HARTSHEAD RESOURCES NL — M&A Activity 2020

Dec 13, 2020

14 December 2020

ACQUISITION OF HARTSHEAD RESOURCES IN A TRANSFORMATIONAL DEAL TO CREATE A NEW UK NORTH SEA GAS COMPANY WITH MULTI‐PHASED DEVELOPMENT OF 2C CONTINGENT RESOURCES

• Agreement reached to acquire the remaining 78.4% interest in Hartshead Resources Limited ( Hartshead or HRL ) that Ansila Energy NL ( Ansila , ANA or the Company ) does not already own in an all share deal aiming to create a new UK North Sea gas developer. Following completion of the deal HRL will become the Company's wholly‐owned subsdiary.

• UK 32[nd] Offshore Licensing Round award will see HRL awarded five contigous blocks in the Southern North Sea ( HRL License ) with four existing discoveries totalling 354 Bcf[1] of 2C Contingent Resources.

• Recently completed CPR by Oilfield Production Consultants Ltd for Phase I development field of 217 Bcf[2] of 2C Contingent Resources.

• Multi‐phased development of existing gas discoveries:

• Phase I : Victoria and Viking Wx fields with 217[2] Bcf of audited 2C Contingent Resources

• Phase II : Audrey NW and Tethys North fields with 139[1] Bcf of 2C Contingent Resources

• Exceptionally experienced management team with over 250 years combined industry experience and UK Southern Gas Basin specific knowledge.

• Phase III exploration protfolio with 141 Bcf[3] of 2U Prospective Resources in two drill‐ready exploration prospects.

In respect of the 2U Prospective Resources (not the Contingent Resources), the estimated quantities of petroleum that may potentially be recovered by the application of a future development project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons.

1 Hartshead management estimates. See Schedule 3 for contingent resource reporting notes.

2 Volumetric estimates are from Oilfield Production Consultants (OPC) Ltd, Independent Competent Persons Report (CPR) entitled “Contingent Resources Review and Audit (Victoria and Viking Wx)” dated October 2020. See Schedule 2, Item 4 for contingent resource reporting notes. 3 See cautionary statement on page 1 and Schedule 3, Item 6 for prospective resource reporting notes.

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• A$7.0 million Placement to fully fund work commitments of Phase I operations through to the preliminary field development plan submission.

• Existing executive directors of the Company to take on management roles on completion of Acquisition. Christopher Lewis to be appointed as Chief Executive Officer and Andrew Matharu to be appointed as Chief Financial Officer.

Ansila Energy NL has entered into a Share Sale Agreement ( SSA ) with the Principals of Hartshead Resources Limited ( Hartshead or HRL ), a private UK company, to acquire the remaining 78.4% of HRL that ANA does not already own subject to shareholder approval ( Acquisition ) in an all share transaction that will transform ANA into a new entrant UK North Sea gas development company and create a platform for future UK Southern Gas Basin ventures. Following completion, HRL will be wholly‐owned by the Company.

Contemporaneous with completion of the Acquisition and also subject to shareholder approval, the Company will conduct a placement to raise A$7.0 million to fund the progress of a multi‐phase portfolio of existing gas fields to the preliminary field development plan (FDP)/Front‐end engineering and design (FEED) stage gate.

• Phase I : Victoria and Viking Wx fields with 217 Bcf[2] of audited 2C Contingent Resources

• Phase II : Audrey NW and Tethys North fields with 139 Bcf[1] of 2C Contingent Resources

The Company is targeting preliminary FDP/FEED for the Phase I projects by April 2022 with work on the Phase II projects continuing in parallel and targeting preliminary FDP/FEED for Audrey NW and Tethys North in Q4 2022.

A full review of the licensed acreage and adjacent region will be completed during the first three years and prior to any partial relinquishment to ensure that additional low‐risk exploration opportunities are captured and aggregated within the Phase III exploration portfolio so that potential further field development plans can be generated post‐2024.

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Figure 1: Hartshead 32[nd] Licensing Round Provisional Award Acreage Position

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BACKGROUND TO HARTSHEAD RESOURCES LIMITED AND HRL LICENSE

Hartshead is a private UK limited company, incorporated as a special purpose vehicle in April 2019, with the objective of making a license application in the UK 32[nd] Offshore Licensing Round and built around an exceptionally experienced management team with deep experience in the UKCS and specific knowledge of the Southern Gas Basin ( SG Basin ).

The team has significant strength and breadth of experience from subsurface through engineering, commercial, HSEQ and capital markets, covering skill sets needed to successfully and safely execute oil and gas upstream projects. Average management experience exceeds 30 years. Most of the team have been responsible for evaluation, execution and management of activities in the SG Basin. In addition, the management team of Hartshead has been responsible for, or closely involved in, raising over US$3

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billion of funds for upstream investments and has been involved in undertaking numerous transactions in both the private and listed oil & gas sector.

The Company already holds a 21.6% equity interest in Hartshead. The Acquisition will provide Shareholders with the greater exposure to the potential upside from Hartshead and the HRL License. Within the HRL License there are a significant number of gas discoveries and prospects ( Gas Pools ) which have been largely overlooked by previous Block operators. The Gas Pools were left unexploited due to a combination of reasons including uncertain data interpretation, unclear reservoir definition and lack of access to infrastructure, as a result of either commercial issues or ageing/failing physical facilities integrity.

When these Gas Pools are aggregated and coupled together with a thorough interpretation of the existing subsurface dataset, there is a compelling investment case that a single owner/operator can execute against a development plan carefully designed and phased to fully exploit the resources through a single offtake route and in order to maximise economic recovery.

As announced by the Company on 7 September 2020, following the 32[nd] Offshore Licensing Round by the OGA the blocks under provisional award to HRL comprising the HRL License are 48/15c, 49/6c, 49/11c, 49/12d and 49/17b and contain multiple fields and undeveloped gas resources, together with a number of drill‐ready exploration prospects.

As further announced by the Company on 5 November 2020, the UK OGA has provided Hartshead with the terms and conditions of the award with a provisional start date of 1 December 2020. The initial term of the HRL License will be 5 years, followed by a second term of 2 years and a third term (intended for production) of 18 years.

The proposed license‐specific conditions of the HRL License are set out in Schedule 1. together with a map of the proposed acreage.

The HRL license will otherwise be granted on the model terms and conditions for seaward production licenses set out in The Petroleum Licensing (Production) (Seaward Areas) Regulations 2008 (UK) as amended.

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In support of the application for the HRL License, the Company has provided a guarantee to the UK OGA and undertaking to provide Hartshead with funds to carry out its obligations in respect of the HRL License once the HRL License is awarded to Hartshead, which is not conditional on completion of the Acquisition.

Hartshead's strategy is to build a European Energy portfolio which is financially, technically and environmentally sound. We aim to do this by following certain principles:

• Environmentally responsible with focus on low emissions operations and a net‐zero future;

• Ensuring commercial potential in all acreage or asset positions which benefits all stakeholders;

• Best in class technical and commercial planning and evaluations;

• Application of industry proven technology to unlock value.

Hartshead believes that, by following these guiding principles, Hartshead can deliver benefits to all stakeholders while helping meet Europe growing energy demands.

HARTSHEAD RESOURCES MANAGEMENT TEAM

The Hartshead team are a highly experienced group of oil & gas professionals with a significant strength and breadth of experience ranging from sub‐surface through engineering, commercial, HSEQ to capital markets with an average experience exceeding 30 years.

The team have a proven track record in the SG Basin with high profile successes as the Principals of private equity backed SG Basin ventures, such as Highland Energy and Caledonia Oil & Gas, which were later sold to European energy utility companies wishing to move their business models into upstream oil & gas.

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Figure 2: Proposed Ansila Board and Management Team

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Chris Lewis
Chief Executive Officer
Bevan Tarratt
Non‐Executive
Chairman
Andrew Matharu Neil Marcus Jon Treen Mark Bracewell Steve Smith Don Ferguson Nathan Lude
Chief Financial Officer Subsurface Commercial Developments QHSE Operations Director
Andrew Smith Debbie Ware Fraser Well Management
Well Management
Financial Controller Petrophysics
Well Operator
Hervey Breese D e n o t e s A N A
Geology B o a r d M e m b e r
First Reserve was amongst the first group of private equity funds to enter the UK North Sea in the late
1990s with its funding of Highland Energy which was subsequently sold to the German utility group
RWE‐Dea in 2002. First Reserve then backed the same Hartshead team members in 2003 to assemble
another Southern Gas Basin vehicle, Caledonia Oil & Gas, which acquired a controlling interest in
Consort Energy and was sold just two years later to German utility, E.oN, for £470 million. A total of
more than US$1.2 billion have been raised by the members of the Hartshead team from First Reserve
for a combination of Southern Gas basin ventures and the First Reserve Fund XII which went on to seed
four further upstream ventures.
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SOUTHERN GAS BASIN HISTORY

In the UK sector, BP’s West Sole Field was the first gas discovery in the Southern Gas Basin. The field was discovered in 1965 and was the first field to be developed in 1967. West Sole has produced over 2 Tcf during its lifetime. The discovery was followed by the Viking Field in 1965 and the Leman, Indefatigable and Hewett fields in 1966. The Phase I development fields (Viking Wx and Victoria) are in

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the Viking development complex area. In this area the Viking A Field, in Block 49/12, was discovered in March 1969 by well 49/12‐2 and the adjacent Viking F accumulation in 1973.

Figure 3: Southern North Sea Viking/Pheonix development map (Riches, 2003)

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These initial discoveries were developed through a five‐platform complex situated over Viking A. The development of Viking A also saw the development of a new gas trunk line dedicated to the new Theddlethorpe gas terminal (TGT) in Lincolnshire. The first Viking A production well, AD1, was drilled in January 1971 and the Viking A field came onstream in October 1972. The Viking A field produced a cumulative 970 Bcf of gas and ceased production in 1991.

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Further exploration in the area resulted in a number of other discoveries (Viking B, C, D, E, G, and Gn) and resulted in the installation of further manned platforms and unmanned satellite platforms to develop these discoveries (see Viking/Phoenix development map).

In 1988 Conoco commissioned a new offshore three‐platform gas complex, called LOGGS (Lincolnshire Offshore Gas Gathering System). A new trunk line was built from LOGGS into TGT, which was expanded with new production trains. After the Viking A trunk line was decommissioned, production from the remaining Viking B area was re‐routed via LOGGS.

LOGGS and TGT and all connected fields ceased production in 2018. Closure of this infrastructure has increased the commercial volume threshold for stranded gas in the area local to the Hartshead provisional license award and demonstrates the requirement for a small pools aggregation strategy.

The Phoenix Development Project began in the early 1990s and relied extensively on new technology at the time, from the application of 3D seismic data, to the use of horizontal drilling and hydraulically fracced completions in tighter reservoirs. One additional and important factor in the project was the re‐negotiation of the gas sales contract and the removal of the Gas Levy in 1992. This provided favourable economic conditions for the development of additional Viking gas production and initiated the appraisal program for remaining reserves.

Following the acquisition of 3D seismic data in 1993 there was renewed exploration and appraisal efforts, which resulted in the successful re‐appraisal of the previously thought uneconomic Viking Wx and Viking Fs areas and new wells into the Vampire Field (formerly Viking Jx) and Kx accumulations.

The Phoenix Development came onstream in 1998, with five wells initially placed on production at a combined rate over 200 MMscfpd.

In recent years the UK government has introduced additional tax allowances to benefit smaller industry participants and specifically benefit smaller field development projects. The small field allowance in 2012 and the investment allowance introduced in 2015 have both improved the potential financial viability projects similar to those being undertaken by Hartshead.

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Figure 4: Viking Complex Gas Production 1972 to 2000 (Riches, 2003)

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Hartshead’s Phase II development fields are Tethys North, originally part of the Saturn Fields complex, and Audrey NW, one of the A‐Fields.

The original Saturn Fields (Atlas, Hyperion and Rhea & Annabel), discovered in 1986 from exploration well 48/10b‐2, were not brought into production until 2005, forty years after the initial license award and almost 20 years after the first discovery well.

Conoco operated and developed the Saturn complex containing the Atlas, Hyperion and Rhea structures, while Venture production operated and developed the Annabel structure.

The main reason the project finally achieved sanction in 2004 was due to the application or pre‐stack depth migration (PSDM) techniques in processing of 3D seismic data. Prior to this, seismic data has not been able to accurately image structures beneath a complex and rapidly changing Zechstein overburden and in particular in the regional beneath the Audrey Salt Wall.

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Mimas and Tethys satellites were discovered and appraised based mostly on the new PSDM 3D data. These satellites could be developed due to the installation of the Satellite Field infrastructure, making the development of small pools of stranded gas viable.

One additional factor in bringing the satellite fields into production was the use of flexible well design, allowing projects to be complete with fewer wells than had previously been envisaged by the operator. This included the drilling of the operators longest North Sea bi‐lateral well at the time of drilling.

The first of the A‐Fields, Audrey, was discovered in 1975 and came on‐stream in 1988. The Audrey development suffered similar challenges to the Saturn Fields, as a large part of the field lies beneath the Audrey Salt wall, causing poor seismic imaging at Top Reservoir. The field was developed with two normally unmanned and peak gas production was achieved shortly after in 1991 at a rate of 219 MMscfpd. The Audrey platforms acted as a hub, exporting gas from the Annabel development in addition to providing power, controls and chemicals to the Ann, Alison and Annabel fields. In 2016 the field ceased production having produced c. 700 Bcf of gas.

PHASE I PROJECTS

The Phase I projects consist of the developments of the Victoria and Viking Wx fields located in block 49/17b of Quadrant 49 of the UK North Sea with audited combined 2C contingent resources of 217 Bcf[4] .

• Victoria Field : Discovered in 1969 and produced from 2008 to 2015 via single development well which produced 13 Bcf following an initial rate of 12 mmscfpd from a single frac. With an initial Gas‐initially‐in‐place (GIIP) estimate ranging from 179 Bcf (P90) to 307 Bcf (P10) with a best estimate of 234 Bcf. The 2C remaining contingent resource estimate is 125 Bcf[5] .

• Viking Wx Field : Also discovered in 1969 and produced a total of 46 Bcf from a single well from 1999 to 2014 at a maximum rate of 44mmscfpd from two fracs. Gas‐initially‐in‐place estimate ranging from 148 Bcf (P90) to 256 Bcf (P10) with a best estimate of 214 Bcf. The 2C remaining contingent resource estimate is 90 Bcf[5] .

4 See Schedule 3, Item 2 for contingent resource reporting notes.

5 See Schedule 3, Item 2 for contingent resource reporting notes.

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Figure 5: Multi‐phased development areas within Hartshead Licensed acreage

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PHASE II PROJECTS

The Phase II projects consist of the developments of the Audrey NW and Tethys North fields located in blocks 48/15c and 49/6c + 49/11c, respectively, of Quadrants 48 & 49 of the UK North Sea with

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management’s best estimate of 139 Bcf of combined recoverable resources.[6] It is the intention to develop the Phase II projects with the infrastructure deployed to develop the Phase I projects.

• Audrey NW: The Audrey field was discovered in 1975 and has produced 700 Bcf to date. The NW flank of the field represents an undeveloped part of the field with a single well penetration that produced on 26 Bcf of gas. Reservoir engineering studies indicate that this well alone could hold up to 153 Bcf of gas whilst further mapping across the entire structure points to a potential for more than 500 Bcf of gas. Management’s estimate of 2C contingent resources for Audrey NW is 100 Bcf.[ 7]

• Tethys North: Discovered in 1991 the Tethys field was placed on production via a single well which produced 18 Bcf of gas. However, the Tethys North part of the field remains undeveloped. Management’s GIIP ranges from 53 Bcf to 239 Bcf with a best estimate of 130 Bcf and management mapping of the field indicate a 2C contingent resource of 39 Bcf likely to be recovered from a single well development tied back to the Phase I infrastructure.[8]

PHASE III PROJECTS

The Phase III projects consist of the exploration portfolio containing the Vixen SW and Vixen SE drill‐ ready prospects in block 49/17b with management’s estimate of unrisked Prospective (P50) Resources totaling 141 Bcf or 60 Bcf on a risked basis.[9] It is management’s aim to progress this portfolio and supplement it with additional exploration prospects; potentially from a review of Harthead’s licensed acreage and the adjacent region for missed opportunities prior to the first‐year license relinquishment. Following final FDP submission of Phases I and II it is management’s aspiration that the Phase III portfolio could potentially generate the next field development opportunities.

TECHNICAL AND SUB‐SURFACE OVERVIEW

6 See Schedule 3, Item 4 for contingent resource reporting notes.

7 See Schedule 3, Item 4 for contingent resource reporting notes.

8 See Schedule 3, Item 4 for contingent resource reporting notes.

9 See cautionary statement on page 1 and Schedule 3, Item 6 for prospective resource reporting notes.

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The blocks provisionally awarded all lie within the Permian aged Rotliegendes sandstone reservoir fairway and the gas in all accumulations is trapped within this sandstone. The Rotliegendes sandstones represent the deposits of an aeolian basin. Overall, the sandstones are predominantly fine to medium grained, well sorted and with individual grains appearing rounded to well rounded. The sandstones are typically clean (<5% detrital clay) to slightly clayey (5‐15% detrital clay), with localised argillaceous sandstones (20‐25% detrital clays) observed in core.

Four key lithofacies associations are recognised locally: aeolian dune, dry aeolian sand flat, damp aeolian dune and wet aeolian sand flat. The rocks from each facies have distinctive porosity‐ permeability relationships due mainly to the differences in grain size, sorting, abundance of matrix clays etc. occurring in each environment. In general, the aeolian dune sandstones display the best reservoir quality, followed by dry and damp aeolian sandflat sandstones respectively. Argillaceous wet aeolian sandflat sandstones are predominantly non‐reservoir intervals.

Generally, the primary depositional facies have the most significant impact on reservoir quality. The proportion of each facies is primarily dependent on the geographic location within the aeolian basin and its proximity to the coeval Silverpit Lake to the north.

The diagenetic history of the Rotliegendes is the result of complex fluid‐rock interactions post deposition and during burial within the sedimentary basin. Carbonates cements (ferroan and non‐ ferroan dolomites are the most common) occur preferentially in the coarser grained laminae whilst authigenic grain‐coating clays are common throughout. With increased depth of burial clay mineral transformation occurs with the deposition of blocky and fibrous illite. Significant reductions in permeability are attributed primarily to the development of hairy illite.

The reservoirs in all four fields in the Phase I and Phase II developments are considered poorer quality and tight, due to either depositional facies or diagenesis (or a combination of both). However, all fields have historically produced gas at commercial rates and with the use of fracture stimulation have produced at rates over 45 mmscfpd in the case of the 49/17‐12 well at Viking Wx.

Hartshead intend to use industry proven techniques of extended reach, high angle, multi‐frac production wells to fully exploit the resources in the fields. This technology is proven and has been

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highly effective at the Clipper South development where results have exceeded expectations. Reservoirs at Viking Wx and Victoria has been compared to those at Clipper South and this field is confirmed as an appropriate analogue for development plan.

The gas fields and exploration prospects are all structural traps and have 3D seismic coverage. In the cases of the Phase I fields, these structures are easily identified and clearly mappable on 3D seismic data. In the case of all four fields, the mapped gas‐in‐place significantly exceeds the gas volume that has historically been produced, leading to the potential to redevelop these fields.

However, the recoverable gas volumes in these four fields is considered contingent resources. In the case of the Phase I fields, the main contingencies are the approval by the OGA of a proposed field development plan and the arrangement of funding to proceed with full field development, in addition to securing access to third party infrastructure and securing gas offtake or sales agreements. In the case of the Phase II fields, the contingencies are the same, although improved seismic imaging is required to reduce subsurface uncertainty and proceed with development planning.

RESOURCE POTENTIAL SUMMARY

The table below summarises the estimates for contingent resources under the 1C, 2C, 3C classifications for the Phase I projects (Victoria and Viking Wx fields) and are derived from an independent Competent Persons Report (CPR) compiled by Oilfield Production Consultants Limited (OPC) for HRL.

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Figure 6: Phase I Audited Contingent Resources by OPC

		CONTINGENT RESOURCES (Bcf)
PHASE I PROJECTS		1C 2C 3C
Victoria	49/17b	84 125 177
Viking Wx	49/17b	62 90 124
Combined†	49/17b	161 217 285

† Volumes combined stochastically to give portfolio volume

HRL management have estimated the following resources for the Phase II and Phase III projects which have not been independently audited.[10]

Figure 7: Phase II and III – Management’s estimate of Contingent and Prospective Resources

		GAS (BCF)
CONTINGENT RESOURCES		1C 2C 3C GCos
PHASE II	49/6c, 49/11cTethys North	14 39 70 100%
	48/15c Audrey NW	35 100 387 100%
PROSPECTIVE RESOURCES		P90 P50 P10 GCoS
PHASE III EXPLORATION	49/17b Vixen SW	29 56 94 50%
	49/17b Vixen SE	43 85 142 30%

10 See cautionary statement on page 1 and Schedule 3 for resource reporting notes.

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WORK PROGRAM AND DEVELOPMENT STRATEGY

Harthead believes that material value remains in the SG Basin and that this can be monetised using a small gas pools aggregation strategy with existing and proven technology. When these small gas pools are aggregated and coupled together with a thorough interpretation of the existing subsurface dataset, it is believed there is a compelling investment case that a single owner/operator can execute against a development plan carefully designed and phased to fully exploit the resources through a single offtake route and in order to maximise economic recovery.

Development on the HRL License has a phased approach, initially with the development of over 200 Bcf of gas to support construction of a production hub, pipeline to host facilities and host facilities modified to receive Hartshead sales gas. This hub will then enable the satellite development of smaller pools, such as those at Tethys North, or indeed from successful exploration drilling, where these gas pools would have been stranded without access to the Phase I infrastructure.

The first part of the development planning will be thorough subsurface analysis and modelling to assist with detailed well placement and design, production forecasting and selecting the optimal development concept. Following this the Phase I development will be ready to commence engineering design prior to taking a final investment decision on the development of the two gas fields.

The Phase II fields have technical uncertainty due to proximity to salt structures in the sedimentary section above the fields. Work will initially focus on reducing this uncertainty using modern seismic depth migration algorithms to improve seismic imaging at the accumulations. Following this, full field dynamic modeling will be introduced in a similar way to the Phase I fields, to enable selection of the optimal development concept, move the project to detailed design and ultimately full field development.

Phase III exploration prospects will be remapped and re‐risked, along with the remapping of the rest of the license area, to generate a full inventory of prospects and leads for future exploration. All of these opportunities will then be evaluated commercially and a decision to potentially drill a future exploration well could be taken.

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Figure 8: Phase I Activities through FEED to Final FDP Submission

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2021 2022 2023 2024
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
Project Management
Subsurface Development
Concept Identification and Screening
Host Processing Facility SOR Engagement
Concept Definition
Host Processing Facility Integration Study
Host Processing Facility Commercial Discussions
Select Stage Gate
Preliminary FDP Preparation
Preliminary FDP Submission
Front End Engineering Design
Environmental Assessment Preparation
Confirmed Host Processing Facility Terms
FID / Define Stage Gate
Detailed Design and Material Delivery
Installation, Hook‐up and Commissioning
First Gas
Budgeted scope
Iteration surface‐subsurface
Scope not yet budgeted
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At each material milestone of the Phase I, II and III work programs management believes there is an opportunity to create material value. The potential relative value creation steps occur as the projects are taken through an independent CPR audit and preliminary FDP/FEED to final FDP approval with the latter step being the most value accretive with the conversion of 2C contingent resources to 2P reserves.

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ACQUISITION

ANA currently holds 21.6% of the issued share capital of HRL which it acquired as part of a seed capital raise conducted by HRL in July 2019 to fund the license applications in the UK North Sea.

ANA is proposing to acquire the remaining 78.4% of the issued capital of HRL that it does not already own via the Acquisition, subject to shareholder approval. The consideration for the Acquisition will be 1,000,000,000 fully paid ordinary ANA shares ( Consideration Shares ) issued to the shareholders of Hartshead ( Vendors ), or their nominees, at Completion in proportion to their respective shareholdings in Hartshead.

The Vendors include existing directors, Mr Christopher Lewis and his related parties (holding a total of 17.7% of Hartshead) and Dr Andrew Matharu (holding 9.1% of Hartshead) together with the other shareholders of Hartshead who are unrelated to the Company. Shareholder approval will be sought under Listing Rule 10.11 for the issue of Consideration Shares to Mr Christopher Lewis (and his related parties) and Dr Andrew Matharu. Shareholder approval will also be sought under Listing Rule 7.1 for the issue of Consideration Shares to the unrelated Vendors. The Company has commissioned an independent expert's report on the fairness and reasonableness of the Acquisition, which will be included in the Company's notice of meeting seeking shareholder approvals for the Acquisition. The ASX has confirmed that Listing Rule 11.1.2 and 11.1.3 do not apply to the Acquisition.

All Consideration Shares will be subject to voluntary escrow for a period of 12 months from Completion and the Vendors who are Listing Rule 10.1 parties (Christopher Lewis and his related parties and Andrew Matharu) will also be subject to escrow restrictions imposed by the ASX.

Completion of the Acquisition is conditional on the satisfaction (or waiver) of a number of conditions including receipt of shareholder and regulatory approvals, due diligence, an independent expert’s report concluding the Acquisition is fair and reasonable, completion of the Placement and HRL being formally awarded the HRL License by the UK OGA.

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On completion, existing Executive Directors will be appointed to management roles with Christopher Lewis appointed Chief Executive Officer and Andrew Matharu appointed Chief Financial Officer. See Schedule 2 for a summary of the credentials of the new CEO and CFO.

CAPITAL RAISING

Contemporaneous with completion of the Acquisition and subject to shareholder approval, the Company proposes to conduct a placement of up to 280,000,000 Shares to professional and sophisticated investors each at an issue price of A$0.025 to raise up to A$7 million (before costs)( Placement ).

CPS Capital Group Pty ( CPS Capital ) has agreed to be the Lead Manager and Broker to the placement and will receive a fee of 6% on the total amount raised. Subject to shareholder approval, the Company is proposing to issue 20,000,000 Shares to CPS Capital each at an issue price of $0.00001 subject to 12 months voluntary escrow as a corporate advisory fee.

Shareholder approvals for the Acquisition and the Placement will be sought at the Company's 2020 annual general meeting. A notice of meeting seeking will be dispatched to shareholders shortly.

The chart below shows shareholdings in the Company and Hartshead prior to and following the Acquisition, including the issue of the Consideration Shares and the completion of the Placement.

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Figure 9: Relative Shareholdings in the Company and Hartshead prior to and following the Acquisition

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INDICATIVE CAPITAL STRUCTURE

Item	Shares	Options	Performance Rights
Currently on issue	508,772,1271	20,000,0002	64,884,9913
Consideration Shares	1,000,000,0004	Nil	Nil
Placement	280000000	Nil	Nil
	,,
Corporate advisory Fee to CPS Capital	20,000,000	Nil	Nil
TOTAL	1,808,772,127	20,000,000	64,884,991

Notes:

1. This figure is based on fully paid ordinary shares on issue. The Company also has a total of 5,703,550 partly paid shares on issue.

2. Exercisable at A$0.04 cents expiring on or before 31 December 2022.

3. 64,884,991 performance rights (of which 6,000,000 have vested due to the relevant milestone being achieved and 58,844,911 remain unvested). The Company has received a notice of exercise in relation to 1,000,000 of these performance rights.

4. Fully paid ordinary shares in Ansila issued to the vendors of Hartshead on completion of the Acquisition.

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INDICATIVE USE OF FUNDS

*Note, this table is indicative only and may be subject to change.

The below table sets out the indicative use of funds of the Company during the 15‐month period following Completion of the Acquisition and the Capital Raising:

		SOURCE OF FUNDS	$(AUD)
		Cash as at 1 October 2020	1,600,000
		Gross proceeds from Placement	7,000,000
		TOTAL	8,600,000
		ESTIMATED APPROXIMATE USE OF FUNDS1
		UK North Sea Phase I Concept Select and Preliminary FDP Preparation1	2,250,000
		UK North Sea Phase II Subsurface1	330,000
		New Ventures1	500,000
		Gora Energy (Poland) Costs1	450,000
		Capex Sub‐Total	(3,530,000)
		Hartshead Acquisition Costs	250,000
		Costs of the Capital Raisings	420,000
		Working Capital	4,400,000
		TOTAL	8,600,000

1 Based on an exchange rate of 1AUD: 0.55GBP.

Please note the above is indicative only and is subject to finalisation of the Entitlements Issue disclosure document.

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INDICATIVE TIMETABLE

*Note, this timetable is indicative only and may be subject to change.

Announcement released on ASX	14 December 2020
NOM despatched to Holders	18 December 2020
Annual General Meeting	18 January 2021
Completion of Placement	19 January 2021
Completion of Acquisition	19 January 2021
Recommence trading in Shares	20 January 2021

STATUS OF ANSILA’S EXISTING PROJECTS

Nkembe Block – Offshore Gabon

The Nkembe block covers an area of 1,210 km² in water depths of 50‐1,100 metres approximately 30 km off the coast of Gabon.

As announced in the Company’s most recent quarterly Ansila maintained its claim of force majeure on the Nkembe Production Sharing Contract ( PSC ), suspending all obligations. In accordance with Ansila’s legal advice, Ansila has asserted that the PSC start date is the date of the issue of the Presidential Decree (4 December 2014) and that, based on this start date, no funds contributions are outstanding as at the date of the force majeure. Ansila has committed substantial investment over a number of years in Gabon, including a US$9,000,000 signing bonus paid in January 2013, and accordingly has reserved all its rights in relation to the PSC, including the right to seek recovery of the signing bonus.

In the circumstances Ansila does not intend to commit any further resources to the Nkembe Project unless and until Ansila reaches a resolution with the Directorate General for Hydrocarbons, that enables Ansila to obtain third party funding to conduct further exploration under the PSC.

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Ambilobe Block – Offshore Madagascar

The Ambilobe block is located in the Ambilobe Basin, offshore north‐west Madagascar covering an area of 17,650 km².

An independent Ambilobe block evaluation report highlighted the potential, interpreted from the 3D seismic data acquired during 2015/16, for significant prospectivity within the block and recommended that Ansila undertake a systematic phased work program to further process and interpret the 3D seismic data for the purposes of improving the definition of and then ranking three previously identified leads. In addition, under the production sharing contract, the Company’s subsidiary that holds the block is required to relinquish a portion of the Ambilobe block.

As stated in the previous quarter, the Company has applied for the 2nd special two (2) year extension of the Ambilobe PSC. Discussions with OMNIS are ongoing and at the date of this report. The Company has not reached agreement with OMNIS on the terms of the 2nd special two (2) year extension of the Ambilobe PSC.

Gora and Nowa Sol Concessions, Poland

The Gora concession covers a Carboniferous unconventional gas play, discovered with the Siciny‐2 well drilled in 2012 and estimated to contain 2C contingent resources of 1.6 trillion cubic feet (Tcf)[11] of gas. The license also hosts a conventional Rotliegendes gas play, containing multiple exploration prospects, yet to be drilled.

The Nowa Sol concession contains the Jany‐C1 unconventional Zechstein Dolomite oil discovery drilled in 2013 and estimated to contain 2C contingent resource of 36 million barrels of oil[1] .

• (i) Gora concession

During the 2020 financial year ANA earned a 35% interest in the Gora concession by spending over £2,150,000 on an appraisal program. As part of these activities, ANA re‐entered the Siciny‐2 well and

11 Volume estimates are from Netherland, Sewell & Associates, Inc. report entitled “Estimates of Reserves and Future Revenue and Contingent Resources to the Gemini Resources Ltd. Interest and Gross (100 Percent) Prospective Resources in Certain Oil and Gas Properties located in the Nowa Sol and Gora Concessions Permian Basin, Onshore Poland as of May 1, 2019” ( Report ), and were first reported to the ASX on 4 July 2019.

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successfully undertook a two‐stage fracture stimulation of the Carboniferous interval. However, the results of this appraisal program indicate that the permeability of the reservoir is materially lower than initially estimated and, coupled the presence of mobile water, inhibits the free flow of gas. Further appraisal of the Carboniferous would significantly increase costs and there is also a significant risk of failing to establish natural gas flow. Accordingly, the near term focus on the Gora concession will be the conventional prospectivity where a number of lower cost and lower risk options have been identified within the Rotliegendes formation. In June 2020 the Operator, GRL, presented several technical workstreams to the operating committee to explore how ANA can exploit the conventional Rotliegendes potential of the Gora license.

(ii) Nowa Sol Concession

The Jany‐C1 appraisal program, consisting of the fracture stimulation and flow testing of the previously discovered 2C contingent resources of 36 MMbbls[1] of oil within the tight Zechstein Dolomite formation at the Nowa Sol concession, was originally scheduled for Q2 2020. However, given the results of the Siciny‐2 appraisal, coupled with the market turmoil surrounding the COVID‐19 pandemic and a material weakening in the oil price during the period, investor support for the risks associated with exposure to unconventional oil projects diminish. This led to ANA’s withdrawal from the Nowa Sol concession and the A$2.24 million Jany‐C1 appraisal program in order to allocate capital to lower risk conventional resource projects and new ventures whilst preserving capital in the near‐term.

‐Ends‐

CONTACTS

The Board of Directors of Ansila Energy NL authorised this announcement to be given to ASX.

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Andrew Matharu Executive Director

Nathan Lude Executive Director

Christopher Lewis Technical Director

Bevan Tarratt Non‐Executive Chairman

w: +61 8 9226 2011 e: info@ansilaenergy.com.au

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SCHEDULE 1 – PROPOSED CONDITIONS AND ACREAGE OF HRL LICENSE

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SCHEDULE 2 – MANAGEMENT APPOINTMENTS

Mr Christopher Lewis – Chief Executive Officer (Designate)

Chris is a geophysicist with over 28 years’ experience in the oil and gas industry having worked for major E&P companies, junior and small cap companies and service companies and is the Chief Executive Officer of Hartshead Resources Limited. Over the last 17 years Chris has held a variety of executive and senior management positions, has managed oil and gas operations in Europe and Africa and has been instrumental in the start‐up and rejuvenation of multiple small companies.

Chris has been involved in multiple, small oil and gas ventures including successful exits from:

• Zeta Petroleum: Built a portfolio of assets in Romanian and sold to GMI Limited (CEO: 2005‐ 2009);

• Centric Energy: Awarded license in the Kenya Tertiary Rift Basin, farmed out to Tullow Oil and then sold to Africa Oil (VP Exploration: 2010);

• VP Exploration: Lion Petroleum: The company had two blocks onshore Kenya and was successfully reversed into TSX listed Taipan Resources (VP Exploration: 2011);

• Black Star Petroleum: Awarded exploration licenses offshore Guinea Bissau and Namibia and sold company to Impact Oil and Gas (Co‐Founder: 2013‐2014).

Chris’s technical strengths are in exploration and development subsurface management and delivering effective and valuable sub‐surface projects. Commercially Chris has been involved in license applications, negotiations with government bodies, new ventures transactions and capital raising for a variety of organisations.

Chris is an existing Technical Director of ANA.

Dr Andrew Matharu – Chief Financial Officer (Designate)

Andrew has over 25 years’ experience in the oil and gas industry and equity capital markets having commenced his career as a Petroleum Engineer with Chevron and Kerr McGee in the UK North Sea and is the Chief Financial Officer of Hartshead Resources Limited.

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Following a move into investment banking he focussed on oil & gas equity research and corporate finance within roles at JP Morgan‐Cazenove, Bridgewell Securities, Numis and Westhouse Securities where he advised a number of AIM listed companies.

Andrew has a wide experience of financing private and publicly‐listed small and mid‐cap companies in the oil and gas sector and also served as Vice President of Corporate Development at AIM‐listed Tower Resources plc where he was involved in a series of corporate and asset transactions and capital raisings. Andrew holds a BEng(Hons) degree in Chemical Engineering from the University of Sheffield, a PhD in Chemical Engineering from the University of Cambridge and is a Chartered Engineer. Andrew is an existing Executive Director of ANA.

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SCHEDULE 3 – COMPETENT PERSON STATEMENTS AND RESOURCE REPORTING NOTES

Item 1 ‐ Contingent Resource Information for the Phase I Victoria and Viking Wx fields:

The information in this announcement that relates to Contingent Resource information in relation to the Phase I Victoria and Viking Wx fields is based on information compiled by technical employees of independent consultants, Oilfield Production Consultants (OPC) Ltd. This information was subsequently reviewed by Mr Christopher Lewis, who has consented to the inclusion of such information in this announcement in the form and context in which it appears. Mr Lewis is the Technical Director of the Company and CEO of Hartshead Resources Limited, with more than 28 years relevant experience in the petroleum industry and is a member of The American Association of Petroleum Geologists (AAPG), the European Association of Geoscientists and Engineers (EAGE) and the Petroleum Exploration Society of Great Britain (PESGB). The resources included in this announcement have been prepared using definitions and guidelines consistent with the 2007 Society of Petroleum Engineers (SPE)/World Petroleum Council (WPC)/ American Association of Petroleum Geologists (AAPG)/ Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (PRMS). The resources information included in this announcement are based on, and fairly represents, information and supporting documentation reviewed by Mr Lewis. Mr Lewis is qualified in accordance with the requirements of ASX Listing Rule 5.41.

Item 2 ‐ Contingent Resources Reporting Notes (Victoria and Viking Wx fields reported for the first time):

The contingent resource information for the Victoria and Viking Wx fields reported in this document:

(i) is effective as at 14 December 2020; (Listing Rule ( LR ) 5.25.1).

(ii) has been estimated and is classified in accordance with SPE‐PRMS (Society of Petroleum Engineers Petroleum Resources Management System) (LR 5.25.2);

(iii) is reported according to the Company's gross 100% economic interest in each of the resources (LR5.25.5);

(iv) has been estimated and prepared using the probabilistic method (LR 5.25.6);

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(v) has been estimated using a 5.8:1 conversion ratio for gas to oil; 5.8:1 conversion ratio is based on an energy equivalency conversion method and does not represent value equivalency (LR 5.25.7);

(vi) been estimated on the basis that products are sold on the spot market with delivery at the sales point on the production facilities (LR 5.26.5).

(vii) LR5.33.1:

The Contingent Resources at the Victoria Field are located within Block 49/17b located in the Southern North Sea, offshore United Kingdom. Hartshead Resources Limited holds a 100% interest in the Victoria Field and Block 49/17b.

The Contingent Resources at the Viking Wx Field are located within Block 49/17b located in the Southern North Sea, offshore United Kingdom. Hartshead Resources Limited holds a 100% interest in the Viking Wx field and Block 49/17b.

(viii) LR5.33.2:

The resource volumes associated with the Rotliegendes sandstones in the Victoria field are classified as Contingent in this evaluation. Gas was discovered in the 49/17‐6 well drilled in 1969 and the field placed on production from 2008 to 2015 via a single well which produced a total of 13 Bcf of gas from a single frac at an initial flow rate of 12 MMscfpd.

The resource volumes associated with the Rotliegendes sandstones in the Viking Wx field are classified as Contingent in this evaluation. Gas was discovered in 1969 with the 49/17‐4 well and the field placed on production from 1999 to 2014 via a single well which produced a total of 46 Bcf from two fracs at a maximum flowrate of 44 MMscfpd.

(ix) LR5.33.3 a brief description of the analytical procedures used to estimate the Contingent Resources:

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of Hartshead’s Contingent Resources. Probabilistic methods were used to determine the Contingent Resource volumes in the Rotliegendes Sandstones of the Victoria and

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Viking Wx fields. The appropriate range of values for each reservoir parameter were incorporated in the volumetric calculation and recovery factor to estimate the unrisked Low Estimate (1C), Best Estimate (2C), and High Estimate (3C) of Gas Initially In Place (GIIP) and recoverable Contingent Resources.

These calculations were based on data and maps provided to OPC by Hartshead or publicly available data.

The key contingencies that prevent the Contingent Resources from being classified as reserves: The Contingent Resources are contingent on a Field Development Plan (FDP) for each of the Victoria and Viking Wx fields being submitted by Hartshead and approved by the UK Oil & Gas Authority (OGA) and funding being in place to execute the field development plan.

Any further appraisal drilling and evaluation work to be undertaken to assess the potential for a commercial discovery and to progress the project: none.

Item 3 ‐ Contingent Resource Information for the Phase II Audrey NW and Tethys North fields:

The information in this announcement that relates to Contingent Resource information in relation to the Phase II Audrey NW and Tethys North fields and is based on information compiled by Mr Christopher Lewis and information complied by technical consultants contracted to Hartshead which has been subsequently reviewed by Mr Christopher Lewis. Mr Lewis has consented to the inclusion of such information in this announcement in the form and context in which it appears. Mr Lewis is Technical Director to the Company and CEO of Hartshead Resources Limited with more than 28 years relevant experience in the petroleum industry and is a member of The American Association of Petroleum Geologists (AAPG), the European Association of Geoscientists and Engineers (EAGE) and the Petroleum Exploration Society of Great Britain (PESGB). The resources included in this announcement have been prepared using definitions and guidelines consistent with the 2007 Society of Petroleum Engineers (SPE)/World Petroleum Council (WPC)/ American Association of Petroleum Geologists (AAPG)/ Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (PRMS). The resources information included in this announcement are based on, and fairly represents, information and supporting documentation reviewed by Mr

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Lewis. Mr Lewis is qualified in accordance with the requirements of ASX Listing Rule 5.41..

Item 4 ‐ Contingent Resources Reporting Notes (Audrey NW and Tethys North fields reported for the first time):

The contingent resource information for the Audrey NW and Tethys North fields reported in this document:

(i) is effective as at 14 December 2020 (LR 5.25.1);

(ii) is classified in accordance with SPE PRMS (Society of Petroleum Engineers Petroleum Resources Management System) (LR 5.25.2);

(iii) is reported according to the Company's gross 100% economic interest in each of the resources following the Acquisition (LR5.25.5);

(iv) has been estimated and prepared using the probabilistic method (LR 5.25.6);

(v) has been estimated using a 5.8:1 conversion ratio for gas to oil; 5.8:1 conversion ratio is based on an energy equivalency conversion method and does not represent value equivalency (LR 5.25.7);

(vi) has been estimated on the basis that products are sold on the spot market with delivery at the sales point on the production facilities (LR 5.26.5.).

(vii) LR5.33.1:

The Contingent Resources at the Audrey NW Field are located within Block 48/15c located in the Southern North Sea, offshore United Kingdom. Hartshead Resources Limited holds a 100% interest in the Audrey NW Field and Block 48/15c.

The Contingent Resources at the Tethys North Field are located within Blocks 49/6c and 49/11c located in the Southern North Sea, offshore United Kingdom. Hartshead Resources Limited holds a 100% interest in the Tethys North field and Blocks 49/6c and 49/11c.

(viii) LR5.33.2:

The resource volumes associated with the Rotliegendes sandstones in the Audrey NW field are classified

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as Contingent in this evaluation. Gas was discovered in the 48/15a‐1 well drilled in 1983 and the field placed on production in 1990 via a single well which produced a total of 26 Bcf of gas.

The resource volumes associated with the Rotliegendes sandstones in the Tethys North field are classified as Contingent in this evaluation. Gas was discovered in 1991 with the 49/11b‐8 well and the field placed on production from 2007 to 2018 via a single well which produced a total of 18 Bcf at an initial flowrate of approximately 80 MMscfpd.

(ix) LR5.33.3 a brief description of the analytical procedures used to estimate the Contingent Resources:

Standard geological and engineering methods generally accepted by the petroleum industry were used in the estimation of Hartshead’s Contingent Resources. Probabilistic methods were used to determine the Contingent Resource volumes in the Rotliegendes Sandstones of the Audrey NW and Tethys North fields. The appropriate range of values for each reservoir parameter were incorporated in the volumetric calculation and recovery factor to estimate the unrisked Low Estimate (1C), Best Estimate (2C), and High Estimate (3C) of Gas Initially In Place (GIIP) and recoverable Contingent Resources.

These calculations were based on data and maps provided to OPC by Hartshead or publicly available data.

The key contingencies that prevent the Contingent Resources from being classified as reserves: The Contingent Resources are contingent on a Field Development Plan (FDP) for each of the Audrey NW and Tethys North fields being submitted by Hartshead and approved by the UK Oil & Gas Authority (OGA) and funding being in place to execute the field development plan.

Any further appraisal drilling and evaluation work to be undertaken to assess the potential for a commercial discovery and to progress the project: Review existing depth migrated seismic data and potentially re‐process data prior to development planning.

Item 5 ‐ Prospective Resource Information for the Vixen SW and Vixen SE prospects:

The information in this announcement that relates to Prospective Resource information in relation

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to the Vixen SW and Vixen SE prospects in Block 49/17b and are based on information compiled by Mr Christopher Lewis and information complied by technical consultants contracted to Hartshead which has been subsequently reviewed by Mr Christopher Lewis. Mr Lewis has consented to the inclusion of such information in this announcement in the form and context in which it appears. Mr Lewis is Technical Director to the Company and CEO of Hartshead Resources Limited with more than 28 years relevant experience in the petroleum industry and is a member of The American Association of Petroleum Geologists (AAPG), the European Association of Geoscientists and Engineers (EAGE) and the Petroleum Exploration Society of Great Britain (PESGB). The resources included in this announcement have been prepared using definitions and guidelines consistent with the 2007 Society of Petroleum Engineers (SPE)/World Petroleum Council (WPC)/ American Association of Petroleum Geologists (AAPG)/ Society of Petroleum Evaluation Engineers (SPEE) Petroleum Resources Management System (PRMS). The resources information included in this announcement are based on, and fairly represents, information and supporting documentation reviewed by Mr Lewis. Mr Lewis is qualified in accordance with the requirements of ASX Listing Rule 5.41.

Item 6 ‐ Prospective Resources Reporting Notes (Vixen SW and Vixen SE Prospects reported for the first time):

The prospective resource information for the Vixen SW and Vixen SE prospectus reported in this document:

(i) is effective as at 14 December 2020 (LR 5.25.1);

(ii) has been estimated and is classified in accordance with SPE PRMS (Society of Petroleum Engineers Petroleum Resources Management System) (LR 5.25.2);

(iii) is reported according to the Company's gross 100% economic interest in each of the resources following the Acquisition (LR5.25.5);

(iv) has been estimated and prepared using the probabilistic method (LR 5.25.6);

(v) has been estimated using a 5.8:1 conversion ratio for gas to oil; 5.8:1 conversion ratio is based on an energy equivalency conversion method and does not represent value equivalency (LR 5.25.7);

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(vi) has been estimated on the basis that products are sold on the spot market with delivery at the sales point on the production facilities (LR 5.26.5);

(vii) Prospective resources are reported on a low, best and high estimate basis (LR 5.28.1); and

(viii) includes a cautionary statement on page 1 proximate to the prospective resource (LR5.28.2).

(ix) Upon completion of the Acquisition of Hartshead, ANA will hold a 100% indirect interest in the Vixen SW and Vixen SE prospects in Block 49/17b (LR 5.35.1).

(x) The prospective resources have been estimated on the following basis (LR5.35.2): the best estimate prospective resource calculation was based on a consideration of offset well information and seismic expression; a combination of volumetric assessment and field analogues have been used to estimate the prospective resources. Exploration drilling will be required to assess these resources. The expected timing for exploration drilling is H2 2025.

(xi) The chance of discovery is considered moderate as the prospective resources are near developed and undeveloped reserves and in a proven oil and gas producing province. There is a risk that exploration will not result in sufficient volumes of oil and/or gas for a commercial development (LR5.35.3).

(xii) Prospective resources are un‐risked and have not been adjusted for an associated chance of discovery and a chance of development (LR5.35.4).

Definitions:

Reserves: represent that part of resources which are commercially recoverable and have been justified for development, while contingent and prospective resources are less certain because some significant commercial or technical hurdle must be overcome prior to there being confidence in the eventual production of the volumes. ANA and Hartshead do not yet have reported reserves.

Contingent resources : are less certain than reserves. These are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. As an

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example, all required internal and external approvals should be in place or determined to be forthcoming, including environmental and governmental approvals. There also must be evidence of firm intention by a company s management to proceed with development within a reasonable time frame (typically 5 years, though it could be longer).

Prospective resources: are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared.

Forward Looking Statements

This document has been prepared by Ansila Energy NL (ANA). This document contains certain statements which may constitute "forward‐looking statements". It is believed that the expectations reflected in these statements are reasonable but they may be affected by a variety of variables and changes in underlying assumptions which could cause actual results or trends to differ materially, including, but not limited to: price fluctuations, actual demand, currency fluctuations, drilling and production results, reserve and resource estimates, loss of market, industry competition, environmental risks, physical risks, legislative, fiscal and regulatory developments, economic and financial market conditions in various countries and regions, political risks, project delays or advancements, approvals and cost estimates.

ANA’s operations and activities are subject to regulatory and other approvals and their timing and order may also be affected by weather, availability of equipment and materials and land access arrangements. Although ANA believes that the expectations raised in this document are reasonable there can be no certainty that the events or operations described in this document will occur in the timeframe or order presented or at all.

No representation or warranty, expressed or implied, is made by ANA or any other person that the

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material contained in this document will be achieved or prove to be correct. Except for statutory liability which cannot be excluded, each of ANA, its officers, employees and advisers expressly disclaims any responsibility for the accuracy or completeness of the material contained in this document and excludes all liability whatsoever (including in negligence) for any loss or damage which may be suffered by any person as a consequence of any information in this document or any error or omission there from. Neither ANA nor any other person accepts any responsibility to update any person regarding any inaccuracy, omission or change in information in this document or any other information made available to a person nor any obligation to furnish the person with any further information.

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