Sundance Energy Australia Ltd (Form: 6-K, Received: 09/13/2019 06:02:50)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 under the Securities Exchange Act of 1934

For the month of September 2019

Commission File Number 000-55246

Sundance Energy Australia Limited

(Translation of registrant’s name into English)

633 17th Street, Suite 1950
Denver, CO 80202

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F ☒ Form 40-F ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ☐ No ☒

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): n/a

sdfsd

Exhibit 99.1 is incorporated by reference in the Registration Statements on Form S-8 (Registration Number 333-204490) and Form F-3 (Registration Number 333-216220 and 333-224583) of Sundance Energy Australia Limited.


Exhibit Number		Description
99.1		Announcement, dated September 13, 2019, to Australian Securities Exchange: Half Year Report
99.2		Third Amendment to Credit Agreement, dated May 15, 2019, among Sundance Energy Australia, Sundance Energy Inc, as borrower, and Natixis, New York Branch, as administrative agent, and the lenders party hereto

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		Sundance Energy Australia Limited


Date: September 12, 2019	By:	/s/ Cathy L Anderson
	Name:	Cathy L. Anderson
	Title:	Chief Financial Officer

Exhibit 99.1

INTERIM FINANCIAL REPORT

HALF-YEAR ENDED

30 JUNE 2019

ABN 76 112 202 883

Table of Contents


	Page

Directors’ Report	1
Auditor’s Independence Declaration	8
Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Loss	9
Condensed Consolidated Statement of Financial Position	10
Condensed Consolidated Statement of Changes in Equity	11
Condensed Consolidated Statement of Cash Flows	12
Selected Explanatory Notes to the Financial Statements	13
Directors’ Declaration	27
Corporate Directory	28

DIRECTORS’ REPORT

Your Directors submit the financial report of Sundance Energy Australia Limited (the “Company” or “the consolidated group”) for the half‐year ended 30 June 2019.

Directors

The names of each person who has been a Director during the half‐year and to the date of this report are:

Michael D. Hannell – Non‐Executive Chairman

Eric P. McCrady – Managing Director and CEO

Damien A. Hannes – Non‐Executive Director

Neville W. Martin – Non–Executive Director

Weldon Holcombe – Non‐Executive Director

Judith D. Buie – Non-Executive Director *

Thomas L. Mitchell – Non-Executive Director

* Appointed in February 2019

Company Secretary

Damien Connor has been the Company Secretary during the half‐year and to the date of this report.

Review of Operations

Revenues and Production. The following table provides the components of our revenues for the six months ended 30 June 2019 and 2018, as well as each period’s respective sales volumes:


	Six months ended June 30,		Change in	Change as
	2019	2018	$	%
Revenue (US$'000)
Oil Sales	86,943	42,986	43,957	102.3
Natural gas sales	6,794	5,217	1,577	30.2
Natural gas liquids ("NGL") sales	6,904	4,562	2,342	51.3
Product revenue	100,641	52,765	47,876	90.7

	Six months ended June 30,		Change in	Change as
	2019	2018	Volume	%
Net sales volumes:
Oil (Bbls)	1,467,525	745,774	721,751	96.8
Natural gas (Mcf)	2,960,551	2,126,674	833,877	39.2
NGL (Bbls)	410,958	198,019	212,939	107.5
Oil equivalent (Boe)	2,371,909	1,298,239	1,073,670	82.7
Average daily sales (Boe/d)	13,104	7,173	5,932	82.7

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Sales volume increased by 1,073,670 Boe (82.7%) to 2,371,909 Boe (13,104 Boe/d) for the six months ended 30 June 2019 compared to 1,298,239 Boe (7,173 Boe/d) for the same period in prior year primarily due to the Company’s 2019 and 2018 drilling program, which was back-loaded in the second half of 2018. The Company had initial production from 8.0 gross (8.0 net) operated wells in the first half of 2019 and 20 gross (20.0 net) operated wells in the second half of 2018.

As at 30 June 2019, the Company was in the process of drilling 2 gross (2.0 net) wells and had 6 gross (6.0 net) wells waiting on completion. In addition, the Company had completed 4.0 gross (4.0 net) wells but delayed turning those wells into sales and left them temporarily shut in to protect them while an offset operator finalized nearby completion activities. All of these wells in progress at 30 June 2019 had initial production prior to the date of this report.

Sales volumes during the six month period were negatively impacted by capacity constraints at a midstream facility. Sundance and its midstream partner completed a capacity expansion of the gas processing plant through the installation of two additional compressors in May 2019. This expansion is expected to sufficiently handle the Company’s current production. The Company is working with the midstream partner for further expansion to support its future development.

Our sales volume is oil‐weighted, with oil representing 62% and 57% of total sales volume for the six‐months ended 30 June 2019 and 2018, respectively, and liquids (oil and NGLs) representing 79% and 73% of total sales volumes for the six-months ended 30 June 2019 and 2018, respectively. Our oil sales and liquid sales volumes as a percentage of total sales volumes was lower during the six months ended 30 June 2019 than what we expect it to be prospectively primarily due to the gassier sales volumes from our Dimmit County assets, which are expected to be disposed of in September 2019. Exclusive of our Dimmit County sales volumes, our oil sales volumes as a percentage of total sales volumes was 64% during the six months ended 30 June 2019 and liquid sales was 81% during the six months ended 30 June 2019.

Oil sales. Oil sales increased by $44.0 million (102.3%) to $86.9 million for the six‐months ended 30 June 2019 from $43.0 million for the same period in prior year. The increase in oil revenue was the result of improved product pricing ($2.4 million) and higher oil production ($41.6 million). Oil sales volumes increased 721,751 Bbls (96.8%) to 1,467,525 Bbls for the six months ended 30 June 2019 compared to 745,774 Bbls for the same period in prior year. The average realised price on the sale of oil increased by 3% to $59.24 per Bbl (a $1.85 per Bbl premium to the average WTI price) for the six months ended 30 June 2019 from $57.64 per Bbl for the same period in prior year.

Natural gas sales. Natural gas sales increased by $1.6 million (30.2%) to $6.8 million for the six months ended 30 June 2019 from $5.2 million for the same period in prior year. The increase in natural gas revenues was the result of increased sales volumes ($2.0 million), partially offset by lower product pricing ($0.5 million). Natural gas sales volumes increased 833,877 Mcf (39.2%) to 2,960,551 Mcf for the six months ended 30 June 2019 compared to 2,126,674 Mcf for the same period in prior year. The average realised price on the sale of natural gas decreased by 6% to $2.29 per Mcf for the six months ended 30 June 2019 from $2.45 per Mcf for the same period in prior year.

NGL sales. NGL sales increased by $2.3 million (51.3%) to $6.9 million for the six months ended 30 June 2019 from $4.6 million for the same period in prior year. The increase in NGL revenues was the result of increased sales volumes ($4.9 million), partially offset by lower product pricing ($2.6 million). NGL sales volumes increased 212,939 Bbls (107.5%) to 410,958 Bbls for the six months ended 30 June 2019 compared to 198,019 Bbls for the same period in prior year. The average realised price on the sale of NGL decreased by 27% to $16.80 per Bbl (29% of average WTI) for the six months ended 30 June 2019 from $23.04 per Bbl (35% of average WTI) for the same period in prior year. NGL prices have worsened relative to WTI since late 2018.


	Six Months Ended June 30,		Change in	Change as
Selected per Boe metrics (US$)	2019	2018	$	%

Total oil, natural gas, NGL revenue	42.43	40.64	1.79	4.4
Lease operating expense (1)	(6.51)	(9.88)	3.37	(34.1)
Workover expense (1)	(1.22)	(1.94)	0.72	(37.1)
Gathering, processing and transportation expense	(2.77)	(0.65)	(2.12)	326.2
Production tax expense	(2.63)	(2.88)	0.25	(8.7)
Depreciation, depletion and amortisation expense	(17.29)	(20.80)	3.51	(16.9)
General and administrative expense	(3.73)	(15.45)	11.72	(75.9)
Total operating costs	(34.15)	(51.60)	17.45	(33.8)
Net operating revenue (costs)	8.28	(10.96)	19.24	175.5

(1)

Lease operating expense and workover expense are included together in lease operating and workover expenses on the condensed consolidated statement of profit or loss and other comprehensive loss.

Lease operating expenses (“LOE”). LOE increased by $2.6 million (20.3%) to $15.4 million for the six‐months ended 30 June 2019 from $12.8 million for the same period in prior year. On a per unit basis, LOE decreased $3.37 per Boe (34.1%) to $6.51 per Boe from $9.88 per Boe. In addition to realizing economies of scale on some of its fixed LOE costs, the Company implemented several cost saving initiatives in early 2019 primarily focused on labor, automating measurements through supervisory control and data acquisition (“SCADA”) and compression, which have resulted in lower LOE on a per Boe basis.

Workover expense. Workover expenses increased by $0.4 million (14.6%) to $2.9 million for the six months ended 30 June 2019 from $2.5 million for the same period in prior year. On a per unit basis, workover expenses decreased $0.72 per Boe (37.1%) to $1.22 per Boe from $1.94 per Boe. The increased sales volumes have diluted the workover costs on a per unit basis due to the wells being brought online recently having higher production, but requiring less workovers.

Gathering, processing and transportation expense (“GP&T”). Our GP&T expense increased by $5.7 million (680.9%) to $6.6 million for the six months ended 30 June 2019 from $0.8 million for the same period in prior year and increased $2.12 per Boe (326.2%) to $2.77 per Boe from $0.65 per Boe. GP&T fees are primarily incurred on production from assets the Company acquired in April 2018. Sales volumes from the acquired assets have increased significantly since the six months ended 30 June 2018. However, we are charged lower GP&T rates by our midstream partner on production from wells we develop on the acquired properties as compared to those that were producing at the time of the acquisition.

Production taxes. Production taxes increased by $2.5 million (66.8%) to $6.2 million for the six months ended 30 June 2019 due to higher revenue, but decreased as a percentage of revenue (6.2% compared to 7.1% in the prior period.) The Eagle Ford properties acquired in 2018 yield lower severance taxes due to higher gas marketing deductions. The increase in production from these properties as a percentage of total production has driven our overall tax rate down as compared to the same prior year period.

Depreciation, depletion and amortisation expense (“DD&A”). DD&A related to development and production assets increased by $14.0 million (51.9%) to $41.0 million for the six months ended 30 June 2019 from $27.0 million for the same period in prior year and decreased $3.51 per Boe (16.9%) to $17.29 per Boe from $20.80 per Boe. The average per well development costs have decreased since prior year, which has driven down the DD&A rate.

Impairment expense. The Company recorded impairment expense of $9.2 million for the six months ended 30 June 2019 to reduce the carrying value of its Dimmit County oil and gas assets, which were classified as held for sale, to the estimated net sales proceeds, less the costs to sell the assets. See Divestitures for additional information. Depreciation and amortisation expense is not recorded on assets held for sale, but would have approximated $2.3 million for the six months ended 30 June 2019.

General and administrative expenses (“G&A”). G&A expenses decreased by $11.2 million (55.9%) to $8.8 million for the six months ended 30 June 2019 from $20.1 million for the same period in prior year. On a per unit basis, G&A expenses decreased $11.72 per Boe (75.9%) to $3.73 per Boe from $15.45 per Boe. The decrease in G&A expenses was due to the Company’s 2018 Eagle Ford acquisition transaction-related costs of $12.4 million, or $9.53 per Boe, in the prior year period.

Finance costs. Finance costs, net of amounts capitalised to development and production assets, increased by $6.4 million (61.7%) to $16.7 million for the six‐months ended 30 June 2019 as compared to $10.3 million in the same period in the prior year. The increase in finance costs during the six months ended 30 June 2019 was primarily driven by an increase in the amount of average outstanding debt during the period of $338 million, compared to $215 million during the prior year, as well as a higher effective interest rate on the Company’s Term Loan, which has a higher margin than the Company’s previous term loan (refinanced in April 2018).

The weighted average interest rate on the Company’s outstanding debt at 30 June 2019 was 8.80%.

Loss on debt extinguishment. There were no debt extinguishment costs incurred in the six months ended 30 June 2019. During the six months ended 30 June 2018, the Company entered into its current Term Loan and Revolving Facility and wrote off the related deferred financing fees for a loss of $2.4 million.

Loss on commodity derivative financial instruments. The Company recognized a net loss on derivative financial instruments during the six months ended 30 June 2019 consisting of $26.6 million of unrealised losses on commodity derivative contracts and $3.6 million of realised gains on commodity derivative contracts. The unrealised loss represents the change in the fair value of the Company’s net commodity derivative position primarily due to the increase in future commodity prices for crude oil since 31 December.

Gain on foreign currency derivative financial instruments. The Company did not have any foreign currency derivatives in place during the six months ended 30 June 2019. During the six months ended 30 June 2018, the Company realised a gain of $6.8 million related to derivative contracts put into place to protect the capital commitments made by investors as part of the Company’s 2018 equity raise from changes in the AUD to USD exchange rate during the period from launch of equity raise to receipt of funds.

Loss on interest rate derivative financial instruments. The Company recognized a net loss on interest rate swaps during the six months ended 30 June 2019 consisting of $4.1 million of unrealised losses on interest rate swap contracts and an insignificant realized gain.

Income tax benefit (expense). The Company recognized income tax benefit of $6.2 million (18%) during the six months ended 30 June 2019. Tax expense differs from the prima facie tax expense at the Company’s statutory income tax rate of 30% due primarily to: $0.3 million of unrecognized tax benefit from current period losses; $3.2 million of tax expense related to US tax rates; and $0.5 million of tax expense related to non-deductible expenses.

Adjusted EBITDAX. The Company uses both IFRS and certain non‐IFRS measures to assess its performance. Management believes Adjusted EBITDAX is useful because it allows it to more effectively evaluate the Company’s operating performance, identify operating trends and compare the results of operations from period to period without regard to financing policies and capital structure. Management excludes the items listed below from profit (loss) attributable to owners of Sundance in arriving at Adjusted EBITDAX, because these amounts can vary substantially from company to company within our industry, depending upon accounting policies and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with IFRS, as issued by the IASB, or as an indicator of the Company’s operating performance or liquidity.

Adjusted EBITDAX is defined as earnings before interest expense, income taxes, depreciation, depletion and amortisation, property impairments, gain/(loss) on sale of non‐current assets, share‐based compensation, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non‐cash or non‐recurring income/expense items. For the six‐months ended 30 June 2019, Adjusted EBITDAX was $65.6 million compared to $21.5 million from the same period in prior year.

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


	Six months ended June 30,
(In US$'000s)	2019	2018

Reconciliation to Adjusted EBITDAX
Loss attributable to owners of the Company	(27,645)	(73,593)
Income tax expense (benefit)	(6,201)	7,610
Finance costs, net of amounts capitalised and interest received	16,727	10,346
Loss on debt extinguishment	—	2,428
Loss on commodity derivative financial instruments	23,057	23,180
Settlement of commodity derivative financial instruments	3,583	(3,894)
Depreciation, depletion and amortization expense	41,265	27,214
Impairment of non-current assets	9,240	21,893
Share-based compensation, value of services	277	186
Transaction-related costs included in general and administrative expenses (1)	1,014	12,377
Loss on interest rate derivative financial instruments	4,026	434
Gain on foreign currency derivatives	—	(6,838)
Other items of expense, net	211	148
Adjusted EBITDAX	65,554	21,491

(1)

Transaction-related costs for the six months ended 30 June 2019 included legal and other professional service fees incurred in connection with the Company’s contemplated re-domiciliation from Australia to the United States. Please see Subsequent Events for more information. For the six months ended 30 June 2018, transaction-costs related to legal, and other professional service fees incurred to complete its Eagle Ford acquisition.

Development

The Company’s development activities during the first half of 2019 totaled $88.7 million, primarily related to drilling costs for 14 gross (14.0 net) operated wells, and completion costs for 12 gross (12.0 net) wells, of which eight wells had initial production in the first half of 2019. As at 30 June 2019, the Company was in the process of drilling 2 gross (2.0 net) wells, with 6 gross (6.0 net) Sundance-operated wells waiting on completion. The Company additionally competed 4 gross (4.0 net) wells but delayed turning those wells into sales and left them temporarily shut in to protect them while an offset operator finalized nearby completion activities. As of the date of this report, all 12 gross (12.0 net) wells in progress at 30 June 2019 have had initial production.

Of the wells with initial production in the first six months of 2019, 4.0 net wells were drilled on legacy acreage (2.0 of which are located in Dimmit County and will be part of the asset sale expected to close in September 2019) and 4.0 net wells were drilled on acreage acquired in 2018.

Divestitures

In July 2019, the Company entered into a definitive agreement to sell its interest in 19 gross producing wells located on approximately 6,100 net acres located in Dimmit County, Texas for $16.5 million, plus reimbursement for capital expenditures for two wells drilled, completed and equipped subsequent to effective date (approximately $13.0 million), less other customary effective date to closing date adjustments (currently estimated at $6.2 million). The Company expects the sale to close in September 2019. Production from these wells was approximately 1,200 Boe/d during the six months ended 30 June 2019. The borrowing base on the Company’s Revolving Credit Facility is not expected to be impacted by the sale.

Financial Position and Liquidity

The Company’s primary sources of liquidity include, cash provided by operating activities and borrowings under its Credit Facilities. In addition, the Company has from time to time, divested of non-core assets, as described in Divestitures above.

As at 30 June 2019, the Company had $1.0 million of cash and equivalents. The Company had $250.0 million outstanding on its Term Loan, $105 million outstanding on its Revolving Facility and letters of credit totaling $16.4 million as of 30 June 2019. In May 2019, the borrowing base on its Revolving Facility was increased from $122.5 million to $170.0 million, leaving available borrowing capacity of $48.6 million. Subsequent to 30 June 2019, the Company drew down an additional $10 million on the Revolving Facility. The Company is focused on maintaining its future capital expenditure development within cash flow from operations and preserving its existing available liquidity. Other than as disclosed herein this report, the Company does not anticipate any additional draws on its Revolving Facility to fund the remainder of its 2019 capital program.

The Company’s credit facility covenants include maintaining a minimum Current Ratio of 1.0, a maximum Total Debt to EBITDAX Ratio of 4.0, a minimum Interest Coverage Ratio of 2.0 and a minimum Asset Coverage Ratio (PV9 of proved reserves to total debt) of at least 1.5. The Company was in compliance with its covenants as at 30 June 2019. Of these covenants, the Company’s business is most sensitive to the Current Ratio, which may be impacted by fluctuations in commodity prices and the Company’s pace of development.

Following is a summary of the Company’s open oil and natural gas derivative contracts at 30 June 2019:


Oil Derivatives	Weighted Average WTI/LLS (1)(2)(3)					Weighted Average Brent (1)
Year	Units (Bbls)	Floor		Ceiling		Units (Bbls)	Floor		Ceiling
Remaining 2019	1,044,000	$	61.02	$	67.07	435,000	$	58.77	$	71.00
2020	2,046,000	$	56.92	$	60.49	—	$	—	$	—
2021	732,000	$	50.37	$	59.34	—	$	—	$	—
2022	528,000	$	45.68	$	60.83	—	$	—	$	—
2023	160,000	$	40.00	$	63.10	—	$	—	$	—
Total	4,510,000	$	54.89	$	61.96	435,000	$	58.77	$	71.00


Gas Derivatives (HH/HSC)	Weighted Average (1)(3)
Year	Units (Mcf)	Floor		Ceiling
Remaining 2019	1,566,000	$	2.86	$	3.13
2020	1,536,000	$	2.65	$	2.70
2021	1,200,000	$	2.66	$	2.66
2022	1,080,000	$	2.69	$	2.69
2023	240,000	$	2.64	$	2.64
Total	5,622,000	$	2.72	$	2.81

(1)

The Company’s outstanding derivative positions include swaps totaling 1,755,000 Bbls and 4,890,000 Mcf, which are included in both the weighted average floor and ceiling value. Additionally, certain volumes in the table above are subject to 3-way collars. 300,000 Bbls in each 2020, 2021 and 2022 contain an additional short put option with a $35 strike price. The put option strike price is not factored into the floor in the table above.

(2)

WTI pricing includes the impact of WTI-Magellan East Houston basis swaps in place through 2021.

(3)

Pricing defined as follows: West Texas Intermediate (“WTI”), Louisiana Light Sweet (“LLS”), Henry Hub (“HH”) and Houston Ship Channel (“HSC”).

In addition to the oil and natural gas derivatives, the Company had outstanding derivative positions related to propane call options sold in July 2018. A total of 167,000 barrels with a strike price of $0.76 per unit is contracted for the remainder of 2019 and 271,000 barrels with a strike price of $0.70 per unit is contracted in 2020.

Subsequent to 30 June 2019, the Company entered into additional derivative swap contracts for 120,000 mcf, 420,000 mcf and 90,000 mcf for the years 2019, 2020 and 2021 with an weighted average price of $2.79/mcf, $2.67/mcf and $2.62 mcf, respectively.

Commitments

The Company has long-term midstream contracts in place for gathering, processing, transportation and marketing of produced volumes from the Eagle Ford assets it acquired in 2018. The contracts contain commitments to deliver oil, natural gas and NGL volumes to meet minimum revenue commitments (“MRC”), with $63.4 million remaining through 2022, a portion of which are secured by letters of credit and performance bonds. Under the terms of the contract, if the Company fails to deliver the minimum revenue commitments, it is required to pay a deficiency payment equal to the shortfall. If the volumes and associated fees are in excess of the MRC in any year, the overage can be applied to reduce the commitment in the subsequent years. The amount of the shortfall, if any, that may exist at 31 December 2019 will depend on the timing of well completions and the associated produced volumes on the new wells. The shortfall is not expected to be material for the year ended 31 December 2019.

Subsequent Events

On 11 September 2019, the Company announced a proposed Scheme of Arrangement to re-domicile the Company from Australia to the United States (the “Scheme”). The Scheme is subject to shareholder, judicial and regulatory approvals. If the Scheme is approved, the Company will transfer its primary listing to the NASDAQ Stock Market and cease to be traded on the Australian Securities Exchange. The Company’s Board of Directors unanimously recommended that the Company’s shareholders vote in favor of the Scheme. The Scheme Meeting is expected to be held in November 2019, and if approved, the Scheme is expected to be implemented in November 2019.

Auditor’s Declaration

The auditor’s independence declaration as required under section 307C of the Corporations Act 2001 is set out on page 8 for the half‐year ended 30 June 2019 financial report.

Signed in accordance with a resolution of the Board of Directors.

MIKE HANNELL SIGNATURE CROPPED

Michael Hannell

Chairman

Adelaide

Dated this 13th day of September 2019


	Deloitte Touche Tohmatsu A.C.N. 74 490 121 060

	Grosvenor Place 225 George Street Sydney NSW 2000 PO Box N250 Grosvenor Place Sydney NSW 1217 Australia
	DX 10307SSE Tel: +61 (0) 2 9322 7000 Fax: +61 (0) 2 9322 7001 www.deloitte.com.au

The Board of Directors

Sundance Energy Australia Limited

Ground Floor

28 Greenhill Road

Wayville, South Australia, 5034

13 September 2019

Dear Board Members,

Sundance Energy Australia Limited

In accordance with section 307C of the Corporations Act 2001, I am pleased to provide the following declaration of independence to the directors of Sundance Energy Australia Limited.

As lead audit partner for the review of the financial statements of Sundance Energy Australia Limited for the half-year ended 30 June 2019, I declare that to the best of my knowledge and belief, there have been no contraventions of:

(i)

the auditor independence requirements of the Corporations Act 2001 in relation to the review; and

(ii)

any applicable code of professional conduct in relation to the review.

Yours sincerely,

DELOITTE TOUCHE TOHMATSU

Jason Thorne

Partner

Chartered Accountant

Liability limited by a scheme approved under Professional Standards Legislation

Member of Deloitte Asia Pacific Limited and the Deloitte Network.

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


		2019		2018
For the six months ended June 30,	Note	US$’000		US$’000

Oil, natural gas and NGL revenue	3	$	100,641	$	52,765
Lease operating and workover expense	4		(18,320)		(15,343)
Gathering, processing and transportation expense			(6,560)		(840)
Production taxes			(6,237)		(3,739)
General and administrative expense	5		(8,844)		(20,052)
Depreciation, depletion and amortisation expense			(41,265)		(27,214)
Impairment expense	6		(9,240)		(21,893)
Finance costs, net of amounts capitalised			(16,727)		(10,346)
Loss on debt extinguishment			—		(2,428)
Loss on commodity derivative financial instruments	13		(23,057)		(23,180)
Gain on foreign currency derivative financial instruments	13		—		6,838
Loss on interest rate derivative financial instruments	13		(4,026)		(434)
Other expense, net			(211)		(117)
Loss before income tax			(33,846)		(65,983)
Income tax benefit (expense)	7		6,201		(7,610)
Loss attributable to owners of the Company			(27,645)		(73,593)
Other comprehensive income
Items that may be subsequently reclassified to profit or loss:
Exchange differences arising on translation of foreign operations (no income tax effect)			17		259
Other comprehensive income			17		259
Total comprehensive loss attributable to owners of the Company		$	(27,628)	$	(73,334)

Loss per share			(cents)		(cents)
Basic	8		(4.0)		(20.6)
Diluted	8		(4.0)		(20.6)

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

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)


		30 June 2019		31 December 2018
As at 31 December	Note	US$’000		US$’000

CURRENT ASSETS
Cash and cash equivalents			977		1,581
Trade and other receivables			14,316		21,249
Derivative financial instruments	13		4,123		24,315
Income tax receivable			2,307		2,384
Other current assets			3,907		3,546
Assets held for sale	10		23,746		24,284
TOTAL CURRENT ASSETS			49,376		77,359

NON-CURRENT ASSETS
Development and production assets			674,887		633,400
Exploration and evaluation assets			80,231		79,470
Property and equipment			990		1,354
Income tax receivable, non-current			2,344		2,344
Derivative financial instruments	13		2,033		8,003
Lease right-of-use assets	9		13,116		—
Other non-current assets			149		149
TOTAL NON-CURRENT ASSETS			773,750		724,720
TOTAL ASSETS			823,126		802,079

CURRENT LIABILITIES
Trade and other payables			21,839		34,796
Accrued expenses			41,238		35,223
Derivative financial instruments	13		2,218		436
Lease liabilities, current	9		7,250		—
Provisions, current	11		1,027		900
Liabilities related to assets held for sale	10		1,245		1,125
TOTAL CURRENT LIABILITIES			74,817		72,480

NON-CURRENT LIABILITIES
Credit facilities, net of deferred financing fees	12		341,922		300,440
Restoration provision			19,179		16,544
Other provisions, non-current	11		986		1,090
Derivative financial instruments	13		5,288		2,578
Lease liabilities, non-current	9		5,913		—
Deferred tax liabilities	7		8,912		15,189
Other non-current liabilities			85		383
TOTAL NON-CURRENT LIABILITIES			382,285		336,224
TOTAL LIABILITIES			457,102		408,704
NET ASSETS			366,024		393,375

EQUITY
Issued capital	15		615,984		615,984
Share-based payments reserve			17,042		16,765
Foreign currency translation reserve			(689)		(706)
Accumulated deficit			(266,313)		(238,668)
TOTAL EQUITY			366,024		393,375

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

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)


			Foreign
		Share-Based	Currency
	Issued	Payments	Translation	Accumulated
	Capital	Reserve	Reserve	Deficit	Total
	US$’000	US$’000	US$’000	US$’000	US$’000
Balance at 31 December 2017	372,764	16,250	(1,134)	(210,529)	177,351
Loss attributable to owners of the Company	—	—	—	(73,593)	(73,593)
Other comprehensive income for the year	—	—	259	—	259
Total comprehensive income (loss)	—	—	259	(73,593)	(73,334)
Shares issued in connection with private placement	253,517	—	—	—	253,517
Cost of capital, net of tax	(10,297)	—	—	—	(10,297)
Share-based compensation value of services	—	186	—	—	186
Balance at 30 June 2018	615,984	16,436	(875)	(284,122)	347,423
Balance at 31 December 2018	615,984	16,765	(706)	(238,668)	393,375
Loss attributable to owners of the Company	—	—	—	(27,645)	(27,645)
Other comprehensive income for the year	—	—	17	—	17
Total comprehensive income (loss)	—	—	17	(27,645)	(27,628)
Share-based compensation value of services	—	277	—	—	277
Balance at 30 June 2019	615,984	17,042	(689)	(266,313)	366,024

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


		2019	2018
For the six months ended June 30,	Note	US$’000	US$’000
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from sales		102,867	49,620
Payments to suppliers and employees		(40,250)	(27,922)
Payments of transaction-related costs		—	(13,282)
Settlements of restoration provision		(116)	(29)
Receipts from (payments for) commodity derivative settlements, net		6,638	(3,667)
Federal withholding tax paid		—	(2,301)
NET CASH PROVIDED BY OPERATING ACTIVITIES		69,139	2,419

CASH FLOWS FROM INVESTING ACTIVITIES
Payments for development assets		(88,123)	(40,717)
Payments for exploration assets		(564)	(1,927)
Payments for acquisition of oil and gas properties	2	—	(220,132)
Sale of non-current assets		50	—
Payments for property and equipment		(120)	(79)
NET CASH USED IN INVESTING ACTIVITIES		(88,757)	(262,855)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of shares		—	253,517
Payments for costs of equity capital raisings		—	(10,260)
Receipts from interest rate derivative settlements		42	—
Borrowing costs paid, net of capitalised portion		(14,851)	(12,436)
Deferred financing fees capitalised		(232)	(16,724)
Receipts from foreign currency derivatives		—	6,849
Proceeds from borrowings	12	40,000	250,000
Repayments of borrowings	12	—	(210,194)
Payments of lease liabilities	9	(5,947)	—
NET CASH PROVIDED BY FINANCING ACTIVITIES		19,012	260,752

Net increase (decrease) in cash and cash equivalents		(606)	316

Cash and cash equivalents at beginning of year		1,581	5,761
Effect of exchange rates on cash		2	180
CASH AND CASH EQUIVALENTS AT END OF YEAR		977	6,257

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

NOTE 1 — BASIS OF PREPARATION

The unaudited general purpose financial statements of Sundance Energy Australia Limited (“SEAL”) and its wholly owned subsidiaries, (collectively, the “Company”, “Consolidated Group” or “Group”), for the interim half‐year reporting period ended 30 June 2019 have been prepared in accordance with the Corporations Act 2001 and Australian Accounting Standards Board (“AASB”) 134 Interim Financial Reporting. These condensed consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

The interim condensed consolidated financial statements do not include all the information and disclosures required in the annual financial statements, and should be read in conjunction with the Company’s annual financial statements as at 31 December 2018 and any public announcements made by the Company during the interim reporting period in accordance with the continuous disclosure requirements of the Corporations Act 2001.

The accounting policies and methods of computation that are discussed in Note 1 of the Company’s 31 December 2018 annual financial statements have been consistently applied to the half‐year reporting period ended 30 June 2019 except as described below.

On 1 January 2019, the Company adopted AASB 16/IFRS 16 - Leases. The objective of the new standard is to increase transparency and comparability among entities by recognizing lease assets and liabilities on the statement of financial position and providing relevant information about the leasing arrangements. The Company operates predominantly as a lessee. To meet the standard’s objective, a lessee applies a single comprehensive model to recognize assets and liabilities arising from a lease on the statement of financial position, and depreciation on the right-of-use asset together with interest on the lease liability on the statement of profit or loss and other comprehensive income (loss). The standard was required to be adopted by the Company using either the full retrospective approach, with all the prior periods presented adjusted, or the cumulative catch-up approach, which allows the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at 1 January 2019 to be made for the difference between the right-of-use asset and liability recorded. The Company elected the cumulative catch-up approach. Adoption of the standard resulted in the recognition of additional lease right-of-use assets and lease liabilities on the condensed consolidated statement of financial position, reclassification of certain costs on the condensed consolidated statement of cash flows from operating or investing activities to financing activities, as well as additional disclosures. The adoption did not have a material impact to the Company’s condensed consolidated statements of profit or loss and other comprehensive income (loss). Refer to Note 9 for further information on the Company’s implementation of this standard.

The condensed consolidated financial statements and accompanying notes are presented in U.S. dollars and all values are rounded to the nearest thousand (US$’000), except where stated otherwise. Certain prior period balances on the condensed consolidated statements of profit or loss and other comprehensive loss have been reclassified to conform to current year presentation. Such reclassifications had no impact on loss attributable to owners of the Company.

NOTE 2 — ACQUISITIONS

Acquisitions in 2019

There were no significant acquisitions during the six months ended 30 June 2019.

Acquisitions in 2018

On 23 April 2018, the Company’s wholly owned subsidiary Sundance Energy, Inc. acquired from Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC (collectively the “Sellers”) approximately 21,900 net acres in the Eagle Ford in McMullen, Live Oak, Atascosa and La Salle counties, Texas for a cash purchase price of $215.8 million. The acquisition included varying working interests in 132 gross (98.0 net) wells.

The acquisition was recorded using the acquisition method of accounting. The following table reflects the fair value of the assets acquired and the liabilities assumed as at the date of acquisition (in thousands):


Fair value of assets acquired:
Development and production assets	$	179,662
Exploration and evaluation assets		43,642
Fair value of liabilities assumed:
Restoration provision		(7,435)
Trade and other payables		(80)
Net assets acquired	$	215,789

Purchase price:
Total cash consideration paid (1)	$	215,789

(1)

During the six months ended 30 June 2018, the Company paid $220.1 million to the sellers to purchase the Eagle Ford assets. In the second half of 2018, the Company received $4.4 million from the sellers to settle post-closing adjustments, for a total purchase price of $215.8 million.

Revenues of $5.3 million and net income, excluding general and administrative costs (which could not be practically estimated) and the impact of income taxes, of $1.9 million were generated from the acquired properties from 23 April 2018 through 30 June 2018.

NOTE 3 – REVENUE

Revenue from Contracts with Customers

The Company recognizes revenue from the sale of oil, natural gas and natural gas liquids (“NGLs”) in the period that the performance obligations are satisfied. The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas, or NGLs at a delivery point. Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through monthly delivery of oil, natural gas and NGLs. Under certain of the Company’s marketing arrangements, the Company maintains control of the product during gathering, processing, and transportation, and these costs are recorded as gathering, processing and transportation expenses on the condensed consolidated statement of profit or loss and other comprehensive loss. Such fees that are incurred after control of the product has transferred are recorded as a reduction to the transaction price.

The Company’s contracts with customers typically require payment for oil, natural gas and NGL sales within one to two months following the calendar month of delivery. The sales of oil, natural gas and NGLs typically include variable consideration that is based on pricing tied to local indices adjusted for fees and differentials and the quantity of volumes delivered. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated based on published commodity price indexes and metered production volumes, and amounts due from customers are accrued in trade and other receivables on the condensed consolidated statements of financial position. At 30 June 2019, the Company’s receivables from contracts with customers totaled $12.1 million. Variances between the Company’s estimated revenue and actual payments are recorded in the month of payment. These variances have not historically been material.

Disaggregation of Revenue

Below the Company has presented disaggregated revenue by product type.


	2019	2018
Six months ended 30 June	US$’000	US$’000
Oil revenue	86,943	42,986
Natural gas revenue	6,794	5,217
NGL revenue	6,904	4,562
Total revenue	100,641	52,765

Substantially all of the Company’s revenues are from contracts with customers.

NOTE 4 — LEASE OPERATING EXPENSES


	2019	2018
Six months ended 30 June	US$’000	US$’000
Lease operating expense	(15,435)	(12,826)
Workover expense	(2,885)	(2,517)
Total lease operating and workover expense	(18,320)	(15,343)

NOTE 5 — GENERAL AND ADMINISTRATIVE EXPENSES


	2019	2018
Six months ended 30 June	US$’000	US$’000
Employee benefits expense, including salaries and wages, net of capitalised overhead	(3,113)	(3,785)
Share-based payments expense (1)	(277)	(186)
Transaction related expense (2)	(1,033)	(12,377)
Other administrative expense	(4,421)	(3,704)
Total general and administrative expenses	(8,844)	(20,052)

(1)

Share-based payment expense includes expense associated with restricted share units and deferred cash awards. See Note 16

(2)

The 2019 amount relates to the Company’s contemplated re-domiciliation from Australia to the United States. See Note 20. The 2018 amount relates to costs incurred in conjunction with its Eagle Ford acquisition. See Note 2.

NOTE 6 — IMPAIRMENT OF ASSETS

Non-current oil and gas assets

At 30 June 2019, the Group reassessed the carrying amount of its non‐current Eagle Ford assets for indicators of impairment or whether there was any indication that an impairment loss may no longer exist or may have decreased in accordance with the Group’s accounting policy. As at 30 June 2019, the Company’s market capitalisation was lower than the net book value of the Company’s net assets, which is deemed to be an indicator of impairment as described by IAS 36. As a result, the Company believes that under the prescribed accounting guidance there was indication that an impairment may exist related to its development and production assets and performed an impairment analysis. There was no indication of impairment or reversal of impairment related to its exploration and evaluation assets.

The Company estimated the value-in-use (“VIU”) of the development and production assets using the income approach (Level 3 on fair value hierarchy) based on the estimated discounted future cash flows from the assets. The model took into account management’s best estimate for pricing and discount rates, as described below.

Future commodity price assumptions are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. Future prices ($ per Bbl) used for the 30 June 2019 VIU calculation were as follows:



	1 July 2019- 30 June 2020		1 July 2020- 30 June 2021		1 July 2021- 30 June 2022		1 July 2022- 30 June 2023		1 July 2023- 30 June 2024		1 July 2024 and thereafter
Oil (WTI)	$	57.50	$	60.00	$	62.50	$	65.00	$	67.50	$	70.00
Oil (Brent)	$	65.00	$	66.00	$	67.00	$	68.00	$	69.00	$	70.00

The pre-tax discount rates that have been applied to the development and production assets were 10.0% and 20.0% for proved developed producing and proved undeveloped properties, respectively.

Management’s estimate of the recoverable amount using the VIU model as at 30 June 2019 exceeded the carrying cost of development and production and therefore no impairment was required.

Dimmit County Assets Held For Sale

In accordance with IFRS 5, assets held for sale are to be measured at the lower of fair value less cost to sell (“FVLCS”) or the carrying value of the assets. In July 2019, the Company entered into a definitive agreement to sell the Dimmit County assets for $16.5 million, plus reimbursement for capital expenditures for two wells drilled, completed and equipped subsequent to effective date (approximately $13.0 million), less other customary effective date closing date adjustments (estimated at $6.2 million). The Company expects to close on the sale in late September 2019. The effective date of the transaction will be 1 November 2018. The Company wrote down the asset group to the expected adjusted purchase price proceeds, less anticipated external broker marketing costs, which resulted in year-to-date impairment expense of $9.2 million. Depletion is not recorded for the disposal group when classified for sale. Any further adverse changes in any of the key assumptions may result in future impairments or a loss on sale at the time of disposition if and when the disposal group is sold.

Cooper Basin

The Company recorded impairment expense of $20 thousand during the six months ended 30 June 2019 for additional costs incurred by the operator and billed to the Company (net to its interest) at the Cooper Basin during the period. The Company continues to carry the asset value at nil value. Impairment totaled $0.7 million during the six months ended 30 June 2018.

NOTE 7 – INCOME TAX EXPENSE

During the six months ended 30 June 2019 the Company recognized income tax benefit of $6.2 million on a pre-tax loss of $33.8 million, representing 18% of pre-tax loss. Tax expense consists of $0.1 million in current tax expense and $6.3 million of deferred tax benefit. Tax expense differs from the prima facie tax expense at the Group’s statutory income tax rate of 30% due primarily to: $0.3 million of unrecognized tax benefit from current period losses; $3.2 million of tax expense related to US tax rates; and $0.5 million of tax expense related to non-deductible expenses.

The Company reported a net deferred tax liability of $8.9 million at 30 June 2019.

NOTE 8 — EARNINGS (LOSS) PER SHARE (“EPS”)


	2019	2018
Six months ended 30 June	US$’000	US$’000
Loss for periods used to calculate basic and diluted EPS	(27,645)	(73,593)
Earnings per share (cents)	(4.0)	(20.6)


	Number	Number
	of shares	of shares
a) -Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS (1)	687,404,775	357,306,968
b) -Incremental shares related to options and restricted share units(2)	—	—
c) -Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS	687,404,775	357,306,968

(1)

All share numbers have been retroactively adjusted for the 2018 periods to reflect the Company’s one-for-ten share consolidation in December 2018, as described in Note 15.

(2)

Incremental shares related to restricted share units were excluded from 30 June 2019 and 2018 weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS as the outstanding shares would be anti-dilutive to the loss per share calculation for the period then ended.

NOTE 9 – LEASES

Adoption and transition

Effective 1 January 2019, the Company adopted AASB 16/IFRS 16 – Leases (“IFRS 16”), under the cumulative catch-up approach, which requires lessees to recognize lease liabilities and right-of-use assets on the statement of financial position at the date of initial application, for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Accordingly, the 2019 financial statements are not comparable with respect to leases in effect for all periods prior to 1 January 2019.

The Company has applied the following elections and transition practical expedients upon adoption of IFRS 16 on 1 January 2019:

Grandfathering of previous conclusions reached under AASB 117/IAS 17- Leases (replaced by IFRS 16) the previous as to whether existing contracts are or contain leases;

Use of hindsight in assessing the lease term;

Exemption from recognition, measurement, and presentation provisions for short-term lease arrangements in certain classes of assets;

Exemption from separation of lease components, such as amounts for related taxes and common area maintenance charges, in certain classes of assets;

General provisions and discount rates applied to certain portfolios of leases with reasonably similar characteristics; and

Measurement of right-of-use assets at an amount equal to the respective lease liabilities, as adjusted for accruals and prepayments to initial application.

As a result of these elections, the adoption of the standard did not result in the Company recognizing a cumulative-effect adjustment to accumulated deficit as of 1 January 2019.

Accounting policies for leases

The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at date of inception. The arrangement is assessed to determine whether its fulfillment is dependent on the use of a specific asset or assets and whether the arrangement conveys a right to use the asset, even if that right is not explicitly specified in an arrangement. Right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease obligations represent the Company’s obligation to make lease payments.

The right-of-use asset is initially measured to be equal to the lease liability and adjusted for any lease incentives received and initial direct costs incurred. Subsequently the right-of-use asset is measured at cost less any accumulated depreciation and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the Company’s incremental borrowing rate, which has been derived from rates expected to be available under the Company’s Revolving Credit Facility. The Company was required to use its incremental borrowing rate in discounting its lease liabilities at 1 January 2019 due to selection of the cumulative catch-up adoption approach. Future variable payments such as for demobilization of the underlying leased asset have typically been excluded from the calculation of the lease liabilities unless they are determinable. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, or for changes to the expected lease term. During the six months ended 30 June 2019, the Company amended its Revolving Credit Facility to increase its borrowing capacity and reduce the interest rate margin charged under the agreement. During this period, the Company had additions of $7,653 of right-of-use assets, representing approximately 58% of its ending right-of-use assets. As a result, the Company elected to remeasure its lease assets and liabilities using its incremental borrowing rate as at 30 June 2019. The weighted-average rate applied was 4.76%. The weighted-average incremental borrowing rate at initial application on 1 January 2019 was 5.21%.

The Company enters into leases as needed to conduct its normal operations. The Company had leases primarily for its use of compression equipment, drilling rig, land right of way and surface use arrangements, other production equipment, such as amine treatment equipment, and office facilities and equipment. Most of the Company’s leasing arrangements are under three years in contractual duration, and include extension and termination options, including evergreen provisions, all of which provide the Company flexibility in retaining the underlying facilities and equipment as well as some protection from future price variability, when extension terms are accompanied by future pricing indices. The Company’s leases are typically not significant enough individually or in the aggregate to impose or affect restrictions in its borrowing capacity or financial covenants.

All payments for short-term leases are recognized in income on a straight-line basis over the lease term. Additionally, any variable payments, which are generally related to the corresponding utilization of the asset or future demobilization costs, are recognized in the period in which the obligation was incurred.

The Company has applied judgement to determine the lease term for some of its lease contracts which include renewal or termination options. Certain of our leases include an “evergreen” provision that allows the contract term to continue on a month-to-month basis following expiration of the initial term included in the contract. For leases with an evergreen provision that was in effect during the six months ended 30 June 2019, the term of the lease was re-assessed by the Company and determined to be the noncancelable period in the contract, plus the period beyond that cancellation period that the Company believes it is reasonably certain it will need the equipment for operational purposes. This re-assessment affects the value of right-of-use assets and lease liabilities recognized at 30 June 2019.

In the event that there is a modification to a lease arrangement, a determination of whether the modification results in a separate lease arrangement being recognized is made. If the modification results in the recognition of a separate lease arrangement, due to an increase in scope of a lease for example through additional underlying leased assets being added and a commensurate increase in lease payments, the Company measures the new arrangement separately, accounting for it as a new lease. If the modification does not result in a separate lease arrangement, for example due to an extension of the lease term that does not exceed the life of the underlying asset, the Company remeasures the remaining lease liability from the effective date of the modification using the redetermined lease term, remaining future lease payments and applicable discount rate. A corresponding adjustment is made to the carrying amount of the associated right-of-use asset. If there has been a partial or full termination of a lease, the Company recognizes any resulting gain or loss in the condensed consolidated statement of profit or loss and other comprehensive income (loss).

Lease arrangements and supplemental disclosures

The following items of income and expense are reflected on the condensed consolidated statement of profit or loss and other comprehensive income (loss) related to the Company’s leases:


		Six months ended
	Classification	30 June 2019

Total Lease Cost
Depreciation charge for right-of-use assets:
Compression	Lease operating and workover expenses	1,171
Drilling rig	(1)	-
Land right of way and surface use	Lease operating and workover expenses	40
Office facilities and equipment	General and administrative expense	338
Other production equipment	Lease operating and workover expenses	366
Total depreciation charge for right-of-use assets:		1,915
Interest on lease liabilities	Finance costs, net of amounts capitalised	128
Total lease cost		2,043

Short-term lease expense		671
Sublease income		149

(1)

Depreciation of $4,166 was capitalized to development and production assets on the condensed consolidated statement of financial position and will be depleted in accordance with the Company’s policies.

The following carrying amounts of the right-of-use assets (net of accumulated depreciation) are reflected on the condensed consolidated statement of financial position related to the Company’s leases:


Leases		30 June 2019
Compression		7,563
Drilling rig		3,642
Land right of way and surface use		819
Office facilities and equipment		367
Other production equipment		725
Total right-of-use assets		13,116

The Company’s lease obligations as of 30 June 2019 will mature as follows:


		30 June 2019
Less than 1 year		7,370
1-3 years		4,339
3-5 years		1,800
More than 5 years		948
Total lease payments		14,457
Less: interest		(1,294)
Total discounted lease payments		13,163

Subsequent to 30 June 2019, the Company entered into additional compression and office facility obligations that will result in the recognition of additional right-of-use assets and lease obligations of $2.1 million.

NOTE 10 — ASSETS HELD FOR SALE

The condensed consolidated statement of financial position includes assets and liabilities held for sale, comprised of the following:


	30 June 2019	31 December 2018
	US$’000	US$’000

Eagle Ford - Dimmit County oil and gas assets	23,746	24,284
Total assets held for sale	23,746	24,284

Restoration provision associated with assets held for sale	1,245	1,125
Total liabilities related to assets held for sale	1,245	1,125

In June 2017, the Company committed to a plan to sell its assets located in Dimmit County, Texas. The assets to be sold include developed and production assets and exploration and evaluation expenditures. In July 2019, the Company entered into a definitive agreement to sell the Dimmit County assets for $16.5 million, plus reimbursement for capital expenditures for two wells drilled, completed and equipped subsequent to the effective date (approximately $13.0 million), less other customary effective date to closing date adjustments (estimated at $6.2 million). The Company expects to close on the sale in late September 2019. Sale of the Dimmit assets will provide additional capital for further development of the Company’s core assets in McMullen, Atascosa, Live Oak and La Salle counties.

The Company wrote-down the carrying value of the Dimmit disposal group during the six months ended 30 June 2019. Depletion is not recorded for the disposal group when classified for sale. See Note 6 for additional information.

NOTE 11 — OTHER PROVISIONS


		30 June 2019
		US$’000
Balance at beginning of period		1,990
Changes in estimates		570
Settlements		(580)
Unwinding of discount		33
Balance at end of period (1)		2,013

(1)As at 30 June 2019 $1.0 million was classified as current.

In 2016 the Company entered into an agreement with Schlumberger Limited (“Schlumberger”) to re‐fracture five Eagle Ford wells. Under the terms of the agreement, Schlumberger will be paid for the services, plus a premium (if applicable), from the incremental production generated by the re‐fractured wells above the forecasted base production prior to the re‐fracture work. The term of the agreement is five years, expiring in 2021. The estimate of the payout amount requires judgements regarding future production, pricing, operating costs and discount rates.

NOTE 12 — CREDIT FACILITIES


	30 June 2019	31 December 2018
	US$'000	US$'000
Revolving Facility	105,000	65,000
Term Loan	250,000	250,000
Total credit facilities	355,000	315,000
Deferred financing fees, net of accumulated amortisation	(13,078)	(14,560)
Total credit facilities, net of deferred financing fees	341,922	300,440

On 23 April 2018, contemporaneous with the closing of its Eagle Ford acquisition, the Company entered into a $250.0 million syndicated second lien term loan with Morgan Stanley Energy Capital, as administrative agent, (the “Term Loan”), and a syndicated revolver with Natixis, New York Branch, as administrative agent, (the “Revolving Facility”) ($250.0 million face).

The Revolving Facility and Term Loan are secured by certain of the Company’s oil and gas properties. The Revolving Facility is subject to a borrowing base, which is redetermined at least semi-annually. In May 2019, the borrowing base was increased from $122.5 million to $170.0 million. The next of such redeterminations will occur in the fourth quarter of 2019. The Revolving Facility has a 4 1/2 year term (matures in October 2022) and the Term Loan has a five year term (matures in April 2023). If upon any downward adjustment of the borrowing base, the outstanding borrowings are in excess of the revised borrowing base, the Company may have to repay its indebtedness in excess of the borrowing base immediately, or in five monthly installments.

Interest on the Revolving Facility accrues at a rate equal to LIBOR, plus a margin, depending on the level of funds borrowed. As of 30 June 2019, the margin ranged from 2.25% to 3.25% (2.5% to 3.5% prior to May 2019). Interest on the Term Loan accrues at a rate equal to the greater of (i) LIBOR plus 8% or (ii) 9%.

The Company is required under our credit agreements to maintain the following financial ratios:

a minimum Current Ratio, consisting of consolidated current assets (as defined in the Revolving Facility) including undrawn borrowing capacity to consolidated current liabilities (as defined in the Revolving Facility), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter;

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

a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Revolving Facility), of not less than 2.0 to 1.0 as of the last day of any fiscal quarter; and

An Asset Coverage Ratio, consisting of Total Proved PV9% to Total Debt (as defined in the Term Loan agreement), of not less than 1.50 to 1.0.

As at 30 June 2019, the Company was in compliance with all restrictive financial and other covenants under the Term Loan and Revolving Facility.

The Company had letters of credit of $16.4 million outstanding on the Revolving Facility and $48.6 million of available borrowing capacity at 30 June 2019. Subsequent to 30 June 2019, the Company drew an additional $10.0 million on the Revolving Facility.

NOTE 13 — DERIVATIVE FINANCIAL INSTRUMENTS


	30 June 2019	31 December 2018
	US$’000	US$’000
FINANCIAL ASSETS:
Current
Derivative financial instruments — commodity contracts	4,123	24,315
Non-current
Derivative financial instruments — commodity contracts	2,033	8,003
Total financial assets	6,156	32,318

FINANCIAL LIABILITIES:
Current
Derivative financial instruments — commodity contracts	389	225
Derivative financial instruments — interest rate swaps	1,829	211
Non-current
Derivative financial instruments — commodity contracts	912	651
Derivative financial instruments — interest rate swaps	4,376	1,927
Total financial liabilities	7,506	3,014

The Company incurred a loss of $23.1 million related to its commodity derivative financial instruments during the six months ended 30 June 2019, consisting of a $26.6 million unrealised loss resulting from the change in fair value of the commodity derivative financial instruments, offset by a $3.6 million realised gain from the settlement of commodity derivative contracts. The commodity derivative activity has been recognised in the condensed consolidated statement of profit or loss and other comprehensive loss within loss on commodity derivative financial instruments, net.

Realised gains on the Company interest rate swap of $41.6 thousand and unrealised losses of $4.1 million for the six months ended 30 June 2019, respectively, were recognized in the condensed consolidated statement of profit or loss and other comprehensive loss within loss on interest rate derivative financial instruments.

In March 2018, the Company entered into short-term foreign currency derivative instruments to lock in the exchange rate for A$284 million. The instruments were designed to protect the funds generated in its equity raise from currency fluctuations during the period between launch of the equity raise and receipt of funds. The Company realized a gain of $6.8 million on the foreign currency derivative instruments during the six months ended 30 June 2018, which was recognized in the condensed consolidated statement of profit or loss and other comprehensive loss within gain on foreign currency derivative financial instruments. There were no foreign currency derivative contracts outstanding at 30 June 2019 and 2018.

NOTE 14 — FAIR VALUE MEASUREMENT

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

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

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

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

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


As at 30 June 2019
(US$’000)	Level 1	Level 2	Level 3	Total
Assets measured at fair value
Derivative commodity contracts	—	6,156	—	6,156
Liabilities measured at fair value
Derivative commodity contracts	—	(1,301)	—	(1,301)
Derivative interest rate swaps	—	(6,205)	—	(6,205)
Net fair value	—	(1,350)	—	(1,350)


As at 31 December 2018
(US$’000)	Level 1	Level 2	Level 3	Total
Assets measured at fair value
Derivative commodity contracts	—	32,318	—	32,318
Liabilities measured at fair value
Derivative commodity contracts	—	(876)	—	(876)
Derivative interest rate swaps	—	(2,138)	—	(2,138)
Net fair value	—	29,304	—	29,304

During the six months ended 30 June 2019 and 2018, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfer into or out of Level 3 fair value measurements.

Measurement of Fair Value

Derivatives

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

b) Credit Facilities

As at 30 June 2019, the Company had $250 million and $105 million of principal debt outstanding under its Term Loan and Revolving Facility, respectively. During the six months ended 30 June 2019, the Company amended its Revolving Facility, which decreased the applicable interest rate margins by 25 basis points. If a similar amendment were to occur to the Company’s Term Loan, the fair value of the loan would approximate $251.1 million. The fair value of the term loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period.

The Company’s Revolving Facility has a recorded value that approximates its fair value as its variable interest rate is tied to current market rates and the applicable margins of 2.25%‑3.25% approximate market rates.

c) Other Financial Instruments

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

d) Non-recurring Fair Value Measurements

Certain non-financial assets and liabilities are initially measured at fair value, including assets held for sale, exploration and evaluation assets and development and production assets. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances. The Company did not recognize any impairment expense with respect to its development and production assets during the six months ended 30 June 2019. The Company did recognize impairment expense with respect to its Dimmit County assets held for sale and its exploration and evaluation assets. See further discussion of impairment methods and assumptions at Note 6.

NOTE 15 — ISSUED CAPITAL

On 24 December 2019, the Company completed the consolidation of its ordinary shares on a 1 for 10 basis (the “Share Consolidation”) as approved by the shareholders of the Company. The Share Consolidation involved the conversion of every ten fully paid ordinary shares on issue into one fully paid ordinary share. Upon the effectiveness of the Share Consolidation, the number of ordinary shares the Company had on issue was reduced from 6.87 billion to 687 million. All share and per share amounts in these condensed consolidated financial statements and related notes for periods prior to December 2018 have been retroactively adjusted to reflect the share consolidation.

Ordinary shares issued and outstanding at each period end are fully paid.


		Number of Shares
a) Ordinary Shares
Total shares issued and outstanding as at 31 December 2018		687,462,327
Shares issued during the year		104,995
Total shares issued and outstanding as at 30 June 2019		687,567,322

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

NOTE 16 — SHARE-BASED PAYMENTS

The Company recognized share-based compensation expense of $0.3 million and $0.2 million during the six month ended 30 June 2019 and 2018, respectively, comprised of RSUs (equity-settled) and deferred cash awards (cash-settled).

Restricted Share Units

This information is summarised for the Group for the six months ended 30 June 2019 below:


		Weighted Average Fair
	Number	Value at Measurement
	of RSUs	Date A$
Outstanding as at 31 December 2018	9,133,930	0.47
Issued or Issuable	3,837,480	0.32
Converted to ordinary shares	(104,995)	0.91
Forfeited	(1,009,592)	1.77
Outstanding at 30 June 2019	11,856,823	0.33

Deferred Cash Awards

Under the deferred cash plan, awards vest between 0%‑300%, through appreciation in the price of Sundance’s ordinary shares over a one to three year period. The expense recorded for the deferred cash awards was not material for the six months ended 30 June 2019 and 2018.


		Amount
		of Deferred
		Cash Awards (US$)
Outstanding as at 31 December 2018		523,163
Granted		—
Vested and paid in cash		—
Forfeited		(8,667)
Outstanding as at 30 June 2019		514,496

NOTE 17 — OPERATING SEGMENTS

The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the Company’s operations and assets are located in the Eagle Ford area of south Texas. The operational characteristics, challenges and economic characteristics are consistent throughout the area in which the Company operates. As such, Management has determined, based upon the reports reviewed and used to make strategic decisions by the Chief Operating Decision Maker (“CODM”), whom is the Company’s Managing Director and Chief Executive Officer, that the Company has one reportable segment being oil and natural gas exploration and production in North America. For the six months ended 30 June 2019 and 2018 all condensed consolidated statement of profit or loss and other comprehensive loss activity was attributed to its reportable segment with the exception of $20 thousand and $0.7 million of pre-tax impairment expense, which related to the impairment of the Company’s Cooper Basin assets in Australia, respectively.

NOTE 18 — EXPENDITURE COMMITMENTS

In conjunction with the Company’s Eagle Ford acquisition in 2018, it entered into midstream contracts with a large pipeline company and production purchaser to provide gathering, processing, transportation and marketing of produced volumes from the acquired properties. The contracts contain commitments to deliver oil, natural gas and NGL volumes to meet minimum revenue commitments (“MRC”), a portion of which are secured by letters of credit and performance bonds. Total MRC by year are as follows:


As at 30 June 2019	Remaining 2019	2020	2021	2022	Total
Hydrocarbon handling and gathering agreement	6,517	14,449	14,232	6,852	42,050
Crude oil and condensate marketing agreements	1,074	4,706	7,565	4,381	17,726
Gas processing agreement	862	2,020	—	—	2,882
Gas transportation agreements	178	595	—	—	773
Total minimum revenue commitment	8,631	21,770	21,797	11,233	63,431

Under the terms of the contract, if the Company fails to deliver the volumes to satisfy the MRC under any of the contracts, it is required to pay a deficiency payment equal to the shortfall. If the volumes and associated fees are in excess of the MRC in any year, the overage can be applied to reduce the commitment in the subsequent years. The amount of the shortfall, if any, that may exist at 31 December 2019 will be highly dependent on the timing of well completions and the production results from new drilling. The shortfall is currently not expected to be material for the year ended 31 December 2019.

NOTE 19 — CONTINGENT ASSETS AND LIABILITIES

The Company is involved in various legal proceedings in the ordinary course of business. The Company recognises a contingent liability when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that as at the date of this report, it is not probable that these claims and litigation involving the Company will have a material adverse impact on the Company. Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at 30 June 2019. At the date of signing this report, the Group is not aware of any other contingent assets or liabilities that should be recognized or disclosed in accordance with AASB 137/IAS 37 — Provisions, Contingent Liabilities and Contingent Assets.

NOTE 20 — SUBSEQUENT EVENTS

DIRECTORS’ DECLARATION

In accordance with a resolution of the directors of Sundance Energy Australia Limited, I state that:

In the opinion of the directors:

The financial statements and notes of Sundance Energy Australia Limited for the half‐year ended 30 June 2019 are in accordance with the Corporations Act 2001, and:

a) give a true and fair view of the consolidated entity’s financial position as at 30 June 2019 and of its performance for

the half‐year ended on that date, and;

b) comply with Australian Accounting Standards and the Corporations Regulations 2001 and other mandatory

professional reporting requirements, as discussed in Note 1.

There are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and payable.

On behalf of the Board of Directors.

MIKE HANNELL SIGNATURE CROPPED

Michael Hannell

Chairman

Adelaide

Dated this 13th day of September 2019

CORPORATE DIRECTORY

Directors

Michael D. Hannell – Chairman

Eric P. McCrady - Managing Director & CEO

Damien Hannes – Non-Executive Director

Neville W. Martin – Non–Executive Director

Weldon Holcombe – Non-Executive Director

Judith D. Buie – Non-Executive Director

Thomas L. Mitchell – Non-Executive Director

Company Secretary

Damien Connor

Registered Office

28 Greenhill Road,

Wayville. SA 5034

Ph. +61 8 8274 2128

Fax +61 8 8132 0766

Website: www.sundanceenergy.com.au

Corporate Headquarters

Sundance Energy, Inc

633 17th Street, Suite 1950

Denver, CO 80202 USA

Ph. +1(303) 543-5700

Fax +1(303) 543-5701

Website: www.sundanceenergy.net

Share Registry

Computershare Investor Services Pty Ltd

Level 5, 115 Grenfell Street

Adelaide SA 5000

Australia

Auditors

Deloitte Touche Tohmatsu

Grosvenor Place

225 George Street

Sydney NSW 2000

Australia

Australian Legal Advisors

Baker & McKenzie Level 27, AMP Centre

50 Bridge Street

Sydney, NSW 2000

Australia

Bankers

National Australia Bank Limited (Treasury Services) – Australia

Natixis, New York Branch (Debt Services – Revolver) – United States

Morgan Stanley Energy Capital Inc. (Debt Services – Term Loan) – United States

Bank of America Merrill Lynch (Treasury Services) – United States

Australian Securities Exchange

The Company is listed on the Australian Securities Exchange (ASX) and NASDAQ

ASX: SEA

NASDAQ: SNDE

Exhibit 99.2

THIRD AMENDMENT TO CREDIT AGREEMENT

This THIRD AMENDMENT TO CREDIT AGREEMENT (hereinafter referred to as this “Amendment”) is entered into as of May 15, 2019 by and among SUNDANCE ENERGY AUSTRALIA LIMITED, a limited company organized and existing under the laws of South Australia (“Parent”), SUNDANCE ENERGY, INC., a Colorado corporation (the “Borrower”), the other LOAN PARTIES hereto, the LENDERS party hereto, SunTrust Bank (“SunTrust”), The Toronto-Dominion Bank, New York Branch (“TD”, and together with SunTrust sometimes collectively referred to herein as the “New Lenders”) and NATIXIS, NEW YORK BRANCH, as Administrative Agent (in such capacity, the “Administrative Agent”). Unless the context otherwise requires or unless otherwise expressly defined herein, capitalized terms used but not defined in this Amendment have the meanings assigned to such terms in the Credit Agreement (as defined below).

WITNESSETH:

WHEREAS, the Parent, the Borrower, the Administrative Agent and the Lenders have entered into that certain Credit Agreement dated as of April 23, 2018 (as the same may have been amended, restated, amended and restated, supplemented or otherwise modified from time to time prior to the date hereof, the “Credit Agreement”);

WHEREAS, the Borrower has requested that the Administrative Agent and the Lenders amend the Credit Agreement for certain purposes as provided herein;

WHEREAS, pursuant to this Amendment, each Lender (other than the New Lenders) is assigning a portion of its Commitment to each New Lender and Annex I to the Credit Agreement is being amended and restated to reflect such assignment as provided herein; and

WHEREAS, the Administrative Agent and the Lenders (including the New Lenders) have agreed to amend the Credit Agreement as provided herein, subject to the terms and conditions set forth herein.

NOW, THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, the Parent, the Borrower, the Administrative Agent and the Lenders party hereto hereby agree as follows:

SECTION 1. Amendments to Credit Agreement. Subject to the satisfaction or waiver in writing of each condition precedent set forth in Section 2 of this Amendment, and in reliance on the representations, warranties, covenants and agreements contained in this Amendment, the Credit Agreement shall be amended in the manner provided in this Section 1.

1.1 Amendment to Section 1.02. (a) Section 1.02 of the Credit Agreement shall be and it hereby is amended by amending and restating the definition of “Applicable Margin” appearing therein, in its entirety, to read as follows:

“Applicable Margin” means, for any date, the applicable rate per annum set forth below as determined based upon the Borrowing Base Utilization Percentage then in effect:

Third Amendment to Credit Agreement – Page 1

Borrowing Base Utilization	<	> 25%	> 50%	> 75%	>
Percentage	25%	and	and	and	90%
Percentage	25%	< 50%	< 75%	< 90%	90%
Base Rate Loans	1.25%	1.50%	1.75%	2.00%	2.25%
Eurodollar Loans	2.25%	2.50%	2.75%	3.00%	3.25%

Each change in the Applicable Margin shall apply during the period commencing on the effective date of such change in the Borrowing Base Utilization Percentage and ending on the date immediately preceding the effective date of the next such change, provided, that if at any time the Borrower fails to deliver a Reserve Report pursuant to Section 8.12(a), then until delivery of such Reserve Report, the “Applicable Margin” shall mean the rate per annum set forth on the grid when the Borrowing Base Utilization Percentage is at its highest level.

(b) Section 1.02 of the Credit Agreement shall be and it hereby is further amended by adding the following definition thereto in appropriate alphabetical order:

“Third Amendment Effective Date” means May 15, 2019.

1.1 Amendment to Article XII. Article XII of the Credit Agreement shall be and it is further amended by adding the following new Section 12.21 to the end thereof, such Section 12.21 to read, in its entirety, as follows:

Section 12.21. Acknowledgement Regarding Any Supported QFCs. To the extent that the Loan Documents provide support, through a guarantee or otherwise, for any Swap Agreement or any other agreement or instrument that is a QFC (such support, “QFC Credit Support”, and each such QFC, a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Loan Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

(a) In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and such QFC Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Loan Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Loan Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that

Third Amendment to Credit Agreement – Page 2

rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support.

(b) As used in this Section 12.21, the following terms have the following meanings:

“BHC Act Affiliate” of a party means an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)) of such party.

“Covered Entity” means any of the following: (i) a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b); (ii) a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or (iii) a “covered FSI” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).

“Default Right” has the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

“QFC” has the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

SECTION 2. Conditions. The amendments to the Credit Agreement contained in Section 1 of this Amendment shall become effective upon the satisfaction of each of the conditions set forth in this Section 2.

2.1 Execution and Delivery. (i) Each Loan Party, each of the Lenders and the New Lenders, and Administrative Agent shall have executed and delivered counterparts of this Amendment to the Administrative Agent, and (ii) each of the Lenders and the New Lenders, and the Administrative Agent shall have executed and delivered counterparts of a letter agreement addressed to the Term Agent with respect to Section 5.03(c) of the Intercreditor Agreement.

2.2 Fee Letter; Fees. (a) Administrative Agent shall have received multiple executed, original counterparts, as requested by the Administrative Agent, of that certain Third Amendment Fee Letter dated as of May 13, 2019 between the Administrative Agent and the Borrower, and (b) the Borrower shall have paid to the Administrative Agent, in immediately available funds, all fees required to be paid on or before the Third Amendment Effective Date pursuant to such Third Amendment Fee Letter.

2.3 No Default. After giving effect to this Amendment, no Default or Event of Default shall have occurred and be continuing.

2.4 Other Documents. The Administrative Agent shall have received such other instruments and documents incidental and appropriate to the transactions provided for herein as the Administrative Agent or its special counsel may reasonably request, and all such documents shall be in form and substance reasonably satisfactory to the Administrative Agent.

SECTION 3. Increase of Borrowing Base. The Borrowing Base is hereby increased from

Third Amendment to Credit Agreement – Page 3

$122,500,000 to $170,000,000. This increase of the Borrowing Base constitutes the May 1, 2019 Scheduled Redetermination of the Borrowing Base under Section 2.07 of the Credit Agreement, and this Section 3 shall be deemed to be the New Borrowing Base Notice for such increased Borrowing Base. Such redetermined Borrowing Base will remain in effect until the next Redetermination Date or otherwise adjusted in accordance with the provisions of the Credit Agreement, as amended hereby.

SECTION 4. Assignment and Assumption. Upon the satisfaction of the conditions set forth in Section 2 of this Amendment:

(a) Each Lender other than the New Lenders (for purposes of this Section 4 herein referred to as the “Assignors”) hereby irrevocably sells and assigns, severally and not jointly, to each New Lender (for purposes of this Section 4 herein referred to as the “Assignees”), and each Assignee hereby irrevocably purchases and assumes from each Assignor, (i) such portion of such Assignor’s rights and obligations in its capacity as a Lender under the Credit Agreement and any other documents or instruments delivered pursuant thereto so that after giving effect to such assignment and assumption the Commitments and Applicable Percentages of the Lenders shall be as set forth on Annex I hereto, and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of such Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by the Assignors to each Assignee pursuant to clauses (i) and (ii) above being referred to herein as such Assignee’s “Assigned Interest”). Such sale and assignment is without recourse to any Assignor and, except as expressly provided in this Section 4 without representation or warranty by such Assignor.

(b) Each Assignor (i) represents and warrants that (A) it is the legal and beneficial owner of its portion of each Assigned Interest being assigned by it pursuant to this Section 4, (B) such Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, and (C) it has full power and authority, and has taken all action necessary, to execute and deliver this Amendment and to consummate the transactions contemplated by this Section 4, and (ii) assumes no responsibility with respect to (A) any statements, warranties or representation made in or in connection with the Credit Agreement or any other Loan Document, (B) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any Collateral thereunder, (C) the financial condition of any Loan Party, or (D) the performance or observance by any Loan Party of any of their respective obligations under any Loan Document.

(c) Each Assignee (i) represents and warrants that (A) it has full power and authority, and has taken all action necessary, to execute and deliver this Amendment and to consummate the transactions contemplated hereby and to become a Lender under the

Third Amendment to Credit Agreement – Page 4

Credit Agreement, (B) it satisfies the requirements specified in the Credit Agreement that are required to be satisfied by it in order to acquire its Assigned Interest, (C) from and after the date hereof, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of such Assigned Interest, shall have the obligations of a Lender thereunder, (D) it has received a copy of the Credit Agreement, together with copies of the most recent financial statements delivered pursuant thereto, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Amendment and to purchase such Assigned Interest on the basis of which it has made such analysis and decision independently and without reliance on Administrative Agent or any other Lender or New Lender, and (E) if it is not organized under the laws of the United States of America or one of its states, it has supplied to Administrative Agent any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by such Assignee, and (ii) agrees that (A) it will, independently and without reliance on Administrative Agent, any Assignor or any other Lender or New Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents and (B) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

(d) From and after the date of the satisfaction of the conditions set forth in Section 2 of this Amendment, Administrative Agent shall distribute all payments in respect of the Assigned Interests (including payments of principal, interest, fees and other amounts) to the Assignors for amounts that have accrued to but excluding such date and to the Assignees for amounts that accrue from and after such date.

(e) After giving effect to the assignment referenced in this Section 4, Borrower, Administrative Agent and the Lenders hereby approve the allocation of the Commitments and Applicable Percentages as set forth on Annex I attached hereto, which amends and restates, in its entirety, Annex I to the Credit Agreement.

SECTION 5. Representations and Warranties of Loan Parties. To induce the Lenders (including the New Lenders) to enter into this Amendment, each Loan Party hereby represents and warrants to the Lenders (including the New Lenders) as follows:

5.1 Reaffirmation of Representations and Warranties/Further Assurances. After giving effect to the amendments contained herein, each representation and warranty of such Loan Party contained in the Credit Agreement and the other Loan Documents is true and correct in all material respects (without duplication of any materiality qualifier contained therein) on the date hereof, except to the extent such representations and warranties relate solely to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects (without duplication of any materiality qualifier contained therein) as of such date.

5.2 Corporate Authority; No Conflicts. The execution, delivery and performance by such Loan Party of this Amendment and all documents, instruments and agreements contemplated herein are within such Loan Party’s corporate or other

Third Amendment to Credit Agreement – Page 5

organizational powers, have been duly authorized by all necessary action, require no action by or in respect of, or filing with, any court or agency of government and do not violate or constitute a default under any provision of any applicable law or other agreements binding upon such Loan Party or result in the creation or imposition of any Lien upon any of the assets of such Loan Party except for Liens permitted under Section 9.03 of the Credit Agreement.

5.3 Enforceability. This Amendment has been duly executed and delivered by each Loan Party and constitutes the valid and binding obligation of such Loan Party enforceable in accordance with its terms, except as (a) the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditor’s rights generally, and (b) the availability of equitable remedies may be limited by equitable principles of general application.

5.4 No Default. As of the effective date of this Amendment, both before and immediately after giving effect to this Amendment, no Default or Event of Default has occurred and is continuing.

SECTION 6. Miscellaneous.

6.1 Reaffirmation of Loan Documents and Liens. Except as amended and modified hereby, any and all of the terms and provisions of the Credit Agreement and the other Loan Documents shall remain in full force and effect and are hereby in all respects ratified and confirmed by each Loan Party. Each Loan Party hereby agrees that the amendments and modifications herein contained shall in no manner affect or impair the liabilities, duties and obligations of any Loan Party under the Credit Agreement and the other Loan Documents or the Liens securing the payment and performance thereof.

6.2 Parties in Interest. All of the terms and provisions of this Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns.

6.3 Legal Expenses. Borrower hereby agrees to pay all reasonable fees and expenses of special counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this Amendment and all related documents.

6.4 Counterparts. This Amendment may be executed in one or more counterparts and by different parties hereto in separate counterparts each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument; signature pages may be detached from multiple separate counterparts and attached to a single counterpart so that all signature pages are physically attached to the same document. Delivery of photocopies of the signature pages to this Amendment by facsimile or electronic mail shall be effective as delivery of manually executed counterparts of this Amendment.

6.5 Complete Agreement. THIS AMENDMENT, THE CREDIT

Third Amendment to Credit Agreement – Page 6

AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

6.6 Headings. The headings, captions and arrangements used in this Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Amendment, nor affect the meaning thereof.

6.7 Severability. Any provision of this Amendment held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

6.8 Governing Law. This Amendment shall be construed in accordance with and governed by the laws of the State of New York.

6.9 Reference to and Effect on the Loan Documents.

(a) This Amendment shall be deemed to constitute a Loan Document for all purposes and in all respects. Each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein” or words of like import, and each reference in the Credit Agreement or in any other Loan Document, or other agreements, documents or other instruments executed and delivered pursuant to the Credit Agreement to the “Credit Agreement”, shall mean and be a reference to the Credit Agreement as amended by this Amendment.

(b) The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents.

[Signature Pages Follow]

Third Amendment to Credit Agreement – Page 7

IN WITNESS WHEREOF, the parties have caused this Amendment to be duly

executed as of the date first above written.

PARENT:

Sundance Energy Australia Limited

By: ____________________________

Name: __________________________

Title: ___________________________

BORROWER:

Sundance Energy, Inc.

By:_____________________________

Name:______________________ ____

Title:____________________________

Third Amendment to Credit Agreement - Signature Page

OTHER LOAN PARTIES:

Sea Eagle Ford, LLC

By:___________________________

Name:_________________________

Title:__________________________

Armadillo E&P, Inc.

By:______________________________

Name:____________________________

Title:_____________________________

Third Amendment to Credit Agreement - Signature Page

NATIXIS, NEW YORK BRANCH, as

Administrative Agent

By:_______________________________

Name:_____________________________

Title:______________________________

NATIXIS, NEW YORK BRANCH , as a Lender

By:________________________________

Name:______________________________

Title:_______________________________

Third Amendment to Credit Agreement- Signature Page

CREDIT AGRICOLE CORPORRA TE AND

INVESTMENT BANK, as a Lender

By:_______________________________

Name: ____________________________

Title: _____________________________

By:_______________________________

Name:_____________________________

Title:______________________________

ABN AMRO CAPITAL USA LLC, as a Lender

By:__________________________________

Name:________________________________

Title:_________________________________

By:__________________________________

Name:________________________________

Title:_________________________________

BANK OF AMERICA, N.A., as a Lender

By:__________________________________

Name: _______________________________

Title:_________________________________

MORGAN STANLEY CAPITAL GROUP INC.,

as a Lender

By:_______________________________________

Name:_____________________________________

Title:______________________________________

Third Amendment to Credit Agreement- Signature Page

SunTrust Bank, as a New Lender

By:______________________________

Name:____________________________

Title:_____________________________

Third Amendment to Credit Agreement - Signature Page

THE TORONTO-DOMINION BANK, NEW YORK BRANCH, as a New Lender

By:_________________________________________

Name:_______________________________________

Title:________________________________________

Third Amendment to Credit Agreement - Signature Page

ANNEX I

LIST OF MAXIMUM CREDIT AMOUNTS

Aggregate Maximum Credit Amounts

of Lender	Percentage		aximum Credit Amount
Name of Lender	Applicable Percentage	Applicable Percentage of the Borrowing Base as of the Third Amendment Effective Date	Maximum Credit Amount
Natixis, New York Branch	21.17647%	$36,000,000.00	$52,941,175.00
Credit Agricole Corporate and Investment Bank	18.82353%	$32,000,000.00	$47,058,825.00
ABN AMRO Capital USA LLC	18.82353%	$32,000,000.00	$47,058,825.00
Bank of America, N.A.	14.70588%	$25,000,000.00	$36,764,700.00
SunTrust Bank	10.29412%	$17,500,000.00	$25,735,300.00
The Toronto-Dominion Bank, New York Branch	10.29412%	$17,500,000.00	$25,735,300.00
Morgan Stanley Capital Group Inc.	5.88235%	$10,000,000.00	$14,705,875.00
TOTAL:	100.00000%	$170,000,000.00	$250,000,000.00

Third Amendment to Credit Agreement – Annex I