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To: Paul Senior who wrote (18893)3/30/2012 12:55:32 PM
From: yyz_man
1 Recommendation   of 23063
 
I bought more CZE today. The selloff in CZE is way overdone, in my opinion, even if the entire block is written off. Skimming through CNE and CZE's presentations, I see the value of the block is about 1/5 the entire value of CZE's exploration prospects this year... something like $0.50 a share in rough numbers. The stock is recovering, but it was down about $1.50 earlier today. I thought CZE was undervalued at it's pre-drill price as well, so this is gravy.

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To: yyz_man who wrote (18894)3/30/2012 1:32:34 PM
From: Paul Senior
   of 23063
 
Thanks. I appreciate your view of the situation.

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To: yyz_man who wrote (18894)3/30/2012 2:41:39 PM
From: westslope
1 Recommendation   of 23063
 
CZE.to produces 10K bopd of light & medium oil; trades at C$43K bopd, 3X CFPS. Median value for Colombia producers I follow is $66K boed, 5.1X CFPS.

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To: architect* who wrote (18885)3/30/2012 2:55:10 PM
From: westslope
   of 23063
 
Hey architect*! Those $1 million paintings might be a better investment than some o&g stocks these days.... Between CEN.to and CZE.to I feel like the rugby team turned on me.....

Kenya and neighbouring countries are risky. But the targets are big. I would definitely go to Kenya on holiday though I'd pay attention in a few areas. Then I doubt you and friends vacation in East L.A.




I like growing working capital surpluses too but seem to settle for companies that maintain healthy surpluses, and yet have trouble finding oil.




Selling at Brent or near Brent prices is nice but I wouldn't shy away from WCSB heavy oil plays just because they are selling product at a discount to WTI. Canadian Oilsands for example. Heavy oil plays offer long-life reserves. Own PRE.to, COS.to, NOC Ecopetrol (ECP.to) and Venezuela-penalized HNR.n.

Watch Venezuela, things might change for the better and soon. Either the government and/or business practices. A Chinese-financed pipeline from Venezuela to the Colombian coast could bring changes even in the absence of a change of government.







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To: yyz_man who wrote (18894)3/30/2012 2:57:39 PM
From: architect*
   of 23063
 
"I bought more CZE today."

I also bought more CZE shares today - increasing my position by 25%.


PS> I sold my 37% portfolio of Coastal Energy, down to 0% portfolio in the $19.75 - $20.50 range. Bought back an 18% portfolio share of CEN shares at $17.90. I thought CZE - better value - today than CEN at $15.21.

PPS> The switch from CEN into PMG shares at a 1 to 1 ratio has been working nicely. Too bad I didn't invest, acoordinly. increased my position in GTE in the $5.80 / share range. The majority of the CEN proceeds, from my "young guy portfolio" were reinvested into an income - "Old guy portfolio".

ING Income funds ETFs ~ 10% distribution

IGA - Global Advance - Apple, Exxon, Micorsoft, Chevron IBM
IHD - Emerging Market High Dividend- Gazprom, Petrolbras, China Mobile, POSCO, VALE, Samsung, China Pacific, Taiwan Semiconductor,
IDE - INdustry and Materials - Catapiller, National Oilwell, Varco, Union pacific, Honeywell, General Dynamics, Emerson Electric, BHP Hilton, Vodafone, Dover, Flur.
IAE - Asia Pacific High Dividend- Samsung Electric, BHP Bilton, Bank of Australia, China Mobile, China Bank
IGD - Glboal Equity High Dividend- Trans-Canada, JP Morgan, Dutch Shell, Zurich financial, Cnetury-Link, UGI, AT&T, Pitney Bowes, Abbott Industires, Vinci.

Distributions from ING income ETF's are a combination of dividends and covered call premium.

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To: westslope who wrote (18897)3/30/2012 3:11:46 PM
From: architect*
1 Recommendation   of 23063
 
Then I doubt you and friends vacation in East L.A.

Manhatten Beach, is where we vacation in Los Angeles. From Manhatten Beach, this summer we'll tour up, the Pacific Coast. I'd like to be rich by say May 2012, yeah that works! Somebody, needs to discovere more oil like CEN with Bua Ban North and Gran Tierra with the Proa oil field. If Gran Tierra is successful with Ramiriqi exploration well into the Mirador reservoir package, that would do the trick. Let GTE do the work in 2012, that CEN did in 2011.

Heavy oil plays offer long-life reserves. Own PRE.to, COS.to, NOC Ecopetrol (ECP.to)

All good!

Let us know when Venezuela gets investor friendly, for United States small cap oil investors.

We're going dancing Saturday in a Latin Club. Where I met a Venezuelan, who was employed in the Venezuelan oil business. He loves Hugo. Hugo has built schools, built hospitals, and built retail shopping centers. Before- no schools, no hospitals, no shopping -and no good. Now Hugo, now good!

I ask the amigo, "What are the top two businesses in Venezuela"?

Amigo relies,
1) a well manged oil company.
2) a poorly managed oil company.

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From: LoneClone3/30/2012 6:05:35 PM
   of 23063
 
Corridor Announces 2011 Year End Results and Reserves

Press Release: Corridor Resources Inc. – 14 minutes ago

finance.yahoo.com




HALIFAX, NOVA SCOTIA--(Marketwire -03/29/12)- (TSX: CDH.TO - News): Corridor Resources Inc. ("Corridor") announced today its 2011 year end financial results and reserve evaluations. Corridor's annual financial statements, management's discussion and analysis and Annual Information Form for the year ended December 31, 2011 have been filed on SEDAR at www.sedar.com and are available on Corridor 's website at www.corridor.ca.

All amounts referred to in this press release are in Canadian dollars unless otherwise stated.

2011 Highlights

--  During the year, Corridor completed the drilling of the vertical Will
DeMille O-59 shale gas appraisal well to a total depth of 3188 meters
measured depth. Strong gas shows were encountered within Hiram Brook
sandstones and the Upper Frederick Brook shale. Based upon initial
analysis of well log information, the well intersected at least eight
intervals with significantly elevated gas shows that are considered frac
candidates. Corridor plans to evaluate these intervals with logs and
sidewall cores in order to select the intervals for future fracture
stimulation. The Will DeMille O-59 well is located north of Elgin, New
Brunswick.

-- During the year, Corridor reported the results of an independent
resource assessment, dated July 12, 2011 and effective June 1, 2011
("the Sproule Report"), by qualified reserves evaluator Sproule
Associates Limited of Calgary ("Sproule"). Based on data available at
the time, Sproule's best estimate of the Total Petroleum Initially-In-
Place of the Macasty Shale on Anticosti Island is 33.9 (19.8 net to
Corridor) billion barrels of oil equivalent ("Bboe") for Corridor's land
holdings. The probability that the Total Petroleum Initially-In-Place
exceeds 21.4 (12.3 net to Corridor) Bboe is 90% (low estimate) and the
probability that the Total Petroleum Initially-In-Place exceeds 53.9
(31.9 net to Corridor) Bboe is 10% (high estimate). Sproule classified
the total Petroleum Initially-In-Place as "undiscovered resources".
Corridor is actively evaluating options regarding further exploration to
determine the potential of this resource, including the possibility of
farming out some of the Corridor interest to an experienced shale oil
developer. The Anticosti exploration program is at an early stage;
further work is required to determine the potential for commercially
viable resource recovery, prior to considering development.

-- During the year, Corridor filed a Project Description and an
Environmental Assessment with the Canada-Newfoundland and Labrador
Offshore Petroleum Board ("C-NLOPB") for the drilling of an exploration
well on the Old Harry prospect. The Project Description commenced the
official regulatory process for obtaining the necessary approvals to
drill the offshore well. Initially, the C-NLOPB determined that
Corridor's application would be subject to a project specific screening
level Environmental Assessment ("EA") while the Western Newfoundland
Strategic Environmental Assessment ("SEA") took place concurrently.
However, subsequently, the C-NLOPB decided that the SEA update would be
completed before proceeding with the review of the Old Harry EA and
announced that the SEA update would be completed in early 2013. Corridor
believes that both the SEA update and the Old Harry EA processes can be
completed in a timeline which will accommodate Corridor's proposed
project schedule. Corridor currently proposes to drill a well at Old
Harry within the 2014-15 timeframe. In October 2011, the C-NLOPB amended
Corridor's Exploration Licence 1105 to extend Period 1 of the license
from five years to seven years (January 15, 2015) which should provide
Corridor with sufficient time to gain the regulatory permits required to
drill the Old Harry prospect in the proposed timeframe. Corridor's
exploration license also has a provision whereby Corridor can extend
this drilling period by an additional year with the payment of a
deposit.

-- Corridor maintains approximately 2 million gross acres (approximately
1.3 million net acres) of undeveloped land in connection with its three
high impact exploration prospects (Frederick Brook shale, Macasty shale
oil and Old Harry prospect). The remaining terms on substantially all
the licenses in respect of such prospects range from 4.5 to 9 years.
Corridor is actively seeking joint venture partners in all three
prospects.

-- On March 20, 2012, the Government of Quebec announced its 2012-2013
budget which includes provisions that recognize the potential of Quebec
as an oil and gas producer and outlines steps to encourage the
development of this potential.

Year End Financial Results

The following table provides a summary of Corridor's financial and operating results for the three and twelve months ended December 31, 2011 with comparisons to the three and twelve months ended December 31, 2010.

Selected Financial Information

 

----------------------------------------------------------------------------
Three months ended Twelve months ended
December 31 December 31
thousands of dollars except
per share amounts 2011 2010 2011 2010
----------------------------------------------------------------------------
Revenues $ 5,295 $ 7,864 $ 23,993 $ 29,558
Net earnings (loss) $ (71,416) $ (3,038) $ (79,585) $ (6,912)
Net earnings (loss) per share
- basic and diluted $ (0.807) $ (0.034) $ (0.899) $ (0.078)
Cash flow from operations(1) $ 2,071 $ 3,585 $ 9,250 $ 13,250
Capital expenditures $ 4,383 $ 1,840 $ 8,951 $ 21,006
Total assets $ 204,017 $ 301,283 $ 204,017 $ 301,283
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Cash flow from operations is a non-IFRS measure. Cash flow from
operations represents net earnings adjusted for non-cash items including
depletion, depreciation and amortization, deferred income taxes, share-based
compensation and other non-cash expenses. See "Non-IFRS Financial Measures"
in Corridor's management's discussion and analysis for the year ended
December 31, 2011.

Financial Summary for 2011

 

-- Natural gas revenues for the year ended December 31, 2011 decreased to
$21,777 thousand from $27,283 thousand for the year ended December 31,
2010 due to a decrease in the average natural gas sales price to
$5.17/mscf in 2011 from $5.66/mscf in 2010 and a decrease in Corridor's
average daily gas production to 11.5 mmscfpd in 2011 from 13.2 mmscfpd
in 2010. The decrease in natural gas prices at Henry Hub during the year
was offset by higher premiums at Dracut which have increased by 25% over
the prior year to an average of approximately US$1.00/mmbtu for the year
ended December 31, 2011.

-- Cash flow from operations was $9,250 thousand for the year ended
December 31, 2011 compared to $13,250 thousand for the year ended
December 31, 2010 due to the lower natural gas revenues in 2011
partially offset by lower transportation expenses. Cash flow from
operations for the year ended December 31, 2011 was approximately $1,000
thousand higher than the latest forecast of $8,200 thousand due to an
increase in gathering, processing and transportation fees in Q4 2011.

 

-- Corridor's net working capital at December 31, 2011 was $9,507 thousand,
approximately $3,500 thousand higher than previously forecasted due to
higher cash flow from operations and reduced capital expenditures in Q4
2011. Corridor had cash and cash equivalents at December 31, 2011 of
$6,396 thousand and no outstanding debt.

-- Due to the significant decline in forecast natural gas prices, Corridor
was required under IFRS to estimate the recoverable amount of its New
Brunswick assets at December 31, 2011. The recoverable amount was
determined using discounted after-tax future net cash flows of proved
plus probable reserves using forecast prices and costs. As IFRS does not
permit the use of a risk-free discount rate, Corridor estimated its
discount rate as 10%. As a result, Corridor recorded an impairment loss
of $90,307 thousand during the year and Corridor's net loss increased to
$79,585 thousand for the year ended December 31, 2011 from $6,192
thousand for the year ended December 31, 2010.

-- Corridor's gross general and administrative expenses decreased by $648
thousand for the year ended December 31, 2011 compared to the year ended
December 31, 2010 reflecting management's commitment to lower general
and administrative expenses during this period of lower natural gas
prices.

-- During the year, workover activities of approximately $900 thousand were
carried out on selected wells in an effort to optimize and improve
production from these wells. Corridor also performed well surveillance
activities with optimization of flow cycles and soaping of liquid
loading wells. Workover activities and optimization efforts resulted in
a gross initial uplift of 1.0 mmscfpd.

Q4 2011 Netback Analysis

 

----------------------------------------------------------------------------
Three months ended Twelve months ended
December 31 December 31
thousands of dollars except
$/mscf 2011 2010 2011 2010
----------------------------------------------------------------------------
Natural gas revenues $ 4,194 $ 7,024 $ 21,777 $ 27,283
Royalty expense (-) (256) (679) (606)
Production expense (752) (1,016) (3,969) (3,931)
Transportation expense (1,181) (1,798) (5,499) (6,840)
----------------------------------------------------------------------------
Netback $ 2,261 $ 3,954 $ 11,630 $ 15,906
----------------------------------------------------------------------------

Natural gas production
(mmscf) 985 1,223 4,213 4,819
Natural gas production per
day (mmscfpd) 10.7 13.3 11.5 13.2

Natural gas revenues ($/mscf) $ 4.26 $ 5.74 $ 5.17 $ 5.66
Royalty expense ($/mscf) (0.00) (0.21) (0.16) (0.13)
Production expense ($/mscf) (0.76) (0.83) (0.94) (0.82)
Transportation expense
($/mscf) (1.20) (1.47) (1.31) (1.42)
----------------------------------------------------------------------------
Netback ($/mscf) $ 2.30 $ 3.23 $ 2.76 $ 3.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Natural gas revenues decreased to $4,194 thousand in Q4 2011 from $7,024 thousand in Q4 2010 due to the decrease in the average natural gas sales price to $4.26/mscf in Q4 2011 from $5.74/mscf in Q4 2010 and the decrease in the average daily natural gas production to 10.7 mmscfpd in Q4 2011 from 13.3 mmscfpd in Q4 2010. The decrease in production is due to the decreased drilling activities at the McCully Field since 2009 following decreases in natural gas prices .

The decrease in the royalty expense for Q4 2011 is due to no royalty amounts being payable as a result of the significant decrease in the natural gas revenues due to low natural gas prices during Q4 2011, while the deductions allowable in the royalty calculation did not decrease significantly.

The decrease in the net production expense per mscf for Q4 2011 to $0.76/mscf from $0.83/mscf for Q4 2010 is due to the decrease in workover activities in Q4 2011. In addition, higher repairs and maintenance and supplies were necessary in Q4 2010 following the installation of an inlet compressor.

Transportation expense decreased to $1.20/mscf for Q4 2011 from $1.47/mscf for Q4 2010 due to the impact of a transportation agreement for 12,000 mmbtu per day of transportation on the Canadian side of the M&NP in effect from April 1, 2011 to March 31, 2012 at a cost significantly lower than firm tolls and to a stronger Canadian dollar as compared to the U.S. dollar.

2011 Reserve Information

Corridor currently has natural gas reserves in the McCully Field near Sussex, New Brunswick and has crude oil reserves in the Caledonia Field near Sussex, New Brunswick.

GLJ has assessed Corridor's reserves in its reports ("the GLJ Reports") dated effective December 31, 2011 and December 31, 2010 which were prepared in accordance with National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities. The following table presents a summary from the GLJ Reports of Corridor's gross natural gas reserves, before the deduction of royalties, using forecast prices and costs.

 

----------------------------------------------------------------------------
2011 Gross 2010 Gross
Reserves Reserves
Reserves Category bscf bscf
----------------------------------------------------------------------------
Total proved 58.7 62.2
Total probable 44.0 59.2
----------------------------------------------------------------------------
Total proved plus probable 102.7 121.4
Possible(1) 114.1 118.7
----------------------------------------------------------------------------
Proved plus probable plus
possible(1) 216.7 240.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Possible reserves are those additional reserves that are less certain to
be recovered than probable reserves. There is a 10% probability that the
quantities actually recovered will equal or exceed the sum of proved plus
probable plus possible reserves.

The decrease in proved reserves results mostly from the 2011 production of 4.2 bscf.

The proved plus probable reserves assessment has decreased due to the delay in drilling new development wells as a result of low forecasted natural gas prices.

GLJ assessed the net present value of Corridor's natural gas, oil and natural gas liquids reserves, based on forecast costs and prices, as follows:

 

Net Present Value ($ in million) - undiscounted

----------------------------------------------------------------------------
2011 2010
----------------------------------------------------------------------------
Before After Before After
Income Income Income Income
Reserves Category Tax(1) Tax(1) Tax(1) Tax(1)
----------------------------------------------------------------------------
Proved 219 211 257 238
Proved plus probable 464 388 627 506
Proved plus probable plus
possible(2) 1,217 931 1,447 1,096
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The estimated value of future net revenue does not represent the fair
market value of Corridor's reserves.
(2) Possible reserves are those additional reserves that are less certain to
be recovered than probable reserves. There is a 10% probability that the
quantities actually recovered will equal or exceed the sum of proved plus
probable plus possible reserves.


Net Present Value ($ in million) - discounted at 10%

----------------------------------------------------------------------------
2011 2010
----------------------------------------------------------------------------
Before After Before After
Income Income Income Income
Reserves Category Tax(1) Tax(1) Tax(1) Tax(1)
----------------------------------------------------------------------------
Proved 96 95 122 118
Proved plus probable 171 152 226 194
Proved plus probable plus
possible(2) 352 283 430 340
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The estimated value of future net revenue does not represent the fair
market value of Corridor's reserves.
(2) Possible reserves are those additional reserves that are less certain to
be recovered than probable reserves. There is a 10% probability that the
quantities actually recovered will equal or exceed the sum of proved plus
probable plus possible reserves.

The decrease in the net present value of Corridor's net reserves is primarily the result of declines in forecasted natural gas prices as estimated by GLJ.

GLJ assigned to Corridor total proved crude oil reserves of 87 mbbls and total proved plus probable crude oil reserves of 521 mbbls in the GLJ Reports. The complete 2011 GLJ Report will be available in the near future on Corridor's website at www.corridor.ca, and a summary of the 2011 GLJ Report is included in Corridor's Annual Information Form for the year ended December 31, 2011, a copy of which has been filed on SEDAR at www.sedar.com.

Corridor is a junior resource company engaged in the exploration for and development and production of petroleum and natural gas onshore in New Brunswick, Prince Edward Island and Quebec and offshore in the Gulf of St. Lawrence. Corridor currently has natural gas reserves and production in the McCully Field near Sussex, New Brunswick and discovered crude oil reserves in the Caledonia Field near Sussex, New Brunswick in 2008. In addition, Corridor has contingent resources and discovered resources in Elgin, New Brunswick.

Forward Looking Statements

This press release contains certain forward-looking statements and forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of Canadian securities laws. All statements other than statements of historical fact are forward-looking statements. Forward-looking information typically contains statements with words such as "anticipate", "believe", "plan", "continuous", "estimate", "expect", "may", "will", "project", "should", or similar words suggesting future outcomes. In particular, this press release contains forward-looking statements pertaining to the estimates of reserves and resources, net present values of reserves, exploration and development plans, including plans regarding development of the Frederick Brook formation, drilling a well on the Old Harry prospect and exploration on Anticosti Island, regulatory developments and timing of such developments and plans to solicit joint venture partners. Statements relating to "reserves" and "resources" are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can profitably be produced in the future.

Undue reliance should not be placed on forward-looking statements, which are inherently uncertain, are based on estimates and assumptions, and are subject to known and unknown risks and uncertainties (both general and specific) that contribute to the possibility that the future events or circumstances contemplated by the forward-looking statements will not occur. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will in fact be realized. Actual results will differ, and the difference may be material and adverse to Corridor and its shareholders.

Forward-looking statements are based on Corridor's current beliefs as well as assumptions made by, and information currently available to, Corridor concerning anticipated financial performance, business prospects, strategies, regulatory developments, future natural gas commodity prices, future natural gas production levels, the ability to obtain equipment in a timely manner to carry out development activities, the ability to market natural gas successfully to current and new customers, the impact of increasing competition, the ability to obtain financing on acceptable terms, and the ability to add production and reserves through development and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that forward-looking statements will not be achieved. These factors may be found under the heading "Risk Factors" in Corridor's Annual Information Form for the year ended December 31, 2011.

The forward-looking statements contained in this press release are made as of the date hereof and Corridor does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Oil and Gas Information

BOE conversions

All calculations converting natural gas to crude oil equivalent have been made using a ratio of six mscf of natural gas to one barrel of oil equivalent ("boe"). Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six mscf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Resources Information

"Total petroleum initially-in-place" or ("PIIP") refers to that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Total petroleum initially-in-place is equivalent to total resources.

"Undiscovered petroleum initially-in-place" or "undiscovered resources" refers to those quantities of petroleum that are estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially-in-place is referred to as prospective resources, the remainder as unrecoverable. Undiscovered resources carry discovery risk. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. There is no certainty that any portion of these resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of undiscovered petroleum initially-in-place at this time.

In respect of the Macasty Shale on Anticosti Island, Sproule classified the total petroleum initially-in-place as undiscovered resources in the Sproule Report, based on the following: (i) a core of the Macasty shale from the Chaloupe well contained residual oil; (ii) the Macasty shale has not been flow tested from any well on Anticosti Island; (iii) the resources are inferred to exist based on the interpretation and mapping of limited pyrolysis, core, well log and seismic data; (iv) this is an unconventional shale oil resource that will require a stimulated completion for evaluation and, until an appropriately researched project has been undertaken to identify and evaluate potentially recoverable volumes, it is premature to speculate whether the Macasty contains recoverable or unrecoverable resources. Corridor believes the significant positive factors relevant to the estimates are: (i) the Macasty core from the Chaloupe well drilled in 2010 contained oil and gas. This well is located on the high side of the Jupiter fault, where most of the Corridor acreage is located, and where the shale is interpreted to be oil prone; (ii) the Macasty shale is equivalent to the Utica shale of the St. Lawrence Lowlands of Quebec, which has been reported to have produced oil and gas on test; (iii) Core analysis indicates that the Macasty has similar petrophysical and geochemical characteristics to Utica fields found in the North-East US; and (iv) the Macasty shale is a prolific source rock which is within the oil generation window over approximately three quarters of the island (most of it located in the Corridor land holdings).


Contact:

Phillip R. Knoll, President
Corridor Resources Inc.
(902) 429-4511
(902) 429-0209 (FAX)
www.corridor.ca

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To: LoneClone who wrote (18900)3/30/2012 6:12:19 PM
From: LoneClone
1 Recommendation   of 23063
 
Gran Tierra Energy Announces 6,300 BOPD Production Test on Proa-2 Appraisal Well, Argentina

Press Release: Gran Tierra Energy Inc. – 17 hours ago

finance.yahoo.com




Drilling Programs Advance in Colombia and Brazil , Production Update

CALGARY , March 29, 2012 /CNW/ - Gran Tierra Energy Inc. ("Gran Tierra Energy") (NYSE Amex: GTE) (TSX: GTE - News), a company focused on oil exploration and production in South America , today provided updates for its operations in Argentina , Colombia and Brazil .

Argentina

Surubi Block, Noroeste Basin (Gran Tierra Energy 85% WI and Operator, Recursos y Energia de Formosa S.A. 15% WI)

Gran Tierra Energy has completed drilling and testing the Proa-2 appraisal well, the second well in the Proa oil field. The successful well encountered approximately 31 meters of net pay in two Palmar Largo intervals. Production tests were performed on the two intervals independently, resulting in combined natural flow rates of 6,300 barrels of oil per day ("BOPD") gross of 46° API oil with no water cut. The well is expected to be on production in April, 2012, initially at approximately 2,000 BOPD gross to further analyze reservoir performance while additional transportation capacity is evaluated.

Colombia

Llanos-22 Block, Llanos Basin (CEPSA 55% WI and Operator, Gran Tierra Energy 45% WI subject to Agencia Nacional de Hidrocarburos approval)

The Ramiriqui-1 oil exploration well in the Llanos-22 block, located in the Andean foothills trend of the Llanos Basin, has reached total depth at 19,519 feet measured depth in basement. A testing program has been designed to test the reservoir and hydrocarbon character of the zones with oil shows encountered during drilling the Mirador Formation. Results from this testing are expected in April, 2012.

Brazil

REC-T-155 Block (Gran Tierra Energy 70% WI & Operator, Alvorada 30% WI)

The 3-GTE-03D-BA and 3-GTE-4DPA-BA appraisal wells, located 1.2 kilometers north and 0.70 kilometers south of the 1-ALV-2-BA oil discovery well respectively, are scheduled to be tested and expected to be on production by June, 2012. In addition, Gran Tierra Energy is currently preparing the necessary Agência Nacional de Petróleo, Gás Natural e Biocombustíveis documents for the declaration of commerciality and the plan of development for the field.

REC-T-142 Block (Gran Tierra Energy 70% WI & Operator, Alvorada 30% WI)

Drilling of the first horizontal sidetrack well, currently planned to be drilled from the 1-GTE-01-BA pilot hole, has been delayed to June, 2012 due to rig availability. This will be the first of three horizontal sidetrack wells that Gran Tierra Energy expects to be drilled to test the productivity of the light oil sandstone reservoir targets in the Recôncavo Basin.

Production

First quarter production and sales have been impacted by approximately 26 days of oil delivery restrictions due to three separate Ecopetrol-operated Oleoducto Transandino ("OTA") pipeline disruptions in Colombia , the latest of which occurred on March 13 , 2012. Gran Tierra Energy continued production at a reduced rate while the OTA pipeline was down, selling a portion of its crude through trucking and storing excess crude. The pipeline has been repaired and was back in service on March 24, 2012 . Gran Tierra Energy's current production is approximately 19,200 barrels of oil equivalent per day ("BOEPD").

Also, as a result of entering into new crude oil sales and transportation agreements with Ecopetrol as of February 1, 2012 , which changed the sales point of produced oil from Orito to Tumaco, Gran Tierra Energy's reported crude oil inventory will increase representing ownership of oil in the OTA and associated Ecopetrol owned facilities. This change in sales point and the increase in crude oil inventory will have a corresponding one-time reduction in oil sales of approximately 1,600 BOEPD net after royalty ("NAR") to be reported for the quarter. As a result of the OTA pipeline disruptions and the new crude oil sales and transportation agreements, sales for all Gran Tierra Energy properties are expected to average approximately 16,000 BOEPD NAR, from January 1, 2012 to March 31, 2012 .

About Gran Tierra Energy Inc.

Gran Tierra Energy is an international oil and gas exploration and production company, headquartered in Calgary , Canada , incorporated in the United States , trading on the NYSE Amex Exchange (GTE) and the Toronto Stock Exchange (GTE), and operating in South America . Gran Tierra Energy holds interests in producing and prospective properties in Colombia , Argentina , Peru , and Brazil . Gran Tierra Energy has a strategy that focuses on establishing a portfolio of producing properties, plus production enhancement and exploration opportunities to provide a base for future growth.

Gran Tierra Energy's Securities and Exchange Commission filings are available on a web site maintained by the Securities and Exchange Commission at sec.gov and on SEDAR at sedar.com.

Forward Looking Statements and Advisories

This news release contains certain forward-looking information and forward-looking statements (collectively, "forward-looking statements") under the meaning of applicable securities laws, including Canadian Securities Administrators' National Instrument 51-102 - Continuous Disclosure Obligations and the United States Private Securities Litigation Reform Act of 1995. The use of the words "expected", "planned", "scheduled", "will" and derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this news release contains forward-looking statements regarding Gran Tierra Energy's planned and expected drilling operations in Argentina , Brazil and Colombia including, without limitation, anticipated production, drilling and testing timelines.

The forward-looking statements contained in this news release reflect several material factors and expectations and assumptions of Gran Tierra Energy including, without limitation: assumptions relating to log evaluations; that Gran Tierra Energy will continue to conduct its operations in a manner consistent with past operations; the accuracy of testing and production results and seismic data; the effects of certain drilling techniques; and the general continuance of current or, where applicable, assumed operational, regulatory and industry conditions. Gran Tierra Energy believes the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking statements contained in this news release are subject to risks, uncertainties and other factors that could cause actual results or outcomes to differ materially from those contemplated by the forward-looking statements, including, among others: unexpected technical difficulties and operational difficulties may occur, or the obtaining of environmental permits may be delayed, which could impact or delay the commencement of drilling, production or testing; geographic, political and weather conditions can impede testing, which could impact or delay the commencement of drilling, production or testing; and the risk that current global economic and credit market conditions may impact oil prices and oil consumption more than Gran Tierra Energy currently predicts, which could cause Gran Tierra Energy to chante its current drilling, production and testing plans. Although Gran Tierra Energy's plans for its ongoing exploration and development and the funding thereof are based upon the current expectations of the management of Gran Tierra Energy, there may be circumstances where, for unforeseen reasons, a change in such plans may be necessary as may be determined at the discretion of Gran Tierra Energy. Should any one of a number of issues arise, Gran Tierra Energy may find it necessary to alter its current business strategy. Further information on potential factors that could affect Gran Tierra Energy are included in risks detailed from time to time in Gran Tierra Energy's Securities and Exchange Commission filings, including, without limitation, under the caption "Risk Factors" in Gran Tierra Energy's Annual Report on Form 10-K filed February 27, 2012 . These filings are available on a Web site maintained by the Securities and Exchange Commission at sec.gov and on SEDAR at www.sedar.com. The forward-looking statements contained herein are expressly qualified in their entirety by this cautionary statement. The forward-looking statements included in this press release are made as of the date of this press release and Gran Tierra Energy disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable securities legislation.

Barrels of oil equivalent ("BOE") may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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To: LoneClone who wrote (18901)3/30/2012 6:20:50 PM
From: LoneClone
   of 23063
 
Iona Energy Provides Orlando Drilling Results and Updates Status of Equity Offering Closing

8 hours ago

ca.finance.yahoo.com
CALGARY, ALBERTA--(Marketwire - March 30, 2012) -

NOT FOR DISTRIBUTION TO UNITED STATES NEWS WIRE SERVICES OR DISSEMINATION IN UNITED STATES

Iona Energy Inc. ("Iona" or the "Company") (TSX VENTURE: INA.V - News) is pleased to announce its Orlando appraisal well 3/3b-13 has reached its total depth target within the planned trajectory for the development well. The top of the reservoir was encountered at approximately 13,286 ft Measured Depth (-11,428 ft True Vertical Depth Sub Sea) and logs show the expected Upper Tarbert reservoir is present and is fully oil bearing and more of the underlying Upper Ness reservoir sands oil bearing than in the original discovery well (Well 3/3-11). The oil bearing interval within the Upper Ness exceeds management's expectations.

The well has been drilled to a Measured Depth ("MD") of 14,300 feet, and Total Vertical Depth Sub Sea ("TVDSS") of -12,104 feet in Middle Jurassic (Brent reservoir group) sands and shales. Based on a preliminary evaluation of the logs, the Tarbert and Ness Reservoirs correlate strongly with those same units encountered in the original discovery well 3/3-11. Logging shows the Tarbert contains 76 ft of True Vertical Thickness ("TVT") gross sandstone (60 ft Net) and the Ness contains gross 166 ft of TVT gross sandstone (46 ft Net). An estimated oil column on the Orlando Field of approximately 270 ft above the 11,670 ft TVDSS oil water contact, inferred by the 3/3-11 well, has been confirmed by the 3/3b-13 well.

To date, Iona has met all of its cash commitments to the project. Iona believes the completion of this well meets its license commitment on the block and looks forward to developing the Orlando field with its joint venture partners.

Neill Carson, Iona's CEO, commented, "We have a better than expected well result which keeps us on track for filing our Field Development Plan with expected approval this summer."

Iona Energy also wishes to update the status of its previously announced public offering of a minimum of CAD$60 million of common shares of the Company and a maximum of CAD$80 million of common shares (the "Offering"). The closing of the Offering is conditional on receipt by the Company of final credit approval from the lenders for its credit facility as further described in the Company's news release dated February 28, 2012 and other customary regulatory approvals, which have been obtained.

Iona has received first stage credit and capital committee approvals from all lenders and the Company expects to receive final credit committee approvals from the lenders on or about April 4, 2012 with the equity Offering to close shortly thereafter.

"Subject to definitive agreements, final terms of the facility have been agreed and the last of our lenders are completing the final steps in their rigorous credit processes, for which we expect to receive a positive result on shortly." commented Brad Gunn, Iona Energy 's CFO.

Mr. Gunn also stated "This is a relatively large credit facility with more than one lender and each has their own processes and stages of approvals. As soon as we receive final credit approval we will move swiftly to close on the Offering. On closing, we expect to be fully funded for our planned development activities."

About Iona Energy:

Iona Energy Inc. is an oil and gas exploration, development and production company focused on oil and gas development and exploration in the United Kingdom's North Sea.

Additional information relating to the Company is available on SEDAR at www.sedar.com.

Forward-looking statements

Some of the statements in this announcement are forward-looking. Forward-looking statements include statements regarding the intent, belief and current expectations of Iona Energy Inc. or its officers with respect to various matters. When used in this announcement, the words "expects," "believes," "anticipate," "plans," "may," "will," "should", "scheduled", "targeted", "estimated" and similar expressions, and the negatives thereof, whether used in connection with the estimated development of the Orlando well and future activity or otherwise, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to risks and uncertainties that could cause actual outcome to differ materially from those suggested by any such statements. These forward-looking statements speak only as of the date of this announcement. Iona Energy Inc. expressly disclaims any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement contained herein to reflect any change in its expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based except as required by applicable securities laws.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Contacts

Neill A. Carson
Iona Energy Inc.
Chief Executive Officer
011 (44) 7919 057989

Brad G. Gunn
Iona Energy Inc.
Chief Financial Officer
(403) 775-7442

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From: LoneClone4/1/2012 7:30:53 PM
   of 23063
 
Canadian Spirit Resources Inc. Announces 2011 Financial Results and Filing of Annual Disclosure Documents

Press Release: Canadian Spirit Resources Inc. – Fri, Mar 30, 2012 8:27 PM EDT

finance.yahoo.com




CALGARY, ALBERTA--(Marketwire - March 30, 2012) - Canadian Spirit Resources Inc. ("CSRI" or the "Corporation")(TSX VENTURE: SPI.V - News) (OTCBB: CSPUF.PK - News) announces the release of its financial results for the three and twelve months ended December 31, 2011 and the filing of its 2011 annual audited Financial Statements and Management Discussion and Analysis and Annual Information Form.

The financial data presented herein is in accordance with International Financial Reporting Standards ("IFRS") and all amounts are presented in Canadian dollars, unless otherwise indicated. The 2011 annual audited financial statements include certain reconciliations between the previously used Canadian Generally Accepted Accounting Principles ("previous GAAP") and IFRS.

This news release summarizes information contained in the audited financial statements and MD&A for the twelve month period ended December 31, 2011 and should not be considered a substitute for reading these documents, which are available on SEDAR at www.sedar.com or the Corporation 's website at www.csri.ca for full disclosure.

CSRI is a natural resources company focusing on the identification and development of opportunities in the unconventional gas sector of the energy industry.

OPERATIONAL HIGHLIGHTS





-- Natural gas sales for 2011 total $1.7 million.

-- 5 wells on production - 2011 exit production of 2 MMcf/d (net).

-- A vertical well at 17-7-83-24W6 was drilled and completed. The well is

designed to evaluate the quantity of natural gas liquids within the

eastern lands of Farrell Creek.

-- Williston Reservoir Water Pipeline Project completed.

-- CSRI's share proved plus probable Montney reserves as at December 31,

2011 of 10.6 Bcf with a net present value of $6.1 million (10% discount

rate).



FINANCIAL HIGHLIGHTS





-- Non-brokered private placement of 2.46 million units at $0.75 per unit

closed in December 2011, realizing gross proceeds of $1.84 million.

-- Obtained a new $3.5 million revolving credit facility with ATB Corporate

Financial Services.



FINANCIAL AND OPERATIONAL OVERVIEW

Selected Financial Information

For the years ended and as at December 31 2011 2010

----------------------------------------------------------------------------



Gross natural gas sales, before royalties $ 1,731,024 $ -

Operating netbacks, after royalty credits

applied $ 745,879 $ -

Cash flow from operating activities $ (930,790) $ (1,583,394)

Net loss and comprehensive loss $ (17,575,219) $ (1,466,747)

Loss per share, basic & diluted $ (0.24) $ (0.03)

Net working capital $ 2,520,655 $ 21,001,529

Total assets $ 62,927,463 $ 89,689,299

Shareholders' capital $ 59,208,853 $ 75,349,547

Common shares outstanding 76,238,661 74,598,861

Total capital expenditures $ 19,390,622 $ 19,519,316



Revenue and Royalties

Total gross revenue from the sale of natural gas for the three and twelve months ended December 31, 2011 was $642,431 and $1,731,024, respectively. The five wells tied into the Farrell Creek Montney Gas Facility as at December 31, 3011 are all deep horizontal wells and as such, each of these producing wells qualifies for the British Columbia Government's Deep Royalty Credit Program. This Program will generate up to $2.5 million (gross) in royalty credits for each well and the royalty credits will be drawn down over time as the wells produce natural gas. At current rates of production, the Corporation should not have to remit any crown royalties to the British Columbia Government for the next two to three years.





Production



Three months ended Twelve months ended

December 31, December 31,

---------------------------------------

2011 2010 2011 2010

----------------------------------------------------------------------------



Total production of natural gas (Mcf) 215,300 - 537,220 -



Average production of natural gas

Mcf/d 2,340 - 1,601 -

boe/d 390 - 267 -



Average sales price of natural gas

$/Mcf $ 2.99 $ - $ 3.30 $ -

$/boe $ 17.91 $ - $ 19.82 $ -

BC Spectra Station 2 Benchmark price

(1)

$/Mcf $ 2.98 $ - $ 3.31 $ -



Note:

(1) Source: NGX Natural Gas Exchange website (converted from $/GJ)

In January 2011, the Farrell Creek Montney Gas Plant commenced operations with natural gas currently being sold on a spot basis at BC Station 2 on the Spectra Energy pipeline system. For the three and twelve months ended Decemer 31, 2011, production averaged 2,340 Mcf/d (390 boe/d) and 1,601 Mcf/d (267 boe/d), respectively with the Corporation realizing an average price of $2.99 per Mcf ($17.91 per boe) and $3.30 per Mcf ($19.82 per boe), respectively.





Operating Netbacks



For the three months ended

December 31, 2011 $ % $/Mcf $/boe

----------------------------------------------------------------------------



Natural gas sales $ 642,431 $ 2.99 $ 17.91

Royalties (56,300) 8.8% (0.26) (1.57)

-------------- ----------------------

Net revenue 586,131 2.73 16.34

Royalty credits applied 56,300 0.26 1.57

Operating costs (432,345) (2.01) (12.05)

-------------- ----------------------



Operating netbacks $ 210,086 $ 0.98 $ 5.86

------------ ---------------------

------------ ---------- ----------





For the twelve months ended

December 31, 2011 $ % $/Mcf $/boe

----------------------------------------------------------------------------



Natural gas sales $1,731,024 $ 3.30 $ 19.82

Royalties (155,854) 9.0% (0.29) (1.74)

-------------- ----------------------

Net revenue 1,575,170 3.01 18.08

Royalty credits applied 151,341 0.28 1.69

Operating costs (980,632) (1.82) (10.93)

-------------- ----------------------



Operating netbacks $ 745,879 $ 1.47 $ 8.84

-------------- ----------------------

-------------- ----------------------



After royalties, operating costs and transportation, operating netbacks were $0.98 per Mcf ($5.86 per boe) and $1.47 per Mcf ($8.84 per boe) for the three and twelve months ended December 31, 2011 respectively.

During the three and twelve months ended December 31, 2011, the Corporation applied $56,300 and $151,341, respectively, of royalty credits against crown royalties that would otherwise have been payable. The royalty credits applied are accounted for as an offset against the capital costs accumulated within Property, Plant and Equipment. The difference between royalty expense and royalty credits applied for the twelve months ended December 31, 2011 of $4,513 represent actual crown royalties paid in relation to the sale of natural gas liquids.

Impairment

The Corporation performed impairment tests as at January 1, 2010 (date of transition to IFRS), as at January 28, 2011 (date of the Corporation's first natural gas production) and as at December 31, 2011 to assess the recoverable value of E&E assets within the Corporation's combined Farrell Creek Gething Formation project and Farrell Creek Montney Formation project E&E CGU's. The estimates of fair value less costs to sell were determined in part using prevailing land tender prices around those dates. Based on the tender prices and other factors, the estimated recoverable amount of E&E assets was greater than the carrying value of the Corporation's combined Farrell Creek Gething Formation project and Farrell Creek Montney Formation project E&E CGU's, and as such there was no impairment.

However, for the year ended December 31, 2011 CSRI recognized an impairment of $14.5 million (2010: $Nil) relating to developed and producing natural gas assets in the Corporation's Farrell Creek Montney Formation project CGU within property, plant and equipment. The impairment resulted primarily from the decline in forecasted natural gas prices.

The impairment is based on the difference between the net book value of the developed and producing natural gas assets within property, plant and equipment and their recoverable amount. The recoverable amount is calculated using fair value less costs to sell based on 9% discounted after-income tax future net cash flows for proved plus probable reserves using forecasted natural gas prices, operating costs and future costs to develop.

Reserves

The following table summarizes the Corporation's reserves and net present value ("NPV") of reserves as at December 31, 2011:





Barrels of Oil NPV Discounted

Natural Gas(1) Equivalent(5) At 10%(6)

---------------------------------------------------

Gross (2) Net(3) Gross (2) Net(3)

(MMcf) (MMcf) (Mboe) (Mboe) (Thousands)

----------------------------------------------------------------------------

PROVED(7)

----------------------------------------------------------------------------

Developed Producing 2,471 2,435 412 406 $ 4,024

----------------------------------------------------------------------------

Total Proved 2,471 2,435 412 406 $ 4,024

----------------------------------------------------------------------------



PROBABLE(8) 8,149 7,605 1,358 1,267 $ 2,072

----------------------------------------------------------------------------



TOTAL PROVED PLUS

PROBABLE(4) 10,620 10,040 1,770 1,673 $ 6,096

----------------------------------------------------------------------------



Notes:

(1) Estimates of Reserves of natural gas include associated and non-associated gas.

(2) "Gross Reserves" are CSRI's working interest share of the remaining reserves, before deduction of royalties.

(3) "Net Reserves" are CSRI's working interest share of remaining reserves less all Crown royalties.

(4) May not add due to rounding.

(5) Boe's have been calculated using a conversion ratio of 6 Mcf of natural gas per barrel of oil energy equivalent.

(6) Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

(7) Proved Resources are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(8) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.





General and Administrative Expenses

Three months ended Twelve months ended

December 31, December 31,

---------------------- ------------------------

2011 2010 2011 2010

----------------------------------------------------------------------------



Consulting fees $ 7,614 $ 35,201 $ 173,038 $ 125,326

Salaries and benefits 370,327 348,017 1,262,786 1,180,732

Other general and

administrative 162,093 300,380 877,448 836,150

--------------------------------------------------

540,034 683,598 2,313,272 2,142,208

Capitalized and other

costs (115,145) (117,285) (474,649) (471,398)

--------------------------------------------------

424,889 566,313 1,838,623 1,670,810

--------------------------------------------------



Share-based compensation 79,558 124,271 649,516 773,459

Capitalized portion of

share-based compensation (17,211) (31,488) (147,487) (210,224)

--------------------------------------------------

62,347 92,783 502,029 563,235

--------------------------------------------------



$ 487,236 $ 659,096 $ 2,340,652 $ 2,234,045

--------------------------------------------------

--------------------------------------------------



In 2011 the Corporation continued consulting contracts with an investment advisor, a land consultant, a computer network maintenance company and an external IFRS consulting firm. During the twelve months ended December 31, 2011, the Corporation also entered into consulting arrangements with a staffing recruitment firm and an executive compensation firm, resulting in an increase of $47,712 or 38.1% in consulting fees, before capitalization compared to the year ended December 31, 2010. Consulting fees for the fourth quarter 2010 were higher compared to the fourth quarter 2011 due to additional IFRS consulting services.

Salaries and benefits, before capitalization, for the twelve months ended December 31, 2011 increased by $82,054 or 6.9% compared with the year ended December 31, 2010 due to general annual salary increases and the hiring of an additional employee in March 2011, but offset by efficiencies gained in the Corporation's group health benefits plan.

The increase in other general and administrative expenses for the twelve months ended December 31, 2011 was mainly attributable to increased professional fees, but offset by a decrease in office premises expenses. Professional fees are comprised of legal counsel fees for corporate and joint venture matters, audit related fees for the three 2011 quarterly interim financial statement reviews, independent reservoir engineering consultants fees for the Corporation's initial Reserve Report as at March 31, 2011 as well as fee accruals for the 2011 annual audit and reserve report, neither of which were accrued until the fourth quarter for the 2010 fiscal year. Office premises expenses decreased by 41% and 20%, respectively, from the three and twelve months ended December 31, 2010 to the three and twelve months ended December 31, 2011 due to the signing of a new lease agreement effective June 2011 for a two year main lease at $12.00 per square foot compared to the prior rate of $28.00 per square foot.

The Corporation capitalizes, within both Exploration and Evaluation assets and Property, Plant and Equipment, certain salary and benefit costs associated with staff directly involved in exploration and development activities. For the year ended December 31, 2011, the Corporation capitalized a total of $474,049 (2010: $468,998) of general and administration expenses, including salaries and benefits, directly related to exploration and development activities. Other costs capitalized during the twelve months ended December 31, 2011 of $600 (2010: $2,400) relate to consulting fees incurred as equity instruments issue costs, and are recorded by the Corporation as a reduction of shareholders' capital.

Due to the reduced levels of stock options granted as well as a decrease in the market price of the Corporation's shares, share-based compensation, before capitalization, decreased by $123,943 or 16.0% for the year ended December 31, 2011, from the comparative prior period. The closing price of the Corporations shares on the Exchange on December 31, 2011 was $0.55 per share. For the twelve months ended December 31, 2011 the Corporation capitalized $147,487 (2010: $210,224) of share- based compensation expense for those employees of the Corporation directly involved in exploration and development activities.

Capital Expenditures, Liquidity and Capital Resources

The Corporation's net capital expenditures for the three and twelve months ended December 31, 2011 and 2010 are detailed in the following table:





Three months ended Twelve months ended

December 31, December 31,

-------------------------- -------------------------

2011 2010 2011 2010

----------------------------------------------------------------------------



Lease acquisitions and

retentions $ 26,593 $ 238,227 $ 1,613,659 $ 4,269,875

Geological and

geophysical 11,030 1,817 11,030 4,929

Net expenditure on

drilling, completion

and facilities costs 1,510,129 9,965,635 17,134,251 14,557,804

Capitalized overhead 132,356 148,173 621,536 679,222

-----------------------------------------------------

Total natural gas

expenditures 1,680,108 10,353,852 19,380,476 19,511,830

Computer and office

equipment, furniture

and fixtures 4,990 - 10,146 7,486

-----------------------------------------------------

Total capital

expenditures 1,685,098 10,353,852 19,390,622 19,519,316

Royalty credits earned (1,632,483) - (3,655,665) -

-----------------------------------------------------



Net capital

expenditures $ 52,615 $ 10,353,852 $ 15,734,957 $ 19,519,316

-----------------------------------------------------



For the year ended December 31, 2011, gross capital expenditures, including land acquisitions but before British Columbia government incentive Summer Drilling and Deep Royalty Credits earned of $3.7 million, totaled $19.4 million (2010: $19.5 million), compared to a budgeted capital expenditure of $16.2 million (2010: $19.7 million). The capital expenditures in excess of budget for the twelve months ended December 31, 2011 were mainly as a result of unexpected cost overruns from the Corporation's joint venture partner, Canbriam, relating to the completion of the c-45-I and c-B18-I wells, the drilling of the 12-07 well, and the construction of the Williston Reservoir Water Pipeline Project.

At December 31, 2011, the Corporation had a net working capital balance of $2.5 million consisting of cash in the amount of $4.1 million, accounts receivable and prepaids of $0.1 million and the current portion of unapplied royalty credits of $0.4 million, offset by accounts payable and other accrued liabilities of $2.1 million. The accounts payable and other accrued liabilities balance at December 31, 2011 relates primarily to drilling and completion activity at c-45-I, c-B18-I and 12-07 in the Montney Project at Farrell Creek as well as the costs related to the Williston Reservoir Water Pipeline Project in conjunction with the Corporation's joint venture partner, Canbriam.

The Corporation's capital budget is reviewed and approved by the Board of Directors on a quarterly basis. The Corporation's Board of Directors has approved a total capital expenditure budget for 2012 of $2.0 million (net), including an estimated $0.5 million for capitalized overhead. CSRI has budgeted for $0.2 million (net) of capital expenditures for the first quarter 2012. Any additional capital required to complete CSRI's share of the Montney program for 2012 of $2.0 million (net) is expected to be raised either via the capital markets, generated internally by cash flow from operating activities, or sourced from borrowings against the Corporation's line of credit.

Subsequent to the year-end, the Corporation established a revolving demand bank credit facility for $3.5 million. The credit facility is fully revolving with no set date of maturity, bears interest at prime rate plus an applicable margin, and is secured by a General Security Agreement conveying a first floating charge over all the Corporation's real property and fixed assets as well as a first fixed charge on all the Corporation's property interests. The credit facility is subject to standard quarterly and annual reporting requirements as well as usual and customary covenants. To date, no draws have been made from the credit facility.

Cash administration expenses (general and administrative expenses excluding share-based compensation) for 2012 are expected to total $1.9 million (2011: $2.3 million), before capitalization of exploration and development related overhead. The Corporation has budgeted for operating netbacks from the Farrell Creek Montney operations of $0.7 million during 2012, which may not be fully achieved due to continued weak natural gas prices.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

In February 2008, the Accounting Standards Board of the Canadian Institute of Chartered Accountants confirmed that IFRS would replace previous GAAP commencing in 2011 for profit-oriented Canadian publicly accountable enterprises effective January 1, 2011. As such, the Corporation has reported its 2011 results and 2010 comparative information in accordance with IFRS. The adoption of IFRS has not had a material impact on the Corporation's operations.

ADDITIONAL INFORMATION

The Corporation's financial statements, management's discussion and analysis of operations and financial condition and annual information form ("AIF") have been filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") and can be viewed at www.sedar.com or through the Corporation's website at www.csri.ca.

On behalf of the Board of Directors,

CANADIAN SPIRIT RESOURCES INC.

Phillip Geiger, President and Chief Operating Officer

The corporate information contained in this news release may contain forward-looking forecast information. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonably accurate by CSRI at the time of preparation, may prove to be incorrect. The actual results achieved during the forecast period will vary from the information provided herein and the variations may be material. Consequently there is no representation by CSRI that actual results achieved during the forecast period will be the same in whole or in part as those forecast.

NEITHER THE TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS NEWS RELEASE


Contact:
Phil Geiger
Canadian Spirit Resources Inc.
President and Chief Operating Officer
(403) 539-5005
(403) 262-4177 (FAX)
phil.geiger@csri.ca

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