Table of Contents

 

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, 20142016                

 

 

OR

 

 

o

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

 

 

OR

 

 

o

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

 

Commission file number: 000-55246001-36302

 

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: None

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:

 

Ordinary SharesNone

(Title of Class)

 



Table of Contents

 

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

None

(Title of Class)

 

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

 

549,295,8391,249,351,617 Ordinary Shares at December 31, 20142016

 

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

 



Table of Contents

 

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

23

28

Item 4A. Unresolved Staff Comments

39

44

Item 5. Operating and Financial Review and Prospects

39

45

Item 6. Directors, Senior Management and Employees

58

60

Item 7. Major Shareholders and Related Party Transactions

67

68

Item 8. Financial Information

68

70

Item 9. The Offer and Listing

70

71

Item 10. Additional Information

71

73

Item 11. Quantitative and Qualitative Disclosures about Market Risk

78

81

Item 12. Description of Securities Other than Equity Securities

80

82

Part II

 

Item 13. Defaults, Dividend Arrearages and Delinquencies

80

84

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

80

84

Item 15. Controls and Procedures

80

84

Item 16A. Audit Committee Financial Expert

81

84

Item 16B. Code of Ethics

81

85

Item 16C. Principal Accountant Fees and Services

81

85

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

81

85

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

81

85

Item 16F. Change in Registrant’s Certifying Accountant

81

85

Item 16G. Corporate Governance

81

85

Item 16H. Mine Safety Disclosure

81

86

Part III

 

Item 17. Financial Statements

82

86

Item 18. Financial Statements

82

86

Item 19. Exhibits

82

86

 

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Table of Contents

EXPLANATORY NOTES

 

Unless otherwise indicated or the context implies otherwise:

 

·                  “we,“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;

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

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

 

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

 

·                  “Netherland“Netherland Sewell” refers to Netherland, Sewell & Associates, Inc., ourthe independent engineering firm, that provided the estimates of proved oil and natural gas reserves as of December 31, 20142014; 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, 2013.2016 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 our 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.

 

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Table of Contents

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.

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 affiliatesnon-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$1.07 billion; or

 

·                  the date on which we have issued more than $1 billion in non convertiblenon-convertible debt securities in any rolling three year period.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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Table of Contents

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 consolidated financial statements and operational information provided throughout for the year ended December 31, 2014 includes amounts related to the Denver-Julesberg divestiture. See page F-2 of our Unaudited Pro Forma Condensed Consolidated Financial Statements included in this annual report for further information on the divestiture and the impact thereof.

The following tables set forth summary historical and pro forma 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

 

 

 

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

 


(1)The summary unaudited pro forma statement of operationsCompany filed an amendment to its Form 20-F for the fiscal year ended December 31, 2014 is derived from the unaudited pro forma condensed consolidated financial statements included in this annual report2015 to correct an identified accounting error related to its income tax benefit and gives effect to our disposition of our remaining Denver-Julesburg assets on July 27, 2014 as if such transaction had occurred on January 1, 2014. As the Denver-Julesburg disposition has beendeferred tax liabilities.  The restated amounts are reflected in our statement of financial position as of December 31, 2014, there is no impactthe table above.  Refer to the summary pro forma unaudited balance sheet data as a result of that transaction. The disposition of our remaining Bakken assets in July 2014 were excluded from these unaudited pro forma financial statements due to the insignificance of the disposition. The summary unaudited pro forma financial information, while helpful in illustrating our financial characteristics using certain assumptions, does not reflect the impact of possible revenue enhancements, expense efficiencies and asset dispositions, among other factors that may result as a consequence of these pro forma transactions and, accordingly, does not attempt to predict or suggest future results. It also does not necessarily reflect what our historical results would have been had the pro forma transactions occurred during these periods.

You should read the selected consolidated financial data in conjunction with our consolidated financial statements and related notes beginning on page F-1 of this annual report and Item 5 “Operating and Financial Review and Prospects” included elsewhere in this annual report. Our historical results do not necessarily indicate our expected results18, Note 7 for any future periods.additional discussion.

 

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Table of Contents

 

 

Pro forma
year ended
December 31,

 

Year ended December 31,

 

Six-month
period ended
December 31,

 

Year ended
June 30,

 

(In $ ‘000s)

 

2014

 

2014

 

2013

 

2012

 

2012

 

2011

 

 

 

(unaudited)

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil revenue

 

$

135,580

 

$

144,994

 

$

79,365

 

$

16,790

 

$

27,965

 

$

16,706

 

Natural gas revenue

 

4,922

 

6,161

 

2,774

 

934

 

1,822

 

1,470

 

Natural gas liquids (NGL) (1)

 

7,763

 

8,638

 

3,206

 

 

 

 

Total oil and natural gas revenues

 

148,265

 

159,793

 

85,345

 

17,724

 

29,787

 

18,176

 

Lease operating and production tax expenses

 

18,892

 

20,489

 

18,383

 

4,082

 

6,355

 

2,858

 

Depreciation and amortization expense

 

84,201

 

85,584

 

36,225

 

6,116

 

11,111

 

6,509

 

General and administrative expense

 

15,527

 

15,527

 

15,297

 

5,810

 

6,863

 

5,338

 

Finance costs, net of interest income

 

494

 

494

 

(351

)

578

 

(111

)

(312

)

Impairment of non-current assets

 

71,212

 

71,212

 

 

 

357

 

1,273

 

Exploration and evaluation expenditure

 

10,934

 

10,934

 

 

 

 

 

Gain on sale of non-current assets

 

(925

)

(48,604

)

(7,335

)

(122,327

)

(3,004

)

(10,940

)

(Gain) / loss on commodity hedging

 

(11,009

)

(11,009

)

554

 

639

 

(1,945

)

1,107

 

Realized currency loss

 

 

 

 

 

4

 

559

 

Other expense (income)

 

686

 

686

 

1,063

 

 

 

 

Income tax (benefit) expense

 

(22,321

)

(841

)

5,567

 

46,616

 

4,145

 

4,755

 

Profit (loss) attributable to owners of Sundance

 

$

(19,426

)

$

15,321

 

$

15,942

 

$

76,210

 

$

6,012

 

$

7,029

 

Other comprehensive income (expense)

 

 

 

 

 

 

 

 

 

 

 

 

 

Exchange differences arising on translation of foreign operations

 

684

 

684

 

(421

)

(154

)

(247

)

384

 

Total comprehensive income (loss) attributable to owners of Sundance

 

$

(18,742

)

$

16,005

 

$

15,521

 

$

76,056

 

$

5,765

 

$

7,413

 

Basic and diluted earnings per share

 

$

(0.04

)

$

0.03

 

$

0.04

 

$

0.27

 

$

0.02

 

$

0.03

 

Basic weighted average number of ordinary shares outstanding

 

531,391,405

 

531,391,405

 

413,872,184

 

277,244,883

 

277,049,463

 

260,935,572

 

Other Supplementary Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDAX(2)

 

$

116,442

 

$

126,373

 

$

52,594

 

$

9,223

 

$

17,093

 

$

9,993

 


(1)(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.

 

(2)(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“Adjusted EBITDAX” below.

 

 

December 31,

 

June 30,

 

 

December 31,

 

Six month
period ended
December 31

 

Year ended
June 30

 

(In $ ‘000s)

 

2014

 

2013

 

2012

 

2012

 

2011

 

 

2016

 

2015

 

2014

 

2013

 

2012

 

2012

 

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

 

 

 

Restated(1)

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Statement of Financial Position Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

69,217

 

$

96,871

 

$

154,110

 

$

15,328

 

$

25,244

 

 

$

17,463

 

$

3,468

 

$

69,217

 

$

96,871

 

$

154,110

 

$

15,328

 

Assets held for sale

 

 

11,484

 

 

 

 

 

18,309

 

90,632

 

 

11,484

 

 

 

Total current assets

 

114,045

 

141,141

 

175,424

 

30,691

 

31,173

 

 

58,840

 

125,345

 

114,045

 

141,141

 

175,424

 

30,691

 

Oil and natural gas properties:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development and production assets

 

519,013

 

312,230

 

79,729

 

87,274

 

45,873

 

 

338,709

 

250,922

 

519,013

 

312,230

 

79,729

 

87,274

 

Exploration and evaluation expenditure

 

155,130

 

166,144

 

33,439

 

11,436

 

6,626

 

 

34,366

 

26,323

 

155,130

 

166,144

 

33,439

 

11,436

 

Total assets

 

796,520

 

625,060

 

291,435

 

130,316

 

84,080

 

 

432,088

 

409,835

 

796,520

 

625,060

 

291,435

 

130,316

 

Current liabilities

 

119,324

 

140,862

 

51,842

 

30,393

 

10,160

 

 

31,820

 

42,215

 

119,324

 

140,862

 

51,842

 

30,393

 

Credit facilities, net of deferred financing fees

 

128,805

 

29,141

 

29,570

 

14,655

 

 

 

188,249

 

187,743

 

128,805

 

29,141

 

29,570

 

14,655

 

Restoration provision

 

8,866

 

5,074

 

1,228

 

588

 

349

 

 

7,072

 

3,088

 

8,866

 

5,074

 

1,228

 

588

 

Deferred tax liabilities

 

102,668

 

102,711

 

56,979

 

10,476

 

6,104

 

 

 

 

102,668

 

102,711

 

56,979

 

10,476

 

Total non-current liabilities

 

242,190

 

136,957

 

87,777

 

25,719

 

6,453

 

 

202,445

 

191,251

 

242,190

 

136,957

 

87,777

 

25,719

 

Total liabilities

 

361,514

 

277,819

 

139,619

 

56,112

 

16,613

 

 

234,265

 

233,466

 

361,514

 

277,819

 

139,619

 

56,112

 

Net assets

 

435,006

 

347,241

 

151,816

 

74,204

 

67,467

 

 

197,823

 

176,369

 

435,006

 

347,241

 

151,816

 

74,204

 

Issued capital

 

306,853

 

237,008

 

58,694

 

57,978

 

57,831

 

 

373,585

 

308,429

 

306,853

 

237,008

 

58,694

 

57,978

 

 

4



(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.

Table of Contents

 

Year ended
December 31,

 

Six month
period ended
December 31,

 

Year ended
June 30,

 

 

Year ended December 31,,

 

Six month
period ended
December 31,

 

Year ended
June 30,

 

(In $ ‘000s)

 

2014

 

2013

 

2012

 

2012

 

2011

 

 

2016

 

2015

 

2014

 

2013

 

2012

 

2012

 

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

128,087

 

$

62,646

 

$

9,386

 

$

11,832

 

$

8,908

 

 

$

42,660

 

$

64,469

 

$

128,087

 

$

62,646

 

$

9,386

 

$

11,832

 

Net cash (used in) provided by investing activities

 

(323,235

)

(164,355

)

114,571

 

(36,149

)

(13,465

)

 

(79,991

)

(180,771

)

(323,235

)

(164,355

)

114,571

 

(36,149

)

Net cash provided by financing activities

 

167,595

 

44,455

 

14,846

 

14,734

 

18,869

 

 

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, and income and gains and losses on commodity hedging, net of settlements of commodity hedging.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 methods orpolicies 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 methodspolicies and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with IFRS, as issued by the IASB, or as an indicator of our operating performance or liquidity.

 

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

 

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

 

 

Pro forma
Year ended
December 31,

 

Year ended December 31,

 

Six-month
period ended
December 31,

 

Year ended
June 30,

 

 

Year ended December 31,

 

Six month
period ended
Decmber 31,

 

Year ended
June 30,

 

(In $ ‘000s)

 

2014

 

2014

 

2013

 

2012

 

2012

 

2011

 

 

2016

 

2015

 

2014

 

2013

 

2012

 

2012

 

 

(unaudited)

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

 

 

 

Restated (1)

 

 

 

 

 

 

 

 

 

IFRS Profit Reconciliation to Adjusted EBITDAX:

 

 

 

 

 

 

 

 

 

 

 

 

 

IFRS Net Profit Reconciliation to Adjusted EBITDAX:

 

 

 

 

 

 

 

 

 

 

 

 

 

Profit (loss) attributable to owners of Sundance

 

$

(19,426

)

$

15,321

 

$

15,942

 

$

76,210

 

$

6,012

 

$

7,029

 

 

$

(45,694

)

$

(263,835

)

$

15,321

 

$

15,942

 

$

76,210

 

$

6,012

 

Income tax (benefit) expense

 

(22,321

)

(841

)

5,567

 

46,616

 

4,145

 

4,755

 

 

1,705

 

(107,138

)

(841

)

5,567

 

46,616

 

4,145

 

Finance costs, net of (interest received)

 

494

 

494

 

(232

)

578

 

(111

)

(312

)

 

12,219

 

9,418

 

494

 

(232

)

578

 

(111

)

(Gain) loss on commodity hedging

 

(10,792

)

(10,792

)

554

 

639

 

(1,945

)

1,107

 

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

 

1,150

 

1,150

 

283

 

551

 

(297

)

(643

)

 

8,672

 

12,404

 

1,150

 

283

 

551

 

(297

)

Depreciation and amortization expense

 

84,201

 

85,584

 

36,225

 

6,116

 

11,111

 

6,509

 

 

48,147

 

94,584

 

85,584

 

36,225

 

6,116

 

11,111

 

Impairment of non-current assets

 

71,212

 

71,212

 

 

 

357

 

1,273

 

 

10,203

 

321,918

 

71,212

 

 

 

357

 

Exploration expense

 

10,934

 

10,934

 

 

 

 

 

 

30

 

7,925

 

10,934

 

 

 

 

Stock compensation, value of services

 

1,915

 

1,915

 

1,590

 

840

 

825

 

1,215

 

Share based compensation, value of services

 

2,524

 

4,100

 

1,915

 

1,590

 

840

 

825

 

Gain on sale of non-current assets

 

(925

)

(48,604

)

(7,335

)

(122,327

)

(3,004

)

(10,940

)

 

 

(790

)

(48,604

)

(7,335

)

(122,327

)

(3,004

)

Other income, net (2)

 

(2,704

)

 

 

 

 

 

Adjusted EBITDAX

 

$

116,442

 

$

126,373

 

$

52,594

 

$

9,223

 

$

17,093

 

$

9,993

 

 

$

47,863

 

$

64,781

 

$

126,373

 

$

52,594

 

$

9,223

 

$

17,903

 


(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.

 

5(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.



Table of Contents

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.

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. Future success therefore depends on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Further to this, our provedProved 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, and natural gas and NGL prices;

 

·                  compliance with governmental requirements; and

 

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

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

 

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.

6



Table of Contents

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

·general worldwide and regional economic and political conditions;

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

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

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

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

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

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

·weather conditions and natural disasters;

·domestic and foreign governmental laws, regulations and taxes;

·volatile trading patterns in commodities futures markets;

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

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

·technological advances affecting energy consumption; and

·the price and availability of alternative fuels.

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 66% of our estimated proved reserves as of December 31, 2014 was attributed to oil, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. Substantially all of our oil production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices.

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

·reducing our revenues, operating income and cash flows;

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

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

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

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

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

7



Table of Contents

·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, 2014, we have commodity price hedging agreements on approximately 13% of our expected Boe production for 2015. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil and natural gas that could materially and adversely affect our business and results of operations.

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

 

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil, and natural gas 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 our cash flows from operations and borrowings under ouravailable credit facilities, andadditional asset sales. However, our financing needssales, or through the issuance of debt and/or equity, which may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets.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 bankslenders to provide us with credit or additional borrowing capacity.

 

If our revenues or the amounts we can borrow under ouravailable credit facilities decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on favorable terms 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;

·                  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;

 

·                  fires;

8



Table of Contentsgeologic formations with abnormal pressures;

 

·                  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.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

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

 

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise and/or oil and natural gas prices decline, the return on our investment in these areas may not be

9



Table of Contents

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:

 

·                  the results of our exploration efforts;

·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; and

 

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

 

·                  additional due diligence;

·                  regulatory requirements and restrictions; and

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

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

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, 2014, 50,0622016, 24,740 net acres of our total acreage position waswere not held by production. For the acreage underlying such properties, if production in paying quantities is not established on units containing these leases, approximately 18,7605,726 net acres will expire in 2015,2017, and approximately 3,95119,014 net acres will expire in 2016 and approximately 27,351 net acres will expire thereafter.

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

·drilling results;

·oil and natural gas prices;

·the availability and cost of capital;

·drilling and production costs;

·the availability of drilling services and equipment;

·gathering system and pipeline transportation constraints; and

·regulatory approvals.

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

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.

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 88.5%87.1% of our total production for the year ended December 31, 2014.2016.

 

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.  Asreport, which could adversely affect business, results of December 31, 2014, approximately 62% of our total proved reserves were proved undeveloped.

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

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

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 oiloperations 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.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 proveddevelopment 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 may incurincurred impairment chargesof 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.

The present value of future which could have a material adverse effectnet 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 our ability to borrow under our credit facilities and which could adversely impact our resultsthe average of operations for the periodssales price on the first day of each month in which such charges are taken.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:

 

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



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

·                  the amount and timing of Contentsactual 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.  Due to the lack of available pipeline capacity in certain regions in which we operate, we have entered into firm transportation agreements for a portion of our production in order to secure guaranteed capacity on major pipelines. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under these agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

 

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

 

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

 

We are parties to a credit agreement with Morgan Stanley Energy Capital Inc. as administrative agent (the “Credit Agreement”), providingOur Credit Agreement provides for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and a term loansloan of $125 million with an accordion feature for up to $50 million in additional term loans subject to certain conditions (the “Term Loans”Loan”).  Our Revolving Facility had a borrowing base of $75$67 million as of May 14, 2015.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.

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.

 

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TableAt December 31, 2016, we had approximately $18.3 million of Contentsassets 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 facilities haveCredit Agreement has substantial restrictions and financial covenants that restrict our business and financing activities.

 

The operating and financial restrictions and covenants in our credit facilitiesCredit 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 agreements,Credit Agreement, our indebtedness may become immediately due and payable, the interest rates under our credit agreementsCredit 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 facilitiesCredit 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 under our credit facilities, and our lenders could foreclose upon critical assets, which could materiallyassets.  As a result, we may be unable to complete any further development of our properties and adverselyit may affect our business, results of operations and financial condition.ability to continue as a going concern. For a description of our credit facilities, please see Item 5.B. “Operating and Financial Review and Prospects—Liquidity and Capital Resources—Credit Facilities.”

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

We intend to fund our capital expenditures through a combination of cash flow from operations, borrowings under our credit facilities and, if necessary, debt or equity financings. Our ability to make the necessary capital investment to maintain or expand our asset base and develop oil and natural gas reserves will be impaired if cash flow from operations is reduced and external sources of capital become limited or unavailable. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:

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

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

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

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

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

 

Increased costs of capital could adversely affect our business.

 

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

 

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

 

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

 

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The 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.

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 andor 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 differencesdeficiencies 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

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all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

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

 

The conduct of exploration for, and production of, hydrocarbons may expose our staff to potentially dangerous working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. 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

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

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 likely willmay continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. Congressional action will be informed by a study commenced in 2011 byOn June 28, 2016, the EPA issued final pre-treatment standards prohibiting the disposal of wastewater pollutants from on the impactsshore unconventional oil and gas extraction facilities to publicly owned treatment works.  EPA’s regulation of hydraulic fracturing on drinking water resources,may result in our incurring additional costs to comply with final results anticipatedsuch requirements that may be significant in 2016. 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.

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.

 

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In addition, as discussed in more detail below, the EPA publishedfinalized its proposed 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. The EPA is expected to finalize the standards in late summer 2015.  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.

 

On January 14, 2015,In May 2016, the Obama Administration announced plansEPA issued final regulations intended to reduce methane emissions from the oil and gas industry, including throughout thesector 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 supply chain.equipment and processes in certain states and areas with smog problems. The methane developmentsregulations 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, some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

 

Certain federal income tax deductions currently available with respectTerrorist 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 exploration and developmentcould 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 eliminated as a resultfuture target of future legislation.

We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. Certain legislation introduced in Congress, if enacted into law, would make significant changes to U.S. tax laws, including, but not limited to, the elimination of certain key federal income tax incentives currently available toterrorist organizations. These developments have subjected oil and natural gas explorationoperations to increased risks. Any future terrorist attack on our facilities, customer facilities, the infrastructure depended upon for transportation of products, and, production companies. These or anyin some cases, those of other similar changes in federal tax lawsenergy companies, could defer or eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could materially and adversely affecthave a material adverse effect on our business, results of operations and financial condition.business.

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.

 

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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 legislation. The CFTC issued regulations settingto set position limits for certain futures, options and optionswap contracts in the major energy marketsdesignated physical commodities, including, among others, oil and for swaps that are their economic equivalents.natural gas. Certain bona fide hedging transactions arepositions would be exempt from these limits. Thethe position limits regulation was vacated byas currently proposed. It is not possible at this time to predict when the United States District Court forCFTC will finalize these regulations or whether the Districtproposed rules will be modified prior to becoming effective, so the impact of Columbia in September 2012. The CFTC has appealed the District Court’s decision and its Chairman has stated that the agencythose provisions on us is working on developing a new proposed rulemaking to address position limits. The CFTC has finalized other regulations, including critical rulemakings on the “swap” and “swap dealer” definitions, swap dealer registration, swap data reporting and mandatory clearing, among others.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 require us in connection with certain derivatives activitiesbe required to comply with the clearing and trade-executionexchange trading requirements (oror to take steps to qualify for an exemption to such requirements).requirements. In addition, new regulations may require us to comply withcertain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements althoughfor 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 regulations arerules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not finalizedqualify for the commercial end-user exception, we could be required to post initial or variation margin, which would impact liquidity and their applicationreduce our cash. This would in turn reduce our ability to us is uncertain at this time. The legislation may also require the counterpartiesexecute hedges to our derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislationreduce risk and any new regulations could: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 some derivative contracts, (including through requirements to post collateral that could adversely affect our available liquidity);

·materially alter the terms of some derivative contracts;

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

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

·potentially increase our exposure to less creditworthy counterparties.

If we reduce our use of derivatives as a result of the new legislationDodd-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. Increased volatility may make us less attractiveFurther, to certain typesthe extent our revenues are unhedged, they could be adversely affected if a consequence of investors. Finally, the Dodd-Frank Act was intended, in part,and implementing regulations is to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected.prices. Any of these consequences could adversely affecthave a material adverse effect on our financial condition andposition, results of operations.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.

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;

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·                  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.

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.“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;results or liquidity;

 

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

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

 

·                  changes in market valuations of similar companies;

 

·                  changes in our key personnel;

 

·                  potential acquisitions and divestitures;

·changes in financial estimates or recommendations by securities analysts;

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

 

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

 

·                  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; and

 

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

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

 

There is no establishedThe 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, foror the perception that these sales could occur, could cause the market price of our securitiesordinary 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 we cannot assure you that1,204,317,759 of our ordinary shares will be listed on any securities exchangebeing 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 that an active trading market will ever developadditional 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 any ofsale. 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 United States.future at such a time and place as we deem appropriate.

 

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

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.

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 are permitted to file less information with the SEC than a company that is notmay follow certain home country corporate governance practices instead of certain NASDAQ requirements.

NASDAQ listing rules allow for a foreign private issuer, orsuch 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 files asdiffer 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 domestic issuer.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 exempt from certain rules under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that impose disclosure requirements as well as procedural requirements for proxy solicitations under Section 14permitted to, and do follow home country practices in lieu of the Exchange Act. In addition,above requirements. Accordingly, our officers, directorsholders of ADSs and principalordinary shares may not have the same protections afforded to shareholders of companies that are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act. Moreover, we are not requiredsubject to file periodic reports and financial statements with the SEC as frequently or as promptly as a company that files as a domestic issuer whose securities are registered under the Exchange Act, nor are we generally required to comply with the SEC’s Regulation FD, which restricts the selective disclosure of material non-public information.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 beginning with our annual report for the year ending December 31, 2016, our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Although Section 404(b) of the Sarbanes-Oxley Act requires our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting, we have opted to rely on the exemptions provided in the JOBS Act, and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

Our first Section 404(a) assessment will take place beginning withmanagement has concluded that our annual report for the year endinginternal controls over financial reporting were effective as of December 31, 2016.  TheHowever, 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

21



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modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

 

If eitherIn addition, if we are unable to conclude that we have effective internal controls over financial reporting, or, at the appropriate time, our independent auditors are unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of the Sarbanes-Oxley Act, investors may lose confidence in our operating results, the price of 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.

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 our shares.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, 2014.2016. 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, 2015.2017. 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. Because the determination of our PFIC status is based on an annual determination that cannot be made until the close of a taxable year, and involves extensive factual investigation, including ascertaining the fair market value of all of our assets on a quarterly basis and the character of each item of income we earn, our U.S. counsel expresses no opinion with respect to our PFIC status. If we are a PFIC for any taxable year during which a U.S. holder (as defined in Item 10.E. “Additional Information—Taxation—U.S. Federal Income Tax Considerations”) holds an 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 boardBoard of directors,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 boardBoard of directorsDirectors 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 share priceshares 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.

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 boardBoard of directorsDirectors 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.

 

22



TableWe have broad discretion in the use of Contentsour 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.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 basinformation (“Eagle Ford”) and north central Oklahoma targeting the Mississippian and Woodford formations (“Mississippian/Woodford”).

 

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.

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. Therespectively for a purchase price included an initial cash payment of approximately $36 million and a commitment to drill four Eagle Ford wells. In addition, we have the option, at our sole discretion, to acquire the seller’s remaining working interests in Dimmit and Maverick Counties, Texas (including the seller’s interest in producing wells) for an additional $45 million (comprised of the seller’s choice of all cash or cash and ordinary shares, with certain restrictions).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 and two separate earn out payments due upon commencement of drilling ($7.7 million) and payout of the first six wells drilled on the acreage ($7.7 million). The term of the agreement is two years and provides a one-year extension for $500 per acre extended. This acreage is adjacent to our current acreage in McMullen County, Texas.

In March 2013, we completed our merger with Texon Petroleum Ltd. (“Texon”) through which we acquired our initial assets in the Eagle Ford, consisting of approximately 7,735 gross (7,336 net) acres at the time of acquisition. Shortly after the acquisition, we changed the name of Texon to Armadillo Petroleum Limited, and we similarly renamed Texon’s subsidiaries. The purchase price for the Texon acquisition was approximately $158.4 million, which involved the issuance of approximately 122,669,678 of our ordinary shares to Texon’s shareholders.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 the northwest North Dakota targeting the Bakken and Three-Forks formations (“Bakken”). The sale price of $14approximately $14.5 million included $10$10.0 million in cash and relief from a net liability owed to the buyer of $4approximately $4.5 million.

In November 2013, we sold our entire interest in an individual operated well and 622 net developed acres, located in the Phoenix prospect of the Bakken, for gross proceeds of approximately $4.3 million. In December 2013, we sold our interests in properties also located in the Phoenix prospect for $35.5 million. The assets sold included 77 gross (3.7 net) non-operated producing wells in McKenzie, Dunn and Mountrail Counties, North Dakota.

 

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, 20142016 our operational activities were conducted in the Eagle Ford and Mississippian/Woodford.

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Table of Contents

 

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, 2014,2016, we operated approximately 83%74% of our developed acreage with an average working interest of approximately 81%92% for Eagle Ford and 89% for Mississippian/Woodford with respect to such operated developed acreage.

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, 20142016 and 20132015 are based on the reserve reports prepared by Netherland SewellRyder 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, 20142016 and 2013,2015, please see Netherland Sewell’s reservethe 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,

 

 

As of December 31,

 

 

2014

 

2013

 

 

2016

 

2015

 

Estimated proved reserves:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

17,026

 

12,956

 

 

18,441

 

17,552

 

Natural gas (MMcf)

 

28,733

 

30,655

 

 

35,730

 

26,576

 

NGL (MBbls)

 

4,166

 

2,683

 

 

5,094

 

3,492

 

Total estimated proved reserves (MBoe)(1)

 

25,981

 

20,747

 

 

29,490

 

25,473

 

Estimated proved developed reserves:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

6,124

 

4,140

 

 

7,440

 

6,379

 

Natural gas (MMcf)

 

12,364

 

10,765

 

 

16,704

 

13,205

 

NGL (MBbls)

 

1,801

 

1,087

 

 

2,269

 

1,998

 

Total estimated proved developed reserves (MBoe)(1)

 

9,985

 

7,021

 

 

12,493

 

10,578

 

Estimated proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

10,903

 

8,815

 

 

11,001

 

11,173

 

Natural gas (MMcf)

 

16,369

 

19,890

 

 

19,026

 

13,371

 

NGL (MBbls)

 

2,365

 

1,596

 

 

2,825

 

1,494

 

Total estimated proved undeveloped reserves (MBoe)(1)(2)

 

15,996

 

13,726

 

 

16,997

 

14,895

 

PV-10 (in thousands)(3)

 

$

531,735

 

$

336,984

 

 

$

159,139

 

$

182,169

 

Standardized Measure (in thousands)

 

$

435,506

 

$

268,163

 

 

$

159,139

 

$

181,767

 

 


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

 

(2)                                 Reserves disclosed hereas of December 31, 2016 and 2015 are not the same reserves that are used to calculate depletion, depreciation and amortization.  See Note 3739 — Unaudited Supplemental Oil and Gas Disclosures within the Notes to the Consolidated Financial Statements for additional information.

 

(3)                                PV-10 ismay be considered a non-IFRS financial measure underas defined by the SEC regulations.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 ismay be considered a non-IFRS financial measure underas defined by the SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, we believe that the use of a pre-tax measure provides greater comparability of assets when evaluating companies, and that most other companies in the oil and gas industry calculate PV-10

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on the same basis. Investors should be cautioned that neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our proved reserves.

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

 

 

As of December 31,

 

 

As of December 31,

 

 

2014

 

2013

 

 

2016

 

2015

 

PV-10 of proved reserves

 

$

531,735

 

$

336,984

 

 

$

159,139

 

$

182,169

 

Present value of future income tax discounted at 10%

 

(96,229

)

(68,821

)

 

 

(402

)

Standardized Measure

 

$

435,506

 

$

268,163

 

 

$

159,139

 

$

181,767

 

 

Proved Undeveloped Reserves

 

At December 31, 2014,2016, our proved undeveloped reserves were approximately 15,99616,997 MBoe, an increase of approximately 2,2702,102 MBoe over our December 31, 20132015 proved undeveloped reserves estimate of approximately 13,72614,895 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 approximately 4,0883,138 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves during 2014, a decrease of approximately 3,996 MBoe due to the sale of our interests in the Denver-Julesburg assets and Bakken prospects and an increase of approximately 10,904 MBoe due to the addition of proved undeveloped locations offset by downward revisions to previous estimates of 550 MBoe. The addition of proved undeveloped locations was attributable to Eagle Ford and Mississippian/Woodford, which were 7,335 MBoe and 3,569 MBoe respectively.reserves.   The revisions to previous estimates were primarily attributable solely to the Mississippian/Woodford, which was a decrease of 942 Mboe, offset by an increase to Eagle Ford of 392 MBoe.Ford.  During the year ended December 31, 2014,2016, we incurred capital expenditures of approximately $103.3$37.8 million to convert proved undeveloped reserves to proved developed reserves. The majorityremainder 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

 

Our proved reservesThe Company’s reserve estimates are calculated by Ryder Scott as of December 31, 20142016 in accordance with SEC guidelines.  The reserve estimates are based on, and 2013, have been independentlyfairly represent, information, supporting documentation prepared by, Netherland Sewell, which was founded in 1961 and performs consulting petroleum engineering servicesor under Texas Boardsupervision of, Professional Engineers Registration No. F-2699. Within Netherland Sewell, the technical person primarily responsible for the estimates set forth in the reserves reports included or incorporated herein is Mr. Neil H. Little. Stephen E. Gardner. Mr. LittleGardner is a Licensed Professional Engineer in the StateStates of Colorado (Colorado No. 44720) and Texas (No. 117966)(Texas No. 100578) with over 1210 years of practical experience in petroleum engineering studiesestimation and over 5 years of practical experience in evaluation of petroleum reserves.  Mr. Little has been practicing consulting petroleum engineering at NSAI since 2011. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering. Mr. LittleGardner 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. DuringCurrent 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 was established to assist the Board of directors with monitoring i)(i) the integrity of our oil, natural gas, and natural gas liquids reserves, ii)(ii) the independence, qualifications and performance of our independent reservoir engineers, and iii)(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.

 

Within our technical team, the person primarily responsible for overseeing the preparation of the reserve estimates is Mr. David Ramsden-Wood,Ms. Trina Medina, Vice President of Reservoir Engineering, is responsible for oversight of the internal reservoir engineering department and Business Development. Mr. Ramsden-Wood is a Licensed Professional Engineer in Alberta, Canada (No. 71507) with over 15 yearspreparation of practical experience focusedthe reserve estimates.  Ms. Medina’s biography and qualifications can be found on reservoir engineering. He graduated from the University of Calgary with a Bachelor of Science degree in Engineering (Chemical) and Cornell University and Queen’s University with a Masters of Business Administration degree.page 61.

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Table of Contents

Acreage

 

We had the following developed, undeveloped and total acres for each of our operating areas as of December 31, 2014:2016:

 

 

Developed

 

Undeveloped

 

Total

 

 

Developed

 

Undeveloped

 

Total

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Eagle Ford (1)

 

6,727

 

5,659

 

31,968

 

20,501

 

38,695

 

26,160

 

 

12,219

 

10,267

 

38,411

 

32,509

 

50,630

 

42,776

 

Mississippian/Woodford

 

17,965

 

11,374

 

55,452

 

29,563

 

73,417

 

40,937

 

 

22,713

 

15,568

 

7,047

 

2,940

 

29,760

 

18,508

 

All properties

 

24,692

 

17,033

 

87,420

 

50,064

 

112,112

 

67,097

 

 

34,932

 

25,835

 

45,458

 

35,449

 

80,390

 

61,284

 

 


(1)         Includes 5,4181,566 net acres located in the Georgetown formation.Texas, targeting non-Eagle Ford formations.

 

Production and Pricing

 

 

Year ended
December 31,

 

Six-month
period ended
December 31,

 

Year ended
June 30,

 

 

Year ended December 31,

 

 

2014(1)

 

2013

 

2012

 

2012

 

 

2016

 

2015

 

2014(1)

 

Net Sales Volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

1,675.1

 

827.4

 

195.5

 

337.7

 

 

1,412.5

 

1,829.0

 

1,675.1

 

Natural gas (MMcf)

 

1,803.0

 

934.2

 

260.4

 

370.3

 

 

2,940.7

 

2,580.7

 

1,803.0

 

NGL (MBbls)(2)

 

268.0

 

95.8

 

 

 

 

331.6

 

393.2

 

268.0

 

Oil equivalent (MBoe)

 

2,244.0

 

1,079.0

 

238.9

 

399.4

 

 

2,234.2

 

2,652.3

 

2,244.0

 

Average daily volumes (Boe/d)

 

6,147

 

2,956

 

1,298

 

1,091

 

 

6,104

 

7,267

 

6,147

 

Average Sales Price, before derivative settlements:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

86.56

 

$

95.92

 

$

85.88

 

$

82.82

 

 

$

40.56

 

$

45.35

 

85.56

 

Natural gas (per Mcf)

 

3.42

 

2.97

 

3.59

 

4.92

 

 

1.68

 

1.83

 

3.42

 

NGL (per MBbls)(2)

 

32.24

 

33.45

 

 

 

 

13.20

 

11.50

 

32.24

 

Average equivalent price (per Boe)

 

71.22

 

79.10

 

74.19

 

74.59

 

 

29.81

 

34.76

 

71.22

 

Expenses (per Boe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

6.03

 

$

11.23

 

$

9.19

 

$

7.76

 

 

$

5.79

 

$

6.96

 

6.03

 

Production tax expense

 

3.10

 

5.80

 

7.90

 

8.15

 

 

1.88

 

2.28

 

3.10

 

Lease operating and production tax expenses

 

9.13

 

17.03

 

17.09

 

15.91

 

 

7.67

 

9.24

 

9.13

 

General and administrative expense, including employee benefits

 

6.92

 

14.18

 

24.32

 

17.18

 

 

5.42

 

6.48

 

6.92

 

Depreciation and amortization expense

 

38.15

 

33.57

 

25.60

 

27.82

 

 

21.55

 

35.66

 

38.15

 

 


(1)                                 Production volumes for the year ended December 31, 2014 includeincluded 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.

(2)Prior to the year ended December 31, 2013, our NGL sales were insignificant as compared to our overall gas sales See Item 4.A. “Information on Sundance — History and as such, were included in our natural gas sales.

26



Table of ContentsDevelopment — 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, 2014

 

December 31, 2013

 

 

 

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

 

1,280

 

866

 

104

 

1,528

 

4,187

 

409

 

320

 

38

 

500

 

1,371

 

Mississippian/Woodford

 

268

 

678

 

142

 

523

 

1,434

 

108

 

247

 

35

 

184

 

503

 

Denver-Julesburg(1)

 

104

 

248

 

20

 

166

 

454

 

121

 

296

 

14

 

185

 

506

 

Bakken(2)

 

23

 

11

 

2

 

27

 

72

 

189

 

71

 

9

 

210

 

576

 

Total

 

1,675

 

1,803

 

268

 

2,244

 

6,147

 

827

 

934

 

96

 

1,079

 

2,956

 

 

 

Six-month period ended

 

Year ended

 

 

 

December 31, 2012

 

June 30, 2012

 

 

 

Oil

 

Natural
Gas

 

Oil
Equivalent

 

Average
Daily
Volume

 

Oil

 

Natural
Gas

 

Oil
Equivalent

 

Average
Daily
Volume

 

 

 

(MBbls)

 

(MMcf)

 

(MBoe)

 

(Boe/d)

 

(MBbls)

 

(MMcf)

 

(MBoe)

 

(Boe/d)

 

Eagle Ford

 

 

 

 

 

 

 

 

 

Mississippian/Woodford

 

10

 

28

 

15

 

82

 

4

 

 

4

 

10

 

Denver-Julesburg

 

29

 

137

 

52

 

281

 

33

 

202

 

66

 

181

 

Bakken

 

156

 

95

 

172

 

935

 

301

 

168

 

329

 

900

 

Total

 

195

 

260

 

239

 

1,298

 

338

 

370

 

399

 

1,091

 

 

 

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

 

 

 

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

 

 


(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.”

 

(2)(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, 2014:2016:

 

 

 

Oil Wells

 

Natural Gas
Wells

 

Total Wells

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Eagle Ford

 

77

 

53.8

 

 

 

77

 

53.8

 

Mississippian/Woodford

 

66

 

28.5

 

 

 

66

 

28.5

 

Total

 

143

 

82.3

 

 

 

 

 

143

 

82.3

 

27



Table of Contents

 

 

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, 20142016, 2015 and 2013, the six-month period ended December 31, 2012 and the fiscal year ended June 30, 2012.2014.

 

 

 

Year ended

 

Six-month
period ended

 

Year ended

 

 

 

December 31,
2014

 

December 31,
2013

 

December 31,
2012

 

June 30,
2012

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

113

 

64.8

 

102

 

58.6

 

37

 

12.3

 

77

 

11.3

 

Natural Gas

 

 

 

 

 

 

 

 

 

Dry

 

2

 

2.0

 

 

 

 

 

 

 

 

 

Exploratory Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

 

 

 

 

 

 

 

 

Natural Gas

 

 

 

 

 

 

 

 

 

Dry

 

3

 

3.0

 

 

 

 

 

 

 

Total Wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

113

 

64.8

 

102

 

58.6

 

37

 

12.3

 

77

 

11.3

 

Natural Gas

 

 

 

 

 

 

 

 

 

Dry

 

5

 

5.0

 

 

 

 

 

 

 

 

 

118

 

69.8

 

102

 

58.6

 

37

 

12.3

 

77

 

11.3

 

 

 

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

 

Present Activities

 

The following table describes wells being drilled or awaiting completion or production testing as of December 31, 2014.2016.

 

 

Development
Wells

 

Exploratory
Wells

 

Total Wells

 

 

Development
Wells

 

Exploratory
Wells

 

Total Wells

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Eagle Ford

 

19

 

10.6

 

 

 

19

 

10.6

 

 

1

 

1.0

 

 

 

1

 

1.0

 

Mississippian/Woodford

 

5

 

3.1

 

 

 

5

 

3.1

 

 

1

 

0.9

 

 

 

1

 

0.9

 

Total

 

24

 

13.7

 

 

 

24

 

13.7

 

 

2

 

1.9

 

 

 

2

 

1.9

 

 

Principal Customers and Marketing

 

For the year ended December 31, 2014,2016, purchases by one of our customerscustomer accounted for 65%over 10% of our total sales revenues. These customers purchaserevenues: 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.”

 

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Table of Contents

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.

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 properties forproducing oil and natural gas productionproperties 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 disposaldisposing 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.

 

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Table of Contents

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.

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. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

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

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

GatheringOnshore gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters.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. To the extent that FERC issues an order that reclassifies transmission facilities as gathering facilities and, depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, non-discriminatorynondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

 

Intrastate natural gas transportation and facilities areis also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC.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 varyvaries 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.

 

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Table of Contents

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.

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.

 

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

 

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. The RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes. The RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and cleanup requirements. No such effort has been successful to date.

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

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requirements, or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects.

 

In August 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines (“RICE NESHAP”). The rule may require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on a portion of our engines located at major sources of hazardous air pollutants and all our engines over a certain size regardless of location, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On January 14, 2013, the EPA signed final revisions to the 2010 RICE NESHAP to reflect new technical information submitted by stakeholders and in response to lawsuits and administrative petitions. On January 30, 2013 the final RICE NESHAP rule was published in the Federal Register with an effective date of April 1, 2013. Several petitions requesting administrative reconsideration of the 2013 RICE NESHAP were received by the EPA. 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.

The EPA also issued new CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard for volatile organic chemicals (“VOCs”) and sulfur dioxide (“SO2”) emissions with expanded applicability to natural gas operations, as well as a new air toxics standard. These rules create significant new technology requirements for controlling wellhead emissions from our operations. The EPA 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. The UNFCCC did not establish any substantive obligations for parties to reduce GHGs. The subsequent treaty,In December 2015 the Kyoto Protocol, did establish binding GHG targets for developed countries, but the United States did not ratify it. The current focus is oninternational community agreed upon a new international agreementclimate change treaty, known as the Paris Agreement.  The U.S. committed to  replace the Kyoto Protocol.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 in 2020, remains under negotiation, but it is expected to be signed in Paris in December 2015. The new agreement is expected to incorporateincorporates 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 CAAfederal Clean Air Act has occurred over the past several years,years.  In particular, the Clean Power Plan regulation under the Clean Air Act, which would likely representregulates carbon pollution from existing fossil fuel-fired power plants represents a significant portion of the United States’ reductions proposed under the Paris agreement. AnyAgreement. 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. In December 2009, the EPA published its finding that certain emissions of GHGs presented an endangerment to human healthfrom stationary and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. Consequently, themobile 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 titleTitle V permit on the basis of greenhouse gas

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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”). The EPA is currently evaluating the implications of the decision and awaiting further action by the U.S. Courts in terms of whether additional rulemaking is necessary.

 

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 January 8, 2014,August 3, 2015, the EPA publishedfinalized its proposed 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 June 2, 2014,August 3, 2015, the EPA released the final Clean Power Plan, which is a proposed rule relatedregulation designed to reduce carbon pollution from existing source performance standards forfossil fuel-fired power plants and settingplants.  In the Clean Power Plan, the EPA sets forth state-specific emission targets. States havetargets 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 proposed rule,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. The EPA is expected to finalize the standards for new, modified and existing power plants in late summer 2015. 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.

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 January 14, 2015,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 announced plansAdministration’s commitment to reduce methane emissions from the oil and gas industry,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.

 

Several of theThe EPA’s GHG rules are being reviewed pursuant to President Trump’s executive order and many are beingchallenged in court proceedings and dependingproceedings. Depending on the outcome of such proceedings, suchthe 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, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, 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.

 

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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.

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 2012, the Occupational Safety and Health Administration (“OSHA”)March 2016, OSHA issued a hazard alertfinal rule related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids.  The alert stated thatkey 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 canmay be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at drill sites may lead to increased regulation and enforcement or related tort claims by our employees. We believe that we are in substantial complianceImplementation of engineering and workplace controls to comply with all applicable laws and regulations relating to worker health and safety.the rule may require significant investment.

 

Hydraulic Fracturing

 

The federal Safe Drinking Water Act (“SDWA”)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

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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. A draft report was expected to be available for public comment and peer review in 2014, but has not yet been released. 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, which remain under review by the White House’s Office of Management and Budget.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.

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

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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.

C.Organizational Structure

 

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

 

GRAPHIC

 

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, 2014,2016, our Eagle Ford properties consisted of approximately 38,69550,630 gross (26,160(42,776 net) acres that are primarily located in McMullen, Dimmit and DimmitAtascosa County, Texas, in the volatile oil window of the Eagle Ford trend.

 

During 2014, we were running a two-rig horizontal development program, with one rig being released in December 2014. As ofFor the year ended December 31, 2014, we were running a one-rig horizontal development program and, during the month of December 2014,2016, we had average net daily production of approximately 8,1775,389 Boe/d from our Eagle Ford properties. For the year ended December 31, 2014, we had average net daily production of approximately 4,187 Boe/d(including flared natural gas) from these properties.properties, with an exit rate of 6,601 Boe/d.  During 2014,2016, we spent $248.8$33.2 million on drilling and completion activities, completing a total of 5417 gross (36.7(9.2 net) Eagle Ford horizontal wells, and $4.3 million on facilities and infrastructure.   As of which 26.1December 31, 2016, we had 1.0 net wells are producing and 10.6 net wells arewell awaiting completion. In 2015, we expectOur 2017 capital program is expected to spend approximately $65 million to $80 millionbe funded with cash on developmenthand, cash flow from operations and production assets.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, 2014,2016, our properties in the Mississippian/Woodford consisted of approximately 73,41729,760 gross (40,937(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.

 

During 2014, we were running a two-rig horizontal development program with those rigs being released in June and December 2014, respectively. As ofFor the year ended December 31, 2014, we did not have any drilling rigs running. During 2014, we spent $81.8 million drilling a total of 45 gross (19.7 net) Mississippian/Woodford wells, of which 16.6 net wells are producing and 3.1 net wells are drilling or awaiting completion as of December 31, 2014. During the month of December 2014,2016, we had average net daily production of approximately 1,257 Boe/d from our Mississippian/Woodford properties. For the year ended December 31, 2014, we had average net daily production of approximately 1,434715 Boe/d from these properties.  In 2015,During 2016, we expect to spend approximately $5spent $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 production assets.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.

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Item 4A.  Unresolved Staff Comments

 

Not applicable.None.

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, 2014,2016, our operational activities arewere 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, 2014,2016, we operated approximately 83%74% of our developed acreage with an average working interest of approximately 81%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 twoseveral years, with the divestiture of our interest in properties located in the South Antelope field of the Williston Basin, North Dakota and our dispositions of Denver-Julesburg assets and the remaining Bakken assets in September 2012 and July 2014, respectively, andas well as the acquisitionanticipated divestiture of Texonour Mississippian/Woodford assets, expected to close in March 2013, through whichMay 2017.  In addition, we acquired the majority ofhave continued to increase our Eagle Ford assets.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 fewseveral 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.

 

Netherland SewellRyder Scott estimated our proved reserves to be approximately 26.029.5 MMBoe as of December 31, 2014,2016, of which approximately 66%63% are oil, approximately 18%20% are natural gas and approximately 16%17% NGLs, with a PV-10 of approximately $531.7$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;

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·                  lease operating and production expenses;

 

·                  general and administrative expenses; and

 

·                  Adjusted EBITDAX.

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.continue into 2017. For example, the NYMEX-WTI oil price ranged from a high of $107.95$54.01 per Bbl to a low of $43.39$26.19 per Bbl during 2014 and through the first quarter of 2015.2016. Our realized price per Bbl varies by basin and is based uponprimarily 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.

 

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Natural gas prices have historically been extremely volatile, and we expect this volatilitygas prices to continue. For example, theremain depressed into 2017. The NYMEX-Henry Hub natural gas price ranged from a high of $6.00$3.80 per MMBtu to a low of $2.83$1.49 per MMBtu during 20142016 and through the first quarter of 2015.2017. 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.

Commodity Derivative Contracts.  We have adopted a commodity derivative policy designed to minimize volatility in our cash flows from changes in commodity prices. Our current policy is to hedge up to 80%at least 50% of forecastedour proved developed producing production, but not more than 25% of total estimated productionreserves through 2019 and for the next five years. Should we reducea rolling 36 month period thereafter, as required by our estimates of future production to amounts that are lower than our commodity derivative volumes, we will reduce our positions as soon as practical. Our credit facilities prohibit us from entering into hedging arrangements for more than 85% of our projected production of oil and natural gas.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 and tax of 0.8125%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, County,Dimmit and Atascosa Counties, Texas assesses an annual ad valorem tax which currently is approximately 1.87%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 imposed during the earlier ofavailable for the first 48 months of sales or until(applicable to wells spud prior to July 1, 2015). For vertical and horizontal wells completed after July 1, 2015 the well has achieved payout.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 includinginclude 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. StockShare based compensation expense, including stock options and 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 options and restricted share units at the grant date. Administrative expenses include overhead costs, such as maintaining our headquarters, costs of managing our production and development operations, audit and other fees for professional services, and legal compliance.

 

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

 

Adjusted EBITDAX

 

Adjusted EBITDAX is a supplemental, non-IFRS financial measure and is defined as our earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain/(loss) on sale of non-current assets, exploration expense, share-based compensation, and income and gains and losses on commodity hedging, net of settlements of commodity hedging.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.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.  In addition, because Adjusted EBITDAX is not an IFRS measure, it may not necessarily be comparable to similarly titled measures employed by other companies. See Item 3.A. “Key Information—Selected Financial Data—Adjusted EBITDAX” for a reconciliation between Adjusted EBITDAX and net income before income tax expense.

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 probablyprobable oil, natural gas and NGL reserves, which are used in calculating depreciation, depletion and amortization of development and production assets’ costs, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated costs and timing of cash outflows underlying restoration provisions. Oil, natural gas and NGL reserve estimates, and therefore calculations based on such reserve estimates, are subject to numerous inherent uncertainties, the accuracy of which, is a function of the quality and quantity of available data, the application of engineering and geological interpretation and judgment to available data and the interpretation of mineral leaseholds and other contractual arrangements, including adequacy of title, drilling requirements and royalty obligations. These estimates also depend on assumptions regarding quantities and production rates of recoverable oil, natural gas and NGL reserves, commodity prices, timing and amounts of development costs and operating expenses, all of which will vary from those assumed in our estimates. Other significant estimates are involved in determining impairments of exploration and evaluation expenditures, fair values of derivative assets and liabilities, stock-basedshare 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 maeriallymaterially 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, 2014.2016.

 

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.

 

An impairment loss is recognized inUnder the income statement whenevervalue-in-use method, the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount.

The recoverable amount of an assetthe CGU to which the assets belong is then estimated based on the greaterpresent value of its fairfuture 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 less costs to sell and its value-in-use. In assessing value-in-use, an asset’s estimatedof future cash flows are discountedis most sensitive to their present value using a pre-taxestimates of future oil price and discount rate that reflects current market assessmentsrates. A change in the modeled assumptions in isolation could materially change the recoverable amount. However, due to the interrelated nature of the time valueassumptions, 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 moneyupsides, 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 risks specificchange 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.

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 assets/CGUs. In addition, we consider market data relatedfuture 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 recent transactionsthe consolidated financial statements for similar assets.

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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.

 

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 December 31, 2014 or 2013.

Exploration and Evaluation Expenditures

 

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

 

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

 

The carrying amounts of our exploration and evaluation assets are reviewed at each reporting date, in conjunction with the impairment review process referred to in Note 1(f)1 to our consolidated financial statements for the year ended December 31, 20142016 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.

Derivative Financial Instruments

 

We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our board directors.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 amortization (depletion), and depreciationdepletion 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

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commercial viability of producing the reserves. For purposes of the calculation of amortization (depletion), and depreciationdepletion expense and the assessment of possible impairment of assets, other than pricing assumptions discussed in Note 1719 to the Consolidated Financial Statements, management prepares reserve estimates that conform to the definitions contained in Rule 4-10(a) of Regulation S-X. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange ratesdevelopment 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.

 

Impairment of Non-Financial Assets

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

At December 31, 2014, future NYMEX strip prices, adjusted for basis differentials, were applied in 2015 and gradually increased through 2016 to $75/bbl in 2017 and thereafter. 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.

At December 31, 2014, we reassessed the carrying amount of its non-current assets for indicators of impairment in accordance with our accounting policy. Due to the change in the oil pricing environment at year-end, the Company performed an impairment analysis for development and production assets which resulted in an impairment charge of $71.2 million. See Note 17 to the consolidated financial statements for additional information.

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, 20142016 and 2013,2015, 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.

 

44Revenue Recognition



Table of Contents

 

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.

Recently Issued Accounting Standards

 

IFRS 15—Revenue from Contracts with Customers

In May 2014, IFRS 15 was issued which establishes a single comprehensive model for entitiesFor further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to use in accounting for revenue arising from contracts with customers. Specifically, the standard introduces a 5-step approach to revenue recognition:

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

Step 2: Identify the performance obligations“Note 1- Statement of Significant Accounting Policies” footnote in the contracts.

Step 3: Determine the transaction price.

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

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

Under 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 January 1, 2017.  Management is currently assessing the impact of the new standard and plans to adopt the new standard on the required effective date.

IFRS 9 – Financial Instruments

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

 

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, 2014.2016.

 

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, 20142016 Compared to the Year Ended December 31, 20132015

 

Revenues and Sales Volume.  The following table provides the components of our revenues for the years ended December 31, 20142016 and 2013,2015, as well as each period’s respective sales volumes:

 

 

Year ended
December 31,

 

 

 

 

 

 

2014

 

2013

 

Change in $

 

Change as %

 

 

Year ended
December 31,

 

 

 

(audited)

 

(audited)

 

 

 

 

 

 

2016

 

2015

 

Change in $

 

Change as %

 

Revenue (In $ ‘000s)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales

 

$

144,994

 

$

79,365

 

$

65,629

 

82.7

 

 

$

57,296

 

$

82,949

 

$

(25,653

)

(30.9

)

Natural gas sales

 

6,161

 

2,774

 

3,387

 

122.1

 

 

4,937

 

4,720

 

217

 

4.6

 

NGL sales

 

8,638

 

3,206

 

5,432

 

169.5

 

 

4,376

 

4,522

 

(146

)

(3.2

)

Product revenue

 

$

159,793

 

$

85,345

 

$

74,448

 

87.2

 

 

$

66,609

 

$

92,191

 

$

(25,582

)

(27.7

)

 

45



Table of Contents

 

Year ended December 31,

 

Change in

 

 

 

 

2014

 

2013

 

Volume

 

Change as %

 

 

Year ended
December 31,

 

 

 

 

 

 

(audited)

 

(audited)

 

 

 

 

 

 

2016

 

2015

 

Change in Volume

 

Change as %

 

Net sales volumes:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

1,675,078

 

827,432

 

847,646

 

102.4

 

 

1,412,475

 

1,828,955

 

(416,480

)

(22.8

)

Natural gas (Mcf)

 

1,803,000

 

934,200

 

868,800

 

93.0

 

 

2,940,715

 

2,580,682

 

360,033

 

14.0

 

NGL (Bbls)

 

267,952

 

95,821

 

172,131

 

179.6

 

 

331,622

 

393,211

 

(61,589

)

(15.7

)

Oil equivalent (Boe)

 

2,243,529

 

1,078,953

 

1,164,576

 

107.9

 

 

2,234,216

 

2,652,280

 

(418,064

)

(15.8

)

Average daily production (Boe/d)

 

6,147

 

2,956

 

3,191

 

107.9

 

 

6,104

 

7,267

 

(1,163

)

(16.0

)

 

Barrel of oil equivalent (Boe) and average net daily production (Boe/d).  Sales volume increaseddecreased by 1,164,576418,064 Boe (107.9%(16%) to 2,243,5292,234,216 Boe (6,147(6,104 Boe/d) for the year ended December 31, 20142016 compared to 1,078,9532,652,280  Boe (2,956(7,267 Boe/d) for the prior year primarily due to successfully bringing online 88 gross (50.1 net) producing wells primarilyflush 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 Eagle Ford and Mississippian/Woodford Formations.second half of the year, resulting in less than a full year of production from those wells.

 

The Eagle Ford contributed 4,1875,389 Boe/d (68.1%(88%) of total sales volume during the year ended December 31, 20142016 compared to 1,3716,167 Boe/d (46.4%(85%) during the prior year. Mississippian/Woodford contributed 1,433715 Boe/d (23.2%(12%) of total sales volume during the year ended December 31, 20142015 compared to 5031,100 Boe/d (17.0%(15%) during the prior year. Our sales volume is oil-weighted, with oil representing 75%63% and 77%69% of total sales volume for the year ended December 31, 20142016 and 2013,2015, respectively.

 

Oil sales.  Oil sales increaseddecreased by $65.6$25.7 million (82.7%(31%) to $145.0$57.3 million for the year ended December 31, 20142016 from $79.4$82.9 million for the prior year. The increasedecrease in oil revenues was the result of increased oil production volumes ($81.3 million) offset by athe decrease in product pricing ($15.76.8 million). Oil, with an additional decrease due to oil production volumes increased 102.4% to 1,675,078 Bbls for the year ended December  31, 2014 compared to 827,432 Bbls for the prior year.($18.9 million).  The average price we realizedrealised on the sale of our oil decreased by 9.8%11% to $86.56$40.56 per Bbl for the year ended December 31, 20142016 from $95.92$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.

Natural gas sales.  Natural gas sales increased by $3.4$0.2 million (122.1%(5%) to $6.2$4.9 million for the year ended December 31, 20142016 from $2.8$4.7 million for the prior year. The increase in natural gas revenues was primarily the result of increased production volumes ($2.60.7 million) and improved, offset by lower product pricing ($0.80.4 million).  Natural gas production volumes increased 868,800360,033 Mcf (93.0%(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.

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.

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 compared to 934,200 Mcf for the prior year.31. 2014. The average price we realized on the sale of our natural gas increaseddecreased by 15.1%52% to $3.42$1.83 per Mcf for the year ended December 31, 20142015 from $2.97$3.42 per Mcf for the prior year.2014.

 

NGL sales. NGL sales increaseddecreased by $5.4$4.1 million (169.5%(47.6%) to $8.6$4.5 million for the year ended December 31, 20142015 from $3.2$8.6 million for the same period in prior year.2014. The increasedecrease in NGL revenues was primarily the result of worse product pricing ($8.2 million), offset by increased production volumes in the Eagle Ford and the Mississippian/Williston.($4.0 million). NGL production volumes increased 172,131125,259  Bbls (179.6%(46.7%) to 267,952393,211  Bbls for the year ended December 31, 20142015 compared to 95,821267,952 Bbls for the prior year.in 2014. The average price we realized on the sale of our natural gas liquids decreased by 3.6%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 from $33.45 per Bbl for the prior year.2014.

 

 

Year ended
December 31,

 

 

 

 

 

Selected per Boe metrics

 

2014

 

2013

 

Change

 

Percent

 

 

 

(audited)

 

(audited)

 

 

 

 

 

Total oil and natural gas revenues, before derivative settlements

 

$

71.22

 

$

79.10

 

$

(7.88

)

(10.0

)

Lease operating expenses

 

(6.03

)

(11.23

)

(5.21

)

(46.4

)

Production taxes

 

(3.10

)

(5.80

)

(2.70

)

(46.5

)

Lease operating and production tax expenses

 

(9.13

)

(17.03

)

(7.90

)

(46.4

)

Depreciation and amortization

 

(38.15

)

(33.57

)

4.58

 

13.6

 

General and administrative expense

 

(6.92

)

(14.18

)

(7.26

)

(51.2

)

Total profit margin

 

17.02

 

14.32

 

2.70

 

18.9

 

 

 

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

)

 

Lease operating expenses.LOE.  Our lease operating expenses (LOE)LOE increased by $1.4$4.9 million (11.6%(36.4%) to $13.5$18.4 million for the year ended December 31, 20142015 from $12.1$13.5 million for the same period in the prior year but decreased $5.21and increased $0.93 per Boe to $6.03$6.96 per Boe from $11.23$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 decreaseincrease in LOE per BoeBOE is primarily due to economies of scale andcosts associated with treating the implementation of several cost saving initiatives in our field operations such as replacing contract lease operators with Company employees and reducing total field head count per well.

46



Table of Contentsgas.

 

Production taxes.  Our production taxes increaseddecreased by $0.7$0.9 million (11.2%(13.2%) to $7.0$6.0 million for the year ended December 31, 20142015 from $6.3$7.0 million for the prior year but as a percent of revenue decreased 290 basis pointsincreased to 4.4%6.7% from 7.3%4.4%. The decrease in production taxes is due to a decrease in revenue.  The increase in production taxes as a percentpercentage of revenue is primarily the result of the sale of our North Dakota and Colorado assets, which are higher production tax rate jurisdictions, and increasing our investment in Texas and Oklahoma, which are lower production tax rate jurisdictions, as well as an adjustment for lower than anticipated ad valorem taxes.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.

 

Depreciation and amortization expense, including depletion.DD&A.  Our depreciation and amortizationDD&A expense increased by $49.4$9.0 million (136.3%(10.5%) to $85.6$94.6 million for the year ended December 31, 20142015 from $36.2$85.6 million for the prior year, and increased $4.58but decreased $2.49 per Boe to $38.15$35.66 per Boe from $33.57$38.15 per Boe.  The increase reflects our increase in production, (107.9%), an increase in ouroffset by a lower depletable asset base subjectdue to amortization as a result of our acquisitionprior-year and development activity, and increased completion costs caused by high-demand for completion services and a shortage of trucks able to transport frac sand and resultant higher trucking rates.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 decreasedincreased by $1.1$4.0 million (19.0%(80%) to $8.9 million for the year ended December 31, 2015 from $5.0 million for the year ended December 31, 2014 from $6.12014. 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, 2013. This decrease is primarily a result of the capitalization of $4.5 million, an increase of amounts capitalized in 2013 by $1.6 million, in overhead costs, including salaries and wages, directly attributable to the exploration, acquisition and development of oil and gas properties. Included in the employee benefits expense for the fiscal year ended December 31, 2014 is stock-based compensation expense of $1.9 million for options issued to officers, management and employees, an increase of $0.3 million (20.4%) compared to $1.6 million for the twelve-month period ended December 31, 2013.

Administrative expense increased by $1.3 million (15.2%) to2015 from $10.5 million for the year ended December 31, 2014 from $9.2 million for the year ended December 31, 2013.2014. This increasedecrease was primarily due to an increasea decrease in general legal and professional fees.

 

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

Impairment expense.  We recorded impairment expense of $71.2$321.9 million for the year ended December 31, 20142015 on the Company’s developmentoil and productiongas assets that are located in the Mississippian/Williston and the Eagle Ford as the recoverable amount was less than the carrying value primarily as a result of lower commodity pricing.  No impairment was necessary on the Company’s exploration and evaluation assets.  See Note 1719 of the Notes to the Consolidated Financial Statements for further discussion.

 

Exploration expense. We The Company incurred exploration expense of $10.9$7.9 million for the year ended December 31, 20142015 on three gross (and net)two unsuccessful exploratory wells in the Mississippian/Williston.wells.  The Company did not drill anyincurred exploratory expense of $10.9 million in 2014 related to three unsuccessful exploratory wells in the prior year.wells.

 

Finance costs, net of interest income and amounts capitalized.capitalized.  Finance costs, net of amounts capitalizedcapitalised to exploration and development, increased by $0.7$8.7 million to $0.5$9.4 million for the year ended December 31, 20142015 as compared to net interest income of $0.2$0.7 million in the prior year. The increase primarily relates to an increase in amortization of deferred financing fees and additional interest incurred on undrawn funds.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 $11.6$4.3 million to an $11.0a $15.3 million gain for the year ended December 31, 20142015 as compared to the prior year. The gain on commodity hedging consisted of $9.7$2.9 million of unrealized gains on commodity derivative contracts and $1.3$12.4 million of realized gains on commodity derivative contracts.

The Company had the following open contracts at December 31, 2014:

Contract Type

Counterparty

Basis

Quantity/mo

Strike Price

Term

Collar

Wells Fargo

WTI

2,000 BBL

$75.00/$98.65

1/1/15 –12/31/15

Collar

Shell Trading US

LLS

3,000 BBL

$85.00/$101.05

1/1/15 –12/31/15

Collar

Wells Fargo

WTI

2,000 BBL

$80.00/$97.00

1/1/15 –12/31/15

Collar

Wells Fargo

WTI

1,000 BBL

$80.00/$94.94

1/1/15 –12/31/15

Swap

Wells Fargo

LLS

2,000 BBL

$91.65

1/1/15 –12/31/15

Swap

Shell Trading US

LLS

5,000 BBL

$98.05

1/1/15 –6/30/15

Swap

Shell Trading US

LLS

3,000 BBL

$94.10

7/1/15 –12/31/15

Swap

Wells Fargo

WTI

2,000 BBL

$95.08

1/1/15 –12/31/15

Swap

Wells Fargo

LLS

2,000 BBL

$97.74

1/1/15 –12/31/15

Swap

Shell Trading US

LLS

5,000 BBL

$100.70

1/1/15 –6/30/15

Swap

Shell Trading US

LLS

5,000 BBL

$94.10

1/1/16 –12/31/16

Swap

Shell Trading US

HH

20,000 MCF

$4.14

1/1/15 –12/31/15

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Table of Contents

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

 

 

Year ended
December 31,

 

 

Year ended
December 31,

 

(in US$000s)

 

2014

 

2013

 

 

2015

 

2014

 

 

(audited)

 

(audited)

 

 

(audited)

 

(audited)

 

Current tax (expense)/benefit

 

$

(17

)

$

21,398

 

 

$

6,191

 

$

(17

)

Deferred tax benefit/(expense)

 

858

 

(26,965

)

Total income tax benefit/(expense)

 

$

841

 

$

(5,567

)

Deferred tax benefit

 

100,947

 

858

 

Total income tax benefit

 

$

107,138

 

$

841

 

Combined federal and state effective tax rate

 

(5.8

)%

25.9

%

 

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.

 

ProfitLoss attributable to owners of Sundance (or net income).Sundance.  Profit  Loss attributable to our owners (or net incomeincome/loss after tax)  decreased slightly by $0.6was a $(263.8) million (3.9%) tofor the year ended December 31, 2015 a decrease from net income of $15.3 million for the year ended December 31, 2014, from net income of $15.9 million for the year ended December 31, 2013, for the reasonreasons discussed above.

 

Adjusted EBITDAX.  Adjusted EBITDAX increased by $73.8 million (140.3%) to $126.4 million for  For the year ended December 31, 20142015, adjusted EBITDAX was $64.8 million, or 70% of revenue, compared to $126.4 million, or 79% of revenue, from $52.6 million for the year ended December 31, 2013.prior year.  The overall increasedecrease in Adjusted EBITDAX was primarily driven by our production and revenue growth, while decreasing our per Boe amounts for LOE and production taxes.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Revenues and Production. The following table provides the components of our revenues for the years ended December 31, 2013 and 2012, as well as each period’s respective sales volumes:

 

 

Year ended
December 31,

 

 

 

 

 

 

 

2013

 

2012

 

Change in $

 

Change as %

 

 

 

(audited)

 

(unaudited)

 

 

 

 

 

Revenue (In $ ‘000s)

 

 

 

 

 

 

 

 

 

Oil sales

 

$

79,365

 

$

33,743

 

$

45,622

 

135.2

%

Natural gas sales

 

2,774

 

2,029

 

745

 

36.7

%

NGL(1)

 

3,206

 

 

3,206

 

100.0

%

Product revenue

 

$

85,345

 

$

35,772

 

$

49,573

 

138.9

%

 

 

Year ended December 31,

 

Change in

 

 

 

 

 

2013

 

2012

 

Volume

 

Change as %

 

 

 

(audited)

 

(unaudited)

 

 

 

 

 

Net sales volumes:

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

827,432

 

397,913

 

429,519

 

107.9

%

Natural gas (Mcf)

 

934,200

 

505,543

 

428,657

 

84.8

%

NGL (Bbls) (1)

 

95,821

 

 

95,821

 

100.0

%

Oil equivalent (Boe)

 

1,078,953

 

482,170

 

596,783

 

123.8

%


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

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Table of Contents

Barrel of oil equivalent (Boe) and average net daily production (Boe/d).  Production increased by 596,783 Boe (123.8%) to 1,078,953 Boe (2,956 Boe/d) for the year ended December 31, 2013 compared to 482,170 Boe (1,321 Boe/d) for the year ended December 31, 2012. The increase in production volumes was primarily due to a net increase from 186 gross (49.4 net) producing wells to 213 gross (99.9 net) wells. This higher net producing well count was achieved through execution of our strategy to divest lower working interest wells and increase operated drilling activity and production through the Texon merger. Our production is oil-weighted, with oil representing 77% and 83% of total production for the years ended December 31, 2013 and 2012, respectively.

Oil sales.  Oil sales increased by $45.6 million (135.2%) to $79.4 million for the fiscal year ended December 31, 2013 from $33.7 million for the year ended December 31, 2012. Increase in oil revenues was the result of both increased oil production volumes and improved product pricing. Oil production volumes increased 107.9% to 827,432 Bbls for the year ended December 31, 2013 compared to 397,913 Bbls for the year ended December 31, 2012. The average price we realized on the sale of our oil increased by 13.1% to $95.92 per Bbl for the year ended December 31, 2013 from $84.80 per Bbl for the year ended December 31, 2012.

Natural gas sales.  Natural gas sales increased by $0.7 million (36.7%) to $2.8 million for the year ended December 31, 2013 from $2.0 million for the ended December 31, 2012. Increase in natural gas revenues was primarily the result of increased production volumes. Natural gas production volumes increased 428,657 Mcf (84.8%) to 934,200 Mcf for the year ended December 31, 2013 compared to 505,543 Mcf for the ended December 31, 2012. The average price we realized on the sale of our natural gas decreased by 26.0% to $2.97 per Mcf for the year ended December 31, 2013 from $4.01 per Mcf for the year ended December 31, 2012.

NGL sales.  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.

 

 

Year ended
December 31,

 

 

 

 

 

Selected per Boe metrics

 

2013

 

2012

 

Change

 

Percent

 

 

 

(audited)

 

(unaudited)

 

 

 

 

 

Total oil and natural gas revenues

 

$

79.10

 

$

74.19

 

$

4.91

 

6.6

%

Lease operating expenses

 

11.23

 

7.89

 

3.34

 

42.3

%

Production taxes

 

5.80

 

7.98

 

(2.18

)

(27.3

)%

Lease operating and production tax expenses

 

17.03

 

15.87

 

1.16

 

7.3

%

Depreciation and amortization

 

33.57

 

26.69

 

6.88

 

25.8

%

General and administrative expense

 

14.18

 

19.41

 

(5.23

)

(26.9

)%

Lease operating expenses.  Our lease operating expenses (“LOE”) increased by $8.3 million (218.4%) to $12.1 million for the year ended December 31, 2013 from $3.8 million for the year ended December 31, 2012. The increase in LOE was primarily due to additional production (increased 123.8% over the comparable period in 2012).

Production taxes.  Our production taxes increased by $2.5 million (62.8%) to $6.3 million for the year ended December 31, 2013 from $3.8 million for the year ended December 31, 2012. The increase was less than the 138.9% increase in oil, natural gas and NGL revenue, and production taxes per Boe declined by $2.18 (27.3%), due to divesting the majority of our production in North Dakota, which has a 10.6% effective production tax rate compared to Texas, Oklahoma and Colorado, which have effective production tax rates of 6.8%, 1.3%, and 10.2%, respectively.

Depreciation and amortization expense, including depletion.  Our depreciation and amortization expense increased by $23.4 million (181.5%) to $36.2 million for the year ended December 31, 2013 from $12.9 million for the year ended December 31, 2012. The increase reflects our increase in production (123.8%) and an increase in our asset base, subject to amortization as a result of our drilling acquisition and activity, and our Texon acquisition during 2013. Depreciation and amortization per Boe increased by approximately 25.8% to $33.57.

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 $1.1 million (22.0%) to $6.1 million for the year ended December 31, 2013 from $5.0 million for the year ended December 31, 2012. Included in the employee benefits expense for the fiscal year ended December 31, 2013 in accordance with IFRS 2 Share-based Payment is a stock-based compensation charge of $1.6 million for options issued to officers, management and employees, an increase of $0.4 million (30.6%) compared to $1.2 million for the twelve-month period ended December 31, 2012. Excluding share-based stock compensation, employee benefits increased $0.7 million for year ended December 31, 2013, compared to the

49



Table of Contents

year ended December 31, 2012. This increase was primarily driven by an increased number of employees that was necessary to support the execution of our change in strategy. As of December 31, 2013, we had 47 employees, an increase of 20 employees (74.1%) from December 31, 2012.

Administrative expense increased by $4.8 million (111.8%) to $9.1 million for the year ended December 31, 2013 from $4.3 million for the year ended December 31, 2012. Included in administrative expenses were $0.5 million of costs related to the Texon acquisition and $2.1 million of costs related to our proposed initial public offering, which was subsequently abandoned, incurred in the year ended December 31, 2013. Excluding acquisition and offering-related expense, administrative expenses increased $2.2 million for the year ended December 31, 2013. This increase was primarily due to an increase in the level of our activity and number of employees.

General and administrative expenses per Boe decreased by 26.9% as compared to the prior year, primarily related to a change in policy, effective January 1, 2013, whereby the overhead costs, including salaries, wages, benefits and consultant fees, directly attributable to the exploration, acquisition and development of oil and gas properties are capitalized. Total amount capitalized for the year ended December 31, 2013 was $2.3 million. Prior to 2013, overhead amounts allowable for capitalization were insignificant and therefore, we did not capitalize overhead costs in the comparable period in 2012.

Finance costs, net of interest income.  Finance costs, net of interest income and amounts capitalized, decreased by $1.1 million (147.1%), resulting in net interest income of $0.4 million for the fiscal year ended December 31, 2013 from a net cost of $0.7 million for the twelve-month period ended December 31, 2012. The change relates to the capitalization of $1.3 million of interest to our oil and natural gas properties related to interest charges incurred. Prior to 2013, these interest amounts subject to capitalization were insignificant and therefore, we did not capitalize interest in the comparable period in 2012.

Gain/(loss) on commodity hedging.  The gain/(loss) on commodity hedging changed by $1.7 million to a $0.6 million loss for the year ended December 31, 2013 compared to a $1.1 million gain for the year ended December 31, 2012.

Profit attributable to owners of Sundance (or net income).  Our profit attributable to owners of Sundance (or net income after tax) decreased by $65.1 million (80.3%) to net income of $15.9 million for the year ended December 31, 2013 from net income of $81.1 million for the year ended December 31, 2012, which included a pre-tax gain on the sale of our South Antelope prospect of $122.5 million. Excluding the gain on sale, our profit attributable to owners increased $57.4 million.

Adjusted EBITDAX.  Adjusted EBITDAX increased by $31.9 million (154.1%) to $52.6 million for the year ended December 31, 2013 from $20.7 million for the year ended December 31, 2012. The overall increase in Adjusted EBITDAX was primarily driven by our production and revenue growth.

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

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



 

Six-month period
ended December 31,

 

 

 

 

 

 

 

2012

 

2011

 

Change in $

 

Change as %

 

 

 

(audited)

 

(unaudited)

 

 

 

 

 

Revenues (In $ ‘000s)

 

 

 

 

 

 

 

 

 

Oil sales

 

$

16,790

 

$

11,012

 

$

5,778

 

52.5

%

Natural gas sales

 

934

 

727

 

207

 

28.5

%

Total revenues

 

$

17,724

 

$

11,739

 

$

5,985

 

51.0

%

 

 

Six-month period
ended December 31,

 

Change in

 

 

 

 

 

2012

 

2011

 

Volume

 

Change as %

 

 

 

(audited)

 

(unaudited)

 

 

 

 

 

Net sales volumes:

 

 

 

 

 

 

 

 

 

Oil (Bbl)

 

195,498

 

135,234

 

60,264

 

44.6

%

Natural gas (Mcf)

 

260,435

 

124,305

 

136,130

 

109.5

%

Oil equivalent (Boe)

 

238,904

 

155,952

 

82,952

 

53.2

%

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Table of Contents

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

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

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

 

 

Six-month period
ended December 31,

 

 

 

 

 

Selected Per Boe Metrics

 

2012

 

2011

 

Change

 

Percent

 

 

 

(audited)

 

(unaudited)

 

 

 

 

 

Total oil and natural gas revenues

 

$

74.19

 

$

75.27

 

$

(1.08

)

(1.4

)%

Lease operating expenses

 

9.19

 

9.56

 

(0.37

)

(3.9

)%

Production taxes

 

7.90

 

8.29

 

(0.39

)

(4.7

)%

Lease operating and production tax expenses

 

17.09

 

17.85

 

(0.76

)

(4.3

)%

Depreciation and amortization expense

 

25.60

 

27.94

 

(2.34

)

(8.4

)%

General and administrative expense

 

24.32

 

21.26

 

3.06

 

14.4

%

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

Production taxes.  The increase in the production tax expense of $0.6 million (45.8%) was consistent with that of the increase in oil and natural gas revenue (51.0%) for the six-month period ended December 31, 2012 compared to same period in 2011. Production tax per Boe slightly decreased.

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

General and administrative expenses.  General and administrative expenses are comprised of employee benefits expense (including salaries and wages) and administrative expenses. Employee benefits expense increased by $0.7 million (34.4%) to $2.8 million for the six-month period ended December 31, 2012 from $2.1 million for the same period in 2011. Included in the employee benefits expense for the six-month period ended December 31, 2012 in accordance with IFRS 2 Share-Based Payment is a stock-based compensation charge of $0.8 million for options issued to officers and employees, an increase of $0.4 million (87.5%) compared to $0.4 million for the same period in 2011. Excluding stock-based compensation, employee benefits expense increased by $0.3 million (19.9%) to $2.0 million for the six-month period ended December 31, 2012 from $1.6 million for the same period in 2011. This increase was primarily driven by higher head count that was necessary

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Table of Contents

to support the execution of our change in strategy. As of December 31, 2012, we had 25 employees, an increase of 9 employees (56%) from December 31, 2011.

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

General and administrative expense per Boe increased by 14.4% as we increased our staffing levels to support the growth of our drilling program and operated production that we expected and have realized through December 31, 2012.

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

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

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

Income tax expense.  Income tax expense for the six-month period ended December 31, 2012 was $46.6 million compared to $0.7 million for the same period in 2011. Substantially all of the income tax expense in the six-month period ended December 31, 2012 was related to the gain on the sale of our interest in properties located in the South Antelope field. The income tax expense related to the gain on the South Antelope field sale has been deferred through qualifying Section 1031 like-kind exchanges and the use of income tax credits generated by our intangible drilling costs. Our current portion of our deferred income tax liability is insignificant relative to its total deferred income tax liability.

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

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

In May 14, 2015, we andrefinanced our wholly-owned subsidiary Sundance Energy, Inc. entered into the Credit Agreementprevious credit facilities with Wells Fargo to new credit facilities with Morgan Stanley, Energy Capital, Inc., as administrative agent and the lendersincreasing our total borrowing capacity from timean aggregate of $135 million to time party thereto, which provides for our $300 million Revolving Facility and$200 million; comprised of a $125 million Term Loans, with an accordion feature providing for additional term loansLoan, and a reserve based revolver of up to $50 million, subject to certain conditions  The Revolving Facility is subject to a borrowing base, which has been set initially at $75 million.  At closing on May 14,Throughout 2015, $25the Company increased its borrowings to $192 million was drawn($125 million Term Loan and $67 million outstanding on the Revolving Facility and $125 million of Term Loans were funded.  TheFacility).  On December 30, 2015, the Revolving Facility has a five year termborrowing 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 Term Loans have a 5 ½ year term.remainder of 2017.

 

The Revolving Facility matures on May 14, 2020 and the Term Loans refinanced the Company’s credit facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively.  At closing, the Company used $145.0 million of the proceeds to pay off its previous credit facilities, which were fully paid-off.  Approximately $1.1 million of deferred financing fees related to the previous credit facilities were written off due to the refinance.Loan matures on November 14, 2020.

 

52In 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. 



TableCertain of Contentsthe 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 20152017 capital budget is approximately $70 million to $90 million,based on our operating cash flows which we intend to use toward the development of our oil and natural gas projects, with approximately $5 million towardsrelatively insignificant planned expenditures toward exploration and evaluation. We believe that our cash on hand, internally generated operating cash flows and expected future availability under our Revolving Facility and Term Loansthe aforementioned asset sale, will be sufficient to fund our operations and planned capital expenditures for at least the next 12 months.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.

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 agreementsCredit Agreement could be adversely affected. In the event of a reduction in the borrowing base under our credit agreements,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, 20142016, 2015 and 2013, for the six-month period ended December 31, 2012, and for the fiscal year ended June 30, 20122014 are as follows:

 

 

Year ended December 31,

 

Six-month
period ended
December 31

 

Year ended
June 30,

 

 

Year ended December 31,

 

(In $ ‘000s)

 

2014

 

2013

 

2012

 

2012

 

 

2016

 

2015

 

2014

 

 

(audited)

 

(audited)

 

(audited)

 

(audited)

 

 

(audited)

 

(audited)

 

(audited)

 

Financial Measures:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

128,087

 

$

62,646

 

$

9,386

 

$

11,832

 

 

$

42,660

 

$

64,469

 

$

128,087

 

Net cash (used in) provided by investing activities

 

(323,235

)

(164,355

)

114,571

 

(36,149

)

Net cash used in investing activities

 

(79,991

)

(180,771

)

(323,235

)

Net cash provided by financing activities

 

167,595

 

44,455

 

14,846

 

14,734

 

 

51,776

 

50,403

 

167,595

 

Cash and cash equivalents

 

69,217

 

96,871

 

154,110

 

15,328

 

 

17,463

 

3,468

 

69,217

 

Payments for development expenditure

 

(361,950

)

(154,700

)

(32,551

)

(34,833

)

 

(64,130

)

(144,316

)

(361,950

)

Payments for exploration expenditure

 

(39,616

)

(20,006

)

(8,031

)

(5,685

)

 

(2,852

)

(20,339

)

(39,616

)

Acquisitions, net of acquired cash

 

(35,606

)

(27,273

)

(11,470

)

 

 

(23,506

)

(15,023

)

(35,606

)

Proceeds from the sale of non-current assets

 

115,284

 

37,848

 

173,822

 

4,679

 

 

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, 2014 increased 104.5%2015 decreased 50% to $128.1$64.5 million compared to the prior year.2014. This increasedecrease was primarily due to receipts from sales increasing $85.7decreasing $71.0 million, or 101.2%42%, to $170.4$99.4 million while keeping paymentsprimarily due to suppliers and employees relatively stable with an increase of $8.2 million, or 37.7%, to $30.0 million.

Net cash provided by operating activities for the fiscal year ended December 31, 2013decrease in commodity prices.  This was $62.6 million compared to $19.1 million provided by operating activities for the twelve-month period ended December 31, 2012, an increase of $43.5 million (228%). The increase in cash flows provided by operating activities resulted primarily from an increase in receipts from oil, natural gas and natural gas liquid sales of $60.3 million,partially offset by an increase in payments to suppliers and employees of $15.8 million.

Net cash provided by operating activities was $9.4 million for the six-month period ended December 31, 2012, compared to $2.1 million provided by operating activities for the six-month period ended December 31, 2011, an increase of $7.3 million (348.0%). The increase in cash flows provided by operating activities resulted primarily from an increase receipts from oil, natural gas, and natural gas liquid sales of $3.4 million and decreased payments to suppliers and employees of $2.9$19.7 million.

 

Cash flows provided by (used in)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 increased $158.9 million, or 96.7%,development and exploration costs) as compared to $323.2 million.million in 2014 (net of $115.3 million cash source from sale of non-current assets).  This increase is due to successful implementation of the Company’s strategy to develop and grow the reserves from our high working interest, repeatable resource plays,decrease was primarily in the Eagle Ford. Due to funding available to the Company through asset sales, capital raises and credit facilities, the Company was able to accelerate a portion of its 2015

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drilling program into 2014. However, due to the reduction in crude oil prices in the fourth quarter of 2014 and continuing into 2015, weCompany’s down-cycle development plan to scale back our drilling program to concentrate on our limited drilling obligations to hold Eagle Ford acreage during 2015.

Netdrill and complete within operating cash used in investing activities for the fiscal year ended December 31, 2013 was $164.4 million compared to $93.4 million provided by investing activities for the twelve-month period ended December 31, 2012, a change of $257.7 million (276%). Our payments for development and exploration expenditures increased by $102.0 million and $6.9 million, respectively, for the fiscal year ended December 31, 2013 compared to the same period in 2012. Net cash consideration paid for the Texon merger was $26.3 million during the fiscal year ended December 31, 2013; there were no comparable transactions during the twelve-month period ended December 31, 2012. Proceeds received from the sales of non-current assets for the fiscal year ended December 31, 2013 decreased by $140.2 million to $37.8 million as compared to $178.0 million for the twelve-month period ended December 31, 2012.

Expenditures for development of oil and natural gas properties are the primary use of our capital resources. Net cash provided by investing activities for the six-month period ended December 31, 2012 was $114.6 million compared to $14.9 million cash used in investing activities for the same period in 2011. Sales of non-current assets for the six-month period ended December 31, 2012 were $173.8 million compared to $0.5 million for the same period in 2011. Excluding sales of non-current assets, net cash used in investing activities for the six-month period ended December 31, 2012 was $59.3 million compared to $15.4 million for the for the same period in 2011, an increase of $43.9 million. Our payments for development and exploration expenditures increased by $17.9 million and $7.4 million, respectively, for the six-month period ended December 31, 2012 compared to the same period in 2011. In addition, we had $11.5 million of payments for the acquisition of oil and natural gas properties in the Denver-Julesburg and $6.3 million of related payments to establish escrows for drilling commitments.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, 2014 increased $123.1 million, or 277.0%,2015 decreased to $167.6$50.4 million.  This increasedecrease is a result of the increased availability andlower net draws underon the Company’s credit facilities and proceeds received($62.0 million in a private placement of shares. In February 2014, the Company completed a private placement in which we sold 84.2 million ordinary shares at A$0.95 per share, resulting in net proceeds of approximately $68.4 million. The first tranche of 63.7 million shares was issued in March 2014 and the second tranche of 20.5 million shares was issued in April 2014.

Net cash provided by financing activities for the fiscal year ended December 31, 2013 was $44.5 million2015 compared to $29.7$100.0 million provided by financing activities for the twelve-month period ended December 31, 2012, an increasein prior year) and no equity raises in 2015 (compared to a net of $14.8$68.7 million (50%). Our primary source of cash provided by financing activities for the fiscal year ended December 31, 2013 was proceeds from the issuance of shares of $48.2 million, reduced by associated capital raising costs of $2.6 million, and by acquisition costs from the Texon merger of $0.5 million; there were no comparable transactions during the twelve-month period ended December 31, 2012. Our primary source of cash provided by financing activities for the twelve-month period ended December 31, 2012 was net borrowings on our credit facility with Wells Fargo Bank, N.A. in the amount of $30.0 million; there were no comparable transactions during the fiscal year ended December 31, 2013.2014).

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

Credit Facilities

 

Wells Fargo Senior Credit Facility.  On December 31, 2012, we entered into our senior credit facility with Wells Fargo Bank, N.A. (“Senior Credit Facility”). Our Wells Fargo Senior Credit Facility provided us with a $300 million facility with a borrowing base of $110 million as of December 31, 2014. As of December 31, 2014, there was $95 million outstanding under our Senior Credit Facility.

Junior Credit Facility.  In August 2013, we entered into our junior credit facility with Wells Fargo Energy Capital, Inc., as the administrative agent, which provides for term loans to be made to us in a series of draws up to $100 million (“Junior Credit Facility”). As at December 31, 2014, the borrowing capacity under the Wells Fargo Junior Credit Facility was $35 million and the Company had $35 million outstanding on the Wells Fargo Junior Credit Facility.

Both our Senior Credit Facility and Junior Credit Facility were refinanced with our new Revolving Facility and Term Loans as discussed below.

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New Credit Facilities.  On May 14, 2015, we and our wholly-owned subsidiary Sundance Energy, Inc. entered into the Credit Agreement with Morgan Stanley Energy Capital, Inc., as administrative agent and the lenders from time to time party thereto, which provides for our $300 million Revolving Facility and $125 million Term Loans, with an accordion feature providing for additional term loans of up to $50 million, subject to certain conditionsLoan.  The Revolving Facility is subject to a borrowing base, which has beenwas set initially at $75 million.million and reduced to $67 million on December 30, 2015.  At closingDecember 31, 2016, we had $125 million outstanding on May 14, 2015, $25the Term Loan and $67 million was drawnoutstanding on the Revolving Facility and $125 million of Term Loans were funded.  The Revolving Facility has a five year term and the Term Loans have a 5 ½ year term.

Facility.

 

Interest on the Revolving Facility accrues at LIBOR plus a margin that ranges from 2.0% to 3.0%.

·The applicable margin varies depending on based upon the amount drawn. We also pay a commitment fee of 0.50% on the undrawn balance of the borrowing base.  Interest on the Term LoansLoan accrues at LIBOR (with a LIBOR floor of 1.0%) plus 7.0%.

 

The key financial covenants of our Credit Agreement require us to (i) maintain a minimum current ratio, which is defined as consolidated current assets inclusive of undrawn borrowing capacity divided by consolidated current liabilities, of 1.00 or greater, (ii) a revolving debt to EBITDAX ratio, (as defined in our Credit Agreement), determined on a rolling four quarter basis, of 4.00 to 1.00 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 1.25 to 1.00 for the 18 month period commencing on May 14, 2015 and 1.50 to 1.00 at any time thereafter, in each case beginning on June 30, 2015.1.00. 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;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 Agentadministrative agent will be able to terminate the commitments under the Credit agreementAgreement 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;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;

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Table of Contents

 

·                  bankruptcy or insolvency events involving us or our subsidiaries;

 

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

 

·                  certain ERISA events involving us or our subsidiaries;

 

·                  bankruptcy or insolvency; and

 

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

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

 

The Revolving Facility and Term Loans refinanced the Company’s Credit Facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively.  At closing, the Company used $145.0 million of the proceeds to pay off its previous credit facilities, which are now fully paid-off.  Approximately $1.1 million of deferred financing fees related to the previous credit facilities were written off due to the refinance.

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, 2014, 20132016 and the six-month period ended December 31, 2012.2015.

 

 

Year ending December 31,

 

Six-month
period ended
December 31,

 

 

Year ending December 31

 

 

 

 

 

(In $ ‘000s)

 

2014

 

2013

 

2012

 

 

2016

 

2015

 

Change in $

 

Change in %

 

 

(audited)

 

(audited)

 

(audited)

 

 

(audited)

 

(audited)

 

 

 

 

 

Development and production assets

 

$

350,196

 

$

219,121

 

$

47,949

 

 

$

57,893

 

$

76,831

 

(18,938

)

(24.6

)

Exploration and evaluation expenditure

 

39,670

 

14,770

 

23,348

 

 

4,429

 

22,501

 

(18,072

)

(80.3

)

Total

 

$

389,866

 

$

233,891

 

$

71,297

 

 

$

62,322

 

$

99,332

 

(37,010

)

(37.3

)

 

C.Research and Development

 

Not applicable.

 

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Table of Contents

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 cashflowscash 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 cashflowcash 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 predicatablepredictable 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 significantcurrent or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors or results of operations.investors.

 

F.Tabular disclosure of contractual obligations

 

The following table summarizes our contractual obligations as of December 31, 2014:2016.

 

 

Payments due by period

 

 

Payments due by period

 

Contractual Obligations (In $ ‘000s)

 

Total

 

Less than
1 year

 

1 - 3 years

 

3 - 5 years

 

More than
5 years

 

 

Total

 

Less than
1 year

 

1 - 3 years

 

3 - 5 years

 

More than
5 years

 

Credit Facilities(1)

 

$

147,994

 

$

5,502

 

$

107,492

 

$

35,000

 

$

 

 

$

235,441

 

$

12,606

 

$

25,213

 

$

197,622

 

$

 

Drilling rig commitments(2)

 

1,460

 

1,460

 

 

 

 

Drilling commitments(3)

 

2,000

 

1,000

 

1,000

 

 

 

Cooper Basin capital commitments (2)

 

3,373

 

1,687

 

1,686

 

 

 

Drilling rig commitments (3)

 

1,085

 

1,085

 

 

 

 

Operating lease obligations(4)

 

2,364

 

430

 

984

 

950

 

 

 

4,123

 

1,353

 

2,267

 

503

 

 

Employment commitments(5)

 

742

 

370

 

372

 

 

 

 

740

 

370

 

370

 

 

 

Asset retirement obligation(4)

 

8,866

 

150

 

 

 

8,716

 

Restoration provision (6)

 

7,072

 

 

 

 

7,072

 

Total

 

$

163,426

 

$

8,912

 

$

109,848

 

$

35,950

 

$

8,716

 

 

$

251,834

 

$

17,101

 

$

29,536

 

$

198,125

 

$

7,072

 

 


(1)         Includes principal and projected interest payments due under our Senior CreditRevolving Facility and Junior Credit Facility.Term Loan.  Projected interest payments are based on a 2.660%3.7% and 8.50%8.0% interest rate for the SeniorRevolving Credit Facility and the Junior Credit Facility,Term Loan, respectively, in effect as of December 31, 2014.2016. Timing above assumes credit facilities are held to maturity and that there are no subsequent changes to the borrowing base.

(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, 2014, there was $130 million outstanding under these credit facilities. Please read2016 the description of our Senior Credit Facility and our Junior Credit Facility above.

(2)As December 31, 2014 weCompany had one outstanding drilling rig contractcontracted to explore and develop our properties.drill seven wells during 2017.  The contracts generally have terms of 6 months and expired in March 2015. Amounts representamount represents minimum expenditure commitments should wethe Company elect to terminate these contractsthis 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.

 

(3)(6)         As a part of our acquisition agreement for certain Wattenberg assets, we are committed to drilling 15 vertical or four horizontal development wells per year for the years ending December 31, 2013, 2014 and 2015 (collectively 45 vertical or 15 horizontal development wells). We have established an escrow account that will release the funds to us at a rate of $67,000 per vertical or $267,000 per horizontal well drilled, with any shortfall wells (less than 45 cumulative vertical or 15 horizontal wells drilled as of December 31, 2015) to be paid to the seller of the assets from the escrow account. If we complete drilling any of the shortfall wells after the deadline, we are able to recoup up to $67,000 per vertical or $267,000 per horizontal well by obtaining an assignment of a 5% overriding royalty interest from the seller until the shortfall well fee is recouped. We sold the properties in July 2014 and should the buyer drill any qualifying wells, the obligation would be satisfied. As of December 31, 2014, nor we or the buyer had drilled any wells and we do not expect any wells to be drilled under this provision in 2015. As such, the remaining commitment of $2.0 million was accrued in our consolidated statement of financial position and recognized against the gain on sale of assets in the consolidated statement of profit or loss and comprehensive income. Total contractual obligation represents amounts accrued.

(4)We have established a restoration provision liability for the reclamation of oil and natural gas properties at the end of their economic lives. Based on our current projections, we believe the majority of our reclamation obligations will be incurred beyond five years from December 31, 2014.2016.  The amount shown does not include our Mississippian/Woodward restoration provision liability, which we expect to dispose of in 2017.

 

57



TableSubsequent to December 31, 2016, the Company contracted two additional drilling rigs with minimum expenditure commitments of Contents$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. The directors have served since their respective election or appointment and will serve until the next annual general meeting of shareholders or until a successor is duly appointed.

 

Name

 

Position

Eric P. McCrady

 

Chief Executive Officer and Managing Director

Cathy L. Anderson

 

Chief Financial Officer

Grace Ford*

 

Vice President of Exploration and DevelopmentChief Operating Officer

Mike Wolfe*

 

Vice President of Land

David Ramsden-Wood*Trina Medina*

 

Vice President of Reservoir Engineering and Business Development

John Whittington*

 

Vice President of Operations

Michael D. Hannell

 

Chairman of the Board

Damien A. Hannes

 

Director

Neville W. Martin

 

Director

H. Weldon Holcombe

 

Director

 


*                                         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.

Cathy L. Anderson has been our Chief Financial Officer since December 2011. Ms. Anderson has over 2530 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 beenserved 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), since March 2013 and had previously served as Vice President of Geology of Sundance Energy, Inc. since September 2011.(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 and enhanced recovery projects.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 as a geologistin 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 BachelorsBachelor’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,

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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.

 

David Ramsden-WoodTrina Medina has beenserved as Vice President of Reservoir Engineering and Business Development of our subsidiary, Sundance Energy, Inc., since May 2014 and previously served as a consultant for us in a similar role since January 2013. HeSeptember 2015.  She has more than 1520 years of broad reservoir engineering experience in the oil and gas industry. His experience has beenindustry, focused on reservoir engineering, strategicacross conventional, unconventional and financial planningsecondary recovery evaluation and production engineering. From 2009 to 2012, Mr. Ramsden-Wood wasdevelopment 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 regional senior manager for Enerplus Resources (USA) Corporation, a public oil and gas exploration and production company. From 2001 to 2009, he served as a manager in various engineering and business planning capacities for Anadarko Petroleum Corporation, a public oil and gas exploration and production company. Prior to his tenure with Anadarko Petroleum Corporation, Mr. Ramsden-Wood worked on mergers and acquisitions and oil and gas marketing for Canadian Hunter Exploration Ltd and Barrington Petroleum. Mr. Ramsden-Wood holds a Masters of Business Administration degree from Cornell University (with Distinction) and Queen’s University and a BachelorMaster of Science degree in Reservoir Engineering (Chemical)from Texas A&M University, a Master of Science degree in Reservoir Geoscience from the University of Calgary. He isInstitut Francais du Petrole, and a professional engineer, licensed in Alberta, Canada.

John Whittington has been Vice President of Operations of our subsidiary, Sundance Energy, Inc., since May 2014. He has more than 20 years of experience in the oil and gas industry. His experience has focused on the development and optimization of onshore US resource plays with a particular emphasis on completion optimization and production operations. From 2011 to 2014, Mr. Whittington served as the Operations Manager, Vice President of Operations, and Shared Services Manager for Triangle Petroleum Corporation, a vertically integrated, public oil and gas exploration and production company. From 2005 to 2010, Mr. Whittington was a lead completions and operations engineer and completions advisor for EOG Resources, Inc., a public oil and gas exploration and production company. From 2002 to 2005, he was an engineer for Encana Oil and Gas USA, Inc, a public oil and gas exploration and production company; a portion of which he was an alliance engineer with Schlumberger Oilfield Services, a public oilfield service company. From 1999 to 2002, he was a petroleum consultant for Apex Petroleum Engineering, an oil and gas technical consulting service company. Prior to his tenure with Apex Petroleum Engineering, Mr. Whittington served as field, acquisitions, production and senior petroleum engineer for a variety of oil and gas companies and consulting firms, including Dowell Schlumberger Inc, the predecessor to Schlumberger Oilfield Services, Lomak Petroleum, Inc., and Integrated Petroleum Technologies, Inc. Mr. Whittington holds a BachelorBachelors of Science degree in Petroleum Engineering from the New Mexico Institute of Mining and Technology. HeUniversidad Central de Venezuela.  Ms. Medina is a member of the Society of Petroleum Engineers.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 over 45 years ofwide 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 recently finished his term ashas 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. He has also held a number of other board appointments includingsupplier; 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 Honors)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.

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, Mr. HannesDamien was a director for Fay Richwhite Australia, a New Zealand merchant bank. Prior to his tenure with Fay Richwhite, Mr. Hannes was the director of operations and chief financial officer of Donaldson, Lufkin and Jenrette Futures Ltd, a U.S. investment bank. He has successfully raised capital and developed and managed mining, commodities trading and manufacturing businesses in the global market. Mr. Hannes also serves as the chairman of the board of directors of Goldsmith Resources SAC, a gold mining company with operations in Peru, and as a director of Quill Stationery

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Manufacturers Limited, a paper products business with operations in China. He holds a Bachelor of Business degree from the NSW University of Technology in Australia.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 ASX,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

 

OurOn April 26, 2016, the Company entered into a new employment agreement (“Employment Agreement”) with our Chief Executive Officer, Eric P. McCrady, has an employment agreement with a three-year term commencingeffective January 20142016 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)Employment Agreement) in which Mr. McCrady does not remain employed by the acquirer, the employment agreementEmployment Agreement provides payment of Mr. McCrady’s base remuneration through the end of the term of the employment agreement.Employment Agreement. He is eligible to participate in our incentive compensation program.

 

Other than Mr. McCrady, at the date of this report, nonewe had not entered into or finalized employment agreements with any of our other executive officers has an employment agreement.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 hashave any service contracts with Sundance or any of its subsidiaries providing for benefits upon termination of employment.

B.Compensation

 

Our boardBoard of directorsDirectors 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 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. To align directors’ interests with shareholder interests, the directors are required to hold our ordinary shares equal to three times their base board fees. 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. All remuneration paid to directors and executives is valued in accordance with applicable IFRS accounting rules.

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The Remuneration and Nominations Committee makes recommendations to our boardBoard of directorsDirectors 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 20142016 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 perquisitesperquisites.  All remuneration paid to directors and executives is valued in accordance with applicable IFRS accounting rules.

 

ExecutivesIn 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, 2014,2016, the targeted “at risk” remuneration relating to performance variability with STIShort-Term Incentive (“STI”) bonuses and LTILong-Term Incentive (“LTI”) awards represents approximately 81% for the Managing Director and approximately 81%75% for all other executives.

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

 

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

 

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

 

We have two active equity incentive plans underDuring 2016, the LTI component of theour incentive compensation program. These are the Sundance Employee Option Plan (“ESOP”) andprogram comprised awards made pursuant to the Sundance Energy Australia Limited Restricted Share Units available only to our U.S. employees under theLong Term Incentive Compensation 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 ESOP provides for the issuance of stock options at an exercise price determined at the time of the issue by a committee designated by the board (the “Plan Committee”). Options under the ESOP may be granted to eligible employees, as determined by the Plan Committee, and typically include our executive officers, directors and key employees. Historically, the Plan Committee has granted options in connection with attracting new employees, which grant is made once employment has

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commenced. It is within the discretion of the Plan Committee, however, to authorize additional option grants during the term of employment. Generally, an option vests 20% on the 90th day following the grant date, with an additional 20% vesting on the first, second, third and fourth anniversaries thereof. Options are valued using the Black-Scholes methodology and recognized as remuneration in accordance with their vesting conditions. In the event of a voluntary winding up of Sundance, unvested stock options vest immediately. We may amend the ESOP or any portion thereof, or waive or modify the application of the ESOP rules in relation to a participant, at any time. Certain amendments to the ESOP may require the approval of the holders of the options granted under the ESOP. No stock options were granted to any officers or directors during fiscal years 2013 or 2014.

The RSU Plan provides for the issuance of restricted stockshare units (“RSUs”) to our U.S. employees.  The purpose of issuing RSUs is to reward senior executives and employees for achievement of financial and operational performance targets established by our board. The RSU Plan is administered by our board.the Board. RSUs under the RSU Plan may be granted to eligible employees (as determined by our board, which typically include our executive officers, directors and key employees) from a bonus pool established at the sole discretion of our board.Board. The bonus pool is subject to boardBoard and management review of performance metrics with respect to both ourthe Company and the individual employee’s performance over a measured period determined by the Remuneration and Nominations Committee and the board as discussed below.Board. The RSUs may be settled in cash or stockshares at the discretion of our board. Under the RSU Plan, 25% of the RSUs vest on the grant date, and 25% vest on each of the first, second and third anniversaries of the grant date. The RSUs are based on performance targets established and approved by our board. In the event of a corporate take-over or change in control (as defined in the RSU Plan), our board in its discretion may cause all unvested RSUs to vest and be satisfied by the issue of one share each or provide for the cancellation of outstanding RSUs and a cash payment equal to the then-fair market value of the RSUs.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.

LTI Award in 2017

 

Starting withFor the 20152016 fiscal year (granted in 2017), the RSU Plan has been amended forLTI incentives granted to executives to reflectwere comprised of:

1)             50% timeof award value granted in RSUs which vest based vesting and 50% vesting based onupon the movement in Sundance ordinary share price over a three-year period (“Absolute Total Shareholder Return” or “A-TSR”).  Absolute total shareholder return (“TSR”) relative to our peer group over a three-year period. The time-based vesting will vest 1/3 on each of the three anniversaries following the grant date subject to continued employment with Sundance. TSR(A-TSR) is calculated asby the change in stockthe Company’s ordinary share price plus dividends paid, if any, over the three yearspecified time period.  The stock price used to calculate the starting stock price value will be the average price of Sundance’s stock for the 20 trading days before the first day of the measurement period. The ending-period stock price will be the average price of Sundance’s stock for the last 20 trading days of the measurement period.

The number of shares that can be earned under TSR performancethe A-TSR component of the award, ranges from 0% to 200%150% of the target share grant, based on Sundance’s percentile rank amongA-TSR calculated at the peer set. If Sundance’s TSR is negative forend of the three-year assessment period butaccording to the percentile rank is above median, the payout will be capped at the target payout. If Sundance’s TSR is between any of the percentile ranks listed in the table below, the payout as a percent of target will be on a pro-rata basis.following multiples:

 

Absolute TSR Percentile RankGoal

 

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

 

90th and above1.95x (equivalent to a 25% preferred return)

 

200133

%

50th1.52x (equivalent to a 15% preferred return)

 

100

%

30th1.26x (equivalent to a 8% preferred return)

 

50

%

Below 30th< 1.26x

 

0

%

 

TSR will be compared to a set2)             50% of 22 oil and gas exploration and production companies headquarteredaward value granted as two tranches of deferred cash, earned through appreciation in the United Statesprice of Sundance’s ordinary shares during 2017 and Australia.2018.  The Australian-headquartered companiesbase deferred cash target awards are highlighted. The chart onpaid only after achieving the right depictsfollowing share performance targets:

·                  Tranche 1- A 20 day volume weighted average (20-day VWAP) of A$0.297 per share for the TSR over a threelast 20-day period in the year period ending December 31, 2014. Diamondback Energy Inc., Matador Resources Co. and Midstates Petroleum Co Inc. were excluded from the chart as there was not enough historical data2017.  This equates to measure the defined TSR.a 25% preferred return over a two-year period.

 

62·                  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.



Table of Contents

Company

Abraxas Petroleum Corp/NV

Approach Resources Inc

Austex Oil Ltd

Beach Energy Ltd

Bonanza Creek Energy Inc.

Callon Petroleum CO/DE

Carrizo Oil & Gas Inc

Contango Oil & Gas Co

Diamondback Energy Inc

Drillsearch Energy Ltd

Emerald Oil Inc

Goodrich Petroleum Corp

Lonestar Resources Ltd

Matador Resources Co

Midstates Petroleum Co Inc

Panhandle Oil & Gas Inc

Red Fork Energy Ltd

Rex Energy Corp

Sanchez Energy Corp

Senex Energy Ltd

Synergy Resources Corp

Triangle Petroleum Corp

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 boardBoard of directors.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, to reflect the current low commodity price environmentcash.  However, no STI bonuses were paid for 2016 and preserve liquidity, the STI earned for the 2014 fiscal year will be paid out in RSUs during 2015. Bonuses earned under the LTI are paid by means of awarding RSUs under the RSU Plan.

For the year ended December 31, 2014 (to be paid in 2015), the following metrics were adopted as targets:

Financial Performance Metric 

 

Performance
Target

 

Target
Weight

 

Production of oil and natural gas per 1,000 debt adjusted share

 

4.06 Boe

 

17.5

%

Cash margin

 

72.6%

 

17.5

%

Net asset value per debt-adjusted share

 

1.02

 

17.5

%

PV/I (1)

 

1.25

 

17.5

%

Health, safety and environmental

 

Qualitative

 

10.0

%

Assessment of the performance of senior executives and managers

 

Qualitative

 

20.0

%


(1)Net change in the proved PV10 of the constant case reserve report divided by development capital expenditures during the period under consideration less proceeds from divestitures.2015 performance.

 

In addition, certain ceiling and claw-back provisions have been set by our boardBoard of directorsDirectors 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 Mr. Ramsden-Wood and Mr. WhittingtonMs. 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, 20142016 are as follows:

 

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Fixed Based Remuneration

 

Share

 

Performance Based

 

 

 

 

 

 

 

Non-

 

Post-

 

 

 

Based

 

 

 

LTI-

 

 

 

Director

 

Cash salary
and Fees

 

monetary
Benefits (1)

 

employment
Benefits

 

Superannuation

 

Payments-
Options (2)

 

STI-Cash
Bonus

 

Share
Based (3)

 

Total

 

E. McCrady

 

$

365,615

 

$

18,816

 

$

7,800

 

$

 

$

 

$

240,000

 

$

542,310

 

$

1,174,540

 

M. Hannell

 

141,958

 

 

 

13,334

 

 

 

 

155,293

 

D. Hannes

 

115,956

 

 

 

10,896

 

 

 

 

126,852

 

N. Martin

 

98,414

 

 

 

9,252

 

 

 

 

107,666

 

W. Holcombe

 

117,792

 

 

 

 

 

 

 

117,792

 

 

 

$

839,735

 

$

18,816

 

$

7,800

 

$

33,482

 

$

 

$

240,000

 

$

542,310

 

$

1,682,143

 

Executive officers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

C. Anderson

 

$

291,770

 

14,144

 

$

7,800

 

$

 

$

26,399

 

$

147,000

 

$

292,885

 

$

779,998

 

G. Ford

 

292,000

 

8,428

 

7,800

 

 

48,385

 

150,000

 

298,010

 

804,623

 

 

 

$

583,769

 

$

22,572

 

$

15,600

 

$

 

$

74,784

 

$

297,000

 

$

590,895

 

$

1,584,621

 

Total

 

$

1,423,505

 

$

41,388

 

$

23,400

 

$

33,482

 

$

74,784

 

$

537,000

 

$

1,133,205

 

$

3,266,764

 

 

 

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

 

 


(1)Non-monetary benefits includes car parking fringe benefits and payment of health premiums.

(2)Fair value of services received in return for the options granted is measured using the Black-Scholes Option Pricing Model, as further discussed in Note 31 to our financial statements, and represents the portion of the grant date fair value expense of the option during the year. Options were granted to Anderson and Ford in December 2011 and September 2011, respectively.

(3)Fair value of services received in return for the LTI share based awards are based on the allocable portion of aggregate fair value expense recognized under AASB 2 for the year. The aggregate fair value is based on the number of RSUs awarded valued at the Company’s stock price at the date of grant, translated at the foreign exchange rate in effect on the date of grant. Vesting is 25% at the time of grant (following the performance period), with 25% cliff vesting each subsequent year on the date of grant. The amount included as remuneration is not related to or indicative of the benefit (if any) that individuals may ultimately realize when the RSUs vest.

 

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.

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, 2014

 

Year ended December 31, 2013

 

 

 

Fixed
Remuneration

 

STI

 

LTI

 

Target
Performance
Related

 

Fixed
Remuneration

 

STI

 

LTI

 

Target
Performance
Related

 

E. McCrady

 

19

%

19

%

62

%

81

%

22

%

22

%

56

%

78

%

C. Anderson

 

25

%

19

%

56

%

75

%

29

%

21

%

50

%

71

%

G. Ford

 

25

%

19

%

56

%

75

%

29

%

21

%

50

%

71

%

Non-executive directors

 

100

%

 

 

 

100

%

 

 

 

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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 boardBoard of directorsDirectors 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 boardBoard of directorsDirectors 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 boardBoard of directorsDirectors may determine the number of directors within those limits;

 

·                  it is the intention of our boardBoard of directorsDirectors 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 boardBoard of directorsDirectors should be an independent director who satisfies the criteria for independence recommended by the ASX Principles and Recommendations; and

 

·                  our boardBoard of directorsDirectors 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 boardBoard of directorsDirectors has delegated responsibility for the conduct of our businesses to the Managing Director, but remains responsible for overseeing the performance of management. Our boardBoard of directorsDirectors has established delegated limits of authority, which define the matters that are delegated to management and those that require boardBoard of directorsDirectors 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 boardBoard of directorsDirectors 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 boardBoard of directors.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 boardBoard of directors,Directors, and maintain a management succession plan. In addition, the committee will oversee, review, act on and report on various remuneration matters to our boardBoard of directors.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.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 boardBoard of directors,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 boardBoard of directors.Directors.

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 the our continuous disclosure policy.

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Table of Contents

 

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 boardBoard of directorsDirectors 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 SessionsWe 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.

QuorumWe 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 IssuancesWe 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, 2014,2016, we had 6054 full-time employees, including 1916 in executive, finance and accounting and administration, 43 in geology, 2227 in production and engineering and 158 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.

E.Share Ownership

Number of Options Held by Executive Officers

Executive Officers

 

Balance
12/31/2013

 

Granted as
Compensation

 

Options
Exercised

 

Options
Expired

 

Balance
12/31/2014

 

Total
Vested
12/31/2014

 

Total
Exercisable
12/31/2014

 

Total
Unexercisable
12/31/2014

 

E. McCrady

 

 

 

 

 

 

 

 

 

C. Anderson

 

1,000,000

 

 

 

 

1,000,000

 

600,000

(1)

600,000

 

400,000

 

G. Ford

 

1,200,000

 

 

 

 

1,200,000

 

800,000

(2)

800,000

 

400,000

 

Total

 

2,200,000

 

 

 

 

2,200,000

 

1,400,000

 

1,400,000

 

800,000

 


(1)Consists of options to purchase up to 600,000 ordinary shares exercisable at $0.95 per share, which expire in March 2019. Options vest 20% on grant date and 20% each anniversary of the grant date over next 4 years.

(2)Consists of options to purchase up to 800,000 ordinary shares exercisable at $0.95 per share, which expire in December 2018. Options vest 17% on grant date and 17% each anniversary of the grant date over next 5 years.

No options were issued as part of remuneration to directors or executive officers for the year ended December 31, 2014.

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Table of Contents

 

Number of Restricted Shares Units Held by Executive Officers

 

Executive
Officer

 

Balance
12/31/2013

 

Issued as
Compensation

 

Forfeited

 

RSUs
converted to
ordinary
shares

 

Balance
12/31/2014

 

Total
Vested
12/31/2014

 

Total
Unvested
12/31/2014

 

E. McCrady

 

555,078

 

671,988

 

 

(435,505

)

791,561

 

 

791,561

 

C. Anderson

 

320,680

 

385,456

 

 

(225,579

)

480,557

 

 

480,557

 

G. Ford

 

322,410

 

394,473

 

 

(228,410

)

488,473

 

 

488,473

 

Total

 

1,198,168

 

1,451,917

 

 

(889,494

)

1,760,591

 

 

1,760,591

 

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

 

 


All RSUs outstanding as of(1)         Market value based on the Company’s closing share price on December 31, 2014, vest 25%2016 or USD $0.158 based on datethe foreign currency exchange spot rate published by the Reserve Bank of grant and 25% vest equallyAustralia.

(2)         Mr. McCrady’s RSUs were approved by the shareholders at the AGM held on each of the first three anniversaries of the grant date.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 549,351,2271,249,351,617 ordinary shares outstanding as of April 30, 201510, 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 30, 2015,10, 2017, we had 5365 shareholders of record in the United States. These shareholders held an aggregate of 5,447,7127,917,988 of our outstanding ordinary shares, or approximately 1.0%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.

 

 

Ordinary Shares
Beneficially Owned

 

Shareholder

 

Number

 

Percent

 

5% Shareholders

 

 

 

 

 

IOOF Holdings Limited(1)

 

42,791,826

 

7.79

%

Officers and Directors

 

 

 

 

 

Eric P. McCrady

 

1,908,581

 

*

 

Michael D. Hannell

 

1,059,000

 

*

 

Damien A. Hannes

 

5,801,561

(2)

1.06

%

Neville W. Martin

 

422,800

(3)

*

 

H. Weldon Holcombe

 

596,700

 

*

 

Cathy L. Anderson

 

1,075,370

(4)

*

 

Grace Ford

 

1,176,403

(5)

*

 

Officers and directors as a group (seven persons)

 

12,040,345

 

2.19

%

 

 

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.

 

67(4)



Table                                 Includes restricted share units that are issuable or scheduled to vest within 60 days of ContentsApril 10, 2017 totaling 683,035 shares.

 

(1)(5)                                 The address for IOOF Holdings Limited is Level 6, 161 Collins Street, Melbourne Victoria 3000.

(2)Includes (i) 377,858493,243 ordinary shares held by Mr. Hannes individually and (ii) 5,423,7035,754,473 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.

 

(3)(6)                                 Includes (i) 20,00096,924 ordinary shares held by Mr. Martin individually, and (ii) 379,942598,185 ordinary shares held in trust of which Mr. Martin serves as trustee and is a beneficiary and (iii) 22,858 ordinary shares jointly held with Mr. Martin’s spouse.beneficiary.

 

(4)(7)                                 Includes (i) 275,370 ordinary shares and (ii) optionsrestricted share units that are issuable or scheduled to purchase up to 800,000 ordinary shares, exercisable until March 2019 at an exercise pricevest within 60 days of A$0.95 per share.April 10, 2017 totaling 380,652 shares.

 

(5)(8)                                 Includes (i) 376,403 ordinary shares and (ii) optionsrestricted share units that are issuable or scheduled to purchase up to 800,000 ordinary shares, exercisable until December 2018 at an exercise pricevest within 60 days of A$0.95 per share.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 27, 2015,18, 2016, IOOF reported that it held 42,791,826 ordinary shares, or 7.790%, of the total voting power as of that date.March 16, 2016, it was no longer a substantial shareholder.

 

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

 

B.Related Party Transactions

 

Other than as disclosed below, fromFrom January 1, 2014 to March 31, 20152016 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.

 

Neville Martin has been a director of Sundance since March 2012 and was a partner and is now a consultant of Minter Ellison, an Australian law firm. Minter Ellison was paid a non-material amountThere were no material related party transactions for legal services for the fiscal year ended December 31, 20142016, 2015 and through April 17, 2015.2014.

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

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

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Table of Contents

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.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,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 boardBoard of directorsDirectors may determine from time to time. Subject to the Corporations Act and the ASX Listing Rules,listing rules, any rights and restrictions attached to a class of shares, we may issue further shares on such terms and conditions as our boardBoard of directorsDirectors resolve. Currently, our outstanding share capital consists of only one class of ordinary shares.

 

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

 

B.Significant Changes

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

Subsequent to December 31, 2014, an additional $15.0 million was drawn-down on our Senior Credit Facility, bringing total outstanding debt to $145.0 million, with no undrawn funds available under our Senior Credit Facility.  Both our Senior Credit Facility and Junior Credit Facility were refinanced as discussed below.

 

On May 14, 2015, we and our wholly-owned subsidiary Sundance Energy, Inc. entered into the Credit Agreement with Morgan Stanley Energy Capital, Inc., as administrative agent and the lenders from time to time party thereto, which provides for our $300 million Revolving Facility and $125 million Term Loans, with an accordion feature providing for additional term loans of up to $50 million, subject to certain conditions  The Revolving Facility is subject to a borrowing base, which has been set initially at $75 million.  At closing on May 14, 2015, $25 million was drawn on the Revolving Facility and $125 million of Term Loans were funded.  The Revolving Facility has a five year term and the Term Loans have a 5 ½ year term.

The Revolving Facility and Term Loans refinanced the Company’s credit facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively.  At closing, the Company used $145.0 million of the proceeds to pay off its previous credit facilities, which are fully paid-off.  Approximately $1.1 million of deferred financing fees related to the previous credit facilities were written off due to the refinance.

Subsequent to year end and in anticipation of closing the aforementioned credit facilities,March 1, 2017, the Company entered into a binding sale and purchase agreement to divest of its assets located in the following hedge contracts.

 

 

 

 

 

 

Units per month

 

Floor

 

Ceiling

 

 

 

Description

 

Commodity

 

Basis

 

2015

 

2016

 

2017

 

2018

 

2019

 

Price

 

Price

 

Term

 

Collar

 

Oil (Bbls)

 

LLS

 

10,000

 

 

 

 

 

$

50.00

 

$

98.65

 

Jun ‘15 – Dec ‘15

 

Collar

 

Oil (Bbls)

 

LLS

 

10,000

 

 

 

 

 

50.00

 

101.05

 

Jun ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

6,000

 

 

 

 

 

64.70

 

64.70

 

Jun ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

6,000

 

 

 

 

 

65.90

 

65.90

 

Jun ‘15 – Sep ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

3,333

*

 

 

 

 

66.75

 

66.75

 

Jun ‘15 – Nov ‘15

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

69.30

 

Jan ‘16 – May ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

72.25

 

Jan ‘16 – May ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

77.00

 

Jun ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

85.00

 

Jul ‘16 – Dec ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

4,000

 

 

 

 

50.00

 

77.80

 

Jan ‘16 – Dec ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

8,000

 

 

 

50.00

 

81.75

 

Jan ‘17 – Dec ‘17

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

4,000

 

 

 

50.00

 

80.25

 

Jan ‘17 – Dec ‘17

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

 

4,000

 

 

55.00

 

80.25

 

Jan ‘18 – Dec ‘18

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

 

 

4,000

 

55.00

 

82.00

 

Jan ‘19 – Dec ‘19

 

Total Oil/Weighted Average Price

 

 

 

 

 

35,333

 

44,000

 

12,000

 

4,000

 

4,000

 

$

52.65

 

$

75.60

 

Jun ‘15 - Dec ‘19

 

Collar

 

Gas (Mmbtu)

 

HH

 

40,000

 

 

 

 

 

$

2.70

 

$

3.20

 

Jun ‘15 - Dec ‘15

 

Swap

 

Gas (Mmbtu)

 

HSC

 

30,000

 

 

 

 

 

$

3.06

 

$

3.06

 

Jun ‘15 - Dec ‘15

 

Collar

 

Gas (Mmbtu)

 

HSC

 

 

20,000

 

 

 

 

$

2.90

 

$

3.50

 

Jan ‘16 - Dec ‘16

 

Collar

 

Gas (Mmbtu)

 

HSC

 

 

20,000

 

 

 

 

$

2.90

 

$

3.75

 

Jan ‘16 - Dec ‘16

 

Collar

 

Gas (Mmbtu)

 

HH

 

 

20,000

 

 

 

 

$

2.90

 

$

3.50

 

Jan ‘16 - Dec ‘16

 

Collar

 

Gas (Mmbtu)

 

HH

 

 

 

20,000

 

 

 

$

3.05

 

$

3.60

 

Jan ‘17 - Dec ‘17

 

Total Gas/Weighted Average Price

 

 

 

 

 

70,000

 

60,000

 

20,000

 

 

 

$

2.91

 

$

3.44

 

Jun ‘15 - Dec ‘17

 


* Units per month range from 0 — 7,000 Bbls

InAnadarko Basin of Oklahoma for cash of $18.5 million.  The assets being sold include all of the above table, “LLS” refersOklahoma wells and acreage owned by the Company.  The transaction is subject to Light Louisiana Sweet, “HH” refersseveral common closing conditions such as confirmatory due diligence but is not subject to Henry Hub and “HSC” refersany financing contingencies.  The Company expects the transaction to Houston Ship Channel.close by May 2017.

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Item 9.  The Offer and Listing

 

A.Offer and Listing Details

 

Pricing History—Australian Securities ExchangeHistory

 

OurThe NASDAQ Stock Market

Since September 7, 2016, our ordinary shares were initially quoted and admitted toin the form of ADSs have been trading on NASDAQ under the ASX (symbol: “SEA”)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 2005. 17, 2017, the closing price of our ADSs as traded on the NASDAQ was $8.50 per ADS.

Australian Securities Exchange

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

 

 

High

 

Low

 

 

High

 

Low

 

 

A$

 

A$

 

 

A$

 

A$

 

Annual:

 

 

 

 

 

 

 

 

 

 

Fiscal year ended December 31

 

 

 

 

 

 

 

 

 

 

2016

 

0.27

 

0.06

 

2015

 

0.71

 

0.16

 

2014

 

1.42

 

0.38

 

 

1.42

 

0.38

 

2013

 

1.18

 

0.76

 

 

1.18

 

0.76

 

Six-month period ended December 31

 

 

 

 

 

 

 

 

 

 

2012

 

0.85

 

0.38

 

 

0.85

 

0.38

 

Fiscal year ended June 30

 

 

 

 

 

 

 

 

 

 

2012

 

0.88

 

0.36

 

 

0.88

 

0.36

 

2011

 

1.10

 

0.17

 

2010

 

0.20

 

0.08

 

Quarterly:

 

 

 

 

 

 

 

 

 

 

Fiscal year ending December 31, 2015

 

 

 

 

 

Second Quarter (through April 30, 2015)

 

0.70

 

0.44

 

Fiscal year ending December 31, 2017

 

 

 

 

 

First Quarter

 

0.63

 

0.44

 

 

0.24

 

0.11

 

Fiscal year ending December 31, 2014

 

 

 

 

 

Fiscal year ended December 31, 2016

 

 

 

 

 

Fourth Quarter

 

1.25

 

0.38

 

 

0.22

 

0.15

 

Third Quarter

 

1.42

 

1.16

 

 

0.18

 

0.10

 

Second Quarter

 

1.20

 

0.92

 

 

0.22

 

0.10

 

First Quarter

 

1.12

 

0.94

 

 

0.27

 

0.06

 

Fiscal year ended December 31, 2013

 

 

 

 

 

Fiscal year ended December 31, 2015

 

 

 

 

 

Fourth Quarter

 

1.18

 

0.88

 

 

0.39

 

0.16

 

Third Quarter

 

1.14

 

0.84

 

 

0.53

 

0.24

 

Second Quarter

 

1.13

 

0.77

 

 

0.71

 

0.45

 

First Quarter

 

1.11

 

0.76

 

 

0.63

 

0.45

 

Most Recent Six Months:

 

 

 

 

 

 

 

 

 

 

March 2015

 

1.20

 

1.04

 

February 2015

 

1.11

 

0.94

 

January 2015

 

1.04

 

0.92

 

December 2014

 

1.02

 

0.94

 

November 2014

 

1.12

 

0.94

 

October 2014

 

1.05

 

0.94

 

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 30, 201517, 2017 the closing price of our ordinary shares as traded on the ASX was A$0.610.105 per ordinary share (U.S.$0.480.08 per share based on the foreign exchange rate of A$1.00 to $0.7981$0.7590 as published by the Reserve Bank of Australia as of April 30, 2015.17, 2017.

 

As of April 30, 2015,10, 2017, we had 549,351,2271,249,351,617 ordinary shares outstanding, with 5,447,7127,917,988 of our ordinary shares being held in the United States by 5365 holders of record and 520,522,9201,204,317,759 of our ordinary shares being held in Australia by 3,9854,211 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.”

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Table  Since September 7, 2016, our ordinary shares in the form of ContentsADSs have been trading on NASDAQ under the symbol “SNDE.”

 

D.Selling Shareholders

 

Not applicable.

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 - Information—Our Constitution” and is incorporated by reference into this annual report.

 

C.Material Contracts

 

Credit Facilities

In August 2013, we entered into our Junior Credit Facility with Wells Fargo Energy Capital, Inc., as the administrative agent, which provides for term loans to be made to us in a series of draws up to $100 million. The Junior Credit Facility has a stated maturity of five years and is secured by a second priority lien on substantially all of our assets. As of December 31, 2014, there was $35 million outstanding under the Junior Credit Facility.

By December 31, 2014, our borrowing capacity under our credit facilities increased from an aggregate of $63 million to $145 million. In conjunction with the increase in our borrowing base, we have expanded the syndicate of banks under our Senior Credit Facility. Led by Wells Fargo, as administrative agent, Bank of America Merrill Lynch and the Bank of Nova Scotia have now joined the banking group.

 

On May 14, 2015, Sundance Energy Australia Limited and Sundance Energy, Inc. entered into athe 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 aour $300 million senior secured revolving credit facility (the “Revolving Facility”)Revolving Facility and term loans of $125 million (the “Term Loans), with an accordion feature providing for additional term loans of up to $50 million, subject to certain conditionsTerm Loan. The Revolving Facility is subject to a borrowing base, which has beenwas set initially at $75 million.  At closingThe borrowing base was reduced to $67 million on May 14,December 30, 2015, $25 millionwhich was drawn on the Revolving Facility and $125 million of Term Loans were funded.amount outstanding.  The Revolving Facility has a five year termmatures May 14, 2020 and the Term Loans have a 5 ½ year term.Loan matures November 14, 2020.

 

The Revolving Facility and Term LoansLoan refinanced the Company’s credit facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively.  At closing, the Company used $145.0 million of the proceeds to pay off its previous credit facilities, which were fully paid-off.  Approximately $1.1 million of deferred financing fees related to the previous credit facilities were written off due to the refinance.

 

For a description of the material terms of our credit facilities, see Item 5.B. “Operating and Financial Review and Prospects-LiquidityProspects—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.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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Table of Contents

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.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 (as defined below).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 of ordinary shares will include the dividend income on the day actually or constructively received by the holder.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, provided that(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 (ii)(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.

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

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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.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.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.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, 2014.2016. 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, 2015.2017. 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. Because the determination of our PFIC status is based on an annual determination that cannot be made until the close of a taxable year, and involves extensive factual investigation, including ascertaining the fair market value of all of our assets on a quarterly basis and the character of each item of income we earn, our U.S. counsel expresses no opinion with respect to our PFIC status.

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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;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. Generally, a “qualified exchange” includes a foreign securities exchange that is regulated or supervised by a governmental authority of the country in which the market is located and that has certain characteristics. 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.  OurUnder 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. So long as ourASX and NASDAQ, respectively, both of which constitute a qualified exchange.  There there can be no assurance, however, that the ordinary shares are regularly traded on that exchange, we expect thator ADSs will be “regularly traded” for purposes of the mark-to-market election would be available to you were we to be or become a PFIC.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.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.

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.

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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.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.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.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.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 theour ordinary shares. Itshares 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 the shares. Thisour shares or ADSs. As used in this summary a “Non-Australian Shareholder” is based upon the premisea holder that the holder is not an Australian tax resident and is not carrying on business in Australia through a permanent establishment.

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. Dividends

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payable to non-Australian resident shareholders that are not operating from an Australian permanent establishment (“Foreign Shareholders”) will be subject toAn exemption for dividend withholding tax can also apply to the extent theunfranked dividends that are not foreign sourced and declared to be conduit foreign income (“CFI”), and are unfranked.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 which 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 company thatNon-Australian Shareholder is a non-Australian resident shareholdercompany 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.zero.

 

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

 

ForeignNon-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.

 

ForeignNon-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. Australian capital gains tax applies to net capital gains at a taxpayer’s marginal tax rate but for certain shareholders a discount of the capital gain may apply if the shares have been held for 12 months or more prior to disposal. We note that legislation was introduced in June 2013 to remove the 50% discount for foreign resident individuals on gains accrued after May 8, 2012. Companies are not entitled to a discount on capital gains tax. Net capital gains are calculated after reduction for capital losses, which may only be offset against capital gains.

 

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

 

Some ForeignNon-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 resident shareholdersShareholders 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 such non-Australian resident shareholdersNon-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 resident shareholder’sNon-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.

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

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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.

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 3334 of our December 31, 20142016 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 boardBoard of directorsDirectors 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 boardBoard of directors.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, 2014,2016, 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, 2014 and taking into consideration interest rate swaps,2016, with all other variables remaining constant for the year ended December 31, 2014,2016, would be as follows (in $ ‘000s):

 

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Effect on profit before tax Increase/(decrease)

—increase in interest rates + 2%

$

(906

)

—decrease in interest rates - 2%

184

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 boardBoard of directorsDirectors actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of our hedging activity are continually monitored against our policy. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use forward contracts to manage our commodity price risk exposure. Our current policy is to hedge up to 80%at least 50% of forecastedour proved developed producing production, but not more than 25% of total estimated productionreserves through 2020 and for the next five years.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, 2014:2016:

 

 

 

 

 

 

 

Units per month

 

Floor

 

Ceiling

 

 

 

Description

 

Commodity

 

Basis

 

2015

 

2016

 

2017

 

Price

 

Price

 

Term

 

Collar

 

Oil (Bbls)

 

NYMEX-WTI

 

2,000

 

 

 

$

75.00

 

$

98.65

 

Jan ‘15 – Dec ‘15

 

Collar

 

Oil (Bbls)

 

LLS

 

3,000

 

 

 

85.00

 

101.05

 

Jan ‘15 – Dec ‘15

 

Collar

 

Oil (Bbls)

 

NYMEX-WTI

 

2,000

 

 

 

80.00

 

97.00

 

Jan ‘15 – Dec ‘15

 

Collar

 

Oil (Bbls)

 

NYMEX-WTI

 

1,000

 

 

 

80.00

 

94.94

 

Jan ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

2,000

 

 

 

 

91.65

 

91.65

 

Jan ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

5,000

 

 

 

98.05

 

98.05

 

Jan ‘15 – Jun ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

3,000

 

 

 

 

94.10

 

94.10

 

Jul ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

NYMEX-WTI

 

2,000

 

 

 

95.08

 

95.08

 

Jan ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

2,000

 

 

 

97.74

 

97.74

 

Jan ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

5,000

 

 

 

100.70

 

100.70

 

Jan ‘15 – Jun ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

 

5,000

 

 

94.10

 

94.10

 

Jan ‘16 – Dec ‘16

 

Total Oil/Weighted Average Price

 

 

 

 

 

27,000

 

5,000

 

 

$

91.08

 

$

96.74

 

Jan ‘14 - Dec ‘16

 

Swap

 

Gas (MCF)

 

HH

 

20,000

 

 

 

$

4.14

 

$

4.14

 

Jan ‘15 - Dec ‘15

 

Total Gas/Weighted Average Price

 

 

 

 

 

20,000

 

 

 

$

4.14

 

$

4.14

 

Jan ‘15 - Dec ‘15

 

 

 

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

 

 

 

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

 

 


In(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 above tables, “NYMEX-WTI” refers to NYMEX-West Texas Intermediate, “NYMEX-HH” refers to NYMEX-Henry Hub, “LLS” refers to Light Louisiana Sweetweighted average floor and “HSC” refers to Houston Ship Channel.ceiling value.

 

OilCommodity 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 earyear ended December 31, 20142016 would be as follows (in $ ‘000s):

 

Effect on profit before tax Increase/(decrease)

 

 

 

Oil

 

 

 

—improvement in oil price of $10 per Bbl

 

$

(2,400

)

—decline in oil price of $10 per Bbl

 

3,041

 

Gas

 

 

 

—improvement in gas price of $0.50 per Mcf

 

$

(120

)

—decline in gas price of $0.50 per Mcf

 

120

 

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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, 2014,2016, we had three customersone customer that owed more than $1.0us approximately $1.5 million each and accounted for approximately 75%21% of total accrued revenue receivables. There wasIn addition, the Group had one customer with balances greater than $5.0joint-interest partner that owed the Group approximately $4.0 million accounting for approximately 56% of total accrued revenue receivables.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.

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.

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, 2014, under the supervision and2016, our management, with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation ofhas 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 suchthis evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures arewere 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 isare (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s 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 disclosure.disclosures.

 

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

 

This annual report does not include a reportOur management assessed the effectiveness of management’s assessment regardingour internal control over financial reporting or an attestation reportas of the company’s registered public accounting firm due to a transition period establishedyear ended December 31, 2016. In making this assessment, our management used the criteria set forth by rulesthe Committee of Sponsoring Organizations of the SecuritiesTreadway Commission in Internal Control — Integrated Framework (2013). Based on management’s assessment and Exchange Commission for newly public companies.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.

 

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(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. - 6.A—Directors, Senior Management and Senior Management”Employees” for Mr. Hannes’s experience and qualifications.

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 the 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.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 periods indicated.years ended December 31, 2016 and 2015, respectively.

 

 

 

Year Ended
December 31,

 

 

 

2014

 

2013

 

Audit fees (a)

 

$

673,642

 

$

520,996

 

Audit - related fees

 

 

 

Tax fees (b)

 

68,815

 

76,708

 

Other services (c)

 

 

47,783

 

Total

 

$

742,457

 

$

645,487

 

 

 

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 20132016 and 20142015 consisted of:

·Auditof the audit of  the Company’s annual financial statements;

·Review and the review of the Company’s half-year financial statements; and

·Servicesstatements.  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 SEC matters.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 2013 and 20142015 consisted of tax compliance and tax planning advice.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.

(c) Fees for other services billed in 2013 consisted of non-audit services related to the acquisition of Texon.

 

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

 

Not applicable.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.

Item 16H.  Mine Safety Disclosure

 

Not applicable.

 

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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 well.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.

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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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Table of Contents

 

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.

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Table of Contents

 

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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Table of Contents

 

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.

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Table of Contents

 

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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Table of Contents

 

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

 

Unaudited Pro Forma Condensed Consolidated Financial Statements:

F-2

Introduction

F-2

Unaudited Pro Forma Condensed Consolidated StatementReport of Profit or Loss for the Year Ended December 31, 2014

F-3

Consolidated Financial Statements for December 31, 2014 and 2013 and the Years Then Ended:

Report ofIndependent Registered Public Accounting Firm

F-4F-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 StatementStatements of Financial PositionChanges in Equity for the Years Ended December 31, 2016, 2015 and 2014

F-6

Consolidated StatementStatements of Changes in EquityCash Flows for the Years Ended December 31, 2016, 2015 and 2014

F-7

Consolidated Statement of Cash Flows

F-8

Notes to the Consolidated Financial Statements

F-9

Consolidated Financial Statements for December 31, 2013 and the Year Then Ended:

Report of Registered Public Accounting Firm

F-60

Consolidated Statement of Profit or Loss and Other Comprehensive Income

F-61

Consolidated Statement of Financial Position

F-62

Consolidated Statement of Changes in Equity

F-63

Consolidated Statement of Cash Flows

F-64

Notes to the Consolidated Financial Statements

F-65

Consolidated Financial Statements for December 31, 2012 and the Six- Month Period Then Ended:

Reports of Registered Public Accounting Firms

F-102

Consolidated Statement of Profit or Loss and Other Comprehensive Income

F-103

Consolidated Statement of Financial Position

F-104

Consolidated Statement of Changes in Equity

F-105

Consolidated Statement of Cash Flows

F-106

Notes to the Consolidated Financial Statements

F-107F-8

 

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Table of Contents

 

SUNDANCE ENERGY AUSTRALIA LIMITED

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Denver-Julesburg Assets DivestitureREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

On July 27, 2014,To the Company sold its entire interest inshareholders and board of directors of
Sundance Energy Australia Limited

We have audited the Denver-Julesburg assets for net proceedsaccompanying consolidated statement of $108.8 million,financial position of which includes the reimbursementSundance Energy Australia Limited as of capital expenditures on 8 gross (3.1 net) non-operated horizontal wells in the Denver-Julesburg. The Company’s Denver-Julesburg assets included approximately 5,100 net acres in the Wattenberg field,December 31, 2016, and the remaining northern Niobrara projects including the Twister, Bull Canyon and Silo prospects. In connection with the sale of the Denver-Julesburg assets, the Company elected “like-kind exchange” treatment under U.S. Internal Revenue Code Section 1031, which provides for deferral of the gain if the proceeds are used to acquire “like-kind property” within six months of the closing of the transaction. The Company deferred a majority of the taxable on the sale of the Denver-Julesburg by acquiring qualified replacement properties.

Pro Forma Condensed Consolidated Financial Statements

The following unaudited pro forma condensed consolidated financial statements are presented to give effect to the disposition of the Denver-Julesburg assets as if these transactions had occurred on January 1, 2014 for the unaudited pro forma condensedrelated consolidated statement of profit or loss. The disposition of the Company’s remaining Bakken assets in July 2014 were excluded from these unaudited pro forma financial statements due to the insignificance of the disposition.

The unaudited pro forma condensedloss and other comprehensive income (loss), consolidated financial statements are provided for illustrative purposes only, and are not intended to represent or be indicative of the profit or loss of the Company that would have been recorded had the disposition of the Denver-Julesburg assets been completed as of the dates presented and should not be taken as representative of the future profit or loss of the Company. The unaudited condensed consolidated financial statements do not reflect the impact of any potential operational efficiencies, cost savings or economies of scale that the Company may achieve with respect to the consolidated operations. Additionally, the pro forma statement of profit or loss does not include non-recurring charges or creditschanges in equity, and the related tax effects which result directly from the transactions.

The unaudited pro forma condensedconsolidated statement of the profit or losscash flows for the year ended December 31, 2014, which presents our operations as if2016. These consolidated financial statements are the dispositionresponsibility of the Denver-Julesburg assets had occurredCompany’s management. Our responsibility is to express an opinion on January 1, 2014, has been derived from the following: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 profit or lossSundance Energy Australia Limited as of December 31, 2016, and the results of its operations and its cash flows for the year ended December 31, 2014; and2016, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ DELOITTE TOUCHE TOHMATSU

Sydney, Australia

April 28, 2017

 

·F-Denver-Julesburg statement of profit or loss for the period from January 1, 2014 through July 27, 2014, the date the assets were sold.

As the Denver-Julesburg divestiture has been reflected in the Company’s statement of financial position as at December 31, 2014, there is no impact to the pro forma condensed statement of financial position as a result of those transactions.

The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the historical consolidated financial statements and accompanying notes contained in the referenced financial statements.

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SUNDANCE ENERGY AUSTRALIA LIMITED

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF PROFIT OR LOSS

FOR THE YEAR ENDED DECEMBER 31, 2014

 

 

Sundance
Historical
US$’000

 

Denver-Julesburg
Historical
US$’000

 

Sundance
Pro Forma
Consolidated
As Adjusted
US$’000

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue (net of transportation)

 

$

159,793

 

$

(11,528

)

$

148,265

 

Lease operating and production expenses

 

(20,489

)

1,597

 

(18,892

)

 

 

 

 

 

 

 

 

Depreciation and amortization expense

 

(85,584

)

1,383

 

(84,201

)

Employee benefits expense

 

(4,979

)

 

(4,979

)

Administrative expense

 

(10,548

)

 

(10,548

)

Finance cost

 

(699

)

 

(699

)

Net gain (loss) on sale of non-current assets

 

48,604

 

(47,679

)

925

 

Gain on commodity hedging

 

11,009

 

 

11,009

 

Exploration expense

 

(10,934

)

 

(10,934

)

Impairment expense

 

(71,212

)

 

(71,212

)

Other income loss

 

(481

)

 

(481

)

Profit (loss) before income tax

 

14,480

 

(56,227

)

(41,747

)

 

 

 

 

 

 

 

 

Income tax benefit (expense)

 

841

 

21,480

)

22,321

 

Profit (loss) attributable to owners of the Company

 

$

15,321

 

$

(34,747

)

$

(19,426

)

Earnings per share

 

 

 

 

 

 

 

Basic earning

 

$

0.03

 

 

 

$

(0.04

)

Diluted earnings

 

$

0.03

 

 

 

$

(0.04

)

F-3



Table of Contents

 

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, 20142015 and 2013,2014, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity and cash flows for each of the twothree years in the period ended December 31, 2014.2015. 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, 20142015 and 2013,2014, and the consolidated results of its operations and its cash flows for each of the twothree years in the period ended December 31, 2014,2015, 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

Sydney, Australia

680 George Street

Sydney NSW 2000

Australia

May 15, 2015

 

F-4F-3



Table of Contents

 

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

 

 

For the year ended 31 December

 

Note

 

2014
US$’000

 

2013
US$’000

 

 

 

 

 

 

 

 

 

Oil and natural gas revenue

 

3

 

159,793

 

85,345

 

Lease operating and production tax expense

 

4

 

(20,489

)

(18,383

)

General and administrative expense

 

5

 

(15,527

)

(15,297

)

Depreciation and amortisation expense

 

16, 19

 

(85,584

)

(36,225

)

Impairment expense

 

17

 

(71,212

)

 

Exploration expense

 

18

 

(10,934

)

 

Finance costs

 

 

 

(699

)

232

 

Gain on sale of non-current assets

 

6

 

48,604

 

7,335

 

Gain (loss) on derivative financial instruments

 

 

 

11,009

 

(554

)

Other income

 

 

 

(481

)

(944

)

 

 

 

 

 

 

 

 

Profit before income tax

 

 

 

14,480

 

21,509

 

 

 

 

 

 

 

 

 

Income tax benefit/(expense)

 

7

 

841

 

(5,567

)

 

 

 

 

 

 

 

 

Profit attributable to owners of the Company

 

 

 

15,321

 

15,942

 

 

 

 

 

 

 

 

 

Other comprehensive income

 

 

 

 

 

 

 

Items that may be reclassified subsequently to profit or loss:

 

 

 

 

 

 

 

Exchange differences arising on translation

 

 

 

 

 

 

 

of foreign operations (no income tax effect)

 

 

 

684

 

(421

)

Other comprehensive income (loss)

 

 

 

684

 

(421

)

 

 

 

 

 

 

 

 

Total comprehensive income

 

 

 

 

 

 

 

attributable to owners of the Company

 

 

 

16,005

 

15,521

 

 

 

 

 

 

 

 

 

Earnings per share (cents)

 

 

 

 

 

 

 

Basic earnings

 

10

 

2.9

 

3.9

 

Diluted earnings

 

10

 

2.9

 

3.8

 

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

 

F-5F-4



Table of Contents

 

CONSOLIDATED STATEMENTSTATEMENTS OF FINANCIAL POSITION

For the year ended 31 December

 

Note

 

2014
US$’000

 

2013
US$’000

 

 

Note

 

2016
US$’000

 

2015
US$’000

 

 

 

 

 

 

(Restated — see
Note 7)

 

CURRENT ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

11

 

69,217

 

96,871

 

 

 

 

$

17,463

 

$

3,468

 

Trade and other receivables

 

12

 

25,994

 

28,748

 

 

12

 

9,786

 

11,508

 

Derivative financial instruments

 

13

 

7,801

 

 

 

13

 

 

9,967

 

Income tax receivable

 

 

 

2,697

 

 

 

 

 

5,204

 

5,616

 

Other current assets

 

15

 

8,336

 

4,038

 

 

16

 

4,078

 

4,154

 

CURRENT ASSETS

 

 

 

114,045

 

129,657

 

Assets held for sale

 

6

 

 

11,593

 

 

14

 

18,309

 

90,632

 

TOTAL CURRENT ASSETS

 

 

 

114,045

 

141,250

 

 

 

 

54,840

 

125,345

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NON-CURRENT ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development and production assets

 

16

 

519,013

 

312,230

 

 

17

 

338,709

 

250,922

 

Exploration and evaluation expenditure

 

18

 

155,130

 

166,144

 

 

18

 

34,366

 

26,323

 

Property and equipment

 

19

 

1,554

 

1,047

 

 

20

 

1,211

 

1,382

 

Derivative financial instruments

 

13

 

1,782

 

176

 

 

13

 

279

 

3,950

 

Deferred tax assets

 

24

 

3,998

 

2,303

 

 

25

 

2,683

 

1,913

 

Other non-current assets

 

20

 

998

 

2,019

 

TOTAL NON-CURRENT ASSETS

 

 

 

682,475

 

483,919

 

 

 

 

377,248

 

284,490

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL ASSETS

 

 

 

796,520

 

625,169

 

 

 

 

$

432,088

 

$

409,835

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CURRENT LIABILITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade and other payables

 

21

 

46,861

 

62,811

 

 

21

 

$

3,579

 

$

21,588

 

Accrued expenses

 

21

 

72,333

 

66,273

 

 

21

 

19,995

 

19,883

 

Income tax payable

 

 

 

 

11,443

 

Derivative financial instruments

 

13

 

130

 

335

 

 

13

 

4,579

 

 

CURRENT LIABILITIES

 

 

 

119,324

 

140,862

 

Provisions, current

 

22

 

2,726

 

 

Liabilities held for sale

 

6

 

 

109

 

 

14

 

941

 

744

 

TOTAL CURRENT LIABILITIES

 

 

 

119,324

 

140,971

 

 

 

 

31,820

 

42,215

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NON-CURRENT LIABILITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

13

 

 

31

 

Credit facilities, net of deferred financing fees

 

22

 

128,805

 

29,141

 

 

23

 

188,249

 

187,743

 

Restoration provision

 

23

 

8,866

 

5,074

 

 

24

 

7,072

 

3,088

 

Other provisions, non-current

 

22

 

3,299

 

 

Deferred tax liabilities

 

24

 

102,668

 

102,711

 

 

25

 

 

 

Derivative financial instruments

 

13

 

3,215

 

 

Other non-current liabilities

 

 

 

1,851

 

 

 

 

 

610

 

420

 

TOTAL NON-CURRENT LIABILITIES

 

 

 

242,190

 

136,957

 

 

 

 

202,445

 

191,251

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TOTAL LIABILITIES

 

 

 

361,514

 

277,928

 

 

 

 

$

234,265

 

$

233,466

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NET ASSETS

 

 

 

435,006

 

347,241

 

 

 

 

$

197,823

 

$

176,369

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

EQUITY

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Issued capital

 

25

 

306,853

 

237,008

 

 

26

 

373,585

 

308,429

 

Share option reserve

 

26

 

7,550

 

5,635

 

Foreign currency translation

 

26

 

(832

)

(1,516

)

Retained earnings

 

 

 

121,435

 

106,114

 

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

 

 

 

435,006

 

347,241

 

 

 

 

$

197,823

 

$

176,369

 

 

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

 

F-6F-5



Table of Contents

 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

Issued
Capital
US$’000

 

Share
Option
Reserve
US$’000

 

Foreign
Currency
Translation
Reserve
US$’000

 

Retained
Earnings
US$’000

 

Total
US$’000

 

 

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 2012

 

58,694

 

4,045

 

(1,095

)

90,172

 

151,816

 

Balance at 31 December 2013

 

237,008

 

5,635

 

(1,516

)

106,114

 

347,241

 

Profit attributable to owners of the Company

 

 

 

 

15,942

 

15,942

 

 

 

 

 

15,321

 

15,321

 

Other comprehensive loss for the year

 

 

 

(421

)

 

(421

)

 

 

 

684

 

 

684

 

Total comprehensive loss

 

 

 

(421

)

15,942

 

15,521

 

 

 

 

684

 

15,321

 

16,005

 

Shares issued in connection with:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

a) Merger with Texon

 

132,092

 

 

 

 

132,092

 

b) Private placement

 

47,398

 

 

 

 

47,398

 

c) Exercise of stock options

 

813

 

 

 

 

813

 

Cost of capital raising, net of tax

 

(1,989

)

 

 

 

(1,989

)

Stock compensation value of services

 

 

1,590

 

 

 

1,590

 

Balance at 31 December 2013

 

237,008

 

5,635

 

(1,516

)

106,114

 

347,241

 

 

 

 

 

 

 

 

 

 

 

 

Profit attributable to owners of the Company

 

 

 

 

15,321

 

15,321

 

Other comprehensive income for the year

 

 

 

684

 

 

684

 

Total comprehensive income

 

 

 

684

 

15,321

 

16,005

 

Shares issued in connection with:

 

 

 

 

 

 

 

 

 

 

 

a) Private placement

 

72,178

 

 

 

 

72,178

 

 

72,178

 

 

 

 

72,178

 

b) Exercise of stock options

 

260

 

 

 

 

260

 

 

260

 

 

 

 

260

 

Cost of capital raising, net of tax

 

(2,593

)

 

 

 

(2,593

)

 

(2,593

)

 

 

 

(2,593

)

Stock compensation value of services

 

 

1,915

 

 

 

1,915

 

Share based compensation value of services

 

 

1,915

 

 

 

1,915

 

Balance at 31 December 2014

 

306,853

 

7,550

 

(832

)

121,435

 

435,006

 

 

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 with private 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

 

F-7F-6



Table of Contents

 

CONSOLIDATED STATEMENTSTATEMENTS OF CASH FLOWS

 

For the year ended 31 December

 

Note

 

2014
US$’000

 

2013
US$’000

 

 

Note

 

2016
US$’000

 

2015
US$’000

 

2014
US$’000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Receipts from sales

 

 

 

170,442

 

84,703

 

 

 

 

64,749

 

99,423

 

170,442

 

Payments to suppliers and employees

 

 

 

(29,967

)

(21,765

)

 

 

 

(32,634

)

(49,639

)

(29,967

)

Settlements of restoration provision

 

 

 

(110

)

(71

)

 

Interest received

 

 

 

201

 

126

 

 

 

 

 

107

 

201

 

Derivative proceeds, net

 

 

 

(3

)

253

 

Income taxes paid, net

 

 

 

(12,586

)

(671

)

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

 

128,087

 

62,646

 

 

30

 

42,660

 

64,469

 

128,087

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Payments for development expenditure

 

 

 

(361,950

)

(154,700

)

 

 

 

(64,130

)

(144,316

)

(361,950

)

Payments for exploration expenditure

 

 

 

(39,616

)

(20,006

)

 

 

 

(2,852

)

(20,339

)

(39,616

)

Payments for acquisition of oil and gas properties

 

 

 

(35,606

)

(141,963

)

 

2

 

(23,506

)

(15,023

)

(35,606

)

Sale of non-current assets

 

 

 

115,284

 

37,848

 

 

3

 

7,141

 

41

 

115,284

 

Transaction costs related to sale of non-current assets

 

 

 

(278

)

(161

)

 

 

 

 

 

(278

)

Cash acquired from merger

 

 

 

 

114,690

 

Cash (paid) received from escrow and deposit accounts, net

 

 

 

(102

)

837

 

Payments for plant and equipment

 

 

 

(967

)

(900

)

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

 

 

 

(323,235

)

(164,355

)

 

 

 

(79,991

)

(180,771

)

(323,235

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from the issuance of shares

 

 

 

72,438

 

48,211

 

 

 

 

67,499

 

 

72,438

 

Payments for costs of capital raisings

 

 

 

(3,778

)

(2,654

)

 

 

 

(3,330

)

 

(3,778

)

Payments for acquisition related costs

 

 

 

 

(533

)

Borrowing costs paid

 

 

 

(1,065

)

(569

)

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

 

 

 

165,000

 

15,000

 

 

 

 

 

207,000

 

165,000

 

Repayments from borrowings

 

 

 

(65,000

)

(15,000

)

 

 

 

(250

)

(145,000

)

(65,000

)

NET CASH PROVIDED BY FINANCING ACTIVITIES

 

 

 

167,595

 

44,455

 

 

 

 

51,776

 

50,403

 

167,595

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net decrease in cash held

 

 

 

(27,553

)

(57,254

)

Net increase (decrease) in cash held

 

 

 

14,445

 

(65,899

)

(27,553

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash at beginning of period

 

 

 

96,871

 

154,110

 

Cash and cash equivalents at beginning of year

 

 

 

3,468

 

69,217

 

96,871

 

Effect of exchange rates on cash

 

 

 

(101

)

15

 

 

 

 

(450

)

150

 

(101

)

CASH AT END OF PERIOD

 

11

 

69,217

 

96,871

 

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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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES

 

The consolidated financial report of Sundance Energy Australia Limited (“SEAL”) and its wholly owned subsidiaries, (collectively, the “Company”, “Consolidated Group” or “Group”), for the year ended 31 December 20142016 was authorised for issuance in accordance with a resolution of the Board of Directors on 3130 March 2015. The Group has2017.  Refer to Note 35 for listing of the power to amend and reissue the financial report.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 derivativethe revaluation of certain non-current assets and financial instruments, which are measured at fair value.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.  The consolidated financial statements incorporate the assets and liabilities of all entities controlled by SEAL asAs at 31 December 20142016 and the results2015, all of allits controlled entities for the year then ended.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/(income)(benefit) and deferred income tax expense/(income)(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.

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

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 agreed to implementimplemented the income tax consolidation regime, with Sundance Energy Australia Limited being the head company of the newly consolidated group. Under this regime the group entities will beare taxed as a single taxpayer.  Whilst this choice is yet to be communicated to the Australian Taxation Office, it is intended to be communicated prior to lodgement of the 31 December 2014 income tax return and will be effective from 1 January 2014. Sundance Energy Australia Limited and its wholly-owned Australian controlled entities intend to enter into a Tax Sharing Agreement and Tax Funding Agreement in due course.

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

 

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

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

b)Exploration and Evaluation Expenditure

 

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

 

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

 

The carrying amounts of the Group’s exploration and evaluation assets are reviewed at each reporting date in conjunction with the impairment review process referred to in Note 1(f), to determine whether any of impairment indicators exists.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 income statement.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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c)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.

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

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

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

Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the group and the cost of the item can be measured reliably. All other repairs  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 being proved developed reserves and probable developed reserves, over the life of an asset or group of assets.

 

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

 

GainsImpairment

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.

 

d)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.

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

Finance leases are capitalised by recording an asset and a liability at the lower of the amounts equal to the fair value of the leased property or the present value of the minimum lease payments, including any guaranteed residual values. Lease payments are allocated between the reduction of the lease liability and the lease interest expense for the period.

 

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.

 

e)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 and interest rate swaps.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. Subsequent to initial recognition, derivative financial instruments are recognisedvalue and remeasured at fair value.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 held for tradingacquired principally for the purpose of short term profit taking, when they are derivatives not held for hedging purposes, or designated as such to avoid an accounting mismatch or to enable performance evaluation where a group of financial assets is managed by key management personnel on a fair value basisselling in accordance with a documented risk management or investment strategy.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.

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

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.

iii)Held-to-maturity investments

Held-to-maturity investments are non-derivative financial assets that have fixed maturities and fixed or determinable payments, and it is the Group’s intention to hold these investments to maturity. They are subsequently measured at amortised cost using the effective interest rate method.

iv)Available-for-sale financial assets

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

v)Financial liabilities

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

 

Derecognition

 

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

 

f)Impairment of Non-Financial Assets

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

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

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

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

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Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

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

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

Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to external market analysts’ forecasts, current spot prices and forward curves.  At 31 December 2014, future NYMEX strip prices, adjusted for basis differentials, were applied in 2015 and gradually increased through 2016 to $75/bbl in 2017 and thereafter.

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.

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 2014 or 2013.

g)Foreign Currency Transactions and Balances

 

Functional and presentation currency

 

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

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

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;

·                  incomerevenues and expenses are translated to USD using the exchange rate at average exchange rates for the period;date of transaction; and

·                  retained profits and issued capital and paid-in-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.

 

h)e)Employee Benefits

 

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

 

Restricted Share Unit Plan

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 actualfair value of time-lapse RSUs awarded annually, are modified according to actual results and generally vest in four equal tranches beginningis determined based on the price of Company ordinary shares on the date of grant date and eachexpense 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 first three subsequent anniversaries.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.

 

i)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.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued31 December 2016, the Company had recognized provisions related to a third-party refracturing agreement ($6.0 million) and office space consolidation ($0.3 million).

 

j)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 unrestricted escrow accounts that management expects to be used to settle current liabilities, capital or operating expenditures, or complete acquisitions and bank overdrafts.

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k)h)Revenue

 

Revenue from the sale of goodsoil and natural gas is recognised upon the delivery of goodsproduct to the customer.  Revenuepurchaser 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 renderingreserves in the underlying properties.  The Company had not recognized an imbalance on the consolidated statement of a service is recognised upon the delivery of the service to the customers. 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”).

 

l)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 at 100 percent equal to $3.4of $1.1 million,$1.6 million and $1.3$3.4 million for the years ended 31 December 20142016, 2015 and 2013,2014 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.

 

m)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.

 

n)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.

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

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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o)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.  The company did not have any assets classified as held for sale as at 31 December 2014.  As at 31 December 2013, all of2016, based upon the Company’s Willistonintent and anticipated ability to sell an interest in these properties, werethe 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.

 

p)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. Management preparesThe Company engaged an independent petroleum engineering firm, Ryder Scott Company to prepare its reserve estimates which conform to guidelines prepared by the Society of Petroleum Engineers. Management also prepares reserve estimates under SEC guidelines.  Reserve estimates conforming to the guidelines prepared by the Society of Petroleum Engineers are utilized for accounting purposes.  These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period, and as additional geological and production data isare generated during the course of operations.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

 

Impairment of Non-Financial Assets

 

The Group assesses impairment at each reporting date by evaluating conditions specific to the Group that may lead to impairment of assets. Where an indicator of impairment exists, the recoverable amount of the cash-generating unit to which the assets belong is then estimated based on the present value of future discounted cash flows. For development and production assets, the expected future cash flow estimation is always based on a number of factors, variables and assumptions, the most important of which are estimates of reserves, future production profiles, commodity prices and costs.  In most cases, the present value of future cash flows is most sensitive to estimates of future oil price and discount rates. A change in the modeled assumptions in isolation could materially change the recoverable amount. However, due to the interrelated nature of the assumptions, movements in any one variable can have an indirect impact on others and individual variables rarely change in isolation. Additional,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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Table of Contents

 

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 DepreciationDepletion

 

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continued

 

The life of each item has regard to both its physical life limitations and present assessments of economically recoverable reserves of the field at which the asset is located.  Economically recoverable reserves are defined as proved developed and probable developed reserves.  These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure.  The calculation of the units of production rate of depreciationdepletion 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.

 

Stock BasedShare-based Compensation

 

The Group’s policy for stock basedshare-based compensation is discussed in Note 1 (h)(g).  The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances.  StockCertain 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 stock optionsthese 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 term, including a forfeiture rate, if appropriate.volatility of the Company’s ordinary share price when valuing these awards.

 

q)n)Change in Accounting EstimateRounding of Amounts

 

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

r)Rounding of Amounts

The Company is of a kind referred to in Class Order 98/100 issued by the Australian Securities and Investment Commission relating to rounding of(“ASIC”) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191, amounts in the financial statements. Amountsstatements have been rounded to the nearest thousand.

 

s)o)Parent Entity Financial Information

 

The financial information for the parent entity, SEAL (“Parent Company”), also the ultimate parent, discussed in Note 34,36, 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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Table of Contents

t)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.

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSs)

NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continuedN

u)    Adoption of Newew and Revised Accounting Standards

 

During the current reporting period theThe 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 applicable to its operations which became mandatory.  The nature and effect of selected new standards and amendmentshas had no significant impact on the Group’s consolidated financial report are described below. Adoption ofaccounting policies or the other new mandatorily applicable standards did not have a material impact onamounts reported during the financial statement, financial position or performance of the Group.

AASB 2011-4 - Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure

This standard removes the requirements to include individual key management personnel disclosures in the notes to and forming part of the Financial Report.  This standard also removes the individual KMP disclosure requirements for all disclosing entities in relation to equity holdings, loans and other related party transactions.

Amendments to IAS 32 - Offsetting Financial Assets and Financial Liabilities

The amendments to IAS 32 clarify the requirements relating to the offset of financial assets and financial liabilities.  Specifically, the amendments clarify the meaning of ‘currently has a legally enforceable right of set-off’ and ‘simultaneous realization and settlement’.  As the Group does not have any financial assets and financial liabilities that qualify for offset, the application of the amendments has had no impact on the disclosure or the Group’s consolidated financial statements.

Recently issued accounting standards to be applied in future reporting periods: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 withwhen 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 assets and financial liabilities.  The final version of IFRS 9 supersedes all previous versions of the standard.  However, for annual periods beginning before 1 January 2018, an entity may elect to apply those earlier versions of IFRS 9 if the entity’s relevant date of initial application is before 1 February 2015.instruments, including new general hedge accounting requirements.  The effective date of this standard is for fiscal years beginning on or after 1 January 2018.2018, 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.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTEstatements when it adopts the standard 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES continuedJanuary 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.Step 1:              Identify the contract(s) with a customer

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

·3.Step 3:              Determine the transaction price.

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

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

 

Under AASB 15/IFRS 15, an entity recognizes revenue when (or as) a performance obligation is satisfied, i.e. when ‘control’ of the goods or services underlying the particular performance obligation is transferred to the customer.  The effective date of this standard is for fiscal years beginning on or after 1 January 2017.  Management2018.  Although the Company is currentlystill 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 ofon the new standard andCompany’s consolidated financial statements other than additional disclosures.  The Company plans to adopt the newstandard 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 required effective date.1 January 2019.

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

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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Table of Contents

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.

 

Acquisition in 2013

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

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

Fair value of assets acquired:

Trade and other receivables

5,604

Other current assets

456

Development and production assets

53,937

Exploration and evaluation assets

150,474

Prepaid drilling and completion costs

3,027

Amount attributable to assets acquired

213,498

Fair value of liabilities assumed:

Trade and other payables

119

Accrued expenses

37,816

Restoration provision

277

Deferred tax liabilities

16,884

Amount attributable to liabilities assumed

55,096

Net assets acquired

158,402

Purchase price:

Cash and cash equivalents, net of cash acquired

26,310

Issued capital

132,092

Total consideration paid

158,402

The net assets recognized in the 31 December 2013 financial statements were based on a provisional assessment of their fair value.

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Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 — BUSINESS COMBINATIONS continuedDISPOSALS OF NON CURRENT ASSETS

 

Since the acquisition date of 8 March 2013 through 31Disposals in 2016

In December 2013,2016, the Company has earned revenuedivested 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 $42.3 million and generated net income of $12.6 million. The following reflects the acquisition’s contribution to the Group as if the merger had occurred on 1 January 2013 instead of the closing date of 8 March 2013 (in thousands, except per share information):

Year ended
31 December 2013

Oil and natural gas revenue

5,163

Lease operating and production expenses

(1,150

)

Depreciation and amortization expense

(1,882

)

General and administrative expense

(667

)

Finance costs

(35

)

Profit before income tax

1,429

Income tax expense

(542

)

Proforma profit attributable to the period 1 January to 7 March 2013

887

Profit attributable to owners of the Company for the year

15,942

Adjusted profit attributable to the owners of the Company for the year

16,829

Adjusted basic earnings per ordinary share

4.1

Adjusted diluted earnings per ordinary share

4.0

The Company incurred $0.2 and $0.5$7.1 million for the years ended 31 December 2014 and 2013, respectively, for professional fees and services related to the Texon acquisition.  These amounts are includedacreage.  No gain or loss was recognized in general and administrative expense in the consolidated statementsstatement of profit orand loss and other comprehensive income and financing activities inrelated to the consolidated statement of cash flows, respectively.

NOTE 3 — REVENUE

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Oil revenue

 

144,994

 

79,365

 

Natural gas revenue

 

6,161

 

2,774

 

Natural gas liquid (NGL) revenue

 

8,638

 

3,206

 

Total revenue (net of royalties and transportation costs)

 

159,793

 

85,345

 

NOTE 4 — LEASE OPERATING AND PRODUCTION TAX EXPENSE

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Lease operating expense

 

(12,466

)

(11,378

)

Workover expense

 

(1,058

)

(743

)

Production tax expense

 

(6,965

)

(6,262

)

Total lease operating and production tax expense

 

(20,489

)

(18,383

)

F-24



Table of Contentssale.

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSDisposals in 2015

 

NOTE 5 — GENERAL AND ADMINISTRATIVE EXPENSES

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Employee benefits expense, including salaries and wages, net of capitalised overhead

 

(3,064

)

(4,553

)

General legal and professional fees

 

(4,661

)

(3,307

)

Corporate fees

 

(2,676

)

(2,344

)

Regulatory expenses

 

(1,374

)

(2,313

)

Share based payments expense

 

(1,915

)

(1,590

)

Rent

 

(631

)

(234

)

Other expenses

 

(1,206

)

(956

)

Total general and administrative expenses

 

(15,527

)

(15,297

)

The company capitalised overhead costs, including salaries, wages benefits and consulting fees, directly attributable toThere were no disposals of non current assets during the exploration, acquisition and development of oil and gas properties of $4.5 million and $2.9 million for the yearsyear ended 31 December 2014 and 2013, respectively.

NOTE 6 — GAIN ON SALE OF NON-CURRENT ASSETS2015.

 

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 $48.7$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.  As at 31 December 2013, the carrying costs of these assets were $11.6 million and were classified as held for sale.

For the Denver-Julesburg Basin sales proceeds, the Company elected to apply Section 1031 “like-kind exchange” treatment under the US tax rules, which allow deferral of the gain if the proceeds are used to acquire “like-kind property” within six months of the closing date of the transaction.  In addition, the US tax rules allow the deduction of all intangible drilling costs (“IDCs”) in the period incurred.  In January 2015, the Company deferred majority of the taxable gain on the sale of the Denver-Julesburg Basin by acquiring qualified replacement properties.

 

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Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSNOTE 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 — GAIN ON SALE OF NON-CURRENT ASSETS continuedGENERAL AND ADMINISTRATIVE EXPENSES

 

Disposals in 2013

 

 

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

)

 


In the fourth quarter of 2013, the Company sold all of its interests in the Phoenix prospect, located in the Williston Basin, for gross proceeds of $39.8 million.  It was determined that approximately $26.0 million of the Company’s carrying costs related to its Phoenix development(1)     Share based payment expense includes expense associated with restricted share units and production properties at the time of the disposal. The sale resulted in a pre-tax gain of $8.2 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 2013.   During 2014, the Company finalized adjustments to the purchase price for the Phoenix sale, which resulted in a net reduction of $0.9 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.deferred cash awards.  See Note 32.

 

The Company deferred majoritycapitalised 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 taxable gain on the sale of the Phoenix development by acquiring qualified replacement properties or utilizing IDCs from its development program.years ended 31 December 2016, 2015 and 2014 respectively.

 

NOTE 7 — INCOME TAX EXPENSE

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

a) The components of income tax expense comprise:

 

 

 

 

 

Current tax benefit/(expense)

 

(17

)

21,398

 

Deferred tax benefit/(expense)

 

858

 

(26,965

)

Total income tax benefit/(expense)

 

841

 

(5,567

)

 

 

 

 

 

 

b) The prima facie tax on income from ordinary activities

 

 

 

 

 

before income tax is reconciled to the income tax as follows:

 

 

 

 

 

 

 

 

 

 

 

Profit before income tax

 

14,480

 

21,509

 

 

 

 

 

 

 

Prima facie tax expense at the Group’s statutory income tax rate of 30% (2013:30%)

 

4,344

 

6,453

 

 

 

 

 

 

 

Increase (decrease) in tax expense resulting from:

 

 

 

 

 

 

 

 

 

 

 

-  Difference of tax rate in US controlled entities

 

220

 

1,607

 

-  Impact of direct accounting from US controlled entities (1)

 

(3,044

)

72

 

-  Employee options

 

428

 

 

-  Excess depletion

 

(489

)

 

-  Other allowable items

 

295

 

144

 

-  Tax adjustments relating to prior years

 

(1,063

)

(984

)

-  Change in apportioned state tax rates in US controlled entities (2)

 

(992

)

(1,520

)

-  Tax consolidation election (3)

 

(3,058

)

 

-  Change in unrecognized tax losses

 

2,518

 

(205

)

 

 

 

 

 

 

Total Income tax (benefit)/expense

 

(841

)

5,567

 

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.

 

F-26F-21



Table of Contents

 

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

)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSF-22



Table of Contents

 

NOTE 7 — INCOME TAX EXPENSE continuedThe following is a summary of 2016, 2015 and 2014 income tax expense (benefit):

 

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

c) Unused tax losses and temporary differences for which

 

 

 

 

 

no deferred tax asset has been recognised at 30%

 

2,685

 

170

 

 

 

 

 

 

 

d) Deferred tax charged directly to equity:

 

 

 

 

 

-  Equity raising costs

 

1,147

 

665

 

-  Currency translation adjustment

 

(268

)

 

 

 

 

 

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)1)             The Oklahoma US state tax jurisdiction computes income taxes on a direct accounting basis.  AIn 2015, a significant portion of the 2014 impairmentimpairments related to this jurisdiction resulting in a deferred tax benefit of $3,044$3,165 creating deferred tax assets, all of which $2,064 were unrecognized.

 

(2)2)             TheIn 2014, the change in apportioned state tax ratesrate in US controlled entities is a result of the CompanyCompany’s disposing of its propertyproprety in Colorado (income tax rate of 4.63%) (2013: North Dakota with income tax rate of 4.53%) through a tax deferred sale and reinvesting the property in Texas (margin tax rate of 1%). 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.purposes

 

(3)3)             ThisIn 2014, this income tax benefit resultsresulted 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 evidenceevenidence of future taxable income for these Australian subsidiaries on a stand-alone basis.

F-23



Table of Contents

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 89 — KEY MANAGEMENT PERSONNEL COMPENSATION

 

a)Names and positions held of Consolidated Group key management personnel in office at any time during the financial period are:

Mr M Hannell     Chairman Non-executive

Mr E McCrady    Managing Director and Chief Executive Officer

Mr D Hannes       Director — Non-executive

Mr N Martin        Director — Non-executive

Mr W Holcombe Director — Non-executive

Ms C Anderson   Chief Financial Officer

Ms G Ford            Vice President of Exploration and Development

Based on her increased responsibilities due to the Company’s growth, Ms. Ford was deemed to be a KMP during the 2014 fiscal year. Prior to that time, Ms. Ford was not considered to be KMP

Other than Directors and Officers of the Company listed above, there are no additional key management personnel.

F-27



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8 — KEY MANAGEMENT PERSONNEL COMPENSATION continued

b)Key Management Personnel Compensation

 

The total cash remuneration paid to Directors and Key Management Personnel (“KMP”) of the Group during the year is as follows:

 

Year ended 31 December

 

2014
US$

 

2013
US$

 

 

2016
US$’000

 

2015
US$’000

 

2014
US$’000

 

 

 

 

 

 

 

 

 

 

 

 

 

Short term wages and benefits

 

2,001,893

 

1,864,751

 

 

1,298

 

1,467

 

1,465

 

Equity settled-options based payments

 

1,207,989

 

625,161

 

Share based payments (equity or cash settled) (1)

 

2,025

 

2,271

 

1,208

 

Post-employment benefit

 

56,882

 

55,416

 

 

49

 

52

 

57

 

 

3,266,764

 

2,545,328

 

 

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.

F-24



Table of Contents

 

c)b)Options Granted as Compensation

 

No options were granted as compensation during each of the years ended 31 December 20142016, 2015 and 20132014 to KMP from the Sundance Energy Employee Stock Option Plan. Options generally vest in five equal tranches of 20% onDuring 2015, the grant date and eachprevious option holders were notified that all of the four subsequent anniversariesCompany’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 the grant date.incremental fair value).

 

d)c)Restricted Share Units  Granted as Compensation

 

RSUs awarded as compensation were 1,451,9179,906,997 ($1.41.2 million fair value), 7,426,596 ($3.8 million fair value) and 623,2511,451,917 ($0.61.4 million fair value) during the years ended 31 December 20142016, 2015 and 2013,2014, 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 fromwas $1.5 million ($0.5 million fair value as at 31 December 2016) during the Sundance Energy Long Term Incentive Plan. RSUs generallyyear ended 31 December 2016.  Deferred cash awards vest in four equal tranches of 25%based on the grant date and eachappreciation of the three subsequent anniversaries of the grant date.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 910 — AUDITORS’ REMUNERATION

 

2014

 

2013

 

 

2016

 

2015

 

2014

 

Year ended 31 December

 

US$

 

US$

 

 

US$’000

 

US$’000

 

US$’000

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash remuneration of the auditor for:

 

 

 

 

 

 

 

 

 

 

 

 

Auditing or review of the financial report

 

428,888

 

90,941

 

 

461

 

463

 

429

 

Professional services related to filing of various Forms with the US Securities and Exchange Commission

 

244,754

 

430,055

 

 

 

13

 

245

 

Non-audit services related to Texon acquisition

 

 

76,708

 

Taxation services provided by the practice of auditor

 

68,815

 

47,783

 

 

 

61

 

69

 

Total remuneration of the auditor

 

742,457

 

645,487

 

 

461

 

537

 

743

 

 

F-28(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

F-25



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10 — EARNINGS PER SHARE (EPS)

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Profit for periods used to calculate basic and diluted EPS

 

15,321

 

15,942

 

 

 

Number
of shares

 

Number
of shares

 

- Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS

 

531,391,405

 

413,872,184

 

- Incremental shares related to options and restricted share units

 

3,208,214

 

2,685,150

 

- Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS

 

534,599,619

 

416,557,334

 

NOTE 11 — CASH AND CASH EQUIVALENTS

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Cash at bank and on hand

 

18,222

 

59,918

 

Cash equivalents in escrow accounts

 

50,995

 

36,953

 

Total cash and cash equivalents

 

69,217

 

96,871

 

As at(2) Incremental shares related to restricted share units were excluded from 31 December 20142016 and 2013,2015 weighted average number of ordinary shares outstanding during the Company had approximately $51.0 million and $37.0 million, respectively,period used in Section 1031 escrow accounts which are not limited in use, except thatcalculation of diluted EPS as the timing of tax payments willoutstanding shares would be accelerated if not used on qualified “like-kind property.”  As such,anti-dilutive to the balances have been included inloss per share calculation for the Company’s cash and cash equivalents in the consolidated statement of financial position and consolidated statement of cash flows as at 31 December 2014 and 2013, respectively.

F-29



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSperiod then ended.

 

NOTE 12 — TRADE AND OTHER RECEIVABLES

 

��

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Oil, natural gas and NGL sales

 

13,246

 

23,364

 

Joint interest billing receivables

 

11,587

 

5,353

 

Commodity hedge contract receivables

 

1,153

 

 

Other

 

8

 

31

 

Total trade and other receivables

 

25,994

 

28,748

 

As at 31 December 2013, the Group had a receivable balance of $11.7 million, which was outside normal trading terms (the receivable was past due but not impaired), offset by a payable balance of $16.7 million to the same debtor company (see Note 20 for additional information). The Company’s remaining Bakken assets were sold to the debtor company in July 2014, for approximately $14.0 million, including the settlement of the net liability due to the debtor company.

 

 

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 2014.2016 and 2015.

 

NOTE 13 — DERIVATIVE FINANCIAL INSTRUMENTS

 

2014

 

2013

 

 

2016

 

2015

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

US$’000

 

US$’000

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL ASSETS:

 

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments — commodity contracts

 

7,801

 

 

 

 

9,967

 

Non-current

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments — commodity contracts

 

1,675

 

 

 

279

 

3,950

 

Derivative financial instruments — interest rate swaps

 

107

 

176

 

Total financial assets

 

9,583

 

176

 

 

279

 

13,917

 

 

 

 

 

 

 

 

 

 

 

FINANCIAL LIABILITIES:

 

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments — commodity contracts

 

 

(188

)

 

4,579

 

 

Derivative financial instruments — interest rate swaps

 

(130

)

(147

)

Non-current

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments — commodity contracts

 

 

(31

)

 

3,215

 

 

Total financial liabilities

 

(130

)

(366

)

 

7,794

 

 

 

F-30F-26



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSNOTE 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 1415 — FAIR VALUE MEASUREMENT

 

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

 

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

 

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

 

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

 

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

 

Consolidated 31 December 2014
(US$’000)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

Assets measured at fair value

 

 

 

 

 

 

 

 

 

Derivative commodity contracts

 

 

9,476

 

 

9,476

 

Interest rate swap contracts

 

 

107

 

 

107

 

Development and production assets (1)

 

 

 

455,084

 

455,084

 

 

 

 

 

 

 

 

 

 

 

Liabilities measured at fair value

 

 

 

 

 

 

 

 

 

Interest rate swap contracts

 

 

(130

)

 

(130

)

 

 

 

 

 

 

 

 

 

 

Net fair value

 

 

9,453

 

455,084

 

464,537

 

F-27



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

 

Consolidated 31 December 2013
(US$’000)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Consolidated 31 December 2016
(US$’000)

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets measured at fair value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest rate swap contract

 

 

176

 

 

176

 

 

 

 

 

 

 

 

 

 

Derivative commodity contracts

 

 

279

 

 

279

 

Liabilities measured at fair value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative commodity contracts

 

 

(219

)

 

(219

)

 

 

(7,794

)

 

(7,794

)

Interest rate swap contracts

 

 

(147

)

 

(147

)

 

 

 

 

 

 

 

 

 

Net fair value

 

 

(190

)

 

(190

)

 

 

(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 20142016 and 2013,2015, 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.

 

F-31



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 14 — FAIR VALUE MEASUREMENT continued

Measurement of Fair Value

 

a)   Derivatives

 

Derivatives entered into by the CompanyThe Company’s derivative instruments consist of commodity contracts (primarily swaps and interest rate swaps.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 2014,2016, the Company had $95$125 million and $35$67 million of principal debt outstanding on the Senior Credit Facilityits Term Loan and the Junior CreditRevolving Facility, respectively. The estimated fair value of the Senior Credit Facility approximated its carrying amount due to the floating interest rate paid on such debt to be set for a period of three months or less.  The estimated fair value of the Junior Credit FacilityTerm Loan was approximately $41.8$123 million, based on indirect, observable inputs (Level 2) regarding interest rates available to the Company. The fair value of the Junior Credit FacilityTerm 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.

 

c)e)   Other Financial Instruments

 

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

 

NOTE 15 — OTHER CURRENT ASSETSF-

 

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

 

 

 

 

 

 

Cash advances to other operators

 

3,270

 

685

 

Escrow accounts

 

1,000

 

1,498

 

Oil inventory on hand, at cost

 

1,331

 

1,088

 

Equipment inventory, at cost

 

1,315

 

 

Prepaid expenses

 

1,401

 

753

 

Other

 

19

 

14

 

Total other current assets

 

8,336

 

4,038

 

F-3228



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSNOTE 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 1617 — DEVELOPMENT AND PRODUCTION ASSETS

 

 

2014

 

2013

 

 

2016

 

2015

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

US$’000

 

US$’000

 

 

 

 

 

 

 

 

 

 

 

Costs carried forward in respect of areas of interest in:

 

 

 

 

 

 

 

 

 

 

Development and production assets, at cost:

 

 

 

 

 

 

 

 

 

 

Producing assets

 

652,035

 

297,469

 

 

838,792

 

694,111

 

Wells-in-progress

 

56,043

 

55,636

 

 

4,997

 

38,210

 

Development and production assets, at cost:

 

708,078

 

353,105

 

Undeveloped assets

 

30,119

 

62,781

 

-Development and production assets, at cost:

 

873,908

 

795,102

 

Accumulated depletion

 

(117,613

)

(40,635

)

 

(258,613

)

(211,123

)

Provision for impairment

 

(71,452

)

(240

)

Total Development and Production Expenditure

 

519,013

 

312,230

 

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

 

312,230

 

79,729

 

 

250,922

 

519,013

 

Amounts capitalised during the period

 

350,196

 

219,121

 

 

57,893

 

76,831

 

Amounts transferred from exploration phase

 

59,209

 

31,999

 

 

 

4,898

 

Fair value of assets acquired

 

 

54,258

 

 

23,873

 

13,170

 

Allocation of working interest assets acquired

 

2,244

 

 

Exploratory dry hole costs previously included in wells-in progress

 

 

(2,416

)

Revision to restoration provision

 

3,238

 

(5,715

)

Depletion expense

 

(47,490

)

(93,429

)

Impairment expense

 

(3,409

)

(184,409

)

Development and production assets sold during the period

 

(5,030

)

 

Reclassifications from assets held for sale

 

77,021

 

 

Reclassifications to assets held for sale

 

 

(10,489

)

 

(18,309

)

(77,021

)

Impairment expense

 

(71,212

)

 

Depletion expense

 

(85,357

)

(36,294

)

Development and production assets, net of accumulated amortization, sold during the period

 

(48,297

)

(26,094

)

Balance at end of period

 

519,013

 

312,230

 

 

338,709

 

250,922

 

F-29



Table of Contents

 

Borrowing costs relating to drilling of development wells that have been capitalized as part of oil and gas properties during the year ended 31 December 2014 was $3.4 million (2013: $1.3 million). The interest capitalization rate for both years ended 31 December 20142016 and 2013 was 100%.

F-33



Table2015 were $1.1 million and $1.6 million, respectively.  The interest amounts capitalized as a percent of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSthe total bank interest incurred for years ended 31 December 2016 and 2015 were 6.7% and 14.1%, respectively.

 

NOTE 1718 — 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 2014,2016, 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.  Due to the change in the oil pricing environment at year-end, theThe 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 developmentits Mississippian/Woodward and productionCooper Basin assets.

F-30



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. TheFor 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, current spot prices and forward curves.  AtFuture 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, were applied in 2015 and gradually increased through 2016 to $75/bbl in 2017 and thereafter.

The Company applied a post-tax discount rate that has been applied to the above non-current assets wasof 8.0%.  The GroupManagement 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.

 

F-31



Table of Contents

Recoverable amounts and resulting impairment write-downsexpense recognized in conjunction with the Consolidated StatementsCompany’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 Profit or Loss and Other Comprehensive Incomeassets held for sale.

(2)  The total impairment expense for the year ended 31 December 2014 are presented in2016 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 below: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.

 

 

Carrying costs (1)

 

Recoverable
amount

 

Impairment

 

Cash-generating unit

 

US$’000

 

US$’000

 

US$’000

 

 

 

 

 

 

 

 

 

Development and production assets:

 

 

 

 

 

 

 

Eagle Ford

 

400,761

 

389,764

 

10,997

 

Mississippian/Woodford

 

125,535

 

65,320

 

60,215

 

Total development and production assets

 

526,296

 

455,084

 

71,212

 


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

 

The impairment chargeAny further adverse changes in any of $71.2 million noted above is primarily the key assumptions may result from the lower oil price environment.in future impairments.

 

F-34F-32



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 18 — EXPLORATION AND EVALUATION EXPENDITURE

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Costs carried forward in respect of areas of interest in:

 

 

 

 

 

Exploration and evaluation phase, at cost

 

156,680

 

167,694

 

Provision for impairment

 

(1,550

)

(1,550

)

Total Exploration and Evaluation Expenditure

 

155,130

 

166,144

 

 

 

 

 

 

 

a) Movements in carrying amounts:

 

 

 

 

 

Exploration and evaluation

 

 

 

 

 

Balance at the beginning of the period

 

166,144

 

33,439

 

Amounts capitalised during the period

 

39,670

 

14,770

 

Fair value of assets acquired

 

 

151,115

 

Allocation of working interest assets acquired

 

34,184

 

 

Exploration costs expensed (1)

 

(10,934

)

 

Reclassifications to assets held for sale

 

 

(1,104

)

Amounts transferred to development phase

 

(59,209

)

(31,999

)

Exploration tenements sold during the period

 

(14,725

)

(77

)

Balance at end of period

 

155,130

 

166,144

 


(1)The Company drilled three exploratory wells in the Anadarko Basin that did not have economically recoverable reserves (i.e. dry wells) and as such, all associated costs were written off.

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

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 1920 — PROPERTY AND EQUIPMENT

 

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Property and equipment, at cost

 

2,570

 

1,603

 

Accumulated depreciation

 

(1,016

)

(556

)

Total Property and Equipment

 

1,554

 

1,047

 

 

 

 

 

 

 

a) Movements in carrying amounts:

 

 

 

 

 

 

 

 

 

 

 

Balance at the beginning of the period

 

1,047

 

423

 

Amounts capitalised during the period

 

967

 

886

 

Depreciation expense

 

(460

)

(262

)

Balance at end of period

 

1,554

 

1,047

 

F-35



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 20 — OTHER NON-CURRENT ASSETS

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Escrow accounts

 

998

 

2,000

 

Other

 

 

19

 

Total other non-current assets

 

998

 

2,019

 

 

 

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

 

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Oil and natural gas property and operating related

 

117,117

 

123,938

 

Administrative expenses, including salaries and wages

 

2,077

 

5,146

 

Total trade, other payables and accrued expenses

 

119,194

 

129,084

 

At 31 December 2013, the Group had payable balances of $16.7 million which was outside normal payment terms, offset by a receivable balance of $11.7 million to the same creditor company (see Note 12 for additional information).  The Company’s remaining Bakken assets were sold to this company in July 2014, for approximately $14.0 million, including the settlement of the net liability.

 

 

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 — CREDIT FACILITIESOTHER PROVISIONS

 

 

 

2014

 

2013

 

Year ended 31 December

 

US$000

 

US$000

 

 

 

 

 

 

 

Senior Credit Facility

 

95,000

 

15,000

 

Junior Credit Facility

 

35,000

 

15,000

 

Total credit facilities

 

130,000

 

30,000

 

Deferred financing fees

 

(1,195

)

(859

)

Total credit facilities, net of deferred financing fees

 

128,805

 

29,141

 

 

 

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

 

 

 

Junior Credit Facility

In August 2013, Sundance Energy, Inc. (“Sundance Energy”), a wholly owned subsidiary ofDuring 2016, the Company entered into a second lien creditan agreement with Wells Fargo Energy Capital, Inc., as the administrative agent (the “Junior Credit Facility”Schlumberger Limited (“Schlumberger”), which provides for term loans to be made in a series of draws up to $100 million. The Junior Credit Facility matures in June 2018 and is secured by a second priority lien on substantially all of the Company’s assets. Upon entering into the Junior Credit Facility, the Company immediately borrowed $15 million pursuant tore-fracture five Eagle Ford wells.  Under the terms of the Junior Credit Facility andagreement, Schlumberger will be paid downfor the outstanding principalservices, 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 Senior Credit Facility. In May 2014,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 borrowing capacity increased to $35 million.  As at 31 December 2014, the borrowing capacityestimate of future obligations under the Junior Credit Facility remains at $35 million.operating leases, net of anticipated sublease income.   The Company’s office lease is in place through 2019.

 

F-36F-33



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2223 — CREDIT FACILITIES continued

 

 

 

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 principal amountRevolving 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 ½ year term (matures in November 2020). If upon any downward adjustment of the loans borrowed under our Junior Creditborrowing 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 is due in full on the maturity date.  and therefore had no borrowing availability as at 31 December 2016.

Interest on the Junior CreditRevolving 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) 8.50%LIBOR, plus 7% or (ii) a base rate (being, at our option, either (a) LIBOR for the applicable interest period (adjusted for Eurodollar Reserve Requirements) or (b) the greatest of (x) the prime rate announced by Wells Fargo Bank, N.A., (y) the federal funds rate plus 0.50% and (z) one-month adjusted LIBOR plus 1.00%), plus a margin of either 6.5% or 7.5%, based on the base rate selected.8%.

 

The Company is also required under our Junior Credit FacilityAgreement 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 debtRevolving Facility Debt to adjusted consolidated EBITDAX (as defined in the Junior Credit Facility), of not greater than 4.54.0 to 1.0 as of the last day of any fiscal quarter (beginning 30 September 2013); andquarter;

·                  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·                  An asset coverage ratio, consisting of PV10PV9% to consolidated debt,Total Debt (as defined in the Credit Facility), of not less than 1.51.50 to 1.0, as of certain test dates.1.0.

 

For the years ended 31 December 2014 and 2013, the Company capitalised $0.7 million and $0.3 million, respectively, of financing costs related to the Junior Credit Facility, which offset the principal balance. As at 31 December 2014 there was $35.0 million outstanding under the Company’s Junior Credit Facility.  As at 31 December 2014,2016, the Company was in compliance with all restrictive financial and other covenants under the Junior Credit Facility.

Senior Credit Facility

On 31 December 2012, Sundance Energy entered into a credit agreement with Wells Fargo Bank, N.A. (the “Senior Credit Facility”), pursuant to which up to $300 million is available on a revolving basis.  The borrowing base under the Senior Credit Facility is determined by reference to the value of the Company’s proved reserves.  The agreement specifies a semi-annual borrowing base redetermination and the Company can request two additional redeterminations each year.  The borrowing capacity was increased from prior year to $110 million as at 31 December 2014 based on Company reserves as at 31 December 2014.  As at 31 December 2014, the Company had $15 million undrawn on the Senior Credit Facility.  In conjunction with the increase in the borrowing base, the Company has expanded the syndicate of banks under the Senior Credit Facility.  With Wells Fargo as administrative agent, Bank of America Merrill Lynch and the Bank of Nova Scotia have now joined the banking group.

Interest on borrowed funds accrue, at the Company’s option, of i) LIBOR plus a margin that ranges from 175 to 275 basis points or ii) the Base Rate, defined as a rate equal to the highest of (a) the Federal Funds Rate plus ½ of 1%, (b) the Prime Rate, or (c) LIBOR plus a margin that ranges from 75 to 175 basis points. The applicable margin varies depending on the amount drawn.  The Company also pays a commitment that ranges from 37.5 to 50 basis points on the undrawn balance of the borrowing base.  The agreement has a five-year term and contains both negative and affirmative covenants, including minimum current ratio and maximum leverage ratio requirements consistent with the Junior Credit Facility’s. Certain development and production assets are pledged as collateral and the facility is guaranteed by the Parent Company.

For the years ended 31 December 2014 and 2013, the Company capitalised nil and $0.2 million, respectively, of financing costs related to the Senior Credit Facility, which offset the principal balance. As at 31 December 2014 there was $95.0 million outstanding under the Company’s Senior Credit Facility.  As at 31 December 2014, the Company was in compliance with all restrictive financial and other covenants under the Senior Credit Facility.

The Company capitalised $3.4 million and $1.3 million of interest expense during the years ended 31 December 2014 and 2013, respectively.

See Note 36 for discussion of credit facility refinance.

F-37



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSAgreement.

 

NOTE 2324 — RESTORATION PROVISION

 

The restoration provision represents the Company’s best estimate of the present value of restoration costs relating to the Company’sits oil and natural gas interests, which are expected to be incurred up to 2043.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.

 

 

 

2014

 

2013

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

 

Balance at the beginning of the period

 

5,074

 

1,228

 

New provisions

 

3,677

 

1,601

 

Changes in estimates

 

1,541

 

2,021

 

Disposals

 

(2,314

)

(146

)

New provisions assumed from acquisition

 

822

 

397

 

Reclassified to assets held for sale

 

 

(109

)

Unwinding of discount

 

66

 

82

 

Balance at end of period

 

8,866

 

5,074

 

F-34



Table of Contents

 

 

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 2425 — DEFERRED TAX ASSETS AND LIABILITIES

 

Deferred tax assets and liabilities are attributable to the following:

 

 

2014

 

2013

 

 

2016

 

2015

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

US$’000

 

US$’000
(Restated)

 

 

 

 

 

 

 

 

 

 

 

Net deferred tax assets:

 

 

 

 

 

 

 

 

 

 

Share issuance costs

 

2,172

 

1,069

 

 

1,534

 

1,342

 

Net operating loss carried forward

 

1,826

 

473

 

 

2,636

 

3,659

 

Unrecognized foreign currency gain (loss)

 

 

761

 

Accrued interest

 

(2,756

)

(2,847

)

Development and production expenditure

 

1,269

 

(241

)

Other

 

 

 

Total net deferred tax assets

 

3,998

 

2,303

 

 

2,683

 

1,913

 

 

 

 

 

 

 

 

 

 

 

Deferred tax liabilities:

 

 

 

 

 

 

 

 

 

 

Development and production expenditure

 

(106,343

)

(114,042

)

 

(10,654

)

1,509

 

Derivatives

 

(3,351

)

 

 

 

(4,371

)

 

 

 

 

 

Other

 

 

(32

)

Offset by deferred tax assets with legally enforceable right of set-off:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net operating loss carried forward

 

5,943

 

10,373

 

 

7,218

 

 

Other

 

1,083

 

958

 

Credits

 

 

150

 

Accrued interest

 

3,436

 

2,744

 

Total net deferred tax liabilities

 

(102,668

)

(102,711

)

 

 

 

 

F-38F-35



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2526 — 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.

 

a)  Ordinary Shares

 

Number of Shares

a)Ordinary Shares

 

 

Total shares issued and outstanding at 31 December 2012

278,765,141

Shares issued during the year

184,408,527

Total shares issued and outstanding at 31 December 2013

463,173,668

Shares issued during the year

86,122,171

 

Total shares issued and outstanding at 31 December 2014

 

549,295,839

 

Shares issued during the year (1)

9,807,723

Total shares issued and outstanding at 31 December 2015

559,103,562

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.

 

 

2014

 

2013

 

 

2016

 

2015

 

2014

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

US$’000

 

US$’000

 

US$’000

 

 

 

 

 

 

 

 

 

 

 

 

 

b) Issued Capital

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of the period

 

237,008

 

58,694

 

 

308,429

 

306,853

 

237,008

 

Shares issued in connection with:

 

 

 

 

 

 

 

 

 

 

 

 

Merger with Texon

 

 

132,092

 

Private placement

 

72,178

 

47,398

 

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

 

813

 

 

 

 

260

 

Total shares issued during the period

 

72,438

 

180,303

 

 

67,499

 

1,576

 

72,438

 

Cost of capital raising during the period, net of tax benefit

 

(2,593

)

(1,989

)

 

(2,343

)

 

(2,593

)

Closing balance at end of period

 

306,853

 

237,008

 

 

373,585

 

308,429

 

306,853

 

 


c)(1)Options         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 Issuethe 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.

 

Details of the share options outstanding as at 31 December:

Grant Date

 

Expiry Date

 

Exercise Price
A$

 

2014
No. of options

 

2013
No. of options

 

02 Dec 2010

 

01 Dec 2015

 

0.37

 

 

291,666

 

02 Mar 2011

 

30 Jun 2014

 

0.95

 

 

30,000

 

03 Jun 2011

 

15 Jan 2016

 

0.65

 

500,000

 

500,000

 

06 Jun 2011

 

01 Sep 2015

 

0.95

 

30,000

 

30,000

 

06 Sep 2011

 

31 Dec 2018

 

0.95

 

1,200,000

 

1,200,000

 

05 Dec 2011

 

05 Mar 2019

 

0.95

 

1,000,000

 

1,000,000

 

01 Nov 2012

 

01 Feb 2020

 

1.15

 

 

350,000

 

03 Dec 2012

 

03 Mar 2020

 

1.15

 

 

350,000

 

01 Apr 2013

 

01 Jul 2020

 

1.25

 

 

350,000

 

24 Sept 2013

 

23 Dec 2020

 

1.40

 

 

950,000

 

Total share options outstanding

 

 

 

 

 

2,730,000

 

5,051,666

 

F-39F-36



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSc)

NOTE 25 — ISSUED CAPITAL continued

d)Restricted Share Units on Issue

 

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

 

Grant Date

 

2014
No. of RSUs

 

2013
No. of RSUs

 

 

2016
No. of RSUs

 

2015
No. of RSUs

 

05 Dec 2011

 

 

88,500

 

 

 

 

 

 

15 Oct 2012

 

352,676

 

709,817

 

 

 

352,676

 

19 April 2013

 

411,769

 

625,304

 

 

 

204,914

 

28 May 2013

 

187,124

 

280,686

 

 

 

93,562

 

15 April 2014

 

126,666

 

 

 

393,311

 

658,080

 

24 April 2014

 

1,291,951

 

 

29 April 2014

 

90,000

 

 

5 May 2014

 

 

45,000

 

12 May 2014

 

 

63,332

 

30 May 2014

 

503,991

 

 

 

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

 

2,964,177

 

1,704,307

 

 

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.

 

e)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 21,23, 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 remains minimal.ratio.  As at 31 December 20142016 and 2013,2015, the Company had $128.8$192 million and $29.1 million of outstanding debt, net of deferred financing fees, respectively.debt.

 

F-40F-37



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2627 — RESERVES

 

a)   Share OptionBased Payments Reserve

 

The share optionbased payments reserve records items recognised as expenses on valuation of employee and supplier 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 2728CAPITAL AND OTHER EXPENDITURE COMMITMENTS

 

Capital commitments relating to tenements

 

As at 31 December 2014,2016, all of the Company’s core exploration and evaluation and development and production assets are located in the United States of America (“US”).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.

 

F-41The Company is committed to fund



Tableexploratory drilling in the Cooper Basin (Australia) of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 27 — CAPITAL AND OTHER EXPENDITURE COMMITMENTS continuedup 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 2014

 

Total

 

Less than
1 year

 

1 — 5 years

 

More than 5
years

 

Drilling rig commitments (1)

 

1,460

 

1,460

 

 

 

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)

 

2,363

 

430

 

1,933

 

 

 

4,123

 

1,353

 

2,267

 

503

 

Employment commitments (4)

 

742

 

370

 

372

 

 

 

740

 

370

 

370

 

 

Total expenditure commitments

 

4,565

 

2,260

 

2,305

 

 

 

9,321

 

4,495

 

4,323

 

503

 

 

As at 31 December 2013

 

Total

 

Less than
1 year

 

1 — 5 years

 

More than 5
years

 

Drilling rig commitments (1)

 

5,159

 

5,159

 

 

 

Drilling commitments (2)

 

2,000

 

 

2,000

 

 

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)

 

1,860

 

200

 

1,354

 

306

 

 

5,892

 

1,372

 

4,520

 

 

Employment commitments (4)

 

104

 

104

 

 

 

 

372

 

372

 

 

 

Total expenditure commitments

 

9,123

 

5,463

 

3,354

 

306

 

 

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 20142016 the Company had one (2013: four) outstanding drilling rig contractscontracted to explore and develop the Company’s properties.drill seven wells during 2017.  The contracts generally have terms of 6 months.  Amounts representamount represents minimum expenditure commitments should the Company elect to terminate these contractsthis contract prior to term.

(2)On  Subsequent to December 31, December 2012,2016, the Company entered into an agreement to acquire certain oil and natural gas properties located in the Wattenberg Field and to drill 45 net wells by 31 December 2015 on the acquired properties (the “Drilling Commitment”).  As each qualifying wellcommenced drilling (and therefore is drilled, approximately $67 thousand is paid from the escrow accountnot subject to the Company. However, for each required net commitment well not completed by the Company during that prorated commitment year, the Company is to pay the seller of the properties approximately $67 thousand from the escrow account.  Certain clawback provisions allow the Company to recoup amounts paid to the sellers if the total 45 wells are drilled by 31 December 2015.  The Company sold the properties in July 2014 and should the buyer drill any qualifying wells, the obligation would be satisfied.  As at 31 December 2014, the Company and the buyer had not drilled any wells and the Company does not expect any wells to be drilled under this provision in 2015.  As such, the remaining commitment of $2.0 million was accrued in our consolidated statement of financial position and recognised against the gain on sale of assets in the consolidated statement of profit or loss and comprehensive income.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.

F-38



Table of Contents

(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.

 

F-42



TableSubsequent to 31 December 2016, the Company contracted two additional drilling rigs with minimum expenditure commitments of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS$0.6 million during 2017.

 

NOTE 2829 — 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 recognisedrecognized or disclosed in accordance with AASB 137/IFRSIAS 37 — Provisions, Contingent Liabilities and Contingent Assets.

 

NOTE 2930 — OPERATING SEGMENTS

 

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America, which is the Company’s only major line of business and only major geographic area of operations.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.

The CODM reviews internal management reports on a monthly basis that are consistent with  For the information provided in theyears ended 31 December 2016 and 2015, all statement of profit or loss and other comprehensive income statementactivity was attributed to its reportable segment with the exception of financial position$6.7 million and statement$2.2 million of cash flows.  As a result no reconciliation is required, becausepre-tax impairment expense, which related to the information as presented is used by the CODM to make strategic decisions.impairment of its Cooper Basin assets in Australia, respectively.

 

Geographic Information

 

The operations of the Group are located in only onetwo geographic location,locations, North America.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 onetwo major customercustomers exceeded 10 percent of Group consolidated revenue for the year ended 31 December 20142016 and accounted for 6569 and 12 percent, (2013: fourrespectively (2015: three major customers accounted for 4730, 29 and 22 percent, 15 percent, 10 percentrespectively and 102014:  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.

 

F-43F-39



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3031 — CASH FLOW INFORMATIONINFORMATION’

 

 

2014

 

2013

 

 

2016

 

2015

 

2014

 

Year ended 31 December

 

US$’000

 

US$’000

 

 

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

 

15,321

 

15,942

 

 

(45,694

)

(263,835

)

15,321

 

Adjustments to reconcile net profit to net operating cash flows:

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortisation expense

 

85,584

 

36,225

 

 

48,147

 

94,584

 

85,584

 

Share options expensed

 

1,915

 

1,590

 

Share based compensation

 

2,524

 

4,100

 

1,915

 

Unrealised (gains) losses on derivatives

 

(9,642

)

837

 

 

21,433

 

(3,444

)

(9,642

)

Net gain on sale of properties

 

(48,604

)

(7,335

)

 

 

(790

)

(48,604

)

Decrease in fair value of securities at FVTPL

 

 

90

 

 

Impairment of development and production assets

 

71,212

 

 

 

10,203

 

321,918

 

71,212

 

Unsuccessful exploration and evaluation expense

 

10,934

 

 

 

30

 

 

10,934

 

Amortisation of deferred financing fees

 

316

 

140

 

Add: Interest expense (disclosed in investing and financing activities)

 

383

 

 

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

 

879

 

665

 

 

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

 

126

 

(153

)

 

21

 

2,240

 

126

 

Changes in assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

- (Decrease) increase in current and deferred income tax

 

(14,606

)

5,147

 

- Decrease in other assets

 

28

 

2,155

 

- Decrease (increase) in trade and other receivables

 

8,679

 

(3,541

)

- Increase in trade and other payables

 

5,562

 

10,974

 

- 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

 

128,087

 

62,646

 

 

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 During

The Company recognized share based compensation expense of $2.7 million, $4.1 million and $1.9 million for the yearyears ended 31 December 2013 $132.1 million in shares2016, 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 in connection withoptions were exercised during the Texon acquisition.years ended 31 December 2016, 2015 and 2014, respectively.

 

F-44F-40



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 31 — SHARE BASED PAYMENTS

Options

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

Year ended 31 December

 

 

2014

 

2013

 

 

 

Number
of
Options

 

Weighted Average
Exercise Price A$

 

Number
of Options

 

Weighted Average
Exercise Price A$

 

Outstanding at start of period

 

5,051,666

 

1.02

 

5,776,666

 

0.59

 

Formally issued

 

 

 

2,000,000

 

1.29

 

Forfeited

 

(1,890,000

)

1.29

 

 

 

Exercised

 

(431,666

)

0.62

 

(2,725,000

)

0.31

 

Expired

 

 

 

 

 

Outstanding at end of period

 

2,730,000

 

0.90

 

5,051,666

 

1.02

 

Exercisable at end of period

 

1,930,000

 

0.87

 

2,241,666

 

0.87

 

The following tables summarise the options issued and awarded and their related grant date, fair value and vesting conditions for the year ended 31 December 2013.  No options were issued during the year ended 31 December 2014.

For options outstanding as at 31 December 2014, the exercise price ranged from A$0.65 to A$0.95 and the weighted average remaining contractual life was 3.5 years.

Options issued during the year ended 31 December 2013:

Grant Date

 

Number of
Options

 

Estimated Fair
Value (US$’000)

 

Vesting Conditions

 

1 April 2013

 

350,000

 

$

217

 

20% issuance date, 20% first four anniversaries

 

24 September 2013

 

950,000

 

$

475

 

20% issuance date, 20% first four anniversaries

 

Total

 

1,300,000

 

$

692

 

 

 

Share based payments expense related to options is determined pursuant to AASB 2 - Share Based Payments (“AASB 2”) / IFRS 2 — Share Based Payments (“IFRS 2”), and is recognised pursuant to the attached vesting conditions.  The fair value of the options awarded ranged from A$0.53 to A$0.59 for the year ended 31 December 2013, which were calculated using a Black-Sholes options pricing model.  Expected volatilities are based upon the historical volatility of the ordinary shares.  Historical data is also used to estimate the probability of option exercise and potential forfeitures.

F-45



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 31 — SHARE BASED PAYMENTS continued

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

2013

Share price:

A$ 1.06 – A$1.10

Exercise price:

A$1.25 – 1.40

Expected volatility:

60%

Option term:

5.75 years

Risk free interest rate:

2.82 to 3.10%

 

Restricted Share Units

 

During the years ended 31 December 20142016, 2015 and 2013,2014, the Board of Directors awarded 16,992,192, 13,322,262 and 2,839,626 and 1,237,994 RSUs, respectively, to certain employees.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 sectionRemuneration Report of the Directors’ Report.  Share based payment expense for RSUs awarded was calculated pursuant to AASB 2 / IFRS 2.  The fair values of RSUs were estimated atvalue calculation methodology is described in Note 1.  RSU expense totaled $2.5 million, $4.1 million and $2.0 million for the date they were approved by the Board of Directors (the measurement dates) based on the Company’s stock price at the date of grant.  The value of the vested portion of these awards has been recognised within the financial statements.years ended 31 December 2016, 2015 and 2014, respectively. This information is summarised for the Group for the years ended 31 December 20142016, 2015 and 2013,2014, respectively, below:

 

 

Number
 of RSUs

 

Weighted Average
Fair Value at
Measurement Date A$

 

 

Number
of RSUs

 

Weighted Average Fair
Value at Measurement
Date A$

 

 

 

 

 

 

 

 

 

 

 

Outstanding at 31 December 2012

 

2,090,893

 

0.59

 

Issued

 

1,237,994

 

0.91

 

Converted to ordinary shares

 

(1,511,511

)

0.76

 

Forfeited

 

(113,069

)

0.76

 

Outstanding at 31 December 2013

 

1,704,307

 

0.83

 

 

1,704,307

 

0.83

 

Issued

 

2,839,626

 

0.97

 

Issued or Issuable

 

2,839,626

 

0.97

 

Converted to ordinary shares

 

(1,479,978

)

0.89

 

 

(1,479,978

)

0.89

 

Forfeited

 

(99,778

)

0.92

 

 

(99,778

)

0.92

 

Outstanding at 31 December 2014

 

2,964,177

 

0.93

 

 

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 2014:2016:

 

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

 

 

 

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

 

 

 

 

 

F-46F-41



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSRSUs awarded during the year ended 31 December 2015:

 

NOTE 31 — SHARE BASED PAYMENTS continued

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 2013:2014:

 

Grant Date

 

Number of
RSUs

 

Estimated Fair
Value (US$’000)

 

Vesting Conditions

 

19 April 2013

 

863,746

 

$

789

 

25% issuance date, 25% first three anniversaries

 

28 May 2013

 

374,248

 

354

 

25% issuance date, 25% first three anniversaries

 

 

 

1,237,994

 

$

1,143

 

 

 

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.  As the daily closing price of the Company’s ordinary shares approximates its estimated fair value at that time, the Company used the grant date closing price to estimate the fair value of the RSUs.

The total share based compensation expense forFor 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 2013A$1.11 per share, respectively.

At 31 December 2016, the weighted average remaining contractual life of the RSUs was $1.9 million1.7 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 $1.6 million, respectively.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 3233 — RELATED PARTY TRANSACTIONS

 

N Martin was previously a partner of Minter Ellison Lawyers and is now a consultant for Minter Ellison Lawyers as well as a Director of the Company. Minter Ellison LawyersThere were paid a nonno material amount for legal services for the year ended 31 December 2014 and $0.2 million for legal servicesrelated party transactions for the years ended 31 December 2013.2016, 2015 and 2014.

F-42



Table of Contents

 

NOTE 3334 — 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 utiliseshas historically used derivative financial instruments to hedge exposure to fluctuations in interest rates and commodity prices. The Group’s financial instruments consist mainly of deposits with banks, short term investments, accounts receivable, derivative financial instruments, financecredit facility, and payables. The main purpose of non-derivative financial instruments is to raise financeproviding 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

Interest rate risk is managed with a mixture of fixed and floating rate cash deposits. As at 31 December 2014 and 2013 approximately nil of Group deposits are fixed. It is the policy of the Group to keep surplus cash in interest yielding deposits.

F-47



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 33 — FINANCIAL RISK MANAGEMENT continued

 

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.

 

During the year ended 31 December 2013, the Group entered into US dollar denominated interest rate swaps which fix the interest rate associated with the credit facilities to protect against the floating LIBOR rates through 2017. As at 31 December 2014 the Group had interest rate swaps with a notional contract amount of $15.0 million (2013: $15.0 million).

The net fair value of interest rate swaps at 31 December 2014 was relatively immaterial, comprising long-term assets of $0.1 million (2013: $0.2 million) and current liabilities of $0.1 million (2013: 0.1 million).  These amounts were recognised as Level 2 fair value derivatives. (See Note 14)

iii)           Commodity Price Risk Exposure and Management

 

The Board actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of the Group’s hedging activity are continually monitored against Group policy. The Group sells its oil on market using NymexNYMEX West Texas Intermediary (WTI) and LLSLouisiana 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 less thanat least 50% of anticipated future oilits proved developed reserves through 2019 and gas production for up to 24 months. The Group may hedge over 50% or beyond 24 months with approval of the Board.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.

 

Commodity Hedge ContractsA summary of the Company’s outstanding hedge positions as at 31 December 20142016 is below:

 

Contract Type

Counterparty

Basis

Quantity/mo

Strike Price

Term

Collar

Wells Fargo

WTI

2,000 BBL

$75.00/$98.65

1 Jan 15 – 31 Dec 15

Collar

Shell Trading US

LLS

3,000 BBL

$85.00/$101.05

1 Jan 15 – 31 Dec 15

Collar

Wells Fargo

WTI

2,000 BBL

$80.00/$97.00

1 Jan 15 – 31 Dec 15

Collar

Wells Fargo

WTI

1,000 BBL

$80.00/$94.94

1 Jan 15 – 31 Dec 15

Swap

Wells Fargo

LLS

2,000 BBL

$91.65

1 Jan 15 – 31 Dec 15

Swap

Shell Trading US

LLS

5,000 BBL

$98.05

1 Jan 15 – 30 Jun 15

Swap

Shell Trading US

LLS

3,000 BBL

$94.10

1 Jul 15 – 31 Dec 15

Swap

Wells Fargo

WTI

2,000 BBL

$95.08

1 Jan 15 – 31 Dec 15

Swap

Wells Fargo

LLS

2,000 BBL

$97.74

1 Jan 15 – 31 Dec 15

Swap

Shell Trading US

LLS

5,000 BBL

$100.70

1 Jan 15 – 30 Jun 15

Swap

Shell Trading US

LLS

5,000 BBL

$94.10

1 Jan 16 – 31 Dec 16

Swap

Shell Trading US

HH

20,000 MCF

$4.14

1 Jan 15 – 31 Dec 15

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

 

 

See Note 36 for discussion of new commodity hedge contracts entered into subsequent to 31 December 2014.

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

 

 

F-48



Table of Contents(1)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 33 — FINANCIAL RISK MANAGEMENT continued         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 Junior Credit Facility,Term Loan, the balances are not materially different from those disclosed in the consolidated statement of financial position of the Group.

 

F-43



Table of Contents

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, at balance date to recognise the financial assets, is the carrying amount, net of any impairment of those assets, as disclosed in the balance sheet and notes to the financial statements.  Receivable balances are monitored on an ongoing basis at the individual customer level.

 

At 31 December 2014,2016, the Group had three customersone customer that owed the Group more than $1.0approximately $1.5 million each and accounted for approximately 75%21% of total accrued revenue receivables.  There wasTo 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 customer with balances greater than $5.0joint-interest partner that owed the Group approximately $4.0 million accounting for approximately 56% of total accrued revenue receivables.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.

As  Financial liabilities are at 31 December 2014, based on the current borrowing based, the Group had $15.0 million of undrawn borrowing facilities.

F-49



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 33 — FINANCIAL RISK MANAGEMENT continuedcontractual 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 2014

 

Total

 

Less than 1
year

 

1 – 5
years

 

More than
5 years

 

Year ended 31 December 2016

 

Total

 

Less than 1
year

 

1 — 5 years

 

More than 5
years

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade and other payable

 

46,861

 

46,861

 

 

 

 

3,579

 

3,579

 

 

 

Accrued expenses

 

72,333

 

72,333

 

 

 

 

19,995

 

19,995

 

 

 

Derivative financial liabilities

 

130

 

130

 

 

 

 

 

Provisions

 

6,025

 

2,726

 

3,299

 

 

Credit facilities payments, including interest(1)

 

147,994

 

5,502

 

142,492

 

 

 

235,441

 

12,606

 

222,835

 

 

Total

 

267,318

 

124,826

 

142,492

 

 

 

265,040

 

38,906

 

226,134

 

 

 

Year ended 31 December 2013

 

Total

 

Less than 1
year

 

1 – 5
years

 

More than
5 years

 

Year ended 31 December 2015

 

Total

 

Less than 1
year

 

1 — 5 years

 

More than 5
years

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade and other payable

 

62,811

 

62,811

 

 

 

 

21,588

 

21,588

 

 

 

Accrued expenses

 

66,273

 

66,273

 

 

 

 

19,883

 

19,883

 

 

 

Derivative financial liabilities

 

366

 

335

 

31

 

 

Credit facilities payments, including interest

 

37,037

 

1,600

 

35,437

 

 

Credit facilities payments, including interest (1)

 

247,259

 

12,420

 

234,839

 

 

Total

 

166,487

 

131,019

 

35,468

 

 

 

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.

F-44



Table of Contents

 

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.

 

F-50



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 33 — FINANCIAL RISK MANAGEMENT continued

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

 

 

 

 

 

 

Effect on profit before tax
Increase / (Decrease)

 

 

 

 

 

Oil

 

 

 

 

 

-          improvement in US$ oil price of $10 per barrel

 

(2,400

)

(2,351

)

-          decline in US$ oil price of $10 per barrel

 

3,041

 

1,477

 

Gas

 

 

 

 

 

-          improvement in US$ gas price of $0.50 per mcf

 

(120

)

(124

)

-          decline in US$ gas price of $0.50 per mcf

 

120

 

180

 

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 20142016, 2015 and 2013, taking into account interest rate swaps,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

 

2014
US$’000

 

2013
US$’000

 

 

 

 

 

 

 

Effect on profit before tax
Increase / (Decrease)

 

 

 

 

 

-         increase in interest rates + 2%

 

(906

)

(177

)

-         decrease in interest rates - 2%

 

184

 

 

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.

 

F-51NOTE 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

F-45



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 34—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

 

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

 

2016

 

2015

 

As at 31 December

 

US$’000

 

US$’000

 

 

 

 

 

 

Parent Entity

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

9,108

 

 

1,962

 

 

11,103

 

18,132

 

Investment in subsidiaries

 

159,606

 

173,633

 

 

61,946

 

37,937

 

Deferred tax assets

 

3,998

 

2,303

 

 

2,683

 

1,913

 

Related party note receivable

 

112,481

 

40,537

 

 

122,174

 

112,481

 

Total assets

 

 

285,193

 

 

218,435

 

 

197,906

 

170,463

 

Liabilities

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

34

 

 

425

 

 

83

 

54

 

Total Liabilities

 

 

34

 

 

425

 

Total liabilities

 

83

 

54

 

Total net assets

 

 

285,159

 

 

218,010

 

 

197,823

 

170,409

 

Equity

 

 

 

 

 

 

 

 

 

 

Issued capital

 

 

306,853

 

237,008

 

 

373,585

 

308,429

 

Share options reserve

 

386

 

386

 

 

386

 

386

 

Foreign currency translation

 

(30,539

)

(20,509

)

 

(52,948

)

(48,214

)

Retained earnings (loss)

 

8,459

 

1,125

 

Accumulated deficit

 

(123,200

)

(90,192

)

Total equity

 

 

285,159

 

 

218,010

 

 

197,823

 

170,409

 

Financial Performance

 

 

 

 

 

Profit/(loss) for the period

 

 

7,334

 

 

275

 

Other comprehensive income

 

(10,030

)

(31,307

)

Total profit or loss and other comprehensive income

 

 

(2,696

)

 

(31,032

)

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

 

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

As at 31 December

 

2016
US$’000

 

2015
US$’000

 

Parent Entity

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

Current assets

 

 

9,108

 

 

1,962

 

 

11,103

 

18,132

 

Investment in subsidiaries

 

309,453

 

302,864

 

 

61,946

 

37,937

 

Deferred tax assets

 

3,998

 

2,303

 

 

2,683

 

1,913

 

Related party note receivable

 

112,481

 

40,537

 

 

122,174

 

112,481

 

Total assets

 

 

435,040

 

 

347,666

 

 

197,906

 

170,463

 

Liabilities

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

34

 

 

425

 

 

83

 

54

 

Non-current liabilities

 

 

 

Total Liabilities

 

 

34

 

 

425

 

 

83

 

54

 

Total net assets

 

 

435,006

 

 

347,241

 

 

197,823

 

170,409

 

Equity

 

 

 

 

 

 

 

 

 

 

Issued capital

 

 

306,853

 

 

237,008

 

 

373,585

 

308,429

 

Share options reserve

 

7,550

 

5,635

 

 

14,174

 

11,650

 

Foreign currency translation

 

(832

)

(1,516

)

 

(1,842

)

(1,310

)

Retained earnings (loss)

 

121,435

 

106,114

 

Accumulated deficit

 

(188,094

)

(148,360

)

Total equity

 

 

435,006

 

 

347,241

 

 

197,823

 

170,409

 

 

F-52F-46



Table of Contents

 

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

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSc)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 34—PARENT COMPANY INFORMATION continued

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

Financial Performance

 

 

 

 

 

Profit/(loss) for the period before equity in income of subsidiaries

 

 

7,334

 

 

275

 

Equity in income of subsidiaries

 

7,987

 

15,667

 

Other comprehensive income

 

684

 

(421

)

Total profit or loss and other comprehensive income

 

 

16,005

 

 

15,521

 

c)Cash Flow

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

Cash flow from operating activities

 

 

(70,216

)

 

(42,934

)

Cash flow from investing activities

 

9,415

 

(136,890

)

Cash flow from financing activities

 

71,761

 

179,904

 

NOTE 3537 — DEED OF CROSS GUARANTEE

 

Pursuant toThe Australian Securities Investments Commission Class Order 98/1418 theis designed to provide relief to wholly-owned subsidiary, Armadillo Petroleum Limited (“APL”), is relievedentities from the Corporations Act 2001 requirements for preparation, auditpreparing and lodgement of itslodging audited financial reports.

reports in Australia. As a condition of the Class Order, SEAL and APLArmadillo 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

 

2014
US$’000

 

2013
US$’000

 

 

 

 

 

 

 

Profit / (loss) before income tax

 

7,764

 

(1,497

)

 

 

 

 

 

 

Income tax (expense)/benefit

 

(324

)

1,780

 

 

 

 

 

 

 

Profit attributable to members of SEAL

 

7,440

 

283

 

 

 

 

 

 

 

Total comprehensive loss attributable to members of SEAL

 

(2,813

)

(18,924

)

 

 

 

 

 

 

Retained earnings at 1 January

 

1,132

 

849

 

Retained earnings at 31 December

 

8,572

 

1,132

 

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

 

 

F-53F-47



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 35 — DEED OF CROSS GUARANTEE continued

 

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

 

Year ended 31 December

 

2014
US$’000

 

2013
US$’000

 

 

2016
US$’000

 

2015
US$’000

 

��

 

 

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

11,506

 

1,558

 

 

10,756 -

 

245

 

Trade and other receivables

 

 

3,426

 

Other current assets

 

185

 

2,200

 

 

346

 

10,001

 

Assets held for sale

 

 

5,234

 

Total current assets

 

11,691

 

3,758

 

 

11,102

 

18,906

 

 

 

 

 

 

 

 

 

 

 

Non-current assets

 

 

 

 

 

 

 

 

 

 

Exploration and evaluation expenditure

 

45

 

170

 

 

40

 

40

 

Related party note receivable

 

112,481

 

40,537

 

 

122,174

 

112,481

 

Deferred tax assets

 

3,998

 

2,303

 

 

2,683

 

1,913

 

Investment in subsidiaries

 

158,047

 

171,937

 

 

56,090

 

36,543

 

Total non-current assets

 

274,571

 

214,947

 

 

180,987

 

150,977

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

286,262

 

218,705

 

 

192,089

 

169,883

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

 

 

 

Trade and other payables

 

988

 

176

 

 

13

 

31

 

Accrued expenses

 

13

 

302

 

 

3,031

 

1,542

 

Total current liabilities

 

1,001

 

478

 

 

3,044

 

1,573

 

 

 

 

 

 

 

 

 

 

 

Non-current liabilities

 

 

 

 

 

 

 

 

 

 

Deferred tax liabilities

 

3

 

4

 

 

 

3

 

Total non-current liabilities

 

3

 

4

 

 

 

3

 

 

 

 

 

 

 

 

 

 

 

Total liabilities

 

1,004

 

482

 

 

3,044

 

1,576

 

 

 

 

 

 

 

 

 

 

 

Net assets

 

285,258

 

218,223

 

 

189,045

 

168,307

 

 

 

 

 

 

 

 

 

 

 

Equity

 

 

 

 

 

 

 

 

 

 

Issued capital

 

306,853

 

237,008

 

 

373,585

 

308,429

 

Share option reserve

 

386

 

386

 

Share based payments reserve

 

386

 

386

 

Foreign currency translation

 

(30,553

)

(20,303

)

 

(52,947

)

(48,224

)

Retained earnings

 

8,572

 

1,132

 

Retained earnings (accumulated deficit)

 

(131,979

)

(92,284

)

Total equity

 

285,258

 

218,223

 

 

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.

 

F-54F-48



Table of Contents

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 36 — EVENTS AFTER THE BALANCE SHEET DATE

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

Subsequent to 31 December 2014, an additional $15.0 million was drawn-down under the Senior Credit Facility, bringing total outstanding debt to $145.0 million, with no undrawn funds available.  Both the Senior Credit Facility and Junior Credit Facility were refinanced as discussed below.

On May 14, 2015, Sundance Energy Australia Limited and Sundance Energy, Inc. entered into a Credit Agreement (the “Credit Agreement”) with Morgan Stanley Energy Capital, Inc., as administrative agent (“Agent”) and the lenders from time to time party thereto, which provides for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and term loans of $125 million (the “Term Loans), with an accordion feature providing for additional term loans of up to $50 million, subject to certain conditions  The Revolving Facility is subject to a borrowing base, which has been set initially at $75 million.  At closing on May 14, 2015, $25 million was drawn on the Revolving Facility and $125 million of Term Loans were funded.  The Revolving Facility has a five year term and the Term Loans have a 5 ½ year term.

The Revolving Facility and Term Loans refinanced the Company’s credit facilities with Wells Fargo Bank, N.A. and Wells Fargo Energy Capital, Inc., respectively.  At closing, the Company used $145.0 million of the proceeds to pay off its previous credit facilities, which are fully paid-off.  Approximately $1.1 million of deferred financing fees related to the previous credit facilities were written off due to the refinance.

Subsequent to year end and in anticipation of closing the aforementioned credit facilities, the Company entered into the following hedge contracts.

 

 

 

 

 

 

Units per month

 

Floor

 

Ceiling

 

 

 

Description

 

Commodity

 

Basis

 

2015

 

2016

 

2017

 

2018

 

2019

 

Price

 

Price

 

Term

 

Collar

 

Oil (Bbls)

 

LLS

 

10,000

 

 

 

 

 

$

50.00

 

$

98.65

 

Jun ‘15 – Dec ‘15

 

Collar

 

Oil (Bbls)

 

LLS

 

10,000

 

 

 

 

 

50.00

 

101.05

 

Jun ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

6,000

 

 

 

 

 

64.70

 

64.70

 

Jun ‘15 – Dec ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

6,000

 

 

 

 

 

65.90

 

65.90

 

Jun ‘15 – Sep ‘15

 

Swap

 

Oil (Bbls)

 

LLS

 

3,333

*

 

 

 

 

66.75

 

66.75

 

Jun ‘15 – Nov ‘15

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

69.30

 

Jan ‘16 – May ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

72.25

 

Jan ‘16 – May ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

77.00

 

Jun ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

10,000

 

 

 

 

50.00

 

85.00

 

Jul ‘16 – Dec ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

4,000

 

 

 

 

50.00

 

77.80

 

Jan ‘16 – Dec ‘16

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

8,000

 

 

 

50.00

 

81.75

 

Jan ‘17 – Dec ‘17

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

4,000

 

 

 

50.00

 

80.25

 

Jan ‘17 – Dec ‘17

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

 

4,000

 

 

55.00

 

80.25

 

Jan ‘18 – Dec ‘18

 

Collar

 

Oil (Bbls)

 

LLS

 

 

 

 

 

4,000

 

55.00

 

82.00

 

Jan ‘19 – Dec ‘19

 

Total Oil/Weighted Average Price

 

 

 

 

 

35,333

 

44,000

 

12,000

 

4,000

 

4,000

 

$

52.65

 

$

75.60

 

Jun ‘15 - Dec ‘19

 

Collar

 

Gas (Mmbtu)

 

HH

 

40,000

 

 

 

 

 

$

2.70

 

$

3.20

 

Jun ‘15 - Dec ‘15

 

Swap

 

Gas (Mmbtu)

 

HSC

 

30,000

 

 

 

 

 

$

3.06

 

$

3.06

 

Jun ‘15 - Dec ‘15

 

Collar

 

Gas (Mmbtu)

 

HSC

 

 

20,000

 

 

 

 

$

2.90

 

$

3.50

 

Jan ‘16 - Dec ‘16

 

Collar

 

Gas (Mmbtu)

 

HSC

 

 

20,000

 

 

 

 

$

2.90

 

$

3.75

 

Jan ‘16 - Dec ‘16

 

Collar

 

Gas (Mmbtu)

 

HH

 

 

20,000

 

 

 

 

$

2.90

 

$

3.50

 

Jan ‘16 - Dec ‘16

 

Collar

 

Gas (Mmbtu)

 

HH

 

 

 

20,000

 

 

 

$

3.05

 

$

3.60

 

Jan ‘17 - Dec ‘17

 

Total Gas/Weighted Average Price

 

 

 

 

 

70,000

 

60,000

 

20,000

 

 

 

$

2.91

 

$

3.44

 

Jun ‘15 - Dec ‘17

 


* Units per month range from 0 — 7,000 Bbls

In the above table, “LLS” refers to Light Louisiana Sweet, “HH” refers to Henry Hub and “HSC” refers to Houston Ship Channel.

F-55



Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 37—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)

 

Year ended
31 December 2014

 

Year ended
31 December 2013

 

 

2016

 

2015

 

2014

 

Property Acquisition Costs

 

 

 

 

 

Property acquisition costs

 

 

 

 

 

 

 

Proved(1)

 

$

2,244

 

$

158,116

 

 

$

23,873

 

$

13,170

 

$

2,244

 

Unproved(1)

 

34,184

 

60,690

 

 

2,815

 

15,495

 

34,184

 

Exploration costs

 

2,929

 

1,338

 

 

1,650

 

10,353

 

2,929

 

Development costs(2)

 

350,196

 

219,121

 

Development costs (1)

 

61,131

 

76,831

 

350,196

 

 

$

389,554

 

$

439,265

 

 

$

89,469

 

$

115,859

 

$

389,554

 

 


(1)                                 2013 property acquisition costs include acquisition date fair value of $157.2 million2016, 2015 and $47.3 million for proved and unproved assets acquired related to the Texon merger, which was primarily a non-cash business combination.

(2)2014 and 2013 development costs include $49.2$5.0 million, $16.6 million and $55.6$49.2 million of costs associated with non-producing wells in progress as at 31 December 20142016, 2015 and 2013,2014 respectively. These wells in progress were either drilling, waiting on hydraulic fracturing or production testing at year-end.

 

SEC Oil and Gas Reserve Information

 

Netherland, Sewell & Associates, Inc. (“NSAI”)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, December 2014 and 2013.2014. 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.

 

F-56F-49



Table of Contents

 

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(1)
(MBbl)

 

Total Oil
Equivalents
(MBbl)

 

 

Oil
(MBbl)

 

Natural
Gas
(MMcf)

 

NGL
(MBbl)

 

Total Oil
Equivalents
(MBbl)

 

Total proved reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

31 December 2012

 

5,758

 

16,888

 

 

8,572

 

Revisions of previous estimates

 

(1,160

)

(4,091

)

74

 

(1,767

)

Extensions and discoveries

 

7,081

 

16,270

 

1,946

 

11,739

 

Purchases of reserves in-place

 

3,857

 

4,674

 

758

 

5,393

 

Production

 

(827

)

(934

)

(96

)

(1,079

)

Sales of reserves in-place

 

(1,753

)

(2,152

)

 

(2,111

)

31 December 2013

 

12,956

 

30,655

 

2,683

 

20,747

 

 

12,956

 

30,655

 

2,683

 

20,747

 

Revisions of previous estimates

 

(143

)

(1,395

)

(580

)

(955

)

 

(143

)

(1,395

)

(580

)

(955

)

Extensions and discoveries

 

9,275

 

16,003

 

2,330

 

14,272

 

 

9,275

 

16,003

 

2,330

 

14,272

 

Purchases of reserves in-place

 

64

 

28

 

1

 

70

 

 

64

 

28

 

1

 

70

 

Production

 

(1,675

)

(1,803

)

(268

)

(2,244

)

 

(1,675

)

(1,803

)

(268

)

(2,244

)

Sales of reserves in-place

 

(3,451

)

(14,754

)

 

(5,910

)

 

(3,451

)

(14,754

)

 

(5,910

)

31 December 2014

 

17,026

 

28,733

 

4,166

 

25,981

 

 

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 2012

 

1,932

 

5,242

 

 

2,805

 

31 December 2013

 

4,140

 

10,765

 

1,087

 

7,021

 

31 December 2014

 

6,124

 

12,364

 

1,801

 

9,985

 

 

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 2012

 

3,826

 

11,646

 

 

5,767

 

31 December 2013

 

8,816

 

19,890

 

1,596

 

13,726

 

31 December 2014

 

10,903

 

16,369

 

2,365

 

15,996

 

 

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

 

 


(1)Proved Undeveloped ReservesPrior

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 year endedconversion 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, December 2013,2016 SEC price assumptions, the Company’s NGL Proved Reserves were insignificant;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 as such, were included in Natural Gas Proved Reserves and not separately reported in the Company’s reserve report.reserves will be spud within the next five years.

F-50



Table of Contents

 

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. With the exception of its Eagle Ford formation,Generally, the Company uses only Proved Developed Reserves in its depletable Reserve base. In addition to Proved Developed Reserves,However, for the year ended December 31, 2014 the Company also included 887.3 MBoe of Probable Developed Reserves of 1,867.0 MBoe and 887.3 MBoe in its Eagle Ford depletable Reserve base used for its year ended 31 December 2013 and 2014 depletion calculations. The Proved and Probable Developed Reserves represent managements’represented management’s best estimate of economically recoverable reserves associated with developed properties located in the Eagle Ford formation.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 Greater Anadarko BasinEagle 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 Greater Anadarko Basin.

The Company’s previous estimates of Proved Reserves related to the Denver-Julesburg decreased by 1,431 MBoe in 2013 (81 percent of the Company’s total revisions of previous estimate). This decrease was due to adjusted forecasts for the Denver-Julesburg.

F-57



Table of ContentsMississippian/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.

 

As a result of the Company’s active 2013 drilling programs in its Eagle Ford and Mississippian/Woodford formations, the Proved Reserves had extensions and discoveries of 5,378 MBoe and 4,252 MBoe, which represent 46% and 36% of the Company’s total extensions and discoveries, respectively.

Purchase of Reserves In-Place

 

During the yearyears ended 31 December 31,2016, 2015 and 2014, our purchase of reserves were located in the Eagle Ford.

During the year ended December 31, 2013, our purchasepurchases 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, ourthe Company’s sales of reserves were located in the Denver-Julesburg Basin and Goliath prospect of the Bakken.

 

During the year ended December 31, 2013, our salesF-51



Table of reserves were located in the Phoenix prospect of the Bakken.Contents

 

Standardized Measure of Future Net Cash Flow

 

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

 

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

 

The following summary sets forth our Standardized Measure:

 

(in thousands)

 

Year ended
31 December 2014

 

Year ended
31 December 2013

 

Cash inflows

 

$

1,822,997

 

$

1,407,871

 

Production costs

 

(444,369

)

(393,300

)

Development costs

 

(411,110

)

(382,259

)

Income tax expense

 

(182,999

)

(137,994

)

Net cash flow

 

784,520

 

494,318

 

10% annual discount rate

 

(349,014

)

(226,155

)

Standardized measure of discounted future net cash flow

 

$

435,506

 

$

268,163

 

F-58



Table of Contents

 

 

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:

 

(in thousands)

 

Year ended
31 December 2014

 

Year ended
31 December 2013

 

Standardized Measure, beginning of period

 

$

268,163

 

$

115,547

 

Sales, net of production costs

 

(139,304

)

(66,962

)

Net change in sales prices, net of production costs

 

37,325

 

6,450

 

Extensions and discoveries, net of future production and development costs

 

252,527

 

182,267

 

Changes in future development costs

 

21,115

 

16,222

 

Previously estimated development costs incurred during the period

 

119,164

 

13,854

 

Revision of quantity estimates

 

(27,495

)

(33,809

)

Accretion of discount

 

33,698

 

13,558

 

Change in income taxes

 

(27,408

)

(48,786

)

Purchases of reserves in-place

 

2,863

 

131,043

 

Sales of reserves in-place

 

(67,754

)

(36,935

)

Change in production rates and other

 

(37,388

)

(24,286

)

Standardized Measure, end of period

 

$

435,506

 

$

268,163

 

The following table provides a reconciliation of PV10 to the Standardized Measure:

(in thousands)

 

Year ended
31 December 2014

 

Year ended
31 December 2013

 

PV10 of proved reserves

 

$

531,735

 

$

336,984

 

Present value of future income tax discounted at 10%

 

(96,229

)

(68,821

)

Standardized Measure

 

$

435,506

 

$

268,163

 

 

 

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.

 

F-52



Table of Contents

The following average prices were used in determining the Standardized Measure as at:

 

 

Year ended 31 December

 

 

Year ended
31 December 2014

 

Year ended
31 December 2013

 

 

2016

 

2015

 

2014

 

Oil price per Bbl

 

$

92.26

 

$

94.55

 

 

$

42.02

 

$

48.47

 

$

92.26

 

Gas price per Mcf

 

$

4.43

 

$

3.45

 

 

$

1.22

 

$

1.27

 

$

4.43

 

NGL price per Bbl

 

$

29.96

 

$

28.78

 

 

$

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.

 

F-59F-53



Table of Contents

Ernst & Young Services Pty Limited

680 George Street

Sydney NSW 2000 Australia

GPO Box 2646 Sydney NSW 2001

Tel: +61 2 9248 5555

Fax: +61 2 9248 5959

ey.com/au

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Sundance Energy Australia Limited:

We have audited the accompanying consolidated statement of financial position of Sundance Energy Australia Limited as of December 31, 2013 and 2012, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity, and cash flows for the year ended December 31, 2013 and the six-month period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our 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 audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our 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, 2013 and 2012, and the consolidated results of its operations and its cash flows for the year ended December 31, 2013 and for the six-month period ended December 31, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ Ernst & Young

Sydney, Australia

680 George Street

Sydney NSW 2000

Australia

11 July 2014

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER 2013

 

 

Note

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Oil and natural gas revenue

 

3

 

$

85,345

 

$

17,724

 

Lease operating and production tax expense

 

4

 

(18,383

)

(4,082

)

Depreciation and amortisation expense

 

17, 19

 

(36,225

)

(6,116

)

General and administrative expense

 

5

 

(15,297

)

(5,810

)

Finance costs

 

 

 

232

 

(593

)

Gain on sale of non-current assets

 

6

 

7,335

 

122,327

 

(Loss)/gain on commodity hedging

 

 

 

(554

)

(639

)

Other (loss)/income

 

 

 

(944

)

15

 

Profit before income tax

 

 

 

21,509

 

122,826

 

Income tax expense

 

7

 

(5,567

)

(46,616

)

Profit attributable to owners of the Company

 

 

 

15,942

 

76,210

 

Other comprehensive income

 

 

 

 

 

 

 

Items that may be reclassified subsequently to profit or loss:

 

 

 

 

 

 

 

Exchange differences arising on translation of foreign operations (no income tax effect)

 

 

 

(421

)

(154

)

Other comprehensive income

 

 

 

(421

)

(154

)

Total comprehensive income attributable to owners of the Company

 

 

 

$

15,521

 

$

76,056

 

Earnings per share (cents)

 

 

 

 

 

 

 

Basic earnings

 

10

 

3.9

¢

27.5

¢

Diluted earnings

 

10

 

3.8

¢

27.2

¢

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AS AT 31 DECEMBER 2013

 

 

Note

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

CURRENT ASSETS

 

 

 

 

 

 

 

Cash and cash equivalents

 

11

 

$

96,871

 

$

154,110

 

Trade and other receivables

 

12

 

28,748

 

15,672

 

Derivative financial instruments

 

13

 

 

617

 

Other current assets

 

15

 

4,038

 

5,025

 

CURRENT ASSETS

 

 

 

129,657

 

175,424

 

Assets held for sale

 

16

 

11,484

 

 

TOTAL CURRENT ASSETS

 

 

 

141,141

 

175,424

 

NON-CURRENT ASSETS

 

 

 

 

 

 

 

Development and production assets

 

17

 

312,230

 

79,729

 

Exploration and evaluation expenditure

 

18

 

166,144

 

33,439

 

Property and equipment

 

19

 

1,047

 

423

 

Derivative financial instruments

 

13

 

176

 

 

Deferred tax assets

 

24

 

2,303

 

 

Other non-current assets

 

20

 

2,019

 

2,420

 

TOTAL NON-CURRENT ASSETS

 

 

 

483,919

 

116,011

 

TOTAL ASSETS

 

 

 

$

625,060

 

$

291,435

 

CURRENT LIABILITIES

 

 

 

 

 

 

 

Trade and other payables

 

21

 

62,811

 

38,770

 

Accrued expenses

 

21

 

77,716

 

13,072

 

Derivative financial instruments

 

13

 

335

 

 

TOTAL CURRENT LIABILITIES

 

 

 

140,862

 

51,842

 

NON-CURRENT LIABILITIES

 

 

 

 

 

 

 

Derivative financial instruments

 

13

 

31

 

 

Credit facilities, net of deferred financing fees

 

22

 

29,141

 

29,570

 

Restoration provision

 

23

 

5,074

 

1,228

 

Deferred tax liabilities

 

24

 

102,711

 

56,979

 

TOTAL NON-CURRENT LIABILITIES

 

 

 

136,957

 

87,777

 

TOTAL LIABILITIES

 

 

 

$

277,819

 

$

139,619

 

NET ASSETS

 

 

 

$

347,241

 

$

151,816

 

EQUITY

 

 

 

 

 

 

 

Issued capital

 

25

 

$

237,008

 

$

58,694

 

Share option reserve

 

26

 

5,635

 

4,045

 

Foreign currency translation

 

26

 

(1,516

)

(1,095

)

Retained earnings

 

 

 

106,114

 

90,172

 

TOTAL EQUITY

 

 

 

$

347,241

 

$

151,816

 

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEAR ENDED 31 DECEMBER 2013

 

 

Issued
Capital
US$’000

 

Share
Option
Reserve
US$’000

 

Foreign
Currency
Translation
Reserve
US$’000

 

Retained
Earnings
US$’000

 

Total
US$’000

 

Balance at 30 June 2012

 

$

57,978

 

$

3,205

 

$

(941

)

$

13,962

 

$

74,204

 

Profit attributable to owners of the Company

 

 

 

 

76,210

 

76,210

 

Other comprehensive loss for the period

 

 

 

(154

)

 

(154

)

Total comprehensive income

 

 

 

(154

)

76,210

 

76,056

 

Shares issued during the period

 

716

 

 

 

 

716

 

Share based payments

 

 

840

 

 

 

840

 

Balance at 31 December 2012

 

58,694

 

4,045

 

(1,095

)

90,172

 

151,816

 

Profit attributable to owners of the Company

 

 

 

 

15,942

 

15,942

 

Other comprehensive loss for the year

 

 

 

(421

)

 

(421

)

Total comprehensive income

 

 

 

(421

)

15,942

 

15,521

 

Shares issued in connection with:

 

 

 

 

 

 

 

 

 

 

 

a) Merger with Texon

 

132,092

 

 

 

 

132,092

 

b) Private placement

 

47,398

 

 

 

 

47,398

 

c) Exercise of stock options

 

813

 

 

 

 

813

 

Cost of capital raising, net of tax

 

(1,989

)

 

 

 

 

 

 

(1,989

)

Share based payments

 

 

1,590

 

 

 

1,590

 

Balance at 31 December 2013

 

$

237,008

 

$

5,635

 

$

(1,516

)

$

106,114

 

$

347,241

 

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE PERIOD ENDED 31 DECEMBER 2013

 

 

Note

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

Receipts from sales

 

 

 

$

84,703

 

$

11,648

 

Payments to suppliers and employees

 

 

 

(21,765

)

(2,886

)

Interest received

 

 

 

126

 

16

 

Derivative proceeds, net

 

 

 

253

 

608

 

Income taxes paid

 

 

 

(671

)

 

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

30

 

62,646

 

9,386

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

Payments for development expenditure

 

 

 

(154,700

)

(32,551

)

Payments for exploration expenditure

 

 

 

(20,006

)

(8,031

)

Payments for acquisition of oil and gas properties

 

 

 

(141,963

)

(11,470

)

Sale of non-current assets

 

 

 

37,848

 

173,822

 

Transaction costs related to sale of non-current assets

 

 

 

(161

)

(862

)

Payments to establish escrow related to acquisition

 

 

 

 

(6,230

)

Cash acquired from merger

 

 

 

114,690

 

 

Cash received from escrow account

 

 

 

837

 

 

Payments for plant and equipment

 

 

 

(900

)

(107

)

NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES

 

 

 

(164,355

)

114,571

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

Proceeds from the issuance of shares

 

 

 

48,211

 

716

 

Payments for costs of capital raisings

 

 

 

(2,654

)

 

Payments for acquisition related costs

 

 

 

(533

)

(192

)

Borrowing costs paid

 

 

 

(569

)

(678

)

Proceeds from borrowings

 

 

 

15,000

 

45,000

 

Repayments from borrowings

 

 

 

(15,000

)

(30,000

)

NET CASH PROVIDED BY FINANCING ACTIVITIES

 

 

 

44,455

 

14,846

 

Net (decrease)/increase in cash held

 

 

 

(57,254

)

138,803

 

Cash at beginning of period

 

 

 

154,110

 

15,328

 

Effect of exchange rates on cash

 

 

 

15

 

(21

)

CASH AT END OF PERIOD

 

11

 

$

96,871

 

$

154,110

 

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEAR ENDED 31 DECEMBER 2013

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 2013 was authorised for issuance in accordance with a resolution of the Board of Directors on 28 March 2014.

The nature of the operations and principal activities of the Group are described in the Directors’ Report.

Change in reporting period

Effective 1 July 2012, the Company changed its financial reporting year end from 30 June to 31 December in order to be more comparable to the Company’s peer group in the US market. This change resulted in the comparative reporting period being a six month period. The six month period ended 31 December 2012, which is the previous reporting period shown in these financial statements, is a shorter reporting period than that of the year ended 31 December 2013, therefore, the amounts presented in the financial statements are not entirely comparable.

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 have been prepared on a historical basis, except for derivative financial instruments that have been measured at fair value. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$’000), except where stated otherwise.

Principles of Consolidation

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

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

a)Income Tax

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

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

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

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

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

Deferred tax assets relating to temporary differences and unused tax losses are recognised only to the extent that it is probable that future taxable profit will be available against which the benefits of the deferred tax asset can be utilised.

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

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

b)Exploration and Evaluation Expenditure

Exploration and evaluation expenditure incurred is 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. 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.

Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made.

When production commences, the accumulated costs for the relevant area of interest are transferred to production assets and amortised over the life of the area according to the rate of depletion of the economically recoverable reserves.

A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest.

c)Development and Production Assets and Property and Equipment

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

The carrying amount of development and production assets and property and equipment are reviewed semi-annually to ensure that they are not in excess of the recoverable amount from these assets. The recoverable amount is assessed on the basis of the expected net cash flows that will be received from the assets employment and subsequent disposal. The expected net cash flows have been discounted to their present values in determining recoverable amounts.

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

Depreciation / Amortisation

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 assets. For this approach, the calculation is based upon economically recoverable reserves, being proved developed reserves and probable developed reserves, over the life of an asset or group of assets.

The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each reporting period. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount.

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

d)Leases

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

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

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.

e)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.

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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.

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 price swap, option and costless collar contracts and interest rate swaps. Their use is subject to policies and procedures as approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes.

Derivative financial instruments are initially recognised at cost, which approximates fair value. Subsequent to initial recognition, derivate financial instruments are recognised at fair value. The 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.

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.

i)Financial assets at fair value through profit or loss

Financial assets are classified at fair value through profit or loss when they are held for trading for the purpose of short term profit taking, when they are derivatives not held for hedging purposes, or designated as such to avoid an accounting mismatch or to enable performance evaluation where a group of financial assets is managed by key management personnel on a fair value basis in accordance with a documented risk management or investment strategy. Realised and unrealised gains and losses arising from changes in fair value are included in profit or loss in the period in which they arise.

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.

iii)Held-to-maturity investments

Held-to-maturity investments are non-derivative financial assets that have fixed maturities and fixed or determinable payments, and it is the Group’s intention to hold these investments to maturity. They are subsequently measured at amortised cost using the effective interest rate method.

iv)Available-for-sale financial assets

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

v)Financial liabilities

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

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f)Impairment of Non-Financial Assets

At each reporting date, the group reviews the carrying values of its tangible and intangible assets to determine whether there is any indication that those assets have been impaired. If such an indication exists, the recoverable amount of the asset, being the higher of the asset’s fair value less costs to sell and value in use, is compared to the asset’s carrying value. Any excess of the asset’s carrying value over its recoverable amount is expensed to the statement of comprehensive income.

Impairment testing is performed annually for intangible assets with indefinite lives.

Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

g)Foreign Currency Transactions and Balances

Functional and presentation currency

The functional currency of each of the Group’s entities is measured using the currency of the primary economic environment in which that entity operates. The consolidated financial statements are presented in US dollars.

Transactions and Balances

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

Exchange differences arising on the translation of 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 operations whose functional currency is different from the Group’s presentation currency are translated as follows:

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

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

·retained profits are translated at the exchange rates prevailing at the date of the transaction.

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

h)Employee Benefits

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

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Equity—Settled Compensation

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

Restricted Share Unit Plan

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 based on goals established and approved by the Board. The actual RSUs, awarded annually, are modified according to actual results and vest in four equal tranches beginning on the grant date and each of the first three subsequent anniversaries.

i)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.

j)Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, unrestricted escrow accounts that management expects to be used to settle current liabilities, capital or operating expenditures, or complete acquisitions and bank overdrafts.

k)Revenue

Revenue from the sale of goods is recognised upon the delivery of goods to the customer. Revenue from the rendering of a service is recognised upon the delivery of the service to the customers. All revenue is stated net of the amount of goods and services tax (“GST”).

l)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 borrowing costs at 100 percent equal to $1.3 million and nil for the year and six month period ended 31 December 2013 and 2012, respectively.

All other borrowing costs are recognised in income in the period in which they are incurred.

m)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.

n)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

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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 acquire over the fair value of the Group’s share 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 income statement as a bargain purchase. Adjustments to the purchase price and excess on consideration transferred may be made up to one year from the acquisition date.

o)Assets Held for Sale

The Company classifies property as held for sale when management commits to a plan to sell the property, the plan has appropriate approvals, the sale of the property is 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 2013 and 2012, all of the Company’s Williston properties and nil properties were classified as held for sale, respectively.

p)Critical Accounting Estimates and Judgements

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

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

Estimates of reserve quantities

The estimated quantities of hydrocarbon reserves reported by the Group are integral to the calculation of amortisation (depletion) and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessment of the technical feasibility and commercial viability of producing the reserves. Management prepares reserve estimates which conform to the definitions contained in Rule 4-10(a) of Regulation S-X. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period, and as additional geological data is generated during the course of operations.

Impairment of Non-Financial Assets

The Group assesses impairment at each reporting date by evaluating conditions specific to the Group that may lead to impairment of assets. Where an indicator of impairment exists, the recoverable amount of the asset is determined. Value-in-use calculations performed in assessing recoverable amounts incorporate a number of key estimates including projections of cash flows, prices of products, production costs, reserve estimates and capitalised amounts.

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. 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,

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then the relevant capitalised amount will be written off through the consolidated statement of profit or loss and other comprehensive income.

Restoration Provision

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

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

Units of Production Depreciation

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

The life of each item has regard to both its physical life limitations and present assessments of economically recoverable reserves of the field at which the asset is located. Economically recoverable reserves are defined as proved developed and probable developed reserves. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the units of production rate of depreciation 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.

Stock Based Compensation

The Group’s policy for stock based compensation is discussed in Note 1 (h). The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances. Stock based compensation related to stock options use estimates for expected volatility of the Company’s share price and expected term, including a forfeiture rate, if appropriate.

q)Change in Accounting Estimate

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

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r)Reclassifications

Certain reclassifications have been made to the prior year consolidated financial statements and associated notes to the financial statements to conform to the current year presentation. Employee benefits expense has been reclassified to be presented with General and administrate expense and Interest received has been reclassified to be presented with Other (loss)/income on the consolidated statement of profit or loss and other comprehensive income. These reclassifications did not impact Profit attributable to owners of the Company.

s)Rounding of Amounts

The company is of a kind referred to in Class Order 98/100 issued by the Australian Securities and Investment Commission, relating to rounding of amounts in the financial statements. Amounts have been rounded to the nearest thousand.

t)Parent Entity Financial Information

The financial information for the parent entity, SEAL (“Parent Company”), also the ultimate parent, discussed in Note 34, has been prepared on the same basis, using the same accounting policies as the consolidated financial statements.

u)Earnings Per Share

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

v)Change in Accounting Policy

Effective 1 July 2013, the Group retrospectively changed its general and administrative overhead policy (“capitalised overhead policy”) from expensing overhead costs directly attributable to the exploration, acquisition and development of oil and gas properties such as salaries, wages, benefits and consultant fees, to capitalizing these costs using an appropriate allocation method in accordance with AASB 6—Exploration and Evaluation Assets and AASB 116—Property and Equipment. This new policy provides reliable and more relevant information as the Company has shifted its focus from non-operated properties to operated properties and this policy better aligns costs with revenues.

The Group adopted the capitalised overhead policy subsequent to the issuance of the Company’s report for the half year ended 30 June 2013 and retrospectively applied the policy for the year ended 31 December 2013. As a result, the half year ended 30 June 2013 is not entirely comparable to the Company’s year ended 31 December 2013. Included in the Company’s year ended 31 December 2013 capitalised overhead amounts are retrospectively applied for pre-effective 1 July 2012 capitalised overhead amounts, which would have increased the Company’s non-current assets and decreased general and administrative expense, of approximately $1.2 million as at 30 June 2013 and for the half year then ended. These overhead amounts capitalised to development and production assets would have been subject to the Company’s units-of-production depletion calculation, which would have been immaterial for the period. The related increase in the Company’s profit attributable to owners and retained earnings of the Company would have been approximately $0.7 million for the half year ended 30 June 2013. The Company determined the capitalized overhead amounts for periods ended on or before 31 December 2012 are immaterial.

w)Adoption of New and Revised Accounting Standards

During the current reporting period the Group adopted all of the new and revised Australian Accounting Standards and Interpretations applicable to its operations which became mandatory. The nature and effect of each new standard and amendment on the Group’s consolidated financial report are described below.

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AASB 10—Consolidated Financial Statements/IFRS 10—Consolidated Financial Statements

The Group adopted AASB 10 Consolidated Financial Statements/IFRS 10 Consolidated Financial Statements, which replaces the guidance on control and consolidation in AASB 127—Consolidated and Separate Financial Statements/IAS 27 Consolidated and Separate Financial Statements and Interpretation 12—Consolidation—Special Purpose Entities. AASB 10/IFRS 10 includes a new definition of control that focuses on the need to have both power and rights or exposure to variable returns. As all of the Group’s subsidiaries are owned 100%, AASB 10/IFRS 10 did not have an impact on the Group’s consolidated financial statements.

AASB 11—Joint Arrangements/IFRS 11—Joint Arrangements

AASB 11/IFRS 11 replaces AASB 131 Interests in Joint Ventures and removes the option to account for jointly controlled entities using proportionate consolidation. Instead, jointly controlled entities that meet the definition of a joint venture under AASB 11/IFRS 11 must be accounted for using the equity method of accounting. The adoption of this standard did not have an impact on the Group’s consolidated financial statements.

AASB 13—Fair Value Measurement/IFRS 13—Fair Value Measurement and AASB 2011-8 Amendments to Australian Accounting Standards arising from AASB 13

AASB 13/IFRS 13 establishes a single source of guidance for fair value measurements and disclosures. The standard defines fair value, establishes a framework for measuring fair value, and requires more extensive disclosures than current standards. Additional disclosures, where required, are provided in the individual notes relating to the assets and liabilities whose fair values were determined.

Recently issued accounting standards to be applied in future reporting periods:

The following Standards and Interpretations are effective for annual periods beginning on or after 1 January 2014 and have not been applied in preparing these consolidated financial statements. The Group’s assessment of the impact of these new standards, amendments to standards, and interpretations is set out below.

AASB 9—Financial Instruments/IFRS 9—Financial Instruments and AASB 2010-7 Amendments to Australian Accounting Standards arriving from AASB 9

AASB 9/IFRS 9 introduces new requirements for the classification, measurement, and derecognition of financial assets and financial liabilities. In November 2013 the effective date was removed from AASB 9/IFRS 9. A new effective date will be provided when the entire standard is closer to completion. The Group will quantify the effect of the application of AASB 9/IFRS 9 when the final standard is issued, however, the impact from adopting this standard is not expected to have a material impact on the Group’s consolidated financial statements.

AASB 2011-4—Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure

This standard removes the requirements to include individual key management personnel disclosures in the notes to and forming part of the Financial Report. The Group will include detailed key management personnel disclosures in the Group’s Remuneration Report for the year beginning on 1 January 2014 incorporating changes from this standard.

IFRS 15—Revenue from Contracts with Customers

In May 2014, the IASB issued IFRS 15, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The Statement allows for the use of either the full or modified retrospective transition method, and the standard will be effective for us in the first quarter of our fiscal year 2017. We are currently evaluating the impact of this new standard on our consolidated financial statements, as well as which transition method we intend to use.

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NOTE 2—BUSINESS COMBINATIONS

Texon Acquisition

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

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

Fair value of assets acquired:

 

 

 

Trade and other receivables

 

$

5,604

 

Other current assets

 

456

 

Development and production assets

 

53,937

 

Exploration and evaluation assets

 

150,474

 

Prepaid drilling and completion costs

 

3,027

 

Amount attributable to assets acquired

 

213,498

 

Fair value of liabilities assumed:

 

 

 

Trade and other payables

 

119

 

Accrued expenses

 

37,816

 

Restoration provision

 

277

 

Deferred tax liabilities

 

16,884

 

Amount attributable to liabilities assumed

 

55,096

 

Net assets acquired

 

$

158,402

 

Purchase price:

 

 

 

Cash and cash equivalents, net of cash acquired

 

$

26,310

 

Issued capital

 

132,092

 

Total consideration paid

 

$

158,402

 

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

 

 

Year ended
31 December 2013

 

Oil and natural gas revenue

 

$

5,163

 

Lease operating and production expenses

 

(1,150

)

Depreciation and amortization expense

 

(1,882

)

General and administrative expense

 

(667

)

Finance costs

 

(35

)

Profit before income tax

 

1,429

 

Income tax expense

 

(542

)

Proforma profit attributable to the period 1 January to 7 March 2013

 

887

 

Profit attributable to owners of the Company for the year

 

15,942

 

Adjusted profit attributable to the owners of the Company for the year

 

$

16,829

 

Adjusted basic earnings per ordinary share

 

4.1

¢

Adjusted diluted earnings per ordinary share

 

4.0

¢

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The Company incurred $0.5 million and $0.7 million for the year and six month period ended 31 December 2013 2012, respectively, in acquisition related costs primarily for professional fees and services. These amounts are included in general and administrative expense and financing activities in the consolidated statements of profit or loss and other comprehensive income and the consolidated statement of cash flows, respectively.

NOTE 3—REVENUE

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Oil revenue

 

$

79,365

 

$

16,790

 

Natural gas revenue

 

5,980

 

934

 

Total oil and natural gas revenue (net of transportation)

 

$

85,345

 

$

17,724

 

NOTE 4—LEASE OPERATING AND PRODUCTION TAX EXPENSE

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Lease operating expense

 

$

(11,378

)

$

(1,908

)

Workover expense

 

(743

)

(287

)

Production tax expense

 

(6,262

)

(1,887

)

Total lease operating and production tax expense

 

$

(18,383

)

$

(4,082

)

NOTE 5—GENERAL AND ADMINISTRATIVE EXPENSES

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Employee benefits expense, including salaries and wages, net of capitalised overhead

 

$

(6,143

)

$

(2,801

)

Professional fees

 

(2,892

)

(929

)

Abandoned US IPO transaction costs(1)

 

(2,081

)

 

Travel

 

(791

)

(280

)

Director fees

 

(617

)

(132

)

Acquisition and merger related fees

 

(533

)

(713

)

Accounting and company secretarial

 

(415

)

(150

)

Insurance

 

(264

)

(130

)

Rent

 

(234

)

(181

)

Share registry and listing fees

 

(232

)

(75

)

Audit fees

 

(139

)

(145

)

Other expenses

 

(956

)

(274

)

Total general and administrative expenses

 

$

(15,297

)

$

(5,810

)


(1)See Note 36—Events After the Balance Sheet Date for further discussion.

NOTE 6—GAIN ON SALE OF NON-CURRENT ASSETS

In the fourth quarter of 2013 and the third quarter of 2012, the Company sold all of its interests in the Phoenix prospect and South Antelope prospect, both located in the Williston Basin, for gross proceeds of $39.8 million and $172.4 million, respectively. Prior to the dispositions, the Phoenix and South Antelope development and production properties were part of the Williston Basin depletion base. To determine the carrying costs of the sold properties, the Company used the relative fair value of the prospect’s proved developed reserves as compared to the Company’s total proved developed reserves in the Williston Basin. As a result, it was determined that approximately $26.0 million and $49.4 million of the Company’s carrying costs related to its Phoenix and South Antelope development and production properties, respectively, at the time of the disposal. In addition to the South Antelope development and production properties, the Purchaser acquired approximately $3.9 million of assets and assumed approximately $3.8 million of liabilities, which were removed from the Company’s consolidated statement of financial position at the time of the sale. The Company incurred approximately $0.9 million and $0.9 million of legal and

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other transaction related costs related to the Phoenix and South Antelope sale, respectively. The sales resulted in a pre-tax gain of $8.2 million and $122.5 million, respectively, which is included in the net gain (loss) on sale of non-current assets in the consolidated statement of profit or loss and other comprehensive income for the year and six month period ended 31 December 2013 and 2012, respectively. In early 2013, the Company finalised the adjustments to the purchase price for the South Antelope sale, resulting in a net reduction of $0.9 million, which is included in the net gain (loss) on sale of non-current assets in the consolidated statement of profit or loss and other comprehensive income for the year ended 31 December 2013. During the six months ended 31 December 2012, the Company also sold all of its properties in the Pawnee prospect for $0.9 million of proceeds, which resulted in a loss of $0.2 million.

For both the Phoenix and South Antelope prospect sales proceeds, the Company elected to apply Section 1031 “like-kind exchange” treatment under the US tax rules, which allow deferral of the gain if the proceeds are used to acquire “like-kind property” within six months of the closing date of the transaction. In addition, the US tax rules allow the deduction of all intangible drilling costs (“IDCs”) in the period incurred. As at 31 December 2013, the Company expects to defer the majority of the taxable gain on the sale of the Phoenix development by acquiring qualified replacement properties or utilizing IDCs from its development program. These proceeds are included in the Company’s cash balance. See Note 11—Cash and Cash Equivalents.

In January and February 2014, the Company entered into lease acquisition agreements to acquire oil and gas properties in the Mississippian/Woodford Basin and the Eagle Ford Basin—see Events After the Balance Sheet Date in Note 36 for further discussion. Management believes the properties that the Company plans to acquire will qualify as “like-kind property” under Section 1031.

In March 2013, the Company completed a transaction in which the majority of the funds remaining in its South Antelope Section 1031 escrow accounts were used to acquire oil and gas properties in connection with the Texon Scheme of Arrangement transaction—see Business Combinations in Note 2 for further discussion.

NOTE 7—INCOME TAX EXPENSE

 

 

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

a)

 

The components of income tax expense comprise:

 

 

 

 

 

 

 

Current tax benefit/(expense)

 

$

21,398

 

$

(11

)

 

 

Deferred tax expense

 

(26,965

)

(46,605

)

 

 

 

 

$

(5,567

)

$

(46,616

)

b)

 

The prima facie tax on income from ordinary activities before income tax is reconciled to the income tax as follows:

 

 

 

 

 

 

 

Profit before income tax

 

$

21,509

 

$

122,826

 

 

 

Prima facie tax expense at the Group’s statutory income tax rate of 30% (2012:30%)

 

$

6,453

 

$

36,848

 

 

 

Tax effect of amounts which are non-deductible/(non- taxable) in calculating taxable income:

 

 

 

 

 

 

 

                 Difference of tax rate in US controlled entities

 

1,607

 

9,417

 

 

 

                 Employee options

 

 

44

 

 

 

                 Other allowable items

 

144

 

93

 

 

 

                 Tax adjustments relating to prior years

 

(984

)

 

 

 

                 Change in apportioned state tax rates in US controlled entities(1)

 

(1,448

)

 

 

 

                 Acquisition related costs

 

 

214

 

 

 

                 Recognition of previously unrecognized tax losses

 

(205

)

 

 

 

Income tax attributable to entity

 

$

5,567

 

$

46,616

 

c)

 

Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30%

 

$

170

 

$

375

 

d)

 

Deferred tax charged directly to equity:

 

 

 

 

 

 

 

                 Equity raising costs

 

$

665

 

$

 

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(1)The change in apportioned state tax rates in US controlled entities is a result of the Company disposing of its property in North Dakota (income tax rate of 4.53%) through a tax deferred sale and reinvesting the property in Texas (margin tax rate of 1%). 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.

NOTE 8—KEY MANAGEMENT PERSONNEL COMPENSATION

a)Names and positions held of Consolidated Group key management personnel in office at any time during the financial period are:

Mr M Hannell

Chairman Non-executive

Mr E McCrady

Chief Executive Officer and Managing Director

Mr D Hannes

Director—Non-executive

Mr N Martin

Director—Non-executive

Mr W Holcombe

Director—Non-executive

Ms C Anderson

Chief Financial Officer

Mr C Gooden

Company Secretary (resigned on 23 August 2013)

Other than Directors and Officers of the Company listed above, there are no additional key management personnel.

b)Key Management Personnel Compensation

The total of remuneration paid to Key Management Personnel (“KMP”) of the Group during the year is as follows:

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Short term wages and benefits

 

$

1,923

 

$

695

 

Equity settled-options based payments

 

625

 

262

 

Post-employment benefit

 

56

 

17

 

 

 

$

2,604

 

$

974

 

c)Options Granted as Compensation

Options granted as compensation were zero ($nil fair value) during each of the year and six month period ended 31 December 2013 and 2012 to KMP from the Sundance Energy Employee Stock Option Plan. Options generally vest in five equal tranches of 20% on the grant date and each of the four subsequent anniversaries of the grant date.

d)Restricted Share Units Granted as Compensation

RSUs awarded as compensation were 623,251 ($0.6 million fair value) and 669,642 ($0.5 million fair value) during the year and six month period ended 31 December 2013 and 2012, respectively, to KMP from the Sundance Energy Long Term Incentive Plan. RSUs generally vest in four equal tranches of 25% on the grant date and each of the three subsequent anniversaries of the grant date.

NOTE 9—AUDITORS’ REMUNERATION

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Remuneration of the auditor for:

 

 

 

 

 

Auditing or review of the financial report

 

$

91

 

$

131

 

Professional services related US IPO

 

430

 

 

Non-audit services related to Texon acquisition

 

77

 

148

 

Taxation services provided by the practice of auditor

 

48

 

14

 

Total remuneration of the auditor

 

$

646

 

$

293

 

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NOTE 10—EARNINGS PER SHARE (EPS)

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Profit for periods used to calculate basic and diluted EPS

 

$

15,942

 

$

76,210

 

 

 

Number of
shares

 

Number of
shares

 

—Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS

 

413,872,184

 

277,244,883

 

—Incremental shares related to options and restricted share units

 

2,685,150

 

2,896,496

 

—Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS

 

416,557,334

 

280,141,379

 

NOTE 11—CASH AND CASH EQUIVALENTS

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Cash at bank and on hand

 

$

59,918

 

$

12,747

 

Cash equivalents in escrow accounts

 

36,953

 

141,363

 

Total cash and cash equivalents

 

$

96,871

 

$

154,110

 

As at 31 December 2013 and 2012, the Company had approximately $37.0 million and $141.4 million, respectively, in Section 1031 escrow accounts which are not limited in use, except that the timing of tax payments will be accelerated if not used on qualified “like-kind property.” As such, the balances have been included in the Company’s cash and cash equivalents in the consolidated statement of financial position and consolidated statement of cash flows as at 31 December 2013 and 2012 and for the year and six month period then ended, respectively.

NOTE 12—TRADE AND OTHER RECEIVABLES

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Oil and natural gas sales

 

$

23,364

 

$

11,376

 

Trade receivables

 

5,353

 

4,185

 

Other

 

31

 

111

 

Total trade and other receivables

 

$

28,748

 

$

15,672

 

As at 31 December 2013 and 2012, the Group had receivable balances of $11.7 million and $8.6 million, respectively, which were outside normal trading terms (the receivable was past due but not impaired). The receivable balance is more than fully offset by the amount due to the same operator, which is also outside normal payment terms. See Note 21 for payable balance information.

Due to the short-term nature of trade and other receivables, their carrying amounts are assumed to approximate fair value.

NOTE 13—DERIVATIVE FINANCIAL INSTRUMENTS

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

FINANCIAL ASSETS:

 

 

 

 

 

Current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

$

 

$

617

 

Non-current

 

 

 

 

 

Derivative financial instruments—interest rate swaps

 

176

 

 

Total financial assets

 

$

176

 

$

617

 

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Table of Contents

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

FINANCIAL LIABILITIES:

 

 

 

 

 

Current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

$

(188

)

$

 

Derivative financial instruments—interest rate swaps

 

(147

)

 

Non-current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

(31

)

 

Total financial liabilities

 

$

(366

)

$

 

NOTE 14—FAIR VALUE MEASUREMENT

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

Level 1:

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

Level 2:

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

Level 3:

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

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

Consolidated 31 December 2013

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets measured at fair value

 

 

 

 

 

 

 

 

 

Interest rate swap contracts

 

$

 

$

176

 

$

 

$

176

 

Liabilities measured at fair value

 

 

 

 

 

 

 

 

 

Derivative commodity contracts

 

 

(219

)

 

(219

)

Interest rate swap contracts

 

 

(147

)

 

(147

)

Net fair value

 

$

 

$

(190

)

$

 

$

(190

)

Consolidated 31 December 2012

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

$

 

$

617

 

$

 

$

617

 

Liabilities

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

 

 

 

 

Net fair value

 

$

 

$

617

 

$

 

$

617

 

During the year and six month period ended 31 December 2013 and 2012, respectively, there were no transfers between level 1 and level 2 fair value measurements, and no transfer into or out of level 3 fair value measurements.

Measurement of Fair Value

a)Derivatives

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

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NOTE 15—OTHER CURRENT ASSETS

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Cash advances to other operators

 

$

685

 

$

625

 

Escrow accounts

 

1,498

 

3,830

 

Oil inventory on hand, at cost

 

1,088

 

69

 

Prepayments

 

753

 

501

 

Other

 

14

 

 

Total other current assets

 

$

4,038

 

$

5,025

 

On 31 December 2012, the Company completed a transaction to acquire certain oil and natural gas properties in the Wattenberg field of the Denver- Julesburg (“DJ”) Basin (the “Wattenberg Acquisition”). In connection with the transaction, the Company transferred $3.0 million, $2.7 million and $0.5 million to escrow accounts related to a drilling commitment, title defect and environmental remediation, respectively ($6.2 million collectively). The use of the Wattenberg Acquisition related escrow accounts are restricted or generally will not be used to settle short-term Company operating costs, as such they have been excluded from the Company’s cash and cash equivalents balance in the consolidated statement of financial position and the consolidated statement of cash flows as at 31 December 2013 and 2012 and for the year and six month period then ended, respectively. Of this $6.2 million escrow account balance, $1.5 million and $3.8 million are classified as other current asset in the consolidated statement of financial position as at 31 December 2013 and 2012, respectively, with $2.7 million being settled during the year ended 31 December 2013.

NOTE 16—ASSETS HELD FOR SALE

As at 31 December 2013, all of the Company’s Williston properties were held for sale. The expected proceeds, net of selling costs, exceed the carrying amount. The following Williston assets and liabilities were included in assets held for sale in the consolidated statement of financial position as at 31 December 2013 (in thousands):

Development and production assets

 

$

10,489

 

Exploration and evaluation expenditure

 

1,104

 

Restoration provision liability

 

(109

)

Total assets held for sale, net of restoration provision liability

 

$

11,484

 

NOTE 17—DEVELOPMENT AND PRODUCTION ASSETS

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Costs carried forward in respect of areas of interest in:

 

 

 

 

 

Development and production assets, at cost:

 

 

 

 

 

Producing assets

 

$

297,469

 

$

70,470

 

Wells-in-progress

 

55,636

 

26,193

 

Development and production assets, at cost:

 

353,105

 

96,663

 

Accumulated amortisation

 

(40,635

)

(14,619

)

Provision for impairment(1)

 

(240

)

(2,315

)

Total Development and Production Expenditure

 

$

312,230

 

$

79,729

 

a) Movements in carrying amounts:

 

 

 

 

 

Development expenditure

 

 

 

 

 

Balance at the beginning of the period

 

$

79,729

 

$

87,274

 

Amounts capitalised during the period

 

219,121

 

46,963

 

Amounts transferred from exploration phase

 

31,999

 

527

 

Fair value of assets acquired

 

54,258

 

986

 

Reclassifications to assets held for sale

 

(10,489

)

 

Amortisation expense

 

(36,294

)

(6,013

)

Development and production assets, net of accumulated amortization, sold during the period

 

(26,094

)

(50,008

)

Balance at end of period

 

$

312,230

 

$

79,729

 

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(1)There was an impairment provision of $1.9 million associated with the Phoenix development and production properties that were sold in 2013. See Note 6—Gain on sale of non-current assets for further discussion.

NOTE 18—EXPLORATION AND EVALUATION EXPENDITURE

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Costs carried forward in respect of areas of interest in:

 

 

 

 

 

Exploration and evaluation phase, at cost

 

$

167,694

 

$

35,053

 

Provision for impairment

 

(1,550

)

(1,614

)

Total Exploration and Evaluation Expenditure

 

$

166,144

 

$

33,439

 

a) Movements in carrying amounts:

 

 

 

 

 

Exploration and evaluation

 

 

 

 

 

Balance at the beginning of the period

 

$

33,439

 

$

11,436

 

Amounts capitalised during the period

 

14,770

 

10,704

 

Fair value of assets acquired

 

151,115

 

12,644

 

Reclassifications to assets held for sale

 

(1,104

)

 

Amounts transferred to development phase

 

(31,999

)

(527

)

Exploration tenements sold during the period

 

(77

)

(818

)

Balance at end of period

 

$

166,144

 

$

33,439

 

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—PROPERTY AND EQUIPMENT

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Property and equipment, at cost

 

$

1,603

 

$

737

 

Accumulated depreciation

 

(556

)

(314

)

Total Property and Equipment

 

$

1,047

 

$

423

 

a) Movements in carrying amounts:

 

 

 

 

 

Balance at the beginning of the period

 

$

423

 

$

418

 

Amounts capitalised during the period

 

886

 

107

 

Depreciation expense

 

(262

)

(102

)

Balance at end of period

 

$

1,047

 

$

423

 

NOTE 20—OTHER NON-CURRENT ASSETS

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Escrow accounts

 

$

2,000

 

$

2,400

 

Casing and tubulars at net realisable value

 

19

 

20

 

Total other non-current assets

 

$

2,019

 

$

2,420

 

The $2.0 million and $2.4 million of escrow accounts as of 31 December 2013 and 2012, respectively, are the long-term portions related to the escrow accounts discussed in Note 15—Other Current Assets.

NOTE 21—TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Oil and natural gas related

 

$

135,381

 

$

49,407

 

Administrative expenses, including salaries and wages

 

5,146

 

2,435

 

Total trade, other payables and accrued expenses

 

$

140,527

 

$

51,842

 

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At 31 December 2013 and 2012, the Group had payable balances of $16.7 million and $15.7 million, respectively, which were outside normal payment terms. These payable balances are partially offset by receivable balances due from the same operator and which are also outside normal paying terms. See Note 12—Trade and Other Receivables for receivable balance information.

NOTE 22—CREDIT FACILITIES

 

 

31 December 2013
US$000

 

31 December 2012
US$000

 

Senior Credit Facility

 

$

15,000

 

$

30,000

 

Junior Credit Facility

 

15,000

 

 

Total credit facilities

 

30,000

 

30,000

 

Deferred financing fees

 

(859

)

(430

)

Total credit facilities, net of deferred financing fees

 

$

29,141

 

$

29,570

 

Junior Credit Facility

In August 2013, Sundance Energy, Inc. (“Sundance Energy”), a wholly owned subsidiary of the Company, entered into a second lien credit agreement with Wells Fargo Energy Capital, Inc., as the administrative agent (the “Junior Credit Facility”), which provides for term loans to be made in a series of draws up to $100 million. The Junior Credit Facility matures in June 2018 and is secured by a second priority lien on substantially all of the Company’s assets. Upon entering into the Junior Credit Facility, the Company immediately borrowed $15 million pursuant to the terms of the Junior Credit Facility and paid down the outstanding principal of the Senior Credit Facility.

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

The Company is also required under our Junior Credit Facility to maintain the following financial ratios:

·a 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 debt to adjusted consolidated EBITDAX (as defined in the Junior Credit Facility), of not greater than 4.5 to 1.0 as of the last day of any fiscal quarter (beginning 30 September 2013); and

·an asset coverage ratio, consisting of PV10 to consolidated debt, of not less than 1.5 to 1.0, as of certain test dates.

For the year ended 31 December 2013, the Company capitalised $0.3 million of financing costs related to the Junior Credit Facility, which offset the principal balance. As at 31 December 2013 there was $15 million outstanding under the Company’s Junior Credit Facility. As at 31 December 2013, the Company was in compliance with all restrictive financial and other covenants under the Junior Credit Facility.

Senior Credit Facility

On 31 December 2012, Sundance Energy entered into a credit agreement with Wells Fargo Bank, N.A. (the “Senior Credit Facility”), pursuant to which up to $300 million is available on a revolving basis. The borrowing base under the Senior Credit Facility is determined by reference to the value of the Company’s proved reserves. The agreement specifies a semi-annual borrowing base redetermination and the Company can request two additional redeterminations each year. The initial borrowing base was set at $30 million and was subsequently increased to $48 million based on March 2013 reserves.

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Interest on borrowed funds accrue, at the Company’s option, of i) LIBOR plus a margin that ranges from 175 to 275 basis points or ii) the Base Rate, defined as a rate equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Prime Rate, or (c) LIBOR plus a margin that ranges from 75 to 175 basis points. The applicable margin varies depending on the amount drawn. The Company also pays a commitment that ranges from 37.5 to 50 basis points on the undrawn balance of the borrowing base. The agreement has a five-year term and contains both negative and affirmative covenants, including minimum current ratio and maximum leverage ratio requirements consistent with the Junior Credit Facility’s. Certain development and production assets are pledged as collateral and the facility is guaranteed by the Parent Company. On 31 December 2012, the Company drew $30 million on the Senior Credit Facility’s borrowing base and used $15 million of the proceeds to repay and retire its outstanding loan with the Bank of Oklahoma. As a part of its Bank of Oklahoma debt extinguishment, the Company expensed approximately $0.3 million of unamortised deferred financing costs, which is included in financing costs in the consolidated statement of profit or loss and other comprehensive income for the six month period ended 31 December 2012.

For the year and six month period ended 31 December 2013 and 2012, the Company capitalised $0.2 million and $0.4 million, respectively, of financing costs related to the Senior Credit Facility, which offset the principal balance. As at 31 December 2013 there was $15 million outstanding under the Company’s Senior Credit Facility. As at 31 December 2013, the Company was in compliance with all restrictive financial and other covenants under the Senior Credit Facility.

The Company capitalised $1.3 million and nil of interest expense during the year and six month period ended 31 December 2013 and 2012, respectively.

NOTE 23—RESTORATION PROVISION

The restoration provision represents the best estimate of the present value of restoration costs relating to the Company’s oil and natural gas interests, which are expected to be incurred up to 2043. 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.

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Balance at the beginning of the period

 

$

1,228

 

$

588

 

New provisions and changes in estimates

 

3,622

 

310

 

Dispositions

 

(146

)

(192

)

New provisions assumed from acquisition

 

397

 

506

 

Reclassified to assets held for sale

 

(109

)

 

Unwinding of discount

 

82

 

16

 

Balance at end of period

 

$

5,074

 

$

1,228

 

NOTE 24—DEFERRED TAX ASSETS AND LIABILITIES

Deferred tax assets and liabilities are attributable to the following:

 

 

31 December 2013
US$’000

 

31 December 2012
US$’000

 

Net deferred tax assets:

 

 

 

 

 

Share issuance costs

 

$

1,069

 

$

 

Net operating loss carried forward

 

473

 

 

Unrecognized foreign currency gain (loss)

 

761

 

 

Total net deferred tax assets

 

$

2,303

 

$

 

Deferred tax liabilities:

 

 

 

 

 

Development and production expenditure

 

$

(114,042

)

$

(79,600

)

Offset by deferred tax assets with legally enforceable right of set- off:

 

 

 

 

 

Net operating loss carried forward

 

10,373

 

22,647

 

Other

 

958

 

(26

)

Total net deferred tax liabilities

 

$

(102,711

)

$

(56,979

)

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Table of Contents

NOTE 25—ISSUED CAPITAL

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

a)Ordinary Shares

Number of Shares

Total shares issued and outstanding at 30 June 2012

277,098,474

Shares issued during the period

1,666,667

Total shares issued and outstanding at 31 December 2012

278,765,141

Shares issued during the year

184,408,527

Total shares issued and outstanding at 31 December 2013

463,173,668

Ordinary shares participate in dividends and the proceeds on winding 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.

b)Issued Capital

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Beginning of the period

 

$

58,694

 

$

57,978

 

Shares issued in connection with:

 

 

 

 

 

Merger with Texon

 

132,092

 

 

Private placement

 

47,398

 

 

Exercise of stock options

 

813

 

716

 

Total shares issued during the period

 

180,303

 

716

 

Cost of capital raising during the period, net of tax

 

(1,989

)

 

Closing balance at end of period

 

$

237,008

 

$

58,694

 

c)Options on Issue

Details of the share options outstanding as at the end of the period:

Grant Date

 

Expiry Date

 

Exercise Price

 

31 December 2013

 

31 December 2012

 

10 Sep 2010

 

31 May 2013

 

A$0.20

 

 

1,000,000

 

10 Sep 2010

 

31 May 2013

 

A$0.30

 

 

500,000

 

02 Dec 2010

 

01 Dec 2015

 

A$0.37

 

291,666

 

1,166,666

 

02 Mar 2011

 

30 Jun 2014

 

A$0.95

 

30,000

 

30,000

 

03 Jun 2011

 

31 May 2013

 

A$0.35

 

 

100,000

 

03 Jun 2011

 

15 Jan 2016

 

A$0.65

 

500,000

 

500,000

 

03 Jun 2011

 

28 Jan 2016

 

A$0.50

 

 

250,000

 

06 Jun 2011

 

01 Sep 2015

 

A$0.95

 

30,000

 

30,000

 

06 Sep 2011

 

31 Dec 2018

 

A$0.95

 

1,200,000

 

1,200,000

 

05 Dec 2011

 

05 Mar 2019

 

A$0.95

 

1,000,000

 

1,000,000

 

01 Nov 2012

 

01 Feb 2020

 

A$1.15

 

350,000

 

 

03 Dec 2012

 

03 Mar 2020

 

A$1.15

 

350,000

 

 

01 Apr 2013

 

01 Jul 2020

 

A$1.25

 

350,000

 

 

24 Sept 2013

 

23 Dec 2020

 

A$1.40

 

950,000

 

 

Total share options outstanding

 

 

 

 

 

5,051,666

 

5,776,666

 

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Table of Contents

d)Restricted Share Units on Issue

Details of the restricted share units outstanding as at the end of the period:

Grant Date

 

31 December 2013

 

31 December 2012

 

05 Dec 2011

 

88,500

 

608,750

 

15 Oct 2012

 

709,817

 

1,482,143

 

19 April 2013

 

905,990

 

 

Total RSUs outstanding

 

1,704,307

 

2,090,893

 

e)Capital Management

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

The Group’s debt and capital includes ordinary share capital and financial liabilities, supported by financial assets. Other than the covenants described in Note 22, 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 the Group’s gearing ratio remains minimal. As at 31 December 2013 and 2012, the Company had $29.1 million and $29.6 million of outstanding debt, net of deferred financing fees, respectively.

NOTE 26—RESERVES

a)Share Option Reserve

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

b)Foreign Currency Translation Reserve

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

NOTE 27—CAPITAL AND OTHER EXPENDITURE COMMITMENTS

Capital commitments relating to tenements

As at 31 December 2013, all of the Company’s exploration and evaluation and development and production assets are located in the United States of America (“US”).

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

 

 

As At 31 December 2013

 

 

 

Total

 

Less than
1 year

 

1 - 5 years

 

More than
5 years

 

Drilling rig commitments(1)

 

$

5,159

 

$

5,159

 

$

 

$

 

Drilling commitments(2)

 

2,000

 

 

2,000

 

 

Operating lease commitments(3)

 

1,860

 

200

 

1,354

 

306

 

Employment commitments(4)

 

104

 

104

 

 

 

Total expenditure commitments

 

$

9,123

 

$

5,463

 

$

3,354

 

$

306

 

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Table of Contents

 

 

As at 31 December 2012

 

 

 

Total

 

Less than
1 year

 

1 - 5 years

 

More than
5 years

 

Drilling commitments(2)

 

$

3,000

 

$

 

$

3,000

 

$

 

Operating lease commitments(3)

 

243

 

162

 

81

 

 

Employment commitments(4)

 

379

 

275

 

104

 

 

Total expenditure commitments

 

$

3,622

 

$

437

 

$

3,185

 

$

 


(1)As at 31 December 2013, the Company had 4 outstanding drilling rig contracts to explore and develop the Company’s properties. The contracts generally have terms of 6 to 12 months. Amounts represent minimum expenditure commitments should the Company elect to terminate these contracts prior to term. Subsequent to year end, the Company entered into a drilling rig contract in which minimum commitments due to early termination would be $2.1 million.

(2)On 31 December 2012, the Company entered into an agreement to acquire certain oil and natural gas properties located in the Wattenberg Field and to drill 45 net wells by 31 December 2015 on the acquired properties (the “Drilling Commitment”). As each qualifying well is drilled, approximately $67 thousand is paid from the escrow account to the Company. However, for each required net commitment well not completed by the Company during that prorated commitment year, the Company is to pay the seller of the properties approximately $67 thousand from the escrow account. Certain clawback provisions allow the Company to recoup amounts paid to the sellers if the total 45 wells are drilled by 31 December 2015. As at 31 December 2013, the Company has not yet drilled any wells, as such, $1.0 million, equal to one third of the total commitment, was accrued and recognised in other (expense) income in the consolidated statement of profit or loss and comprehensive income and was released from the escrow account subsequent to the balance sheet date.

(3)Represents commitments for minimum lease payments in relation to non-cancellable operating leases for office space not provided for in the consolidated financial statements.

(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.

NOTE 28—CONTINGENT ASSETS AND LIABILITIES

At the date of signing this report, the Group is not aware of any contingent assets or liabilities that should be recognised or disclosed in accordance with AASB 137—Provisions, Contingent Liabilities and Contingent Assets / IFRS 37—Provisions, Contingent Liabilities and Contingent Assets.

NOTE 29—OPERATING SEGMENTS

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America, which is the Company’s only major line of business and only major geographic area of operations. All of the basins and/or formations in which the Company operates have common operational characteristics, challenges and economic characteristics. As such, Management has determined, based upon the reports reviewed by the Chief Operating Decision Maker (“CODM”) and used to make strategic decisions, that the Company has one reportable segment being oil and natural gas exploration and production in North America.

The CODM reviews internal management reports on a monthly basis that are consistent with the information provided in the statement of profit or loss and other comprehensive income, statement of financial position and statement of cash flows. As a result no reconciliation is required, because the information as presented is used by the CODM to make strategic decisions.

Geographic Information

The operations of the Group are located in only one geographic location, the United States of America. All revenue is generated from sales to customers located in the US.

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Revenue from four major customers exceeded 10 percent of Group consolidated revenue for the year ended 31 December 2013 and accounted for 47 percent, 15 percent, 10 percent and 10 percent (six month period ended 31 December 2012: four major customers accounted for 29 percent, 22 percent, 21 percent and 10 percent) of our consolidated oil and natural gas revenues.

NOTE 30—CASH FLOW INFORMATION

a)Reconciliation of cash flows from operations with income from ordinary activities after income tax

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Profit from ordinary activities after income tax

 

$

15,942

 

$

76,210

 

Non cash flow in operating income

 

 

 

 

 

Depreciation and amortisation expense

 

36,225

 

6,116

 

Share options expensed

 

1,590

 

733

 

Unrealised losses on derivatives

 

837

 

1,190

 

Net gain on sale of properties

 

(7,335

)

(122,327

)

Write-off of Bank of Oklahoma deferred financing fees

 

 

349

 

Other

 

(13

)

 

Changes in assets and liabilities:

 

 

 

 

 

—Increase in current and deferred tax

 

5,812

 

46,616

 

—Decrease (increase) in other assets, excluding investing activities

 

2,155

 

(381

)

—Increase in trade and other receivables

 

(3,541

)

(3,320

)

—Increase in trade and other payables

 

10,974

 

4,200

 

Net cash provided by operating activities

 

$

62,646

 

$

9,386

 

b)Non Cash Financing and Investing Activities

·During the year ended 31 December 2013 $132.1 million in shares were issued in connection with the Texon acquisition.

NOTE 31—SHARE BASED PAYMENTS

During the year and six month period ended 31 December 2013 and 2012, a total of 2,000,000 and nil options were granted to employees pursuant to employment agreements and a total of 2,725,000 and 1,666,667 previously issued options were exercised, respectively. There were 700,000 awarded options that the Company expected to issue in early 2013 for which Company employees rendered services during the six month period ended 31 December 2012. Using the best estimate of fair value on the employees’ hire date, the Company began expensing these awards during the six month period ended 31 December 2012. The 700,000 options were issued in early 2013, but were excluded from the outstanding options summary below as at 31 December 2012:

 

 

Year ended
31 December 2013

 

Six months ended
31 December 2012

 

 

 

Number of
Options

 

Weighted
Average
Exercise Price A$

 

Number of
Options

 

Weighted
Average
Exercise Price A$

 

Outstanding at start of period

 

5,776,666

 

0.59

 

7,443,333

 

0.55

 

Formally issued

 

2,000,000

 

1.29

 

 

 

Forfeited

 

 

 

 

 

Exercised

 

(2,725,000

)

0.31

 

(1,666,667

)

0.41

 

Expired

 

 

 

 

 

Outstanding at end of period

 

5,051,666

 

1.02

 

5,776,666

 

0.59

 

Exercisable at end of period

 

2,241,666

 

0.87

 

3,729,999

 

0.44

 

The following tables summarise the options issued and awarded and their related grant date, fair value and vesting conditions for the year and six month period ended 31 December 2013 and 2012, respectively:

Options issued during the year ended 31 December 2013:

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Grant Date

 

Number of
Options

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

1 April 2013

 

350,000

 

$

217

 

20% issuance date, 20% first four anniversaries

 

24 September 2013

 

950,000

 

$

475

 

20% issuance date, 20% first four anniversaries

 

Total

 

1,300,000

 

$

692

 

 

 

Options awarded, but not yet issued during the six month period ended 31 December 2012:

Award Date (not issued)

 

Number of
Options

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

1 November 2012

 

350,000

 

$

145

 

20% issuance date, 20% first four anniversaries

 

3 December 2012

 

350,000

 

$

157

 

20% issuance date, 20% first four anniversaries

 

 

 

700,000

 

$

302

 

 

 

Share based payments expense related to options is determined pursuant to AASB 2—Share Based Payments (“AASB 2”) / IFRS 2—Share Based Payments (“IFRS 2”), and is recognised pursuant to the attached vesting conditions. The fair value of the options awarded ranged from A$0.53 to A$0.59 and A$0.42 to A$0.45 for the year and six month period ended 31 December 2013 and 2012, respectively, which were calculated using a Black-Sholes options pricing model. Expected volatilities are based upon the historical volatility of the ordinary shares. Historical data is also used to estimate the probability of option exercise and potential forfeitures. Included in the 2,000,000 options issued during the year ended 2013 were 700,000 options that were granted in the fourth quarter of 2012, which began being expensed during the six month period ended 31 December 2012 according to the relevant service periods.

The following table summarises the key assumptions used to calculate the estimated fair value awarded or granted during the periods:

 

 

Issued during
year ended
31 December 2013

 

Issued in
early 2013(1)

 

Share price:

 

A$1.06 - 1.10

 

A$0.78 - A$0.82

 

Exercise price:

 

A$1.25 - 1.40

 

A$1.15

 

Expected volatility:

 

60%

 

65%

 

Option term:

 

5.75 years

 

5.75 years

 

Risk free interest rate:

 

2.82% to 3.10%

 

2.75%

 


(1)As at 31 December 2012, options were subject to formal issuance, but had been awarded and expensed beginning on the employees’ hire date during the six month period ended 31 December 2012.

Restricted Share Units

During the year and six month period ended 31 December 2013 and 2012, the Board of Directors awarded 1,237,994 and 1,482,143 RSUs to certain employees. These awards were made in accordance with the long-term equity component of the Company’s incentive compensation plan, the details of which are described in more detail in the remuneration section of the Directors’ Report. Share based payment expense for RSUs awarded was calculated pursuant to AASB 2 / IFRS 2. The fair values of RSUs were estimated at the date they were approved by the Board of Directors, 19 April 2013 and 15 October 2012 (the measurement dates). As at 30 June 2012, the 5 December 2011 awards had been approved but not yet issued. All unforfeited awards were issued to employees upon finalisation of the plan documents, which occurred in December 2012. The value of the vested portion of these awards has been recognised within the financial statements. This information is summarised for the Group for the year and six month period ended 31 December 2013 and 2012, respectively, below:

Year ended 31 December 2013

Number
of RSUs

Weighted Average
Fair Value at
Measurement Date

Outstanding at beginning of year

2,090,893

A$0.59

Issued

1,237,994

A$0.91

Converted to ordinary shares

(1,511,511

)

A$0.76

Forfeited

(113,069

)

A$0.76

Outstanding at end of year

1,704,307

A$0.83

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Six months ended
31 December 2012

Number
of RSUs

Weighted Average
Fair Value at
Measurement Date

Awarded, but not yet issued (beginning of period)*

910,000

A$0.38

Forfeited prior to finalisation of plan*

(301,250

)

A$0.38

Formally issued (in addition to unissued units at beginning of period)

1,482,143

A$0.68

Forfeited subsequent to finalisation of plan

Converted to ordinary shares

Outstanding at end of period

2,090,893

A$0.59

Vested at end of period

765,286

A$0.48


*RSUs awarded, but not yet issued at beginning of period were issued upon finalisation of the plan during the period ended 31 December 2012 and are included in the total outstanding at end of period (net of forfeited units).

The following tables summarise the RSUs issued and their related grant date, fair value and vesting conditions for the year and six month period ended 31 December 2013 and 2012, respectively:

RSUs awarded during the year ended 31 December 2013:

Grant Date

 

Number
of RSUs

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

19 April 2013

 

863,746

 

$

789

 

25% issuance date, 25% first three anniversaries

 

28 May 2013

 

374,248

 

$

354

 

25% issuance date, 25% first three anniversaries

 

 

 

1,237,994

 

$

1,143

 

 

 

RSUs issued during the six month period ended 31 December 2012:

Grant Date

 

Number
of RSUs

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

15 October 2012

 

1,080,358

 

$

809

 

25% issuance date, 25% first three anniversaries

 

29 November 2012

 

401,785

 

$

340

 

25% issuance date, 25% first three anniversaries

 

 

 

1,482,143

 

$

1,149

 

 

 

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

NOTE 32—RELATED PARTY TRANSACTIONS

N Martin was previously a partner of Minter Ellison Lawyers and is now a consultant for Minter Ellison Lawyers as well as a Director of the Company. Minter Ellison Lawyers were paid a total of $0.2 million and $0.1 million for legal services for the year and six month period ended 31 December 2013 and 2012, respectively.

NOTE 33—FINANCIAL RISK MANAGEMENT

a)Financial Risk Management Policies

The Group is exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. The Group’s risk management strategy focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. The Group utilises derivative financial instruments to hedge exposure to

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fluctuations in interest rates and commodity prices. The Group’s financial instruments consist mainly of deposits with banks, short term investments, accounts receivable, derivative financial instruments, finance facility, and payables. The main purpose of non-derivative financial instruments is to raise finance for the Group operations.

i)Treasury Risk Management

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

ii)Financial Risk Exposure and Management

Interest rate risk is managed with a mixture of fixed and floating rate cash deposits. As at 31 December 2013 and 2012 approximately nil of Group deposits are fixed. It is the policy of the Group to keep surplus cash in interest yielding deposits.

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.

During the year ended 31 December 2013, the Group entered into US dollar denominated interest rate swaps which fix the interest rate associated with the credit facilities to protect against the floating LIBOR rates through 2017.

As at 31 December 2013 the Group had interest rate swaps with a notional contract amount of $15.0 million (2012: nil).

The net fair value of interest rate swaps at 31 December 2013 was relatively immaterial, comprising long-term assets of $0.2 million and current liabilities of $0.1 million. These amounts were recognised as fair value derivatives.

iii)Commodity Price Risk Exposure and Management

The Board actively reviews oil and 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 and LLS market spot rates reduced for basis differentials in the basins from which the Company produces. Gas is sold using Henry Hub and Houston Ship Channel 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 less than 50% of anticipated future oil and gas production for up to 24 months. The Group may hedge over 50% or beyond 24 months with approval of the Board. The Group has not elected to utilise hedge accounting treatment and changes in fair value are recognised in the statement of profit or loss and other comprehensive income.

Commodity Hedge Contracts outstanding as at 31 December 2013

Contract Type

Counterparty

Basis

Quantity/mo

Strike Price

Term

Collar

Shell Trading US

NYMEX

2.500 BBL

$80.00/$98.25

1-Jul-14 - 31-Dec-14

Collar

Wells Fargo

NYMEX

3,000 BBL

$90.00/$99.75

1-Jul-13 - 30-Jun-14

Collar

Wells Fargo

NYMEX

3,000 BBL

$85.00/$94.75

1-Jan-14 - 31-Dec-14

Swap

Wells Fargo

NYMEX

2,000 BBL

$97.40

1-Jan-14 - 31-Dec-14

Collar

Wells Fargo

NYMEX

2,000 BBL

$75.00/$98.65

1-Jan-15 - 31-Dec-15

Collar

Wells Fargo

NYMEX

2,000 BBL

$90.00/$102.85

1-Jan-14 - 31-Dec-14

Collar

Wells Fargo

NYMEX

2,000 BBL

$80.00/$97.00

1-Jan-15 - 31-Dec-15

Collar

Shell Trading US

LLS

2,000 BBL

$90.00/$102.00

1-Jan-14 - 31-Dec-14

Collar

Shell Trading US

LLS

3,000 BBL

$90.00/$101.30

1-Jan-14 - 31-Dec-14

Collar

Shell Trading US

LLS

2,000 BBL

$85.00/$102.00

1-Jul-14 - 31-Dec-14

Collar

Shell Trading US

LLS

3,000 BBL

$85.00/$101.05

1-Jan-15 - 31-Dec-15

Swap

Wells Fargo

LLS

3,000 BBL

$101.75

1-Jul-13 - 30-Jun-14

Swap

Wells Fargo

LLS

3,000 BBL

$100.15

1-Jan-14 - 31-Dec-14

Swap

Wells Fargo

LLS

3,000 BBL

$102.30

1-Jan-14 - 31-Dec-14

Swap

Shell Trading US

HH

20,000 MCF

$4.23

1-Jan-14 - 31-Dec-14

Collar

Shell Trading US

HSC

10,000 MCF

$3.75/$4.60

1-Jan-14 - 31-Dec-14

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Table of Contents

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. The balances are not materially different from those disclosed in the consolidated statement of financial position of the Group.

c)Credit Risk

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

The maximum exposure to credit risk, excluding the value of any collateral or other security, at balance date to recognise the financial assets, is the carrying amount, net of any impairment of those assets, as disclosed in the balance sheet and notes to the financial statements.

The Group does not have any material credit risk exposure to any single debtor or group of debtors under financial instruments entered into by the consolidated entity.

d)Liquidity Risk

Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and the availability of funding through an adequate committed credit facility. The Company aims to maintain flexibility in funding to meet ongoing operational requirements and exploration and development expenditures by keeping a committed credit facility available.

The Company has the following commitments related to its non-derivative financial liabilities as at 31 December 2013 (in 000s):

 

 

Total

 

Less than
1 year

 

1 - 5 years

 

More than
5 years

 

Trade and other payable

 

$

62,811

 

$

62,811

 

$

 

$

 

Accrued expenses

 

77,716

 

77,716

 

 

 

Credit facilities payments

 

37,037

 

1,600

 

35,437

 

 

Total

 

$

177,564

 

$

142,127

 

$

35,437

 

$

 

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Table of Contents

The Company has the following commitments related to its non-derivative financial liabilities as at 31 December 2012 (in 000s):

 

 

Total

 

Less than
1 year

 

1 - 5 years

 

More than
5 years

 

Trade and other payable

 

$

38,770

 

$

38,770

 

$

 

$

 

Accrued expenses

 

13,072

 

13,072

 

 

 

Credit facilities payments

 

30,000

 

 

30,000

 

 

Total

 

$

81,842

 

$

51,842

 

$

30,000

 

$

 

e)Market Risk

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

Commodity Price Risk

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

Commodity Price Risk Sensitivity Analysis

The table below summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are and therefore fair valued 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 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Change in profit/(loss)

 

 

 

 

 

Oil

 

 

 

 

 

—improvement in US$ oil price of $10 per barrel

 

$

(2,351

)

$

(702

)

—decline in US$ oil price of $10 per barrel

 

1,477

 

840

 

Gas

 

 

 

 

 

—improvement in US$ gas price of $0.50 per mcf

 

$

(124

)

$

(60

)

—decline in US$ gas price of $0.50 per mcf

 

180

 

60

 

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 2013, taking into account interest rate swaps, 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 2013
US$’000

 

Six month ended
31 December 2012
US$’000

 

Change in profit/(loss)

 

 

 

 

 

—increase in interest rates + 2%

 

$

(177

)

$

(157

)

—decrease in interest rates - 2%

 

 

157

 

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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.

Foreign Currency Risk

The Group is exposed to fluctuations in foreign currency arising from transactions in currencies other than the Group’s functional currency (US$).

NOTE 34—PARENT COMPANY INFORMATION

a)Cost Basis

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Parent Entity

 

 

 

 

 

Assets

 

 

 

 

 

Current assets

 

$

1,962

 

$

1,490

 

Investment in subsidiaries

 

173,633

 

134,094

 

Non-current assets

 

42,840

 

 

Total assets

 

$

218,435

 

$

135,584

 

Liabilities

 

 

 

 

 

Current liabilities

 

$

425

 

$

127

 

Non-current liabilities

 

 

 

Total Liabilities

 

425

 

127

 

Total net assets

 

$

218,010

 

$

135,457

 

Equity

 

 

 

 

 

Issued capital

 

237,008

 

58,694

 

Share options reserve

 

386

 

386

 

Foreign currency translation

 

(20,509

)

925

 

Retained earnings (loss)

 

1,125

 

75,452

 

Total equity

 

$

218,010

 

$

135,457

 

Financial Performance

 

 

 

 

 

Profit/(loss) for the period

 

$

275

 

$

(241

)

Other comprehensive income

 

(31,307

)

 

Total profit or loss and other comprehensive income

 

$

(31,032

)

$

(241

)

b)Equity Basis

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Parent Entity

 

 

 

 

 

Assets

 

 

 

 

 

Current assets

 

$

1,962

 

$

1,490

 

Investment in subsidiaries

 

302,864

 

150,453

 

Non-current assets

 

42,840

 

 

Total assets

 

$

347,666

 

$

151,943

 

Liabilities

 

 

 

 

 

Current liabilities

 

$

425

 

$

127

 

Non-current liabilities

 

 

 

Total Liabilities

 

425

 

127

 

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Table of Contents

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Total net assets

 

$

347,241

 

$

151,816

 

Equity

 

 

 

 

 

Issued capital

 

237,008

 

58,694

 

Share options reserve

 

5,635

 

4,045

 

Foreign currency translation

 

(1,516

)

(1,095

)

Retained earnings (loss)

 

106,114

 

90,172

 

Total equity

 

$

347,241

 

$

151,816

 

Financial Performance

 

 

 

 

 

Profit/(loss) for the period before equity in income of subsidiaries

 

$

275

 

$

(241

)

Equity in income of subsidiaries

 

15,667

 

76,451

 

Other comprehensive income

 

(421

)

(154

)

Total profit or loss and other comprehensive income

 

$

15,521

 

$

76,056

 

c)Cash Flow

 

 

Year ended
31 December 2013
US$’000

 

Six months ended
31 December 2012
US$’000

 

Cash flow from operating activities

 

$

(42,934

)

$

(1,655

)

Cash flow from investing activities

 

(136,890

)

11

 

Cash flow from financing activities

 

179,904

 

716

 

NOTE 35—DEED OF CROSS GUARANTEE

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

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

The Closed Group was formed in 2013; therefore, there is no comparable information.

Set out below is a consolidated statement of profit or loss and other comprehensive income and retained earnings for the year ended 31 December 2013 of the Closed Group:

 

 

Year ended
31 December 2013
US$’000

 

Profit / (loss) before income tax

 

$

(1,497

)

Income tax benefit

 

1,780

 

Profit attributable to members of SEAL

 

$

283

 

Total comprehensive loss attributable to members of SEAL

 

$

(18,924

)

Retained earnings at 1 January

 

$

849

 

Retained earnings at 31 December

 

$

1,132

 

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Set out below is a condensed consolidated statement of financial position as at 31 December 2013 of the Closed Group:

 

 

31 December 2013
US$’000

 

Current assets

 

 

 

Cash and cash equivalents

 

$

1,558

 

Other current assets

 

2,200

 

Total current assets

 

3,758

 

Non-current assets

 

 

 

Exploration and evaluation expenditure

 

170

 

Related party note receivable

 

40,537

 

Other non-current assets

 

174,240

 

Total non-current assets

 

214,947

 

Total assets

 

$

218,705

 

Current liabilities

 

 

 

Trade and other payables

 

176

 

Accrued expenses

 

302

 

Total current liabilities

 

478

 

Non-current liabilities

 

 

 

Deferred tax liabilities

 

4

 

Total non-current liabilities

 

4

 

Total liabilities

 

$

482

 

Net assets

 

$

218,223

 

Equity

 

 

 

Issued capital

 

$

237,008

 

Share option reserve

 

386

 

Foreign currency translation

 

(20,303

)

Retained earnings

 

1,132

 

Total equity

 

$

218,223

 

NOTE 36—EVENTS AFTER THE BALANCE SHEET DATE

In May 2014, the Company entered into a Purchase and Sale Agreement to divest of its remaining Denver-Julesburg Basin assets. The sale price of $116 million in cash includes capital expenditure reimbursement on 8 gross (3.1 net) non- operated horizontal wells. The sale is expected to close in the third quarter of 2014.

In July 2014, the Company acquired the working interests in 9,200 gross (5,700 net) and 18,000 gross (5,400 net) mineral acres in Dimmit and Maverick Counties, Texas, respectively. The purchase price includes an initial cash payment of $33 million and a commitment to drill four Eagle Ford wells. In addition, the Company has the option, at its sole discretion, to acquire the Seller’s remaining working interests in Dimmit and Maverick Counties, Texas (including the Seller’s interest in producing wells) for an additional $45 million (comprised of the Seller’s choice of all cash or cash and ordinary shares, with certain restrictions).

In May 2014, the Company’s borrowing capacity under its Credit Facilities increased from $63 million to $135 million. Contemporaneously with and subsequent to the borrowing base redetermination, the Company drew an additional $50 million of net debt under its Credit Facilities, which increased the debt outstanding to $80 million as of June 30, 2014.

In April 2014, the Company acquired approximately 4,800 net acres in the Eagle Ford for an initial purchase price of approximately $10.5 million and two separate earn out payments due upon commencement of drilling ($7.7 million) and payout of the first six wells drilled on the acreage ($7.7 million). The term of the agreement is two years and provides a one year extension for $500 per acre extended. This acreage is adjacent to the Company’s current acreage in McMullen County, Texas.

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In February 2014, the Company completed a placement of 84.2 million ordinary shares at A$0.95 per share, raising A$80.0 million. The first tranche of 63.7 million shares were issued in March 2014 and the second tranche of 20.5 million shares were issued in April 2014. The placement was undertaken after the Company chose not to proceed with its U.S. initial public offering as it did not meet the goals and objectives of the proposed issue. As a result, the Company expensed all transaction costs incurred on the initial public offering as at 31 December 2013 of $2.1 million.

After year-end, there was a well site accident in which two employees of a sub-contractor were injured. One of those employees subsequently passed away from their injuries. Due to various available indemnities and applicable insurance coverage, the Company believes the resolution of any potential claims that may ultimately name the Company as a defendant will not have a material adverse effect on its financial condition or results of operations

NOTE 37—UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES

Costs Incurred

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

(in thousands)

 

Year ended
31 December 2013

 

Six months ended
31 December 2012

 

Property Acquisition Costs

 

 

 

 

 

Proved(1)

 

$

158,116

 

$

986

 

Unproved(1)

 

60,690

 

23,330

 

Exploration costs

 

1,338

 

 

Development costs(2)

 

219,121

 

46,981

 

 

 

$

439,265

 

$

71,297

 


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

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

Oil and Gas Reserve Information

Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interest owned by the Company as at 31 December 2013 and 2012. The individual primarily responsible for overseeing the review is a Senior Vice President with NSAI and a Registered Professional Engineer in the State of Texas with over 30 years of experience in oil and gas reservoir studies and evaluations.

Proved reserves are those quantities of oil and 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.

 

 

Oil
(MBbl)

 

Natural
Gas
(MMcf)

 

NGL(1)
(MBbl)

 

Total Oil
Equivalents
(MBbl)

 

Total proved reserves:

 

 

 

 

 

 

 

 

 

30 June 2012

 

7,979

 

13,052

 

 

10,155

 

Revisions of previous estimates

 

(556

)

(1,205

)

 

(757

)

Extensions and discoveries

 

1,597

 

4,322

 

 

2,317

 

Purchases of reserves in-place

 

827

 

5,797

 

 

1,793

 

Production

 

(195

)

(233

)

 

(234

)

Sales of reserves in-place

 

(3,894

)

(4,845

)

 

(4,702

)

31 December 2012

 

5,758

 

16,888

 

 

8,572

 

Revisions of previous estimates

 

(1,160

)

(4,091

)

74

 

(1,767

)

Extensions and discoveries

 

7,081

 

16,270

 

1,946

 

11,739

 

Purchases of reserves in-place

 

3,857

 

4,674

 

758

 

5,393

 

Production

 

(827

)

(934

)

(96

)

(1,079

)

Sales of reserves in-place

 

(1,753

)

(2,152

)

 

(2,111

)

31 December 2013

 

12,956

 

30,655

 

2,683

 

20,747

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

30 June 2012

 

2,564

 

4,905

 

 

3,382

 

31 December 2012

 

1,932

 

5,242

 

 

2,805

 

31 December 2013

 

4,140

 

10,765

 

1,087

 

7,021

 

Proved undeveloped reserves

 

 

 

 

 

 

 

 

 

30 June 2012

 

5,415

 

8,147

 

 

6,773

 

31 December 2012

 

3,826

 

11,646

 

 

5,767

 

31 December 2013

 

8,816

 

19,890

 

1,596

 

13,726

 


(1)Prior to the year ended 31 December 2013, the Company’s NGL Proved Reserves were insignificant; and as such, were included in Natural Gas Proved Reserves and not separately reported in the Company’s reserve report.

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. With the exception of its Eagle Ford formation, the Company uses only Proved Developed Reserves in its depletable Reserve base. In addition to Proved Developed Reserves, the Company included Probable Developed Reserves of 887.3 MBoe in its Eagle Ford depletable Reserve base used for its six-month ended 31 December 2013 depletion calculation. The Proved and Probable Developed Reserves represent managements’ best estimate of economically recoverable reserves associated with developed properties located in the Eagle Ford formation.

Revisions of Previous Estimates

The Company’s previous estimates of Proved Reserves related to the Denver-Julesburg decreased by 1,431 MBoe in 2013 (81 percent of the Company’s total revisions of previous estimate). This decrease was due to adjusted forecasts for the Denver-Julesburg.

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Extensions and Discoveries

During the six-month period ended December 31, 2012, we added 2,317 MBoe through extensions and discoveries. Of these additions, approximately 1,522, 306 and 489 MBoe were attributable to our Wattenberg, Bakken and Mississippian/Woodford assets, respectively.

As a result of the Company’s active 2013 drilling programs in its Eagle Ford and Mississippian/Woodford formations, the Proved Reserves had extensions and discoveries of 5,378 MBoe 4,252 MBoe, which represent 46 and 36 percent of the Company’s total extensions and discoveries, respectively.

Purchase of Reserves In-Place

During the six-months ended December 31, 2012, our purchase of reserves were located in the Machii Ross project of the Wattenberg.

During the year ended December 31, 2013, our purchase of reserves were located in the Eagle Ford.

Sales of Reserves In-Place

During the six-months ended December 31, 2012, our sales of reserves were located in the South Antelope prospect of the Bakken.

During the year ended December 31, 2013, our sales of reserves were located in the Phoenix prospect of the Bakken.

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. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth our Standardized Measure:

(in thousands)

 

Year ended
31 December 2013

 

Six months ended
31 December 2012

 

Cash inflows

 

$

1,407,871

 

$

594,549

 

Production costs

 

(393,300

)

(198,304

)

Development costs

 

(382,259

)

(113,531

)

Income tax expense

 

(137,994

)

(51,408

)

Net cash flow

 

494,318

 

231,306

 

10% annual discount rate

 

(226,155

)

(115,759

)

Standardized measure of discounted future net cash flow

 

$

268,163

 

$

115,547

 

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

(in thousands)

 

Year ended
31 December 2013

 

Six months ended
31 December 2012

 

Standardized Measure, beginning of period

 

$

115,547

 

$

137,285

 

Sales, net of production costs

 

(66,962

)

(13,642

)

Net change in sales prices, net of production costs

 

6,450

 

(4,997

)

Extensions and discoveries, net of future production and development costs

 

182,267

 

41,481

 

Changes in future development costs

 

16,222

 

(3,565

)

Previously estimated development costs incurred during the period

 

13,854

 

33,714

 

Revision of quantity estimates

 

(33,809

)

(15,138

)

Accretion of discount

 

13,558

 

17,442

 

Change in income taxes

 

(48,786

)

17,098

 

Purchases of reserves in-place

 

131,043

 

7,626

 

Sales of reserves in-place

 

(36,935

)

(87,374

)

Change in production rates and other

 

(24,286

)

(14,383

)

Standardized Measure, end of period

 

$

268,163

 

$

115,547

 

The following table provides a reconciliation of PV10 to the Standardized Measure:

(in thousands)

 

Year ended
31 December 2013

 

Six months ended
31 December 2012

 

PV10 of proved reserves

 

$

336,984

 

$

135,582

 

Present value of future income tax discounted at 10%

 

(68,821

)

(20,035

)

Standardized Measure

 

$

268,163

 

$

115,547

 

Impact of Pricing

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

The following average prices were used in determining the Standardized Measure as at:

 

 

Year ended
31 December 2013

 

Six months ended
31 December 2012

 

Oil price per Bbl

 

$

94.55

 

$

94.71

 

Gas price per Mcf

 

$

3.45

 

$

2.75

 

NGL price per Bbl

 

$

28.78

 

N/A

 

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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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Sundance Energy Australia Limited

We have audited the accompanying consolidated statement of financial position of Sundance Energy Australia Limited as of December 31, 2012, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity, and cash flows for the half year ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Sundance Energy Australia Limited at December 31, 2012, and the consolidated results of its operations and its cash flows for the half year ended December 31, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ Ernst & Young

680 George Street

Sydney NSW 2000 Australia

GP Box 2646 Sydney NSW 2001

October 18, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

Sundance Energy Australia Limited

We have audited the accompanying consolidated statement of financial position of Sundance Energy Australia Limited and subsidiaries (the “Company”) as of June 30, 2012, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity, and cash flows for the year ended June 30, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sundance Energy Australia Limited and subsidiaries as of June 30, 2012, and the results of their operations and their cash flows for the year ended June 30, 2012, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

/s/ GRANT THORNTON LLP

707 17th Street

Denver, Colorado 80202

October 18, 2013

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2012

 

 

 

 

Consolidated Group

 

 

 

Note

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

Oil and gas sales revenue

 

 

 

$

17,724

 

$

29,787

 

Lease operating and production expenses

 

2

 

(4,082

)

(6,355

)

Depreciation and amortisation expense

 

 

 

(6,116

)

(11,111

)

Employee benefits expense

 

 

 

(2,801

)

(4,318

)

Administrative expense

 

3

 

(3,009

)

(2,545

)

Interest received

 

 

 

15

 

263

 

Finance costs

 

18

 

(593

)

(152

)

Impairment of non-current assets

 

 

 

 

(357

)

Gain on sale of non-current assets

 

4

 

122,327

 

3,004

 

(Loss)/gain on commodity hedging

 

 

 

(639

)

1,945

 

Realised currency (loss)

 

 

 

 

(4

)

Profit before income tax

 

 

 

122,826

 

10,157

 

Income tax expense

 

5

 

(46,616

)

(4,145

)

Profit attributable to owners of the Company

 

 

 

76,210

 

6,012

 

Other comprehensive income

 

 

 

 

 

 

 

Items that may be reclassified subsequently to profit or loss:

 

 

 

 

 

 

 

Exchange differences arising on translation of foreign operations (no income tax effect)

 

 

 

(154

)

(247

)

Total comprehensive income attributable to owners of the Company

 

 

 

$

76,056

 

$

5,765

 

Earnings per share

 

 

 

 

 

 

 

Basic earnings

 

8

 

$

0.27

 

$

0.02

 

Diluted earnings

 

8

 

$

0.27

 

$

0.02

 

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AS AT DECEMBER 31, 2012

 

 

 

 

Consolidated Group

 

 

 

Note

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

CURRENT ASSETS

 

 

 

 

 

 

 

Cash and cash equivalents

 

9

 

$

154,110

 

$

15,328

 

Trade and other receivables

 

10

 

15,672

 

12,352

 

Derivative financial instruments

 

11

 

617

 

1,331

 

Other current assets

 

12

 

5,025

 

1,680

 

TOTAL CURRENT ASSETS

 

 

 

175,424

 

30,691

 

NON-CURRENT ASSETS

 

 

 

 

 

 

 

Development and production assets

 

13

 

79,729

 

87,274

 

Exploration and evaluation expenditure

 

14

 

33,439

 

11,436

 

Plant and equipment

 

15

 

423

 

418

 

Derivative financial instruments

 

11

 

 

476

 

Other non-current assets

 

16

 

2,420

 

21

 

TOTAL NON-CURRENT ASSETS

 

 

 

116,011

 

99,625

 

TOTAL ASSETS

 

 

 

$

291,435

 

$

130,316

 

CURRENT LIABILITIES

 

 

 

 

 

 

 

Trade and other payables

 

17

 

38,770

 

22,056

 

Accrued expenses

 

17

 

13,072

 

8,337

 

TOTAL CURRENT LIABILITIES

 

 

 

51,842

 

30,393

 

NON-CURRENT LIABILITIES

 

 

 

 

 

 

 

Credit facility, net of $430 and $345 of deferred financing fees, respectively

 

18

 

29,570

 

14,655

 

Restoration provision

 

19

 

1,228

 

588

 

Deferred tax liabilities

 

20

 

56,979

 

10,476

 

TOTAL NON-CURRENT LIABILITIES

 

 

 

87,777

 

25,719

 

TOTAL LIABILITIES

 

 

 

$

139,619

 

$

56,112

 

NET ASSETS

 

 

 

$

151,816

 

$

74,204

 

EQUITY

 

 

 

 

 

 

 

Issued capital

 

21

 

$

58,694

 

$

57,978

 

Share option reserve

 

22

 

4,045

 

3,205

 

Foreign currency translation

 

22

 

(1,095

)

(941

)

Retained earnings

 

 

 

90,172

 

13,962

 

TOTAL EQUITY

 

 

 

$

151,816

 

$

74,204

 

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

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Table of Contents

SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2012

Consolidated Group

 

Issued
Capital
US$’000

 

Retained
Earnings
US$’000

 

Foreign
Currency
Translation
Reserve
US$’000

 

Share
Option
Reserve
US$’000

 

Total
US$’000

 

Balance at 30 June 2011

 

$

57,831

 

$

7,950

 

$

(694

)

$

2,380

 

$

67,467

 

Shares issued during the year

 

147

 

 

 

 

147

 

Stock compensation, value of services

 

 

 

 

825

 

825

 

Profit attributable to owners of the Company

 

 

6,012

 

 

 

6,012

 

Other comprehensive loss for the year

 

 

 

(247

)

 

(247

)

Balance at 30 June 2012

 

57,978

 

13,962

 

(941

)

3,205

 

74,204

 

Shares issued during the period

 

716

 

 

 

 

716

 

Stock compensation, value of services

 

 

 

 

840

 

840

 

Profit attributable to owners of the Company

 

 

76,210

 

 

 

76,210

 

Other comprehensive loss for the period

 

 

 

(154

)

 

(154

)

Balance at 31 December 2012

 

$

58,694

 

$

90,172

 

$

(1,095

)

$

4,045

 

$

151,816

 

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

CONSOLIDATED STATEMENT OF CASH FLOWS

FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 2012

 

 

 

 

Consolidated Group

 

 

 

Note

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

Receipts from sales

 

 

 

$

11,648

 

$

20,987

 

Payments to suppliers and employees

 

 

 

(2,886

)

(8,900

)

Interest received

 

 

 

16

 

263

 

Derivative proceeds (payments)

 

 

 

608

 

(297

)

Income taxes (paid)/refunded

 

 

 

 

(221

)

NET CASH PROVIDED BY OPERATING ACTIVITIES

 

26

 

9,386

 

11,832

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

Payments for development expenditure

 

 

 

(32,551

)

(34,833

)

Payments for exploration expenditure

 

 

 

(8,031

)

(5,685

)

Payments for acquisition of oil and gas properties

 

 

 

(11,470

)

 

Sale of non-current assets

 

 

 

173,822

 

4,679

 

Transaction costs related to sale of non-current assets

 

 

 

(862

)

 

Payments to establish escrow related to acquisition

 

 

 

(6,230

)

 

Payments for plant and equipment

 

 

 

(107

)

(310

)

NET CASH (USED IN) INVESTING ACTIVITIES

 

 

 

114,571

 

(36,149

)

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

Proceeds from the issue of shares

 

 

 

716

 

147

 

Payments for acquisition related costs

 

 

 

(192

)

 

Borrowing costs, including capitalised financing fees

 

 

 

(678

)

(408

)

Proceeds from borrowings

 

 

 

45,000

 

15,000

 

Payments of borrowings

 

 

 

(30,000

)

 

Realised currency (loss)

 

 

 

 

(5

)

NET CASH PROVIDED BY FINANCING ACTIVITIES

 

 

 

14,846

 

14,734

 

Net (decrease)/increase in cash held

 

 

 

138,803

 

(9,583

)

Cash at beginning of period

 

 

 

15,328

 

25,244

 

Effect of exchange rates on cash

 

 

 

(21

)

(333

)

CASH AT END OF PERIOD

 

9

 

$

154,110

 

$

15,328

 

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

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SUNDANCE ENERGY AUSTRALIA LIMITED

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR DECEMBER 31, 2012 AND

THE SIX-MONTH PERIOD THEN ENDED

NOTE 1—STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES

The financial report includes the consolidated financial statements and notes of Sundance Energy Australia Limited (SEAL) and its wholly owned subsidiary, Sundance Energy, Inc. (collectively, the ‘Company,’ ‘Consolidated Group’ or ‘Group’).

Basis of Preparation

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

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

Change in reporting period

Effective 1 July 2012, the Company changed its financial year end from 30 June to 31 December. This change resulted in the current reporting period being a six-month period. The six-month period ended 31 December 2012 is a shorter reporting period than that of the year ended 30 June 2012, which is the previous reporting period shown in these financial statements; therefore, the amounts presented in the financial statements are not entirely comparable.

Change in presentation currency

The Group’s cash flows and economic returns are principally denominated in US Dollars. From 1 July 2011, SEAL changed the currency in which it presents its consolidated and parent Company Financial Statements from Australian Dollars to US Dollars.

Principles of Consolidation

A controlled entity is any entity over which SEAL has the power to govern the financial and operating policies so as to obtain benefits from its activities. In assessing the power to govern, the existence and effect of holdings of actual and potential voting rights are considered. The consolidated financial statements incorporate the assets and liabilities of all entities controlled by SEAL as at 31 December 2012 and the results of all controlled entities for the financial period then ended.

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

a)Income Tax

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

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

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

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

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

Deferred tax assets relating to temporary differences and unused tax losses are recognised only to the extent that it is probable that future taxable profit will be available against which the benefits of the deferred tax asset can be utilised.

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

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

b)Development Assets and Plant and Equipment

Development assets and plant and equipment are carried at cost less where applicable, any accumulated depreciation, amortisation and impairment losses. The initial measurement of development and production assets subject to depreciation and amortisation include developed leasehold costs, intangible and tangible drilling and completion costs, allocated drilling overhead, capitalised finance costs and the estimated fair value of restoration provisions as at the date of each wells’ initial production. The initial measurement of development and production assets not subject to depreciation and amoritsation include similar costs of wells that have not had initial production as at the date of the statement of financial position. The initial measurement of plant and equipment assets include primarily office and computer equipment.

The carrying amount of development assets and plant and equipment are reviewed semi-annually to ensure that they are not in excess of the recoverable amount from these assets. The recoverable amount is assessed on the basis of the expected net cash flows that will be received from the assets employment and subsequent disposal. The expected net cash flows have been discounted to their present values in determining recoverable amounts.

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

Depreciation / Amortisation

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

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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 assets. For this approach, the calculation is based upon proved developed reserves.

The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each reporting period. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount.

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

c)Exploration and Evaluation Expenditure

Exploration and evaluation expenditure incurred is accumulated in respect of each identifiable area of interest. The initial measurement of these costs include the acquisition of rights to explore and mineral rights, various topographical, geological, geochemical and geophysical studies and other expenditures associated with finding specific mineral resources. These costs are only carried forward to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves.

Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made.

When production commences, the accumulated costs for the relevant area of interest are transferred to production assets and amortised over the life of the area according to the rate of depletion of the economically recoverable reserves.

A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest.

d)Leases

Leases of fixed assets where substantially all the risks and benefits incidental to the ownership of the asset, but not the legal ownership that are transferred to entities in the consolidated group, are classified as finance leases.

Finance leases are capitalised by recording an asset and a liability at the lower of the amounts equal to the fair value of the leased property or the present value of the minimum lease payments, including any guaranteed residual values. Lease payments are allocated between the reduction of the lease liability and the lease interest expense for the period.

Leased assets are depreciated on a straight-line basis over the shorter of their estimated useful lives or the lease term. Lease payments for operating leases, where substantially all the risks and benefits remain with the lessor, are charged as expenses in the periods in which they are incurred.

Lease incentives under operating leases are recognised as a liability and amortised on a straight-line basis over the life of the lease term.

e)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.

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Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified as at fair value through profit or loss. Transaction costs related to instruments classified at fair value through profit or loss are expensed to profit or loss immediately. Financial instruments are classified and measured as set out below.

Derivative Financial Instruments

The Group uses derivative financial instruments to hedge its exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity crude oil price swap, option, and costless collar contracts. Their use is subject to policies and procedures as approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. Derivative financial instruments are initially recognised at cost, which approximates fair value. Subsequent to initial recognition, derivate financial instruments are recognised at fair value. The derivatives are valued on a mark to market valuation and the gain or loss on re-measurement to fair value is recognised through the statement of comprehensive income.

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.

i)Financial assets at fair value through profit or loss

Financial assets are classified at fair value through profit or loss when they are held for trading for the purpose of short term profit taking, when they are derivatives not held for hedging purposes, or designated as such to avoid an accounting mismatch or to enable performance evaluation where a group of financial assets is managed by key management personnel on a fair value basis in accordance with a documented risk management or investment strategy. Realised and unrealised gains and losses arising from changes in fair value are included in profit or loss in the period in which they arise.

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.

iii)Held-to-maturity investments

Held-to-maturity investments are non-derivative financial assets that have fixed maturities and fixed or determinable payments, and it is the Group’s intention to hold these investments to maturity. They are subsequently measured at amortised cost using the effective interest rate method.

iv)Available-for-sale financial assets

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

v)Financial liabilities

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

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f)Impairment of Non-Financial Assets

At each reporting date, the group reviews the carrying values of its tangible and intangible assets to determine whether there is any indication that those assets have been impaired. If such an indication exists, the recoverable amount of the asset, being the higher of the asset’s fair value less costs to sell and value in use, is compared to the asset’s carrying value. Any excess of the asset’s carrying value over its recoverable amount is expensed to the statement of comprehensive income.

Impairment testing is performed annually for intangible assets with indefinite lives.

Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

g)Foreign Currency Transactions and Balances

Functional and presentation currency

The functional currency of each of the Group’s entities is measured using the currency of the primary economic environment in which that entity operates. The consolidated financial statements are presented in US dollars.

Transactions and Balances

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

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

Group Companies

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

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

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

·retained profits are translated at the exchange rates prevailing at the date of the transaction.

Exchange differences arising on translation of foreign operations are transferred directly to the Group’s foreign currency translation reserve in the statement of comprehensive income. These differences are recognised in the statement of comprehensive income in the period in which the operation is disposed.

h)Employee Benefits

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

Equity—Settled Compensation

The Group has an employee share option plan. The fair value of the options awarded are amortised as an expense in the statement of comprehensive income over their performance period. The total amount to be expensed over the vesting period is determined by reference to the fair value of the options at the grant date.

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Restricted Share Unit Plan

The group has a restricted share unit plan (RSU) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Group’s long-term goals. The RSUs are based on targets established and approved by the Board. Actual RSUs, awarded annually, are modified according to actual results and vest in four equal tranches beginning on the grant date.

i)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.

j)Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less, unrestricted escrow accounts that management expects to be used to settle current liabilities, capital or operating expenditures, or complete acquisitions and bank overdrafts.

k)Revenue

Revenue from the sale of goods is recognised upon the delivery of goods to customer. Interest revenue is recognised on a proportional basis taking into account the interest rates applicable to the financial assets.

Revenue from the rendering of a service is recognised upon the delivery of the service to the customers. All revenue is stated net of the amount of goods and services tax (GST).

l)Borrowing Costs

Borrowing costs directly attributable to the acquisition, construction or production of assets that necessarily take a substantial period of time to prepare for their intended use or sale are added to the cost of those assets until such time as the assets are substantially ready for their intended use or sale. Borrowings are recognised initially at fair value, net of transaction costs incurred. Subsequent to initial recognition, borrowings are stated as amortised cost with any difference between cost and redemption being recognised in the statement of profit or loss and other comprehensive income over the period of the borrowings on an effective interest basis. No borrowing costs were capitalised in the six month period and year ended 31 December 2012 and 30 June 2012.

All other borrowing costs are recognised in income in the period in which they are incurred.

m)Goods and Services Tax (GST)

Revenues, expenses and assets are recognised net of the amount of GST, except where the amount of GST incurred is not recoverable from the Australian Tax Office. In these circumstances the GST is recognised as part of the cost of acquisition of the asset or as part of an item of the expense. Receivables and payables in the statement of financial position are shown inclusive of GST.

Cash flows are presented in the statement of cash flows on a gross basis, except for the GST component of investing and financing activities, which are disclosed as operating cash flows.

n)Critical Accounting Estimates and Judgments

The Directors evaluate estimates and judgments incorporated into the financial report based on historical knowledge and best available current information. Estimates assume a reasonable expectation of future events and are based on current trends and economic data obtained both externally and within the Group.

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Key estimates

Estimates of reserve quantities

The estimated quantities of hydrocarbon reserves reported by the consolidated entity are integral to the calculation of amortisation (depletion), depreciation expense and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessment of the technical feasibility and commercial viability of producing the reserves. For purposes of the calculation of amortization (depletion), and depreciation and the assessment of possible impairment of assets, management prepares reserve estimates which conform to the definitions contained in Rule 4-10(a) of Regulation S-X. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period, and as additional geological data is generated during the course of operations. These reserve estimates may differ from estimates prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding oil and natural gas reserve reporting including those presented in Note 33.

Exploration and Evaluation

The Company’s policy for exploration and evaluation is discussed in Note 1 (c). The application of this policy requires the Company to make certain estimates and assumptions as to future events and circumstances. Any such estimates and assumptions may change as new information becomes available. If, after having capitalised exploration and evaluation expenditure, the directors conclude that the capitalised expenditure is unlikely to be recovered by future sale or exploitation, then the relevant capitalised amount will be written off through the statement of comprehensive income.

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 life of the assets and the provision is revised at each balance date through the statement of profit or loss as the discounting of the liability unwinds.

o)Change in Accounting Estimate

The same accounting policies and methods of computation have been followed in this financial report as were applied in the 30 June 2012 financial statements.

p)Reclassifications

Certain reclassifications have been made to the prior year financial statements and associated notes to the financial statements to conform to the current year presentation.

q)Rounding of amounts

The company is of a kind referred to in Class Order 98/100 issued by the Australian Securities and Investment Commission, relating to rounding of amounts in the financial statements. Amounts have been rounded to the nearest thousand.

r)Parent Entity Financial Information

The financial information for the parent entity, SEAL, discussed in Note 32, has been prepared on the same basis, using the same accounting policies as the consolidated financial statements.

s)Earnings Per Share

The group presents basic and diluted earnings per share for its ordinary shares. Basic earnings per share is calculated by dividing the profit or loss attributable to ordinary shareholders of the Company by the weighted average number of ordinary shares outstanding during the year. Diluted earnings per share is determined by adjusting the profit or loss attributable to

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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.

t)Adoption of New and Revised Accounting Standards

During the current reporting period the Group adopted all of the new and revised International Accounting Standards and Australia Accounting Standards and Interpretations applicable to its operations which became mandatory.

AASB 2011-9 Amendments to Australian Accounting Standards Presentation of Items of Other Comprehensive Income (IAS 1 Amendments)

The IAS 1 Amendments require an entity to group items presented in other comprehensive income into those that, in accordance with other IFRSs: (a) will not be reclassified subsequently to profit or loss and (b) will be reclassified subsequently to profit or loss when specific conditions are met. It is applicable for reporting periods beginning on or after 1 July 2012. The Group’s management adopted this change in the current presentation of items in other comprehensive income. This adoption did not affect the measurement or recognition of such items.

Recently issued accounting standards to be applied in future reporting periods:

The following Standards and Interpretations are effective for annual periods beginning on or after 1 January 2013 and have not been applied in preparing these consolidated financial statements. The Group’s assessment of the impact of these new standards, amendments to standards, and interpretations is set out below.

IFRS 9—Financial Instruments

IFRS 9 introduces new requirements for the classification, measurement, and derecognition of financial assets and financial liabilities. IFRS 9 is effective for annual periods beginning on or after 1 January 2015, and is available for early adoption.

IFRS 10—Consolidated Financial Statements

IFRS 10 replaces the guidance on control and consolidation in IAS 27— Consolidated and Separate Financial Statements and Interpretation 12—Consolidation—Special Purpose Entities. IFRS 10 includes a new definition of control that focuses on the need to have both power and rights or exposure to variable returns.

IFRS 13—Fair Value Measurement

IFRS 13 establishes a single source of guidance for fair value measurements and disclosures. The standard defines fair value, establishes a framework for measuring fair value, and requires more extensive disclosures than current standards. IFRS 13 is effective for annual periods beginning on or after 1 January 2013.

AASB 2011-4 Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure

This standard removes the requirements to include individual key management personnel disclosures in the notes to and forming part of the Financial Report. AASB 2011-4 is effective for annual periods beginning on or after 1 July 2013.

AASB 2012-5 Amendments to Australian Accounting Standards arising from Annual Improvements 2009-2011 Cycle

AASB 2012-5 makes amendments to several Australian Accounting Standards. These amendments primarily relate to clarification of narrative requirements for comparative information and segment disclosures for interim financial reports. AASB 2012-5 is effective for annual periods beginning on or after 1 January 2013.

The potential effect of these Standards is yet to be fully determined. However, it is not expected that the new or amended standards will significantly affect the Group’s financial position or performance.

The financial report was authorised for issue on 28 March 2013, by the Board of Directors.

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NOTE 2—LEASE OPERATING AND PRODUCTION EXPENSES

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

Lease operating expense

 

$

(1,908

)

$

(2,921

)

Workover expense

 

(287

)

(180

)

Production taxes

 

(1,887

)

(3,254

)

 

 

$

(4,082

)

$

(6,355

)

NOTE 3—ADMINISTRATIVE EXPENSES

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

Accounting and company secretarial

 

$

(150

)

$

(271

)

Acquisition and merger related fees

 

(713

)

 

Audit fees

 

(145

)

(51

)

Professional fees

 

(929

)

(789

)

Travel

 

(280

)

(390

)

Rent

 

(181

)

(287

)

Share registry and listing fees

 

(75

)

(122

)

Other expenses

 

(536

)

(635

)

 

 

$

(3,009

)

$

(2,545

)

NOTE 4—GAIN ON SALE OF NON-CURRENT ASSETS

On 27 September 2012, the Company sold all of its interest in properties located in the South Antelope field for $172.4 million. Prior to the disposition, the South Antelope development and production properties were part of the Williston Basin depletion base. To determine the carrying costs of the sold properties, the Company used the relative fair value of South Antelope proved developed reserves as compared to the Company’s total proved developed reserves in the Williston Basin. As a result, it was determined that approximately $49.4 million of the Company’s carrying costs related to its South Antelope development and production properties at the time of the disposal. In addition to the South Antelope development and production properties, the Purchaser acquired approximately $3.9 million of assets and assumed approximately $3.8 million of liabilities, which were removed from the Company’s statement of financial position at the time of the sale. The Company incurred approximately $0.9 million of legal and other transaction related costs. This sale resulted in a gain of $122.5 million. The Company also sold all of its properties in the Pawnee prospect for $0.9 million of proceeds, which resulted in a loss of $0.2 million. Both the South Antelope gain and the Pawnee loss on sale are included in the gain on sale of non-current assets in the statement of profit or loss and other comprehensive income for the six month period ended 31 December 2012.

The Company elected to apply Section 1031 “like-kind exchange” treatment of the South Antelope sales proceeds under the US tax rules which allow deferral of the gain if the proceeds are used to acquire “like-kind property” within six months of the closing date of the transaction. In addition, the US tax rules allow the deduction of all intangible drilling costs (“IDCs”) in the period incurred. As at 31 December 2012, the Company expected to defer the majority of the taxable gain on the sale by acquiring qualified replacement properties or utilising IDCs from its development program. In March 2013, the Company completed a transaction in which the majority of the funds remaining in its Section 1031 escrow account were used to acquire oil and gas properties in connection with the Texon Scheme of Arrangement transaction discussed in more detail in Note 29. Management believes the properties acquired qualify as “like-kind property” under Section 1031 which will result in deferral of the majority of the gain associated with the South Antelope sale.

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NOTE 5—INCOME TAX EXPENSE

 

 

 

Consolidated Group

 

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

a)

The components of income tax expense comprise:

 

 

 

 

 

 

Current tax benefit/(expense)

 

$

(11

)

$

242

 

 

Deferred tax expense

 

(46,605

)

(4,387

)

 

 

 

$

(46,616

)

$

(4,145

)

b)

The prima facie tax on income from ordinary activities before income tax is reconciled to the income tax as follows:

 

 

 

 

 

 

Profit before income tax

 

$

122,826

 

$

10,157

 

 

Prima facie tax expense on income from ordinary activities before income tax at 30%

 

$

36,848

 

$

3,047

 

 

Add:

 

 

 

 

 

 

Tax effect of:

 

 

 

 

 

 

—difference of tax rate in US controlled entities

 

9,417

 

862

 

 

—employee options

 

44

 

276

 

 

—other allowable items

 

93

 

4

 

 

—previously unrecognised tax gains used to (reduce)/increase current tax expense

 

 

(139

)

 

—previously unrecognised tax losses used to (reduce)/increase current tax expense

 

 

 

 

—Acquisition related costs

 

214

 

 

 

—Deferred tax assets associated with capital raising costs recognised direct to equity but not meeting the recognition criteria

 

 

95

 

 

Income tax attributable to entity

 

$

46,616

 

$

4,145

 

c)

Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30%

 

$

375

 

$

375

 

At December 31, 2012 the Company had U.S. federal and state net operating loss carryforwards for tax purposes of approximately $58.8 million and $54.5 million, respectively which will expire in 2030 through 2032. We believe that it is more likely than not that the carryforward will be utilized before it expires.

NOTE 6—KEY MANAGEMENT PERSONNEL COMPENSATION

a)Names and positions held of Consolidated Group key management personnel in office at any time during the financial period are:

Mr M Hannell

Chairman Non-executive

Mr E McCrady

Chief Executive Officer & Managing Director

Mr D Hannes

Director—Non-executive

Mr N Martin

Director—Non-executive

Mr W Holcombe

Director—Non-executive (appointed as Director on 19 December 2012)

Mr A Hunter III

Director—Executive (resigned as a Director on 13 July 2012)

Ms C Anderson

Chief Financial Officer

Mr C Gooden

Company Secretary

Other than employees of the Company listed above, there are no additional key management personnel.

b)Key Management Personnel Compensation

Refer to the Remuneration Report contained in the Report of Directors’ for details of the remuneration paid or payable to each member of the Group’s key management personnel (KMP) for the six month period ended 31 December 2012 and year ended 30 June 2012.

The total of remuneration paid to KMP of the Group during the year is as follows:

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Consolidated Group

 

 

 

6 months to
31 December 2012
US$ ‘000

 

12 months to
30 June 2012
US$ ‘000

 

Short term wages and benefits

 

$

695

 

$

1,389

 

Equity settled-options based payments

 

262

 

496

 

Post-employment benefit

 

17

 

31

 

 

 

$

974

 

$

1,916

 

c)Options Granted as Compensation

Options granted as compensation were zero ($nil fair value) and 1,000,000 ($0.2 million fair value) during the six month period and year ended 31 December and 30 June 2012, respectively, to KMP from the Sundance Energy Employee Stock Option Plan. Options generally vest in five equal tranches of 20% on the grant date and each of the four subsequent anniversaries of the grant date.

d)Restricted Share Units Granted as Compensation

Restricted share units (RSUs) awarded as compensation were 669,642 ($0.5 million fair value) and 776,000 ($0.3 million fair value) during the six month period and year ended 31 December and 30 June 2012, respectively, to KMP from the Sundance Energy Long Term Incentive Plan. RSUs generally vest in four equal tranches of 25% on the grant date and each of the three subsequent anniversaries of the grant date.

NOTE 7—AUDITORS’ REMUNERATION

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

Remuneration of the auditor for:

 

 

 

 

 

Auditing or review of the financial report

 

$

131

 

$

90

 

Non-audit services related to Texon acquisition

 

148

 

 

Taxation services provided by the practice of auditor

 

14

 

13

 

Total remuneration of the auditor

 

$

293

 

$

103

 

NOTE 8—EARNINGS PER SHARE (EPS)

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

Profit for periods used to calculate basic and diluted EPS

 

$

76,210

 

$

6,012

 

 

 

Number of
shares

 

Number of
shares

 

—Weighted average number of ordinary shares outstanding during the year used in calculation of basic EPS

 

277,244,883

 

277,049,463

 

—Incremental shares related to options and restricted share units

 

2,896,496

 

1,900,976

 

—Weighted average number of ordinary shares outstanding during the year used in calculation of diluted EPS

 

280,141,379

 

278,950,439

 

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Table of Contents

NOTE 9—CASH AND CASH EQUIVALENTS

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Cash at bank and on hand

 

$

12,747

 

$

14,353

 

Cash equivalents in escrow accounts

 

141,363

 

 

Short term deposits

 

 

975

 

 

 

$

154,110

 

$

15,328

 

Included in cash equivalents, the Company has approximately $141.4 million in a Section 1031 escrow account which is not limited in use, except that the timing of tax payments will be accelerated if not used on qualified “like- kind property.” As such, the balance has been included in the Company’s cash and cash equivalents in the statement of financial position and statement of cash flows as at 31 December 2012 and for the six month period then ended.

For the year ended 30 June 2012, the effective interest rate on short term bank deposits was 1.5% for the Group. 94% of deposits were at 24 hours call and the balance of deposits has an average maturity of 49 days. The Groups’ exposure to interest rate risk is summarised at Note 31.

NOTE 10—TRADE AND OTHER RECEIVABLES

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Oil and gas sales

 

$

11,376

 

$

8,244

 

Trade receivables

 

4,185

 

3,940

 

Other

 

111

 

168

 

 

 

$

15,672

 

$

12,352

 

At 31 December and 30 June 2012, the Group had receivable balances of $8.6 million and $6.7 million, respectively, which were outside normal trading terms (the receivable was past due but not impaired). Due to the short term nature of these receivables, their carrying amounts are assumed to approximate their fair value.

NOTE 11—DERIVATIVE FINANCIAL INSTRUMENTS

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

FINANCIAL ASSETS COMPRISE:

 

 

 

 

 

Current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

$

617

 

$

1,331

 

Non-current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

 

476

 

Total financial assets

 

$

617

 

$

1,807

 

FINANCIAL LIABILITIES COMPRISE:

 

 

 

 

 

Current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

$

 

$

 

Non-current

 

 

 

 

 

Derivative financial instruments—commodity contracts

 

 

 

Total financial liabilities

 

$

 

$

 

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

Level 1:

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

Level 2:

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

Level 3:

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

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

Consolidated 31 December 2012

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

$

 

$

617

 

$

 

$

617

 

Liabilities

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

 

 

 

 

Net fair value

 

$

 

$

617

 

$

 

$

617

 

Consolidated 30 June 2012

 

Level 1

 

Level 2

 

Level 3

 

Total

 

Assets

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

$

 

$

1,807

 

$

 

$

1,807

 

Liabilities

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

 

 

 

 

Net fair value

 

$

 

$

1,807

 

$

 

$

1,807

 

Measurement of Fair Value

The methods and valuation techniques used for the purpose of measuring fair value are unchanged compared to the previous reporting period.

a)Derivatives

Where derivatives are traded either on exchanges or liquid over-the-counter markets the Group uses the closing price at the reporting date. Normally, the derivatives entered into by the Group are not traded in active markets. The fair values of these contracts are estimated using a valuation technique that maximises the use of observable market inputs, eg market exchange and interest rates (Level 2). Most derivatives entered into by the Group are included in Level 2 and consist of commodity contracts.

NOTE 12—OTHER CURRENT ASSETS

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Cash advances to other operators

 

$

625

 

$

1,514

 

Escrow accounts

 

3,830

 

 

Oil inventory on hand, at cost

 

69

 

46

 

Prepayments

 

501

 

120

 

 

 

$

5,025

 

$

1,680

 

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On 31 December 2012, the Company completed a transaction to acquire certain oil and gas properties in the Wattenberg field of the Denver-Julesburg (DJ) Basin (the “Wattenberg Acquisition”). In connection with the transaction the Company transferred $3.0 million, $2.7 million and $0.5 million to escrow accounts related to a drilling commitment, title defect and environmental remediation, respectively ($6.2 million collectively). Because the use of the Wattenberg Acquisition related escrow accounts are restricted or generally will not be used to settle short-term Company operating costs, they have been excluded from the Company’s cash and cash equivalents balance in the statement of financial position and statement of cash flows as at 31 December 2012 and for the six month period then ended. Of this $6.2 million escrow account balance, $3.8 million is classified as other current asset in the statement of financial position as at 31 December 2012.

NOTE 13—DEVELOPMENT AND PRODUCTION ASSETS

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Costs carried forward in respect of areas of interest in:

 

 

 

 

 

Development and production phase at cost

 

$

96,663

 

$

113,830

 

Accumulated amortisation

 

(14,619

)

(24,241

)

Provision for impairment

 

(2,315

)

(2,315

)

Total Development and Production Expenditure

 

$

79,729

 

$

87,274

 

 

a)

Movements in carrying amounts:

 

 

 

 

 

 

 

Development expenditure

 

 

 

 

 

 

 

Balance at the beginning of the period

 

$

87,274

 

$

45,873

 

 

 

Amount transferred from exploration phase

 

527

 

2,277

 

 

 

Amounts capitalised during the period

 

47,949

 

50,520

 

 

 

Amortisation expense

 

(6,013

)

(10,971

)

 

 

Development assets sold during the period

 

(50,008

)

(425

)

 

 

Balance at end of period

 

$

79,729

 

$

87,274

 

NOTE 14—EXPLORATION AND EVALUATION EXPENDITURE

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Costs carried forward in respect of areas of interest in:

 

 

 

 

 

Exploration and evaluation phase at cost

 

$

35,053

 

$

13,050

 

Provision for impairment

 

(1,614

)

(1,614

)

Total Exploration and Evaluation Expenditure

 

$

33,439

 

$

11,436

 

 

a)

Movements in carrying amounts:

 

 

 

 

 

 

 

Exploration and evaluation

 

 

 

 

 

 

 

Balance at the beginning of the period

 

$

11,436

 

$

6,626

 

 

 

Amounts capitalised during the period

 

23,348

 

8,670

 

 

 

Impairment of exploration and expenditure

 

 

(357

)

 

 

Amount transferred to development phase

 

(527

)

(2,277

)

 

 

Exploration tenements sold during the period

 

(818

)

(1,226

)

 

 

Balance at end of period

 

$

33,439

 

$

11,436

 

Included in the amounts capitalised during the six month period ended 31 December 2012, was $12.7 million related the Wattenberg Acquisition, which occurred on 31 December 2012. The remaining $1.0 million of the total consideration paid or liabilities assumed was included in the amount capitalised of the Company’s development and production assets.

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

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Table of Contents

NOTE 15—PLANT AND EQUIPMENT

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Plant and equipment at cost

 

$

737

 

$

630

 

Accumulated depreciation

 

(314

)

(212

)

Total Plant and Equipment

 

$

423

 

$

418

 

 

a)

Movements in carrying amounts:

 

 

 

 

 

 

 

Balance at the beginning of the period

 

$

418

 

$

210

 

 

 

Additions

 

107

 

310

 

 

 

Depreciation

 

(102

)

(102

)

 

 

Balance at end of period

 

$

423

 

$

418

 

NOTE 16—OTHER NON-CURRENT ASSETS

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Escrow accounts

 

$

2,400

 

$

 

Casing and tubulars at net realisable value

 

20

 

21

 

 

 

$

2,420

 

$

21

 

The $2.4 million of escrow accounts is the long-term portion related to the escrow accounts discussed in Note 12.

NOTE 17—TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Oil and gas related

 

$

49,407

 

$

29,059

 

Administrative expenses

 

2,435

 

1,334

 

Total trade and other payable and accrued expenses

 

$

51,842

 

$

30,393

 

NOTE 18—CREDIT FACILITY

 

 

Consolidated Group

 

 

 

31 December 2012
US$000

 

30 June 2012
US$000

 

Wells Fargo Credit Facility

 

$

30,000

 

$

 

Bank of Oklahoma Credit Facility

 

 

15,000

 

Total credit facilities

 

30,000

 

15,000

 

Deferred financing fees

 

(430

)

(345

)

 

 

$

29,570

 

$

14,655

 

On 31 December 2012, Sundance Energy, Inc. (“SEI”), a wholly owned subsidiary of the Company, entered into a credit agreement with Wells Fargo (the “Credit Facility”), pursuant to which up to $300 million is available on a revolving basis. The borrowing base under the Credit Facility is determined by reference to the value of the Company’s proved reserves. The agreement specifies a semi-annual borrowing base redetermination and the Company can request two additional redeterminations each year. The borrowing base was originally set at $30 million. Interest on borrowed funds accrues, at the Company’s option, of i) LIBOR plus a margin that ranges from 175 to 275 basis points or ii) the Base Rate, defined as a rate equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Prime Rate, or (c) LIBOR plus a margin that ranges from 75 to 175 basis points. The applicable margin varies depending on the amount drawn. The Company also pays a commitment that ranges from 37.5 to 50 basis points on the undrawn balance of the borrowing base. The agreement has a five year term and contains both negative and affirmative covenants, including minimum current ratio and maximum leverage ratio requirements. As at 31 December 2012 the Company requested and received a waiver from Wells Fargo regarding compliance with the maximum leverage ratio as at 31 December 2012 as required under the terms of the Credit Facility. Certain development and production assets are pledged as collateral and the facility is guaranteed by the Parent Company. The Company immediately drew on the Credit Facility’s full $30 million borrowing base and used $15 million of the proceeds to repay and retire its outstanding loan with the Bank of Oklahoma. As a part of its Bank of Oklahoma debt extinguishment, the

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Company expensed approximately $0.3 million of unamortised deferred financing costs, which is included in financing costs in the statement of profit or loss and other comprehensive income for the six month period ended 31 December 2012. The Company capitalised $0.4 million of financing costs related to the Wells Fargo credit facility, which will be amortised over the term of the loan. Under the terms of the credit facility, SEI is limited to payment of $2 million in dividends annually to SEAL without prior creditor approval.

NOTE 19—RESTORATION PROVISION

The restoration provision represents the present value of restoration costs relating to the Company’s oil and gas interests, which are expected to be incurred up to 2042. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual restoration costs will reflect market conditions at the relevant time. Furthermore, the timing of restoration is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend on future oil and gas prices, which are inherently uncertain.

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June
US$’000

 

a) Decommissioning costs:

 

 

 

 

 

Balance at the beginning of the period

 

$

588

 

$

349

 

New provisions and changes in estimates

 

310

 

230

 

Dispositions

 

(192

)

(2

)

New provisions assumed from asset acquisition

 

506

 

 

Unwinding of discount

 

16

 

11

 

Balance at end of period

 

$

1,228

 

$

588

 

NOTE 20—DEFERRED TAX LIABILITIES

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

The balance comprises temporary differences attributable to:

 

 

 

 

 

Plant and equipment

 

$

26

 

$

37

 

Development and production expenditure

 

79,600

 

24,276

 

Net operating loss carried forward

 

(22,647

)

(13,837

)

 

 

$

56,979

 

$

10,476

 

NOTE 21—ISSUED CAPITAL

Total ordinary shares issued at each year end are fully paid.

Number of Shares

a)

Ordinary Shares

Total shares issued at 30 June 2011

276,709,585

Shares issued during the year

388,889

Total shares issued at 30 June 2012

277,098,474

Shares issued during the year

1,666,667

Total shares issued at 31 December 2012

278,765,141

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

 

 

 

Consolidated Group

 

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

b)

Issued Capital

 

 

 

 

 

 

Opening balance

 

$

57,978

 

$

57,831

 

 

Shares issued during the period

 

716

 

147

 

 

Closing balance at end of period

 

$

58,694

 

$

57,978

 

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Table of Contents

c)Options on Issue

Details of the share options outstanding as at the end of the period:

Grant Date

 

Expiry Date

 

Exercise Price

 

31 December 2012

 

30 June 2012

 

10 Sep 2010

 

31 May 13

 

A$0.20

 

1,000,000

 

1,000,000

 

10 Sep 2010

 

31 May 13

 

A$0.30

 

500,000

 

500,000

 

02 Dec 2010

 

01 Dec 15

 

A$0.37

 

1,166,666

 

2,333,333

 

02 Mar 2011

 

30 Jun 14

 

A$0.95

 

30,000

 

30,000

 

03 Jun 2011

 

31 May 13

 

A$0.35

 

100,000

 

100,000

 

03 Jun 2011

 

15 Jan 16

 

A$0.65

 

500,000

 

500,000

 

03 Jun 2011

 

28 Jan 16

 

A$0.50

 

250,000

 

750,000

 

06 Jun 2011

 

01 Sep 15

 

A$0.95

 

30,000

 

30,000

 

06 Sep 2011

 

31 Dec 18

 

A$0.95

 

1,200,000

 

1,200,000

 

05 Dec 2011

 

05 Mar 19

 

A$0.95

 

1,000,000

 

1,000,000

 

 

 

 

 

 

 

5,776,666

 

7,443,333

 

d)Restricted Share Units (RSUs) on Issue

Details of the restricted share units outstanding as at the end of the period:

Consolidated Group

Grant Date

31 December 2012

30 June 2012

05 Dec 2011

608,750

15 Oct 2012

1,482,143

2,090,893

e)Capital Management

Management controls the capital of the Group in order to maintain a good debt 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 18, 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 year. The strategy is to ensure that the Group’s gearing ratio remains minimal. At 31 December and 30 June 2012, the Company had $30 million and $15 million of outstanding debt, respectively.

NOTE 22—RESERVES

a)Share Option Reserve

The share option reserve records items recognised as expenses on valuation of employee and supplier 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.

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Table of Contents

NOTE 23—CAPITAL AND OTHER EXPENDITURE COMMITMENTS

Capital commitments relating to joint ventures and tenements

As at 31 December 2012, all of the Company’s exploration and evaluation and development and production assets are located in the United States of America.

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

On 31 December 2012, the Company entered into an agreement to acquire certain oil and gas properties located in the Wattenberg Field and to drill 45 net wells by 31 December 2015 on the acquired properties (the “Drilling Commitment”). As each qualifying well is drilled, approximately $67 thousand is paid from the escrow account to the Company. However, for each required net commitment well not completed by the Company during that prorated commitment year, the Company is to pay the seller of the properties approximately $67 thousand from the escrow account. Certain clawback provisions allow the Company to recoup amounts paid to the sellers if the total 45 wells are drilled by 31 December 2015.

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Operating lease commitments

 

 

 

 

 

Commitments for minimum lease payments in relation to non-cancellable operating leases not provided for in the financial statements.

 

 

 

 

 

Lease expenditure commitments

 

 

 

 

 

—due within one year

 

$

162

 

$

202

 

—due within 1 - 5 years

 

81

 

162

 

 

 

$

243

 

$

364

 

Drilling commitments

 

 

 

 

 

Commitments for the payment related to drilling not provided for in the financial statements.

 

 

 

 

 

Expenditure commitments

 

 

 

 

 

due within one year

 

$

1,000

 

$

 

due within 1 - 5 years

 

2,000

 

 

 

 

$

3,000

 

$

 

Employment and consultant commitments

 

 

 

 

 

Commitments for the payment of salaries and other remuneration under long-term employment and consultant contracts not provided for in the financial statements.

 

 

 

 

 

Expenditure commitments

 

 

 

 

 

—due within one year

 

$

275

 

$

180

 

—due within 1 - 5 years

 

104

 

270

 

 

 

$

379

 

$

450

 

Details relating to the employment contracts are set out in the remuneration report.

NOTE 24—CONTINGENT ASSETS AND LIABILITIES

At the date of signing this report, the Group is not aware of any contingent assets or liabilities that should be disclosed in accordance with IAS 37.

NOTE 25—OPERATING SEGMENTS

Management has determined, based upon the reports reviewed by the CEO and used to make strategic decisions, that the Group has one reportable segment being oil and gas exploration and production in the United States of America.

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Table of Contents

The CEO reviews internal management reports on a monthly basis that are consistent with the information provided in the statement of profit or loss and other comprehensive income, statement of financial position and statement of cash flows. As a result no reconciliation is required, because the information as presented is used by the CEO to make strategic decisions.

NOTE 26—CASH FLOW INFORMATION

 

 

 

Consolidated Group

 

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

a)

Reconciliation of cash flows from operations with income from ordinary activities after income tax

 

 

 

 

 

 

Profit from ordinary activities after income tax

 

$

76,210

 

$

6,012

 

 

Non cash flow in operating income

 

 

 

 

 

 

Depreciation and exploration expenditure written off

 

6,116

 

11,468

 

 

Share options expensed

 

733

 

930

 

 

Unrealised losses (gains) on derivatives

 

1,190

 

(2,242

)

 

Net gain on sale of properties

 

(122,327

)

(3,004

)

 

Write-off of Bank of Oklahoma deferred financing fees

 

349

 

 

 

Changes in assets and liabilities:

 

 

 

 

 

 

—Increase in current and deferred tax

 

46,616

 

3,732

 

 

—(Increase) / decrease in other assets, excluding investing

 

(381

)

1,517

 

 

—Increase in trade and other receivables

 

(3,320

)

(8,814

)

 

—Increase in trade and other payables

 

4,200

 

2,233

 

 

Net cash provided by operating activities

 

$

9,386

 

$

11,832

 

b)Non Cash Financing and Investing Activities

During the six month period and year ended 31 December and 30 June 2012, 1,666,667 and 388,889 shares were issued at A$0.41 and A$0.37 per weighted average share, respectively.

c)Business Combinations

There were no non-cash business combinations in the six month period and year ended 31 December and 30 June 2012.

NOTE 27—SHARE BASED PAYMENTS

During the six month period ended 31 December 2012, a total of nil (year ended 30 June 2012: 2,260,000) options were granted to employees pursuant to employment agreements and a total of 1,666,667 (year ended 30 June 2012: 388,889) previously issued options were exercised. There were 700,000 awarded options that the Company expected to issue in early 2013 for which Company employees rendered services during the six month period ended 31 December 2012. Using the best estimate of fair value on the employees’ hire date, the Company began expensing these awards during the six month period ended 31 December 2012. The 700,000 options expected to be issued in early 2013 are excluded from the outstanding options summary below:

 

 

Consolidated Group

 

 

 

31 December 2012

 

30 June 2012

 

 

 

Number
of Options

 

Weighted
Average
Exercise
Price A$

 

Number
of Options

 

Weighted
Average
Exercise
Price A$

 

Outstanding at start of year

 

7,443,333

 

0.55

 

5,632,222

 

0.38

 

Formally issued

 

 

 

2,260,000

 

0.95

 

Forfeited

 

 

 

(60,000

)

0.50 - 0.70

 

Exercised

 

(1,666,667

)

0.41

 

(388,889

)

0.37

 

Expired

 

 

 

 

 

Outstanding at end of year

 

5,776,666

 

0.59

 

7,443,333

 

0.55

 

Exercisable at end of year

 

3,729,999

 

0.44

 

3,551,889

 

0.45

 

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The following tables summarise the options issued and awarded and their related grant date, fair value and vesting conditions for the six month period ended 31 December 2012 and the year ended 30 June 2012:

Options awarded, but not yet issued during the six month period ended 31 December 2012:

Award Date (not issued)

 

Number
of Options

 

Estimated
Fair Value

 

Vesting Conditions

 

1 November 2012

 

350,000

 

$

145

 

20% issuance date, 20% first four anniversaries

 

3 December 2012

 

350,000

 

157

 

20% issuance date, 20% first four anniversaries

 

 

 

700,000

 

$

302

 

 

 

Options issued during the year ended 30 June 2012:

Grant Date

 

Number
of Options

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

1 July 2011

 

30,000

 

$

14

 

33% issuance date, 33% first two anniversaries

 

1 September 2011

 

30,000

 

12

 

33% issuance date, 33% first two anniversaries

 

7 October 2011

 

1,200,000

 

408

 

17% issuance date, 17% first five anniversaries

 

5 March 2012

 

1,000,000

 

212

 

20% issuance date, 20% first four anniversaries

 

 

 

2,260,000

 

$

646

 

 

 

Share based payments expense related to options is determined pursuant to IFRS 2: Share Based Payments, and is recognised pursuant to the attached vesting conditions. The fair value of the options awarded ranged from A$0.42 to A$0.45 for the period ended 31 December 2012 and A$0.21 to A$0.46 for the year ended 30 June 2012, which was calculated using a Black-Sholes options pricing model. Expected volatilities are based upon the historical volatility of the ordinary shares. Historical data is also used to estimate the probability of option exercise and potential forfeitures. No options were issued in the six month period ended 31 December 2012; however, 700,000 awarded options were expected to be issued in early 2013 and were expensed during the period according to the relevant service period.

The following table summarises the key assumptions used to calculate the estimated fair value awarded or granted during the periods:

 

 

Expected to be
issued in
early 2013(1)

 

Issued during
year ended
30 June 2012

 

Share price:

 

A$0.78 - A$0.82

 

A$0.38 - 0.96

 

Exercise price:

 

A$1.15

 

A$0.95

 

Expected volatility:

 

65%

 

75%

 

Option term:

 

5.75 years

 

3.3 to 7.3 years

 

Risk free interest rate:

 

2.75%

 

5.5% to 6.25%

 


(1)Options subject to formal issuance, but were awarded and expensed beginning on the employees’ hire date during the six month period ended 31 December 2012.

Restricted Share Units

During the six month period and year ended 31 December and 30 June 2012, the Board of Directors awarded 1,482,143 and 910,000 restricted share units (RSUs) to certain employees. These awards were made in accordance with the long term equity component of the Company’s incentive compensation plan, the details of which are described in more detail in the remuneration section of the Directors’ Report. Share based payment expense for RSUs awarded was calculated pursuant to IFRS 2: Share Based Payments. The fair values of RSUs were estimated at the date they were approved by the Board of Directors, 15 October 2012 and 5 December 2011 (the measurement dates). As at 30 June 2012, the 5 December 2011 awards had been approved but not yet issued. All unforfeited awards were issued to employees upon finalisation of the plan documents, which occurred in December 2012. The value of the vested portion of these awards has been recognised within the financial statements. This information is summarised for the Consolidated Group for the six month period ended 31 December 2012 below:

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Table of Contents

 

 

Number
of RSUs

 

Weighted
Average
Fair Value at
Measurement
Date A$

 

Awarded, but not yet issued (beginning of period)*

 

910,000

 

0.38

 

Forfeited prior to finalisation of plan*

 

(301,250

)

0.38

 

Formally issued (in addition to unissued units at beginning of period)

 

1,482,143

 

0.68

 

Forfeited subsequent to finalisation of plan

 

 

 

Converted to ordinary shares

 

 

 

Outstanding at end of period

 

2,090,893

 

0.59

 

Vested at end of period

 

765,286

 

0.48

 


*RSUs awarded, but not yet issued at beginning of period were issued upon finalisation of the plan during the period ended 31 December 2012 and are included in the total outstanding at end of period (net of forfeited units).

The following tables summarise the RSUs issued and their related grant date, fair value and vesting conditions for the six month period ended 31 December 2012 and the year ended 30 June 2012:

RSUs issued during the six month period ended 31 December 2012:

Award Date (not issued)

 

Number of
Options

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

15 October 2012

 

1,080,358

 

$

809

 

25% issuance date, 25% first three anniversaries

 

29 November 2012

 

401,785

 

340

 

25% issuance date, 25% first three anniversaries

 

 

 

1,482,143

 

$

1,149

 

 

 

RSUs awarded during the year ended 30 June 2012:

Award Date (not issued)

 

Number of
Options

 

Estimated
Fair Value
(US$’000)

 

Vesting Conditions

 

5 December 2011

 

375,000

 

$

146

 

25% issuance date, 25% first three anniversaries

 

29 November 2012

 

535,000

 

212

 

25% issuance date, 25% first three anniversaries

 

 

 

910,000

 

$

358

 

 

 

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

NOTE 28—JOINT VENTURE INTERESTS

The Group had interests in joint venture operations of 23.34% in oil and gas exploration in the PEL 100 blocks in South Australia. In December 2011, the joint venture interests were sold for $0.5 million. The net book value was nil, as the joint venture interests were impaired in previous years.

NOTE 29—EVENTS AFTER THE BALANCE SHEET DATE

On 8 March 2013, the Company acquired 100% of the outstanding shares of Texon Petroleum Ltd (“Texon”, whose name was changed to Armadillo Petroleum Ltd), an Australian corporation with oil and gas assets in the Eagle Ford formation in the United States. The Company acquired Texon to gain access to its existing production and drilling inventory in the Eagle Ford formation. As consideration, the Company issued 122.7 million ordinary shares (approximately 30.6% of the total outstanding shares immediately subsequent to the acquisition), which had a fair value of $132.1 million on the acquisition date and net cash consideration of $26.3 million for a total purchase price of $158.4 million. The net cash consideration includes a

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$141.0 million pre-merger purchase by the Company of certain Texon oil and gas properties, offset by $114.7 million of cash acquired at the time of the merger. The current income tax liability, included in accrued expenses, and deferred tax liability of $30.3 million and $15.1 million, respectively, are comprised of tax liabilities assumed as at the acquisition date and an increase in the tax liability related to the incremental acquisition date fair value of the acquired development and production and exploration and evaluation assets as compared to Texon’s historical basis.

The Company paid $158.4 million for substantially all of the net assets of Armadillo Petroleum Ltd. Due to the complexity and timing of the merger, the fair values are provisional. The following table reflects the assets acquired and the liabilities assumed at their estimated fair value (in thousands). The Company will continue to review the assets acquired and the liabilities assumed for twelve months from the date of the merger.

Estimated fair value of assets acquired:

 

 

 

Trade and other receivables

 

$

5,284

 

Other current assets

 

456

 

Development and production assets

 

53,937

 

Exploration and evaluation assets

 

145,881

 

Prepaid drilling and completion costs

 

3,027

 

Amount attributable to assets acquired

 

208,585

 

Estimated fair value of liabilities assumed:

 

 

 

Trade and other payables

 

119

 

Accrued expenses

 

34,693

 

Restoration provision

 

277

 

Deferred tax liabilities

 

15,094

 

Amount attributable to liabilities assumed

 

50,183

 

Net assets acquired

 

$

158,402

 

Purchase price:

 

 

 

Cash and cash equivalents

 

$

26,310

 

Issued capital

 

132,092

 

Total consideration paid

 

$

158,402

 

Since the acquisition date of March 8, 2013, the Company has earned revenue of $11.3 million and generated income of $5.8 million. The following reflects select pro forma information as if the merger had occurred on July 1, 2012 instead of the closing date of March 8, 2013, and excludes the results of operations for and the disposition of the South Antelope property:

 

 

6 months to
31 December 2012

 

Oil and gas revenue

 

$

913

 

Lease operating and production expenses

 

(1,689

)

Depreciation and amortisation expense

 

(3,471

)

Employee benefits expense

 

(1,085

)

Administrative expense

 

(2,098

)

Finance income

 

201

 

Exploration and evaluation expenditures

 

(359

)

Impairment of non-current assets

 

(576

)

Net gain/loss on sale of non-current assets

 

(122,327

)

Realised currency loss

 

(108

)

Profit (loss) before income tax

 

(130,599

)

Income tax benefit (expense)

 

49,585

 

 

 

(81,014

)

Profit attributable to owners of the Company for the period

 

76,210

 

Adjusted profit (loss) attributable to the owners of the Company for the period

 

$

(4,804

)

Adjusted basic and diluted earnings (loss) per share

 

$

(0.01

)

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Table of Contents

In the six month period ended 31 December 2012, the Company incurred approximately $0.7 million of transaction costs related to the acquisition of Texon. These transaction costs are included in the administrative expenses in the statement of profit or loss and other comprehensive income and are not deductible for US tax purposes. These transaction costs continued through the effective date of the acquisition and were expensed as incurred.

In connection with the sale of its South Antelope assets in September 2012, the Company elected Section 1031 “like-kind exchange” treatment which, under the US tax rules, provides for deferral of the gain if the proceeds are used to acquire “like-kind property” within six months of the closing of the transaction. In March 2013, the Company completed a transaction in which the majority of the funds remaining in its Section 1031 escrow account were used to acquire oil and gas properties in connection with the Texon Scheme of Arrangement transaction discussed above. Management believes the properties acquired qualify as “like-kind property” under Section 1031 which will result in deferral of the majority of the gain associated with the South Antelope sale.

On 6 June 2013, SEAL completed an A$48.1 million placement of 55,984,884 shares priced at A$0.86 per share. Proceeds from the placement will be used primarily to accelerate development of the Company’s Eagle Ford and Mississippian/Woodford acreage and for general corporate purposes.

After settlement of the placement, SEAL offered its shareholders with registered addresses in Australia and New Zealand the opportunity to participate in a capital raise pursuant to a Share Purchase Plan at the placement price of A$0.86 per share for up to A$15,000 per shareholder of record as at 30 May 2013 and up to a maximum capital raise of A$15.0 million. The Share Purchase Plan was open for a period from 10 June 2013 through 28 June 2013 and raised A$1.3 million from the sale of 1,517,454 shares.

On 30 August 2013, the Company entered into a second lien five-year term loan with Wells Fargo Energy Capital for $15 million and used the proceeds to pay down the balance of the first lien revolving line of credit with Wells Fargo Bank on 3 September 2013. Substantially all of the Company’s assets are collateralized by both the first lien revolving line of credit and the second lien term loan. The Company’s total outstanding debt remained at $30 million as at 18 October 2013.

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

Contract Type

 

Basis

 

Quantity/Month

 

Floor Price

 

Ceiling Price

 

Term

 

Swap

 

LLS

 

3,000

 

$

101.75

 

$

101.75

 

Jul 13 - Dec 13

 

Collar

 

LLS

 

3,000

 

95.00

 

104.90

 

Jul 13 - Dec 13

 

Swap

 

NYMEX-WTI

 

1,000

 

106.55

 

106.55

 

Oct 13 - Dec 13

 

Swap

 

LLS

 

10,000

 

110.85

 

110.85

 

Oct 13 - Dec 13

 

Swap

 

LLS

 

5,000

 

103.75

 

103.75

 

Jul 13 - Dec 13

 

Swap

 

LLS

 

3,000

 

101.75

 

101.75

 

Jul 13 - Jun 14

 

Collar

 

NYMEX-WTI

 

3,000

 

90.00

 

99.75

 

Jul 13 - Jun 14

 

Collar

 

LLS

 

2,000

 

90.00

 

102.00

 

Jan 14 - Dec 14

 

Collar

 

LLS

 

3,000

 

90.00

 

101.30

 

Jan 14 - Dec 14

 

Swap

 

NYMEX-WTI

 

2,000

 

97.40

 

97.40

 

Jan 14 - Dec 14

 

Swap

 

LLS

 

3,000

 

102.30

 

102.30

 

Jan 14 - Dec 14

 

Collar

 

NYMEX-WTI

 

3,000

 

85.00

 

94.75

 

Jan 14 - Dec 14

 

Swap

 

LLS

 

3,000

 

100.15

 

100.15

 

Jan 14 - Dec 14

 

Collar

 

LLS

 

2,000

 

85.00

 

102.00

 

Jul 14 - Dec 14

 

Collar

 

NYMEX-WTI

 

2,500

 

80.00

 

98.25

 

Jul 14 - Dec 14

 

Collar

 

NYMEX-WTI

 

2,000

 

75.00

 

98.65

 

Jan 15 - Dec 15

 

Collar

 

LLS

 

3,000

 

85.00

 

101.05

 

Jan 15 - Dec 15

 

Contract Type

 

Basis

 

Quantity/Month

 

Floor Price

 

Ceiling Price

 

Term

 

Swap

 

NYMEX-HH

 

10,000

 

$

4.15

 

$

4.15

 

May 13 - Dec 13

 

Swap

 

HSC

 

10,000

 

4.01

 

4.01

 

Jun 13 - Dec 13

 

Swap

 

NYMEX-HH

 

20,000

 

4.23

 

4.23

 

Jan 14 - Dec 14

 

Collar

 

HSC

 

10,000

 

3.75

 

4.60

 

Jan 14 - Dec 14

 

Other than as detailed above, no matters or circumstances have arisen since the end of the financial year which significantly affected or may significantly affect the operations of the Group, the results of those operations, or the state of affairs of the Group in future financial years.

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Table of Contents

NOTE 30—RELATED PARTY TRANSACTIONS

Transactions with related parties: N Martin was a partner and is now a consultant of Minter Ellison Lawyers and has been a Director since 1 March 2012. Minter Ellison Lawyers were paid a total of $148,073 and $124,007 for legal services for the period and year ended 31 December and 30 June 2012, respectively.

NOTE 31—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 focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. The Group utilise derivative financial instruments to hedge certain risk exposures. The Group’s financial instruments consist mainly of deposits with banks, short term investments, accounts receivable, derivative financial instruments, finance facility, and payables. The main purpose of non-derivative financial instruments is to raise finance for the Group operations.

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 main risk the Group is exposed to through its financial instruments is interest rate risk. The interest rate risk is managed with a mixture of fixed and floating rate cash deposits. At 31 December and 30 June 2012 approximately nil and 6% of Group deposits are fixed, respectively. It is the policy of the Group to keep surplus cash in interest yielding deposits.

iii)Commodity Price Risk Exposure and Management

The Board actively reviews oil hedging on a monthly basis. Reports providing detailed analysis of the Group’s hedging activity are continually monitored against Group policy. The Group sells its oil on market using Nymex market spot rates reduced for basis differentials in the basins from which the Company produces. Nymex is a light, sweet crude oil delivered to Cushing, Oklahoma, which is used as the benchmark for onshore United States petroleum prices. Forward contracts are used by the Group to manage its forward commodity price risk exposure. The Group’s policy is to hedge less than 50% of anticipated future oil production for up to 24 months. The Group may hedge over 50% or beyond 24 months with approval of the Board. The Group has not elected to utilise hedge accounting treatment and changes in fair value are recognised in the statement of profit or loss and other comprehensive income.

Commodity Hedge Contracts outstanding at 31 December 2012

Contract Type

Counterparty

Basis

Quantity/mo

Strike Price

Term

Swap

Shell Trading US

NYMEX

2,000 BBL

$99.00

1-Mar-12 - 31-Dec-13

Collar

Shell Trading US

NYMEX

1,000 BBL

$90.00/$117.50

1-Jan-13 - 31-Dec-13

Collar

Shell Trading US

NYMEX

1,000 BBL

$95.00/$112.75

1-Jan-13 - 31-Dec-13

Swap

Shell Trading US

NYMEX

3,000 BBL

$102.95

1-Jan-13 - 31-Dec-13

Swap

Shell Trading US

NYMEX

10,000 MMBTU

$3.58

1-Jan-13 - 31-Dec-13

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a)Sensitivity Analysis

Interest Rate and Price Risk

The Group has performed a sensitivity analysis relating to its exposure to interest rate risk at balance date. This sensitivity analysis demonstrates the effect on the current period results and equity which could result from a change in these risks. The balance of debt as at 31 December and 30 June 2012 was $30 million and $15 million and is included in the Interest Rate Sensitivity Analysis below.

Interest Rate Sensitivity Analysis

The effect on income and equity as a result of changes in the interest rate, with all other variables remaining constant would be as follows:

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months
30 June 2012
US$’000

 

Change in profit/(loss)

 

 

 

 

 

—increase in interest rates + 2%

 

$

(157

)

$

310

 

—decrease in interest rates - 2%

 

157

 

(234

)

Change in equity

 

 

 

 

 

—increase in interest rates + 2%

 

$

(157

)

$

310

 

—decrease in interest rates - 2%

 

157

 

(234

)

Foreign Currency Risk Sensitivity Analysis

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

Oil Prices Risk Sensitivity Analysis

The effect on profit and equity as a result of changes in oil prices with all variables remaining constant would be as follows:

 

 

Consolidated Group

 

 

 

6 months to
31 December 2012
US$’000

 

12 months to
30 June 2012
US$’000

 

Change in profit/(loss)

 

 

 

 

 

—improvement in US$ oil price of $10 per barrel

 

$

1,476

 

$

3,648

 

—decline in US$ oil price of $10 per barrel

 

(1,424

)

(3,637

)

Change in equity

 

 

 

 

 

—improvement in US$ oil price of $10 per barrel

 

$

1,476

 

$

3,648

 

—decline in US$ oil price of $10 per barrel

 

(1,424

)

(3,637

)

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. The balances are not materially different from those disclosed in the statement of financial position of the Group.

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c)Credit Risk

The maximum exposure to credit risk, excluding the value of any collateral or other security, at balance date to recognise the financial assets, is the carrying amount, net of any impairment of those assets, as disclosed in the balance sheet and notes to the financial statements.

The Group does not have any material credit risk exposure to any single debtor or group of debtors under financial instruments entered into by the consolidated entity.

d)Major Customers

For the six-month period ended 31 December 2012, our major customers were Helis Oil & Gas Company LLC (“Helis”), EOG Resources Inc. (“EOG”), Hess Corporation (“Hess”) and Suncor Energy Marketing Inc. (“Suncor”) and accounted for 29%, 22%, 21% and 10%, respectively, of our consolidated oil and gas sales revenue. For the year period ended 30 June 2012, our major customers were Helis, Hess, and EOG, and accounted for 47%, 20% and 14%, respectively, of our consolidated oil and gas sales revenue.

Helis, Hess and EOG are operators of our properties in the Bakken; they sell crude oil and natural gas to various purchasers in the region and remit our share of the revenue to us. If any of the companies who purchase the crude oil and natural gas from the operators were to discontinue purchasing production from this area, there are a number of other purchasers to whom we could sell our production with little or no delay. If those parties were to discontinue purchasing our product, there would be challenges initially, but ample markets to handle the disruption.

e)Liquidity Risk

Prudent liquidity risk management implies maintaining sufficient cash and marketable securities and the availability of funding through an adequate committed credit facility. The Company aims to maintain flexibility in funding to meet ongoing operational requirements and exploration and development expenditures by keeping a committed credit facility available. The Company has the following commitments related to its non-derivative financial liabilities:

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Trade and other payables

 

 

 

 

 

—due within one year

 

$

38,770

 

$

22,056

 

—due within 1 - 5 years

 

 

 

—due later than 5 years

 

 

 

 

 

$

38,770

 

$

22,056

 

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Accrued expenses

 

 

 

 

 

—due within one year

 

$

13,072

 

$

8,337

 

—due within 1 - 5 years

 

 

 

—due later than 5 years

 

 

 

 

 

$

13,072

 

$

8,337

 

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Credit facility principal payments

 

 

 

 

 

—due within one year

 

$

 

$

 

—due within 1 - 5 years

 

30,000

 

15,000

 

—due later than 5 years

 

 

 

 

 

$

30,000

 

$

15,000

 

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f)Foreign Currency Risk

The Group is exposed to fluctuations in foreign currency arising from transactions in currencies other than the Group’s functional currency (US$).

g)Market Risk

The Company is exposed to fluctuations in its share price arising from the Texon Acquisition Scheme, in which subsequent to 31 December 2012, the Company used approximately 122.7 million newly issued Sundance shares to acquire Texon (“Acquisition Scheme Consideration”). Immediately preceding the announcement of the Acquisition Scheme, Sundance shares were valued at A$0.82 per share, which would have represented equity consideration of A$100.6 million. As at the Acquisition Date, Sundance shares were valued at A$1.05 per share, which resulted in equity consideration fair value of A$128.8 million. Following the completion of the Acquisition Scheme, the Company will undertake a comprehensive assessment of the fair value of the assets acquired and liabilities assumed as at the acquisition date and record the asset and liability fair values accordingly. Any difference between the fair value of the Acquisition Scheme Consideration and the fair value of the net assets acquired will be accounted for as goodwill or a bargain purchase as appropriate.

NOTE 32—PARENT COMPANY INFORMATION

a)Cost Basis

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Parent Entity

 

 

 

 

 

Assets

 

 

 

 

 

Current assets

 

$

1,490

 

$

986

 

Investment in subsidiaries

 

134,094

 

57,643

 

Total assets

 

$

135,584

 

$

58,629

 

Liabilities

 

 

 

 

 

Current liabilities

 

$

127

 

$

109

 

Non-current liabilities

 

 

 

Total liabilities

 

127

 

109

 

Total net assets

 

$

135,457

 

$

58,520

 

Equity

 

 

 

 

 

Issued capital

 

58,694

 

57,978

 

Share options reserve

 

386

 

386

 

Retained earnings (loss)

 

76,377

 

156

 

Total equity

 

$

135,457

 

$

58,520

 

Financial Performance

 

 

 

 

 

Profit/(loss) for the year

 

$

(241

)

$

464

 

Other comprehensive income

 

 

 

Total profit or loss and other comprehensive income

 

$

(241

)

$

464

 

b)Equity Basis

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Parent Entity

 

 

 

 

 

Assets

 

 

 

 

 

Current assets

 

$

1,490

 

$

986

 

Investment in subsidiaries

 

150,453

 

73,327

 

Total assets

 

$

151,943

 

$

74,313

 

Liabilities

 

 

 

 

 

Current liabilities

 

$

127

 

$

109

 

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Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Non-current liabilities

 

 

 

Total liabilities

 

127

 

109

 

Total net assets

 

$

151,816

 

$

74,204

 

Equity

 

 

 

 

 

Issued capital

 

$

58,694

 

$

57,978

 

Share options reserve

 

4,045

 

3,205

 

Foreign currency translation

 

(1,095

)

(941

)

Retained earnings (loss)

 

90,172

 

13,962

 

Total equity

 

$

151,816

 

$

74,204

 

Financial Performance

 

 

 

 

 

Profit/(loss) for the period before equity in income of subsidiaries

 

$

(241

)

$

464

 

Equity in income of subsidiaries

 

76,451

 

5,548

 

Other comprehensive income

 

(154

)

(247

)

Total profit or loss and other comprehensive income

 

$

76,056

 

$

5,765

 

c)Cash Flow

 

 

Consolidated Group

 

 

 

31 December 2012
US$’000

 

30 June 2012
US$’000

 

Cash flow from operating activities

 

$

(1,655

)

$

396

 

Cash flow from investing activities

 

11

 

(7,629

)

Cash flow from financing activities

 

716

 

147

 

Guarantees in relation to relation to the debts of subsidiaries

Sundance Energy Australia Limited has not entered into a deed of cross guarantee with its’ wholly-owned subsidiary, Sundance Energy, Inc. related to the credit facility with Wells Fargo.

NOTE 33. UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES

Costs Incurred—The following table sets forth the capitalized costs incurred in our oil and gas production, exploration, and development activities:

(in thousands)

 

Six months ended
December 31, 2012

 

Year ended
June 30, 2012

 

Property Acquisition Costs

 

 

 

 

 

Proved

 

$

986

 

$

 

Unproved

 

23,330

 

8,670

 

Exploration costs

 

 

 

Development costs

 

46,981

 

50,520

 

 

 

$

71,297

 

$

59,190

 

Oil and Gas Reserve Information—Proved reserve quantities are based on estimates prepared by the Company in accordance with guidelines established by the Securities and Exchange Commission (SEC). Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC.

Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interests owned by the Company as at December 31, 2012, and June 30, 2012 and 2011. The individual primarily responsible for overseeing the review is a Senior Vice President with NSAI and a Registered Professional Engineer in the State of Texas with over 30 years of experience in oil and gas reservoir studies and evaluations.

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

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

The following reserve data represents estimates only and should not be construed as being exact.

 

 

Oil
(MBbl)

 

Gas
(MMcf)

 

Total Oil
Equivalents
(MBbl)

 

Total proved reserves:

 

 

 

 

 

 

 

June 30, 2011

 

4,788

 

7,692

 

6,070

 

Revisions of previous estimates

 

220

 

170

 

248

 

Extensions and discoveries

 

3,309

 

5,560

 

4,236

 

Production

 

(338

)

(370

)

(399

)

June 30, 2012

 

7,979

 

13,052

 

10,155

 

Revisions of previous estimates

 

(556

)

(1,205

)

(757

)

Extensions and discoveries

 

1,597

 

4,322

 

2,317

 

Purchases of reserves in-place

 

827

 

5,797

 

1,793

 

Production

 

(195

)

(233

)

(234

)

Sales of reserves in-place

 

(3,894

)

(4,845

)

(4,702

)

December 31, 2012

 

5,758

 

16,888

 

8,572

 

Proved developed reserves:

 

 

 

 

 

 

 

June 30, 2011

 

1,497

 

2,637

 

1,936

 

June 30, 2012

 

2,564

 

4,905

 

3,382

 

December 31, 2012

 

1,932

 

5,242

 

2,805

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

June 30, 2011

 

3,291

 

5,055

 

4,134

 

June 30, 2012

 

5,415

 

8,147

 

6,773

 

December 31, 2012

 

3,826

 

11,646

 

5,767

 

During the year ended June 30, 2012, we added 4,236 MBoe through extensions and discoveries. Of these additions, approximately 1,486 and 2,750 MBoe were attributable to our Wattenberg and Bakken assets, respectively.

During the six-month period ended December 31, 2012, we added 2,317 MBoe through extensions and discoveries. Of these additions, approximately 1,522, 306 and 489 MBoe were attributable to our Wattenberg, Bakken and Mississippian/Woodford assets, respectively. Our purchase of reserves were located in the Machii Ross project of the Wattenberg, and sales of reserves were located in the South Antelope prospect of the Bakken.

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

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

The following summary sets forth our Standardized Measure:

(in thousands)

 

Six months ended
December 31, 2012

 

Year ended
June 30, 2012

 

Cash inflows

 

$

594,549

 

$

773,203

 

Production costs

 

(198,304

)

(215,252

)

Development costs

 

(113,531

)

(137,121

)

Income tax expense

 

(51,408

)

(101,481

)

Net cash flow

 

231,306

 

319,349

 

10% annual discount rate

 

(115,759

)

(182,064

)

Standardized measure of discounted future net cash flow

 

$

115,547

 

$

137,285

 

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

(in thousands)

 

Six months ended
December 31, 2012

 

Year ended
June 30, 2012

 

Standardized Measure, beginning of period

 

$

137,285

 

$

59,444

 

Sales, net of production costs

 

(13,642

)

(23,432

)

Net change in sales prices, net of production costs

 

(4,997

)

23,379

 

Extensions and discoveries, net of future production and development costs

 

41,481

 

63,264

 

Changes in future development costs

 

(3,565

)

(13,921

)

Previously estimated development costs incurred during the period

 

33,714

 

39,268

 

Revision of quantity estimates

 

(15,138

)

5,645

 

Accretion of discount

 

17,442

 

7,750

 

Change in income taxes

 

17,098

 

(19,081

)

Purchases of reserves in-place

 

7,626

 

 

Sales of reserves in-place

 

(87,374

)

 

Change in production rates and other

 

(14,383

)

(5,031

)

Standardized Measure, end of period

 

$

115,547

 

$

137,285

 

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

The following average prices were used in determining the Standardized Measure as at:

 

 

December 31, 2012

 

June 30, 2012

 

Oil price per Bbl

 

$

94.71

 

$

95.67

 

Gas price per Mcf

 

$

2.75

 

$

3.15

 

We calculate 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/ ERICEric P. MCCRADYMcCrady

 

 

Name:

Eric P. McCrady

 

 

Title:

Chief Executive Officer

 

Date: May 15, 2015April 28, 2017

 

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Table of Contents

EXHIBIT INDEX

 

Exhibit
Number

 

Description of Exhibit

1.1

 

Constitution of Sundance Energy Australia Limited*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**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**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*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*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, 2013 dated July 3, 2014*

15.2

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)


*Filed as an Exhibit to our Form 20-F filed with the SEC on July 11, 2014, and incorporated herein by reference.

**Filed herewith.

 


* Filed herewith.