EKA - Eureka Energy
- Thread starter Broadside
- Start date
-
- Tags
- eka eureka energy
- Joined
- 29 January 2010
- Posts
- 305
- Reactions
- 0
A proposed new acquisition and proposed capital raising..
they're going to need a lot of work to secure these leases of all this new land!! $$$$
they're going to need a lot of work to secure these leases of all this new land!! $$$$
- Joined
- 29 June 2006
- Posts
- 1,458
- Reactions
- 0
EUREKA SECURES OPTION TO INCREASE NET EAGLE FORD ACREAGE BY 278%
● Eureka signs option agreement to acquire 3,975 net acres in the Eagle Ford Shale. (“Brioche Project”)
● Upon exercise of the Option, Eureka will hold over 6,200 net acres of Eagle Ford shale and nearly 30,000 gross acres.
Eureka Energy is pleased to announce completion of an option agreement to acquire 3,975 net acres in the Burleson and Washington counties, Texas. The acreage lies within the eastern liquids-rich fairway and potentially is within the gas-condensate window of the Eagle Ford shale.
Agent M you got any comment on this new acquisition ground ??
Thanks,
● Eureka signs option agreement to acquire 3,975 net acres in the Eagle Ford Shale. (“Brioche Project”)
● Upon exercise of the Option, Eureka will hold over 6,200 net acres of Eagle Ford shale and nearly 30,000 gross acres.
Eureka Energy is pleased to announce completion of an option agreement to acquire 3,975 net acres in the Burleson and Washington counties, Texas. The acreage lies within the eastern liquids-rich fairway and potentially is within the gas-condensate window of the Eagle Ford shale.
Agent M you got any comment on this new acquisition ground ??
Thanks,
- Joined
- 2 October 2006
- Posts
- 3,043
- Reactions
- 2
i can see some 19 efs wells for the apache, all drilled in 2008. none since
looks like only one well, the apache giesenchlag-groce is showing any signs of some payback for the well costs so far, the greater majority would be not so pleasing for apache in any way really imho in terms of payback
2 wells last year in january and in june for williams clayton energy..
thats all i can find,, i cant find anything for washington county what so ever in the EFS
i can post up the production numbers for you
looks like only one well, the apache giesenchlag-groce is showing any signs of some payback for the well costs so far, the greater majority would be not so pleasing for apache in any way really imho in terms of payback
2 wells last year in january and in june for williams clayton energy..
thats all i can find,, i cant find anything for washington county what so ever in the EFS
i can post up the production numbers for you
Attachments
i can see some 19 efs wells for the apache, all drilled in 2008. none since
looks like only one well, the apache giesenchlag-groce is showing any signs of some payback for the well costs so far, the greater majority would be not so pleasing for apache in any way really imho in terms of payback
2 wells last year in january and in june for williams clayton energy..
thats all i can find,, i cant find anything for washington county what so ever in the EFS
i can post up the production numbers for you
The majority of wells other than 2 gas wells are still a fair distant to where EKA are looking at so i dont see the relevance in what your saying Agentm.
It's a bit like comparing McMullen to Duval county but thanks for the interest.
Attachments
Sdajii
Sdaji
- Joined
- 13 October 2009
- Posts
- 2,063
- Reactions
- 2,043
Agentm is probably thinking it's a hot deal and quietly accumulating
*waits for Agentm's next abusive PM*
- Joined
- 19 January 2010
- Posts
- 63
- Reactions
- 0
Capital raising was at 36c and oversubscribed, at only a small discount to current levels this is a good sign imo. Land purchased at a bargain price. If this land turns out to be productive the share price should really kick on.
A copy and paste of what I wrote up on Hotcopper, regarding an estimation as to what the value of our Sugarloaf interest. Make of it what you will.
We own 1500 acres net, out of the 24000 gross sugarloaf acres. Therefore by owning a relatively small percentage of a very big area, we won't face issues of wasted offcuts of land e.g. in our Fayette acreage, there might be an offcut or two which the company can't squeeze into the drilling plans as there isn't enough spacing within our acreage to do so. This won't be an issue for the sugarloaf, as missing out on the spacing of 1 well with a 6.25% working interest isn't that significant at all in the scheme of things.
1500 acres / 80 acre spacings = a total of 18.75 wells for EKA over the duraction of the Sugarloaf. I'll use 80 acre spacings for these calcs but in the future 60 acre spacings will probably come into play, with the possibility of slightly even tighter spacings eventually.
Expenses first: This data comes from NSAI's assumptions for the December 2010 reserves report (located in AUT's investor presentation from March 8)
18.75 net wells * $6.75 million per well = $126.6 million we have to pay for capital expenses over the duration of the Sugarloaf.
We also pay $20,000 per well/month. Let's assume the well flows for 15 years (EOG investor reports show a possible flow of 20 years)
That's $3.6 million per well over this 15 year period.
In other words roughly $10.35 million per well, capital and operating expenses.
Revenue:
If we assume a possible 500K EUR, that's equivalent to $54 million (p.o. $108/barrel) revenue from this well.
54-10.35 = roughly $44 million per well of profit (before tax and royalties)
After royalties of 25%, this = $33 million
after corporate tax of 35%, this = $21.45 million
$21.45 million * 18.75 = $402 million
Take about $50 million for admin expenses and this becomes $350 million. Our current MCap is only $80 million.
So a fully developed MCap of $350 million could be achievable from purely producing the sugarloaf over the 15 or so years. (with peak production most likely in line with AUT's peak production in 2017).
N.B. These rough calculations are using 80 acre wells spacings. The potential of 60 and possibly 40 acres could very well (60 acre well spacings probably will) come into play in the future. If 60 acre spacings eventuate, that $350 million can turn into something like $450 million.
So although the growth would be steady over 10 years or so, share price growth of 5 times purely from the Sugarloaf is very much achievable, and this is using the current assumptions. An AUT broker report has said that AUT's reserves could increase by as much as 10 times with tighter well spacings and new fraccing technology.
We own 1500 acres net, out of the 24000 gross sugarloaf acres. Therefore by owning a relatively small percentage of a very big area, we won't face issues of wasted offcuts of land e.g. in our Fayette acreage, there might be an offcut or two which the company can't squeeze into the drilling plans as there isn't enough spacing within our acreage to do so. This won't be an issue for the sugarloaf, as missing out on the spacing of 1 well with a 6.25% working interest isn't that significant at all in the scheme of things.
1500 acres / 80 acre spacings = a total of 18.75 wells for EKA over the duraction of the Sugarloaf. I'll use 80 acre spacings for these calcs but in the future 60 acre spacings will probably come into play, with the possibility of slightly even tighter spacings eventually.
Expenses first: This data comes from NSAI's assumptions for the December 2010 reserves report (located in AUT's investor presentation from March 8)
18.75 net wells * $6.75 million per well = $126.6 million we have to pay for capital expenses over the duration of the Sugarloaf.
We also pay $20,000 per well/month. Let's assume the well flows for 15 years (EOG investor reports show a possible flow of 20 years)
That's $3.6 million per well over this 15 year period.
In other words roughly $10.35 million per well, capital and operating expenses.
Revenue:
If we assume a possible 500K EUR, that's equivalent to $54 million (p.o. $108/barrel) revenue from this well.
54-10.35 = roughly $44 million per well of profit (before tax and royalties)
After royalties of 25%, this = $33 million
after corporate tax of 35%, this = $21.45 million
$21.45 million * 18.75 = $402 million
Take about $50 million for admin expenses and this becomes $350 million. Our current MCap is only $80 million.
So a fully developed MCap of $350 million could be achievable from purely producing the sugarloaf over the 15 or so years. (with peak production most likely in line with AUT's peak production in 2017).
N.B. These rough calculations are using 80 acre wells spacings. The potential of 60 and possibly 40 acres could very well (60 acre well spacings probably will) come into play in the future. If 60 acre spacings eventuate, that $350 million can turn into something like $450 million.
So although the growth would be steady over 10 years or so, share price growth of 5 times purely from the Sugarloaf is very much achievable, and this is using the current assumptions. An AUT broker report has said that AUT's reserves could increase by as much as 10 times with tighter well spacings and new fraccing technology.
- Joined
- 29 January 2010
- Posts
- 305
- Reactions
- 0
Does EKA, And AUT pay the full price for the wells?? which you got @ 6.75m... or is this cost split up between the operators??
or was that only part of the original farm in business?
or was that only part of the original farm in business?
My understanding with the farm in was that Hillcorp paid for the cost of the wells and re couped the cost of the well once it went to sales. When the cost was recovered from the sales EKA AUT recieved their % on the continuing sales.
Angus,
the 18.5 net well count I calculated, came from dividing our net sugarloaf area by the acre spacing.
The reality is that EKA will be participating in (23500/80) = 294 sugarloaf wells at the current spacing, but these are at the 6.25% working interest, which ends up being 18.5 net wells. So by the time the sugarloaf is fully developed we'd have paid 18.5* $6.75 million based on current costs.
As for the capex of the wells, I thought that for the first 3 farm in wells, we paid back the capex of those through production (i.e. we only actually got revenue from the wells after our capital share of the costs had been recovered through oil production), and that for the rest of the wells we just paid it in cash.
That's what I think anyway.
the 18.5 net well count I calculated, came from dividing our net sugarloaf area by the acre spacing.
The reality is that EKA will be participating in (23500/80) = 294 sugarloaf wells at the current spacing, but these are at the 6.25% working interest, which ends up being 18.5 net wells. So by the time the sugarloaf is fully developed we'd have paid 18.5* $6.75 million based on current costs.
As for the capex of the wells, I thought that for the first 3 farm in wells, we paid back the capex of those through production (i.e. we only actually got revenue from the wells after our capital share of the costs had been recovered through oil production), and that for the rest of the wells we just paid it in cash.
That's what I think anyway.
Sugarloaf Gas and Condensate Project >> Hilcorp Energy – Sugarloaf Farm-in
In the 3rd quarter of 2009 Eureka, together with other Sugarloaf AMI participants, was successful in farming out its Sugarloaf acreage to Hilcorp Energy Company (“Hilcorp”), one the largest privately owned E&P companies in the USA.
At the time, in the midst of the Global Financial Crisis, the farmin by an established large company such as Hilcorp represented a significant endorsement of the multi TCFe potential of the Sugarloaf gas and condensate asset and the value of Eureka’s interest. Since that time, Hilcorp has demonstrated its ability to efficiently operate the Sugarloaf AMI.
Pursuant to the farmout arrangements, Eureka has and will continue to be free carried for the:
•drilling, completion, fracture stimulation and tie in of 3 new horizontal wells (these wells have now been drilled & tied in to sales lines and are awaiting stimulation - Rancho Grande #1H, Morgan #1H, and Easley #1H), and
•fracture stimulation of the three existing Sugarloaf horizontal wells; Kennedy #1H, Kowalik #1H and Weston #1H (the stimulation of Kennedy#1H and Weston#1H has occurred – with very encouraging initial production rates).
Under the Farmout, Eureka’s working interest in the Sugarloaf AMI will reduce by 50% (from 12.5% to 6.25%) upon completion of the above work obligations.
The Hilcorp activity within Sugarloaf has yielded very encouraging production from the first two stimulation operations and the initial production results from the first two new wells are amongst the best reported in the field. Eureka believes that these results together with the production results from the final farminwell which is soon to be stimulated and the widespread ongoing regional activity will greatly assist in establishing the considerable value of our interest in the Sugarloaf AMI.
Eureka’s capital requirements during the farmin period have been minimal as Hilcorp is providing a free carry over 100% of Eureka’s costs. Hilcorp will receive priority pay back of its capital costs, thereafter, Eureka is entitled to its post farmout share of production income.
Hilcorp has also committed to a farmin over other land areas within the Sugarkane Field either adjacent to or nearby the Sugarloaf AMI, with corresponding drilling requirements. This additional activity will lead to a meaningful drilling and completion program that aims to establish a portfolio of producing wells within the Sugarkane acreage that in turn will assist in demonstrating the multi Tcfe potential of the Sugarloaf AMI.
This website is optimised for viewing with Internet Explorer 6.0 or better. Using other browsers may have unpredictable results.
All content © 2011 Eureka Energy Ltd. Site by Biz AnyWare
In the 3rd quarter of 2009 Eureka, together with other Sugarloaf AMI participants, was successful in farming out its Sugarloaf acreage to Hilcorp Energy Company (“Hilcorp”), one the largest privately owned E&P companies in the USA.
At the time, in the midst of the Global Financial Crisis, the farmin by an established large company such as Hilcorp represented a significant endorsement of the multi TCFe potential of the Sugarloaf gas and condensate asset and the value of Eureka’s interest. Since that time, Hilcorp has demonstrated its ability to efficiently operate the Sugarloaf AMI.
Pursuant to the farmout arrangements, Eureka has and will continue to be free carried for the:
•drilling, completion, fracture stimulation and tie in of 3 new horizontal wells (these wells have now been drilled & tied in to sales lines and are awaiting stimulation - Rancho Grande #1H, Morgan #1H, and Easley #1H), and
•fracture stimulation of the three existing Sugarloaf horizontal wells; Kennedy #1H, Kowalik #1H and Weston #1H (the stimulation of Kennedy#1H and Weston#1H has occurred – with very encouraging initial production rates).
Under the Farmout, Eureka’s working interest in the Sugarloaf AMI will reduce by 50% (from 12.5% to 6.25%) upon completion of the above work obligations.
The Hilcorp activity within Sugarloaf has yielded very encouraging production from the first two stimulation operations and the initial production results from the first two new wells are amongst the best reported in the field. Eureka believes that these results together with the production results from the final farminwell which is soon to be stimulated and the widespread ongoing regional activity will greatly assist in establishing the considerable value of our interest in the Sugarloaf AMI.
Eureka’s capital requirements during the farmin period have been minimal as Hilcorp is providing a free carry over 100% of Eureka’s costs. Hilcorp will receive priority pay back of its capital costs, thereafter, Eureka is entitled to its post farmout share of production income.
Hilcorp has also committed to a farmin over other land areas within the Sugarkane Field either adjacent to or nearby the Sugarloaf AMI, with corresponding drilling requirements. This additional activity will lead to a meaningful drilling and completion program that aims to establish a portfolio of producing wells within the Sugarkane acreage that in turn will assist in demonstrating the multi Tcfe potential of the Sugarloaf AMI.
This website is optimised for viewing with Internet Explorer 6.0 or better. Using other browsers may have unpredictable results.
All content © 2011 Eureka Energy Ltd. Site by Biz AnyWare
EUREKA AGREES EAGLE FORD SHALE LEASE POOLING ARRANGEMENT IN FAYETTE COUNTY – FIRST WELL PLANNED TO SPUD DURING Q2 2011
The Directors are pleased to announce that Eureka has entered into a lease-pooling agreement covering part of its Fayette County Eagle Ford Shale acreage.
Commenting on the arrangement, Eureka Chairman Ian McCubbing said:
“This is a mutually beneficial arrangement with the potential to add greatly to the value of our overall Fayette County acreage with a comparatively modest drilling outlay. We are pleased to be moving on to the exploration phase of our second Eagle Ford shale property with a well expected to be spud within only 10 months of acquiring these leases. Since Eureka acquired this acreage leasing activity in Fayette County has accelerated rapidly and (as detailed in our December Quarterly Report) wells within approximately 20 miles of our holding that appear to be on trend have reported estimated ultimate recoveries of 362,000 and 500,000 boe. We look forward to working together with the highly regarded and experienced GeoResources and Nabors groups to unlock the value of this project area”
Under the terms of the agreement Eureka will:
● Contribute approximately 86 acres to form a new drilling unit known as Blackjack Springs
● Hold a 9.4% working interest in the 916 acre pooled area (see Fig 1.)
● Pay for its working interest share of a planned horizontal well expected to be spud during Q2 2011
● Retain its current 100% working interest ownership of the remaining 675 acres of Eureka’s Fayette County project area
The agreement is with Southern Bay Operating, LLC (”Southern Bay”). Southern Bay is a wholly-owned subsidiary of NASDAQ-listed GeoResources, Inc. (“GeoResources”), and is involved in a joint venture with an affiliate of Nabors Industries LTD (“Nabors”) to acquire and develop acreage in Texas that is prospective for the Eagle Ford Shale.
The Directors are pleased to announce that Eureka has entered into a lease-pooling agreement covering part of its Fayette County Eagle Ford Shale acreage.
Commenting on the arrangement, Eureka Chairman Ian McCubbing said:
“This is a mutually beneficial arrangement with the potential to add greatly to the value of our overall Fayette County acreage with a comparatively modest drilling outlay. We are pleased to be moving on to the exploration phase of our second Eagle Ford shale property with a well expected to be spud within only 10 months of acquiring these leases. Since Eureka acquired this acreage leasing activity in Fayette County has accelerated rapidly and (as detailed in our December Quarterly Report) wells within approximately 20 miles of our holding that appear to be on trend have reported estimated ultimate recoveries of 362,000 and 500,000 boe. We look forward to working together with the highly regarded and experienced GeoResources and Nabors groups to unlock the value of this project area”
Under the terms of the agreement Eureka will:
● Contribute approximately 86 acres to form a new drilling unit known as Blackjack Springs
● Hold a 9.4% working interest in the 916 acre pooled area (see Fig 1.)
● Pay for its working interest share of a planned horizontal well expected to be spud during Q2 2011
● Retain its current 100% working interest ownership of the remaining 675 acres of Eureka’s Fayette County project area
The agreement is with Southern Bay Operating, LLC (”Southern Bay”). Southern Bay is a wholly-owned subsidiary of NASDAQ-listed GeoResources, Inc. (“GeoResources”), and is involved in a joint venture with an affiliate of Nabors Industries LTD (“Nabors”) to acquire and develop acreage in Texas that is prospective for the Eagle Ford Shale.
SUGARLOAF PROJECT - INDEPENDENT RESERVES REPORT
● Proved (1P) oil Reserves Increase by 145% to 1.2 million barrels plus 5.6 BCF gas (50% increase)*
● Proved + Probable (2P) oil Reserves increased by 70% to 2.7 million barrels plus 12.4 BCF gas (13% increase)*
● Proved + Probable + Possible Oil (3P) Reserves increased by 10% to 5.4 million barrels, Gas reduced 16% to 25 BCF*
The Eureka Directors are pleased to report that independent petroleum consultants, Netherland Sewell & Associates (NSAI), Inc., of Houston, Texas have completed estimates of petroleum reserves and future revenues for the Eureka Energy Limited interest in the Sugarloaf Project. Their report is dated 31 December 2010.
NSAI have prepared the estimates in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE).
* The noted change in reserves is in relation to the 1st July, 2010 NSAI reserves report, as disclosed by Eureka Energy on 18th August, 2010.
Page | 2
Eureka has prepared the following summary from the NSAI Report.
STATEMENT OF RESERVES AND FUTURE NET REVENUE FOR EUREKA’S INTEREST
Net Reserves
Future Net Revenue (USD) Category
Oil (Barrels)
Gas (MCF)
Total
Present Worth at 10% discount Proved
1,233,797
5,575,139
86,418,400
48,897,000 Probable
1,503,801
6,845,226
102,506,800
46,322,200 Sub-total 2P
2,737,598
12,420,365
188,925,200
95,219,200 Possible
2,702,691
12,586,978
184,154,600
64,852,100 Total 3P
5,440,289
25,007,343
373,079,800
160,071,300
Reserves are for Eureka’s post farmout interest in Sugarloaf (6.25%) and are net of all royalties. Future Net Revenue to Eureka is after deducting royalties, state production taxes, ad valorem taxes, capital expenditure, operating expenditure and abandonment costs but not company income taxes.
Oil and gas prices used are based on 1 January 2011 NYMEX West Texas Intermediate prices and are adjusted for quality, transportation fees and regional price differential. Gas prices are based on 1 January NYMEX Henry Hub prices and are adjusted for energy content, transportation fees, and a regional price differential. All prices before adjustment are shown on the following table:
Period Ending
Oil Price (USD/Barrel)
Gas Price (USD/MMBTU)
31/12/2011
93.61
4.59
31/12/2012
93.95
5.08
31/12/2013
92.95
5.33
31/12/2014
92.40
5.49
31/12/2015
92.55
5.64
Thereafter
93.11
5.79
The reserves are based on 283 horizontal wells with 80 acre spacing. There is potential to increase reserves by increasing recovery per well and by reducing future well spacing.
Page | 3
Mr Ian McCubbing, chairman of Eureka commented:
“Eureka is pleased to note a 70% increase in Proved and Probable (2P) oil reserves and a 13% increase in 2P gas reserves.
The 3P NPV10 value of the project is calculated by NSAI to have reduced by some 15% from US $187 to US $160 million. The main reason for the reduction is the conservative application of higher Operating Cost assumptions. The NPV has also been calculated using January 1 2011 prices, but if the February 28th forward strip is used, the NPV10 increases to US$178 million.
Given that we can expect to have an additional 13 wells by December 31 2011 , it is expected that most of the 3P reserves will be converted to Proved and Probable (2P) reserves by year end.”
Technical Information contained in this report has been reviewed by Mr C. C. Hodge M.Sc, a consultant to Eureka who has had more than 30 years experience in petroleum geology and has consented to the inclusion of the information in the form and context in which it appears.
● Proved (1P) oil Reserves Increase by 145% to 1.2 million barrels plus 5.6 BCF gas (50% increase)*
● Proved + Probable (2P) oil Reserves increased by 70% to 2.7 million barrels plus 12.4 BCF gas (13% increase)*
● Proved + Probable + Possible Oil (3P) Reserves increased by 10% to 5.4 million barrels, Gas reduced 16% to 25 BCF*
The Eureka Directors are pleased to report that independent petroleum consultants, Netherland Sewell & Associates (NSAI), Inc., of Houston, Texas have completed estimates of petroleum reserves and future revenues for the Eureka Energy Limited interest in the Sugarloaf Project. Their report is dated 31 December 2010.
NSAI have prepared the estimates in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE).
* The noted change in reserves is in relation to the 1st July, 2010 NSAI reserves report, as disclosed by Eureka Energy on 18th August, 2010.
Page | 2
Eureka has prepared the following summary from the NSAI Report.
STATEMENT OF RESERVES AND FUTURE NET REVENUE FOR EUREKA’S INTEREST
Net Reserves
Future Net Revenue (USD) Category
Oil (Barrels)
Gas (MCF)
Total
Present Worth at 10% discount Proved
1,233,797
5,575,139
86,418,400
48,897,000 Probable
1,503,801
6,845,226
102,506,800
46,322,200 Sub-total 2P
2,737,598
12,420,365
188,925,200
95,219,200 Possible
2,702,691
12,586,978
184,154,600
64,852,100 Total 3P
5,440,289
25,007,343
373,079,800
160,071,300
Reserves are for Eureka’s post farmout interest in Sugarloaf (6.25%) and are net of all royalties. Future Net Revenue to Eureka is after deducting royalties, state production taxes, ad valorem taxes, capital expenditure, operating expenditure and abandonment costs but not company income taxes.
Oil and gas prices used are based on 1 January 2011 NYMEX West Texas Intermediate prices and are adjusted for quality, transportation fees and regional price differential. Gas prices are based on 1 January NYMEX Henry Hub prices and are adjusted for energy content, transportation fees, and a regional price differential. All prices before adjustment are shown on the following table:
Period Ending
Oil Price (USD/Barrel)
Gas Price (USD/MMBTU)
31/12/2011
93.61
4.59
31/12/2012
93.95
5.08
31/12/2013
92.95
5.33
31/12/2014
92.40
5.49
31/12/2015
92.55
5.64
Thereafter
93.11
5.79
The reserves are based on 283 horizontal wells with 80 acre spacing. There is potential to increase reserves by increasing recovery per well and by reducing future well spacing.
Page | 3
Mr Ian McCubbing, chairman of Eureka commented:
“Eureka is pleased to note a 70% increase in Proved and Probable (2P) oil reserves and a 13% increase in 2P gas reserves.
The 3P NPV10 value of the project is calculated by NSAI to have reduced by some 15% from US $187 to US $160 million. The main reason for the reduction is the conservative application of higher Operating Cost assumptions. The NPV has also been calculated using January 1 2011 prices, but if the February 28th forward strip is used, the NPV10 increases to US$178 million.
Given that we can expect to have an additional 13 wells by December 31 2011 , it is expected that most of the 3P reserves will be converted to Proved and Probable (2P) reserves by year end.”
Technical Information contained in this report has been reviewed by Mr C. C. Hodge M.Sc, a consultant to Eureka who has had more than 30 years experience in petroleum geology and has consented to the inclusion of the information in the form and context in which it appears.
SUGARLOAF AMI OPERATIONS AND PRODUCTION UPDATE
Aurora Oil & Gas Limited (“Aurora”) is pleased to provide the following update on operations and
production at the Sugarloaf Area of Mutual Interest (“AMI”) within the Sugarkane Gas &
Condensate Field, Texas.
Aurora also participates as a WI holder in a larger area made up of an additional ~ 49,500 acres
within the Sugarkane Field adjacent to the Sugarloaf AMI. Aurora is the only listed participant in
these areas and currently has three other rigs operating in that acreage. Aurora provides separate
updates on those operations.
Production Data
The following wells have been on production for a period of either 30 or 60 days and Aurora is
pleased to provide the market with an update on produced volumes during that period:-
Working
Interest
Total Gas
Production
(mmscf)
Total
Condensate
Production
(bbls)
Average Daily
Equivalent Oil
Rate (boe/d)*
Direct Assets #1H – 30 day 10% 40.6 13,930 690
Direct Assets #1H – 60 day 10% 81.7 26,376 666
Hollman #1H – 30 day 15.78% 58.8 17,875 884
*The equivalent barrels per day production rate has been calculated on a simple 6:1 ratio in compliance with Canadian
securities laws under National Instrument 51 - 101.
Operations
Hollman #1H (15.78% WI)
This Hollman well was fracture stimulated with 18 stages across approximately 4,800 ft of
horizontal length. The well commenced flowing on 7th March 2011 and the 30 day production
results are provided in the table above. This well achieved first production 43 days after it was
spudded.
PMT #1H (28.7% WI)
The PMT well location lies across the Sugarloaf and Ipanema AMI areas. As such Aurora holds a
blended working interest of 28.7% in the well. The well spudded on 14/2/11 and reached TD on the
26th March 2011 at a Total Depth (“TD”) of 18,200 ft. Production casing has been run on this well
and it is awaiting fracture stimulation.
Buehring #1H (15.78% WI)
Drilling operations commenced on the 18th February 2011 and the well reached a TD of 17,386ft on
9th March 2011. Production casing has been run on this well and the fracture stimulation of this well
has just been completed with 16 fracture stages. Aurora will provide an update to the market once
30 day production figures are available.
Davenport #1H (24.31% WI)
The Davenport #1H well location lies across the Sugarloaf and Longhorn AMI boundaries and as
such Aurora holds a 24.31% blended working interest in the well. This well is presently at
approximately 5,000 ft and drilling ahead.
ASX participants in the Sugarloaf AMI are:
Aurora (ASX:AUT and TSX:AEF) – 15.7%
AWE (ASX:AWE) – 10%
Eureka (ASX:EKA) – 6.25%
About Aurora
Aurora is an Australian and Toronto listed oil and gas company active exclusively in the over
pressured liquids rich region of the Eagle Ford Shale in Texas, United States. The Company is
engaged in the development and production of oil, condensate and natural gas in Karnes, De Witt
and Atascosa counties in South Texas. Aurora participates in over 73,000 highly contiguous gross
acres in the heart of the trend, including over 15,600 net acres within the liquids rich zones of the
Eagle Ford. Aurora is funded for and expects to participate in approximately 60 new development
wells during 2011.
Technical information contained in this report in relation to the Sugarkane field was compiled by
Aurora from information provided by the project operator and reviewed by I L Lusted, BSc (Hons),
SPE, a Director of Aurora who has had more than 15 years experience in the practice of petroleum
engineering. Mr. Lusted consents to the inclusion in this report of the information in the form and
context in which it appears.
Aurora Oil & Gas Limited (“Aurora”) is pleased to provide the following update on operations and
production at the Sugarloaf Area of Mutual Interest (“AMI”) within the Sugarkane Gas &
Condensate Field, Texas.
Aurora also participates as a WI holder in a larger area made up of an additional ~ 49,500 acres
within the Sugarkane Field adjacent to the Sugarloaf AMI. Aurora is the only listed participant in
these areas and currently has three other rigs operating in that acreage. Aurora provides separate
updates on those operations.
Production Data
The following wells have been on production for a period of either 30 or 60 days and Aurora is
pleased to provide the market with an update on produced volumes during that period:-
Working
Interest
Total Gas
Production
(mmscf)
Total
Condensate
Production
(bbls)
Average Daily
Equivalent Oil
Rate (boe/d)*
Direct Assets #1H – 30 day 10% 40.6 13,930 690
Direct Assets #1H – 60 day 10% 81.7 26,376 666
Hollman #1H – 30 day 15.78% 58.8 17,875 884
*The equivalent barrels per day production rate has been calculated on a simple 6:1 ratio in compliance with Canadian
securities laws under National Instrument 51 - 101.
Operations
Hollman #1H (15.78% WI)
This Hollman well was fracture stimulated with 18 stages across approximately 4,800 ft of
horizontal length. The well commenced flowing on 7th March 2011 and the 30 day production
results are provided in the table above. This well achieved first production 43 days after it was
spudded.
PMT #1H (28.7% WI)
The PMT well location lies across the Sugarloaf and Ipanema AMI areas. As such Aurora holds a
blended working interest of 28.7% in the well. The well spudded on 14/2/11 and reached TD on the
26th March 2011 at a Total Depth (“TD”) of 18,200 ft. Production casing has been run on this well
and it is awaiting fracture stimulation.
Buehring #1H (15.78% WI)
Drilling operations commenced on the 18th February 2011 and the well reached a TD of 17,386ft on
9th March 2011. Production casing has been run on this well and the fracture stimulation of this well
has just been completed with 16 fracture stages. Aurora will provide an update to the market once
30 day production figures are available.
Davenport #1H (24.31% WI)
The Davenport #1H well location lies across the Sugarloaf and Longhorn AMI boundaries and as
such Aurora holds a 24.31% blended working interest in the well. This well is presently at
approximately 5,000 ft and drilling ahead.
ASX participants in the Sugarloaf AMI are:
Aurora (ASX:AUT and TSX:AEF) – 15.7%
AWE (ASX:AWE) – 10%
Eureka (ASX:EKA) – 6.25%
About Aurora
Aurora is an Australian and Toronto listed oil and gas company active exclusively in the over
pressured liquids rich region of the Eagle Ford Shale in Texas, United States. The Company is
engaged in the development and production of oil, condensate and natural gas in Karnes, De Witt
and Atascosa counties in South Texas. Aurora participates in over 73,000 highly contiguous gross
acres in the heart of the trend, including over 15,600 net acres within the liquids rich zones of the
Eagle Ford. Aurora is funded for and expects to participate in approximately 60 new development
wells during 2011.
Technical information contained in this report in relation to the Sugarkane field was compiled by
Aurora from information provided by the project operator and reviewed by I L Lusted, BSc (Hons),
SPE, a Director of Aurora who has had more than 15 years experience in the practice of petroleum
engineering. Mr. Lusted consents to the inclusion in this report of the information in the form and
context in which it appears.
EKA hasn't had much support in the wake of it's capital raising @ 36c.
For a change Mr average share holder can buy in at a cheaper price at around 34c unlike TXN who had a raising @ 65c? to all of it's holders and has maintained their sp of around 83c.
Maybe holders of EKA aren't too happy with the Brioche Project? Some large sells and few buyers lined up today. Patience is the key here and a buying opportunity for those who missed out on the raising.
For a change Mr average share holder can buy in at a cheaper price at around 34c unlike TXN who had a raising @ 65c? to all of it's holders and has maintained their sp of around 83c.
Maybe holders of EKA aren't too happy with the Brioche Project? Some large sells and few buyers lined up today. Patience is the key here and a buying opportunity for those who missed out on the raising.
- Joined
- 21 May 2010
- Posts
- 223
- Reactions
- 9
Cheers Jancha,
I think a lot of funds have shifted over to TXN who seem to be the flavour of the month, (probably rightly so). I've also been tempted to do so but just can't seem to push the sell button at these levels. I sold out of SEA a week or so ago to buy TXN and also more EKA.
Just can't see why EKA is so unloved. Noika has a chant going on another forum which is proving un-successful. Perhaps it will be EKA's turn next month. Dec-Jan was AUT's, last month was SSN, this month is TXN, next EKA???
Just as I dont fall in love with a share nor do I fall out of love with one. I just sit back and wonder where I may be wrong. I go back and look at the reasons why i hold that share. If I decide the reasons still add up fundamentally then i continue to hold. With EKA I continue to hold, even buy a few more. I'll admit I did sell some. They were the ones that are part of my project on ASF to show that it is worth investing $1500. They were sold to take up the TXN SPP as part of the exercise and not for any other reason. I am now buying them back in slightly increased numbers thanks to the drop in th SP. That is one advantage of a stagnant SP, an opportunity to trade for freebies.
I have been saying "Come on EKA Come on" and "Aussie, Aussie, Aussie Oi, Oi, Oi" Hoping to use some cheer squad psychology to motivate this little beast in the olympics of oil search. It doesn't seem to be working. Team EKA will lose a sponsor or two if this keeps up.:aus:
I have been saying "Come on EKA Come on" and "Aussie, Aussie, Aussie Oi, Oi, Oi" Hoping to use some cheer squad psychology to motivate this little beast in the olympics of oil search. It doesn't seem to be working. Team EKA will lose a sponsor or two if this keeps up.:aus:
Cheers Jancha,
I think a lot of funds have shifted over to TXN who seem to be the flavour of the month, (probably rightly so). I've also been tempted to do so but just can't seem to push the sell button at these levels. I sold out of SEA a week or so ago to buy TXN and also more EKA.
Just can't see why EKA is so unloved. Noika has a chant going on another forum which is proving un-successful. Perhaps it will be EKA's turn next month. Dec-Jan was AUT's, last month was SSN, this month is TXN, next EKA???
You could be right there Assasin,
I've been top heavy in EKA and did exactly that. I like to trade a % in and out of EKA but find of late it's not volatile enough hence the trade down. Still my favourite tho and as you say down the track they should have their own run up but i wish it would hurry up.
