Brookfield Business Partners 20F/A 2017 Annual report (foreign) (amended)

As filed with the Securities and Exchange Commission on June 28, 2018


		UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 20-F/A (AMENDMENT NO. 1)


o		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the fiscal year ended December 31, 2017
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
o		SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-37775

BROOKFIELD BUSINESS PARTNERS L.P.
(Exact name of Registrant as specified in its charter)

Bermuda
(Jurisdiction of incorporation or organization)

73 Front Street
Hamilton, HM 12, Bermuda
+1-441-294-3309
(Address of principal executive offices)
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

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

Title of each class		Name of each exchange on which registered

Limited Partnership Units		New York Stock Exchange
Limited Partnership Units		Toronto Stock Exchange

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

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

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

66,185,798 Limited Partnership Units as of December 31, 2017.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No o

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. Yes o No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

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 ý Accelerated filer o Non-accelerated filer o

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


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

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. Item 17 o Item 18 o

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). Yes o No ý

EXPLANATORY NOTE

This Amendment No. 1 on Form 20-F/A (the "Form 20-F/A") is being filed by Brookfield Business Partners L.P. (the "Registrant") to amend the Registrant's Annual Report on Form 20-F (the "Form 20-F") for the fiscal year ended December 31, 2017, filed with the Securities and Exchange Commission on March 9, 2018. This Form 20-F/A is being filed solely to supplement Item 18 of the Form 20-F with the inclusion of the financial statements of Quadrant Energy Holdings Pty (Ltd.) ("Quadrant") for the fiscal year ended December 31, 2017 (the "Quadrant Financial Statements") pursuant to Rule 3-09 of Regulation S-X.

As required by Rule 12b-15 under the Securities Exchange Act of 1934, as amended, updated certifications of our principal executive officer and our principal financial officer are being filed as exhibits to the Form 20-F/A. The Form 20-F/A also includes Exhibit 15.2, which contains the consent of Ernst & Young LLP with respect to the Quadrant Financial Statements.

This Form 20-F/A consists solely of a cover page, this explanatory note, the Quadrant Financial Statements, updated certifications of our principal executive officer and our principal executive officer, Exhibit 15.2 and a signature page.

Except as described above, this Form 20-F/A does not amend, update or restate the information in any other item of the Form 20-F, or reflect any events that have occurred after the original filing of the Form 20-F.

ITEM 18. FINANCIAL STATEMENTS

The following financial statements are included in this Form 20-F/A:

(1): Consolidated Financial Statements as of and for the years ended December 31, 2017 and 2016 for Quadrant Energy Holdings Pty (Ltd.).

Contents


Consolidated Statement of Financial Position as at 31 December 2017			2
Consolidated Statement of Profit or Loss and Other Comprehensive Income for the years ended 31 December 2017 and 31 December 2016 and the period ended 31 December 2015			3
Consolidated Statements of Cash Flows for the years ended 31 December 2017 and 31 December 2016 and the period ended 31 December 2015			4
Consolidated Statements of Cash Flows for the years ended 31 December 2017 and 31 December 2016 and the period ended 31 December 2015			5
1—Group Structure and Overview			6
2—Operational Performance			15
3—Liquidity and Capital Management			22
4—Working Capital			34
5—Non Financial Assets and Liabilities			36
6—Unrecognised Items			46
7—Equity and Reserves			48
8—Other Information			50

Consolidated Statement of Financial Position as at 31 December 2017

(stated in millions of US dollars)	Notes		2016

			(unaudited)
Assets
Current Assets
Cash and cash equivalents	3a	146.0		105.9
Trade and other receivables	4a	98.2		105.4
Inventories	4c	47.4		56.1
Income tax receivable		—		14.8
Derivative financial assets	3e	5.6		47.3
Contractual assets	5e	14.7		15.3

Total current assets		311.9		344.8

Non-current assets
Other receivables	4a	1.3		3.7
Oil and gas properties	5a	2,786.3		2,595.0
Corporate assets	5a	24.2		18.3
Exploration and evaluation	5b	258.1		229.8
Goodwill	5a	246.9		246.9
Intangible assets		5.5		5.5
Derivative financial assets	3e	0.3		13.0
Contractual assets	5e	21.6		36.3
Deferred tax assets	8b	486.7		626.9

Total non-current assets		3,830.9		3,775.4

Total assets		4,142.8		4,120.2

Liabilities
Current liabilities
Trade and other payables	4b	57.3		94.5
Interest-bearing loans—external banks	3c	170.8		242.0
Provisions	5c	104.0		121.9
Deferred Revenue	5d	2.6		10.4
Derivative financial liabilities	3e	5.9		3.0
Contractual liabilities	5e	47.1		51.5

Total current liabilities		387.7		523.3

Non-current liabilities
Interest-bearing loans—external banks	3c	361.1		282.3
Interest-bearing loans—shareholders	3c	—		341.4
Trade and other payables	4b	13.4		5.0
Deferred tax liabilities	8b	946.9		920.1
Provisions	5c	949.2		819.6
Deferred revenue	5d	708.5		709.2
Contractual liabilities	5e	171.7		217.5

Total non-current liabilities		3,150.8		3,295.1

Total liabilities		3,538.5		3,818.4

Net assets		604.3		301.8

Equity
Contributed equity	7a	224.6		224.6
Retained earnings		378.4		36.5
Other reserves	7b & 7d	1.3		40.7

Total equity		604.3		301.8

The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes.

Consolidated Statements of Profit or Loss and Other Comprehensive Income for the years ended
31 December 2017 and 31 December 2016 and the period ended 31 December 2015

(stated in millions of US dollars except per share amounts)	Notes			Year ended 31 December 2016			Period from 27 March to 31 December 2015

				(unaudited)			(unaudited)
Operating revenue	2b	822.6			781.5			478.1
Cost of sales	2c	(436.4	)		(467.4	)		(316.2	)

Gross profit		386.2			314.1			161.9

Other income	2d	241.4			156.5			82.4
Other expenses	2e	(68.6	)		(232.2	)		(258.5	)

Profit / (loss) before tax and finance costs		559.0			238.4			(14.2	)

Finance income	3d	3.3			4.4			0.6
Finance costs	3d	(58.5	)		(76.5	)		(48.8	)

Profit / (loss) before tax		503.8			166.3			(62.4	)

Taxation (expense) / benefit	8a	(161.9	)		(80.5	)		13.1

Profit / (loss) after tax		341.9			85.8			(49.3	)

Other comprehensive income / (loss)
Items that may be reclassified to profit and loss Cash flow hedges (net of tax)	7b	(40.1	)		(137.6	)		177.7

Other comprehensive income / (loss) for the period, net of tax		(40.1	)		(137.6	)		177.7

Total comprehensive income / (loss) for the period		301.8			(51.8	)		128.4

Earnings / (loss) per share attributable to the ordinary shareholders of the Company:		US cents			US cents			US cents
Basic and diluted earnings / (loss) per share	8d	142.5			35.7			(20.5	)

The above Consolidated Statements of Profit or Loss and Other Comprehensive Income should be read in conjunction with the accompanying notes.

Consolidated Statements of Cash Flows for the years ended 31 December 2017 and 31 December 2016 and the period ended 31 December 2015

(stated in millions of US dollars)	Notes			Year ended 31 December 2016			Period from 27 March to 31 December 2015

				(unaudited)			(unaudited)
Cash flows from / (used in) operating activities
Receipts from customers and third parties		818.0			674.2			417.4
Proceeds on settlement of derivatives		67.3			143.7			37.9
Deferred revenue receipt		—			35.1			564.6
Payments to suppliers and employees		(215.3	)		(221.5	)		(244.9	)
Payments for commercial settlements		(51.9	)		—			—
Interest paid		(21.9	)		(26.3	)		(19.1	)
Stamp duty paid in relation to acquisition of business		—			(27.9	)		—
Taxation (paid) / received		(44.6	)		10.9			(22.1	)

Net cash from operating activities	3b	551.6			588.2			733.8
Cash flows from / (used in) investing activities
Payments for capital and exploration expenditure		(177.5	)		(411.9	)		(190.0	)
Payments for corporate assets		(11.6	)		(3.6	)		(8.6	)
Proceeds from disposal of assets		—			20.0			13.8
Acquisition of businesses (net of closing adjustments and cash acquired)		11.6			—			(1,720.0	)

Net cash used ininvesting activities		(177.5	)		(395.5	)		(1,904.8	)
Cash flows from / (used in) financing activities
Proceeds from borrowings		302.0			—			1,290.0
Repayment of borrowings		(638.6	)		(320.0	)		(99.0	)
Net proceeds from the issue of shares		—			—			224.6

Net cash from / (used) in financing activities		(336.6	)		(320.0	)		1,415.6

Net increase / (decrease) in cash and cash equivalents		37.5			(127.3	)		244.6

Net foreign exchange differences		2.6			(4.7	)		(6.7	)
Cash and cash equivalents at the beginning of the period*		105.9			237.9			—

Cash and cash equivalents at the end of the period*	3a	146.0			105.9			237.9

*: Includes the Groups share of cash held in Joint Operations as per note 3a.

The above Consolidated Statements of Cash Flows should be read in conjunction with the accompanying notes.

Consolidated Statements of Changes in Equity for the year ended 31 December 2017 and 31 December 2016 and the period ended 31 December 2015

(stated in millions of US dollars)

Balance at 1 January 2017	224.6	40.1		0.6	36.5		301.8
Net profit after tax	—	—		—	341.9		341.9
Other comprehensive loss	—	(40.1	)	—	—		(40.1	)

Total comprehensive income / (loss)	—	(40.1	)	—	341.9		301.8

Share based payments expense	—	—		0.7	—		0.7

Balance at 31 December 2017	224.6	—		1.3	378.4		604.3

Unaudited
Balance at 1 January 2016	224.6	177.7		0.2	(49.3	)	353.2
Net profit after tax	—	—		—	85.8		85.8
Other comprehensive loss	—	(137.6	)	—	—		(137.6	)

Total comprehensive income / (loss)	—	(137.6	)	—	85.8		(51.8	)

Share based payments expense	—	—		0.4	—		0.4

Balance at 31 December 2016	224.6	40.1		0.6	36.5		301.8

Unaudited
Balance at 27 March 2015	—	—		—	—		—
Net profit after tax	—	—		—	(49.3	)	(49.3	)
Other comprehensive income / (loss)	—	177.7		—	—		177.7

Total comprehensive income / (loss)	—	177.7		—	(49.3	)	128.4

Shares issued (net of costs)	224.6	—		—	—		224.6
Share based payments expense	—	—		0.2	—		0.2

Balance at 31 December 2015	224.6	177.7		0.2	(49.3	)	353.2

The above Consolidated Statements of Changes in Equity should be read in conjunction with the accompanying notes.

1—Group Structure and Overview

1a) General information

About this report

The financial report of Quadrant Energy Holdings Pty Ltd ("QEHPL" or "the Company") and its subsidiaries (collectively "Quadrant Energy" or "the Group") for the year ended 31 December 2017 was authorised for issue in accordance with a resolution of the Directors on 26 June 2018.

Quadrant Energy Holdings Pty Ltd is a Company limited by shares, incorporated and domiciled in Australia. Quadrant Energy Holdings Pty Ltd was incorporated on 27 March 2015. The group was effectively dormant until the acquisition of Apache Energy Australia Ltd on 5 June 2015, therefore the 2015 comparative figures in this report effectively represent six months and twenty five days of operations of the acquired business. Quadrant Energy Holdings Pty Ltd is a for-profit entity for the purpose of preparing financial statements under International Financial Reporting Standards.

The Group is principally engaged in the exploration, evaluation, development, production and marketing of hydrocarbons.

The Group's principal place of business is Western Australia and the Group's registered office is 100 St Georges Terrace, Perth, Australia. Further information on the nature of the operations, structure and principal activities of the Group, and related party relationships is provided throughout this report.

Basis of preparation

(i): Compliance with IFRS:

These general purpose financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

(ii): Historical cost convention:

The financial statements have been prepared on a historical cost basis, except for derivative financial assets and liabilities, which are measured at fair value.

The Group has also applied a number of amendments to accounting standards applicable for the first time for the financial year ended 31 December 2017. The impact of the amendments does not have a material impact on the consolidated financial statements.

Joint arrangements and key changes in participating equity interests

Exploration, development and production activities of the Group are primarily carried out through joint arrangements with other parties.

Joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations each participant has, rather than the legal structure of the joint arrangement. The Group has assessed the nature of its joint arrangements and determined that they comprise interests in joint operations.

In respect of interests in joint operations, the Group recognises its:

•: Assets, including its share of any assets held jointly;
•: Liabilities, including its share of any liabilities incurred jointly;
•: Revenue from the sale of its share of the output arising from the joint operation;

•: Share of revenue from the sale of output by the joint operation; and
•: Expenses, including its share of any expenses incurred jointly.

These have been incorporated in the financial statements under the appropriate headings.

The table below summarises key operating assets, the related permits and Quadrant Energy's ownership percentage at 31 December 2017 and 31 December 2016.

Portfolio	Asset name	Permits

Gas segment
Varanus Island	Harriet	TL/1, 5, 6, 8, 9 & 10	100.00	**	80.72
	Airlie	TL/2	68.83		68.83
	John Brooks	WA-29-L	55.00		55.00
	East Spar / Halyard	WA-13-L	55.00		55.00
Macedon	Macedon	WA-42-L	28.57		28.57
Reindeer	Devil Creek	WA-41-L	55.00		55.00
Oil segment
Ningaloo Vision	Van Gogh Coniston / Novara	WA-35-L	52.50		52.50
Pyrenees	Pyrenees	WA-42-L	28.57		28.57
	Ravensworth	WA-43L	31.50		31.50
Stag	Stag	WA-15-L	0.00		0.00	*

Further information in relation to joint arrangements is provided in section 8.

*: Stag Divestment

During 2016 Mitra Energy Inc. ("Mitra") through a wholly owned subsidiary Jadestone Energy (Australia) Pty Ltd ("Jadestone") signed a definitive Sale & Purchase Agreement ("SPA") for the acquisition of a 100% interest in the Stag Oilfield. The SPA was subject to the satisfaction of certain conditions precedent to closing. All conditions precedent were satisfied and the Stag Oilfield acquisition closed with an effective date of 11 November 2016. Prior to the sale Quadrant Energy held a 33.33% interest. Total cash consideration was US$10.0 million (Quadrant Energy share US$3.3 million) plus adjustments to reflect an economic effective date of 1 July 2016. Transfer of operatorship and title occurred upon completion of the required regulatory processes and approvals.

**: Harriet Acquisition

During the financial year the Group acquired the other participants' interest in the operation (refer to note 1c) and gained control of the operations.

Basis of consolidation

The consolidated financial statements comprise the financial statements of the Group and controlled entities (subsidiaries).

The consolidated financial statements of subsidiaries are prepared for the same reporting period as the Company, using consistent accounting policies. Adjustments are made to bring into line any dissimilar accounting policies that may exist. In preparing the consolidated financial statements, all inter-company balances and transactions, income and expenses and profits and losses resulting from intra-Group transactions have been eliminated.

Subsidiaries are consolidated from the date on which control is obtained to the date on which control is disposed (refer note 8e). Control is achieved when the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Business combinations are accounted for using the acquisition method of accounting.

Foreign currency

Items included in the consolidated financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates ('the functional currency'). The consolidated financial statements are presented in United States dollars, which is the Group's presentation currency and the functional currency of Quadrant Energy Holdings Pty Ltd and its operations and subsidiaries.

Transactions in foreign currencies are initially recorded in the functional currency at the exchange rates ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the rate of exchange ruling at the statement of financial position date. Exchange differences arising from the application of these procedures are taken to the consolidated statement of profit or loss and other comprehensive income.

Notes to the financial statements

The notes include information which is required to understand the financial statements and is material and relevant to the operations, financial position and performance of the Group. The notes are organised into the following sections with relevant notes summarising the accounting policies, judgements and estimates relevant to understanding related line items:

1.: Group Structure and Overview
2.: Operational Performance
3.: Liquidity and Capital Management
4.: Working Capital
5.: Non Financial Assets and Liabilities
6.: Unrecognised Items
7.: Equity and Reserves
8.: Other Information

Other accounting policies

Significant and other accounting policies that summarise the measurement basis used and are relevant to an understanding of the financial statements are provided throughout the notes to the financial statements.

New and amended standards and interpretations issued but not yet effective

A number of new, amended standards and interpretations have recently been issued but are not yet effective and have not been adopted by the Group as at the financial reporting date. The Group expects to adopt the new standards at the mandatory application date.

The Group has reviewed these standards and interpretations, and with the exception of the items listed below, none of the new or amended standards will significantly affect the Group's accounting policies, financial position or performance. The Group's assessment of the impact of certain relevant new standards and interpretations is set out below.

Title

Nature of change

Impact

Mandatory
application
date

IFRS 15Revenue from Contracts with Customers

IFRS 15 is based on the principle that revenue is recognised when control of a good or service transfers to a customer. IFRS 15 provides a single, principles-based five-step model to be applied to all contracts with customers. Guidance is provided on topics such as the point at which revenue is recognised, accounting for variable consideration, costs of fulfilling and obtaining a contract and various related matters. New disclosures regarding revenue are also introduced.

The Group has assessed the impact of applying the new standard.

The new standard is expected to impact primarily on the Gas segment with Gas sales are provided under long term supply agreements.

The major adjustment identified is in relation to prepaid domestic gas supply contracts where these are considered to contain a significant financing component. The new standard requires the application of an interest charge on these contracts, which is not required under IAS 18.

The new standard is not expected to significantly impact revenue recognition for oil and condensate sales. The majority of such sales are made as spot sales under the Free On Board Incoterm, which will continue to be recognised on completion of the bill of lading.

The Group does not expect a change to its current revenue recognition for tolling income, which is currently recognised as the gas is processed and services rendered.

Had the standard been adopted from 1 January 2017, the Group estimates that it would have to make the following adjustments to the amounts recognised in the 31 December 2017 Statement of profit or loss and other comprehensive income:

•

An increase in interest expense of approximately US$41.8 million; offset by

•

A decrease in tax expense of approximately US$12.6 million.

1 January 2018

Title

Nature of change

Impact

Mandatory
application
date

The Group currently expects to adopt the modified retrospective approach to transition, where the cumulative effect of initially applying this Standard is recognised as an adjustment to the opening balance of retained earnings at the date of implementation of the standard without adjustment of comparatives.

On adoption date on 1 January 2018, the Group estimates that it will make the following adjustments to the financial information;

•

An increase to contract liabilities of approximately US$99.3 million;

•

A decrease to opening retained earnings of approximately US$69.6 million and

•

A decrease to the deferred tax liability of US$29.8 million.

The new standard will only be applied to contracts that remain in force at the transition date.

IFRS 9Financial Instruments

IFRS 9 addresses the classification, measurement and derecognition of financial assets and financial liabilities, introduces a new, single 'expected loss impairment model for financial assets and a substantially redesigned approach to hedge accounting.

The Group has reviewed its financial assets and liabilities and does not expect the new standard to have a significant impact on the measurement of its financial assets and liabilities. Fair value changes resulting from credit risk and the introduction of the expected loss impairment model for determining credit provisions are not expected to have a material impact on future results.

All of the Group's financial assets will be measured at amortised cost. This treatment is consistent with the current policy applied and so no adjustments are expected to arise.

There will be no impact on the Group's accounting for financial liabilities, as the new requirements only affect the accounting for financial liabilities that are designated at fair value through profit or loss and the Group currently does not have any such liabilities.

1 January 2018

Title

Nature of change

Impact

Mandatory
application
date

The new hedge accounting rules will align the accounting for hedging more closely with the Group's risk management practices. The new standard introduces a more principles-based approach providing the ability to hedge risk exposures not previously able to be hedged, and to use new hedging instruments to do so.

The Group's existing hedge relationships have been reviewed and qualify as continuing hedges and are expected to continue to be effective under IFRS 9. As a result, the Group does not expect a significant impact on the accounting for its current hedging relationships.

IFRS16Leases

IFRS 16 provides a new lessee accounting model which will result in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed.

Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. A lessee measures right-of-use assets similarly to other non-financial assets and lease liabilities similarly to other financial liabilities. Assets and liabilities arising from a lease are initially measured based on the present value of lease payments.

The only exceptions are short-term and low-value leases.The accounting for lessors will not significantly change.

The Group currently expects to adopt the modified retrospective approach with an adoption date 1 January 2019.

Under IFRS 16, the Group's leases will now be shown as right of use assets with related lease liabilities on the balance sheet.

To date, work has focused on the identification of those contracts which may be impacted most by the provisions of the standard, primarily the Group's operating leases. These include contracts over office tenancy, vessels, helicopters and production & storage facilities.

The Group estimates that on adoption of the new standard, there will be a material impact in relation to:

•

An increase in Other property, plant and equipment related to the right to use asset; and

•

An increase in Interest bearing liabilities relating to the lease liability.

The Group expects to adopt the modified retrospective approach to implementation, where the cumulative effect of initially applying this Standard is recognised as an adjustment to the opening balance of retained earnings at the date of implementation of the standard without adjustment of comparatives.

1 January 2019

Title		Nature of change		Impact			Mandatory application date

					The Group does not expect a material impact on adoption of the new standard on profit before tax. The Group does however expect a material impact in relation to the Statement of Financial Position, as well as classification in the Statement of Profit or Loss. The Group is still finalising its assessment of the effects of applying the new standard.

1b) Critical estimates and judgements

In the process of applying the Group's accounting policies, management has made a number of judgements and applied estimates of future events. Judgements and estimates which are material to the financial report are found in the following notes:


3e		Derivative financial assets and liabilities
5a		Oil and gas properties and corporate assets
5b		Exploration and evaluation
5c		Provisions
7d		Share-based payments reserve
8a/b		Taxation / deferred tax
8f		Joint arrangements and controlled permits

In applying the Group's accounting policies, management regularly evaluates judgements, estimates and assumptions based on experience and other factors, including expectations of future events that may have an impact on the Group. All judgements, estimates and assumptions made are believed to be reasonable based on the most current set of circumstances available to management. Actual results may differ from those judgements, estimates and assumptions.

1c) Acquisition accounting

Harriet Acquisition

On 15 June 2017 the Group acquired Kufpec's 19.28% interest in the Harriet Joint Venture, taking the Group's ownership to 100%. The Harriet Joint Venture owns significant infrastructure on Varanus Island as well as the remaining oil and gas operations in the Harriet field and related asset restoration obligations. This transaction enabled Quadrant to have full control over future uses of the infrastructure and the approach to rehabilitation.

Kufpec made a payment of US$9.9 million to Quadrant in full settlement of its obligations under the Joint Venture agreement and has ceased to be a party to the agreement.

The Group has applied its accounting policy for business combinations in accounting for this acquisition. This requires the Group to remeasure its previously held interest in the joint operation to its acquisition date fair value immediately prior to the business combination. This has given rise to a gain of US$192.4 million recognised in "Other Income" in the Consolidated Statement of Profit or Loss and Other Comprehensive Income (refer note 2d), based on level 3 measurements in the fair value hierarchy. The increase in the value of the previously held interest relates primarily to tolling agreements that have been negotiated for access to the infrastructure owned by the Harriet Joint Venture on Varanus Island.

i): Consideration transferred and value of previously held interest in acquiree

(stated in millions of US dollars)

Amount received from Kufpec (related to the 19.28% incremental interest)	(9.9	)
Value of pre-existing interest	(41.6	)

Total purchase consideration transferred and value of pre-existing interest	(51.5	)

ii): Details of net assets and liabilities acquired

The provisional fair value of the identifiable assets and liabilities acquired at acquisition date were;

(stated in millions of US dollars)

Cash and cash equivalents	11.4
Accounts receivable	0.5
Inventory	7.1
Property plant and equipment	472.8
Deferred tax assets (net)	33.8
Trade and other payables	(7.7	)
Contract liabilities	(8.1	)
Asset retirement obligations	(556.7	)
Other provisions	(4.6	)

Total identifiable liabilities	(51.5	)

The provisional fair value includes the re-measured valuation of the previously held interest in the joint operation. As such these valuations reflect the 100% equity interest in the Harriet Joint Venture and are aligned with the value implied by the consideration received from Kufpec for Quadrant to assume their 19.28% interest. Fair value measurements are classified as level 3 fair value measurements in the fair value hierarchy. There is additional analysis that may be required in finalising and confirming the fair values of assets and liabilities at acquisition date. As a result these values have only been provisionally determined in these financials statements.

Aside from gain of US$192.4 million recognised in "Other Income" the contribution to revenue and net profit of the additional interest in 2017 was not significant. Further had the acquisition occurred at the start of the period, given interim agreements in place, there would have been no significant impact on reported revenues or operating costs.

Apache Acquisition—2015

On 5 June 2015 QEPL acquired AEAL for total consideration (prior to closing adjustments and cash acquired) of US$2,100.0 million ("the Acquisition") from Apache Corporation ('The Vendors').

The Acquisition was funded through a mixture of equity contributions and borrowings. In addition at the date of the acquisition Quadrant entered into a new 12-year gas supply agreement which included a prepayment of US$500.0 million ("Gas prepayment").

Accounting standards require that all assets acquired and liabilities assumed in a business combination are measured at acquisition-date fair value, an exercise known as Purchase Price Allocation ("PPA").

The fair value of the identifiable assets acquired and liabilities assumed as at the acquisition date, based on the final PPA is outlined below:

(stated in millions of US dollars)		Fair values recognised on acquisition

Assets
Trade and other receivables			91.5
Inventories			56.2
Income tax receivable			28.8
Derivative financial assets			24.0
Contractual assets			63.0
Oil and gas properties			3,205.6
Other property, plant and equipment			17.4
Exploration and evaluation			80.6
Deferred Tax Asset			768.5

Total assets			4,335.6
Liabilities
Trade and other payables			322.5
Provisions			1,038.2
Contractual liabilities			498.7
Deferred tax liability			1,003.1

Total liabilities			2,862.5
Total identifiable net assets at fair value			1,473.1

Goodwill arising on acquisition			246.9

Net cash consideration			1,720.0

Cash acquired and closing adjustments			380.0

Total consideration			2,100.0

Fair value measurements are classified as level 3 fair value measurements in the fair value hierarchy.

The trade and other receivables acquired (which principally comprised trade receivables) in the transaction with a fair value of US$74.6 million had gross contractual amounts of US$74.6 million. The best estimate at acquisition date of the contractual cash flows not expected to be collected was nil.

The Group has not disclosed the impact of the acquisition on the consolidated results of the Group, as the group was effectively dormant until the acquisition of Apache Energy Australia Ltd on 5 June 2015, therefore that 2015 comparative figures in this report effectively represent six months and twenty five days of operations of the acquired business.

Acquisition costs have been accounted for as follows;

•: Costs of raising debt are initially recognised as an addition to the borrowing amount and subsequently measured based on the effective interest method;
•: Incremental costs that are directly attributable to the gas prepayment have been recognised as an intangible asset;
•: Incremental costs that are directly attributable to issuing new shares are deducted from equity (net of tax); and
•: All other costs related to the transactions expensed as incurred (classified within other expenses).

Recognition and measurement

The Group accounts for business combinations using the acquisition method. The consideration transferred in the acquisition is measured at fair value, as are the identifiable net assets acquired. Any goodwill that arises is tested annually for impairment. Transaction costs are expensed as incurred, except if related to the issue of debt or equity securities. When undertaking the acquisition certain contracts that were in place within the acquiree transferred to Quadrant Energy. Changes in market conditions resulted in the original terms of the contracts being unfavourable in comparison to market conditions present at the date of acquisition. The obligation for discounted future above-market payments are provided for, calculated using the discount rate determined at acquisition date. The discounted future above-market provision is released to earnings over the duration of the contract.

Goodwill

The amount of goodwill initially recognised as a result of a business combination reflects the excess of the fair value of the purchase consideration over the fair value of the identifiable assets acquired and the liabilities assumed. The determination of the fair value of the assets and liabilities is based, to a considerable extent, on management's judgement. The goodwill arose due to the measurement differences arising from deferred tax under the acquisition method of accounting for business combinations.

Refer to note 5a for the Group's policy in relation to the impairment testing of goodwill.

2—Operational Performance

2a) Segment reporting

The Company has identified its segments based on the internal reports that are reviewed and used by the senior leadership team in assessing performance and the allocation of resources. The operating segments are based on primary product type.

Each of the segment's assets are located in Australia and all revenue from segments is derived from operations based in Australia and are subject to the same economic environment.

The performance of each segment is evaluated based on revenue, costs of production and gross profit, measured in accordance with the Company's accounting policies, as well as capital expenditure. Other financial information including other income, other expenses, finance income, finance costs, taxation and statement of financial position items are reported and assessed at the consolidated Group level only, and as such are not included in the segment information below.

Segments are as follows:

•

Oil—Quadrant Energy's oil business participates in two operations located offshore in the Exmouth sub-basin and produces oil from multiple fields, connected back to FPSOs. Quadrant Energy's oil assets include:

•: Ningaloo Vision FSPO ("Ningaloo Vision"): an oil producing FPSO vessel operated by Quadrant Energy, stationed 60km north of Exmouth;
•: Pyrenees Venture FSPO ("Pyrenees"): an oil producing FPSO vessel operated by BHP, stationed 43km north of the Exmouth; and
•: Stag Platform ("Stag"): an oil producing platform, previously operated by Quadrant Energy. The asset was disposed of in 2016, refer to note 1a) for further information.

Sales from this segment are predominately sold onto the international market with revenue from one customer in 2017 contributing 11.9% of the Group's consolidated revenue (2016: one

customer contributing 20.3% of consolidated revenue and 2015: one customer contributing 29.6% of consolidated revenue).

•: Gas—Quadrant Energy's gas business is a major supplier of gas to the WA domestic market. Vertical integration and ownership of extensive existing infrastructure provides the Company with significant flexibility across its portfolio to utilise available capacity in the system.

Quadrant Energy's gas assets are connected to three separate processing hubs, which are operated as one integrated gas supply portfolio. The gas produced via these processing hubs is then distributed to Quadrant Energy's customers through WA's main gas pipelines. The three gas processing hubs are:

•: Varanus Island Processing Hub ("Varanus Island"): a gas processing hub operated by Quadrant Energy located 75km offshore, surrounded by a network of fixed production platforms and pipelines connecting into the Dampier to Bunbury Natural Gas Pipeline ("DBNGP") and the Goldfields Gas transmission ("GGT") pipeline;
•: Devil Creek Gas Processing Plant ("Devil Creek"): a gas processing hub located near Karratha. Gas from Devil Creek feeds directly into the DBNGP; and
•: Macedon Gas Plant ("Macedon"): a gas processing hub operated by BHP located at Onslow, 210km southwest of Dampier. Gas from Macedon feeds directly into the DBNGP.

The segment also generates tolling income through the use of its processing facility at Varanus Island.

Gas sales from this segment are predominately sold into the domestic market through long-term contracts with high quality industrial consumers. Revenue from one customer in 2017 contributed 17.7% of the Group's consolidated revenue (2016: one customer contributed 10.8% of consolidated revenue and 2015: no customers greater than 10.0%).

•: Corporate and other—includes general corporate activities, hedging activities and exploration expenditure not directly attributable to the Oil and Gas segments. Inter-segment eliminations are also included within the segment disclosure for reconciliation purposes.

The Group's equity interests in the above assets are disclosed in note 1a).

Year ended 31 December 2017 (stated in millions of US dollars)

Oil sales	228.3		—		—		228.3
Gas liquids and condensates sales	—		47.1		—		47.1
Gas sales	—		450.8		—		450.8
Tolling	—		18.5		—		18.5
Other revenue	—		14.8		—		14.8
Realised derivative gain—hedging	—		—		63.1		63.1

Segment revenue	228.3		531.2		63.1		822.6

Production costs	(63.4	)	(77.1	)	(0.1	)	(140.6	)
Entitlement adjustment	0.2		(1.4	)	—		(1.2	)
Inventory provision movements	(1.0	)	(3.4	)	(6.3	)	(10.7	)
Other operating costs	(4.2	)	(12.8	)	(1.1	)	(18.1	)
Depreciation & amortisation of oil and gas properties	(59.6	)	(206.2	)	—		(265.8	)

Segment result	100.3		230.3		55.6		386.2

Reconciliation to profit before tax:
Unwind of contractual assets and liabilities	—		—		34.7		34.7
Gain on pre-existing interest in Harriet Joint Venture	—		—		192.5		192.5
Other income	—		—		14.2		14.2
Exploration costs expensed	—		—		(12.2	)	(12.2	)
Other expenses	—		—		(56.4	)	(56.4	)
Finance income	—		—		3.3		3.3
Finance costs	—		—		(58.5	)	(58.5	)

Profit before tax	100.3		230.3		173.2		503.8

Capital expenditure^*
Exploration and evaluation	(1.8	)	(1.8	)	(36.9	)	(40.5	)
Oil and gas properties and other PPE	(7.7	)	(42.3	)	(17.4	)	(67.4	)

Total capital expenditure	(9.5	)	(44.1	)	(54.3	)	(107.9	)

*: This excludes expenditure incurred for restoration of US$23.4 million which is included in the internal reports that are reviewed and used by the senior leadership team.

Year ended 31 December 2016 (stated in millions of US dollars)

Oil sales	256.2		—		—		256.2
Gas liquids and condensates sales	—		35.4		—		35.4
Gas sales	—		350.8		—		350.8
Other revenue	—		1.7		—		1.7
Realised derivative gain—hedging	—		—		137.4		137.4

Segment revenue	256.2		387.9		137.4		781.5

Production costs	(64.2	)	(74.3	)	0.7		(137.8	)
Entitlement adjustment	0.9		(1.8	)	—		(0.9	)
Inventory provision movements	(1.1	)	(0.3	)	1.8		0.4
Other operating costs	(5.2	)	(10.7	)	(1.7	)	(17.6	)
Depreciation & amortisation of oil and gas properties	(121.9	)	(189.5	)	(0.1	)	(311.5	)

Segment result	64.7		111.3		138.1		314.1

Reconciliation to profit / (loss) before tax:
Unwind of contractual assets and liabilities	—		—		100.9		100.9
Net gain on disposal of non-current asset	—		—		29.8		29.8
Other income	—		—		25.8		25.8
Impairment of oil and gas properties	—		—		(95.4	)	(95.4	)
Exploration costs expensed	—		—		(65.6	)	(65.6	)
Other expenses	—		—		(71.2	)	(71.2	)
Finance income	—		—		4.4		4.4
Finance costs	—		—		(76.5	)	(76.5	)

Profit / (loss) before tax	64.7		111.3		(9.7	)	166.3

Capital expenditure^*
Exploration and evaluation	(3.2	)	(1.9	)	(234.8	)	(239.9	)
Oil and gas properties and other PPE	(48.1	)	(7.8	)	(3.6	)	(59.5	)

Total capital expenditure	(51.3	)	(9.7	)	(238.4	)	(299.4	)

*: This excludes expenditure incurred for restoration of US$69.4 million which is included in the internal reports that are reviewed and used by the senior leadership team.

Period ended 31 December 2015 (stated in millions of US dollars)

Oil sales	214.2		—		—		214.2
Gas liquids and condensates sales	—		17.2		—		17.2
Gas sales	—		192.2		—		192.2
Other revenue	—		6.7		—		6.7
Realised derivative gain—hedging	—		—		47.8		47.8

Segment revenue	214.2		216.1		47.8		478.1

Production costs	(44.2	)	(50.8	)	—		(95.0	)
Entitlement adjustment	3.7		1.1		—		4.8
Inventory provision movements	(2.3	)	(2.7	)	(1.0	)	(6.0	)
Other operating costs	(2.7	)	(6.4	)	(1.4	)	(10.5	)
Depreciation & amortisation of oil and gas properties	(102.5	)	(107.0	)	—		(209.5	)

Segment result	66.2		50.3		45.4		161.9

Reconciliation to profit / (loss) before tax:
Unwind of contractual assets and liabilities	—		—		66.2		66.2
Other income	—		—		16.2		16.2
Impairment of oil and gas properties	—		—		(88.3	)	(88.3	)
Exploration costs expensed	—		—		(90.0	)	(90.0	)
Other expenses	—		—		(80.2	)	(80.2	)
Finance income	—		—		0.6		0.6
Finance costs	—		—		(48.8	)	(48.8	)

Profit / (loss) before tax	66.2		50.3		(178.9	)	(62.4	)

Capital expenditure^*
Exploration and evaluation	—		(1.0	)	(79.1	)	(80.1	)
Oil and gas properties and other PPE	(83.4	)	(22.3	)	(8.2	)	(113.9	)

Total capital expenditure	(83.4	)	(23.3	)	(87.3	)	(194.0	)

*: This excludes expenditure incurred for restoration of US$18.7 million which is included in the internal reports that are reviewed and used by the senior leadership team.

2b) Revenue

(stated in millions of US dollars)

Oil sales	228.3	256.2	214.2
Gas liquids and condensates	47.1	35.4	17.2
Gas sales	450.8	350.8	192.2
Tolling income	18.5	—	—
Other revenue	14.8	1.7	6.7
Realised derivative gain—hedging	63.1	137.4	47.8

Total revenue	822.6	781.5	478.1

Recognition and measurement

Revenue is recognised when the significant risks and rewards of ownership have been transferred to the customer, recovery of the consideration is probable, the associated costs can be estimated reliably, there is no continuing management involvement with the goods, and the amount of revenue can be measured reliably. Revenue for the Group's main products are recognised as follows:

Oil, gas liquids and condensates—Crude oil and condensate sales are recognised for each joint arrangement based on Quadrant Energy's ownership percentage applied to sales made by participants to the joint arrangement (the entitlement method). Sales are recognised when the risk and rewards of ownership are transferred which depends on the terms which govern the sale. The majority of oil sales are Free On Board and revenue is therefore recognised on completion of the bill of lading.

Gas—Gas sales are recognised after production upon delivery to the contractually agreed point on the relevant pipeline. Revenue is recognised based on Quadrant Energy's ownership percentage applied to total sales made in to the joint arrangement.

Tolling—Tolling income relates primarily to gas processing tolls for third party gas processed through infrastructure owned by the Harriet Joint Venture on Varanus Island. This income is recognised based on the terms of the related tolling agreement which generally results in recognition as the gas is processed and services rendered.

Other revenue—Other revenue primarily relates to take or pay arrangements included within gas customer contracts. Revenue is recognised when the customer is no longer contractually able to exercise these rights under these contracts or where the likelihood of the customer exercising these rights becomes remote.

Realised derivative gain—Refer to note 3e for further details on accounting policies related to the Group's derivative financial assets and liabilities.

2c) Costs of sales

(stated in millions of US dollars)	Notes

Production costs		(138.1	)	(137.8	)	(95.0	)
Entitlement adjustment		(1.2	)	(0.9	)	4.8
Inventory provision movements	4c	(10.7	)	0.4		(6.0	)
Other operating costs		(20.6	)	(17.6	)	(10.5	)
Depreciation & amortisation	5a	(265.8	)	(311.5	)	(209.5	)

Total costs of sales		(436.4	)	(467.4	)	(316.2	)

Recognition and measurement

The point at which an expense is recognised is dependent on the nature of the transaction or other event that gives rise to the expense. Production costs and other operating costs are recognised on the same timing basis as the associated earning of specific items of income (refer to revenue and inventory policies).

Included in production costs are employee benefits directly related to production. Refer to note 5c for the Group's policy in relation to employee benefits.

Refer to section 5 for further details on accounting policies related to the Group's depreciation & amortisation charge and note 4c for the accounting policies related to the Group's inventory provision policy.

2d) Other Income

(stated in millions of US dollars)	Notes

Unwind of contractual assets and liabilities	5e	34.7	100.9	66.2
Net foreign currency gains		1.0	3.4	—
Other Income		13.3	22.4	16.2
Net gain on disposal of non-current asset		—	29.8	—
Gain on pre-existing interest in Harriet Joint Venture		192.4	—	—

Total other income		241.4	156.5	82.4

Gain on pre-existing interest in Harriet Joint Venture

The US$192.4 million gain in 2017 relates to the purchase of Kufpec's share in the Harriet Joint Venture, refer to note 1c for further details.

Net gain on disposal of non-current asset

The net gain on sale on disposals in 2016 relates to the disposal of the company's interest in the Stag oil field and the disposal of equity interests in exploration permits. Refer to note 1a for further information and note 8f for further information in relation to changes in equity interests.

2e) Other expenses

(stated in millions of US dollars)	Notes

Administrative and corporate expenses
Corporate costs		(20.2	)	(11.9	)	(15.3	)
Depreciation of corporate assets		(10.2	)	(11.9	)	(10.1	)
Share based payments		(0.7	)	(0.4	)	(0.2	)
Expensed changes in asset restoration obligation		—		(12.6	)	—
Fair value of product swaps		(9.2	)	(5.1	)	—
Movement in other provisions		(4.3	)	(10.1	)	—
Other expenses		(11.8	)	(19.2	)	(28.7	)
Other expense items
Fair value movement in embedded derivative	3e	—		—		(16.9	)
Net foreign currency losses		—		—		(9.0	)
Impairment of oil and gas properties	5a	—		(95.4	)	(88.3	)
Exploration costs expensed	5b	(12.2	)	(65.6	)	(90.0	)

		(68.6	)	(232.2	)	(258.5	)

Corporate costs

Corporate costs include corporate overheads and Quadrant specific corporate expenditure.

Other expenses

Other expenses primarily include costs related to rig stacking / subsidies (2016) and transition costs associated with the initial acquisition (2015).

Recognition and measurement

Impairment of oil and gas properties

Refer to note 5a for the Group's policy in relation to the impairment of oil and gas properties.

Exploration costs expensed

Refer to note 5b for the Group's policy in relation to exploration and evaluation expenditure.

Employee benefits

Included within Corporate costs are employee benefits associated with the Group's corporate function. Refer to note 5c for the Group's policy in relation to employee benefits.

Fair value of product swaps

Fair value of product swaps relate to expenses recognised in relation to gas swapped or received which is to be returned in the future. An expense is recognised as the gas is received, and income is recognised as the gas is returned.

3—Liquidity and Capital Management

3a) Cash and cash equivalents

(stated in millions of US dollars)

Cash at bank and on hand	93.0	66.5
Share of cash in joint operations*	53.0	39.4

	146.0	105.9

*: Share of cash in joint operations relates to cash held in joint operations which is held in secured bank accounts with restrictions around the ability to distribute linked to Joint Operating Agreements.

Recognition and measurement

Cash and short-term deposits in the consolidated statement of financial position comprise cash at bank and on hand, and short-term deposits (with an original maturity of three months or less) and are classified as financial assets held at amortised cost.

Cash at bank earns interest at floating rates based on daily bank deposit rates. Short-term deposits are made for varying periods of between one day and three months, depending on the immediate cash requirements of the Group, and earn interest at the respective short-term deposit rates.

For the purposes of the consolidated statement of cash flows, cash and cash equivalents consists of cash and cash equivalents as described above, net of outstanding bank overdrafts.

3b) Cash flow statement reconciliation

(stated in millions of US dollars)	Notes

Cash flows from operating activities
Profit / (loss) after tax		341.9		85.8		(49.3	)
Adjustments to reconcile profit after tax to operating net cash flows:
Depreciation & amortisation		276.0		323.4		211.2
Impairment of oil and gas properties	5a	—		95.4		88.3
Exploration costs expensed	5b	12.2		65.6		90.0
Unwind of contractual assets and liabilities	5e	(34.7	)	(100.9	)	(66.2	)
Finance costs	3d	58.5		76.5		48.0
Tax expense / (benefit)	8a	161.9		80.5		(13.1	)
Realised derivative gain—hedging	2b	(63.1	)	(137.4	)	(47.8	)
Gain on pre-existing interest in Harriet Joint Venture	2d	(192.4	)	—		—
Net foreign currency (gains) / losses	2d	(1.0	)	(3.4	)	9.0
Other non-cash items		5.0		(37.6	)	21.8
Changes in assets and liabilities
Decrease / (increase) in trade and other receivables		6.3		(14.1	)	(24.1	)
Decrease / (increase) in trade and other payables		23.0		(33.0	)	(25.5	)
Decrease / (increase) in inventories		7.4		(1.9	)	2.0
(Decrease) / increase in deferred revenue		(8.5	)	43.5		521.6
(Decrease) / increase in other assets and liabilities		(41.6	)	17.5		(28.8	)

		550.9		459.9		737.1

Interest paid		(21.9	)	(26.3	)	(19.1	)
Income tax received / (paid)		15.9		29.9		(15.0	)
PRRT paid		(60.6	)	(19.0	)	(7.1	)
Proceeds on settlement of derivatives		67.3		143.7		37.9

Net cash flows from operating activities		551.6		588.2		733.8

3c) Interest bearing loans

(stated in millions of US dollars)

Current
Interest-bearing loans—External banks	170.8	242.0
Non-current
Interest-bearing loans—External banks	361.1	282.3
Interest-bearing loans—Shareholders	—	341.4

	361.1	623.7

Movement in the period

(stated in millions of US dollars)

Opening balance 1 January 2017	524.3		341.4		865.7
Cash movements
Loan drawdown	250.0		—		250.0
Principal repayments	(245.6	)	(341.0	)	(586.6	)
Interest payments	(19.9	)	(5.3	)	(25.2	)
Working capital facility drawdown	52.0		—		52.0
Working capital facility repayment	(52.0	)	—		(52.0	)
Non cash movements
Transaction costs capitalised	(1.9	)	—		(1.9	)
Interest expense	25.0		4.9		29.9

Closing balance 31 December 2017	531.9		—		531.9

Opening balance 1 January 2016	731.2		444.2		1,175.4
Cash movements
Principal repayments	(217.1	)	(102.9	)	(320.0	)
Interest payments	(16.7	)	(15.2	)	(31.9	)
Non cash movements
Interest expense	26.9		15.3		42.2

Closing balance 31 December 2016	524.3		341.4		865.7

Group facility summary

Terms		Facility details

• Facility		• Interest-bearing loans—external banks
• Currency		• United States Dollar (US$)
• Limit		• US$534.3 million (2016: US$530.0 million)
• Drawn principal		• US$534.3 million (2016: US$530.0 million)
• Interest rate		• Weighted average of 2.00% plus Libor (2016: Weighted average of 1.93% plus Libor)
• Repayments / maturity		• Quarterly repayment to 2021
• Security		• Secured by a floating charge over all the Group's assets
• Other		• The syndicated loan comprises 3 tranches (2016: 2 tranches)
		• The syndicate comprises large domestic and international banks, providing a diversified lending source for the Group
		• The facility expires December 2021 (2016: March 2020)

Terms

Facility details

•

Facility

•

Working capital facility—external banks

•

Currency

•

United States Dollar (US$)

•

Limit

•

US$125.0 million (2016: US$125.0 million)

•

Drawn principal

•

Nil (2016: Nil)

•

Interest rate

•

2.00% plus Libor

•

Repayments / maturity

•

2021

•

Security

•

Secured by a floating charge over all the Group's assets.

•

Other

•

The syndicate comprises large domestic and international banks, providing a diversified lending source for the Group.

The shareholder loan facility was fully repaid during the year ended 31 December 2017.

The external bank loans were fully repaid subsequent to the end of the reporting period. Refer to note 6c for futher information.

Assets pledged as security

The external bank loans are secured by a floating charge over all the Group's assets. There is also security in place related to prepayments relating to deferred revenue (refer note 5d).

Compliance with debt covenants

Under the terms of the borrowing facilities, the Group is required to comply with the financial covenants related to backward debt service coverage ratio, gearing ratio and senior leverage ratio. The Group was in compliance with the financial covenants of its borrowing facilities during the 2017, 2016 and the 2015 periods.

Recognition and measurement

Borrowings are initially recognised at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortised cost. Any difference between the proceeds received (net of transaction costs) and the redemption amount is recognised in profit or loss over the period of the borrowings using the effective interest method.

Borrowings are removed from the consolidated statement of financial position when the obligation specified in the contract is discharged, cancelled or expired. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least twelve months after the reporting period.

3d) Finance income and expenses

(stated in millions of US dollars)

Finance Income
Interest income	3.3		4.4		0.6
Finance costs
Interest expense—Shareholder loans	(4.9	)	(15.3	)	(10.5	)
Interest expense—External banks	(25.0	)	(26.9	)	(18.0	)
Accretion expense	(26.4	)	(30.7	)	(18.5	)
Interest rate swap expense	(0.8	)	(2.2	)	(1.0	)
Other finance costs	(1.4	)	(1.4	)	(0.8	)

	(58.5	)	(76.5	)	(48.8	)

Recognition and measurement

Finance costs are recognised as an expense when they are incurred.

Provisions and other payables are discounted to their present value when the effect of the time value of money is significant. The impact of the unwinding of these discounts and any changes to the discounting is shown as an accretion expense within finance costs.

Borrowing costs related to qualifying assets under development are capitalised as a component of the cost of development. Borrowing costs are capitalised based on the weighted average cost of borrowings. The Group suspends capitalisation of borrowing costs in relation to qualifying assets where there is no active development. There were no borrowing costs capitalised by the Group during 2017 (2016: Nil and 2015: Nil).

3e) Derivative financial assets and liabilities

The Group is exposed to various risks including those arising from movements in oil pricing, interest rates and foreign exchange. As part of the risk management strategy the Group holds the following types of derivative instruments:

•: Interest rate swaps: to optimise the Group's exposure to fixed and floating interest rates arising from borrowings;
•: Oil swaps: to reduce the Group's exposure to oil price fluctuations; and
•: Foreign exchange forward contracts; to reduce the Group's exposure to fluctuations in foreign currency.

The fair value measurement of all derivative financial instruments held at 31 December 2017, and in the comparative period, are classified as level 2 fair value measurements in the fair value hierarchy and there has been no transfers between levels. All derivative financial instruments have a designated hedging relationship.

(stated in millions of US dollars unless otherwise noted)		Weighted average

2017
Interest rate swaps	267.2		3.64% fixed	1.7	—
Oil swaps	163.0	$	63 per Bbl	—	2.4
Foreign exchange forward contracts	38.3	$	1.31 AUD	0.7	—

				2.4	2.4
2016
Interest rate swaps	265.0		3.26% fixed	0.2	—
Oil swaps	318.2	$	72 per Bbl	59.6	—
Foreign exchange forward contracts	74.4	$	1.34 AUD	—	2.5

				59.8	2.5

Realised gains / (losses) on interest rate swaps are treated as finance income / expenses and disclosed in note 3d. Realised gains / (losses) on oil swaps are treated as revenue and disclosed in note 2b.

(stated in millions of US dollars)

Current—Cash flow hedge
Derivative financial assets	5.6		47.3
Derivative financial liabilities	(5.9	)	(3.0	)
Non-Current—Cash flow hedge
Derivative financial assets	0.3		13.0
Derivative financial liabilities	—		—

Net derivative financial assets / (liabilities)	—		57.3

Movement in the period (stated in millions of US dollars)

Opening balance	57.3		253.9
Settlement of derivative financial instruments	(62.3	)	(135.3	)
Net movement recognised in other comprehensive income	5.0		(61.3	)

Closing balance	—		57.3

Recognition and measurement

Valuation techniques used to determine fair values

Specific valuation techniques used to value financial instruments include:

•: the use of quoted market prices or dealer quotes for similar instruments
•: the fair value of interest rate swaps is calculated as the present value of the estimated future cash flows based on observable yield curves
•: the fair value of forward foreign exchange contracts is determined using forward exchange rates at the balance sheet date
•: the fair value of oil swap contracts is calculated as the present value of the estimated future cash flows based on observable forward curves

All of the resulting fair value estimates are included in level 2 in the fair value hierarchy.

Derivatives

Derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured to their fair values in line with market fluctuations. The method of recognising any measurement gain or loss depends on the nature of the hedge.

Hedge accounting

For the purposes of hedge accounting, hedges are classified as either; fair value hedges where they hedge the exposure to changes in the fair value of a recognised asset or liability; cash flow hedges where they hedge exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability or a highly probable forecasted transaction.

At the beginning of a hedge relationship, the Group designates and documents the hedge relationship and the related risk management objective and strategy. The documentation identifies the hedging instrument and the hedged item as well as describing the economic relationship, and potential sources of ineffectiveness. The documentation also includes the nature of the risk being hedged and the method of assessing the hedging instrument's effectiveness. To achieve hedge accounting, the relationships must be expected to be highly effective and are assessed on an ongoing basis to determine that they continue to meet the risk management objective.

Hedge accounting is discontinued when the hedge instrument expires or is sold, terminated or exercised, or no longer qualifies for hedge accounting. At that point in time, any cumulative gain or loss on the hedging instrument recognised in equity remains in equity until the forecasted transaction occurs. If a hedged transaction is no longer expected to occur, the net cumulative gain or loss recognised in equity is transferred to profit or loss for the year.

Cash flow hedges

In relation to cash flow hedges to hedge firm commitments or highly probable forecast transactions, the portion of the gain or loss on the hedging instrument that is determined to be an effective hedge is recognised directly in equity and the ineffective portion is recognised in the statement of profit or loss and other comprehensive income.

When the hedged item gives rise to the recognition of an asset or a liability, the associated deferred gains or losses are included in the initial measurement of the asset or liability.

For all other cash flow hedges, the gains or losses that are recognised in equity are transferred to the statement of profit or loss and other comprehensive income in the same period in which the hedged item affects the profit and loss, for example when the future sale actually occurs.

Offsetting financial instruments

The Group presents its derivative assets and liabilities on a gross basis. Derivative financial instrument entered into by the Group are subject to enforceable master netting arrangements, such as the International Swaps and Derivatives Associations (ISDA) master netting agreement. In certain circumstances, for example, when a credit event such as a default occurs, all outstanding transactions under an ISDA agreement are terminated, the termination value is assessed and only a single net amount is payable in settlement of all transactions.

Embedded derivatives

The Group previously recognised an embedded derivative in relation to an unrelated commodity price link within a sales contract. The fair value of the embedded derivative is classified as level 2 in the fair value hierarchy. A reasonable increase / decrease in the commodity would not have materially impacted the fair value of the derivative at 31 December 2017, 31 December 2016 and 31 December 2015. The carrying value of the embedded derivative at 31 December 2017 was nil (2016: nil). The reduction in carrying value of the embedded derivative recognised upon acquisition was expensed in the period ended 31 December 2015. Refer to note 2e.

3f) Financial risk management

Overall financial risk management

Financial risk exposures arise in the course of the Group's operating activities primarily due to the impact of changes in commodity prices, foreign exchange (FX) rates and interest rates. The overall financial risk management strategy is to safeguard the Group's ability to fund ongoing operations and growth plans and meet stakeholder obligations.

The Group utilises financial modelling to assess the sensitivity and impact of changes in financial conditions.

Derivative financial instruments may be used to hedge exposures. These are managed within the framework of the Group's Board approved Treasury Policy.

The key financial risks to which the Group is exposed are explained further in the following sections:

•: Liquidity and funding risk
•: Interest rate risk
•: Foreign exchange risk
•: Commodity price risk
•: Credit risk

Liquidity and funding risk

Nature of the risk

Liquidity risk is the risk that the Group does not have sufficient funds available to meet its financial obligations as they fall due. The Group is exposed to liquidity risk through its liabilities, offset by its available cash and cash equivalents, net cash provided by operating activities, proceeds from divesture and proceeds from financing activities (primarily borrowings as described in note 3c).

The Group focuses on maintaining a strong liquidity position to ensure financial flexibility and to withstand changing financial and economic conditions.

Risk management

The Group centrally manages liquidity to ensure available surplus cash together with committed undrawn lines of credit for operations, business opportunities and unanticipated cash outflows, and regularly updates operating cash flow forecasts and availability of undrawn debt facilities as part of its liquidity management process.

The Group has a syndicated long term committed external debt facility, including working capital and guarantee facilities, which it utilises to execute its operating strategies. The syndicate comprises large domestic and international banks, providing a diversified lending source for the Group.

The Group seeks to ensure maturities of committed debt facilities are spread over time to minimise the Group's exposure to risk on the cost or availability of funds should the refinancing requirement coincide with unexpected short-term disruption or adverse fundraising conditions in the capital markets.

As at 31 December 2017, the Group has cash* of US$146.0 million (2016: US$105.9 million) and undrawn loan facilities of US$125.0 million (2016: US$125.0 million).

Level of exposure at balance date

The following tables analyse the maturities of the Group's contractual undiscounted cash flows arising from its material financial liabilities, net and gross settled derivative financial instruments.

*: Included within cash is the Group's share of cash in joint operations which is held in secured bank accounts with restrictions around the ability to distribute. Refer to note 3a) for further information.

Liquidity and funding risk

	Maturing in:

(stated in millions of US dollars)	Less than 1 year			1 to 2 Years			2 to 5 years			Over 5 years		Contractual Total			Carrying amount
2017
Non-derivative financial liabilities
External bank loans		191.3			108.8			278.8			—		578.9			531.9
Shareholder loans		—			—			—			—		—			—
Trade and other creditors		57.3			—			—			—		57.3			57.3

		248.6			108.8			278.8			—		636.2			589.2
Derivative financial liabilities/(assets)
Hedged interest rate swaps (net settled)		(0.2	)		(1.6	)							(1.8	)		(1.7	)
Hedged foreign exchange contracts (gross settled):
inflow		38.3			—			—			—		38.3
outflow		(39.0	)		—			—			—		(39.0	)		(0.7	)
Hedged oil swaps (net settled)		1.3			1.2			—			—		2.5			2.4

		0.4			(0.4	)		—			—		—			—
2016
Non-derivative financial liabilities
External bank loans		261.0			171.9			112.4			—		545.3			524.3
Shareholder loans		—			—			—			432.5		432.5			341.4
Trade and other creditors		94.6			—			—			—		94.6			94.6

		355.6			171.9			112.4			432.5		1,072.4			960.3
Derivative financial liabilities / (assets)
Hedged interest rate swaps (net settled)		0.5			(0.4	)		(0.3	)		—		(0.2	)		(0.2	)
Hedged foreign exchange contracts (gross settled):
Inflow		74.5			—			—			—		74.5
Outflow		(72.0	)		—			—			—		(72.0	)		2.5
Hedged oil swaps (net settled)		(49.8	)		(10.1	)		—			—		(59.9	)		(59.6	)

		(46.8	)		(10.5	)		(0.3	)		—		(57.6	)		(57.3	)

Available facilities

(stated in millions of US dollars)

Credit facilities
Total credit facilities	659.3	655.0
Used	534.3	530.0

Available facilities	125.0	125.0

Cash and cash equivalents	146.0	105.9

Total Liquidity	271.0	230.9

Facilities used represents the principal value of borrowings drawn against the relevant facilities. This amount differs by US$2.4 million (2016: US$5.7 million) from borrowings as shown in the consolidated statement of financial position which are measured on the basis of amortised cost as

determined under the effective interest method and include accrued interest and unamortised transaction costs.

Used facilities are payable in line with the exposure at balance date maturities disclosed in the table above and available facilities expire in 2021.

Interest rate risk

Nature of the risk

Interest rate risk is the risk that fluctuations in interest rates will impact the Group's results. Debt funding plays a key role in Quadrant Energy's overall funding strategy and provides a flexible and cost-effective way to fund the Group's operations and its investments in fixed assets. Borrowings at variable interest rates expose the Group to cash flow interest rate risk and derivatives may be used to hedge the exposure.

The Group is principally exposed to changes in the Libor rate.

Risk management

Quadrant Energy's policy is to limit exposure to interest rate risk which could erode the profitability of the Group. In order to mitigate interest rate risk the Group looks to achieve a target proportion of fixed debt through borrowing at fixed rates, or at variable rates and entering into financial derivatives. The Group uses interest rate swaps to fix interest rates on a specified notional amount of outstanding debt exposed to variable interest rates.

Level of exposure at balance date

At balance date, the Group had the following mix of financial assets and liabilities with exposure to interest rate risk;

Refer also to Note 3e for information on derivatives.

Interest rate risk

(stated in millions of US dollars unless otherwise noted)

Financial assets—floating rate
Cash and cash equivalents	146.0		1.56%	105.9		1.10%	237.9		0.10%
Financial liabilities—floating rate
Interest-bearing loans—external banks	534.3		3.33%	530.0		2.76%	747.1		2.19%
Less: interest rate swaps notional amount	(267.2	)	3.64%	(265.0	)	3.24%	(373.5	)	3.17%

	267.1			265.0			373.6

Sensitivity to changes in interest rates

	Pre-tax impact on profit									Pre-tax impact on OCI

(stated in millions of US dollars)	2017			2016			2015			2017			2016			2015
Interest rates—increase by 50 basis points		(0.6	)		(0.8	)		(0.7	)		2.7			1.5			3.0
Interest rates—decrease by 50 basis points		0.6			0.8			0.7			(2.8	)		(1.5	)		(2.9	)

Foreign exchange risk

Nature of the risk

Foreign exchange risk is the risk that fluctuations in exchange rates will impact on the Group's results. The Group's primary currency exposures are to AUD$ as the Group has significant revenues and expenses in AUD$. Quadrant Energy has a AUD$ exposure primarily from:

•: Administrative and business development expenditures incurred at the corporate level in AUD$;
•: Operating, capital and restoration expenditures incurred by the Group in relation to its operations in AUD$; and
•: Petroleum resource rent tax payments in AUD$

The Group is exposed to foreign exchange risk on financial assets and liabilities denominated in AUD$ as disclosed in the level of exposure section below. The Group has no other material ongoing currency exposures.

Risk management

Foreign exchange risk may be managed through the use of derivative instruments in accordance with Quadrant Energy's Treasury Policy. Significant capital expenditure or project based foreign exchange risk are managed on a case-by-case basis.

At 31 December 2017, the Group has designated Foreign Exchange Forward Contracts in place to mitigate its risk arising from movements in AUD$ denominated expenditure.

The Group's hedging strategy in response to foreign exchange risk is further detailed in note 3e.

Level of exposure at balance date

At balance date, the Group had the following financial assets and financial liabilities denominated in AUD$:

(stated in millions of US dollars)

Financial assets
Cash and cash equivalents	50.0	56.8
Trade and other debtors	18.1	17.0

Total assets	68.1	73.8

Financial liabilities
Trade payables	57.7	65.2

Sensitivity to changes in exchange rates

At 31 December 2017 a +/- 10% strengthening/weakening of the US dollar against the Australian Dollar would have resulted in a +/- US$1.0 million (2016: +/- US$1.4 million and 2015: +/- US$1.7million) impact on pre-tax profit, and a +/- US$3.9 million (2016: +/- US$7.2 million and 2015: +/- Nil) impact on pre-tax equity.

Commodity price risk

Nature of the risk

Quadrant Energy has exposure to commodity price risk associated with the production and sale of oil, condensate and other oil linked gas contracts.

The Group has limited exposure in the short term to commodity price risk in relation to natural gas, with the majority of the Group's sales during the period under medium to long term gas contracts.

Risk management

Quadrant Energy may enter into a hedging program using derivatives to manage its exposure to commodity price risk. Any derivatives entered into are in compliance with the Group's Treasury Policy, within approved limits and utilising approved instruments. The aim of hedging is to reduce fluctuations in the Group's revenue and to ensure its financial position remains sound.

Hedging programs are determined through detailed modelling of the Group's position under various oil price scenarios. The Group continually monitors oil prices and assesses whether commodity price hedging is warranted.

Level of exposure at balance date

At balance date, Quadrant's exposure arose from its oil price derivatives, which had a notional amount of 2.6 million barrels of oil equivalent (boe) (2016: 4.4 million boe and 2015: 10.2 million boe).

	Pre-tax impact on profit

							Pre-tax impact on OCI
Sensitivity to changes in commodity price (stated in millions of US dollars)							Pre-tax impact on OCI
	2017		2016		2015		2017			2016			2015
Oil price—increase by US$10/boe		—		—		—		(25.5	)		(44.0	)		(101.1	)
Oil price—decrease by US$10/boe		—		—		—		25.5			44.0			101.1

Credit risk

Nature of the risk

Credit Risk is the risk that a counterparty will not fulfil its financial obligations under a contract or other arrangement. Counterparty credit risk arises on the following assets:

•: Cash and cash equivalents;
•: Derivative financial instruments; and
•: Trade and other receivables.

Risk management

Credit limits have been established for financial transactions. Limits are based on the counterparties' credit rating as issued by Standard and Poor's and Moody's.

Gas sales are predominantly through long term contracts and the Group may seek security through parent company guarantees or letter of credit instruments issued by investment grade banks. Oil and Condensate sales are generally sold on shorter term contracts. The Group's maximum credit risk is limited to the carrying amount of its financial assets.

Level of exposure at balance date

Cash and financial assets: There is US$146.0 million (2016: US$105.9 million) of cash invested with a number of reputable financial institutions, which is available at call, and US$5.9 million (2016: US$60.3 million) of assets related to derivative financial instruments, with exposure limited to these amounts.

Trade and other receivables: Trade and other debtors total US$98.2 million (2016: US$105.4 million). The Group's exposure to credit risk with a single party is not significant and there are no

indications as of the reporting date that the debtors will not meet their payment obligations. The default rates have historically been low.

4—Working Capital

4a) Trade and other receivables

(stated in millions of US dollars)

Current
Trade debtors	60.6	74.3
Other debtors	37.6	31.1

	98.2	105.4

Non-current
Other debtors	1.3	3.7

Recognition and measurement

Trade receivables generally have terms of up to 30 days. They are recognised initially at fair value and subsequently at amortised cost using the effective interest method, less an allowance for impairment. Customers who wish to trade on credit terms are subject to credit verification procedures. Receivable balances are monitored on an ongoing basis and the Group's exposure to bad debts is not significant. With respect to trade receivables that are neither impaired nor past due, there are no indications as of the reporting date that the debtors will not meet their payment obligations.

Fair value

Due to the short term nature for the majority of trade receivables and other debtors, their carrying amount is considered to be the same as their fair value.

4b) Trade and other payables

(stated in millions of US dollars)

Current
Trade creditors	3.8	22.8
Accruals and other payables	53.5	71.7

	57.3	94.5

Non-current
Accruals and other payables	13.4	5.0

Recognition and measurement

Trade and other payables are recognised when the related goods or services have been received at the amount of cash or cash equivalents that will be required to discharge the obligation.

Fair value

The carrying amounts of current trade and other payables are considered to be the same as their fair value.

4c) Inventories

(stated in millions of US dollars)

Materials and supplies (net of provisions)	35.0	45.1
Petroleum products	12.4	11.0

	47.4	56.1

Write downs of inventories to net realisable value during the year amounted to US$10.7 million (2016: US$(0.4) million and 2015: US$6.0 million). The carrying amount of inventories carried at net realisable value amounted to US$12.7 million (2016: US$6.4 million). Write downs related solely to materials and supplies and arose principally on spare parts held in excess of expected needs. Such items were provided for, given the unlikelihood of their sale or use. These expenses were included in cost of production (refer 2c).

Recognition and measurement

Inventories are valued at the lower of cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business, less estimated selling costs. Cost is determined as follows:

•: Materials, which include drilling and maintenance stocks, are valued at the cost of acquisition on an average cost basis. Materials and supplies are disclosed net of provisions. A provision is recognised when materials are not expected to be used in production to reduce their carrying value to the amount of any expected sale proceeds; and
•: Petroleum products, comprising primarily extracted crude oil and condensate stored in tanks, pipeline systems and aboard vessels are valued using the weighted average cost of production method. A provision is recognised when the carrying value of the inventory exceeds its expected selling price less costs to complete and sell the inventory.

5—Non Financial Assets and Liabilities

5a) Oil and gas properties ("OGP") and corporate assets

Oil and gas properties

Quadrant Energy has an extensive portfolio of producing assets. Details in relation to key portfolios of assets have been included in section 1a.

(stated in millions of US dollars)

Gross carrying amount—at cost
Balance at 1 January 2017	45.2		616.3		2,080.9		244.2		312.2		3,298.8
Additions	0.1		13.6		2.4		1.1		32.8		50.0
Impact of a business combination*	20.3		325.0		—		—		—		345.3
Changes in restoration obligations	—		13.2		28.7		—		—		41.9
Disposals at written down value	—		(2.1	)	—		—		—		(2.1	)
Transfers	—		—		249.4		—		(249.4	)	—

Balance at 31 December 2017	65.6		966.0		2,361.4		245.3		95.6		3,733.9
Accumulated depreciation, amortisation & impairment
Balance at 1 January 2017	(6.5	)	(88.9	)	(574.9	)	(33.5	)	—		(703.8	)
Depreciation & amortisation	(4.3	)	(62.9	)	(178.0	)	(20.6	)	—		(265.8	)
Impact of a business combination*	0.7		13.2		8.0		—		—		21.9
Disposals at written down value	—		0.1		—		—		—		0.1

Balance at 31 December 2017	(10.1	)	(138.5	)	(744.9	)	(54.1	)	—		(947.6	)

Net carrying amount at 31 December 2017	55.5		827.5		1,616.5		191.2		95.6		2,786.3

Gross carrying amount—at cost
Balance at 1 January 2016	45.2		634.1		2,059.2		244.2		314.9		3,297.6
Additions	—		0.2		54.8		—		0.9		55.9
Changes in restoration obligations	—		(18.0	)	(32.0	)	—		—		(50.0	)
Disposals at written down value	—		—		(4.4	)	—		(0.3	)	(4.7	)
Transfers	—		—		3.3		—		(3.3	)	—

Balance at 31 December 2016	45.2		616.3		2,080.9		244.2		312.2		3,298.8
Accumulated depreciation, amortisation & impairment
Balance at 1 January 2016	(2.4	)	(33.9	)	(248.3	)	(13.2	)	—		(297.8	)
Depreciation & amortisation	(4.1	)	(55.0	)	(232.1	)	(20.3	)	—		(311.5	)
Impairment loss	—		—		(95.4	)	—		—		(95.4	)
Disposals at written down value	—		—		0.9		—		—		0.9

Balance at 31 December 2016	(6.5	)	(88.9	)	(574.9	)	(33.5	)	—		(703.8	)

Net carrying amount at 31 December 2016	38.7		527.4		1,506.0		210.7		312.2		2,595.0

*: Refer to note 1c for further details on the Harriet Acquisition.

Refer to note 3c for the Group's encumbrances over its oil and gas properties ("OGP")

Recognition and measurement

Developing assets

When the technical and commercial feasibility of an undeveloped oil or gas field has been demonstrated and approval of commercial development occurs, the field enters its development phase. The costs of oil and gas assets in development are separately accounted for and include past exploration and evaluation costs, development drilling and other subsurface expenditure, surface plant and equipment and any associated land and buildings. When the committed development expenditure programmes are completed and production commences assets are transferred to producing assets, and subject to DD&A.

Producing assets

Cost

Producing assets are carried at cost less accumulated depreciation and impairment.

The costs of oil and gas assets in production include past exploration and evaluation costs, past development costs and the ongoing costs of continuing to develop reserves for production and to expand, replace or improve plant and equipment and any associated land and buildings. These costs are subject to depreciation and amortisation. Any gain or loss on the disposal of assets is determined as the difference between the carrying value of the asset at the time of disposal and the proceeds from disposal, and is included in the results of the Group in the year of disposal.

Restoration expenditure

Site restoration costs are capitalised within the cost of the associated assets and the provision is stated in the consolidated statement of financial position at total estimated present value. These costs are based on judgements and assumptions regarding removal dates, technologies, and industry practice. The costs of restoration are brought to account in the statement of comprehensive income through depreciation of the associated assets over the economic life of the projects with which these costs are associated. Over time, the liability is increased for the change in the present value based on a risk adjusted pre-tax discount rate appropriate to the risks inherent in the liability. The unwinding of the discount is recorded as an accretion charge within finance costs. Cost estimates and timing in relation site restoration costs are updated throughout the life of operating assets, with the provision for restoration costs adjusted to reflect such changes. Increases and decreases in the asset retirement obligation are adjusted against the carrying value of the producing asset.

DD&A

Dependent on the nature of the related asset DD&A is calculated either on a straight line basis based on the expected life of the related asset, or using the units of production method for an asset or group of assets from the date of commencement of production. Depletion charges are calculated using the units of production method over the life of the estimated developed and undeveloped, Proven plus Probable ('2P') reserves for an asset or group of assets with an adjustment for the cost of accessing undeveloped 2P reserves. Producing assets depreciated on a straight line basis have an estimated useful life ranging from approximately 5 to 20 years (2016: 5 to 20 years and 2015: 5 to 20 years).

Depreciation on plant and equipment is calculated on a straight-line basis so as to generally write-off the cost of each fixed asset over its estimated useful life on the following basis;

Category	Method	Estimated Useful Life

Buildings	Straight-line over useful life	10 - 20 Years
Plant and equipment	Straight-line over the shorter of useful life or term of lease	5 - 20 Years
Offshore production assets	Units of production over proved and probable, developed and undeveloped reserves	7 - 20 Years
Marine vessels	Straight-line over the useful life	8 - 16 Years

Key judgements

Reserve estimates

The Developed and Undeveloped Proven plus Probable ('2P') Reserve estimates are management assessment's and take into consideration reviews by an independent third party, under the Company's reserves audit programme, as well as other assumptions, interpretations and assessments.

These include assumptions regarding commodity prices, exchange rates, discount rates, future production and transportation costs, and interpretations of geological and geophysical models to make assessments of the quality of reservoirs and their anticipated recoveries. Changes in reported reserves can impact asset carrying values, the provision for restoration and the recognition of deferred tax assets, due to changes in expected future cash flows. Reserves are integral to the amount of depreciation, depletion and amortisation ("DD&A") charged to the consolidated statement of comprehensive income and the calculation of inventory.

Impairment of non-current assets

No impairment or impairment reversals have been recognised for the year ended 31 December 2017.

Methodology

The Group assesses oil and gas assets for indicators of impairment at each reporting date. Where an indicator of impairment exists, a formal assessment of the asset or cash generating units (CGU) recoverable amount takes place. Assets are assessed for impairment on a CGU basis where the CGUs are determined on a project by project basis, comprising the lowest level of grouping of assets which produce independent cash flows.

Impairment is recognised where the recoverable amount is less than the carrying amount of the CGU and subsequently an impairment charge is recognised in profit or loss, reducing the carrying value of the CGU down to its recoverable amount by allocating the charge to any goodwill first and then to the other assets within the CGU on a pro rata basis.

Each CGU which has associated goodwill is reviewed for impairment annually, or more frequently if events or changes in circumstances indicate that that the carrying value may be impaired. Goodwill is impaired to the extent the recoverable amount of the segment is less than the carrying amount of the segment. Goodwill is not amortised.

The recoverable value of a CGU is the greater of its fair value less costs of disposal (FVLCOD) and value-in-use (VIU). For Quadrant, both approaches utilise a discounted cash flow, using the CGU's

estimated post-tax cash flows reduced to present value using post-tax discount rates to reflect the time value of money. The expected future cash flow estimation is based on reserves, future production profiles, foreign exchange rates, commodity prices and costs. The FVLCOD approach includes the costs and benefits of undeveloped reserves, market assumptions on future foreign exchange rates in addition to an estimate of the cost to dispose of the asset. The Group considers this valuation approach to be consistent with the approach taken by market participants.

Key assumptions

Significant judgement is required in making estimates of the recoverable value for assets, in particular those with a long life. The determination of recoverable value also includes key assumptions, including, but not limited to commodity prices, currency exchange rates and discount rates, set out in the table below.

	2017			2016			2015

	2018 - 2020	Long-term (2021+)		2017 - 2019	Long-term (2020+)		2016 - 2020	Long Term (2020+)
Oil Price ($US/bbl—Real)	$60	$	60	$60 - 70	$	70	$45 - 73	$	80
AUD: USD Exchange Rate	0.77		0.77	0.78 - 0.70		0.70	0.73 - 0.70		0.68
Nominal post-tax discount rate	8.5%			8.5%			8.5%

Determination of assumptions

Commodity prices and exchange rates

Commodity prices and forecasts in relation to exchange rates are updated at each reporting date, giving consideration to available short term spot and forward values. Longer term assumptions in relation to commodity pricing and exchange rates are determined based on market analysis inclusive of external broker outlooks. Prices from 2020 are escalated at 2%.

From a gas pricing perspective the Western Australian gas market is dominated by a small number of high volume gas buyers. The Group's significant gas customers are contracted with medium and long-term GSAs in place. These contracts and long-term customer partnerships form an important part of Quadrant Energy's gas business.

Gas pricing assumptions are based on contractually agreed prices with consideration to other relevant market data. The Group has limited exposure to commodity pricing risk in the short to medium term, with the majority of the Group's sales under medium to long term gas supply agreements. Price assumptions applied for uncontracted gas is validated against externally prepared market research.

Discount rates

The recoverable value of each CGU has been determined after discounting cash flows at the Group's estimated post-tax nominal discount rate of 8.5% (2016: 8.5% and 2015 8.5%). The discount rate has been determined with consideration to CGU specific risks included in the cashflows. The use of a post-tax discount rate of 8.5% (2016: 8.5%) is the equivalent of a pre-tax discount rate of between 12% and 25% (2016: 12% and 25% and 2015: 12% and 25%) depending on the CGU.

Cost assumptions

Cost assumptions are based on the 2P reserve profile, which give rise to cash flows over a period of between 6 and 20 years depending on the CGU. This includes operating cost assumptions, capital

requirements and asset maintenance assumptions. Short term cost assumptions are aligned to the Group's short term budgets.

Production forecasts and reserves

Estimated production forecasts are developed based on Quadrant Energy's 2P developed and undeveloped reserves (as independently reviewed), with no value ascribed to contingent resources. Short term production forecasts are aligned to the Group's short term budgets.

Impairment analysis—oil CGUs

Quadrant recognised an impairment charge of US$95.4 million related to the Pyrenees CGU in 2016, and an impairment charge of US$22.1 million and US$66.2 million related to the Pyrenees and Ningaloo Vision CGU's respectively in 2015, within the oil segment. The impairments arose primarily due to deteriorations in the consensus outlook for oil pricing since Quadrant's original acquisition date and adjustments to forecast production and costs. The recoverable amounts in each period was calculated using a VIU model with the recoverable amount compared to the carrying value, resulting in the recognition of an impairment write-down in each period.

As a result of the impairment recorded at 31 December 2016 there was no differential between the recoverable amount and the revised carrying value for Pyrenees and there was also limited headroom for Quadrant's other oil asset (Ningaloo Vision). As a result of the impairment recorded at 31 December 2015, there was no differential between the recoverable amount and the revised carrying value of Pyrenees and Ningaloo Vision. These assets therefore remain particularly sensitive to changes in key assumptions.

An impairment test for oil assets has been performed at 31 December 2017 given the limited headroom at the previous testing date. No impairment expense or reversal has been recorded and both assets have performed inline or ahead of forecast during FY17.

The oil price outlook and production forecasts are the two factors which most significantly impacts valuations. The recoverable amount of both oil assets are also impacted to a lesser extent by a range or factors including production costs, foreign exchange forecasts, capital expenditure estimates and discount rates.

Any adverse or positive movement in these assumptions could result in an impairment expense or reversal in future periods. Using a value in use model, using a +/- 10% sensitivity would have the following impact on the combined recoverable value of both oil assets (split reasonably evenly across the two CGUs):

•: +/- 10% Oil price sensitivity would have an approximate +/- US$60 million combined impact; and
•: +/- 10% Production volume sensitivity would have an approximate +/- US$60 million combined impact

Prior to recording any expense or reversal further assessment would be performed including completion of a fair value model and assessment of the recoverable amount versus available market information.

Owing to the complexity of the analysis caused by the relationship between each key assumption, a change in one assumption as modelled would potentially cause a change to several other inputs in to the calculation. Management's sensitivity analysis is therefore performed for each assumption individually.

Impairment analysis—gas CGUs

For the purposes of impairment testing, goodwill of US$246.9 million has been allocated to the gas operating segment, which is the level at which management monitor and manage the goodwill arising at acquisition.

The Group has performed impairment tests on the gas CGUs on a value in use basis using the assumptions outlined above which indicate headroom over the CGU carrying values, including the goodwill allocated to the gas segment.

The gas CGUs have limited exposure to commodity pricing risk in the short to medium term, with the majority of the Group's sales under medium to long term gas supply agreements. The combination of contracted volumes with relatively stable price step-ups provides Quadrant Energy with a high degree of visibility over future revenues. The Group does not believe that there are any reasonably possible changes in key economic and pricing assumptions that could result in impairment. Potential factors which could significantly reduce the recoverable value of the gas asset include significant changes to reserves, loss of key customers, or significant changes in legislation.

Corporate Assets

Corporate assets of US$24.2 million (2016 US$18.3 million) relate primarily to IT equipment and Leasehold improvements. There have been no significant disposals during the year with the increase reflecting expenditure on Quadrant Energy's ERP system and corporate office refurbishment.

DD&A

Depreciation on corporate assets is calculated on a straight-line basis so as to generally write-off the cost of each fixed asset over its estimated useful life on the following basis;

Category	Method	Estimated Useful Life

Computer Plant and Equipment	Straight-line over useful life	3 Years
Leasehold improvements	Straight-line over the shorter of useful life and lease term	Term of lease

Refer to note 3c for the Group's encumbrances over its Corporate assets.

5b) Exploration and evaluation

(stated in millions of US dollars)

Balance at beginning of period	229.8		70.7
Additions	40.5		239.9
Exploration and evaluation expense written off	(12.2	)	(65.6	)
Disposals	—		(15.2	)

Balance at end of period	258.1		229.8

Disposals in 2016 relate primarily to the disposal of equity interest in the non-core exploration permit, Bunyip. Refer to note 8f for further information in relation to changes in relation to equity interests.

Recognition and measurement

The Group's accounting policies are outlined below;

Exploration and evaluation expenditures

Exploration and evaluation expenditures are accounted for by area of interest, which is applied in a way that is broadly aligned to the successful efforts method where success is determined based on the technical feasibility of an identified resource. The Group generally defines the area of interest by basin. The costs of drilling exploration and appraisal wells are initially capitalised pending evaluation. Costs are expensed where the well does not enhance the value of the related area of interest. All other exploration and evaluation expenditures including directly attributable general administration costs, geological and geophysical costs, exploration, seismic and new venture activity expenditures are expensed in the consolidated statement of comprehensive income as incurred, except where the expenditure relates to an exploration discovery that:

•: At balance date, an assessment of the existence or otherwise of economically recoverable or technically feasible reserves is not yet complete; or
•: The expenditure is expected to be recouped by future exploitation or sale.

Exploration licence acquisition costs are initially capitalised and where an acquisition of ownership interest takes place any cash consideration paid, including transaction costs is accounted for as an acquisition of exploration and evaluation assets.

The recoverability of the carrying amount of the exploration and evaluation asset is dependent on the successful development and commercial exploitation or alternatively the sale of the area of interest.

When an oil or gas field has been approved for development, the accumulated exploration and evaluation costs are transferred to oil and gas assets—assets in development.

Key estimates

Area of interest

An area of interest (AOI) is defined by the Group as an individual geographic area whereby the presence of hydrocarbons is considered favourable or proved to exist. The Group has established criteria to recognise and maintain an AOI. There is separate guidance for conventional and unconventional AOIs.

Impairment of exploration and evaluation assets

The application of the above policy requires management 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 exploitation or sale, then the relevant capitalised amount will be written off to the consolidated statement of comprehensive income.

5c) Provisions

(stated in millions of US dollars)

Current
Employee entitlement provisions	29.3	19.3
Asset restoration obligations	48.8	20.6
Other provisions	25.9	82.0

	104.0	121.9

Non-current
Employee entitlement provisions	7.5	4.6
Asset restoration obligations	927.0	802.3
Other provisions	14.7	12.7

	949.2	819.6

Movement in the period (stated in millions of US dollars)

Opening balance 1 January 2017	822.9		23.9	94.7		941.5
Accretion expense	26.4		—	—		26.4
Change in provision (net of settlements / expenditure)	(22.7	)	12.9	(54.1	)	(63.9	)
Adjustments recorded against oil and gas properties	41.9		—	—		41.9
Recognised in business combination*	107.3		—	—		107.3

Closing Balance 31 December 2017	975.8		36.8	40.6		1,053.2

Opening balance 1 January 2016	923.0		15.0	117.0		1,055.0
Accretion expense	30.7		—	—		30.7
Change in provision (net of settlements/expenditure)	(52.7	)	8.9	(22.3	)	(66.1	)
Adjustments recorded against oil and gas properties	(50.0	)	—	—		(50.0	)
Provisions disposed	(28.1	)	—	—		(28.1	)

Closing Balance 31 December 2016	822.9		23.9	94.7		941.5

*: Refer to note 1c for further details on the Harriet acquisition

Recognition and measurement

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the obligation.

Asset restoration obligations

Refer to note 5a for disclosure of the Group's accounting policy in relation to asset restoration obligations.

Employee benefits

Liabilities for wages and salaries and other short term benefits that are expected to be settled within 12 months of the reporting period date, are recognised in respect of employee service up to the reporting date, and are measured at the amounts expected to be paid when the liabilities are settled. Employee benefits include provisions related to employee bonuses, based on management's best

estimate of the consideration required to settle the present obligation at the end of the reporting period.

Annual and long service leave provisions not expected to be settled within 12 months after the end of the reporting period are measured using the projected unit credit valuation method. The present value of expected future payments for services provided up to the end of the reporting period, discounted using market yields on high quality corporate bonds at the end of the reporting period that match as closely as possible the estimated future cash payments.

Other provisions

Other provisions include amounts for a number of commercial and legal disputes with a variety of counterparties, in additions to provisions related to Good Standing Agreements. Other provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probably than an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

Key judgments

Asset restoration obligations

The Group estimates the future removal and restoration costs of oil and gas production facilities, wells, pipelines and related assets at the time of installation of the assets. In most instances the removal or restoration of these assets will occur many years in the future. The forecast timing of the cash flows related to the obligation is predominantly into the future, with 25% of undiscounted cash flows forecast to occur in 5 to 10 years and 63% of undiscounted cash flows forecast to occur beyond 10 years. The estimate of future removal costs are made considering relevant legislation and industry practice and require management to make significant judgments regarding the removal date, currency denomination of cash flow, the extent of restoration activities required and future removal technologies.

Separate forecast risk free rates and inflation are applied to AUD and USD specific cash flows in which the underlying cash flows are forecast. The risk free discount rate is calculated using government bond rates as a proxy for a risk free rate. A move in the risk free rate has an impact on the carrying value of the provision, given the timing profile over which restoration will commence.

A significant portion of the ARO obligations are likely to be settled in Australian Dollars which also creates volatility from a valuation perspective.

Whilst the provision amount is sensitive to the above assumptions, where supportable the changes to the estimate will generally be added/deducted from the cost base of the restoration asset cost base (which is amortised over the life of the project). As a result changes to the estimate do not ordinarily present a significant immediate impact on the Group's profit or loss for the period with the exception of late life assets. Refer to note 5a for further information related to the Group's policy in relation to the booking of valuation movements.

Other provisions

The Group estimates provisions for a number of commercial and legal disputes with a variety of counterparties where the timing of outflows is considered uncertain. A provision is recognised where management considers the liability is probable.

The amounts recorded represent management's best estimate of the likely settlement amounts which necessarily involves a degree of estimation and judgement where the conclusion cannot be finally determined until resolution has been reached with the relevant counterparty or, as appropriate, through a formal legal process. The final resolution of some of these items may give rise to material profits, losses and / or cash flows. Resolution can take extended periods and as a result differences can arise between the estimated expense and the actual settlement amount.

5d) Deferred Revenue

(stated in millions of US dollars)

Current
Take or pay supply obligations	2.6	10.4

	2.6	10.4

Non-current
Take or pay supply obligations	208.5	209.2
Prepaid Gas	500.0	500.0

	708.5	709.2

Recognition and measurement

Deferred income represents payments collected but not yet earned at the end of the reporting period. These payments are recognised as revenue in the period when the goods are delivered.

Prepaid gas

With respect to the deferred revenue balance, if this contract is cancelled and obligations are not met, the Group will be required to pay US$99.3 million. As at the date of this report the Group expects to meet all current obligations under the contract and as a result, no provision has been recognised in the financial statements for this amount. The balance is recognised at the amount received in advance and no interest is imputed in relation to the balance. There is security in place over the prepayment, with a floating charge over the assets of the Group, which ranks subordinate to the external debt in place, covering the payment of any outstanding prepaid gas amount.

Take or pay obligation

The Group has a number of liabilities recorded for take or pay obligations, which arise under contracts for domestic gas sales, where payment for an obligation to deliver future gas has already been received. The balance is recognised at the amount received in advance, and revenue is recognised on delivery of the gas. The Group has an obligation to deliver gas over a remaining period of seven years (2016: eight years).

As at the date of this report, all commitments for the future delivery of gas are expected to be met.

5e) Contractual assets and liabilities

The contractual assets and liabilities relate to instances where the Group acquired customer and supplier contracts in a business combination. The contractual assets and liabilities will be unwound by December 2026.

(stated in millions of US dollars)

Contractual assets (current)	14.7		15.3
Contractual assets (non-current)	21.6		36.3
Contractual obligations (current)	(47.1	)	(51.5	)
Contractual obligations (non-current)	(171.7	)	(217.5	)

Net contractual obligations	(182.5	)	(217.4	)

Movement in the period (stated in millions of US dollars)

Opening balance	(217.4	)	(369.2	)
Contractual obligations acquired in a business combination	(1.5	)	—
Released to profit and loss	34.7		100.9
Unwound against exploration and evaluation	1.7		33.1
Utilisation of provision	—		9.8
Derecognised via asset disposal	—		8.0

Closing Balance	(182.5	)	(217.4	)

Recognition and measurement

When undertaking business acquisitions the Group may take on responsibility for contracts that are in place within the acquiree. Changes in market conditions may result in the original terms of the contract becoming favourable or unfavourable in comparison to market conditions present at the date of acquisition. The obligation for discounted future above / below market payments are provided for and calculated using the discount rate determined at acquisition date. The discounted future above / below market provision is released to earnings over the contracted delivery profile.

6—Unrecognised Items

6a) Commitments

(stated in millions of US dollars)

Lease commitments
Operating leases
—Not later than 1 year	13.2	28.5
—Later than 1 year, but not later than 5 years	34.0	24.4
—Greater than 5 years	59.2	17.0

Operating lease commitments	106.4	69.9

Expenditure commitments
—Exploration commitments	112.3	148.5
—Purchase obligations	3.5	1.3

Expenditure commitments	115.8	149.8

Total commitments	222.2	219.7

Lease commitments

The Group's operating leases primarily consist of the following:

•: Non-cancellable leases for office premises with terms remaining of approximately 11 years, with options to further renew after that time.
•: Leases in relation to gas pipeline capacity, with one contract expiring in 2024 with an option for a further 5 year extension, and another contract with options extending until 2033.

No liability has been recorded in the financial statements in relation to the expenditure and lease commitments on the basis that goods or services in relation to the commitments have not yet been received.

Expenditure commitments

The Group has minimum expenditure commitments arising from the terms of the granting of petroleum exploration permits in order to maintain rights of tenure.

These commitments may be varied as a result of renegotiations of the terms of exploration permits, licences or contracts or alternatively upon their relinquishment. The minimum exploration commitments are less than the normal level of budgeted exploration expenditure included expected to be undertaken by the Group.

Recognition and measurement

The determination of whether an arrangement is (or contains) a lease is based on the substance of the arrangement at the inception of the lease. The arrangement is, or contains, a lease if fulfilment of the arrangement is dependent on the use of a specific asset or assets and the arrangement conveys a right to use the asset (or assets), even if that asset is (or those assets are) not explicitly specified in an arrangement.

Included in the Group's Operating lease commitments are leases that upon unwinding to earnings can be recovered from joint venture participants.

6b) Contingencies

Except as disclosed in the section below the company has no contingent assets (2016: Nil).

There are a number of other claims and possible claims that have arisen in the course of business against entities in the Group, the outcome of which cannot be foreseen at present (refer below and note 5d). Unless recognised as a provision, management considers the liability is not probable and therefore the Group has not provided for such amounts in this financial report.

Apache claim

On 3 June 2016 Quadrant Energy notified the vendors of various claims it intended to bring arising from its acquisition of Apache Energy Australia Limited in June 2015. The claims relate to alleged breaches of representations, warranties or covenants included in the Sales and Purchase Agreement ("SPA") between the two parties. The initial value of claims raised against Apache exceeded AU$200.0 million.

Quadrant Energy is also currently subject to a dispute with Apache in relation to a tax refund of AU$82.9m which it received from the Australian Taxation Office. Apache has alleged that Quadrant Energy is required to transfer to Apache the tax refund that the Company received under the Sale and Purchase Agreement that the parties executed in respect of the Acquisition.

These disputes are the subject of proceedings in the Supreme Court of Western Australia.

No asset has been recognised for the differential between the amounts claimed from the Vendors and potential amounts repayable under the SPA. The net potential receivable cannot be recognised under accounting standards until it has become virtually certain that an inflow of economic benefits will arise. Where applicable, any asset, and the related income, will be recognised in the financial statements of the period in which the change occurs.

6c) Events after the reporting period

In the period to 26 June 2018 there were a number of subsequent events as follows;

Refinance of the Group's debt facility

On 15 March 2018, the Group completed a refinance of its existing debt facility. Draw down of the new facility took place on 21 March 2018, with the new facility drawn down US$535.0 million. The funds were applied to fully repay the outstanding principal on the Group's pre-existing facility of US$534.3 million. The new facility expires in 2025, with the first repayment of drawn debt due 2021.

Dividends on ordinary shares declared and paid

On 26 March 2018, the directors of the company declared a dividend attributable to its shareholders of US 40 cents per share (US$100.0 million). The dividend included US$3.5 million which was payable to members of the Group's Senior Management Incentive Plan.

The dividend was not reflected as a liability at reporting date as the dividend was not declared or determined by the directors on or before the end of the financial year.

Changes in ownership percentage of exploration and retention licenses

There were also changes in the Group's equity interests related to exploration and retention licenses occurring in the period to 26 June 2018. In relation to permits surrendered is no material exploration and evaluation expenditures capitalised against the permits at 31 December 2017. Refer note 8f for further information.

There were no matters or circumstances that has arisen subsequent to the end of the financial year other than those noted above, that in the opinion of the directors have significantly affected or may significantly affect future years.

7—Equity and Reserves

7a) Contributed equity

i) Issued capital

Balance at 1 January 2017	250,534,776		233.1

Balance at 31 December 2017	250,534,776		233.1

Reserved shares at 31 December 2017	(10,534,362	)	(8.5	)

Issued Capital at 31 December 2017	240,000,414		224.6

Balance at 1 January 2016	251,309,362		233.7
Shares redeemed and cancelled	(774,586	)	(0.6	)
Balance at 31 December 2016	250,534,776		233.1
Reserved shares at 31 December 2016	(10,534,362	)	(8.5	)

Issued Capital at 31 December 2016	240,000,414		224.6

ii) Reserved shares

Balance at 1 January 2017	(10,534,362	)	(8.5	)
Movement in reserved shares	—		—

Balance at 31 December 2017	(10,534,362	)	(8.5	)

Balance at 1 January 2016	(11,308,948	)	(9.1	)
Reserved shares cancelled	774,586		0.6

Balance at 31 December 2016	(10,534,362	)	(8.5	)

Issued capital consists of ordinary shares which have no par value. Issued and paid up capital is recognised at fair value of the consideration received by the company. Any transaction costs arising on the issue of ordinary shares are recognised directly in equity as a reduction of the share proceeds received.

The Group's own equity instruments, which are reacquired for later use in employee share-based payment arrangements (reserved shares) are deducted from equity. No gain or loss is recognised in the income statement on the purchase, sale or cancellation of the Group's own equity instruments.

Capital management

The key objectives of Quadrant's approach to capital management include:

•: safeguarding its ability to continue as a going concern;
•: maintaining access to funding with a spread of maturity dates and sufficient undrawn committed facility capacity;
•: optimising over the long term, and to the extent practicable, the weighted average cost of capital to reduce the cost of capital to the Group while maintaining financial flexibility; and
•: providing returns to shareholders and benefits to other stakeholders.

Capital is defined as the combination of shareholder debt, equity and reserves. In determining its capital structure, the Group considers the robustness of future cash flows, potential funding requirements for growth opportunities and acquisitions, the cost of capital and ease of access to funding sources. In order to optimise the Group's capital structure, management may: alter the amount of dividends paid to shareholders; issue new shares or return capital to shareholders; vary discretionary expenditure; draw-down additional debt; or sell assets to reduce debt.

7b) Cash flow hedge reserve

(stated in millions of US dollars)

Opening balance	40.1		177.7
Movement recognised in other comprehensive income	5.0		(61.3	)
Realised gains transferred to the income statement	(62.3	)	(135.3	)
Income tax related to gains recognised	17.2		59.0

Closing balance	—		40.1

Recognition and measurement

The cash flow hedging reserve represents the cumulative effective portion of gains or losses arising on changes in fair value of hedging instruments entered into for cash flow hedges. The cumulative gain or loss arising on changes in fair value of the hedging instruments that are recognised and accumulated under the heading of cash flow hedging reserve will be reclassified to profit and loss only when the hedged transaction affects the profit or loss.

7c) Dividends paid and proposed

The dividend was not reflected as a liability at reporting date as the dividend was not declared or determined by the directors on or before the end of the financial year.

As at 31 December 2017, the Group has nil franking credits (2016: US$14.8 million).

7d) Share-based payments reserve

(stated in millions of US dollars)

Balance at beginning of period	0.6	0.2
Share-based Payments Expense	0.7	0.4

Balance at end of period	1.3	0.6

The Group provides benefits to certain employees in the form of share-based payment awards, whereby employees render services in exchange for rights over shares under the Group's Senior Management Incentive Plan ('the Plan'). The Plan was set up following the acquisition of Apache Energy Australia Ltd ("AEAL") to incentivise and retain senior management. The grant date of instruments under the plan was 8 August 2015.

The Plan is delivered in the form of reserved shares held by Senior Management ('the Plan'), which allow their holders to receive equity in the Group. The plan is accounted for as an equity settled share-based payment. There are multiple potential settlement mechanisms for the Plan and the accounting treatment has been determined based on the mechanism deemed most likely to occur. There are also service conditions attached to the plan.

If the employee is still with the company at the Redemption Date (15 February 2020), and none of the potential settlement mechanisms have occurred, then each participant can elect to redeem up to 20% of their plan units each year thereafter.

Refer to Note 7a for further information in relation to the number of reserved shares on issue and movements during the period.

Recognition and measurement

The fair value of the rights granted are determined using a Black-Scholes option pricing model, incorporating inputs including the price on issue, strike price, expected option life, volatility, interest rate and dividend yield. Non-market performance conditions associated with the grant do not impact the value of share rights, but rather the proportion expected to vest and therefore the proportion expensed.

Subsequent to grant date, and over the applicable vesting period, the fair value of the share rights is progressively recognised as an employee benefits expense with a corresponding increase in equity. The vesting period is the period over which all of the specified vesting conditions are to be satisfied.

At each reporting date the Group revises its estimate of the number of share rights that are expected to vest and the employee benefits expense recognised each period takes this estimate into account. No expense is recognised for shares and performance rights that do not ultimately vest.

8—Other Information

8a) Taxation

Recognition and measurement

The current tax payable or receivable is based on taxable profit for the year. Taxable profit differs from net profit as reported in the statement of comprehensive income because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability or asset for current tax is calculated using tax rates that have been enacted or substantively enacted at the reporting date.

Deferred tax is accounted for using the balance sheet liability method. Temporary differences are differences between the tax base of an asset or liability and its carrying amount in the consolidated statement of financial position. The tax base of an asset or liability is the amount attributed to that asset or liability for tax purposes.

In principle, deferred tax liabilities are recognised for all taxable temporary differences. Deferred tax assets are recognised to the extent that it is probable that sufficient taxable amounts will be available against which deductible temporary differences or unused tax losses and tax offsets can be utilised. However, deferred tax assets and liabilities are not recognised if the temporary differences giving rise to them arise from initial recognition of assets and liabilities (other than as a result of a business combination) which affects neither taxable income nor accounting profit. Furthermore, a deferred tax liability is not recognised in relation to taxable temporary differences arising from the initial recognition of goodwill.

In relation to PRRT, the impact of future augmentation on expenditure is included in the determination of future taxable profits when assessing the extent to which a deferred tax asset can be recognised.

The carrying amount of deferred tax assets is reviewed at each balance date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilised.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the period when the asset is realised or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the consolidated statement of financial position date. Deferred tax is charged or credited in the statement of comprehensive income, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.

Tax benefits transferred between Group companies are transferred under normal commercial arrangements, with consideration paid equal to the tax benefit of the transfer.

Deferred tax assets and deferred tax liabilities are offset only if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to the same taxable entity and the same taxation authority. Petroleum Resource Rent Tax ('PRRT') is accounted for as income tax.

Key estimates

The Group's tax charge on ordinary activities is the sum of the total current and deferred tax charges. The calculation of the Group's total tax charge necessarily involves a degree of estimation and judgement in respect of certain items whose tax treatment cannot be finally determined until resolution has been reached with the relevant tax authority or, as appropriate, through a formal legal process. The final resolution of some of these items may give rise to material profits, losses and / or cash flows. The resolution of issues is not always within the control of the Group and it is often dependent on the efficiency of processes that occur externally of the Group. Issues can take an extended period of time to resolve. Payments in respect of tax liabilities for an accounting period are made by payments on account and on the final resolution of open items. As a result differences can arise between the tax charge in the consolidated statement of comprehensive income and tax payments.

The Group also has unrecognised deferred tax assets relating to PRRT. PRRT is allocated on a project basis and at 31 December 2017 due to the substantial value of carry forward deductible PRRT expenditure in relation to several projects, the Group does not expect to generate sufficient taxable profit to utilise these credits over the life of these projects and as a result, no deferred tax asset has been recognised as at 31 December 2017. Refer to note 8b for further information related to unrecognised temporary differences.

Tax consolidated group

Quadrant Energy Holdings Pty Ltd and its 100 percent owned Australian resident subsidiaries have formed a tax consolidated group. Quadrant Energy Holdings Pty Ltd is the head entity of the tax consolidated group. Members of the Group have entered into a tax sharing agreement in order to allocate income tax expense to the wholly owned subsidiaries on a group allocation basis. The tax sharing arrangement provides for the allocation of income tax liabilities between the entities should the head entity default on its tax payment obligations. The possibility of such a default is considered remote at the date of this report.

Members of the tax consolidated group have entered into a tax funding agreement. The Group has applied the Group allocation approach in determining the appropriate amount of current taxes to allocate to members of the tax consolidated Group. The tax funding agreement provides for each member of the tax consolidated group to pay or receive an amount to or from the parent equivalent to their allocation under the tax sharing agreement. Such amounts are reflected in amounts receivable from or payable to the parent company in their accounts and are settled as soon as practicable after lodgement of the consolidated return and payment of the tax liability.

(i) Income tax benefit / (expense)

(stated in millions of US dollars)

Current tax charge	(53.7	)	(12.8	)	(13.1	)
Deferred tax (charge) / benefit (note 8b)	(108.2	)	(67.7	)	26.2

Tax (charge) / benefit	(161.9	)	(80.5	)	13.1

(ii) Numerical reconciliation of income tax to prima facie tax payable


Profit before tax	503.8		166.3		(62.4	)

Prima facie income tax expense at Australian tax rate of 30% (2016 & 2015: 30%)	(151.1	)	(49.9	)	18.7
Tax effect amounts which are not deductible (taxable) in calculating taxable income:
Gain on remeasurement of pre-existing interest	57.7		—		—
Stamp duty	—		—		(7.7	)
Other	(9.0	)	(0.7	)	0.2
Adjustments from prior periods	0.5		6.6		2.9
Prior year temporary differences not previously recognised now brought to account	5.3		8.2		—
Capital gain on transactions	(5.3	)	(7.4	)	(10.0	)
FX gain on tax provisions	1.4		5.4		(6.0	)
Research and development tax credits	—		0.4		—

Income tax charge	(100.5	)	(37.4	)	(1.9	)
PRRT (net of income tax benefit)	(61.4	)	(43.1	)	15.0

Total Tax charge	(161.9	)	(80.5	)	13.1

(iii) Tax effect of balances recognised in other comprehensive income

Income tax recognised through other comprehensive income is disclosed in note 7(b)

8b) Deferred tax

	Deferred tax assets						Deferred tax liabilities

(stated in millions of US dollars)	2017			2016			2017			2016
Temporary differences attributable to:
OGP and PPE		—			—			(323.4	)		(178.3	)
Exploration and evaluation		—			—			(77.4	)		(69.0	)
Contractual Assets/Liabilties (net)		59.2			69.8			—			—
Provisions		287.4			265.1			—			—
PRRT
OGP and PPE		44.8			16.2			(827.8	)		(834.9	)
Exploration and evaluation		67.0			83.6			(115.0	)		(75.6	)
Provisions		195.2			213.8			—			—
Other		—			—			(4.2	)		(9.4	)
Income tax effect of deferred PRRT		192.0			181.9			—			—
Derivative financial instruments		2.7			—			—			(6.2	)
Carried forward tax losses		—			49.9			—			—
Other		39.3			—			—			(0.1	)

Total deferred tax assets / (liabilities)		887.6			880.3			(1,347.8	)		(1,173.5	)
Set-off of deferred tax pursuant to set-off provisions		(400.9	)		(253.4	)		400.9			253.4

Net deferred tax assets / (liabilities)		486.7			626.9			(946.9	)		(920.1	)

(i): Unrecognised temporary differences

(stated in millions of US dollars)

Deferred tax assets have not been recognised in respect of the following items
Capital losses	14.7	20.1
Deductible PRRT expenditure (net of income tax)	1,161.3	1,340.2
PRRT benefit of closing down costs (net of income tax)	196.0	153.3

	1,372.0	1,513.6

Carried forward Capital losses of US$49.1 million have not been recognised as at 31 December 2017 (2016: US$66.9 million) as the Group is not expected to generate sufficient future capital gains for which these losses can be utilised.

The Group has US$2,508.9 million of unrecognised deferred tax assets at 31 December 2017 (2016: US$2,133.6 million) relating to PRRT, with a corresponding unrecognised deferred tax liability for income tax purposes of US$752.6 million (2016: US$640.1 million). Recognition of a deferred tax asset for accumulated PRRT expenditure and augmentation depends on benefits expected to be obtained from the deduction against PRRT liabilities in the future. PRRT is allocated on a project basis, as at 31 December 2017 due the substantial value of carry forward deductible PRRT expenditure in relation to several projects, the Group does not expect to generate sufficient taxable profits to utilise these credits over the life of these projects and as a result, no deferred tax asset has been recognised as at 31 December 2017.

During the year the Group derecognised deferred tax assets related to PRRT of US$23.4 million (2016: US$46.7 million) on the basis that the Group does not expect to generate sufficient future taxable profits against which to utilise the benefits.

(ii): Deferred tax income statement reconciliation

(stated in millions of US dollars)

PRRT
OGP and PPE	35.9		103.1		51.1
Exploration and evaluation	(56.1	)	(39.4	)	17.0
Provisions	(18.6	)	(102.1	)	(26.8	)
Other	5.3		(2.1	)	(6.6	)
Income tax effect of deferred PRRT	10.1		10.7		(10.4	)

PRRT deferred tax (benefit) / expense	(23.4	)	(29.8	)	24.3

Income Tax
OGP and PPE	(36.0	)	47.5		17.6
Exploration and evaluation	8.5		(47.7	)	3.0
Contractual assets / liabilities (net)	(11.1	)	(43.5	)	(19.5	)
Provisions	18.1		(19.9	)	(3.6	)
Derivative financial instruments	(4.9	)	4.6		12.6
Carried forward tax losses	(49.8	)	36.8		13.1
Other	(9.6	)	(15.7	)	(21.3	)

Income tax deferred tax (benefit) / expense	(84.8	)	(37.9	)	1.9

Deferred tax (benefit) / expense	(108.2	)	(67.7	)	26.2

iii): Movement in deferred tax assets

(stated in millions of US dollars)

Opening net deferred tax liabilities	(293.2	)	(284.5	)
Recognised in business combination*	(76.0	)	—
Tax benefit / (charge) recognised in other comprehensive income	17.2		59.0
Tax charge recognised in profit and loss	(108.2	)	(67.7	)

Closing net deferred tax liabilities	(460.2	)	(293.2	)

*: refer to note 1c for further details on the Harriet Acquisition.

Recognition and measurement

Refer note 8a for accounting polices related to taxation.

Key estimates

As outlined in note 8a significant judgements, estimates and assumptions have been made by management in accounting for deferred tax.

8c) Related party transactions

Subsidiaries

Interests in subsidiaries are set out in note 8e.

Key management personnel compensation

Key management personnel compensation for the period is as follows:

(stated in millions of US dollars)

Key management personnel compensation
Short-term benefits	4,210	3,873	1,854
Post-employment benefits	319	296	141
Other long-term benefits	2,075	2,488	1,604
Share-based payments	868	596	101

	7,472	7,253	3,700

Transactions with other related parties

The following transactions occurred with related parties:

(stated in millions of US dollars)

Transactions with other related parties
Rental expense(i)	2,837	2,890	1,606
Acquisition costs(ii)	—	—	33,035
Interest expense(iii)	4,926	15,257	10,529
Sales(iv)	2,563	1,240	—
Other	208	312	—

(i): Rental expense paid

The Group leases office premises from a shareholder. Terms of the lease agreements were agreed prior the shareholder becoming a related party.

(ii): Acquisition costs

In completing the acquisition in 2015, the Group made payments to a shareholder for providing administrative services required to complete the acquisition.

(iii): Interest expense

Interest expense recognised on the Group's shareholder loans. Further information on loans from shareholders is disclosed in note 3c.

(iv): Sales

Sales of oil and gas on an arm's length basis at market rates under normal market conditions with a shareholder.

Outstanding balances with related parties

The following balances at the end of the reporting period were outstanding in relation to transactions with related parties:

(stated in millions of US dollars)

Outstanding balances with related parties
Trade receivables	256	—
Other payables	208	312
Shareholder loans(i)	—	341,378

(i): Shareholder loans

Loans from shareholders are disclosed in note 3c. These loans were issued, and related interest was charged, with the rate disclosed in note 3c.

8d) Earnings per share

Basic earnings per share amounts are calculated by dividing net profit or loss for the year attributable to ordinary equity holders of the Company by the weighted average number of ordinary shares outstanding during the year.

As no dilutive potential ordinary shares were on issue at any stage during the current and comparative periods, diluted earnings per share are equal to basic earnings per share and as a result basic and diluted earnings per share have been reported together.

Performance rights of 10,534,362 shares (2016: 10,534,362 shares and 2015: 11,308,948 shares) are considered to be contingently issuable and have not been allowed for in the diluted earnings per share calculation.

Calculation of basic and diluted earnings per share is as follows:

(stated in millions of US dollars unless otherwise noted)

Earnings attributable to ordinary shareholders of the Company used in calculating basic and diluted earnings per share	341.9	85.8	(49.3	)
Weighted average number of ordinary shares used in calculating basic and diluted earnings per share	240,000,414	240,000,414	240,000,414



Basic and diluted earnings / (loss) per share attributable to ordinary shareholders of the company	142.5	35.7	(20.5	)

8e) Subsidiaries

The Group's principal subsidiaries at 31 December 2017 are set out below. Unless otherwise stated, they have share capital consisting solely of ordinary shares held directly by the Group, and the proportion of ownership interests held equals the voting rights held by the Group. The principal place of business is also the country of incorporation or registration.

Name of entity	Principal place of business

QUADRANT ENERGY HOLDINGS PTY LTD^(*)	Australia	100%	100%
QUADRANT ENERGY PTY LTD^(*)	Australia	100%	100%
QUADRANT ENERGY AUSTRALIA LIMITED^(*)	Australia	100%	100%
QUADRANT LOWENDAL PTY LIMITED^(*)	Australia	100%	100%
HARRIET (ONYX) PTY LTD^(*)	Australia	100%	100%
QUADRANT NORTHWEST PTY LTD^(*)	Australia	100%	100%
QUADRANT OIL AUSTRALIA PTY LIMITED^(*)	Australia	100%	100%
QUADRANT KERSAIL PTY LTD^(*)	Australia	100%	100%
QUADRANT EAST SPAR PTY LIMITED^(*)	Australia	100%	100%
NORTHWEST JETTY SERVICES PTY LTD^(*)	Australia	100%	100%
QUADRANT ONSHORE HOLDINGS PTY LTD^(*)	Australia	100%	100%
QUADRANT JULIMAR HOLDINGS PTY LTD^(*)	Australia	100%	100%
QUADRANT PERMITS PTY LTD^(*)	Australia	100%	100%
QUADRANT LNG PTY LTD^(*)	Australia	100%	100%
QUADRANT PVG PTY LTD^(*)	Australia	100%	100%
QUADRANT AUSTRALIA MANAGEMENT PTY LTD^(*)	Australia	100%	100%
QUADRANT AUSTRALIA HOLDINGS PTY LIMITED^(*)	Australia	100%	100%
QUADRANT AUSTRALIA INTERNATIONAL PTY LTD^(*)	Australia	100%	100%
QUADRANT VARANUS ISLAND PTY LTD^(**)	Australia	100%	100%
QUADRANT AUSTRALIA OFFSHORE HOLDINGS PTY LTD	Australia	100%	100%
NINGALOO VISION HOLDINGS PTE LTD	Singapore	100%	100%
APACHE AUSTRALIA FINANCE GENERAL PARTNERSHIP	Australia	100%	100%

(*): The entity is a party to a Deed of Cross Guarantee.
(**): This entity was previously named Quadrant Balnaves Pty Ltd

8f) Joint arrangements and controlled permits

The Group's investments in joint arrangements are classified as joint operations, based on the contractual rights and obligations each investor has, rather than the legal structure of the joint arrangement. A joint operation is an arrangement in which the jointly controlling parties have rights to assets and obligations for liabilities relating to the arrangement.

The Group recognises its own assets, liabilities and transactions, including its share of those incurred jointly.

The table below summarises key production areas, exploration areas and retention leases together with Quadrant Energy's ownership percentage. All joint operations are located in the North West Shelf region off the coast of Western Australia.

	Area of interest

Production licenses
TL/1, TL/5, TL/6, TL/8, TL/9, TL/10^2,3	Harriet	100.00%	80.72%
TL/2	Airlie	66.83%	66.83%
WA-13-L	East Spar	55.00%	55.00%
WA-20-L	Dampier	77.44%	77.44%
WA-29-L	John Brookes	55.00%	55.00%
WA-35-L	Van Gogh	52.50%	52.50%
WA-41-L	Devil Creek	55.00%	55.00%
WA-42-L¹	Pyrenees / Macedon	28.57%	28.57%
WA-43-L¹	Ravensworth	31.50%	31.50%
WA-45-L	Spar	55.00%	55.00%
WA-55-L	Coniston/Novara	52.50%	52.50%
Retention licenses
TR/3³	Exmouth	100.00%	100.00%
WA-33-R	Outer Barrow	48.82%	48.82%
WA-43-R	Outer Barrow	55.00%	100.00%
WA-45-R	Dampier	68.75%	55.00%
WA-48-R³	Dampier	100.00%	34.03%
WA-49-R⁴	Exmouth	38.50%	30.25%
WA-50-R	Outer Barrow	55.00%	100.00%
WA-55-R	Outer Barrow	55.00%	100.00%
WA-59-R	Exmouth	75.00%	75.00%
WA-72-R¹	Exmouth	25.00%	25.00%

1: Quadrant Energy is the Operator of all Joint Operations above, aside from those identified with (¹), whereby another external party is the primary operator of the Joint Operation.
2: Refer to note 1a for further information relating to equity interest changes during the period.
3: The permit is 100% held by the Group, and as such is not accounted for as a joint arrangement.
4: Subsequent to the end of the reporting period, the Group acquired an additional equity interest in the permit due to the withdrawal of an external party. The Group's equity interest increased to 42.78%.

The joint arrangements disclosed above had no other contingent liabilities or capital commitments as at 31 December 2017 except as disclosed already in Note 6a.

	Area of interest

Exploration licences
EP307^1,2	Barrow-HJV	100.00%	80.72%
EP358^1,2	Barrow-HJV	100.00%	80.72%
TP/7	Barrow-Flinders	38.50%	83.37%
TP/8^1,2	Barrow-HJV	100.00%	80.72%
WA-155-P (Part 1)	Exmouth	71.50%	71.50%
WA-155-P (Part 2)	Exmouth	0.00%	47.67%
WA-192-P	Outer Barrow	0.00%	0.00%
WA-1-P	Dampier	55.00%	77.44%
WA-208-P²	Dampier	100.00%	47.70%
WA-209-P	Dampier	55.00%	55.00%
WA-214-P	Outer Barrow	55.00%	55.00%
WA-290-P	Exmouth	38.50%	30.25%
WA-320-P	Exmouth	0.00%	40.67%
WA-418-P³	Exmouth Plateau	65.00%	65.00%
WA-435-P	Bedout	80.00%	80.00%
WA-436-P	Bedout	70.00%	70.00%
WA-437-P	Bedout	80.00%	80.00%
WA-438-P	Bedout	70.00%	70.00%
WA-482-P	Beagle	50.00%	50.00%
WA-486-P²	Exmouth	100.00%	100.00%
WA-499-P	Dampier	55.00%	100.00%
WA-501-P³	Dampier	55.00%	100.00%
WA-505-P	Roebuck	0.00%	100.00%
WA-510-P	Outer Barrow	55.00%	100.00%
WA-531-P	Northern Carnarvon Basin	55.00%	0.00%

1: Refer to note 1a for further information relating to equity interest changes during the period.
2: The permit is 100% held by the Group, and as such is not accounted for as a joint arrangement.
3: Subsequent to 31 December 2017, the Group relinquished its interest in the permits. There are no material exploration and evaluation expenditures capitalised against the permits at 31 December 2017.

The joint arrangements disclosed above had no other contingent liabilities or capital commitments as at 31 December 2017 except as disclosed already in Note 6a.

Key judgements

Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity; depending upon the facts and circumstances in each case, the Group may obtain control, joint control or significant influence over the entity or arrangement. Judgment is applied when determining the relevant activities of a project and if joint control is held over them. Relevant activities include, but are not limited to, work program and budget approval, investment decision approval, voting rights in joint operating committees, amendments to permits and changes to joint arrangement participant holdings. Transactions which give the Group control of a business are business combinations. If the Group obtains joint control of an arrangement, judgment is also required to assess whether the arrangement is a joint operation or a joint venture. If the Group has neither control nor joint control, it may be in a position to exercise significant influence over the entity, which is then accounted for as an associate.

Report of independent auditors to the members of Quadrant Energy Holdings Pty Ltd

We have audited the accompanying consolidated financial statements of Quadrant Energy Holdings Pty Ltd and subsidiaries (the Company), which comprise the consolidated statement of financial position as of December 31, 2017, and the related consolidated statements of profit or loss and other comprehensive income, changes in equity and cash flows for the year then ended, and the related notes to the consolidated financial statements.

Management's responsibility for the financial statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with International Financial Reporting Standards issued by the International Accounting Standards Board; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor's responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Quadrant Energy Holdings Pty Ltd and subsidiaries at December 31, 2017, and the consolidated results of its operations and its cash flows for the year then ended in conformity with International Financial Reporting Standards issued by the International Accounting Standards Board.

A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation

Other matters

The accompanying consolidated statement of financial position of Quadrant Energy Holdings Pty Ltd as of December 31, 2016 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, 2016 and the period from March 27, 2015 to December 31, 2015 were not audited, reviewed, or compiled by us and, accordingly, we do not express an opinion or any other form of assurance on them.

/s/ Ernst & Young
Ernst & Young
Perth, Australia
June 26, 2018

A member firm of Ernst & Young Global Limited
Liability limited by a scheme approved under Professional Standards Legislation

ITEM 19. EXHIBITS

Number			Description

	1.1		Certificate of registration of Brookfield Business Partners L.P., registered as of January 18, 2016⁽¹⁾
	1.2		Amended and Restated Limited Partnership Agreement of Brookfield Business Partners L.P., dated May 31, 2016⁽²⁾
	1.3		Bye-Laws of Brookfield Business Partners Limited⁽³⁾
	4.1		Master Services Agreement by and among Brookfield Asset Management Inc., Brookfield Business Partners L.P., and the other parties thereto, dated June 1, 2016⁽²⁾
	4.2		Amended and Restated Limited Partnership Agreement of Brookfield Business L.P., dated May 31, 2016⁽²⁾
	4.3		Relationship Agreement between Brookfield Business Partners L.P. and Brookfield Asset Management Inc., dated June 1, 2016⁽²⁾
	4.4		Registration Rights Agreement between Brookfield Business Partners L.P. and Brookfield Asset Management, dated June 1, 2016⁽²⁾
	4.5		Second Amended and Restated Credit Agreement between Brookfield Business L.P., Brookfield BBP Canada Holdings Inc., Brookfield BBP Bermuda Holdings Limited, Brookfield BBP US Holdings LLC and the other borrowers thereto, Brookfield Business Partners L.P. and BPEG US Inc., dated October 19, 2017⁽³⁾
	4.6		Voting Agreement, between Brookfield Asset Management Inc., Brookfield CanGP Limited, Brookfield Canada GP L.P. and Brookfield BBU Canada Holdings Inc., dated June 1, 2016⁽²⁾
	4.7		Trade-Mark Sublicense Agreement, dated May 24, 2016, by and among Brookfield Asset Management Holdings Ltd., our company, and the Holding LP.⁽²⁾
	8.1		List of subsidiaries of Brookfield Business Partners L.P. (incorporated by reference to Item 4.C., Organizational Structure)⁽³⁾
	12.1		Certification of Cyrus Madon, Chief Executive Officer, Brookfield Business Partners L.P., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
	12.2		Certification of Craig Laurie, Chief Financial Officer, Brookfield Business Partners L.P., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
	13.1		Certification of Cyrus Madon, Chief Executive Officer, Brookfield Business Partners L.P., pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes Oxley Act of 2002*
	13.2		Certification of Craig Laurie, Chief Financial Officer, Brookfield Business Partners L.P., pursuant to 18 U.S.C. Section 1350, as adopted to Section 906 of the Sarbanes Oxley Act of 2002*
	15.1		Consent of Deloitte LLP, Independent Registered Public Accounting Firm⁽³⁾
	15.2		Consent of Ernst & Young LLP relating to the incorporation of the consolidated financial statements of Quadrant Energy Holdings Pty (Ltd.) into the Annual Report on Form 20-F filed with the Securities and Exchange Commission (the "SEC") on March 9, 2018.*

(1): Filed as an exhibit to Amendment No. 3 to the Registration Statement on Form F-1 filed with the SEC on February 26, 2016 and incorporated herein by reference.
(2): Incorporated by reference to our Current Report on Form 6-K filed with the SEC on June 22, 2016.
(3): Incorporated by reference to our Form 20-F filed with the SEC on March 9, 2018.
*: Filed herewith.

SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing an annual report on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

Dated: June 28, 2018


		BROOKFIELD BUSINESS PARTNERS L.P., by its general partner,BROOKFIELD BUSINESS PARTNERS LIMITED
		By:		/s/ JANE SHEERE Name: Jane Sheere Title:Secretary

Brookfield Business Partners (BBU) 20-F/A2017 FY Annual report (foreign) (amended)