west perth wa 6005 facsimile: + 61 8 9324 1224 for personal … · 25/07/2011 · attached...

ANTARES ENERGY LIMITED

Level 2, 5 Ord Street Telephone: + 61 8 9324 2177 West Perth WA 6005 Facsimile: + 61 8 9324 1224 Website:www.antaresenergy.com PO Box 690 Email: [email protected] West Perth WA 6872

ASX/NEWS RELEASE 25 July 2011

QUARTERLY ACTIVITY REPORT

FOR THE QUARTER ENDED 30 JUNE 2011 To Date Highlights: 1. Northern Star expansion from approximately 8,000 gross (8,000 net) acres

representing 200 net drilling locations on 40 acre spacing to 12,400 gross (12,400 net) acres representing 310 net drilling locations on 40 acre spacing.

2. Big Star expansion from 6,000 gross (4,500 net) acres to over 17,500 gross (13,125 net) acres with the expectation to eclipse 20,000 gross (15,000 net) acres in the third quarter. 20,000 gross acres represents 500 drilling locations on 40 acre development spacing.

3. Five infill-development wells drilled/drilling in Southern Star: Lonestar No. 1, Cottonwood No. 1, Smith No. 1, Ray No. 3 and Smith No. 2.

4. Fracture stimulations on three Southern Star wells: Lonestar No. 1, Cottonwood No. 1 and Smith No. 1.

5. Lonestar No. 1 producing in excess of 100 boepd while cleaning-up. Cottonwood No. 1 and Smith No. 1 coming online.

6. Four Big Star evaluation wells drilled/drilling: Stuart 12 No. 1, Esmond 20 No. 1, Simmons 27 No. 2 and Cline 46 No. 1.

7. Fracture stimulations on two Big Star wells: Stuart 12 No. 1 and Esmond 20 No. 1. 8. Stuart 12 No. 1 producing at commercial quantities while cleaning up. Esmond 20

No. 1 coming online while Simmons 27 No. 2 and Cline 46 No. 1 to be frac’d third quarter.

9. Drilling operations concluding on first new evaluation well at Northern Star. Cozart “A” No. 1 to be frac’d third quarter.

10. Remediation of shallow water bearing zone ongoing on Northern Star Newbrough No. 1. Well to enter into production third quarter.

11. Harrison No. 3 to be frac’d on July 27th in the F41 reservoir. 12. Aggregate ongoing share buyback has resulted in 32,807,277 shares bought back

and cancelled at an average price of 41.3 cents. There are currently 267,500,000 shares on issue.

A.C.N. 009 230 835

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http://www.antaresenergy.com/

Antares Energy Limited Quarterly Activity Report to 30 June 2011

OPERATIONAL UPDATE FOR THE QUARTER ENDED 30 JUNE 2011 LETTER TO SHAREHOLDERS FROM THE CHIEF OPERATING OFFICER

Dear Shareholders, 115 Days – that’s the number of days Antares Energy has been “in” the Permian Basin. In those 115 days Antares has amassed an acreage position exceeding 28,500 net acres divided amongst three project areas: Southern Star, Big Star and Northern Star. In those project areas we have drilled or are drilling 10 wells and have fracture stimulated six wells. While it is still very early in these projects there is cause for encouragement and even a bit of excitement. At Southern Star, the Lonestar No. 1 well continues to clean-up while already exceeding 100 boepd with the expectation of achieving “type-curve” results. The Cottonwood No. 1 and Smith No. 1 have been fracture stimulated and are just now coming online. The Ray No. 3 and Smith No. 2 will be fracture stimulated third quarter and will add to our growing production base. The addition of these five wells will bring the gross production from the Southern Star project to near, if not over, 1,000 boepd – a near term milestone. Production prior to the addition of these new wells was approximately 700 gross boepd. More detailed production information will be available after the final adjustment settlement of the Southern Star project, scheduled for the 5th August 2011. Going forward; surveyors have been sent out to the field to stake our next five drilling locations. There is a balance to strike in selecting locations. Firstly, given the proven nature of the asset, drilling those wells located on leases with the highest net revenue interest (NRI) is paramount. This maximizes project net present value, the ultimate objective of any commercial endeavor. Secondly, locating wells adjacent to those wells that are believed to exceed “type-curve” performance. This was the impetus in selecting the Ray No. 3 and Smith No. 2 locations. The Ray No. 3 is adjacent to an exceptional well being operated by Linn Energy and the Smith No. 2 is a direct offset to the Smith No. 1, we recently drilled and fracture stimulated. In that well oil flowed to surface while drilling through an objective reservoir – always a good sign. Thirdly, locating wells in those leases still requiring production to hold the lease. Currently 15 wells are needed to hold the entire position. A final note of interest regarding Southern Star is that only a handful of the existing 24 wells were completed with current stimulation technology and techniques. This has led Antares to rework several wells and plan for the fracture stimulation of others. For example, the Thomas No. 1 was not fracture stimulated and was only completed through several perforations and acid placed over those perforations. That same well drilled and completed today would be subject to a 10-stage fracture stimulation with over 1,000,000 pounds of proppant placed. This type of low hanging fruit has been catalogued and is currently being addressed. While Southern Star is currently our reserve and production foundation it currently represents less than 12% of our net acreage position. Our largest position in the Permian resides at Big Star where we are now in possession of over 13,000 net acres. We have been so encouraged with this position that it has rapidly expanded from 4,500 net acres on April 27th to its current size. That encouragement is now beginning to be

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Antares Energy Limited Quarterly Activity Report to 30 June 2011

realized. Three wells have been drilled with a fourth currently drilling. Two wells have been fracture stimulated with the remaining two to be frac’d in August. The first of the frac’d wells, the Stuart 12 No. 1, has only been online for approximately 14 days with commercial quantities of oil and gas flowing. As the well continues to clean up these rates will further increase. It should be noted no reserves have been assigned to the Big Star project area; however, 3P reserve potential assuming a range of estimated ultimate recoveries (EURs) of 125 Mboe and 175 Mboe could yield between 30 Mmboe and 43 Mmboe of net, after-royalty reserves on 40 acre spacing. There have also been some growing pains and learning curves to surmount with our entry into the Permian Basin. Our first fracture stimulation in the Northern Star project area has not gone as we envisaged. After a month of production data from the Newbrough No. 1 it is apparent we have communicated with a shallow, water-bearing zone. However, we are confident we have a commercial well due to the flow of hydrocarbons into the wellbore from deeper zones prior to the fracture stimulation of the shallower zones. So what do we do now? We learn. We will set a retrievable bridge plug to isolate the shallow water-bearing zone from the deep hydrocarbon-bearing zone. We will then pump as much fluid off the formation to determine when/if the water cut decreases and oil cut increases. If not, we will pump cement into the perforations, retrieve the bridge plug and begin producing from the deeper hydrocarbon-bearing zone. On our next fracture stimulation at Northern Star, Cozart “A” No. 1 well, we will avoid this zone. The above aside, there is certainly industry excitement surrounding the Northern Star project area. Geologically, this area is located in a depositional low meaning the potential reservoir section is thicker. Petrophysical log analysis confirms this with some of the highest oil and gas in place numbers we’ve seen in the Basin. Industry is realizing this as well, and permitting and drilling activity in our immediate area is at a brisk pace. As a result of the expanded section there are numerous oil and gas bearing zones over thousands of feet. We admiringly call this a vertical horizontal, meaning we are essentially encountering the same amount of gross reservoir one would encounter in a horizontal well but doing it for approximately 1/5 of the cost in a vertical well. In the attached quarterly presentation we attempt to visualize this concept with images you may find familiar. In conclusion, I want to thank all shareholders for their loyalty and patience as we endeavor to build a company we will all be proud of. While there is reason for excitement, there is also much work ahead. Know that we are working hard to make this a reality. Very truly yours,

Matt Gentry Director & Chief Operating Officer

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2Q2011 PRESENTATION

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Disclosure Statement

Quarterly Presentation, 25 July 2011 Slide 2

This presentation may include forward-looking statements within the meaning of section 27a of the United States securities act of 1933, as amended, and section 21e of the United States securities and exchange act of 1934, as amended, with respect to achieving corporate objectives, developing additional project interests, the company's analysis of opportunities in the acquisition and development of various project interests and certain other matters. These statements involve risks and uncertainties which could cause actual results to differ materially from those in the forward-looking statements contained herein. Given these uncertainties, undue reliance should not be placed on forward-looking statements.

Newbrough No. 1 Tank Battery Esmond 20 No. 1

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Company Profile


267.5 million ordinary shares (AZZ) 7.5 million convertible notes @ $A2.00/note (AZZG) Directors hold 15.8 million shares No Director has sold a share in Antares Energy (est. 23 November 2004) 2010 Sale of Yellow Rose and Bluebonnet for $200,000,000 USD (Antares Net $156,200,000 USD) 2010 Net Profit After Income Tax of $75,379,000 AUD $29,000,000 USD – Cash at Bank (30 June 2011) Wolfberry / Missberry / Wolffork explorer, producer & developer Operational focus on the Permian Basin, West Texas, USA Attractive, 33,800 gross (28,600 net) acre position in the Permian Basin 1P Net Permian Reserves of 12.6 MMBOE 2P Net Permian Reserves of 27.0 MMBOE 3P Net Permian Reserve Potential of 87 - 111 MMBOE Proven, 75 well drilling inventory on 40 acre spacing Over 800 net drilling locations in the success case High growth profile through quickly derisking large Permian acreage position Chairman and CEO based in Dallas, Texas, USA Chief Operating Officer & Chief Scientist based in Houston, Texas, USA Corporate office in Perth, Western Australia

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Top 20 Shareholders


Twenty Largest Shareholders

Number of Shares

% of Issued Shares

1 HSBC Custody Nominees Aust Ltd 31,019,115 11.39% 2 J P Morgan Nominees Aust Ltd 23,196,990 8.52% 3 National Nominees Ltd 15,045,357 5.53% 4 Citicorp Nominees PL 14,258,919 5.24% 5 Yandal Investments PL 12,200,000 4.48% 6 James Cruickshank 10,200,000 3.75% 7 Link Entps International 5,055,864 1.86% 8 Williams BL + VRD 3,700,000 1.36% 9 Essential Faith PL 3,580,000 1.31%

10 Tangled-Blue Investments PL 3,236,255 1.19% 11 Rodney Alexander Shea 2,773,000 1.02% 12 Mark Clohessy 2,715,000 1.00% 13 Collin Mackellar 2,610,000 0.96% 14 Johjam PL 2,535,000 0.93% 15 Valware PL 2,003,972 0.74% 16 Matt Gentry 1,900,000 0.70% 17 Howard McLaughlin 1,775,500 0.65% 18 Jaswinder Takhar 1,502,009 0.55% 19 Kaysu Holdings No. 2 PL 1,450,000 0.53% 20 Jonathan Kerr-Sheppard 1,400,000 0.51%

Totals 142,156,981 52.22%

AS AT 30 JUNE 2011

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Top 20 Note Holders


Twenty Largest Convertible Note Holders

Number of Convertible Notes

% of issued Convertible

Notes 1 HSBC Custody Nominees (Aus.) Ltd 5,433,200 72.58% 2 Link Enterprises (International) PL 596,999 7.96% 3 Michael Edward Constable 228,000 3.04% 4 Dorran PL 150,000 2.00% 5 Kampar PL 92,277 1.23% 6 Gim Tong Teo & B H Kwah 90,500 1.21% 7 JP Morgan Nom Aust Ltd 88,000 1.17% 8 D J & B L Le Cornu 76,000 1.01% 9 Yee Lan Teo 53,500 0.71% 10 RBC Dexia Investor Services A 50,000 0.67% 11 J Newman & J A Holman 50,000 0.67% 12 Duncan O'Brien 50,000 0.67% 13 Rijean PL 41,000 0.55% 14 E B & G F Norris 25,000 0.33% 15 W & H Hall 25,000 0.33% 16 National Nominees Ltd 24,400 0.33% 17 Gamog No. 8 PL 19,000 0.25% 18 R M Hipkins 15,000 0.20% 19 B F Bamkin 15,000 0.20% 20 Bond Street Custs Ltd 15,000 0.20% Totals 7,147,876 95.31%

AS AT 30 JUNE 2011

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Sale of Yellow Rose and Bluebonnet


Antares Energy and its operating partner, San Isidro Development Company, sold

100% of its leasehold interest in the Eagle Ford shale to Chesapeake Energy Corporation for $200 MM USD.

Antares proportionate share of the proceeds was $156.2 MM USD. The price per acre metric achieved was $8,628/acre The transaction closed on 15 December 2010 Proceeds from the transaction are now being deployed in to the Permian Basin

1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 2007 2008 2009 2010

Enter partnership with SIDC to explore Yellow

Rose

Acquired 72 sq mi 3D seismic

Processed 3D seismic data

Preliminary seismic interpretation

Acquire 8,200 acre lease position

Refine geological and geophysical models

Increase Yellow Rose leasehold and acquire

Bluebonnet

Drill additional wells

$200 MM sale to Chesapeake

Drill initial Yellow Rose well

Permian Basin entry within repeatable business model

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Why the Permian Basin?


“Best place to find oil is in an oilfield!” Permian Basin has been producing commercial oil since 1921 (90+ years). United States Geological Survey (USGS) estimates 95.4 BBO Original Oil In Place for Permian reservoirs (34+ main conventional play types). Over 33.7 BBO of reserves produced (35% of OOIP from 1,340+ fields). Currently producing 420,000 BOPD (44% of Texas’ 960,000 BOPD output). Permian experiencing significant activity in oil rich unconventional plays (300+ wells). Principal oil targets – Wolfberry (Wolfcamp & Spraberry), Missberry (Mississippian & Wolfberry), & Wolffork (Wolfberry & Clearfork). Investment drivers :

1.Full vertical completion costs of approx. $2.0 MM USD (accessing approximately 4,000+’ of pays) vs. horizontal shale completions of up to $10 MM USD.

2.Attractive finding & development (F&D) costs – assuming 150 Mboe/well & $2 MM USD completed well cost = F&D cost of $13.3/boe.

3.Better access to services (drilling rigs, fracture stimulations, and sales infrastructure) in the proven Permian Basin as compared to new resource play areas.

4.Significant and liquid deal opportunities for Antares providing the ability to grow oil portfolio.

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The Permian Basin


Delaware Basin Central Basin

Platform

Midland Basin Eastern Shelf W E

Antares Targeted Interval

Permian Basin Structural Setting

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Midland Basin Resource Plays


Key Aspects Continual rig count growth (Currently 200+ rigs active). Drilling Permits at historic high. Play expanding from western concentration to east and north. Higher IP’s and EUR’s in previously underexploited areas. Completion “recipes” being improved in latest wells. Good, expanding oil and gas infrastructure in place.

$1.5-2.5 MM USD vertical well costs to exploit multi thousand feet hydrocarbon column unique in resource plays.

Wolfberry covers over 6,000 sq. mi. Reserve accreditors accepting larger proved areas and de-

risking 40 acre reserves. Deeper reserves potential and 20 acre spacing exploitation is

accelerating and inevitable.

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Evolution of the “Wolfberry”


Clearfork

Upper Spraberry

Lower Spraberry

Dean

Upper Wolfcamp

Strawn

Atoka

Mississippian

Woodford

Limestone Pay

Non-Organic Shale Non-Pay

Sandstone Pay

Organic Rich Shale Pay

6,000 ft

8,000 ft

10,000 ft

1950 – 70s 1980 – 90s 2010+s 2000s 2005 - 10s

Fracture Stimulation Stage

After Pioneer Natural Resources

Lower Wolfcamp

Increasing EUR

with greater

depths & frac stages

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Drilling Operations


Prior to the commencement of drilling operations: Survey proposed drilling location File a permit to drill with regulatory agency Build wellsite location

Drilling Operations take 14-20 days 1 day to mobilize rig 1 day to drill & cement surface casing to 350 ft 4 to 6 days to drill & cement intermediate casing

to 4,500 ft 8-12 days to drill & cement production casing to

a total depth of 10,500 – 12,000 ft.

Robinson Rig No. 5 drilling ahead at the Big Star project area – Stuart 12 No. 1

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Drilling Operations (continued)


Surface Casing at 350’ (Ground Water Protection)

Intermediate Casing at 4500’ to isolate

problematic drilling formations

(red beds & salt)

5.5” N-80 Production Casing to total depth

(allows for high fracture stimulation pressures).

Upper Clearfork Lower Clearfork Upper Spraberry Lower Spraberry Upper Wolfcamp Middle Wolfcamp Lower Wolfcamp Strawn Atoka Mississippian Woodford

Typical Capital Costs INTANGIBLE DRILLING COST Drilling $400,000 Mud $25,000 Cementing $35,000 Logging $35,000 Misc. $115,000 TANGIBLE DRILLING COST Casing $100,000 Misc. $10,000 COMPLETION COST Casing $180,000 Tubing $45,000 Cementing $30,000 Perforating $25,000 Fracturing $600,000 Completion Unit $25,000 Misc. $140,000 PRODUCTION EQUIPMENT COST Artificial Lift $95,000 Tank Battery $75,000 TOTAL $1,935,000

Prospective Reservoirs Encountered

Typical Wellbore Schematic

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Completion Operations


After the well is drilled, mudlogs and wireline logs are evaluated. A perforation schedule is devised to access the oil and gas in place in

each of the prospective reservoirs. Working with the fracture stimulation companies, an optimal treatment

procedure is created to allow the oil and gas in each reservoir to access the recently completed wellbore.

Typical fracture treatment is between 8 and 12 stages, and lasts 2-3 days. Total treatment cost is approximately $600,000.

Schlumberger rigged up for the fracture stimulation of the Cottonwood No. 1 well.

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Visualizing Completion Operations


Sydney Opera House With a length of slightly longer than 600 ft. and a height of nearly 250 ft. the Opera House closely approximates one side of a single fracture stimulation envelope in a typical “Wolfberry” well.

Melbourne’s Eureka Tower Standing at nearly 1,000 ft. in height the Eureka Tower is less than 1/5 of the total prospective hydrocarbon-bearing interval Antares encounters while drilling a vertical wellbore in the Midland Basin.

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Visualizing Completion Operations (cont.)


~ 1,

000

ft.

~ 600 ft.

~ 25

0 ft.

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Visualizing Completion Operations (cont.)


Clearfork

Upper Spraberry

Lower Spraberry

Dean

Upper Wolfcamp

Strawn

Atoka

Mississippian

Woodford

Limestone Pay

Non-Organic Shale Non-Pay

Sandstone Pay

Organic Rich Shale Pay

6,000 ft

8,000 ft

10,000 ft Fracture Stimulation Stage

Lower Wolfcamp

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Production Operations


320 Pumping Unit at the Southern Star project area

Typical tank battery at the Southern Star project area

After the fracture stimulation, the well will go through a period of “clean-up” where the water used to fracture stimulate the well (e.g. the load) is recovered.

During clean-up, oil production gradually increases until it reaches its peak initial production rate. This can take as long as a 1-3 months.

Peak initial production rates will typically range between 75 – 150 boepd.

Our experience demonstrates mobilizing a pumping unit (320 pumping unit or 467 pumping unit) immediately onto location saves time and money. A well can immediately be put on pump when natural flow subsides.

Initial tank battery consists of two 500 barrel oil tanks and one 200-500 barrel water tank. The batteries are modular to allow for additional tanks as more wells are brought online.

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Antares Energy’s Permian Position


Howard Co., TX

LOCATION CURRENT

NET ACRES

3P NET RESERVE

POTENTIAL EUR/WELL # NET WELL LOCATIONS

1P NET RESERVES PROJECT

3,100 173* 225 MBOE

12.6 MMBOE

27 MMBOE

27 MMBOE

2P NET RESERVES

Dawson Co., TX 13,125 328* 125 – 175

MBOE Not

Booked Not

Booked 31 - 43

MMBOE

Dawson Co., TX 12,400 310* 125 – 175

MBOE Not

Booked Not

Booked 29 - 41

MMBOE

TOTALS 28,625 800+ 125 – 225 MBOE

12.6 MMBOE

27 MMBOE

87 - 111 MMBOE

NOTE: All reserves information has been compiled by Antares Energy’s Chief Operating Officer, Mr. Matt Gentry, who is a full-time employee of Antares Energy. Mr. Gentry exceeds the professional qualifications of reserve estimators as set forth by the SPE/WPC/AAPG/SPEE Petroleum Resource Management System (SPE-PRMS). Mr. Gentry is qualified in accordance with ASX Listing Rule 5.11 and has consented to the form and context in which this statement appears. * Southern Star locations based on 20 acre spacing, while Big Star and Northern Star are based on 40 acre spacing.

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Southern Star


3,920 Gross Acres 1P Net Reserves of 12.6 MMBOE (40 ac spacing) 2P Net Reserves of 27.0 MMBOE (20 ac spacing) Current Gross Production – 700 BOEPD Current Net Monthly Revenue - $1MM

Final adjustment settlement – August 5th 10,300’wells: Spraberry, Dean, Wolfcamp, Cline,

Strawn, Mississippian & Woodford 1 rig currently drilling

5 wells drilled/drilling since acquisition 3 wells fracture stimulated, 2 wells awaiting on frac Lonestar No. 1 cleaning up flowing > 100 boepd Cottonwood No. 1 & Smith No. 1 just online All expected to be “type curve” wells 5 additional wells to be staked Near term milestone of > 1,000 boepd gross All land to be HBP in 2012

SUMMARY UPDATE

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Southern Star Type Curve


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Southern Star Type Curve (continued)


Southern Star Wells

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Southern Star Well Performance Summary


Time (Days)

Well C

ount

Southern Star Area Well Performance

Oil

Pro

duct

ion

(bop

d)

Total Well Cost $1.9 MM USD

IP (BOPD) 132

EUR MBOE (% Liquids) 226 (80%)

Remaining 40 acre locations 72

Remaining 20 acre locations

Up to 98 (170 total)

Blended WI/NRI 75.3%/ 57.3%

Undiscounted/Discounted Payback (years) 1.1 / 1.2

ROR @ $95/bo & $5/mcf 68%

F&D Cost ($/boe) $8.41/boe

Future Net Revenue (40 ac) $550 MM USD

Future Net Revenue (20 ac) $1,300 MM USD

Actual Average

Type Curve

Well Count

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Pace of Development – 1 Well / Month


Gro

ss P

rodu

ctio

n (b

oepd

) G

ross

Pro

duct

ion

(boe

pd)

Net M

onthly Operating R

evenue ($) N

et Monthly O

perating Revenue ($)

Monthly Net Operating Revenue ($)

Gross Daily Production (boepd)

Time (months)

Time (months)

40 ac development

20 ac development Monthly Net Operating Revenue ($)


Peak Net Revenue

Peak Daily Production

Peak Net Revenue


$4.5 MM / MONTH

3,600 BOEPD

$6.9 MM / MONTH

5,400 BOEPD

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Pace of Development – 2 Wells / Month


Gro

ss P

rodu

ctio

n (b

oepd

) G

ross

Pro

duct

ion

(boe

pd)

Net M

onthly Operating R

evenue ($) N

et Monthly O

perating Revenue ($)

Monthly Net Operating Revenue ($)


Time (months)

Time (months)

40 ac development

20 ac development Monthly Net Operating Revenue ($)


Peak Net Revenue


Peak Net Revenue


$6.2 MM / MONTH

4,900 BOEPD

$9.6 MM / MONTH

7,550 BOEPD

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Why 20 Acre Downspacing Is Inevitable


Spraberry Reservoirs Petrophysical Character

Wolfcamp Reservoirs Petrophysical Character

Wolfberry is currently being developed on 40-acre spacing. Large Operators (i.e. Pioneer) are undertaking 20-acre down-

spacing to maximize reservoir recoveries. Pioneer drilled 45, 20-acre wells in 2008 through 2010 with plans

to drill 20 more in 2011 following Field Rules applications. Original Oil in Place (OOIP) of 150-250 MMBO/section (640 Acres) Current Wolfberry per well EUR’s imply < 3% recovery of OOIP Spraberry = 60-100 MBOE Wolfcamp = 100-130 MBOE

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Big Star


SUMMARY UPDATE Currently over 17,500 gross (13,125 net) acres Projected over 20,000 gross (15,000 net) acres 11,200’ wells: Clear Fork, Spraberry, Dean,

Wolfcamp, Cline, Strawn, Mississippian & Woodford

400+ gross drilling locations on 40 acre spacing. 1 rig currently drilling No reserves are currently associated with Big Star

4 wells drilled/drilling since project acquisition 2 wells fracture stimulated 2 wells awaiting fracs (August) Stuart 12 No. 1 cleaning up. Has been online for

two weeks currently producing at commercial rates Evaluation period to take place at the conclusion of

all fracs. Reserves to be associated with Big Star

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Big Star Well Performance Summary


Total Well Cost $2.0 MM USD

IP (BOPD) 93

Type Curve EUR MBOE (% Liquids) 186 (80%)

Current Gross 40 acre drilling locations 400+

Projected Gross 40 acre drilling locations 500+

WI/NRI 90% BPO / 67.5% BPO 75% APO / 56.25% APO

Undiscounted/Discounted Payback (years) 1.2 / 1.3

ROR @ $95/bo & $5/mcf 65%

F&D Cost ($/boe) $10.22/boe

Net Reserve Potential (40 ac) 31 - 43 MMBOE

Net Revenue Potential (40 ac) $1,500+ MM USD

Time (Months) Actual Average

Type Curve

Well Count

Well C

ount

Oil

Pro

duct

ion

(bop

d)

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Northern Star


SUMMARY UPDATE 12,400 gross (12,400 net) acres 12,500’ wells: Clear Fork, Spraberry, Dean,

Wolfcamp, Cline, Strawn, Mississippian, Woodford & Devonian

300+ drilling locations on 40 acre spacing. 1 rig currently drilling No reserves currently associated with

Northern Star

1 well fracture stimulated 1 well currently drilling Newbrough No. 1 currently being remediated

for shallow water flow. To be in production during 3Q.

Cozart No. 1 to be fracture stimulated in 3Q Additional wells to be added in 2H2011 Tremendous level of permitting and drilling

activity

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Northern Star Value Proposition


Total Well Cost $2.2 – 2.4 MM USD

IP (BOEPD) 75 - 150

EUR MBOE (% Liquids) 125 - 175 (85%)

Net acreage position 12,400

40 acre drilling locations 310

WI/NRI 100% / 75%

Undiscounted/Discounted Payback (years) 1.3 – 1.5

Projected ROR 50%

F&D Cost ($/boe) $12.50 - $20.00

Net Reserve Potential (40 ac) 29 – 41 MMBOE

Net Revenue Potential (40 ac) $1,500+ MM USD

Recent flurry of permitting activity Chesapeake has permitted two

horizontal wells near lease position WTG Exploration – 13 wells Pioneer Natural Resources – 8 wells Element Petroleum – 7 wells – new

focus area W&T Offshore purchase of adjacent

leases for $366 MM USD Newbrough No. 1 – shallow water

remediation underway. Antares to drill new wells in 2H2011 After evaluating well results and

obtained geological data, Antares to bring in rig to fully develop leasehold.

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Peer Group – 2P Reserves


2P R

eser

ves

(MM

BO

E)

-

10,000,000

20,000,000

30,000,000

40,000,000

50,000,000

60,000,000

70,000,000

80,000,000

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Peer Group – Market Capitalization


Mar

ket C

apita

lizat

ion

($)

$-

$200,000,000

$400,000,000

$600,000,000

$800,000,000

$1,000,000,000

$1,200,000,000

$1,400,000,000

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$10.25

$17.23

$6.78 $4.81

$60.55

$7.42

$20.94

$13.87 $13.65

$8.40

$30.63

$13.99

$4.88

$50.92

$72.35

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

Peer Group – Market Cap / 2P Reserves


$22.44 Average

Mar

ket C

ap /

2P R

eser

ves

($/B

OE

)

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$1.00/share by Year End 2011


To achieve, Antares will need a market capitalization of $267.5 MM by years end. This will be reached due to:

Increasing 2P/3P reserve base through successful operational outcomes

Readily achievable production targets > 1,000 net boepd – 2011 > 2,000 net boepd – 2012 > 3,000 net boepd – 2013

Transparency in reporting operational activities and results as they are known. Strategic, focused acquisitions within the Permian Basin. Proven ability to optimally monetize assets Compelling value proposition in existing assets

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Investment Highlights


Proven successful management

Proven, profitable, repeatable business model

Proven acreage position

Proven development plan

Proven operators

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Contact Information


Antares Energy Limited 2nd Floor, 5 Ord Street West Perth, Western Australia 6005 + (61 8) 9324 2177 [email protected] www.antaresenergy.com

For further information contact: James Cruickshank Chairman & CEO + (61) (0) 488 222 122 or + (1) 214 762 2222

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Appendix 5B Mining exploration entity quarterly report

+ See chapter 19 for defined terms. 30/9/2001 Appendix 5B Page 1

Rule 5.3

Appendix 5B

Mining exploration entity quarterly report Introduced 1/7/96. Origin: Appendix 8. Amended 1/7/97, 1/7/98, 30/9/2001, 01/06/10.

Name of entity

Antares Energy Limited ABN Quarter ended (“current quarter”)

75 009 230 835 30 June 2011

Consolidated statement of cash flows

Cash flows related to operating activities

Current quarter $A’000

Year to date (6 months)

$A’000 1.1 Receipts from product sales and related

debtors

373 1,152

1.2 Payments for (a) exploration & evaluation (b) development (c) production (d) administration

(4,290) (3,534)

(24) (400)

(7,054) (3,534)

(130) (960)

1.3 Dividends received - - 1.4 Interest and other items of a similar nature

received 19 65

1.5 Interest and other costs of finance paid (1,964) (2,342) 1.6 Income taxes paid (8,317) (8,317) 1.7 Other (a) withholding tax (333) (333)

Net Operating Cash Flows (18,470) (21,453)

Cash flows related to investing activities

1.8 Payment for purchases of: (a) prospects (b) equity investments (c) other fixed assets

(70,381) -

(57)

(70,381) -

(140) 1.9 Proceeds from sale of: (a) prospects

(b) equity investments (c) other fixed assets

- - -

56,682 - -

1.10 Loans to other entities - - 1.11 Loans repaid by other entities - - 1.12 Other (provide details if material) - -

Net investing cash flows (70,438) (13,839) 1.13 Total operating and investing cash flows

(carried forward) (88,908) (35,292)

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+ See chapter 19 for defined terms. Appendix 5B Page 2 30/9/2001

1.13 Total operating and investing cash flows (brought forward) (88,908) (35,292)

Cash flows related to financing activities

1.14 Proceeds from issues of shares, options, etc. - - 1.15 Proceeds from sale of forfeited shares - - 1.16 Proceeds from borrowings - - 1.17 Repayment of borrowings - - 1.18 Dividends paid - - 1.19 Other (provide details if material)

• Share issue transaction costs • Payments for share buy-back

-

(3,393)

-

(8,309) Net financing cash flows (3,393) (8,309)

Net increase (decrease) in cash held

(92,301) (43,601)

1.20 Cash at beginning of quarter/year to date 124,878 77,443 1.21 Exchange rate adjustments to item 1.20 (4,705) (5,970)

1.22 Cash at end of quarter 27,872 27,872

Payments to directors of the entity and associates of the directors Payments to related entities of the entity and associates of the related entities

Current quarter $A'000

1.23

Aggregate amount of payments to the parties included in item 1.2

377

1.24

Aggregate amount of loans to the parties included in item 1.10

-

1.25

Explanation necessary for an understanding of the transactions

Item 1.23 includes aggregate amounts paid to directors including salary, directors’ fees, consulting fees and superannuation.

Non-cash financing and investing activities 2.1 Details of financing and investing transactions which have had a material effect on

consolidated assets and liabilities but did not involve cash flows

2.2 Details of outlays made by other entities to establish or increase their share in projects in

which the reporting entity has an interest

Financing facilities available Add notes as necessary for an understanding of the position.

Amount available $A’000

Amount used $A’000

3.1 Loan facilities

Nil Nil

3.2 Credit standby arrangements

Nil Nil

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Estimated cash outflows for next quarter $A’000

4.1 Exploration and evaluation 4,000

4.2 Development 4,000

4.3 Production 1,000

4.4 Administration 1,000

Total 10,000

Reconciliation of cash Reconciliation of cash at the end of the quarter (as shown in the consolidated statement of cash flows) to the related items in the accounts is as follows.

Current quarter $A’000

Previous quarter $A’000

5.1 Cash on hand and at bank 3,170 780

5.2 Deposits at call 24,702 67,416

5.3 Bank overdraft - -

5.4 Other (provide details) Promissory note - 56,682

Total: cash at end of quarter (item 1.22) 27,872 124,878

Changes in interests in mining tenements Tenement reference Nature of

interest (note (2))

Interest at beginning of quarter

Interest at end of quarter

6.1

Interests in mining tenements relinquished, reduced or lapsed

N/A

6.2

Interests in mining tenements acquired or increased

Texas-Midland Basin Northern Star Big Star Southern Star

12,400 leased mineral acres 11,250 leased mineral acres 3,120 leased mineral acres

Nil Nil Nil

100% (net acres) 100% (net acres) 100% (net acres) F

or p

erso

nal u

se o

nly


+ See chapter 19 for defined terms. Appendix 5B Page 4 30/9/2001

Issued and quoted securities at end of current quarter Description includes rate of interest and any redemption or conversion rights together with prices and dates. Total

number Number quoted

Issue price per security (see note 3) (cents)

Amount paid up per security (see note 3) (cents)

7.1 Preference +securities (description)

Nil

7.2 Changes during quarter (a) Increases through issues (b) Decreases through returns of capital, buy-backs, redemptions

Nil

7.3 +Ordinary securities 271,387,983 271,387,983 7.4 Changes during

quarter (a) Increases through issues (b) Decreases through returns of capital, buy-backs

974,167

(8,419,294)

974,167

(8,419,294)

7.5 +Convertible debt securities* (description)

7,500,000 7,500,000 $2.00 Fully paid

7.6 Changes during quarter (a) Increases through issues (b) Decreases through securities matured, converted

Nil

Nil

7.7 Options (description and conversion factor)

Nil Exercise price

Expiry date

7.8 Issued during quarter Nil 7.9 Exercised during

quarter Nil

7.10 Expired during quarter Nil 7.11 Performance rights** 666,667

7,500,000 Nil Nil

Nil Nil

09/10/2014 01/07/2015

7.12 a) Issued during quarter

Nil

b) Exercised during quarter

232,500 75,000

666,667

Nil Nil Nil

Nil Nil Nil

02/07/2012 31/10/2012

09/10/2014 c) Expired during

quarter 284,166 91,666

750,002 566,668

Nil Nil Nil Nil

Nil Nil Nil Nil

02/07/2012 31/10/2012

07/05/2013 04/11/2013

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* Convertible at a rate of 1:1. Interest paid at 10%, quarterly in arrears. Expiry date is 31 October 2013. Next reset date is 31 October 2012. At the reset date the Company resets the interest rate, conversion rate (to a maximum of 4:1) and the next reset date. The notes can be redeemed by the holders at the reset date and can be converted to ordinary shares at any time.

** Issued under the Performance Rights Plan approved by shareholders on 23 November 2004 and 26 May 2010 AGMs.

Compliance statement 1 This statement has been prepared under accounting policies which comply with

accounting standards as defined in the Corporations Act or other standards acceptable to ASX (see note 5).

2 This statement does /does not* (delete one) give a true and fair view of the

matters disclosed. Sign here: ............................................................ Date: 25 July 2011

(Director and Company Secretary) Print name: Vicky McAppion

Notes 1 The quarterly report provides a basis for informing the market how the entity’s

activities have been financed for the past quarter and the effect on its cash position. An entity wanting to disclose additional information is encouraged to do so, in a note or notes attached to this report.

2 The “Nature of interest” (items 6.1 and 6.2) includes options in respect of

interests in mining tenements acquired, exercised or lapsed during the reporting period. If the entity is involved in a joint venture agreement and there are conditions precedent which will change its percentage interest in a mining tenement, it should disclose the change of percentage interest and conditions precedent in the list required for items 6.1 and 6.2.

3 Issued and quoted securities The issue price and amount paid up is not

required in items 7.1 and 7.3 for fully paid securities. 4 The definitions in, and provisions of, AASB 1022: Accounting for Extractive

Industries and AASB 1026: Statement of Cash Flows apply to this report. 5 Accounting Standards ASX will accept, for example, the use of International

Accounting Standards for foreign entities. If the standards used do not address a topic, the Australian standard on that topic (if any) must be complied with.

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