
| —increase in interest   rates + 2% |   | $      | (3,357 | ) |
| —decrease in interest   rates - 2% |   | 396    |   |
|                                                   |        |        |        |  |

 

***Commodity Price Risk Exposure and Management***

 

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 at least 50% of our proved developed reserves through 2020 and for a rolling 36 month period thereafter, as required by our Credit Agreement.

 

The following table provides a summary of derivative contracts as of December 31, 2016:

 
| ** **             | ** ** | **Oil Contracts (Weighted Average)(1)** | ** ** |
|------------------------|------------|--------------------------------------------------------|------------|
| **Contract Year** | ** ** | **Units (Bbl)**                                   | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| 2017                   |       | 930,000                                                |       | $ | 49.12 |   | $ | 58.78 |   |
| 2018                   |       | 612,000                                                |       | $ | 49.88 |   | $ | 58.92 |   |
| 2019                   |       | 300,000                                                |       | $ | 52.51 |   | $ | 54.31 |   |
| Total                  |       | 1,842,000                                              |       | $ | 49.87 |   | $ | 58.10 |   |

 

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| ** **             | ** ** | **Natural Gas Contracts (Weighted Average) (1)** | ** ** |
|------------------------|------------|---------------------------------------------------------------------------|------------|
| **Contract Year** | ** ** | **Units (Mmbtu)**                                                    | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| 2017                   |       | 1,680,000                                                                 |       | $ | 2.86 |   | $ | 3.21 |   |
| 2018                   |       | 1,290,000                                                                 |       | $ | 2.95 |   | $ | 3.36 |   |
| 2019                   |       | 720,000                                                                   |       | $ | 2.95 |   | $ | 3.78 |   |
| Total                  |       | 3,690,000                                                                 |       | $ | 2.91 |   | $ | 3.37 |   |

 

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(1)         The Company’s outstanding derivative positions include swaps totaling 1,182,000 Bbls and 1,830,000 Mcf, which are included in both the weighted average floor and ceiling value.

 

***Commodity Prices Risk Sensitivity Analysis***

 

The table below summarizes the impact on income and equity for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on income as these derivative financial instruments have not been designated as hedges and are, and therefore, fair valued through the statement of operations. The effect on income as a result of changes in crude oil and natural gas prices, with all variables remaining constant, for the year ended December 31, 2016 would be as follows (in $ ‘000s):

 
| Effect on profit before tax   Increase/(decrease) |   |   |    |
|---------------------------------------------------|--------|--------|---------|
| *Oil*                                             |   |   |    |
| —improvement in oil price of $10   per Bbl   |   | $      | (12,813 | ) |
| —decline in oil price of $10 per   Bbl       |   | 16,233 |    |
| *Gas*                                             |   |   |    |
| —improvement in gas price of   $0.50 per Mcf |   | $      | (1,423  | ) |
| —decline in gas price of $0.50   per Mcf     |   | 1,306  |    |

 

***Counterparty and Customer Credit Risk***

 

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. At December 31, 2016, we had one customer that owed us approximately $1.5 million and accounted for approximately 21% of total accrued revenue receivables. In addition, the Group had one joint-interest partner that owed the Group approximately $4.0 million of revenue from a non-operated property.  In 2017, the Company expects to begin marketing the production from this property itself; which will reduce its credit risk exposure from this party. For joint interest billing receivables, if payment is not made, we can withhold future payments of revenue, as such, there is minimal to no credit risk associated with these receivables.

 

**Item 12.  Description of Securities Other than Equity Securities**

 

**A.**                                    **Debt Securities**

 

Not applicable.

 

**B.**                                    **Warrants and Rights**

 

Not applicable.

 

**C.**                                    **Other Securities**

 

Not applicable.

 

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**D.**                                    **American Depositary Shares**

 

**Fees and Charges Our ADS Holders May Have to Pay**

 

Holders of our ADSs may have to pay to the depositary, either directly or indirectly, fees or charges up to the amounts set forth in the table below.

 
| **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.

 

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The depositary may convert currency itself or through any of its affiliates and, in those cases, acts as principal for its own account and not as agent, advisor, broker or fiduciary on behalf of any other person and earns revenue, including, without limitation, transaction spreads, that it will retain for its own account.  The revenue is based on, among other things, the difference between the exchange rate assigned to the currency conversion made under the deposit agreement and the rate that the depositary or its affiliate receives when buying or selling foreign currency for its own account.  The depositary makes no representation that the exchange rate used or obtained in any currency conversion under the deposit agreement will be the most favorable rate that could be obtained at the time or that the method by which that rate will be determined will be the most favorable to ADS holders, subject to the depositary’s obligations under the deposit agreement.  The methodology used to determine exchange rates used in currency conversions is available upon request.

 

**PART II**

 

**Item 13.  Defaults, Dividend Arrearages and Delinquencies**

 

Not applicable.

 

**Item 14.  Material Modifications to the Rights of Security Holders and Use of Proceeds**

 

Not applicable.

 

**Item 15.  Controls and Procedures**

 

*(a)*         *Disclosure Controls and Procedures*

 

As of December 31, 2016, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act). There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.

 

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of December 31, 2016 to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act are (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures.

 

*(b)*         *Management’s Annual Report on Internal Control over Financial Reporting*

 

Our management assessed the effectiveness of our internal control over financial reporting as of the year ended December 31, 2016. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (2013). Based on management’s assessment and those criteria, our management believes that we maintained effective internal control over financial reporting as of December 31, 2016.

 

*(c)*          *Attestation Report of the Registered Public Accounting Firm*

 

Not applicable.

 

*(d)*         *Changes in Internal Control over Financial Reporting*

 

There was no change in our internal control over financial reporting that occurred during the period covered by this annual report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

**Item 16A.  Audit Committee Financial Expert**

 

The Board of Directors has determined that Damien Hannes qualifies as an “audit committee financial expert,” as that term is defined in Item 16A of Form 20-F and is independent.  See “Item 6.A—Directors, Senior Management and Employees” for Mr. Hannes’s experience and qualifications.

 

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**Item 16B.  Code of Ethics**

 

The Company has a Code of Conduct and Ethics which establishes the practices that directors, management and staff must follow in order to comply with the law, meet shareholder expectations, maintain public confidence in Sundance’s integrity, and provide a process for reporting and investigating unethical practices. The Code of Conduct is available in the corporate governance section of Sundance’s website at http://www.sundanceenergy.net/governance.cfm.

 

**Item 16C.  Principal Accountant Fees and Services**

 

The following table sets forth the aggregate fees paid by categories specified below in connection with certain professional services rendered by Deloitte Touche Tomatsu and Ernst and Young, our principal external auditors, for the years ended December 31, 2016 and 2015, respectively.

 
| ** **                                                                                                  | ** ** | **Year Ended   December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------|------------|
| ** **                                                                                                  | ** ** | **2016**                                | ** ** | **2015** | ** ** |
| Audit fees (a)                                                                                              |       | $                                       | 461,360    |   | $ | 462,950 |   |
| Professional services related to filing of various forms with   the U.S. Securities and exchange Commission |       | —                                  |       | 13,000 |   |
| Tax fees(b)                                                                                                 |       | —                                  |       | 61,535 |   |
| Total                                                                                                       |       | $                                       | 461,360    |   | $ | 537,485 |   |

 

----

(a) Fees for audit services billed in 2016 and 2015 consisted of the audit of  the Company’s annual financial statements; and the review of the Company’s half-year financial statements.  Of the amounts paid in 2016, $361,360 was paid to the Company’s former auditor, Ernst & Young, who provided audit services for the year ended December 31, 2015. The Company paid $100,000 in 2016 to Deloitte Touche Tohmatsu Limited as its auditor for the year ended December 31, 2016.  The remainder of the fees related to the audit of the Company’s December 31, 2016 and the year then ended financial statements were incurred and paid in 2017.

 

(b) Fees for tax services billed in 2015 consisted of tax compliance and tax planning advice performed by Ernst and Young. Tax compliance services are services rendered based upon facts already in existence or transactions that have already occurred to document, compute and obtain government approval for amounts to be included in tax filings.

 

**Pre-approval policies and procedures**

 

The policy of our Audit Committee is to pre-approve all audit and non-audit services performed by our auditors in order to assure that the provision of such services does not impair the audit firm’s independence.  Pre-approved services include audit services, audit-related services, tax services and other services as described above, other than those for de minimus services which are approved by our Audit Committee prior to the completion of the audit.  Additional services may be pre-approved by the Audit Committee on an individual basis.

 

All of the audit fees, audit-related fees and tax fees described in this item have been approved by the Audit Committee.

 

**Item 16D.  Exemptions from the Listing Standards for Audit Committees.**

 

Not applicable.

 

**Item 16E.  Purchases of Equity Securities by the Issuer and Affiliated Purchasers**

 

Not applicable.

 

**Item 16F.  Change in Registrant’s Certifying Accountant**

 

Not applicable.

 

**Item 16G.  Corporate Governance**

 

Refer to “Item 6.C.—Compliance with NASDAQ Rules” regarding the Company’s corporate governance practices and the key differences between the ASX listing rules and NASDAQ listing rules as they apply to us.

 

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**Item 16H.  Mine Safety Disclosure**

 

Not applicable.

 

**PART III**

 

**Item 17.  Financial Statements**

 

Refer to “Item 18 — Financial Statements” below

 

**Item 18.  Financial Statements**

 

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

 

**Item 19.  Exhibits**

 

See Exhibit Index.

 

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**Appendix A**

 

**GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS**

 

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.

 

***Boe/d.***  Barrels of oil equivalent per day.

 

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

 

***Constant case.***     The reserve report case using the first of the month average pricing for the trailing 12 months held constant throughout the life of the reserves as prescribed by the U.S. Securities and Exchange Commission (SEC).

 

***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 hole.***  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.

 

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***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.

 

***Mcf.***  Thousand cubic feet of natural gas.

 

***MMBtu.***  Million British Thermal Units.

 

***Natural gas liquids*** or ***NGLs.***  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.

 

***NYMEX.***  New York Mercantile Exchange.

 

***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.

 

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***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 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 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 proved 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.

 

***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.

 

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***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.

 

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**INDEX TO FINANCIAL STATEMENTS**

 
| **Sundance Energy Australia   Limited**                                                                                                      |   |
|----------------------------------------------------------------------------------------------------------------------------------------------|--------|
| Report of Independent Registered Public   Accounting Firm                                                                                    | F-2    |
| Consolidated Statement of Profit or Loss   and Other Comprehensive Income (Loss) for the Years Ended December 31,   2016, 2015 and 2014 | F-4    |
| Consolidated Statements of Financial   Position, December 31, 2016 and 2015                                                             | F-5    |
| Consolidated Statements of Changes in   Equity for the Years Ended December 31, 2016, 2015 and 2014                                     | F-6    |
| Consolidated Statements of Cash Flows for   the Years Ended December 31, 2016, 2015 and 2014                                            | F-7    |
| Notes to the Consolidated Financial   Statements                                                                                             | F-8    |

 

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**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

 

To the shareholders and board of directors of Sundance Energy Australia Limited

 

We have audited the accompanying consolidated statement of financial position of Sundance Energy Australia Limited as of December 31, 2016, and the related consolidated statement of profit or loss and other comprehensive income (loss), consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated 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 consolidated 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 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 consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sundance Energy Australia Limited as of December 31, 2016, and the results of its operations and its cash flows for the year ended December 31, 2016, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

 

/s/ DELOITTE TOUCHE TOHMATSU

 

Sydney, Australia

 

April 28, 2017

 

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**Report of Independent Registered Public Accounting Firm**

 

The Board of Directors and Shareholders of Sundance Energy Australia Limited

 

We have audited the accompanying consolidated statements of financial position of Sundance Energy Australia Limited as of December 31, 2015 and 2014, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2015. 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. We were not engaged to perform an audit of the Company’s 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, and evaluating the overall financial statement presentation. We believe that our audits provide 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, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

 

As described in Note 7 of the accompanying consolidated financial statements, the Company’s management identified and has retrospectively restated for an error in its December 31, 2015 income tax accounting.

 

/s/ Ernst & Young

 

Ernst & Young  200 George Street  Sydney NSW 2000  Australia

 

May 2, 2016, except as to Note 7, which is as of February 24, 2017

 

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**CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME (LOSS)**

 
| **For the year ended 31 December**                                | ** ** | **Note** | ** ** | **2016   US$’000** | ** **  | **2015   US$’000**            | ** ** | **2014   US$’000** | ** ** |
|--------------------------------------------------------------------------------------------|------------|----------|------------|-------------------------|-------------|------------------------------------|------------|-------------------------|------------|
|                                                                                       |       |     |       |                    |        | **(Restated —   see Note 7)** |       |                    |       |
| Oil and natural gas revenue                                                                |       | 4        |       | $                       | 66,609      |                               | $          | 92,191                  |       | $ | 159,793 |   |
| Lease operating expenses                                                                   |       | 5        |       | (12,937                 | )           | (18,455                            | )          | (13,524                 | )          |
| Production taxes                                                                           |       |     |       | (4,200                  | )           | (6,043                             | )          | (6,965                  | )          |
| General and administrative   expense                                                       |       | 6        |       | (12,110                 | )           | (17,176                            | )          | (15,527                 | )          |
| Depreciation and amortisation   expense                                                    |       | 17, 20   |       | (48,147                 | )           | (94,584                            | )          | (85,584                 | )          |
| Impairment expense                                                                         |       | 19       |       | (10,203                 | )           | (321,918                           | )          | (71,212                 | )          |
| Exploration expense                                                                        |       | 18       |       | (30                     | )           | (7,925                             | )          | (10,934                 | )          |
| Finance costs, net of amounts   capitalized                                                |       |     |       | (12,219                 | )           | (9,418                             | )          | (699                    | )          |
| Loss on debt extinguishment                                                                |       |     |       | —                  |        | (1,451                             | )          | —                  |       |
| Gain on sale of non-current   assets                                                       |       |     |       | —                  |        | 790                                |       | 48,604                  |       |
| (Loss) gain on derivative   financial instruments                                          |       |     |       | (12,761                 | )           | 15,256                             |       | 11,009                  |       |
| Other income (loss)                                                                        |       | 8        |       | 2,009                   |        | (2,240                             | )          | (481                    | )          |
|                                                                                       |       |     |       |                    |        |                               |       |                    |       |
| **(Loss) profit   before income tax**                                                      |       |     |       | **(43,989**             | **)**       | **(370,973**                       | )          | **14,480**              |       |
|                                                                                       |       |     |       |                    |        |                               |       |                    |       |
| **Income tax   (expense)/benefit**                                                         |       | 7        |       | (1,705                  | )           | 107,138                            |       | 841                     |       |
|                                                                                       |       |     |       |                    |        |                               |       |                    |       |
| **(Loss) profit attributable   to owners of the Company**                                  |       |     |       | **(45,694**             | **)**       | **(263,835**                       | **)**      | **15,321**              |       |
|                                                                                       |       |     |       |                    |        |                               |       |                    |       |
| **Other comprehensive   (loss) income**                                                    |       |     |       |                    |        |                               |       |                    |       |
| Items that may be reclassified   subsequently to profit or loss:                           |       |     |       |                    |        |                               |       |                    |       |
| Exchange differences arising on   translation of foreign operations (no income tax effect) |       |     |       | **(532**                | **)**       | **(478**                           | **)**      | **684**                 |       |
| **Other comprehensive   (loss) income**                                                    |       |     |       | **(532**                | **)**       | **(478**                           | **)**      | **648**                 |       |
|                                                                                       |       |     |       |                    |        |                               |       |                    |       |
| **Total comprehensive   (loss) income attributable to owners of the Company**              |       |     |       | **$**                   | **(46,226** | **)**                              | **$**      | **(264,313**            | **)**      | **$** | **16,005** |   |
|                                                                                       |       |     |       |                    |        |                               |       |                    |       |
| **(Loss) earnings per   share**                                                            |       |     |       | (cents)                 |        | (cents)                            |       | (cents)                 |       |
| Basic earnings                                                                             |       | 10       |       | (5.2                    | )           | (47.7                              | )          | 2.9                     |       |
| Diluted earnings                                                                           |       | 10       |       | (5.2                    | )           | (47.7                              | )          | 2.9                     |       |

 

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

 

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**CONSOLIDATED STATEMENTS OF FINANCIAL POSITION**

 
| **For the year ended 31 December** | ** ** | **Note**   | ** ** | **2016********US$’000** | ** **  | **2015********US$’000**                      | ** ** |
|-------------------------------------------------------------|------------|------------|------------|------------------------------|-------------|---------------------------------------------------|------------|
| ** **                                                  | ** ** | ** ** | ** ** | ** **                   | ** **  | **(Restated — see   Note 7)** | ** ** |
| **CURRENT ASSETS**                                     | ** ** | ** ** | ** ** | ** **                   | ** **  | ** **                                        | ** ** |
| Cash and cash equivalents                                   |       |       |       | $                            | 17,463      |                                              | $          | 3,468 |   |
| Trade and other receivables                                 |       | 12         |       | 9,786                        |        | 11,508                                            |       |
| Derivative financial instruments                            |       | 13         |       | —                       |        | 9,967                                             |       |
| Income tax receivable                                       |       |       |       | 5,204                        |        | 5,616                                             |       |
| Other current assets                                        |       | 16         |       | 4,078                        |        | 4,154                                             |       |
| Assets held for sale                                        |       | 14         |       | 18,309                       |        | 90,632                                            |       |
| **TOTAL CURRENT   ASSETS**                                  |       |       |       | **54,840**                   |        | **125,345**                                       |       |
|                                                        |       |       |       |                         |        |                                              |       |
| **NON-CURRENT ASSETS**                                      |       |       |       |                         |        |                                              |       |
| Development and production assets                           |       | 17         |       | 338,709                      |        | 250,922                                           |       |
| Exploration and evaluation   expenditure                    |       | 18         |       | 34,366                       |        | 26,323                                            |       |
| Property and equipment                                      |       | 20         |       | 1,211                        |        | 1,382                                             |       |
| Derivative financial instruments                            |       | 13         |       | 279                          |        | 3,950                                             |       |
| Deferred tax assets                                         |       | 25         |       | 2,683                        |        | 1,913                                             |       |
| **TOTAL NON-CURRENT   ASSETS**                              |       |       |       | **377,248**                  |        | **284,490**                                       |       |
|                                                        |       |       |       |                         |        |                                              |       |
| **TOTAL ASSETS**                                            |       |       |       | **$**                        | **432,088** |                                              | **$**      | **409,835** |   |
|                                                        |       |       |       |                         |        |                                              |       |
| **CURRENT LIABILITIES**                                     |       |       |       |                         |        |                                              |       |
| Trade and other payables                                    |       | 21         |       | $                            | 3,579       |                                              | $          | 21,588 |   |
| Accrued expenses                                            |       | 21         |       | 19,995                       |        | 19,883                                            |       |
| Derivative financial instruments                            |       | 13         |       | 4,579                        |        | —                                            |       |
| Provisions, current                                         |       | 22         |       | 2,726                        |        | —                                            |       |
| Liabilities held for sale                                   |       | 14         |       | 941                          |        | 744                                               |       |
| **TOTAL CURRENT   LIABILITIES**                             |       |       |       | **31,820**                   |        | **42,215**                                        |       |
|                                                        |       |       |       |                         |        |                                              |       |
| **NON-CURRENT   LIABILITIES**                               |       |       |       |                         |        |                                              |       |
| Credit facilities, net of   deferred financing fees         |       | 23         |       | 188,249                      |        | 187,743                                           |       |
| Restoration provision                                       |       | 24         |       | 7,072                        |        | 3,088                                             |       |
| Other provisions, non-current                               |       | 22         |       | 3,299                        |        | —                                            |       |
| Deferred tax liabilities                                    |       | 25         |       | —                       |        | —                                            |       |
| Derivative financial instruments                            |       | 13         |       | 3,215                        |        | —                                            |       |
| Other non-current liabilities                               |       |       |       | 610                          |        | 420                                               |       |
| **TOTAL NON-CURRENT   LIABILITIES**                         |       |       |       | **202,445**                  |        | **191,251**                                       |       |
|                                                        |       |       |       |                         |        |                                              |       |
| **TOTAL LIABILITIES**                                       |       |       |       | **$**                        | **234,265** |                                              | **$**      | **233,466** |   |
|                                                        |       |       |       |                         |        |                                              |       |
| **NET ASSETS**                                              |       |       |       | **$**                        | **197,823** |                                              | **$**      | **176,369** |   |
|                                                        |       |       |       |                         |        |                                              |       |
| **EQUITY**                                                  |       |       |       |                         |        |                                              |       |
| Issued capital                                              |       | 26         |       | 373,585                      |        | 308,429                                           |       |
| Share based payments reserve                                |       | 27         |       | 14,174                       |        | 11,650                                            |       |
| Foreign currency translation   reserve                      |       | 27         |       | (1,842                       | )           | (1,310                                            | )          |
| Accumulated deficit                                         |       |       |       | (188,094                     | )           | (142,400                                          | )          |
| **TOTAL EQUITY**                                            |       |       |       | **$**                        | **197,823** |                                              | **$**      | **176,369** |   |

 

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

 

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**CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY**

 
| ** **                                                                | ** ** | **Issued   Capital   US$’000** | ** **  | **Share   Option   Reserve   US$’000** | ** ** | **Foreign   Currency   Translation   Reserve   US$’000** | ** ** | **Retained   Earnings   (Accumulated   Deficit)   US$’000** | ** ** | **Total   US$’000** | ** ** |
|---------------------------------------------------------------------------|------------|-------------------------------------|-------------|---------------------------------------------|------------|---------------------------------------------------------------|------------|------------------------------------------------------------------|------------|--------------------------|------------|
| **Balance at 31   December 2013**                                    |       | **237,008**                         |        | **5,635**                                   |       | **(1,516**                                                    | **)**      | **106,114**                                                      |       | **347,241**              |       |
| Profit attributable to owners of   the Company                            |       | —                              |        | —                                      |       | —                                                        |       | 15,321                                                           |       | 15,321                   |       |
| Other comprehensive loss for the   year                                   |       | —                              |        | —                                      |       | 684                                                           |       | —                                                           |       | 684                      |       |
| Total comprehensive loss                                                  |       | —                              |        | —                                      |       | 684                                                           |       | 15,321                                                           |       | 16,005                   |       |
| Shares issued in connection with:                                         |       |                                |        |                                        |       |                                                          |       |                                                             |       |                     |       |
| a) Private placement                                                      |       | 72,178                              |        | —                                      |       | —                                                        |       | —                                                           |       | 72,178                   |       |
| b) Exercise of stock options                                              |       | 260                                 |        | —                                      |       | —                                                        |       | —                                                           |       | 260                      |       |
| Cost of capital raising, net of   tax                                     |       | (2,593                              | )           | —                                      |       | —                                                        |       | —                                                           |       | (2,593                   | )          |
| Share based compensation value of   services                              |       | —                              |        | 1,915                                       |       | —                                                        |       | —                                                           |       | 1,915                    |       |
| **Balance at 31   December 2014**                                    |       | **306,853**                         |        | **7,550**                                   |       | **(832**                                                      | **)**      | **121,435**                                                      |       | **435,006**              |       |
|                                                                      |       |                                |        |                                        |       |                                                          |       |                                                             |       |                     |       |
| Loss attributable to owners of   the Company (restated — See Note 7) |       | —                              |        | —                                      |       | **—**                                                    |       | (263,835                                                         | )          | (263,835                 | )          |
| Other comprehensive loss for the   year                                   |       | —                              |        | —                                      |       | (478                                                          | )          | —                                                           |       | (478                     | )          |
| Total comprehensive loss   (restated — see Note 7)                   |       | —                              |        | —                                      |       | (478                                                          | )          | (263,835                                                         | )          | (264,313                 | )          |
| Shares issued in connection with:                                         |       |                                |        |                                        |       |                                                          |       |                                                             |       |                     |       |
| a) business combinations                                                  |       | 1,576                               |        | —                                      |       | —                                                        |       | —                                                           |       | 1,576                    |       |
| Share based compensation value of   services                              |       | —                              |        | 4,100                                       |       | —                                                        |       | —                                                           |       | 4,100                    |       |
| **Balance at 31   December 2015 (restated — see Note 7)**       |       | **$**                               | **308,429** |                                        | **$**      | **11,650**                                                    |       | **$**                                                            | **(1,310** | **)**                    | **$**      | **(142,400** | **)** | **$** | **176,369** |   |
| Loss attributable to owners of   the Company                              |       | —                              |        | —                                      |       | —                                                        |       | (45,694                                                          | )          | (45,694                  | )          |
| Other comprehensive loss for the   year                                   |       | —                              |        | —                                      |       | (532                                                          | )          | —                                                           |       | (532                     | )          |
| Total comprehensive loss                                                  |       | —                              |        | —                                      |       | (532                                                          | )          | (45,694                                                          | )          | (46,226                  | )          |
| Shares issued in connection withprivate placement (Note 26)               |       | 67,499                              |        | —                                      |       | —                                                        |       | —                                                           |       | 67,499                   |       |
| Cost of capital, net of tax (Note   26)                                   |       | (2,343                              | )           | —                                      |       | —                                                        |       | —                                                           |       | (2,343                   | )          |
| Share based compensation value of   services                              |       | —                              |        | 2,524                                       |       | —                                                        |       | —                                                           |       | 2,524                    |       |
| **Balance at 31   December 2016**                                    |       | **373,585**                         |        | **14,174**                                  |       | **(1,842**                                                    | **)**      | **(188,094**                                                     | **)**      | **197,823**              |       |
|                                                                           |            |                                     |             |                                             |            |                                                               |            |                                                                  |            |                          |            |  |  |  |  |  |

 

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

 

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**CONSOLIDATED STATEMENTS OF CASH FLOWS**

 
| **For the year ended 31 December** | ** ** | **Note** | ** ** | **2016********US$’000** | ** ** | **2015********US$’000** | ** ** | **2014********US$’000** | ** ** |
|-------------------------------------------------------------|------------|----------|------------|------------------------------|------------|------------------------------|------------|------------------------------|------------|
|                                                        |       |     |       |                         |       |                         |       |                         |       |
| **CASH FLOWS FROM   OPERATING ACTIVITIES**                  |       |     |       |                         |       |                         |       |                         |       |
| Receipts from sales                                         |       |     |       | 64,749                       |       | 99,423                       |       | 170,442                      |       |
| Payments to suppliers and   employees                       |       |     |       | (32,634                      | )          | (49,639                      | )          | (29,967                      | )          |
| Settlements of restoration   provision                      |       |     |       | (110                         | )          | (71                          | )          | —                       |       |
| Interest received                                           |       |     |       | —                       |       | 107                          |       | 201                          |       |
| Receipts from commodity   derivatives, net                  |       |     |       | 10,630                       |       | 11,736                       |       | (3                           | )          |
| Premium payments for commodity   derivatives                |       |     |       | —                       |       | (690                         | )          | —                       |       |
| Income taxes received, net                                  |       |     |       | 25                           |       | 3,603                        |       | (12,586                      | )          |
| **NET CASH PROVIDED   BY OPERATING ACTIVITIES**             |       | 30       |       | **42,660**                   |       | **64,469**                   |       | **128,087**                  |       |
|                                                        |       |     |       |                         |       |                         |       |                         |       |
| **CASH FLOWS FROM   INVESTING ACTIVITIES**                  |       |     |       |                         |       |                         |       |                         |       |
| Payments for development   expenditure                      |       |     |       | (64,130                      | )          | (144,316                     | )          | (361,950                     | )          |
| Payments for exploration   expenditure                      |       |     |       | (2,852                       | )          | (20,339                      | )          | (39,616                      | )          |
| Payments for acquisition of oil   and gas properties        |       | 2        |       | (23,506                      | )          | (15,023                      | )          | (35,606                      | )          |
| Sale of non-current assets                                  |       | 3        |       | 7,141                        |       | 41                           |       | 115,284                      |       |
| Transaction costs related to sale   of non-current assets   |       |     |       | —                       |       | —                       |       | (278                         | )          |
| Payments for acquisition related   costs                    |       |     |       | —                       |       | (578                         | )          | —                       |       |
| Payments for property and   equipment                       |       |     |       | (295                         | )          | (371                         | )          | (967                         | )          |
| Other investing activities                                  |       |     |       | 3,651                        |       | (185                         | )          | (102                         | )          |
| **NET CASH USED IN   INVESTING ACTIVITIES**                 |       |     |       | **(79,991**                  | **)**      | **(180,771**                 | **)**      | **(323,235**                 | **)**      |
|                                                        |       |     |       |                         |       |                         |       |                         |       |
| **CASH FLOWS FROM   FINANCING ACTIVITIES**                  |       |     |       |                         |       |                         |       |                         |       |
| Proceeds from the issuance of   shares                      |       |     |       | 67,499                       |       | —                       |       | 72,438                       |       |
| Payments for costs of capital   raisings                    |       |     |       | (3,330                       | )          | —                       |       | (3,778                       | )          |
| Borrowing costs paid, net of   capitalized portion          |       |     |       | (11,753                      | )          | (6,889                       | )          | (1,065                       | )          |
| Deferred financing fees   capitalized                       |       |     |       | —                       |       | (4,708                       | )          | —                       |       |
| Payments for foreign currency   derivatives                 |       |     |       | (390                         | )          | —                       |       | —                       |       |
| Proceeds from borrowings                                    |       |     |       | —                       |       | 207,000                      |       | 165,000                      |       |
| Repayments from borrowings                                  |       |     |       | (250                         | )          | (145,000                     | )          | (65,000                      | )          |
| **NET CASH PROVIDED   BY FINANCING ACTIVITIES**             |       |     |       | **51,776**                   |       | **50,403**                   |       | **167,595**                  |       |
|                                                        |       |     |       |                         |       |                         |       |                         |       |
| Net increase (decrease) in cash   held                      |       |     |       | **14,445**                   |       | **(65,899**                  | **)**      | **(27,553**                  | **)**      |
|                                                        |       |     |       |                         |       |                         |       |                         |       |
| Cash and cash equivalents at   beginning of year            |       |     |       | 3,468                        |       | 69,217                       |       | 96,871                       |       |
| Effect of exchange rates on cash                            |       |     |       | (450                         | )          | 150                          |       | (101                         | )          |
| **CASH AND CASH   EQUIVALENTS AT END OF YEAR**              |       |     |       | **17,463**                   |       | **3,468**                    |       | **69,217**                   |       |

 

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

 

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**NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES**

 

The consolidated financial report of Sundance Energy Australia Limited (“SEAL”) and its wholly owned subsidiaries, (collectively, the “Company”, “Consolidated Group” or “Group”), for the year ended 31 December 2016 was authorised for issuance in accordance with a resolution of the Board of Directors on 30 March 2017.  Refer to Note 35 for listing of the Company’s significant subsidiaries.

 

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

 

**Basis of Preparation**

 

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

 

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

 

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

 

**Principles of Consolidation**

 

The consolidated financial statements incorporate the assets and liabilities as at December 31 2016 and 2015, and the results for the years then ended, of Sundance Energy Australia Limited (“SEAL”) and the entities it controls.  A controlled entity is any entity over which SEAL is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity.  As at 31 December 2016 and 2015, all of its controlled entities were wholly-owned.

 

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

 

**a)**             **Income Tax**

 

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

 

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

 

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

 

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

 

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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 utilized. Where temporary differences exist in relation to investments in subsidiaries, branches, associates, and joint ventures, deferred tax assets and liabilities are not recognised where the timing of the reversal of the temporary difference can be controlled and it is not probable that the reversal will occur in the foreseeable future.

 

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

 

*Tax Consolidation*

 

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

 

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

 

**Exploration and Evaluation Expenditure**

 

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

 

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

 

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

 

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**b)**             **Development and Production Assets and Property and Equipment**

 

Development and production assets, and property and equipment are carried at cost less, where applicable, any accumulated depreciation, amortisation and impairment losses. The costs of assets constructed within the Group includes the cost of materials, direct labor, borrowing costs and an appropriate proportion of fixed and variable overheads directly attributable to the acquisition or development of oil and gas properties and facilities necessary for the extraction of resources.  Repairs and maintenance are charged to the consolidated statement of profit or loss and comprehensive income during the financial period in which are they are incurred.

 

**Depreciation and Amortisation Expense**

 

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

 

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

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

 

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

 

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

 

**Impairment**

 

The carrying amount of development and production assets and property and equipment are reviewed at each reporting date to determine whether there is any indication of impairment.  Where an indicator of impairment exists, a formal estimate of the recoverable amount is made.

 

Development and production assets are assessed for impairment on a cash-generating unit basis.  A cash-generating unit is the smallest grouping of assets that generates independent cash inflows.  Management has assessed its CGUs as being an individual basin, which is the lowest level for which cash inflows are largely independent of those of other assets.  Each of the Group’s development and production asset CGUs include all of its developed producing properties, shared infrastructure supporting its production and undeveloped acreage that the Group considers technically feasible and commercially viable.  An impairment loss is recognized in the consolidated statement of profit and loss whenever the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount.Impairment losses recognised in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit on a pro-rata basis.

 

The recoverable amount of an asset is the greater of its fair value less costs to sell (“FVLCS”) or its value-in-use (“VIU”).  In assessing VIU, an asset’s estimated future cash flows are discounted to their present value using an appropriate discount rate that reflects current market assessments of the time value of money and the risks specific to the assets/CGUs.  The estimated future cash flows for the VIU calculation are based on estimates, the most significant of which are hydrocarbon reserves, future production profiles, commodity prices, operating costs and any future development costs necessary to produce the reserves.

 

Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves.The discount rates applied to the future forecast cash flows are based on a third party participant’s post-tax weighted average cost of capital, adjusted for the risk profile of the asset.

 

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Under a FVLCS calculation, the Group considers market data related to recent transactions for similar assets. In determining the fair value of the Group’s investment in shale properties, the Group considers a variety of valuation metrics from recent comparable transactions in the market. These metrics include price per flowing barrel of oil equivalent and undeveloped land values per net acre held.

 

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.

 

An impairment loss is reversed if there has been an increase in the estimated recoverable amount of a previously impaired assets.  An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or depletion if no impairment loss had been recognized.  The Company has not reversed an impairment loss during the years ended 31 December 2016 or 2015.

 

If an entire CGU is disposed, 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.  If a disposition is less than an entire CGU and the property had been previously subjected to amortization or impairment at the CGU level, and there would be no significant impact to the Company’s depletion rate, no gain or loss is recognized and the proceeds of the sale are treated as a cost reduction to the Company’s net book value of the CGU in which the assets were previously included.

 

**c)**              **Leases**

 

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

 

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

 

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.

 

Assets under financing leases 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.

 

**d)**             **Financial Instruments**

 

**Recognition and Initial Measurement**

 

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 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.

 

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**Derivative Financial Instruments**

 

The Group uses derivative financial instruments to economically 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 or natural gas 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 fair value and remeasured at each reporting period.  The fair value of these derivative financial instruments is the estimated amount that the Group would receive or pay to terminate the contracts at the reporting date, taking into account current market prices and the current creditworthiness of the contract counterparties.  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 profit or loss and other comprehensive income.

 

i)           Financial assets at fair value through profit or loss

 

Financial assets are classified at fair value through profit or loss when they are acquired principally for the purpose of selling in the near-term.  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.

 

ii)        Loans and receivables

 

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.

 

**Derecognition**

 

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

 

**Foreign Currency Transactions and Balances**

 

**Functional and presentation currency**

 

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

 

**Transactions and Balances**

 

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

 

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

 

**Group Companies**

 

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

 

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

 

·                  revenues and expenses are translated to USD using the exchange rate at the date of transaction; and

 

·                  retained profits and issued capital are translated at the exchange rates prevailing at the date of 

 

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the transaction.

 

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

 

**e)**              **Employee Benefits**

 

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.

 

**Equity - Settled Compensation**

 

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

 

The group has a restricted share unit (“RSU”) plan 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 target RSUs are generally based on goals established by the Remuneration and Nominations Committee and approved by the Board.  The fair value of time-lapse RSUs is determined based on the price of Company ordinary shares on the date of grant and expense is recognized over the vesting period.  Certain of its RSUs vest based on the achievement of metrics related to the Company’s 3-year absolute shareholder return or total shareholder return as compared to its peer group, as defined.  The Company uses a Monte Carlo valuation model to determine the fair value of such RSUs and the expense is recognized over the vesting period.  The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment.  The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award.  The risk-free rate used in the model is based on Australian Treasury bond relevant to the term of the RSU award.

 

**Deferred Cash Compensation**

 

In 2016, the Group granted deferred cash compensation awards to certain employees, which may be earned through appreciation in the weighted average price of Sundance’s ordinary shares from the last 20 days of 2015 as compared to the last 20 days of 2017 and 2018.  The Group recognizes general and administrative expense for the deferred cash compensation to the extent to which the employees have rendered service, with a corresponding liability included within other noncurrent liabilities on the consolidated statement of financial position.  The fair value of the deferred cash awards are estimated initially and at the end of each reporting period until settled, using a Monte Carlo model that takes into consideration the terms and conditions of the award.  The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award.  The risk-free rate used in the model is based on U.S. Treasury bond relevant to the term of the award. The awards may ultimately be settled in cash or fully vested RSUs at the discretion of the Board.

 

**f)**               **Provisions**

 

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.  As of 31 December 2016, the Company had recognized provisions related to a third-party refracturing agreement ($6.0 million) and office space consolidation ($0.3 million).

 

**g)**             **Cash and Cash Equivalents**

 

Cash and cash equivalents include cash on hand, deposits held at call with banks, and other short-term highly liquid investments with original maturities of three months or less

 

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**h)**             **Revenue**

 

Revenue from the sale of oil and natural gas is recognised upon the delivery of product to the purchaser and title transfers to the purchaser.  The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties.  The Company had not recognized an imbalance on the consolidated statement of financial position as at 31 December 2016.

 

All revenue is stated net of royalties, transportation costs and the amount of goods and services tax (“GST”).

 

**i)**                **Borrowing Costs**

 

Borrowing costs, including interest, 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 consolidated statement of profit or loss and other comprehensive income over the period of the borrowings on an effective interest basis.  The Company capitalised eligible borrowing costs of $1.1 million,$1.6 million and $3.4 million for the years ended 31 December 2016, 2015 and 2014 respectively.  All other borrowing costs are recognised in the consolidated statement of profit or loss and other comprehensive income in the period in which they are incurred.

 

**j)**                **Goods and Services Tax**

 

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 consolidated 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.

 

**k)**             **Business Combinations**

 

A business combination is a transaction in which an acquirer obtains control of one or more businesses.  The acquisition method of accounting is used to account for all business combinations regardless of whether equity instruments or other assets are acquired.  The acquisition method is only applied to a business combination when control over the business is obtained.  Subsequent changes in interests in a business where control already exists are accounted for as transactions between owners.  The cost of the business combination is measured at fair value of the assets given, shares issued and liabilities incurred or assumed at the date of acquisition.  Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance.

 

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

 

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**l)**                **Assets Held for Sale**

 

The Company classifies property as held for sale when management commits to a plan to sell the property, the plan has appropriate approvals, the sale of the property is highly probable within the next twelve months, and certain other criteria are met. At such time, the respective assets and liabilities are presented separately on the Company’s consolidated statement of financial position and amortisation is no longer recognized. Assets held for sale are reported at the lower of their carrying amount or their estimated fair value, less the costs to sell the assets. The Company recognizes an impairment loss if the current net book value of the property exceeds its fair value, less selling costs.  As at 31 December 2016, based upon the Company’s intent and anticipated ability to sell an interest in these properties, the Company had classified its Mississippian/Woodward properties as held for sale.  As at 31 December 2015 the Company had 25% of its Eagle Ford assets and 100% of its Cooper Basin assets classified as held for sale.

 

**m)**         **Critical Accounting Estimates and Judgements**

 

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

 

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

 

**Estimates of reserve quantities**

 

The estimated quantities of hydrocarbon reserves reported by the Group are integral to the calculation of amortisation (depletion) and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessment of the technical feasibility and commercial viability of producing the reserves. The Company engaged an independent petroleum engineering firm, Ryder Scott Company to prepare its reserve estimates which conform to SEC guidelines.  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 and production data are generated during the course of operations.

 

**Impairment of Non-Financial Assets**

 

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

 

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**Exploration and Evaluation**

 

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

 

**Restoration Provision**

 

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

 

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

 

**Units of Production Depletion**

 

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

 

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

 

**Share-based Compensation**

 

The Group’s policy for share-based compensation is discussed in Note 1 (g).  The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances.  Certain of the Company’s restricted share units vest based on the Company’s ordinary share price appreciation over a 3-year period in absolute terms or as compared to a defined peer group.  Share-based compensation related to these awards use estimates for the expected volatility of the Company’s ordinary share price and of its peer’s ordinary share price (total shareholder return shares).  The Company’s deferred cash awards also vest upon the Company’s ordinary share price appreciate through 2017, 2018 and 2019.  The Company must also estimate expected volatility of the Company’s ordinary share price when valuing these awards.

 

**n)**             **Rounding of Amounts**

 

In accordance with the Australian Securities and Investment Commission (“ASIC”) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191, amounts in the financial statements have been rounded to the nearest thousand.

 

**o)**             **Parent Entity Financial Information**

 

The financial information for the parent entity, SEAL (“Parent Company”), also the ultimate parent, discussed in Note 36, has been prepared on the same basis, using the same accounting policies as the consolidated financial statements, except for its investments in subsidiaries which are accounted for at cost in the individual financial statements of the parent entity less any impairment.

 

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**p)**             **Earnings (loss) Per Share**

 

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

 

**s)**     **N****ew and Revised Accounting Standards**

 

The Group has adopted all of the new and revised Standards and Interpretations issued by IFRS/AASB that are relevant to its operations and effective for the current annual reporting period. The adoption of these new and revised Australian Accounting Standards and Interpretations has had no significant impact on the Group’s accounting policies or the amounts reported during the financial year.

 

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

 

**AASB 9/IFRS 9 — *Financial Instruments,* and the relevant amending standards**

 

AASB 9/IFRS 9, approved in December 2015, introduces new requirements for the classification, measurement, and derecognition of financial instruments, including new general hedge accounting requirements.  The effective date of this standard is for fiscal years beginning on or after 1 January 2018, with early adoption permitted.  Management is currently assessing the impact of the new standard but it is not expected to have a material impact on the Group’s consolidated financial statements when it adopts the standard 1 January 2018.

 

**AASB 15/IFRS 15 — *Revenue from Contracts with Customers***

 

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

 

1.              Identify the contract(s) with a customer

2.              Identify the performance obligations in the contracts.

3.              Determine the transaction price.

4.              Allocate the transaction price to the performance obligations in the contract.

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

 

Under AASB 15/IFRS 15, an entity recognizes revenue when (or as) a performance obligation is satisfied, i.e. when ‘control’ of the goods or services underlying the particular performance obligation is transferred to the customer.  The effective date of this standard is for fiscal years beginning on or after 1 January 2018.  Although the Company is still in the process of assessing its contracts with customers and evaluating the effect of adopting these standards, as well as the transition method to be applied, the adoption is not expected to have a significant impact on the Company’s consolidated financial statements other than additional disclosures.  The Company plans to adopt the standard on 1 January 2018.

 

**AASB 16/IFRS 16 — *Leases***

 

In January 2016, AASB 16/IFRS 16 was issued which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors.  AASB 16/IFRS 16 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the balance sheet, initially recorded at the fair value of unavoidable lease payments.  The entity will then recognize depreciation of the lease assets and interest on the statement of profit and loss.

 

The effective date of this standard is for fiscal years beginning on or after 1 January 2019.  As of 31 December 2016, the Company had approximately $5.2 million of contractual obligations related to its non-cancelable leases and drilling rig contracts, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under AASB 16/IFRS 16.  The Company plans to adopt the standard on the 1 January 2019.

 

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**NOTE 2 — BUSINESS COMBINATIONS**

 

**Acquisitions in 2016**

 

Acquisition #1

 

On 29 July 2016, the Company completed its acquisition of 5,050 net acres targeting the Eagle Ford in McMullen County, Texas, for a cash purchase price of $15.9 million.  The assets acquired included approximately 26 gross (9.1 net) producing wells, which were primarily Sundance-operated prior to the acquisition.  The Company acquired the assets to execute on its strategy of growing its Eagle Ford position.

 

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

 
| *Fair value of   assets acquired:*     |   |   |   |
|----------------------------------------|--------|--------|--------|
| Development and production assets      |   | $      | 16,628 |   |
| *Fair value of   liabilities assumed:* |   |   |   |
| Restoration provision                  |   | (747   | )      |
| Net assets acquired                    |   | $      | 15,881 |   |
|                                   |   |   |   |
| *Purchase price:*                      |   |   |   |
| Cash consideration                     |   | $      | 15,881 |   |
| Total consideration paid               |   | $      | 15,881 |   |

 

Revenues of $2.4 million and net income of $0.4 million (excluding the impact of income taxes) were generated from the acquired properties from 29 July 2016 through 31 December 2016.  The Company did not incur any material acquisition costs related to the transaction.

 

Acquisition #2

 

On 19 December 2016, the Company completed its acquisition of additional working interest in 23 gross (1.5 net) producing wells and 130 acres in McMullen County for cash consideration of $7.2 million.  12 gross (1.0 net) of the acquired wells are Sundance operated. The Company acquired the assets to execute on its strategy of growing its Eagle Ford position.

 

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

 
| *Fair value of assets acquired:*       |   |   |   |
|----------------------------------------|--------|--------|--------|
| Development and production assets      |   | 7,348  |   |
| *Fair value of   liabilities assumed:* |   |   |   |
| Restoration provision                  |   | (118   | )      |
| Net assets acquired                    |   | $      | 7,230  |   |
|                                   |   |   |   |
| *Purchase price:*                      |   |   |   |
| Cash consideration                     |   | $      | 7,230  |   |
| Total consideration paid               |   | $      | 7,230  |   |

 

Subsequent to the acquisition on 19 December 2016, revenue and net income generated from the properties for the remainder of 2016 were not material.  The Company did not incur any material acquisition costs related to the transaction.

 

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If both Eagle Ford acquisitions had been completed as of 1 January 2016, the Company’s pro forma revenue and loss before income taxes would have been increased and reduced by $5.3 million and $1.2 million to $72.0 million and $(42.8) million, respectively.  This pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations.

 

**Acquisitions in 2015**

 

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

 

Consideration paid for the assets included payment of $15.0 million to repay NSE’s outstanding debt and the issuance of 6 million fully paid ordinary Company shares, offset by acquired cash of $0.2 million.  Approximately 1.5 million of the 6 million Company shares were held in escrow and are expected to be returned to the Company in 2017 in satisfaction of certain unresolved working capital adjustments and were not valued as part of consideration paid.

 

**Acquisition in 2014**

 

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

 

**NOTE 3 — DISPOSALS OF NON CURRENT ASSETS**

 

**Disposals in 2016**

 

In December 2016, the Company divested an acreage block containing 3,336 gross (2,709 net) acres located in Atascosa County, Texas. The Eagle Ford acreage was undeveloped and outside the Company’s core development project area. Sundance received cash proceeds of $7.1 million for the acreage.  No gain or loss was recognized in consolidated statement of profit and loss and other comprehensive income related to the sale.

 

**Disposals in 2015**

 

There were no disposals of non current assets during the year ended 31 December 2015.

 

**Disposals in 2014**

 

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

 

In July 2014, the Company sold its remaining Bakken assets, located in the Williston Basin, for approximately $14.0 million, which included $10 million in cash and approximately $4.0 million in settlement of a net liability due to the buyer. The sale resulted in a pre-tax gain of $1.6 million, which is included in the gain on sale of non-current assets in the consolidated statement of profit or loss and other comprehensive income for the year ended 31 December 2014.

 

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**NOTE 4 — REVENUE**

 
| ** **                                | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|-------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                      |       |             |       |             |       |             |       |
| Oil revenue                               |       | 57,296           |       | 82,949           |       | 144,994          |       |
| Natural gas revenue                       |       | 4,937            |       | 4,720            |       | 6,161            |       |
| Natural gas liquid (NGL) revenue          |       | 4,376            |       | 4,522            |       | 8,638            |       |
| Total revenue                             |       | 66,609           |       | 92,191           |       | 159,793          |       |

 

**NOTE 5 — LEASE OPERATING EXPENSES**

 
| ** **                                | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|-------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                      |       |             |       |             |       |             |       |
| Lease operating expense                   |       | (11,259          | )          | (16,667          | )          | (12,466          | )          |
| Workover expense                          |       | (1,678           | )          | (1,788           | )          | (1,058           | )          |
| Total lease operating expense             |       | (12,937          | )          | (18,455          | )          | (13,524          | )          |

 

**NOTE 6 — GENERAL AND ADMINISTRATIVE EXPENSES**

 
| ** **                                                                             | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|----------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                                              | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                                                   |       |             |       |             |       |             |       |
| Employee   benefits expense, including salaries and wages, net of capitalised overhead |       | (3,260           | )          | (4,849           | )          | (3,064           | )          |
| Share based   payments expense (1)                                                     |       | (2,748           | )          | (4,100           | )          | (1,915           | )          |
| Legal and other   professional fees                                                    |       | (2,085           | )          | (3,347           | )          | (4,661           | )          |
| Corporate fees                                                                         |       | (1,762           | )          | (1,986           | )          | (2,526           | )          |
| Rent                                                                                   |       | (669             | )          | (993             | )          | (631             | )          |
| Regulatory   expenses                                                                  |       | (279             | )          | (203             | )          | (1,374           | )          |
| Transaction   related costs                                                            |       | (323             | )          | (540             | )          | (150             | )          |
| Other expenses                                                                         |       | (984             | )          | (1,158           | )          | (1,206           | )          |
| Total general   and administrative expenses                                            |       | (12,110          | )          | (17,176          | )          | (15,527          | )          |

 

----

(1)     Share based payment expense includes expense associated with restricted share units and deferred cash awards.  See Note 32.

 

The Company capitalised overhead costs, including salaries, wages benefits and consulting fees, directly attributable to the exploration, acquisition and development of oil and gas properties of $2.1 million, $3.0 million and $4.5 million for the years ended 31 December 2016, 2015 and 2014 respectively.

 

**NOTE 7 — INCOME TAX EXPENSE**

 

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

 

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The effect of this correction is shown in the table below. There was no impact to the consolidated statement of cash flows.

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

 
| **Condensed Consolidated Statement of**  | ** ** | ** **             | ** ** | ** **     | ** ** | ** **             | ** ** |
|---------------------------------------------------------|------------|------------------------|------------|----------------|------------|------------------------|------------|
| **Financial Statement of Loss and** | ** ** | ** **             | ** ** | ** **     | ** ** | ** **             | ** ** |
| **Other Comprehensive Loss**                  | ** ** | **As Originally** | ** ** | ** **     | ** ** | ** **             | ** ** |
| **(Year ended 31 December 2015)**   | ** ** | **Filed**              | ** ** | **Correction** | ** ** | **2015 Restated** | ** ** |
|                                                    |       |                   |       |           |       |                   |       |
| Income tax   benefit                                    |       | 101,178                |       | 5,960          |       | 107,138                |       |
| Loss   attributable to owners of the Company            |       | (269,795               | )          | 5,960          |       | (263,835               | )          |
| Total comprehensive   loss                              |       | (270,273               | )          | 5,960          |       | (264,313               | )          |
| Basic and   diluted loss per share (cents)              |       | (48.8                  | )          | 1.1            |       | (47.7                  | )          |

 

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The following is a summary of 2016, 2015 and 2014 income tax expense (benefit):

 
| ** **                                                                                                                         | ** ** | ** **       | ** ** | **2015**         | ** ** | ** **       | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| ** **                                                                                                                         | ** ** | **2016**         | ** ** | **US$’000** | ** ** | **2014**         | ** ** |
| **Year ended 31 December **                                                                                    | ** ** | **US$’000** | ** ** | **(Restated)**   | ** ** | **US$’000** | ** ** |
|                                                                                                                               |       |             |       |             |       |             |       |
| a) The components of   income tax expense comprise:                                                                                |       |             |       |             |       |             |       |
| Current tax   expense/(benefit)                                                                                                    |       | 1,563            |       | (6,191           | )          | 17               |       |
| Deferred tax   expense/ (benefit)                                                                                                  |       | 142              |       | (100,947         | )          | (858             | )          |
| Total income tax   expense/ (benefit)                                                                                              |       | 1,705            |       | (107,138         | )          | (841             | )          |
|                                                                                                                               |       |             |       |             |       |             |       |
| b) The prima facie tax on   income (loss) from ordinary activities before income tax is reconciled to the   income tax as follows: |       |             |       |             |       |             |       |
|                                                                                                                               |       |             |       |             |       |             |       |
| Loss before   income tax                                                                                                           |       | (43,989          | )          | (370,973         | )          | 14,480           |       |
|                                                                                                                               |       |             |       |             |       |             |       |
| Prima facie tax   expense (benefit) at the Group’s statutory income tax rate of 30%                                           |       | (13,197          | )          | (111,292         | )          | 4,344            |       |
|                                                                                                                               |       |             |       |             |       |             |       |
| Increase   (decrease) in tax expense resulting from:                                                                               |       |             |       |             |       |             |       |
|                                                                                                                               |       |             |       |             |       |             |       |
| - Difference   of tax rate in US controlled entities                                                                               |       | (2,161           | )          | (20,447          | )          | 220              |       |
| - Impact   of direct accounting from US controlled entities (1)                                                                    |       | (98              | )          | (3,165           | )          | (3,044           | )          |
| - Share   based compensation                                                                                                       |       | 539              |       | 747              |       | 428              |       |
| - Excess   depletion                                                                                                               |       | —           |       | —           |       | (489             | )          |
| - Other   allowable items                                                                                                          |       | 314              |       | 77               |       | 295              |       |
| - Tax   adjustments relating to prior years                                                                                        |       | —           |       | —           |       | (1,063           | )          |
| - Change   in apportioned state tax rates in US controlled entities (2)                                                            |       | —           |       | (84              | )          | (992             | )          |
| - Tax   consolidation election(3)                                                                                                  |       | —           |       | —           |       | (3,058           | )          |
| - Current   year tax losses not recognised                                                                                         |       | 16,308           |       | 27,026           |       | 2,518            |       |
|                                                                                                                               |       |             |       |             |       |             |       |
| Total Income tax   expense (benefit)                                                                                               |       | 1,705            |       | (107,138         | )          | (841             | )          |
|                                                                                                                               |       |             |       |             |       |             |       |
| c) Unused tax losses and   temporary differences for which no deferred tax asset has been recognised at   30%                      |       | 46,022           |       | 29,714           |       | 2,685            |       |
|                                                                                                                               |       |             |       |             |       |             |       |
| d) Deferred tax charged   directly to equity:                                                                                      |       |             |       |             |       |             |       |
| - Equity   raising costs                                                                                                           |       | (986             | )          | —           |       | 1,147            |       |
| - Currency   translation adjustment                                                                                                |       | 73               |       | (362             | )          | (268             | )          |

 

----

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

 

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

 

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

 

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** **

**NOTE 8 — OTHER INCOME (EXPENSE), NET**

 
| ** **                                           | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**            | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                 |       |             |       |             |       |             |       |
| Insurance   proceeds (1)                             |       | 2,375            |       | —           |       | —           |       |
| Litigation   settlement                              |       | 1,200            |       | —           |       | —           |       |
| Restructuring   expenses (2)                         |       | (856             | )          | —           |       | —           |       |
| Loss on foreign   currency derivative                |       | (390             | )          | —           |       | —           |       |
| Write-off of   unrecoverable cash call               |       | —           |       | (1,621           | )          | —           |       |
| Write-down of   inventory to lower of cost or market |       | —           |       | (319             | )          | —           |       |
| Contract   cancellation fee                          |       | —           |       | —           |       | (477             | )          |
| Other                                                |       | (320             | )          | (300             | )          | (4               | )          |
| Total other   income (expense), net                  |       | 2,009            |       | (2,240           | )          | (481             | )          |

 

----

(1)         During 2016, the Company received insurance proceeds of $2.4 million related to a well control incident in 2014.  In addition the Company was awarded a cash settlement of $1.2 million from litigation against a third party contractor for damages to a well that occurred in 2014.  As part of the litigation settlement, the Company was also awarded $0.6 million for reimbursement of legal costs incurred (recorded to general and administrative expenses on the consolidated statement of profit and loss).

 

(2)         In January 2016, the Company restructured its corporate organization and reduced its headcount by approximately 30% in order to reduce its cash operating costs in response to the lower oil price environment. Restructuring costs included $0.4 million in employee severance costs and $0.5 million in office lease-related costs for certain office space that is expected to be no longer used as a result of office space consolidation. The office-lease-related costs represent the Company’s future obligations under the operating leases, net of anticipated sublease income.  See also Note 22.

 

**NOTE 9 — KEY MANAGEMENT PERSONNEL COMPENSATION**

 

**a)**             **Directors and Key Management Personnel Compensation**

 

The total remuneration paid to Directors and Key Management Personnel (“KMP”) of the Group during the year is as follows:

 
| **Year ended 31 December**           | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|-----------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                                |       |                    |       |                    |       |                    |       |
| Short term wages   and benefits                     |       | 1,298                   |       | 1,467                   |       | 1,465                   |       |
| Share based   payments (equity or cash settled) (1) |       | 2,025                   |       | 2,271                   |       | 1,208                   |       |
| Post-employment   benefit                           |       | 49                      |       | 52                      |       | 57                      |       |
|                                                |       | 3,372                   |       | 3,790                   |       | 2,730                   |       |

 

(3)         The 2014 short-term incentive bonus (“STI”) granted to KMP, excluding the Managing Director, was granted by the Board of Directors in 2015 and paid out in the form of RSUs, which vested immediately.  The associated expense is included in 2015 share-based payments in the table above. The 2014 STI to the Managing Director was approved by shareholders in 2016 and paid out in the form of RSUs with immediate vesting.  The associated expense is included in 2016 share based payments in the table above.

 

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**b)**             **Options Granted as Compensation**

 

No options were granted as compensation during each of the years ended 31 December 2016, 2015 and 2014 to KMP from the Sundance Energy Employee Stock Option Plan. During 2015, the previous option holders were notified that all of the Company’s options would be converted to RSUs, which included 2.2 million options held by KMP, that were converted into 1.0 million RSUs ($0.2 million of incremental fair value).

 

**c)**              **Restricted Share Units  Granted as Compensation**

 

RSUs awarded as compensation were 9,906,997 ($1.2 million fair value), 7,426,596 ($3.8 million fair value) and 1,451,917 ($1.4 million fair value) during the years ended 31 December 2016, 2015 and 2014, respectively, to KMP.  The vesting provisions of the RSUs vary and may vest immediately, based upon the passage of time or based on achievement of metrics related to the Company’s 3-year absolute total shareholder return (ATSR) or total shareholder return (TSR) as compared to its peer group. The details of the plan and TSR RSUs are described in more detail in Part I, Item 6.

 

**d)**             **Deferred Cash Awards as Compensation**

 

Deferred cash awarded as compensation to KMP was $1.5 million ($0.5 million fair value as at 31 December 2016) during the year ended 31 December 2016.  Deferred cash awards vest based on the appreciation of the Company’s ordinary shares measured during 2017, 2018 and 2019. There were no deferred cash awards in 2015 or 2014.  The deferred cash award is described in more detail in Part I, Item 6.

 

**NOTE 10 — AUDITORS’ REMUNERATION**

 
| ** **                                                                                                | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|-----------------------------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                                                                 | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                                                                      |       |             |       |             |       |             |       |
| Cash remuneration of the auditor   for:                                                                   |       |             |       |             |       |             |       |
| Auditing or review of the   financial report                                                              |       | 461              |       | 463              |       | 429              |       |
| Professional services related to   filing of various Forms with the US Securities and Exchange Commission |       | —           |       | 13               |       | 245              |       |
| Taxation services provided by the   practice of auditor                                                   |       | —           |       | 61               |       | 69               |       |
| Total remuneration of the auditor                                                                         |       | 461              |       | 537              |       | 743              |       |

 

(1)         The 2016 amount includes $0.4 million paid to the Company’s former auditor, Ernst & Young, who provided audit services for the year ended 31 December 2015.   The Company paid $0.1 million in 2016 to Deloitte Touche Tohmatsu Limited as its auditor for the year ended 31 December 2016.

 

**NOTE 11 — EARNINGS (LOSS) PER SHARE (EPS)**

 
| ** **                                                 | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                  | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                       |       |             |       |             |       |             |       |
| Loss for periods used to   calculate basic and diluted EPS |       | (45,694          | )          | (263,835         | )          | 15,321           |       |

 
| ** **                                                                                                           | ** ** | **Number********of shares** | ** ** | **Number********of shares** | ** ** | **Number********of shares** | ** ** |
|----------------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|----------------------------------|------------|----------------------------------|------------|
| a) -Weighted   average number of ordinary shares outstanding during the period used in   calculation of basic EPS(1) |       | 870,582,898                      |       | 552,847,289                      |       | 531,391,405                      |       |
| b) -Incremental   shares related to options and restricted share units(2)                                            |       | —                           |       | —                           |       | 3,208,214                        |       |
| c) -Weighted   average number of ordinary shares outstanding during the period used in calculation   of diluted EPS  |       | 870,582,898                      |       | 552,847,289                      |       | 534,599,619                      |       |

 

----

(1) Calculation excludes approximately 1.5 million ordinary shares held in escrow as at 31 December 2016 and 2015.  The shares were issued as part of the NSE acquisition in 2015 and are expected to be returned to the Company in satisfaction of certain working capital adjustments during 2017

 

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(2) Incremental shares related to restricted share units were excluded from 31 December 2016 and 2015 weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS as the outstanding shares would be anti-dilutive to the loss per share calculation for the period then ended.

 

**NOTE 12 — TRADE AND OTHER RECEIVABLES**

 
| ** **                                | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|-------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                      |       |             |       |             |       |
| Oil, natural gas and NGL sales            |       | 8,201            |       | 5,684            |       |
| Joint interest billing   receivables      |       | 1,545            |       | 4,108            |       |
| Commodity hedge contract   receivables    |       | 37               |       | 1,653            |       |
| Other                                     |       | 3                |       | 63               |       |
| Total trade and other receivables         |       | 9,786            |       | 11,508           |       |

 

Due to the short-term nature of trade and other receivables, their carrying amounts are assumed to approximate fair value.  No receivables were outside of normal trading terms as at 31 December 2016 and 2015.

 

**NOTE 13 — DERIVATIVE FINANCIAL INSTRUMENTS**

 
| ** **                                                    | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|---------------------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                     | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                          |       |             |       |             |       |
| **FINANCIAL ASSETS****:**                                     |       |             |       |             |       |
| *Current*                                                     |       |             |       |             |       |
| Derivative financial instruments   — commodity contracts |       | —           |       | 9,967            |       |
| *Non-current*                                                 |       |             |       |             |       |
| Derivative financial instruments   — commodity contracts |       | 279              |       | 3,950            |       |
| Total financial assets                                        |       | 279              |       | 13,917           |       |
|                                                          |       |             |       |             |       |
| **FINANCIAL   LIABILITIES****:**                              |       |             |       |             |       |
| *Current*                                                     |       |             |       |             |       |
| Derivative financial instruments   — commodity contracts |       | 4,579            |       | —           |       |
| *Non-current*                                                 |       |             |       |             |       |
| Derivative financial instruments   — commodity contracts |       | 3,215            |       | —           |       |
| Total financial liabilities                                   |       | 7,794            |       | —           |       |

 

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**NOTE 14 — ASSETS HELD FOR SALE**

 

The consolidated statement of financial position includes assets and liabilities as held for sale, comprised of the following:

 
| **Year ended 31 December**                           | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** |
|---------------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                                                |       |                    |       |                    |       |
| Mississippian/Woodford                                              |       |                    |       |                    |       |
| Development and   production assets                                 |       | 18,309                  |       | —                  |       |
| Eagle Ford                                                          |       |                    |       |                    |       |
| Development and   production assets (25%)                           |       | —                  |       | 77,021                  |       |
| Exploration and   evaluation expenditure (25%)                      |       | —                  |       | 8,377                   |       |
| Cooper Basin                                                        |       |                    |       |                    |       |
| Exploration and   evaluation expenditure                            |       | —                  |       | 5,234                   |       |
| Total assets   held for sale                                        |       | 18,309                  |       | 90,632                  |       |
|                                                                |       |                    |       |                    |       |
| Restoration   provision for Mississippian/Woodford developed assets |       | 941                     |       | —                  |       |
| Restoration   provision for Eagle Ford developed assets (25%)       |       | —                  |       | 744                     |       |
| Total   liabilities held for sale                                   |       | 941                     |       | 744                     |       |

 

In June 2016, the Company’s management committed to a plan to sell its Mississippian/Woodford assets.  The Company entered into a purchase and sale agreement on 1 March 2017 to sell the assets for $18.5 million, subject to post-closing adjustments for net cash flow attributable to the assets from 1 August 2016 through the closing date.  The Company expects the transaction to close by May 2017.

 

The Company had previously intended to sell a 25% non-operated interest in its Eagle Ford assets. However, the Company changed its strategy in June 2016 as a result of its 3-tranche private placement, initiated in the second quarter of 2016 (and closed over the second and third quarters 2016).  These Eagle Ford assets were reclassified and are presented as development and production assets and exploration and evaluation expenditures as at 31 December 2016.

 

The Company’s Cooper Basin assets no longer met the criteria as held for sale as at 31 December 2016.  However, the Company still intends to dispose of the assets, as they fall outside the Company’s strategic focus.

 

**NOTE 15 — FAIR VALUE MEASUREMENT**

 

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

 

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

 

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

 

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

 

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

 

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| **Consolidated 31 December 2016    (US$’000)** | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|-------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
|                                                                    |       |             |       |             |       |             |       |      |       |
| Assets measured   at fair value                                         |       |             |       |             |       |             |       |      |       |
| Derivative   commodity contracts                                        |       | —           |       | 279              |       | —           |       | 279       |       |
| Liabilities   measured at fair value                                    |       |             |       |             |       |             |       |      |       |
| Derivative   commodity contracts                                        |       | —           |       | (7,794           | )          | —           |       | (7,794    | )          |
| Net fair value                                                          |       | —           |       | (7,515           | )          | —           |       | (7,515    | )          |

 
| **Consolidated 31 December 2015    (US$’000)**                   | ** ** | **Level 1** | ** ** | **Level 2** | ** ** | **Level 3** | ** ** | **Total** | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|-----------|------------|
|                                                                                      |       |             |       |             |       |             |       |      |       |
| Assets measured   at fair value                                                           |       |             |       |             |       |             |       |      |       |
| Derivative   commodity contracts                                                          |       | —           |       | 13,917           |       | —           |       | 13,917    |       |
| Investment in   equity instruments at fair value though profit and loss “FVTPL” |       | 89               |       | —           |       | —           |       | 89        |       |
|                                                                                      |       |             |       |             |       |             |       |      |       |
| Net fair value                                                                            |       | 89               |       | 13,917           |       | —           |       | 14,006    |       |

 

During the years ended 31 December 2016 and 2015, respectively, there were no transfers between level 1 and level 2 fair value measurements, and no transfer into or out of level 3 fair value measurements.

 

**Measurement of Fair Value**

 

**a)   Derivatives**

 

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

 

**b)   Investment in Equity Securities - FVTPL**

 

The Company purchased 122 million shares of Elixir Petroleum Limited (ASX: EXR) in conjunction with its purchase of NSE in 2015. The fair value of the securities was determined using ASX trade data, which is directly observable by the Company, and was included with the Level 1 fair value hierarchy as at 31 December 2015. The Company sold its investment in Elixir Petroleum for $0.1 million in 2016.

 

**c)   Credit Facilities**

 

As at 31 December 2016, the Company had $125 million and $67 million of principal debt outstanding on its Term Loan and Revolving Facility, respectively. The estimated fair value of the Term Loan was approximately $123 million, based on indirect, observable inputs (Level 2) regarding interest rates available to the Company. The fair value of the Term Loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period.  The Company’s Revolving Facility has a recorded value that approximates its fair value as its variable interest rate is tied to current market rates and the applicable margins of 2%-3% represent market rates.

 

**e)   Other Financial Instruments**

 

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

 

F-28

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** **

**NOTE 16 — OTHER CURRENT ASSETS**

 
| **Year ended 31 December**                       | ** ** | **2016********US$’000** | ** ** | **2015********US$’000** | ** ** |
|-----------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|
|                                                            |       |                         |       |                         |       |
| Investment in equity instruments   - FVTPL                      |       | —                       |       | 89                           |       |
| Cash advances to other operators                                |       | 27                           |       | 27                           |       |
| Oil inventory on hand, lesser of   cost or net realizable value |       | 517                          |       | 632                          |       |
| Equipment inventory, lesser of   cost or net realizable value   |       | 1,721                        |       | 783                          |       |
| Prepaid expenses                                                |       | 1,807                        |       | 2,578                        |       |
| Other                                                           |       | 6                            |       | 45                           |       |
| Total other current assets                                      |       | 4,078                        |       | 4,154                        |       |

 

**NOTE 17 — DEVELOPMENT AND PRODUCTION ASSETS**

 
| ** **                                                                      | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|---------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                                       | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                                            |       |             |       |             |       |
| Costs carried forward in respect   of areas of interest in:                     |       |             |       |             |       |
| Development and production   assets, at cost:                                   |       |             |       |             |       |
| Producing assets                                                                |       | 838,792          |       | 694,111          |       |
| Wells-in-progress                                                               |       | 4,997            |       | 38,210           |       |
| Undeveloped assets                                                              |       | 30,119           |       | 62,781           |       |
| -Development and production   assets, at cost:                                  |       | 873,908          |       | 795,102          |       |
| Accumulated depletion                                                           |       | (258,613         | )          | (211,123         | )          |
| Accumulated impairment                                                          |       | (258,277         | )          | (256,036         | )          |
| Total development and production   expenditure                                  |       | 357,018          |       | 327,943          |       |
| Less amount classified as asset   held for sale                                 |       | (18,309          | )          | (77,021          | )          |
| **Total Development   and Production Expenditure, net of assets held for sale** |       | 338,709          |       | 250,922          |       |
|                                                                            |       |             |       |             |       |
| **a)****Movements in carrying amounts:**                                        |       |             |       |             |       |
| Development expenditure                                                         |       |             |       |             |       |
| Balance at the beginning of the   period                                        |       | 250,922          |       | 519,013          |       |
| Amounts capitalised during the   period                                         |       | 57,893           |       | 76,831           |       |
| Amounts transferred from   exploration phase                                    |       | —           |       | 4,898            |       |
| Fair value of assets acquired                                                   |       | 23,873           |       | 13,170           |       |
| Exploratory dry hole costs   previously includedin wells-in progress            |       | —           |       | (2,416           | )          |
| Revision to restoration provision                                               |       | 3,238            |       | (5,715           | )          |
| Depletion expense                                                               |       | (47,490          | )          | (93,429          | )          |
| Impairment expense                                                              |       | (3,409           | )          | (184,409         | )          |
| Development and production assetssold during the period                         |       | (5,030           | )          | —           |       |
| Reclassifications from assets   held for sale                                   |       | 77,021           |       | —           |       |
| Reclassifications to assets held   for sale                                     |       | (18,309          | )          | (77,021          | )          |
| **Balance at end of period**                                                    |       | 338,709          |       | 250,922          |       |

 

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Borrowing costs relating to drilling of development wells that have been capitalized as part of oil and gas properties during the years ended 31 December 2016 and 2015 were $1.1 million and $1.6 million, respectively.  The interest amounts capitalized as a percent of the total bank interest incurred for years ended 31 December 2016 and 2015 were 6.7% and 14.1%, respectively.

 

**NOTE 18 — EXPLORATION AND EVALUATION EXPENDITURE**

 
| ** **                                                                      | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|---------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                                       | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                                            |       |             |       |             |       |
| Costs carried forward in respect   of areas of interest in:                     |       |             |       |             |       |
| Exploration and evaluation phase,   at cost                                     |       | 176,550          |       | 178,693          |       |
| Provision for impairment                                                        |       | (142,184         | )          | (138,759         | )          |
| **Total exploration   and evaluation expenditures**                             |       | 34,366           |       | 39,934           |       |
| **Less amount   classified as asset held for sale**                             |       | —           |       | (13,611          | )          |
| **Total Exploration and   Evaluation Expenditure, net of assets held for sale** |       | 34,366           |       | 26,323           |       |

 
| **a)**  **Movements in carrying amounts:**      |   |   |   |     |   |
|------------------------------------------------------|--------|--------|--------|----------|--------|
| Exploration and evaluation                           |   |   |   |     |   |
| Balance at the beginning of the   period             |   | 26,323 |   | 155,130  |   |
| Amounts capitalised during the   period              |   | 4,429  |   | 22,508   |   |
| Fair value of assets acquired (1)                    |   | — |   | 4,586    |   |
| Exploration costs expensed (2)                       |   | (30    | )      | (183     | )      |
| Amounts transferred to   development phase           |   | — |   | (4,898   | )      |
| Exploration tenements sold during   the period       |   | (2,096 | )      | —   |   |
| Impairment expense                                   |   | (7,871 | )      | (137,209 | )      |
| Reclassifications from assets   held for sale (3)    |   | 13,611 |   |     |   |
| Reclassifications from to assets   held for sale (3) |   | — |   | (13,611  | )      |
| **Balance at end of   period**                       |   | 34,366 |   | 26,323   |   |

 

----

(1)         In 2015, the Company acquired a 17.5% WI in the PEL570 concession in the Cooper Basin during 2015 as part of its acquisition of NSE.

 

(2)         In 2015, the Company expensed costs associated with two exploratory wells located in the Eagle Ford that did not have economically recoverable reserves (i.e. dry hole wells).

 

(3)         In 2016, the Company committed to a plan to sell its interest in its Mississippian/Woodward assets.  In 2015, the Company had committed to a plan to sell its interest in the Cooper Basin and 25% of its Eagle Ford assets.  However, the Company changed its strategy in June 2016 as a result of its capital raise, and as of 31 December 2016, no longer intended to sell its interest in Eagle Ford 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.

 

**NOTE 19 — IMPAIRMENT OF NON-CURRENT ASSETS**

 

Year-End 2016

 

At 31 December 2016, the Group reassessed the carrying amount of its non-current assets for indicators of impairment or whether there is any indication that an impairment loss may no longer exist or may have decreased in accordance with the Group’s accounting policy.  The Company determined there was no indication of impairment or impairment reversal for its Eagle Ford assets. The Company determined that there was an indication of impairment for its Mississippian/Woodward and Cooper Basin assets.

 

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Table of Contents

 

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

 

*Mississippian/Woodward assets*

 

Beginning in June 2016, the Company actively marketed its Mississippian/Woodward assets.  Based on the value of third-party bids and the execution of a purchase of sale agreement subsequent to year-end, the Company determined that there was an indication of impairment of both its exploration and evaluation assets and development and production assets.  The Company recorded an impairment expense of $4.6 million, which is equal to the difference between the carrying value and the estimated sale proceeds, less selling costs.

 

*Cooper Basin*

 

The Company has not received operational information indicating that the recovery of the Company’s carrying costs in the Cooper Basin is likely.  As such, the Company wrote the asset down to nil and recorded an impairment expense of $6.7 million during the year ended 31 December 2016.

 

Year-End 2015

 

At 31 December 2015, the Group determined that due to the decline in the oil pricing environment, that there was an indication of impairment for all of its exploration and evaluation expenditures and its development and production assets.

 

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

 

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

 
| **2016** | ** ** | **2017** | ** ** | **2018** | ** ** | **2019 and   thereafter** | ** ** |
|----------|------------|----------|------------|----------|------------|--------------------------------|------------|
| $        | 40.00      |     | $          | 50.00    |       | $                              | 60.00      |   | $ | 70.00 |   |
|          |            |          |            |          |            |                                |            |  |  |  |  |

 

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

 

Year-End 2014

 

As a result of the change in the oil pricing environment at 31 December 2014, the Company determined that there was an indication of impairment for development and production assets.  For the Company’s FVLCS calculation, management used future NYMEX strip prices, adjusted for basis differentials, in 2015 and gradually increased through 2016 to $75/bbl in 2017 and thereafter.  The Company applied a post-tax discount rate of 8.0%.  Management also applied further risk-adjustments appropriate for risks associated with its developed and undeveloped reserves using a weighted average risk-adjustment rate of 6% and 17%, respectively, based on the risk associate with each reserve category.

 

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Table of Contents

 

Recoverable amounts and resulting impairment expense recognized in conjunction with the Company’s impairment analysis as at 31 December 2016, 2015and 2014 are presented in the table below.

 
| **31 December 2016**             | ** ** | **Carrying costs** | ** ** | **Recoverable    amount (1)** | ** ** | **Impairment**   | ** ** |
|--------------------------------------------|------------|-------------------------|------------|-----------------------------------------|------------|------------------|------------|
| **Cash-generating unit (2)**     | ** ** | **US$’000**        | ** ** | **US$’000**                        | ** ** | **US$’000** | ** ** |
|                                       |       |                    |       |                                    |       |             |       |
| Exploration and evaluation   expenditures: |       |                    |       |                                    |       |             |       |
| Mississippian/Woodford                     |       | 1,183                   |       | —                                  |       | 1,183            |       |
| Cooper Basin                               |       | 6,688                   |       | —                                  |       | 6,688            |       |
| Total exploration and evaluation           |       | 7,871                   |       | —                                  |       | 7,871            |       |
| Development and production   assets:       |       |                    |       |                                    |       |             |       |
| Mississippian/Woodford                     |       | 21,693                  |       | 18,309                                  |       | 3,384            |       |
| Total development and production   assets  |       | 21,693                  |       | 18,309                                  |       | 3,384            |       |

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

 
| **31 December 2014**            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| **Cash-generating unit**             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|                                      |       |       |       |       |       |       |       |
| Development and production assets   (4):  |       |       |       |       |       |       |       |
| Eagle Ford                                |       | 400,761    |       | 389,764    |       | 10,997     |       |
| Mississippian/Woodford                    |       | 125,535    |       | 65,320     |       | 60,215     |       |
| Total development and production   assets |       | 526,296    |       | 455,084    |       | 71,212     |       |

 

----

(1)  Before reclassification of assets held for sale.

(2)  The total impairment expense for the year ended 31 December 2016 was $11.3 million, which was net of an adjustment to 2015 impairment expense of $1.1 million related to a vendor discount for well completion services obtained subsequent to the filing of the Company’s 2015 Annual Report.  Total impairment expense was $10.2 million.

(3)  The 31 December 2015 table reflects the year-end impairment analysis.  The Company also recorded impairment expense related to its Mississippian/Woodford development and production assets of $2.6 million and its exploration and evaluation assets of $13.4 million during the first half of the year ended 31 December 2015.

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

 

Any further adverse changes in any of the key assumptions may result in future impairments.

 

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**NOTE 20 — PROPERTY AND EQUIPMENT**

 
| ** **                                | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|-------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                      |       |             |       |             |       |
| Property and equipment, at cost           |       | 3,146            |       | 2,942            |       |
| Accumulated depreciation                  |       | (1,935           | )          | (1,560           | )          |
| **Total Property and   Equipment**        |       | 1,211            |       | 1,382            |       |
|                                      |       |             |       |             |       |
| **a)****Movements in carrying amounts:**  |       |             |       |             |       |
|                                      |       |             |       |             |       |
| Balance at the beginning of the   period  |       | 1,382            |       | 1,554            |       |
| Amounts capitalized during the   period   |       | 355              |       | 372              |       |
| Amounts disposed of during the   period   |       | (151             | )          | —           |       |
| Depreciation expense                      |       | (375             | )          | (544             | )          |
| **Balance at end of   period**            |       | 1,211            |       | 1,382            |       |

 

**NOTE 21 — TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES**

 
| ** **                                              | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|---------------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**               | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                    |       |             |       |             |       |
| Oil and natural gas property and   operating related    |       | 18,588           |       | 37,167           |       |
| Administrative expenses,   including salaries and wages |       | 2,225            |       | 1,253            |       |
| Accrued interest payable                                |       | 2,761            |       | 3,051            |       |
| Total trade, other payables and   accrued expenses      |       | 23,574           |       | 41,471           |       |

 

**NOTE 22 — OTHER PROVISIONS**

 
| ** **                                        | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|---------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**         | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                              |       |             |       |             |       |
| Current                                           |       |             |       |             |       |
| Restructuring — office space   consolidation |       | 154              |       | —           |       |
| Third-party refracture                            |       | 2,572            |       | —           |       |
| Provisions, current                               |       | 2,726            |       | —           |       |
| Long-term                                         |       |             |       |             |       |
| Restructuring — office space consolidation   |       | 91               |       | —           |       |
| Third-party refracture                            |       | 3,208            |       | —           |       |
| Other provisions, non-current                     |       | 3,299            |       | —           |       |
| Total other provisions                            |       | 6,025            |       | —           |       |

 

During 2016, the Company entered into an agreement with Schlumberger Limited (“Schlumberger”) to re-fracture five Eagle Ford wells.  Under the terms of the agreement, Schlumberger will be paid for the services, plus a premium (if applicable), from the incremental production generated by the re-fractured wells above the forecasted base production prior to the re-fracture work. The term of the agreement is five years.  The estimate of the payout amount requires judgements regarding production, pricing, future operating costs and discount rates.

 

During 2016, the Company also recognized a provision related to certain office space that will no longer be used as a result of office space consolidation. The office-lease-related costs represents the Company’s estimate of future obligations under the operating leases, net of anticipated sublease income.   The Company’s office lease is in place through 2019.

 

F-33

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**NOTE 23 — CREDIT FACILITIES**

 
| ** **                                                 | ** ** | **2016**   | ** ** | **2015**   | ** ** |
|------------------------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                                 | ** ** | **US$000** | ** ** | **US$000** | ** ** |
| Revolving   Facility                                       |       | 66,750     |       | 67,000     |       |
| Term Loan                                                  |       | 125,000    |       | 125,000    |       |
| Total Credit   Facilities                                  |       | 191,750    |       | 192,000    |       |
| Deferred   financing fees, net of accumulated amortisation |       | (3,501     | )          | (4,257     | )          |
| Total credit facilities, net of   deferred financing fees  |       | 188,249    |       | 187,743    |       |

 

On May 14, 2015, Sundance Energy Australia Limited and Sundance Energy, Inc. entered into a Credit Agreement (the “Credit Agreement”) with Morgan Stanley Energy Capital, Inc., as administrative agent (“Agent”) and the lenders from time to time party thereto, which provides for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and a term loan of $125 million (the “Term Loan”). The Revolving Facility is subject to a borrowing base, which is redetermined at least semi-annually. The borrowing base was reaffirmed at $67 million in the fourth quarter of 2016. The Revolving Facility has a five year term (matures in May 2020) and the Term Loan has a 5 1⁄2 year term (matures in November 2020). If upon any downward adjustment of the borrowing base, the outstanding borrowings are in excess of the revised borrowing base, the Company may have to repay its indebtedness in excess of the borrowing base immediately, or in five monthly installments.

 

The Company had a $0.3 million letter of credit outstanding on its Revolving Facility and therefore had no borrowing availability as at 31 December 2016.

 

Interest on the Revolving Facility accrues at a rate equal to LIBOR, plus a margin ranging from 2% to 3% depending on the level of funds borrowed. Interest on the Term Loan accrues at a rate equal to the greater of (i) LIBOR, plus 7% or (ii) 8%.

 

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

 

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

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

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

·                  An asset coverage ratio, consisting of PV9% to Total Debt (as defined in the Credit Facility), of not less than 1.50 to 1.0.

 

As at 31 December 2016, the Company was in compliance with all restrictive financial and other covenants under the Credit Agreement.

 

**NOTE 24 — RESTORATION PROVISION**

 

The restoration provision represents the Company’s best estimate of the present value of restoration costs relating to its oil and natural gas interests, which are expected to be incurred through 2046.  Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability.  The estimate of future removal costs requires management to make significant judgments regarding removal date or well lives, the extent of restoration activities required, discount and inflation rates. These estimates are reviewed regularly to take into account any material changes to the assumptions.  However, actual restoration costs will reflect market conditions at the relevant time.  Furthermore, the timing of restoration is likely to depend on when the fields cease to produce at economically viable rates.  This in turn will depend on future oil and natural gas prices, which are inherently uncertain.

 

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| ** **                                        | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|---------------------------------------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**         | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                              |       |             |       |             |       |
| Balance at the beginning of the   period          |       | 3,088            |       | 8,866            |       |
| New provisions                                    |       | 305              |       | 560              |       |
| Changes in estimates (1)                          |       | 2,956            |       | (5,661           | )          |
| Disposals                                         |       | (28              | )          | —           |       |
| Settlements                                       |       | (86              | )          | (290             | )          |
| New provisions assumed from   acquisition         |       | 894              |       | 334              |       |
| Unwinding of discount                             |       | 140              |       | 23               |       |
| Reclassification from liabilities   held for sale |       | 744              |       | —           |       |
| Reclassification to liabilities   held for sale   |       | (941             | )          | (744             | )          |
| **Balance at end of   period**                    |       | 7,072            |       | 3,088            |       |

 

----

(1)         The change in estimates for the year ended 31 December 2016 was primarily related to additional surface reclamation costs included in the Company’s estimate.

 

**NOTE 25 — DEFERRED TAX ASSETS AND LIABILITIES**

 

Deferred tax assets and liabilities are attributable to the following:

 
| ** **                                                                 | ** ** | **2016**         | ** ** | **2015**                      | ** ** |
|----------------------------------------------------------------------------|------------|------------------|------------|-------------------------------|------------|
| **Year ended 31 December**                                  | ** ** | **US$’000** | ** ** | **US$’000   (Restated)** | ** ** |
|                                                                       |       |             |       |                          |       |
| Net deferred tax   assets:                                                 |       |             |       |                          |       |
| Share issuance   costs                                                     |       | 1,534            |       | 1,342                         |       |
| Net operating   loss carried forward                                       |       | 2,636            |       | 3,659                         |       |
| Accrued interest                                                           |       | (2,756           | )          | (2,847                        | )          |
| Development and   production expenditure                                   |       | 1,269            |       | (241                          | )          |
| Other                                                                      |       | —           |       | —                        |       |
| Total net   deferred tax assets                                            |       | 2,683            |       | 1,913                         |       |
|                                                                       |       |             |       |                          |       |
| Deferred tax   liabilities:                                                |       |             |       |                          |       |
| Development and   production expenditure                                   |       | (10,654          | )          | 1,509                         |       |
| Derivatives                                                                |       | —           |       | (4,371                        | )          |
| Other                                                                      |       | —           |       | (32                           | )          |
| Offset by   deferred tax assets with legally enforceable right of set-off: |       |             |       |                          |       |
| Net operating   loss carried forward                                       |       | 7,218            |       | —                        |       |
| Credits                                                                    |       | —           |       | 150                           |       |
| Accrued interest                                                           |       | 3,436            |       | 2,744                         |       |
| Total net   deferred tax liabilities                                       |       | —           |       | —                        |       |

 

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**NOTE 26 — ISSUED CAPITAL**

 

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

 
| ** **                                                         |   | **Number of Shares** |   |
|--------------------------------------------------------------------|--------|----------------------|--------|
| **a)****Ordinary Shares**                                          |   |                 |   |
| **Total shares issued   and outstanding at 31 December 2014** |   | 549,295,839          |   |
| Shares issued during the year (1)                                  |   | 9,807,723            |   |
| **Total shares issued   and outstanding at 31 December 2015** |   | 559,103,562          |   |
| Shares issued during the year                                      |   | 690,248,055          |   |
| **Total shares issued   and outstanding at 31 December 2016** |   | 1,249,351,617        |   |

 

----

(1)               Includes 1.5 million shares held in escrow related to the Company’s acquisition of NSE. The shares are expected to be returned to the Company in satisfaction of certain unresolved due diligence defects during 2017.

 

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

 
| ** **                                                      | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|-----------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                       | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                            |       |             |       |             |       |             |       |
| **b)****Issued Capital**                                        |       |             |       |             |       |             |       |
| Beginning of the period                                         |       | 308,429          |       | 306,853          |       | 237,008          |       |
| Shares issued in connection with:                               |       |             |       |             |       |             |       |
| Share consideration paid in   business combination              |       | —           |       | 1,576            |       | —           |       |
| Shares issued in conjunction with   private placement (1)       |       | 67,499           |       | —           |       | 72,178           |       |
| Exercise of stock options                                       |       | —           |       | —           |       | 260              |       |
| Total shares issued during the   period                         |       | 67,499           |       | 1,576            |       | 72,438           |       |
| Cost of capital raising during   the period, net of tax benefit |       | (2,343           | )          | —           |       | (2,593           | )          |
| **Closing balance at   end of period**                          |       | 373,585          |       | 308,429          |       | 306,853          |       |

 

----

(1)         Throughout the second and third quarters of 2016, the Company completed a 3-tranche private placement of 685 million ordinary shares to professional and sophisticated investors for net proceeds of $64.2 million.  The Company also recognized a tax benefit on the cost of capital of $1.0 million.  Proceeds were used to accelerate development in the Eagle Ford and to finance its 2016 Eagle Ford acquisitions.

 

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**c)**                    **Restricted Share Units on Issue**

 

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

 
| **Grant Date**    | ** ** | **2016********No. of RSUs** | ** ** | **2015********No. of RSUs** | ** ** |
|------------------------|------------|---------------------------------------|------------|---------------------------------------|------------|
|                   |       |                                  |       |                                  |       |
| 15 Oct 2012            |       | —                                |       | 352,676                               |       |
| 19 April 2013     |       | —                                |       | 204,914                               |       |
| 28 May 2013       |       | —                                |       | 93,562                                |       |
| 15 April 2014     |       | 393,311                               |       | 658,080                               |       |
| 5 May 2014        |       | —                                |       | 45,000                                |       |
| 12 May 2014       |       | —                                |       | 63,332                                |       |
| 30 May 2014       |       | 167,997                               |       | 503,991                               |       |
| 27 April 2015     |       | —                                |       | 28,874                                |       |
| 28 May 2015       |       | 1,030,075                             |       | 1,545,113                             |       |
| 28 May 2015 (1)   |       | 1,545,113                             |       | 1,545,113                             |       |
| 24 June 2015      |       | 2,382,229                             |       | 4,267,002                             |       |
| 24 June 2015(1)   |       | 2,267,879                             |       | 2,815,681                             |       |
| 17 July 2015      |       | —                                |       | 1,275,000                             |       |
| 1 August 2015     |       | 214,000                               |       | 321,000                               |       |
| 15 March 2016(2)  |       | 6,824,950                             |       | —                                |       |
| 27 May 2016(2)    |       | 4,342,331                             |       | —                                |       |
| 29 June 2016(3)   |       | 3,614,316                             |       | —                                |       |
| 15 August 2016(2) |       | 800,000                               |       | —                                |       |
| 15 August 2016    |       | 200,000                               |       | —                                |       |
| Total RSUs outstanding |       | 23,782,201                            |       | 13,719,338                            |       |

 

----

(1)         RSU’s vest based on 3-year total shareholder return (“TSR”) as compared to the 20-day volume weighted average price (“VWAP”) at 31 December 2014.

 

(2)         ATSR RSUs vest based on 3-year total shareholder return as compared to the 20-day VWAP at 31 December 2015.  These are described in more detail in Part I, Item 6.

 

(3)         Shares will be formally issued on the ASX subsequent to 31 December 2016.

 

**d)**                         **Capital Management**

 

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

 

The Group’s debt and capital includes ordinary share capital and financial liabilities, supported by financial assets.  Other than the covenants described in Note 23, the Group has no externally imposed capital requirements.

 

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

 

There have been no changes in the strategy adopted by management to control the capital of the Group since the prior period.  The strategy is to ensure that any significant increases to the Group’s debt or equity through additional draws or raises have minimal impact to its gearing ratio.  As at 31 December 2016 and 2015, the Company had $192 million outstanding debt.

 

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**NOTE 27 — RESERVES**

 

**a)   Share Based Payments Reserve**

 

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

 

**b)  Foreign Currency Translation Reserve**

 

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

 

**NOTE 28 —****CAPITAL AND OTHER EXPENDITURE COMMITMENTS**

 

**Capital commitments relating to tenements**

 

As at 31 December 2016, all of the Company’s core exploration and evaluation and development and production assets are located in the Oklahoma and Texas. The Company has an interest in a non-core exploration and evaluation license located in Australia.

 

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

 

The Company is committed to fund exploratory drilling in the Cooper Basin (Australia) of up to approximately A$10.6 million through 2019, of which A$5.9 million (US$4.3 million) had been incurred as at 31 December 2016.

 

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

 
| **As at 31 December 2016** | ** ** | **Total****US$’000** | ** ** | **Less than   1 year** | ** ** | **1 — 5 years** | ** ** | **More than 5   years** | ** ** |
|------------------------------------------------|------------|---------------------------|------------|----------------------------------|------------|-------------------------------------|------------|-----------------------------------|------------|
| Cooper Basin   capital commitments (1)         |       | 3,373                     |       | 1,687                            |       | 1,686                               |       | —                            |       |
| Drilling rig   commitments (2)                 |       | 1,085                     |       | 1,085                            |       | —                              |       | —                            |       |
| Operating lease   commitments (3)              |       | 4,123                     |       | 1,353                            |       | 2,267                               |       | 503                               |       |
| Employment commitments   (4)                   |       | 740                       |       | 370                              |       | 370                                 |       | —                            |       |
| Total   expenditure commitments                |       | 9,321                     |       | 4,495                            |       | 4,323                               |       | 503                               |       |

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

 

----

(1)         The Company has capital commitments of up to approximately A$10.6 million through 2019 (commitment amounts in table shown in USD translated at year-end).  Timing of commitment may vary.

(2)         As at 31 December 2016 the Company had one drilling rig contracted to drill seven wells during 2017.  The amount represents minimum expenditure commitments should the Company elect to terminate this contract prior to term.  Subsequent to December 31, 2016, the Company commenced drilling (and therefore is not subject to the termination fee).

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

 

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

 

Subsequent to 31 December 2016, the Company contracted two additional drilling rigs with minimum expenditure commitments of $0.6 million during 2017.

 

**NOTE 29 — CONTINGENT ASSETS AND LIABILITIES**

 

In August 2015, the Company received notice from the buyer of its non-operated Phoenix properties sold in December 2013 that they filed a lawsuit against the Company. The claim of $0.9 million relates to costs not included by the buyer on the final post-closing settlement, for which it seeks reimbursement from the Company. The Company does not believe the case has merit and continues to vigorously defend itself against the lawsuit.

 

The Company recognizes a contingent liability when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that as of the date of this report, it is not probable that the aforementioned claims and litigation involving the Company will have a material adverse impact on the Company.  Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at December 31, 2016 or 2015. At the date of signing this report, the Group is not aware of any other contingent assets or liabilities that should be recognized or disclosed in accordance with AASB 137/IAS 37 — *Provisions, Contingent Liabilities and Contingent Assets.*

 

**NOTE 30 — OPERATING SEGMENTS**

 

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America.  All of the basins and/or formations in which the Company operates in North America have common operational characteristics, challenges and economic characteristics.  As such, Management has determined, based upon the reports reviewed and used to make strategic decisions by the Chief Operating Decision Maker (“CODM”), whom is the Company’s Managing Director and Chief Executive Officer, that the Company has one reportable segment being oil and natural gas exploration and production in North America.  For the years ended 31 December 2016 and 2015, all statement of profit or loss and other comprehensive income activity was attributed to its reportable segment with the exception of $6.7 million and $2.2 million of pre-tax impairment expense, which related to the impairment of its Cooper Basin assets in Australia, respectively.

 

**Geographic Information**

 

The operations of the Group are located in two geographic locations, North America and Australia.  The Company’s Australian assets (Cooper Basin) were acquired in 2015 from NSE and the Company intends to sell these assets as they fall outside the Company’s strategic focus. All revenue is generated from sales to customers located in North America.  As at 31 December 2016 and 2013, the carrying value of the assets held in Australia was nil and $5.2 million respectively.

 

Revenue from two major customers exceeded 10 percent of Group consolidated revenue for the year ended 31 December 2016 and accounted for 69 and 12 percent, respectively (2015: three major customers accounted for 30, 29 and 22 percent, respectively and 2014:  one major customer for 65 percent) of our consolidated oil, natural gas and NGL revenues.  In addition, 12% of the Company’s revenue is paid from a single third party oil and gas operator at a non-operated oil and gas property.

 

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**NOTE 31 — CASH FLOW INFORMATION’**

 
| ** **                                                                                                     | ** ** | **2016**         | ** ** | **2015**         | ** ** | **2014**         | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|------------------|------------|
| **Year ended 31 December**                                                                      | ** ** | **US$’000** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                                                                                           |       |             |       |             |       |             |       |
| **a)****Reconciliation of cash flows from operations with income from   ordinary activities after income tax** |       |             |       |             |       |             |       |
| Profit from ordinary activities   after income tax                                                             |       | (45,694          | )          | (263,835         | )          | 15,321           |       |
| **Adjustments to   reconcile net profit to net operating cash flows:**                                         |       |             |       |             |       |             |       |
| Depreciation and amortisation   expense                                                                        |       | 48,147           |       | 94,584           |       | 85,584           |       |
| Share based compensation                                                                                       |       | 2,524            |       | 4,100            |       | 1,915            |       |
| Unrealised (gains) losses on   derivatives                                                                     |       | 21,433           |       | (3,444           | )          | (9,642           | )          |
| Net gain on sale of properties                                                                                 |       | —           |       | (790             | )          | (48,604          | )          |
| Decrease in fair value of   securities at FVTPL                                                                |       | —           |       | 90               |       | —           |       |
| Impairment of development and   production assets                                                              |       | 10,203           |       | 321,918          |       | 71,212           |       |
| Unsuccessful exploration and   evaluation expense                                                              |       | 30               |       | —           |       | 10,934           |       |
| Loss on debt extinguishment                                                                                    |       | —           |       | 1,151            |       | 316              |       |
| Add: Interest expense and   financing costs(disclosed in investing and financing activities)                   |       | 12,219           |       | 9,418            |       | 383              |       |
| Recognition of DTA on items   directly within equity                                                           |       | 986              |       | —           |       | 879              |       |
| Less: Gain from insurance   proceeds and litigation settlement (disclosed in investing activities              |       | (3,603           | )          | —           |       | —           |       |
| Less: Loss on foreign currency   derivative (disclosed in financing activities)                                |       | 390              |       | —           |       | —           |       |
| Other                                                                                                          |       | 21               |       | 2,240            |       | 126              |       |
| Changes in assets and   liabilities:                                                                           |       |             |       |             |       |             |       |
| - Decrease in current and   deferred income tax                                                                |       | (826             | )          | (100,583         | )          | (14,606          | )          |
| - Decrease in other current   assets                                                                           |       | (511             | )          | 2,742            |       | 28               |       |
| - Decrease in trade and other   receivables                                                                    |       | 2,009            |       | 7,007            |       | 8,679            |       |
| - Increase (decrease) in trade   and other payables                                                            |       | (5,080           | )          | (2,177           | )          | 5,562            |       |
| - Increase in tax receivable                                                                                   |       | 412              |       | (6,522           | )          | —           |       |
| - Decrease in non-current   liability                                                                          |       | —           |       | (1,430           | )          | —           |       |
| **Net cash provided   by operating activities**                                                                |       | 42,660           |       | 64,469           |       | 128,087          |       |

 

**b) Non Cash Financing and Investing Activities**

 

- The Company had additions to oil and natural gas properties of $13,161, $22,559 and $96,586 included in current liabilities at 31 December 2016, 2015 and 2014, respectively. 

 

- During the year ended 31 December 2015, the net gain on sale of properties primarily related to an ad valorem tax true-up related to properties sold in 2014.

 

- During the year ended 31 December 2014 the net gain on sale of properties for the disposition of the Company’s remaining Williston assets included the relief of a net payable due to the buyer of $4.0 million ($17.1 million payable and $13.1 million receivable).

 

**NOTE 32 — SHARE BASED PAYMENTS**

 

The Company recognized share based compensation expense of $2.7 million, $4.1 million and $1.9 million for the years ended 31 December 2016, 2015 and 2014, respectively, comprised of RSUs (equity-settled) and deferred cash awards (cash-settled) and options.

 

**Options**

 

No options were granted during the years ended 31 December 2016, 2015 and 2014 and a total of nil, nil and 431,666 previously issued options were exercised during the years ended 31 December 2016, 2015 and 2014, respectively.

 

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**Restricted Share Units**

 

During the years ended 31 December 2016, 2015 and 2014, the Board of Directors awarded 16,992,192, 13,322,262 and 2,839,626 RSUs, respectively, to certain employees (of which 5,113,281, 3,090,000 and 671,988, respectively, granted to the Company’s Managing Director were approved by shareholders).  These awards were made in accordance with the long-term equity component of the Company’s incentive compensation plan, the details of which are described in more detail in the Remuneration Report of the Directors’ Report.  The fair value calculation methodology is described in Note 1.  RSU expense totaled $2.5 million, $4.1 million and $2.0 million for the years ended 31 December 2016, 2015 and 2014, respectively. This information is summarised for the Group for the years ended 31 December 2016, 2015 and 2014, respectively, below:

 
| ** **                                 | ** ** | **Number   of RSUs** | ** ** | **Weighted Average Fair   Value at Measurement   Date A$** | ** ** |
|--------------------------------------------|------------|---------------------------|------------|-------------------------------------------------------------------------------------|------------|
|                                       |       |                      |       |                                                                                |       |
| **Outstanding   at 31 December 2013** |       | **1,704,307**             |       | **0.83**                                                                            |       |
| Issued or Issuable                         |       | 2,839,626                 |       | 0.97                                                                                |       |
| Converted to   ordinary shares             |       | (1,479,978                | )          | 0.89                                                                                |       |
| Forfeited                                  |       | (99,778                   | )          | 0.92                                                                                |       |
| **Outstanding   at 31 December 2014** |       | **2,964,177**             |       | **0.93**                                                                            |       |
| Issued or   Issuable                       |       | 13,322,262                |       | 0.53                                                                                |       |
| Converted to   ordinary shares             |       | (3,805,789                | )          | 0.63                                                                                |       |
| Forfeited                                  |       | (46,312                   | )          | 0.93                                                                                |       |
| **Outstanding   at 31 December 2015** |       | **12,434,338**            |       | **0.55**                                                                            |       |
| Issued or   Issuable (1)(2)                |       | 18,267,192                |       | 0.18                                                                                |       |
| Converted to   ordinary shares             |       | (5,501,538                | )          | 0.54                                                                                |       |
| Forfeited                                  |       | (1,417,792                | )          | 0.59                                                                                |       |
| **Outstanding   at 31 December 2016** |       | **23,782,200**            |       | **0.34**                                                                            |       |

 

----

(1)         Includes 1,275,000 of RSUs formally issued on the ASX in 2016 in conjunction with a 2015 option conversion.

(2)         Includes 3,853,961 of RSUs that will be formally issued on the ASX subsequent to 31 December 2016.

 

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

 

RSUs awarded during the year ended 31 December 2016:

 
| **Grant Date** | ** ** | **Number of RSUs** | ** ** | **Fair Value at   Measurement Date   (Per RSU in US$)** | ** ** | **Vesting Conditions** |
|---------------------|------------|------------------------------|------------|---------------------------------------------------------------------------------------|------------|-----------------------------|
| 15 March 2016  |       | 6,824,950                    |       | $                                                                                     | 0.15       |                        | 0 % - 133% based on 3 year ATSR |
| 27 May 2016    |       | 4,342,331                    |       | $                                                                                     | 0.10       |                        | 0 % - 133% based on 3 year ATSR |
| 27 May 2016    |       | 770,950                      |       | $                                                                                     | 0.12       |                        | 100% vested immediately |
| 29 June 2016   |       | 3,853,961                    |       | $                                                                                     | 0.08       |                        | 33% on 1 January 2017, 2018 and 2019 |
| 15 August 2016 |       | 400,000                      |       | $                                                                                     | 0.11       |                        | 50% on 13 November 2016 and 50% on 11   February 2017 |
| 15 August 2016 |       | 800,000                      |       | $                                                                                     | 0.11       |                        | 0 % - 133% based on 3 year ATSR |
|                |       | 16,992,192                   |       |                                                                                  |       |                        |

 

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RSUs awarded during the year ended 31 December 2015:

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

 

RSUs awarded during the year ended 31 December 2014:

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

 

Upon vesting, and after a certain administrative period, the RSUs are converted to ordinary shares of the Company.  Once converted to ordinary shares, the RSUs are no longer restricted.  For the years ended 31 December 2016, 2015 and 2014 the weighted average price of the RSUs at the date of conversion was A$0.11, A$0.52 and A$1.11 per share, respectively.

 

At 31 December 2016, the weighted average remaining contractual life of the RSUs was 1.7 years.

 

**Deferred Cash Awards**

 

During the year ended 31 December 2016, the Board of Directors awarded $2,079,879 deferred cash awards to certain employees (of which $601,250 were granted to the Company’s Managing Director approved by shareholders).  Under the deferred cash plan, awards may vest between 0%-300%, earned through appreciation in the price of Sundance’s ordinary shares during 2017 and 2018 (50% of award will be evaluated for vesting at each period end).  The details of the award is described in more detail in the Remuneration Report of the Directors’ Report and the fair value calculation methodology is described in Note 1. The estimated fair value of each one dollar unit of deferred cash awards as at 31 December 2016 was $0.38 and $0.28 for awards vesting at the end of 2017 and 2018, respectively, resulting in a total liability $0.2 million.  There were no deferred cash awards granted in 2015 or 2014.

 

**Grants Subsequent to Year End**

 

Subsequent to 31 December 2016, the Board granted 10,351,858 RSUs that vest between 0% and 150% based on Company’s three year absolute total shareholder return and $1,504,125 of base deferred cash awards which vest 0-300% based on the Company’s stock price appreciation in 2017, 2018 and 2019.

 

**NOTE 33 — RELATED PARTY TRANSACTIONS**

 

There were no material related party transactions for the years ended 31 December 2016, 2015 and 2014.

 

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**NOTE 34 — FINANCIAL RISK MANAGEMENT**

 

**a)   Financial Risk Management Policies**

 

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

 

i)                 Treasury Risk Management

 

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

 

ii)              Financial Risk Exposure and Management

 

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

 

iii)           Commodity Price Risk Exposure and Management

 

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

 

A summary of the Company’s outstanding hedge positions as at 31 December 2016 is below:

 
| **Oil   Derivatives (WTI/LLS)** | ** ** | **Weighted   Average (1)** | ** ** |
|---------------------------------|------------|----------------------------|------------|
| **Year**                        | ** ** | **Units (Bbls)**      | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| 2017                            |       | 930,000                    |       | $ | 49.12 |   | $ | 58.78 |   |
| 2018                            |       | 612,000                    |       | $ | 49.88 |   | $ | 58.92 |   |
| 2019                            |       | 300,000                    |       | $ | 52.51 |   | $ | 54.31 |   |
| Total                           |       | 1,842,000                  |       | $ | 49.87 |   | $ | 58.10 |   |

 

 
| **Gas   Derivatives (HH/HSC)** | ** ** | **Weighted   Average (1)** | ** ** |
|--------------------------------|------------|----------------------------|------------|
| **Year**                       | ** ** | **Units (Mcf)**       | ** ** | **Floor** | ** ** | **Ceiling** | ** ** |
| 2017                           |       | 1,680,000                  |       | $ | 2.86 |   | $ | 3.21 |   |
| 2018                           |       | 1,290,000                  |       | $ | 2.95 |   | $ | 3.36 |   |
| 2019                           |       | 720,000                    |       | $ | 2.95 |   | $ | 3.78 |   |
| Total                          |       | 3,690,000                  |       | $ | 2.91 |   | $ | 3.37 |   |

 

----

(1)         The Company’s outstanding derivative positions include swaps totaling 1,182,000 Bbls and 1,830,000 Mcf, which are included in both the weighted average floor and ceiling value.

 

**b)**             **Net Fair Value of Financial Assets and Liabilities**

 

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

 

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

 

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**c)**              **Credit Risk**

 

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

 

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

 

At 31 December 2016, the Group had one customer that owed the Group approximately $1.5 million and accounted for approximately 21% of total accrued revenue receivables.  To partially mitigate our credit risk, the customer has a letter of credit in place for our benefit.  In the event that the customer defaults, the Company could draw upon the letter of credit.  In addition, the Group had one joint-interest partner that owed the Group approximately $4.0 million of revenue from a non-operated property.  In 2017, the Company expects to begin marketing the production from this property itself; which will reduce its credit risk exposure from this party.  For joint interest billing receivables, if payment is not made, the Group can withhold future payments of revenue, as such, there is minimal to no credit risk associated with these receivables.

 

**d)**             **Liquidity Risk**

 

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

 

The Company has the following commitments related to its financial liabilities (US$’000):

 
| **Year ended 31 December 2016**  | ** ** | **Total** | ** ** | **Less than 1   year** | ** ** | **1 — 5 years** | ** ** | **More than 5   years** | ** ** |
|------------------------------------------------------|------------|-----------|------------|----------------------------------|------------|-------------------------------------|------------|-----------------------------------|------------|
|                                                 |       |      |       |                             |       |                                |       |                              |       |
| Trade and other   payable                            |       | 3,579     |       | 3,579                            |       | —                              |       | —                            |       |
| Accrued expenses                                     |       | 19,995    |       | 19,995                           |       | —                              |       | —                            |       |
| Provisions                                           |       | 6,025     |       | 2,726                            |       | 3,299                               |       | —                            |       |
| Credit   facilities payments, including interest (1) |       | 235,441   |       | 12,606                           |       | 222,835                             |       | —                            |       |
| Total                                                |       | 265,040   |       | 38,906                           |       | 226,134                             |       | —                            |       |

 
| **Year ended 31 December 2015**  | ** ** | **Total** | ** ** | **Less than 1   year** | ** ** | **1 — 5 years** | ** ** | **More than 5   years** | ** ** |
|------------------------------------------------------|------------|-----------|------------|----------------------------------|------------|-------------------------------------|------------|-----------------------------------|------------|
|                                                 |       |      |       |                             |       |                                |       |                              |       |
| Trade and other   payable                            |       | 21,588    |       | 21,588                           |       | —                              |       | —                            |       |
| Accrued expenses                                     |       | 19,883    |       | 19,883                           |       | —                              |       | —                            |       |
| Credit   facilities payments, including interest (1) |       | 247,259   |       | 12,420                           |       | 234,839                             |       | —                            |       |
| Total                                                |       | 288,730   |       | 53,891                           |       | 234,839                             |       | —                            |       |

 

----

(1)  Assumes credit facilities are held to maturity.

 

**e)**              **Market Risk**

 

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

 

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***Commodity Price Risk***

 

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

 

*Commodity Price Risk Sensitivity Analysis*

 

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

 
| **Year ended 31 December**               | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|---------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                                    |       |                    |       |                    |       |                    |       |
| Effect on profit   before tax                           |       |                    |       |                    |       |                    |       |
| Increase /   (Decrease)                                 |       |                    |       |                    |       |                    |       |
| *Oil*                                                   |       |                    |       |                    |       |                    |       |
| - improvement   in US$ oil price of $10 per barrel |       | (12,813                 | )          | (22,731                 | )          | (2,400                  | )          |
| - decline   in US$ oil price of $10 per barrel     |       | 16,233                  |       | 22,731                  |       | 3,041                   |       |
| *Gas*                                                   |       |                    |       |                    |       |                    |       |
| - improvement   in US$ gas price of $0.50 per mcf  |       | (1,423                  | )          | (2,325                  | )          | (120                    | )          |
| - decline   in US$ gas price of $0.50 per mcf      |       | 1,306                   |       | 2,325                   |       | 120                     |       |

 

***Interest Rate Risk***

 

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

 

*Interest Rate Sensitivity Analysis*

 

Based on the net debt position as at 31 December 2016, 2015 and 2014 with all other variables remaining constant, the following table represents the effect on income as a result of changes in the interest rate.  The impact on equity is the same as the impact on profit before tax.

 
| **Year ended 31 December**           | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|-----------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                                |       |                    |       |                    |       |                    |       |
| Effect on profit   before tax Increase / (Decrease) |       |                    |       |                    |       |                    |       |
| - increase   in interest rates + 2%                 |       | (3,357                  | )          | (1,140                  | )          | (906                    | )          |
| - decrease   in interest rates - 2%                 |       | 396                     |       | 112                     |       | 184                     |       |

 

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

 

**NOTE 35 — SUBSIDIARIES**

 

The Company’s significant subsidiaries are as follows:

 
| **Name of Entity**               | ** ** | **Place of Incorporation** | ** ** | **Percentage Owned** | ** ** |
|--------------------------------------------|------------|--------------------------------------|------------|---------------------------|------------|
|                                       |       |                                 |       |                      |       |
| Sundance Energy Inc.                       |       | Colorado                             |       | 100                       |       |
| Sundance Energy Oklahoma, LLC              |       | Delaware                             |       | 100                       |       |
| SEA Eagle Ford, LLC                        |       | Texas                                |       | 100                       |       |
| Armadillo Eagle Ford   Holdings, Inc. |       | Delaware                             |       | 100                       |       |
| Armadillo E&P, Inc.               |       | Delaware                             |       | 100                       |       |
| NSE PEL570 LTD                             |       | Australia                            |       | 100                       |       |

 

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**NOTE 36 — PARENT COMPANY INFORMATION**

 

The Company has prepared Parent Company only financial statements under the cost method of accounting for statutory purposes in Australia, and has also included the presentation under the equity method of accounting.  The Parent Company financial information has been prepared on the same basis, using the same accounting policies as the consolidated financial statements.

 

**a)**             **Cost Basis**

 
| ** **                           | ** ** | **2016**         | ** ** | **2015**         | ** ** |
|--------------------------------------|------------|------------------|------------|------------------|------------|
| **As at 31 December** | ** ** | **US$’000** | ** ** | **US$’000** | ** ** |
|                                 |       |             |       |             |       |
| **Parent Entity**                    |       |             |       |             |       |
| **Assets**                           |       |             |       |             |       |
| Current assets                       |       | 11,103           |       | 18,132           |       |
| Investment in subsidiaries           |       | 61,946           |       | 37,937           |       |
| Deferred tax assets                  |       | 2,683            |       | 1,913            |       |
| Related party note receivable        |       | 122,174          |       | 112,481          |       |
| Total assets                         |       | 197,906          |       | 170,463          |       |
| **Liabilities**                      |       |             |       |             |       |
| Current liabilities                  |       | 83               |       | 54               |       |
| Total liabilities                    |       | 83               |       | 54               |       |
| Total net assets                     |       | 197,823          |       | 170,409          |       |
| **Equity**                           |       |             |       |             |       |
| Issued capital                       |       | 373,585          |       | 308,429          |       |
| Share options reserve                |       | 386              |       | 386              |       |
| Foreign currency translation         |       | (52,948          | )          | (48,214          | )          |
| Accumulated deficit                  |       | (123,200         | )          | (90,192          | )          |
| Total equity                         |       | 197,823          |       | 170,409          |       |

 
| **Year ended 31 December**                              | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|------------------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
| **Financial   Performance**                                            |       |                    |       |                    |       |                    |       |
| Profit/(loss) for the period   before equity in income of subsidiaries |       | (33,009                 | )          | (98,651                 | )          | 7,334                   |       |
| Other comprehensive income                                             |       | (4,733                  | )          | (17,675                 | )          | (10,030                 | )          |
| **Total profit or   loss and other comprehensive income**         |       | (37,742                 | )          | (116,326                | )          | (2,696                  | )          |

 

**b)**             **Equity Basis**

 
| **As at 31 December** | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** |
|--------------------------------------|------------|-------------------------|------------|-------------------------|------------|
| **Parent Entity**                    |       |                    |       |                    |       |
| **Assets**                           |       |                    |       |                    |       |
| Current assets                       |       | 11,103                  |       | 18,132                  |       |
| Investment in subsidiaries           |       | 61,946                  |       | 37,937                  |       |
| Deferred tax assets                  |       | 2,683                   |       | 1,913                   |       |
| Related party note receivable        |       | 122,174                 |       | 112,481                 |       |
| Total assets                         |       | 197,906                 |       | 170,463                 |       |
| **Liabilities**                      |       |                    |       |                    |       |
| Current liabilities                  |       | 83                      |       | 54                      |       |
| Total Liabilities                    |       | 83                      |       | 54                      |       |
| Total net assets                     |       | 197,823                 |       | 170,409                 |       |
| **Equity**                           |       |                    |       |                    |       |
| Issued capital                       |       | 373,585                 |       | 308,429                 |       |
| Share options reserve                |       | 14,174                  |       | 11,650                  |       |
| Foreign currency translation         |       | (1,842                  | )          | (1,310                  | )          |
| Accumulated deficit                  |       | (188,094                | )          | (148,360                | )          |
| Total equity                         |       | 197,823                 |       | 170,409                 |       |

 

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| **Year ended 31 December**                       | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|-----------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
| **Financial   Performance**                                     |       |                    |       |                    |       |                    |       |
| Profit for the period before   equity in income of subsidiaries |       | 9,028                   |       | 6,225                   |       | 7,334                   |       |
| Equity in income of subsidiaries                                |       | (54,723                 | )          | (276,020                | )          | 7,987                   |       |
| Other comprehensive income                                      |       | (531                    | )          | (478                    | )          | 684                     |       |
| **Total profit or   loss and other comprehensive income**  |       | (46,226                 | )          | (270,273                | )          | 16,005                  |       |

 

**c)**                                      **Cash Flow**

 
| **Year ended 31 December**              | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|--------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
| Cash flow provided by (used in)   operating activities |       | 7,105                   |       | (17,772                 | )          | (70,216                 | )          |
| Cash flow (used in)/provided by   investing activities |       | (64,273                 | )          | 1,243                   |       | 9,415                   |       |
| Cash flow provided by financing   activities           |       | 67,679                  |       | 5,676                   |       | 71,761                  |       |

 

**NOTE 37 — DEED OF CROSS GUARANTEE**

 

The Australian Securities Investments Commission Class Order 98/1418 is designed to provide relief to wholly-owned entities from preparing and lodging audited financial reports in Australia. As a condition of the Class Order, SEAL and Armadillo Petroleum Limited (“APL”) and collectively (“the Closed Group”) have entered into a Deed of Cross Guarantee (“Deed”).  The effect of the Deed is that SEAL has guaranteed to pay any deficiency in the event of the winding up of APL under certain provision of the *Corporations Act 2001*.  APL has also given a similar guarantee in the event that SEAL is wound up.

 

Set out below is a consolidated statement of profit or loss and other comprehensive income and retained earnings of the Closed Group:

 
| **Year ended 31 December**                  | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** | **2014   US$’000** | ** ** |
|------------------------------------------------------------|------------|-------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                                       |       |                    |       |                    |       |                    |       |
| Profit / (loss) before income tax                          |       | (38,383                 | )          | (99,132                 | )          | 7,764                   |       |
|                                                       |       |                    |       |                    |       |                    |       |
| Income tax expense                                         |       | (1,316                  | )          | (1,723                  | )          | (324                    | )          |
|                                                       |       |                    |       |                    |       |                    |       |
| (Loss) profit attributable to   members of SEAL            |       | (39,699                 | )          | (100,855                | )          | 7,440                   |       |
|                                                       |       |                    |       |                    |       |                    |       |
| Total comprehensive loss   attributable to members of SEAL |       | (44,440                 | )          | (118,526                | )          | (2,813                  | )          |
|                                                       |       |                    |       |                    |       |                    |       |
| Retained earnings (accumulated   deficit) at 1 January     |       | (92,284                 | )          | 8,572                   |       | 1,132                   |       |
| Retained earnings (accumulated   deficit) at 31 December   |       | (131,979                | )          | (92,284                 | )          | 8,572                   |       |

 

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

 
| **Year ended 31 December** | ** ** | **2016   US$’000** | ** ** | **2015   US$’000** | ** ** |
|-------------------------------------------|------------|-------------------------|------------|-------------------------|------------|
|                                      |       |                    |       |                    |       |
| **Current   assets**                      |       |                    |       |                    |       |
| Cash and cash   equivalents               |       | 10,756 -                |       | 245                     |       |
| Trade and other   receivables             |       | —                  |       | 3,426                   |       |
| Other current   assets                    |       | 346                     |       | 10,001                  |       |
| Assets held for   sale                    |       | —                  |       | 5,234                   |       |
| **Total   current assets**                |       | 11,102                  |       | 18,906                  |       |
|                                      |       |                    |       |                    |       |
| **Non-current   assets**                  |       |                    |       |                    |       |
| Exploration and   evaluation expenditure  |       | 40                      |       | 40                      |       |
| Related party   note receivable           |       | 122,174                 |       | 112,481                 |       |
| Deferred tax   assets                     |       | 2,683                   |       | 1,913                   |       |
| Investment in   subsidiaries              |       | 56,090                  |       | 36,543                  |       |
| **Total   non-current assets**            |       | **180,987**             |       | **150,977**             |       |
|                                      |       |                    |       |                    |       |
| **Total   assets**                        |       | **192,089**             |       | **169,883**             |       |
|                                      |       |                    |       |                    |       |
| **Current   liabilities**                 |       |                    |       |                    |       |
| Trade and other   payables                |       | 13                      |       | 31                      |       |
| Accrued expenses                          |       | 3,031                   |       | 1,542                   |       |
| **Total   current liabilities**           |       | **3,044**               |       | **1,573**               |       |
|                                      |       |                    |       |                    |       |
| **Non-current   liabilities**             |       |                    |       |                    |       |
| Deferred tax   liabilities                |       | —                  |       | 3                       |       |
| **Total   non-current liabilities**       |       | **—**              |       | **3**                   |       |
|                                      |       |                    |       |                    |       |
| **Total   liabilities**                   |       | **3,044**               |       | **1,576**               |       |
|                                      |       |                    |       |                    |       |
| **Net   assets**                          |       | **189,045**             |       | **168,307**             |       |
|                                      |       |                    |       |                    |       |
| **Equity**                                |       |                    |       |                    |       |
| Issued capital                            |       | 373,585                 |       | 308,429                 |       |
| Share based   payments reserve            |       | 386                     |       | 386                     |       |
| Foreign currency   translation            |       | (52,947                 | )          | (48,224                 | )          |
| Retained   earnings (accumulated deficit) |       | (131,979                | )          | (92,284                 | )          |
| **Total   equity**                        |       | **189,045**             |       | **168,307**             |       |

 

**NOTE 38 — EVENTS AFTER THE BALANCE SHEET DATE**

 

On 1 March 2017, the Company entered into a binding sale and purchase agreement to divest of its assets located in the Anadarko Basin of Oklahoma for cash of $18.5 million.  The assets being sold include all of the Oklahoma wells and acreage owned by the Company.   The transaction is subject to several common closing conditions such as confirmatory due diligence but is not subject to any financing contingencies.  The Company expects the transaction to close by May 2017.

 

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**NOTE 39—UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES**

 

**Costs Incurred**

 

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

 
| ** **                 | ** ** | **Year ended December 31,** | ** ** |
|----------------------------|------------|--------------------------------------------|------------|
| **(in thousands)**    | ** ** | **2016**                                   | ** ** | **2015** | ** ** | **2014** | ** ** |
| Property acquisition costs |       |                                       |       |   |   |   |   |
| Proved(1)                  |       | $                                          | 23,873     |   | $ | 13,170 |   | $ | 2,244 |   |
| Unproved(1)                |       | 2,815                                      |       | 15,495 |   | 34,184 |   |
| Exploration costs          |       | 1,650                                      |       | 10,353 |   | 2,929 |   |
| Development costs (1)      |       | 61,131                                     |       | 76,831 |   | 350,196 |   |
|                       |       | $                                          | 89,469     |   | $ | 115,859 |   | $ | 389,554 |   |

 

----

(1)                                 2016, 2015 and 2014 development costs include $5.0 million, $16.6 million and $49.2 million of costs associated with non-producing wells in progress as at 31 December 2016, 2015 and 2014 respectively. These wells in progress were either drilling, waiting on hydraulic fracturing or production testing at year-end.

 

**SEC Oil and Gas Reserve Information**

 

Ryder Scott Company, L.P., an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interest owned by the Company as of December 31, 2016 and 2015. The technical person primarily responsible for the estimates set forth in the reserves report is Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado and Texas with over 10 years of practical experience in estimation and evaluation of petroleum reserves.

 

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

 

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

 

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

 

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

 
| ** **                        | ** ** | **Oil   (MBbl)** | ** ** | **Natural   Gas   (MMcf)** | ** ** | **NGL   (MBbl)** | ** ** | **Total Oil   Equivalents   (MBbl)** | ** ** |
|-----------------------------------|------------|------------------|------------|----------------------------|------------|------------------|------------|-------------------------------------------|------------|
| **Total proved   reserves:**      |       |             |       |                       |       |             |       |                                      |       |
| **31 December 2013**    |       | 12,956           |       | 30,655                     |       | 2,683            |       | 20,747                                    |       |
| Revisions of previous estimates   |       | (143             | )          | (1,395                     | )          | (580             | )          | (955                                      | )          |
| Extensions and discoveries        |       | 9,275            |       | 16,003                     |       | 2,330            |       | 14,272                                    |       |
| Purchases of reserves in-place    |       | 64               |       | 28                         |       | 1                |       | 70                                        |       |
| Production                        |       | (1,675           | )          | (1,803                     | )          | (268             | )          | (2,244                                    | )          |
| Sales of reserves in-place        |       | (3,451           | )          | (14,754                    | )          | —           |       | (5,910                                    | )          |
| **31 December 2014**    |       | 17,026           |       | 28,733                     |       | 4,166            |       | 25,981                                    |       |
| Revisions of previous estimates   |       | (3,491           | )          | (8,152                     | )          | (1,218           | )          | (6,068                                    | )          |
| Extensions and discoveries        |       | 1,950            |       | 4,122                      |       | 699              |       | 3,336                                     |       |
| Purchases of reserves in-place    |       | 3,896            |       | 4,454                      |       | 238              |       | 4,876                                     |       |
| Production                        |       | (1,829           | )          | (2,581                     | )          | (393             | )          | (2,652                                    | )          |
| Sales of reserves in-place        |       | —           |       | —                     |       | —           |       | —                                    | )          |
| **31 December 2015**    |       | 17,552           |       | 26,576                     |       | 3,492            |       | 25,473                                    |       |
| Revisions of previous estimates   |       | (1,397           | )          | 536                        |       | (833             | )          | (2,141                                    | )          |
| Extensions and discoveries        |       | 4,242            |       | 10,240                     |       | 1,551            |       | 7,500                                     |       |
| Purchases of reserves in-place    |       | 1,432            |       | 3,121                      |       | 1,216            |       | 3,168                                     |       |
| Production                        |       | (1,412           | )          | (2,941                     | )          | (332             | )          | (2,234                                    | )          |
| Sales of reserves in-place        |       | (1,976           | )          | (1,802                     | )          | —           |       | (2,276                                    | )          |
| **31 December 2016**    |       | 18,441           |       | 35,730                     |       | 5,094            |       | 29,490                                    |       |
| **Proved developed   reserves:**  |       |             |       |                       |       |             |       |                                      |       |
| 31 December 2014        |       | 6,124            |       | 12,364                     |       | 1,801            |       | 9,985                                     |       |
| 31 December 2015        |       | 6,379            |       | 13,205                     |       | 1,998            |       | 10,578                                    |       |
| 31 December 2016        |       | 7,440            |       | 16,704                     |       | 2,269            |       | 12,493                                    |       |
| **Proved undeveloped   reserves** |       |             |       |                       |       |             |       |                                      |       |
| 31 December 2014        |       | 10,903           |       | 16,369                     |       | 2,365            |       | 15,996                                    |       |
| 31 December 2015        |       | 11,173           |       | 13,371                     |       | 1,494            |       | 14,895                                    |       |
| 31 December 2016        |       | 11,001           |       | 19,026                     |       | 2,825            |       | 16,997                                    |       |

 

**Proved Undeveloped Reserves**

 

At December 31, 2016, the Company’s proved undeveloped reserves were approximately 16,997 MBoe, an increase of 2,102 MBoe over our December 31, 2015 proved undeveloped reserves estimate of approximately 14,895 MBoe. The change primarily consisted of extensions and discoveries of 7,500 MBoe (Eagle Ford) and purchases of reserves of 845 MBoe (Eagle Ford, from its acquisitions in July and December 2016), partially offset by downward revisions to previous estimates of approximately 863 MBoe, sales of reserves of 2,242 Mboe and a decrease of 3,138 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves.   The revisions to previous estimates were attributable solely to the Eagle Ford.

 

Over the next five years, the Company expects to fund its future development costs associated with proved undeveloped reserves of $247.4 million with operating cash flows from its existing proved developed reserves and proved undeveloped reserves that are expected to be converted to proved developed reserves.  Using the December 31, 2016 SEC price assumptions, the Company’s proved reserves operating cash flows are expected to be approximately $310.3 million (undiscounted, before income taxes (if any)).  As such, the Company expects all proved undeveloped locations that are scheduled and included in the Company’s reserves will be spud within the next five years.

 

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**Depletable Reserve Base**

 

In accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board, the Company includes economically recoverable reserves as its depletable Reserve base used for its depletion calculation. Generally, the Company uses only Proved Developed Reserves in its depletable Reserve base. However, for the year ended December 31, 2014 the Company also included 887.3 MBoe of Probable Developed Reserves in its Eagle Ford depletable Reserve base used for its depletion calculations. The Proved and Probable Developed Reserves represented management’s best estimate of economically recoverable reserves associated with developed properties located in the Eagle Ford formation for the year ended December 31, 2014.  There were no Probable Developed Reserves as of December 31, 2016 and 2015; therefore, the Company only included Proved Developed Reserves in its Eagle Ford depletable Reserve base used for its depletion calculation for the years ended December 31, 2016 and 2015.

 

**Revisions of Previous Estimates**

 

The Company’s previous estimates of Proved Reserves related to the Eagle Ford decreased by 2,141 MBoe in 2016 (100% percent of the Company’s total revisions of previous estimate). This decrease was due to the majority of the Company’s previous Eagle Ford Proved Undeveloped Reserves becoming uneconomic as the result of adjusted forecasts and lower oil, natural gas and NGL pricing.

 

The Company’s previous estimates of Proved Reserves related to the Mississippian/Woodford formation decreased by 5,900 MBoe in 2015 (97 percent of the Company’s total revisions of previous estimate). This decrease was due to the majority of the Company’s previous Mississippian/Woodford Proved Undeveloped Reserves becoming uneconomic as the result of lower oil, natural gas and NGL pricing.

 

The Company’s previous estimates of Proved Reserves related to the Mississippian/Woodford formation decreased by 821 MBoe in 2014 (86 percent of the Company’s total revisions of previous estimate). This decrease was due to adjusted forecasts for the Mississippian/Woodford formation.

 

**Extensions and Discoveries**

 

As a result of the Company’s 2016 drilling programs in Dimmit and McMullen Counties, targeting the Eagle Ford formation, the Proved Reserves had extensions and discoveries of 7,500 MBoe, which represent 100% of the Company’s total extensions and discoveries.

 

As a result of the Company’s 2015 drilling programs in Dimmit County targeting the Eagle Ford formation, the Proved Reserves had extensions and discoveries of 3,303 MBoe, which represent 99% of the Company’s total extensions and discoveries.

 

As a result of the Company’s active 2014 drilling programs in its Eagle Ford and Mississippian/Woodford formations, the Proved Reserves had extensions and discoveries of 9,488 MBoe and 4,784 MBoe, which represent 66% and 34% of the Company’s total extensions and discoveries, respectively.

 

**Purchase of Reserves In-Place**

 

During the years ended 31 December 2016, 2015 and 2014, our purchases of reserves were located in the Eagle Ford.

 

**Sales of Reserves In-Place**

 

During the year ended 31 December 2016, the Company’s sales of reservers were located in the Atascosa County, Texas, of the Eagle Ford formation.

 

During the year ended 31 December 2015, we did not have any sales of reserves in-place.

 

During the year ended 31 December 2014, the Company’s sales of reserves were located in the Denver-Julesburg Basin and Goliath prospect of the Bakken.

 

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**Standardized Measure of Future Net Cash Flow**

 

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

 

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

 

The following summary sets forth our Standardized Measure:

 
| ** **                                                | ** ** | **Year ended 31 December** | ** ** |
|-----------------------------------------------------------|------------|-------------------------------------------|------------|
| **(in thousands)**                                   | ** ** | **2016**                                  | ** ** | **2015** | ** ** | **2014** | ** ** |
| Cash inflows                                              |       | $                                         | 892,576    |   | $ | 936,041 |   | $ | 1,822,997 |   |
| Production costs                                          |       | (307,907                                  | )          | (246,277 | ) | (444,369 | ) |
| Development costs                                         |       | (274,384                                  | )          | (308,253 | ) | (411,110 | ) |
| Income tax expense                                        |       | —                                    |       | (1,602 | ) | (182,999 | ) |
| Net cash flow                                             |       | 310,285                                   |       | 379,909 |   | 784,520 |   |
| 10% annual discount rate                                  |       | (151,146                                  | )          | (198,142 | ) | (349,014 | ) |
| Standardized measure of   discounted future net cash flow |       | $                                         | 159,139    |   | $ | 181,767 |   | $ | 435,506 |   |

 

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

 
| ** **                                                                   | ** ** | **Year ended 31 December** | ** ** |
|------------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| **(in thousands)**                                                      | ** ** | **2016**                                  | ** ** | **2015** | ** ** | **2014** | ** ** |
| Standardized Measure, beginning   of period                                  |       | $                                         | 181,767    |   | $ | 435,506 |   | $ | 268,163 |   |
| Sales, net of production costs                                               |       | (49,496                                   | )          | (67,693 | ) | (139,304 | ) |
| Net change in sales prices, net   of production costs                        |       | (62,670                                   | )          | (369,770 | ) | 37,325 |   |
| Extensions and discoveries, net   of future production and development costs |       | 3,603                                     |       | 11,609 |   | 252,527 |   |
| Changes in future development   costs                                        |       | 5,331                                     |       | 28,092 |   | 21,115 |   |
| Previously estimated development   costs incurred during the period     |       | 45,012                                    |       | 31,007 |   | 119,164 |   |
| Revision of quantity estimates                                               |       | 9,762                                     |       | (91,440 | ) | (27,495 | ) |
| Accretion of discount                                                        |       | 18,217                                    |       | 53,173 |   | 33,698 |   |
| Change in income taxes                                                       |       | 402                                       |       | 95,827 |   | (27,408 | ) |
| Purchases of reserves in-place                                               |       | 17,004                                    |       | 442 |   | 2,863 |   |
| Sales of reserves in-place                                                   |       | 845                                       |       | — |   | (67,754 | ) |
| Change in production rates and   other                                       |       | (10,638                                   | )          | 55,014 |   | (37,388 | ) |
| Standardized Measure, end of   period                                        |       | $                                         | 159,139    |   | $ | 181,767 |   | $ | 435,506 |   |

 

**Impact of Pricing**

 

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

 

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The following average prices were used in determining the Standardized Measure as at:

 
| ** **                       | ** ** | **Year ended 31 December** | ** ** |
|----------------------------------|------------|-------------------------------------------|------------|
| ** **                       | ** ** | **2016**                                  | ** ** | **2015** | ** ** | **2014** | ** ** |
| Oil price per Bbl |       | $                                         | 42.02      |   | $ | 48.47 |   | $ | 92.26 | ** ** |
| Gas price per Mcf                |       | $                                         | 1.22       |   | $ | 1.27 |   | $ | 4.43 |   |
| NGL price per Bbl                |       | $                                         | 14.55      |   | $ | 14.80 |   | $ | 29.96 |   |

 

The Company calculates the projected income tax effect using the “year- by-year” method for purposes of the supplemental oil and gas disclosures.

 

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** **

**SIGNATURES**

 

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

 
|   | SUNDANCE   ENERGY AUSTRALIA LIMITED |
|--------|-------------------------------------|
|   |                                |
|   |                                |
|   | By:                                 | /s/ Eric   P. McCrady |
|   |                                | Name: | Eric P.   McCrady |
|   |                                | Title: | Chief   Executive Officer |

 

Date: April 28, 2017

 

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** **

**EXHIBIT INDEX**

 

| **Exhibit   Number** | ** ** | **Description of Exhibit**                                                                                                                                                                                                                                                                                                                                            |
|----------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 1.1                  |       | Constitution of Sundance Energy Australia Limited (incorporated   by reference to Exhibit 1.1 of Form 20-F (File No. 000-55246) filed with   the SEC on July 11, 2014)                                                                                                                                                                                                |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 4.1                  |       | Credit Agreement, dated as of May 14, 2015, among Sundance   Energy Australia Limited, Sundance Energy, Inc., as borrower, Morgan   Stanley Energy Capital, Inc., as administrative agent, and the lenders   party thereto (incorporated by reference to Exhibit 4.1 of Form 20-F   (File No. 000-55246) filed with the SEC on May 15, 2015)           |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 4.2                  |       | Guarantee and Collateral Agreement, dated as of May 14,   2015, by Sundance Energy Australia Limited, Sundance Energy Inc. and other   guarantor party thereto, in favor of Morgan Stanley Energy Capital Inc.,   as administrative agent (incorporated by reference to Exhibit 4.2 of Form   20-F (File No. 000-55246) filed with the SEC on May 15, 2015) |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 4.3                  |       | Form of Deed of Access, Insurance and Indemnity for   Directors and Officers (incorporated by reference to Exhibit 4.9 of Form   20-F (File No. 000-55246) filed with the SEC on July 11, 2014)                                                                                                                                                             |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 4.4                  |       | Form of Employment Agreement, by and between Sundance Energy Inc.   and Eric P. McCrady (incorporated by reference to Exhibit 4.4 of Form   20-F (File No. 000-55246) filed with the SEC on May 2, 2016)                                                                                                                                                    |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 8.1                  |       | List of significant subsidiaries of Sundance Energy Australia   Limited*                                                                                                                                                                                                                                                                                                        |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 12.1                 |       | Certification of Chief Executive Officer pursuant to   Section 302 of the Sarbanes-Oxley Act of 2002*                                                                                                                                                                                                                                                                      |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 12.2                 |       | Certification of Chief Financial Officer pursuant to   Section 302 of the Sarbanes-Oxley Act of 2002*                                                                                                                                                                                                                                                                      |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 13.1                 |       | Certification of Chief Executive Officer pursuant to   Section 906 of the Sarbanes-Oxley Act of 2002*                                                                                                                                                                                                                                                                      |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 13.2                 |       | Certification of Chief Financial Officer pursuant to   Section 906 of the Sarbanes-Oxley Act of 2002*                                                                                                                                                                                                                                                                      |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.1                 |       | Consent of Deloitte Touche Tomatsu*                                                                                                                                                                                                                                                                                                                                             |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.2                 |       | Consent of Ernst and Young*                                                                                                                                                                                                                                                                                                                                                     |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.3                 |       | Consent of Ryder Scott Company to use its reports*                                                                                                                                                                                                                                                                                                                              |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.4                 |       | Consent of Netherland, Sewell & Associates, Inc.   to use its report*                                                                                                                                                                                                                                                                                             |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.5                 |       | Report of Ryder Scott Company regarding the Company’s estimated   proved reserves as of December 31, 2016 dated January 30, 2017*                                                                                                                                                                                                                                |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.6                 |       | Report of Ryder Scott Company regarding the Company’s estimated   proved reserves as of December 31, 2015 dated April 30, 2016   (incorporated by reference to Exhibit 15.4 of Form 20-F (File No.   000-55246) filed with the SEC on May 2, 2016)                                                                                                     |
|                 |       |                                                                                                                                                                                                                                                                                                                                                                            |
| 15.7                 |       | Report of Netherland, Sewell & Associates, Inc.   regarding the Company’s estimated proved reserves as of December 31,   2014 dated April 27, 2015 (incorporated by reference to   Exhibit 15.2 of Form 20-F (File No. 000-55246) filed with the SEC on   May 15, 2015)                                                                  |

 

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* Filed herewith.

 

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