Challenger Energy Corp.
TSX VENTURE : CHA

Challenger Energy Corp.

May 30, 2006 08:45 ET

Challenger Energy Corp. Poised to Move Forward with Drilling Offshore Trinidad, and Announces First Quarter 2006 Operating Results and Files Statement of Reserves Data

CALGARY, ALBERTA--(CCNMatthews - May 30, 2006) - Challenger Energy Corp. (TSX VENTURE:CHA) ("Challenger" or the "Company") of Calgary Alberta, Canada, announces today that it is moving forward with drilling planned for later this year offshore Trinidad and also announced today 2006 first quarter operating results and announced as required by National Instrument 51-101 it has filed its Statement of Reserves Data and other Oil and Gas Information with Canadian securities authorities. The filing can be found on the System for Electronic Document Analysis and Retrieval ("SEDAR").

Challenger Energy Corp. is a Calgary Alberta, Canada based oil and gas exploration Company which is currently focusing on "high impact" oil and gas plays offshore Trinidad and Tobago and offshore Nova Scotia.

Cautionary Statements

This news release contains forward-looking information on future production, project start-ups and future capital spending. Actual results or estimated results could differ materially due to changes in project schedules, operating performance, demand for oil and gas, commercial negotiations or other technical and economic factors or revisions. The information in this news release also includes certain information and statements about management's view of future events, expectations, plans and prospects that constitute forward looking statements. These statements are based upon assumptions that are subject to significant risks and uncertainties. Because of these risks and uncertainties and as a result of a variety of factors, the actual results, expectations, achievements or performance may differ materially from those anticipated and indicated by these forward looking statements. Although the Company believes that the expectations reflected in forward-looking statements are reasonable, it can give no assurances that the expectations of any forward-looking statements will prove to be correct.

Statements contained in this news release relating to future results, events and expectations are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Corporation, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such statements.

MESSAGE TO SHAREHOLDERS

On behalf of the team at Challenger Energy Corp., I am very pleased to provide you with a summary of our achievements in the first quarter of 2006 and our go forward plan with Canadian Superior Energy Inc. ("Canadian Superior", TSX, AMEX: SNG) to drill offshore Trinidad and Tobago on one of the best natural gas plays in the world, during the fourth quarter of 2006. At March 31, 2006, the corporation was debt free, had $19.2 million in working capital and our cash position was $19.4 million. During the first quarter of 2006 we completed the raising $19.5 million in equity financing to initially fund our operations. I would like to thank our shareholders for their support and we are committed to moving forward into 2006 and beyond with a conservative disciplined financial approach. 2006 will be an exciting year for us.

With the commencement of 2006, Challenger is poised to move forward pursuant to three notable agreements executed, having established our core focus.

- In November 2004, Challenger entered into a participation agreement as a non-competitive financial industry partner with Canadian Superior with respect to the development of Canadian Superior's Intrepid "Block 5(c)" located offshore Trinidad. Challenger will be funding one-third of Canadian Superior's initial cost of drilling 3 wells off-shore Trinidad on Block 5(c) to obtain 25 percent of the revenue Canadian Superior earns from Block 5(c).

- Also in November 2004, Challenger entered into a financial participation agreement with Canadian Superior to have the opportunity to participate with Canadian Superior on Canadian Superior's Mayaro and Guayaguayare Bay lands located off-shore Trinidad. Under this agreement Challenger may pay one-third of Canadian Superior's costs related to 2 wells Canadian Superior may drill on the Mayaro and Guayaguayare block to receive 25 percent of Canadian Superior's revenues from this block.

- Furthermore in November 2004 Challenger entered into a Farm-Out agreement, which has subsequently been amended, whereby Challenger has the opportunity to participate in Canadian Superior's next Mariner test well, off-shore Nova Scotia. To earn a 25 percent interest in Canadian Superior's Mariner Block, Challenger may farm-in by paying one-third of the cost of the next Mariner well. Challenger has the further right to participate on the same terms on Canadian Superior's Marauder and Marconi Blocks, off-shore Nova Scotia.

TRINIDAD AND TOBAGO

We are pleased to report that on March 19, 2006, the operator of Block 5(c), Canadian Superior, entered into a firm multi-well drilling contract for the Kan Tan IV Semi-Submersible Offshore Drilling Rig managed by A. P. Moller-Maersk ("Maersk"), (OMX:MAERSK B), of Copenhagen, Denmark and owned by Beijing Zhiyuan Industries Company Limited ("Beijing Zhiyuan"), of Beijing, China. Beiing Zhiyuan, is a member of the SINOPEC Group of companies (NYSE: SNP), both Maersk and Beijing Zhiyuan who are truly world class companies. Canadian Superior will be bringing this rig into Trinidad and Tobago with no other oil and gas companies involved in the contracting of this offshore drilling rig, at a very favorable day rate, honoured by Maersk and Beijing Zhiyuan, negotiated by Canadian Superior several months ago, as compared to day rates which have gone up considerably. Trinidad and Tobago is a very economic and important source of North America's naturally gas supply. This rig will commence drilling of two back-to-back wells for Canadian Superior and ourselves offshore Trinidad on the "Intrepid" Block 5 (c) during the fourth quarter of this year.

Also we are pleased to report that on May 10, 2006 we inspected the Kan Tan IV Offshore Drilling Rig in Brownsville, Texas, with senior officials of Maersk from Copenhagen where rig work is underway to retrofit the drilling rig for our operations offshore Trinidad.

Offshore Trinidad is a highly desirable oil and gas basin. Offshore Trinidad has multiple large exploration and development opportunities as evidenced by recent drilling successes in the Columbus Basin where Block 5(c) is located. It also has well developed, and developing, LNG facilities and capacity, and ready access to international markets. 80% of North America's LNG is supplied from Trinidad, and some of the largest producing wells in the world are located in Trinidad. 15 of British Petroleum's top 25 producing wells world-wide are located in Trinidad in close proximity to where we will be drilling later this year. In Trinidad and Tobago natural gas at the wellhead is currently selling near Henry Hub pricing.

Also, off the east coast of Trinidad British Petroleum has just put on production 800 mmcf/d of natural gas being produced by only 4 wells from their new "Cannonball" discovery, evidencing the "World-Class" potential of our prospects.

The "Intrepid" Block 5(c) is comprised of 80,041 acres located about 96 kilometers (60 miles) off the east coast of the island of Trinidad with water depths in the range of 150 to 450 meters (500 to 1,500 feet) and all wells in Block 5(c) will be drilled one immediately after the other from the Kan Tan IV semi-submersible drilling rig in water depths of about 245 meters (800 feet) with drilling planned to commence during the fourth quarter of 2006. These prospects have been estimated to potentially contain over 4 TCF of undiscovered resources of natural gas and condensate. As previously indicated some of the largest producing natural gas wells and natural gas field structures of similar size are located in the immediate vicinity and/or offset our "Intrepid" Block 5(c) prospect.

OFFSHORE NOVA SCOTIA

Also we are very excited about our prospects offshore Nova Scotia, which offer tremendous multi-zone opportunities and on one of the drilling prospects natural gas has been found on it previously and it has prospective resources estimated to be up to 600 Bcf. Commencement of drilling on these prospects may occur late this year or in early 2007.

OTHER ACTIVITIES

Challenger Energy is also pleased to report that it is pursuing participation in other high impact basin opportunities in North Africa, where we are currently accessing a number of oil and gas prospects. In addition to this, work is currently underway to list the Company's shares on an exchange in the United States. We expect this listing, subject to regulatory approval, to be completed within about the next 8 to 10 weeks.

OUTLOOK

Accordingly we are looking forward to proceeding further with a very exciting 2006. We would again like to thank shareholders for your tremendous support!

Respectfully submitted on behalf of the Management, Staff and Directors of Challenger Energy Corp.:



Challenger Energy Corp.

Per:



Neil Mackenzie

President and Chief Executive Officer

May 30, 2006




BALANCE SHEET (unaudited) (audited)
March 31, 2006 December 31, 2005
---------------------------------------------------------------------
ASSETS
Current
Cash and cash equivalents 19,357,987 1,147,876
Accounts receivable 101,814 53,636
---------------------------------------------------------------------
19,459,801 1,201,512

Petroleum and natural gas
properties (Note 2) 578,255 540,424
---------------------------------------------------------------------
20,038,056 1,741,936
---------------------------------------------------------------------
---------------------------------------------------------------------

LIABILITIES
Current
Accounts payable and accruals 267,979 144,975
---------------------------------------------------------------------
267,979 144,975

Asset retirement obligation 3,048 2,981
---------------------------------------------------------------------
271,027 147,956

Shareholders' Equity
Share capital 16,704,458 2,019,750
Warrants 3,414,462 104,063
Contributed surplus 416,825 19,939
Deficit (768,716) (549,772)
---------------------------------------------------------------------
19,767,029 1,593,980
Related party transactions
Commitments and contingencies
Subsequent events
20,038,056 1,741,936
---------------------------------------------------------------------
---------------------------------------------------------------------


INCOME STATEMENT
For the three months ended
March 31, 2006
(unaudited)
---------------------------------------------------------------------
Revenue
Oil and natural gas sales $ 60,164
Royalties net of royalty tax credit (14,018)
---------------------------------------------------------------------
Net Production Revenue 46,146

Interest on deposits 72,697
---------------------------------------------------------------------
118,843
---------------------------------------------------------------------

Expense
Professional fees 49,598
Stock based compensation 400,604
Office and administration 50,428
Listing fees 8,053
Depletion, depreciation, and accretion 26,456
Production and operating costs 1,475
Miscellaneous 554
---------------------------------------------------------------------
537,168
---------------------------------------------------------------------

Net loss from operations (418,325)
Foreign exchange gain 199,381
---------------------------------------------------------------------
Net loss for the period (218,944)

Deficit at beginning of period (549,772)
---------------------------------------------------------------------

Deficit at end of period $ (768,716)
---------------------------------------------------------------------
---------------------------------------------------------------------

Loss per share $ (0.01)



STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
(Form NI 51-101F1)

This statement of reserves data and other oil and gas information has been prepared as at December 31, 2005.

Reserves and Future Net Revenue

The following is a summary of the oil and natural gas reserves and the value of future net revenue of CHALLENGER ENERGY CORP. ("Challenger Energy" or the "Company") as evaluated by Chapman Petroleum Engineering Ltd. as at December 31, 2005 (the " Chapman Report"). The pricing used in the forecast and constant price evaluations is set forth in the notes to the tables.

All evaluations of future revenue are after the deduction of future income tax expenses, unless otherwise noted in the tables, royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of the Company's reserves. There is not assurance that the forecast price and cost assumptions contained in the Chapman Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are included in the Chapman Report. The recovery and reserves estimates on the Company's properties described herein are estimates only. The actual reserves on the Company's properties may be greater or less than those calculated.



SUMMARY OF OIL AND GAS RESERVES
BASED ON CONSTANT PRICES AND COSTS (8)

Company Reserves (1)
----------------------------------------------------
Light and Natural Natural Gas
Medium Oil Heavy Oil Gas(11) Liquids
----------- ------------ ------------- -------------
Reserves Gross Net Gross Net Gross Net Gross Net
Category MSTB MSTB MSTB MSTB MMscf MMscf Mbbl Mbbl
---------------- ----- ----- ------ ----- ------ ------ ------ ------
PROVED
Developed
Producing(2)(5) 0 0 0 0 97 79 6 5
Developed
Non-Producing
(2)(6) 0 0 0 0 0 0 0 0
Undeveloped(2)(7) 0 0 0 0 0 0 0 0
----- ----- ------ ----- ------ ------ ------ ------
TOTAL PROVED(2) 0 0 0 0 97 79 6 5
PROBABLE(3) 0 0 0 0 26 21 2 1
----- ----- ------ ----- ------ ------ ------ ------
TOTAL PROVED
PLUS PROBABLE
(2)(3) 0 0 0 0 123 100 8 7


All of the Company's reserves are in Canada.


SUMMARY OF NET PRESENT VALUES
BASED ON CONSTANT PRICES AND COSTS(8)

Net Present Values of Future Net Revenue (9)
---------------------------------------------------
Before Income Tax After Income Tax
Discounted at Discounted at
------------------------- -------------------------
0%/yr. 10%/yr. 15%/yr. 0%/yr. 10%/yr. 15%/yr.
Reserves Category $M $M $M $M $M $M
------- -------- -------- ------- -------- --------
PROVED
Developed
Producing(2)(5) 917 634 551 608 421 366
Developed
Non-Producing
(2)(6) 0 0 0 0 0 0
Undeveloped(2)(7) 0 0 0 0 0 0
------- -------- -------- ------- -------- --------
TOTAL PROVED(2) 917 634 551 608 421 366
PROBABLE(3) 242 105 77 161 70 52
------- -------- -------- ------- -------- --------
TOTAL PROVED
PLUS PROBABLE
(2)(3) 1,159 739 628 769 491 418
------- -------- -------- ------- -------- --------
------- -------- -------- ------- -------- --------



TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
BASED ON CONSTANT PRICES AND COSTS(8)
Abandonment
and
Operating Development Reclamation
Revenue Royalties Costs Costs Costs
($M) ($M) ($M) ($M) ($M)
-------- ---------- --------- ----------- ------------
Total Proved(2) 1,389 291 176 0 5
Total Proved
Plus Probable
(2)(3) 1,753 367 223 0 223


Future Net Future Net
Revenue Before Revenue After
Income Taxes(9) Income Taxes Income Taxes(9)
($M) ($M) ($M)
----------------- -------------- ---------------
Total Proved(2) 917 309 608
Total Proved Plus
Probable(2)(3) 1,159 390 769



FUTURE NET REVENUE
BY PRODUCTION GROUP
BASED ON CONSTANT PRICES AND COSTS (8)

Future Net
Revenue Before
Income Taxes
(Discounted at
10%/Year)(10)
Reserve Category Production Group ($M)
-------------------------------- -------------------
Total Proved(2) Light and Medium Oil (including
solution gas and other
by-products) 0
Heavy Oil (including solution
gas and other by-products) 0
Natural Gas (including by-
products but not solution gas) 634
Total Proved
Plus Probable
(2)(3) Light and Medium Oil (including
solution gas and other by-products) 0
Heavy Oil (including solution gas
and other by-products) 0
Natural Gas (including
by-products but not solution gas) 739


SUMMARY OF OIL AND GAS RESERVES
BASED ON FORECAST PRICES AND COSTS(8)

Company Reserves
----------------------------------------------------

Light and Natural Natural Gas
Medium Oil Heavy Oil Gas(11) Liquids
----------- ------------ ------------- -------------
Reserves Gross Net Gross Net Gross Net Gross Net
Category MSTB MSTB MSTB MSTB MMscf MMscf Mbbl Mbbl
---------------- ----- ----- ------ ----- ------ ------ ------ ------

PROVED
Developed
Producing(2)(5) 0 0 0 0 97 79 6 5
Developed
Non-Producing
(2)(6) 0 0 0 0 0 0 0 0
Undeveloped(2)(7) 0 0 0 0 0 0 0 0
---------------- ----- ----- ------ ----- ------ ------ ------ ------
TOTAL PROVED(2) 0 0 0 0 97 79 6 5
TOTAL PROBABLE(2) 0 0 0 0 26 21 2 1
---------------- ----- ----- ------ ----- ------ ------ ------ ------
TOTAL PROVED
PLUS PROBABLE
(2)(3) 0 0 0 0 123 100 8 7
---------------- ----- ----- ------ ----- ------ ------ ------ ------
---------------- ----- ----- ------ ----- ------ ------ ------ ------

All of the Company's reserves are in Canada.


SUMMARY OF NET PRESENT VALUES
BASED ON FORECAST PRICES AND COSTS (8)
Net Present Values of Future Net Revenue (1)(9)

----------------------------------------------
Before Income Tax
Discounted at
----------------------------------------------
0%/yr. 5%/yr. 10%/yr. 15%/yr. 20%/yr.
Reserves Category $M $M $M $M $M
------ ------ ------- ------- -------
PROVED
Developed
Producing(2)(5) 745 621 535 472 423
Developed
Non-Producing(2)(6) 0 0 0 0 0
Undeveloped(2)(7) 0 0 0 0 0
------ ------ ------- ------- -------
TOTAL PROVED(2) 745 621 535 472 423
PROBABLE(3) 187 120 83 62 48
------ ------ ------- ------- -------
TOTAL PROVED
PLUS PROBABLE(2)(3) 932 741 618 533 471
------ ------ ------- ------- -------
------ ------ ------- ------- -------


----------------------------------------------
After Income Tax
Discounted at
----------------------------------------------
0%/yr. 5%/yr. 10%/yr. 15%/yr. 20%/yr.
Reserves Category $M $M $M $M $M
------ ------ ------- ------- -------
PROVED
Developed
Producing(2)(5) 493 412 355 313 281
Developed
Non-Producing(2)(6) 0 0 0 0 0
Undeveloped(2)(7) 0 0 0 0 0
------ ------ ------- ------- -------
TOTAL PROVED(2) 493 412 355 313 281
PROBABLE(3) 124 80 55 41 32
------ ------ ------- ------- -------
TOTAL PROVED
PLUS PROBABLE(2)(3) 617 492 410 354 313
------ ------ ------- ------- -------
------ ------ ------- ------- -------

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS(8)

Abandonment
and
Operating Development Reclamation
Revenue Royalties Costs Costs Costs
($M) ($M) ($M) ($M) ($M)
--------- --------- --------- ----------- ------------
Total Proved(2) 1,189 245 193 0 6
Total Proved
Plus Probable
(2)(3) 1,492 306 247 0 6


Future Net Future Net
Revenue Before Revenue After
Income Taxes(9) Income Taxes Income Taxes(9)
($M) ($M) ($M)
----------------- -------------- ---------------
Total Proved(2) 745 252 493
Total Proved
Plus Probable
(2)(3) 932 315 617



FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON FORECAST PRICES AND COSTS(8)

Future Net Revenue Before
Income Taxes (Discounted
at 10%/Year)(10)
Reserve Category Production Group ($M)
---------------------------------------------------------------------
Total Proved(2) Light and Medium Oil
(including solution gas
and other by-products) 0
Heavy Oil (including
solution gas and other
by-products) 0

Natural Gas (including
by-products but not
solution gas) 535

Total Proved Plus Light and Medium Oil
Probable(2)(3) (including solution gas
and other by-products) 0
Heavy Oil (including
solution gas and other
by-products) 0

Natural Gas (including
by-products but not
solution gas) 618


RECONCILATION OF COMPANY NET RESERVES
BY PRINCIPAL PRODUCT TYPE BASED ON FORECAST PRICES AND COSTS(8)

Light and Medium Oil Heavy Oil
---------------------------------------------------
Net Net
Proved Proved
Net Net Plus Net Net Plus
Proved Probable Probable Proved Probable Probable
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
-----------------------------------------------------
At January 1, 2005 0 0 0 0 0 0

Production (Sales) 0 0 0 0 0 0


Acquisitions 0 0 0 0 0 0
Dispositions
Discoveries
Extensions
Revisions to
Previous Estimates
Economic Factors
Technical
Improved Recovery
---------------------------------------------------
At January 1, 2006


Associated and
Non-Associated Gas
-------------------------
Net
Proved
Net Net Plus
Proved Probable Probable
(MMscf) (MMscf) (MMscf)
-------------------------
At January 1, 2005 0 0 0

Production(Sales) 3 0 3

Acquisitions 82 21 103
Dispositions
Discoveries 0 0 0
Extensions 0 0 0
Revisions to Previous Estimates 0 0 0
Economic Factors
Technical
Improved Recovery
-------------------------
At January 1, 2006 79 21 100

The following table sets forth changes between future net revenue
estimates attributable to net proved reserves as at January 1, 2006
against such reserves as at January 1, 2005.

RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE
OF NET PROVED RESERVES DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND
COSTS (8)

2005
($M)
Future Revenue Prediction at January 1, 2005 0
Net Value of Sales. 29
Net change in production costs for future production. 0
Net change in sales prices for future production. 0
Net change in royalties for future production. 0
Change in development costs Incurred. 0
Change in future future development costs. 0
Change from extension & improved recovery. 0
Discoveries. 0
Acquisition Disposition. 392
Revisions in quantity estimates. 0
Accretion of discount (10% of discounted future net
revenue at the beginning for the financial year.) 0
Net change in income taxes. 0
Other Factors. 0
-------
Future Net Revenue at January 1, 2006 421

Notes:
1. "Gross Reserves" are the Company's working interest (operating or
non-operating) share before deducting of royalties and without
including any royalty interests of the Company. "Net Reserves" are
the Company's working interest (operating or non-operating) share
after deduction of royalty obligations, plus the Company's royalty
interests in reserves.
2. "Proved" reserves 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.
3. "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.
4. "Developed" reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low
expenditure (e.g. when compared to the cost of drilling a well)
to put the reserves on production.
5. "Developed Producing" reserves are those reserves that are
expected to be recovered from completion intervals open at the
time of the estimate. These reserves may be currently producing
or, if shut-in, they must have previously been on production, and
the date of resumption of production must be known with
reasonable certainty.
6. "Developed Non-Producing" reserves are those reserves that either
have not been on production, or have previously been on
production, but are shut in, and the date of resumption of
production is unknown.
7. "Undeveloped" reserves are those reserves expected to be
recovered from know accumulations where a significant expenditure
(for example, when compared to the cost of drilling a well) is
required to render them capable of production. They must fully
meet the requirements of the reserves classification (proved,
probable, possible) to which they are assigned.
8. The pricing assumptions used in the Chapman Report with respect
to net values of future net revenue (forecast) as well as the
inflation rates used for operating and capital costs are set
forth below along with the product prices used in the constant
price and cost evaluations. Chapman Petroleum Engineering Ltd. Is
an independent qualified reserves evaluator appointed pursuant to
NI 51-101.
9. Includes ARTC.
10. Does not include ARTC.
11. Includes associated, non-associated and solution gas where
applicable.


CRUDE OIL
HISTORICAL, CONSTANT, CURRENT & FUTURE PRICES
January 1, 2006

Alberta
Par Alberta Sask.
WTI (1) Price (2) Heavy (3) Light (4)
Date $US/STB $CDN/STB $CDN/STB $CDN/STB
----- --------- ---------- ---------- ---------
HISTORICAL PRICES
1994 17.16 22.27 18.19 20.76
1995 18.41 25.11 19.76 22.77
1996 21.98 29.39 25.09 28.41
1997 20.59 27.90 21.15 26.52
1998 14.46 20.39 14.68 19.31
1999 19.21 27.88 23.71 27.23
2000 30.39 44.90 34.51 43.37
2001 25.98 39.66 25.41 35.57
2002 26.09 40.63 32.20 37.67
2003 30.84 43.57 32.65 40.13
2004 41.48 52.89 37.52 48.96
2005 56.62 69.16 43.25 62.04
CONSTANT PRICES
December 30,
2005(8) 61.13 68.75 37.52 57.71
CURRENT YEAR
FORECAST
2006 59.00 68.91 43.41 62.37
FUTURE FORECAST
2007 58.00 67.74 42.67 61.30
2008 56.00 65.38 41.19 59.17
2009 54.00 63.03 39.71 57.04
2010 52.00 60.68 38.23 54.91
2011 50.00 58.32 36.74 52.78
2012 50.75 59.21 37.30 53.58
2013 51.51 60.10 37.86 54.39
2014 52.28 61.01 38.44 55.21
2015 53.07 61.93 39.02 56.05
2016 53.86 62.87 39.61 56.90
2017 54.67 63.82 40.21 57.76
2018 55.49 64.78 41.81 58.63
2019 56.32 65.76 41.43 59.52
2020 57.17 66.76 42.06 60.42
2021 58.03 67.77 42.69 61.33
Constant thereafter


ART Credits (7)
Sask. B.C. ---------------------
Heavy (5) Light (6) Rate Max
Date $CDN/STB $CDN/STB % $M
----- --------- ---------- -------- ---------
HISTORICAL PRICES
1994 19.16 21.12 70.08 n/a
1995 20.57 23.85 73.75 n/a
1996 26.07 27.99 72.82 n/a
1997 23.73 26.32 61.35 n/a
1998 17.01 19.38 69.32 n/a
1999 25.65 27.42 68.88 n/a
2000 40.12 n/a 25.85 n/a
2001 31.84 n/a 25.00 n/a
2002 34.57 n/a 25.00 n/a
2003 37.64 n/a 25.00 500
2004 45.74 n/a 25.00 500
2005 56.53 n/a 25.00 500

December 30,
2005(8) 50.08 67.03 25.00 500
CURRENT YEAR
FORECAST
2006 57.22 67.19 25.00 500
FUTURE FORECAST
2007 56.24 66.04 25.00 500
2008 54.29 63.75 25.00 500
2009 52.34 61.45 25.00 500
2010 50.38 59.16 25.00 500
2011 48.43 56.87 25.00 500
2012 49.16 57.73 25.00 500
2013 49.90 58.60 25.00 500
2014 50.66 59.49 25.00 500
2015 51.43 60.38 25.00 500
2016 52.20 61.30 25.00 500
2017 52.99 62.22 25.00 500
2018 53.79 63.17 25.00 500
2019 54.61 64.12 25.00 500
2020 55.43 65.09 25.00 500
2021 56.27 66.07 25.00 500
Constant
thereafter

Notes:
(1) West Texas Intermediate quality (D2/S2) crude landed in Cushing,
Oklahoma.
(2) Equivalent price for Light Sweet Crude (D2/S2) landed in
Edmonton, Alberta after exchange of .85 $US/$CDN for 2006 and
Thereafter, and transportation differential of $0.50 CDN/STB.
(3) Bow River at Hardisty, Alberta (905 kg/m3, 2.1% sulphur).
(4) Light Sour Blend at Cromer, Saskatchewan (850 kg/m3, 1.2%
sulphur).
(5) Midale at Cromer, Saskatchewan (880 kg/m3, 2.0% sulphur).
(6) B.C. Light at Taylor, British Columbia (825 kg/m3, 0.5% sulphur).
(7) ARTC rates are from www.revenue.gov.ab.ca/publications/
tax_rebates/rates_surveys_tnotes/rtc.html.
(8) December 30, 2005 is the last trading day of 2005.
(9) Capital expenditures and operating costs are escalated at 1.5%
per year until 2021.


NATURAL GAS & BY-PRODUCTS
HISTORICAL, CONSTANT, CURRENT & FUTURE PRICES
January 1, 2006


GRP (1) AECO Spot Sask. B.C.
---------------- Gas (NIT) Gas (2) Gas (3)
Date $/MMBTU $/GJ $/MMBTU $/MMBTU $/MMBTU
----- --------- ------- ----------- --------- ---------
HISTORICAL PRICES
1994 1.82 1.73 1.78 1.88 1.81
1995 1.31 1.24 1.08 1.35 1.29
1996 1.63 1.55 1.33 1.52 1.50
1997 1.97 1.87 1.67 1.84 1.80
1998 1.94 1.84 1.94 2.05 1.94
1999 2.48 2.35 2.82 2.83 2.51
2000 4.50 4.27 5.56 4.85 4.00
2001 5.78 5.48 5.44 5.48 6.12
2002 3.86 3.66 4.13 4.17 3.85
2003 6.45 6.11 7.03 6.47 6.45
2004 6.25 5.92 6.60 6.50 6.25
2005 8.13 7.71 8.82 8.38 8.13
CONSTANT PRICES
December 30,
2005(6) 9.29 8.81 9.54 9.54 9.29
CURRENT YEAR
FORECAST
2006 9.45 8.96 9.80 9.70 9.45
FUTURE FORECAST
2007 8.51 8.06 8.86 8.76 8.51
2008 8.00 7.58 8.35 8.25 8.00
2009 7.50 7.11 7.85 7.75 7.50
2010 7.25 6.87 7.6 7.50 7.25
2011 7.00 6.64 7.35 7.25 7.00
2012 7.11 6.73 7.46 7.36 7.11
2013 7.21 6.84 7.56 7.46 7.21
2014 7.32 6.94 7.67 7.57 7.32
2015 7.43 7.04 7.78 7.68 7.43
2016 7.54 7.15 7.89 7.79 7.54
2017 7.65 7.26 8.00 7.90 7.65
2018 7.77 7.36 8.12 8.02 7.77
2019 7.89 7.47 8.24 8.14 7.89
2020 8.00 7.59 8.35 8.25 8.00
2021 8.12 7.70 8.47 8.37 8.12
Constant thereafter


Pentanes NGL
Propane (4) Butane (4) Plus (4) Mix (5)
Date $/BBL $/BBL $/BBL $/BBL
----- ------------ ----------- ----------- --------
HISTORICAL PRICES
1994 12.72 13.44 21.67 15.62
1995 14.38 13.97 24.11 17.18
1996 22.95 17.19 30.05 23.35
1997 17.73 19.07 30.90 22.08
1998 11.13 12.06 21.86 14.63
1999 15.93 18.01 27.73 20.09
2000 31.38 35.01 46.35 36.96
2001 31.27 30.27 44.98 35.08
2002 19.14 25.11 40.72 27.41
2003 28.85 32.15 44.23 34.46
2004 31.95 38.40 54.06 40.52
2005 38.03 46.31 69.32 49.90

December 30,
2005 (6) 44.36 54.05 70.43 55.09
CURRENT YEAR
FORECAST
2006 37.21 45.48 69.60 49.41
FUTURE FORECAST
2007 36.58 44.71 68.41 48.57
2008 35.31 43.15 66.04 46.88
2009 34.04 41.60 63.66 45.19
2010 32.77 40.05 61.28 43.51
2011 31.49 38.49 58.91 41.82
2012 31.97 39.08 59.80 42.45
2013 32.45 39.67 60.70 43.09
2014 32.95 40.27 61.62 43.74
2015 33.44 40.88 62.55 44.41
2016 33.95 41.49 63.50 45.08
2017 34.46 42.12 64.46 45.76
2018 34.98 42.76 65.43 46.45
2019 35.51 43.40 66.42 47.15
2020 36.05 44.06 67.43 47.87
2021 36.59 44.73 68.44 48.59
Constant
thereafter

Notes:
(1) Gas Reference Price (GRP) represents the average of all system
and direct (spot and firm) sales.
(2) Price paid at field delivery point.
(3) Price paid by CanWest net of raw gas gathering and processing
field gathering and compression charges.
(4) Reference point is FOB Edmonton for fractionated product.
(5) Natural Gas Liquids blended mix price assuming typical liquid
composition of 40% propane, 30% butane and 30% pentanes plus.
(6) December 30, 2005 is the last trading day of 2005.
(7) Capital expenditures and operating costs are escalated at 1.5%
per year until 2021.


Undeveloped Reserves

The Company has no undeveloped reserves.

Future Development Costs - none scheduled for reserves

Significant Factors or Uncertainties

The estimation of reserves requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates can change substantially as additional information from ongoing development activities and production performance becomes available and as economic and political conditions impact oil and gas prices and costs change.

Oil and Gas Properties and Wells

The following table sets forth the number of wells in which the Company held a working interest as at December 31, 2005:



Oil Natural Gas
-------------------------------------------
Gross(1) Net(1) Gross(1) Net(1)
-------- ------- --------- -------
Innisfail
Producing 0 0 1 0.1
Non-producing - - - -


All of the Company's wells are located in Canada

Properties with No Attributed Reserves

The Company has properties with no attributed reserves, but which contain Prospective Resources, in two offshore tracts in Trinidad and Tobago and three offshore Nova Scotia tracts in Canada.

In November 2004, Challenger entered into a farm-out agreement for drilling offshore Nova Scotia, Canada (the "Farm-out Agreement") with Canadian Superior Energy Inc. ("Canadian Superior"), a participation agreement for drilling offshore Trinidad with Canadian Superior (the "Participation Agreement") and a participation agreement (the "Trinidad Participation Agreement") with Canadian Superior Trinidad and Tobago Ltd., a wholly owned subsidiary of Canadian Superior for also drilling offshore Trinidad.

Pursuant to the Participation Agreement, Challenger has the right to earn up to a 25% interest in a production-sharing contract between Canadian Superior and the government of the Republic of Trinidad and Tobago relating to the exploration and development of land designated as "Block 5(c)" located offshore the Republic of Trinidad and Tobago (comprised of 80,041 gross acres). Pursuant to Challenger's rights under the Participation Agreement, Challenger is required to pay 1/3 of the costs and expenses paid by Canadian Superior relating to certain wells and the work program described by the production-sharing contract.

The Trinidad Participation Agreement also grants Challenger the right to finance 1/3 of Canadian Superior's minimum work obligations to obtain 25% of Canadian Superior's revenue share under a participation agreement entered into by Canadian Superior with the Petroleum Company of Trinidad and Tobago (Petrotrin) in respect of the Mayaro and Guayaguayare Bay lands located offshore the Republic of Trinidad and Tobago (comprised of 50,000 gross acres). In the event of commercial discovery, the participating interests in the Trinidad Participation Agreement are 70% Canadian Superior Trinidad and Tobago Ltd and 30% Petrotrin.

Pursuant to the Farm-out Agreement, Challenger may also earn a 25% interest in Canadian Superior's Mariner project offshore Nova Scotia by payment of a 1/3 share of the cost and expenses associated with drilling a test well on the Mariner project land. The Mariner prospect is located approximately 14 miles northeast of Sable Island, offshore Nova Scotia and is comprised of 101,800 gross acres. Provided that Challenger has earned an interest in the Mariner project pursuant to the Farm-out Agreement, it shall have a further option to participate and earn a 25% interest by paying 1/3 share of the costs of drilling wells on Canadian Superior's Marauder project lands and Marconi project lands, both offshore Nova Scotia, Canada.

Forward Contracts

Currently, the Company has no forward contracts.

Abandonment and Reclamation Costs

Currently the Company has only one tenth of a well and abandonment and restoration costs are of a minor nature. These costs were accounted for in the Chapman reserve and economic evaluation in the cash flows presented therein, based on the AEUB Directive 11.



FUTURE ABANDONMENT ANS RESTORATION COSTS

Total Total
Proved Proved
Total Total Plus Plus
Proved Proved Probable Probable
Estimated Estimated Estimated Estimated
Using Using Using Using
Forecast Forecast Forecast Forecast
Prices Prices Prices Prices
and Costs and Costs and Costs and Costs
(Undiscounted) (10% Discounted) (Undiscounted)(10% Discounted)
($M) ($M) ($M) ($M)
---------------------------------------------------------------------
2006 0 0 0 0
2007 0 0 0 0
2008 0 0 0 0
---------------------------------------------------------------------
Total for
three
years 0 0 0 0
Remainder 6 1 6 1
---------------------------------------------------------------------
Total for
all years 6 1 6 1
---------------------------------------------------------------------
---------------------------------------------------------------------


Tax Horizon

The Company is forecasting it will not to be taxable in 2006 in both proved and proved plus probable cases as it is incurring general operating expenses in excess of the revenue generated.

Capital Expenditures

The following tables summarize capital expenditures related to our activities for the periods indicated:



The following tables summarize capital expenditures related to our
activities for the periods indicated:


Petroleum and Natural Gas Properties at August 6, 2004 -
Additions to December 31, 2004 -
-------
Balance December 31, 2004 -
Additions to December 31, 2005 555,344
-------
Balance December 31, 2005 555,344
-------
-------


Exploration and Development Activities

The Company had no exploration or development activities during the past fiscal year.

The Company has important exploration opportunities in Trinidad and Tobago and offshore Nova Scotia in Canada. Activity will likely commence on Block 5(c) in Trinidad and Tobago during the fourth quarter of 2006.



Production Estimates

The following tables set forth the volume of production estimated for
2006:

2006 Net Production - Constant Prices and Costs
-------------------------------------------------
Light and Heavy Sales Oil
Medium Oil Oil Gas NGL Equivalent
MSTB MSTB MMscf Mbbls MBOE
------------ ------ ------- ------ -----------

Total Proved Producing 0 0 14 0 2

Total Proved 0 0 14 0 2

Total Proved Plus
Probable 0 0 14 0 2


These values are net to Challenger's working interest after the deduction of royalties payable to others.

Production History

The following table sets forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by the Company for each quarter of its most recently completed financial year:



Three Months Three Months Three Months Three Months
Ended Ended Ended Ended
January 31, April 30, July 31, December 31,
2005 2005 2005 2005
------------ ------------ ------------ -------------
Average Daily
Production
Light and Medium
(Oil Mbbl/d) - - - -
Natural Gas (mcf/d) - - - 61.8
Average Net Prices
Received
Light and Medium
Oil ($/Mbbl) - - - -
Natural Gas ($/mcf) - - - 12.0
Royalties
Light and Medium
Oil ($/Mbbl) - - - -
Natural Gas ($/mcf) - - - 1.8
Production Costs
Light and Medium
Oil ($/Mbbl) - - - -
Natural Gas ($/mcf) - - - 1.6
Netback Received
Light and Medium
Oil ($/Mbbl) - - - -
Natural Gas ($/mcf) - - - 8.6



The TSX Venture Exchange neither approved nor disapproved the contents of this press release.

Contact Information

  • Challenger Energy Corp.
    Calgary, Alberta
    Attn: Investor Relations
    Phone: (403) 503-8810
    Website: www.chaenergy.ca