Exhibit 99.3



DeGolyer and MacNaughton

4925
Greenville Avenue, Suite 400

One Energy Square

Dallas, Texas 75206



APPRAISAL REPORT

as of

DECEMBER 31, 2004

on

RESERVES

owned by

CHALLENGER MINERALS, INC.

in the

WEST HEATHER AREA

of the

BROOM FIELD

offshore

UNITED KINGDOM





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DeGolyer and MacNaughton

4925 Greenville Avenue, Suite 400

One Energy Square

Dallas, Texas 75206



APPRAISAL REPORT

as of

DECEMBER 31, 2004

on

RESERVES

owned by

CHALLENGER MINERALS, INC.

in the

WEST HEATHER AREA

of the

BROOM FIELD

offshore

UNITED KINGDOM



FOREWORD



Scope of Investigation



This report presents an appraisal, as of December 31, 2004, of the extent and value of the proved and probable crude oil, natural gas, and natural gas
liquids (NGL) reserves of the West Heather Area of the Broom field located offshore the United Kingdom. The field is operated by Lundin Petroleum (Lundin).



Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced
after December 31, 2004, from the property evaluated herein. Net reserves are defined as that portion of the gross reserves attributable to the 8-percent interest owned by Challenger Minerals, Inc. (CMI) after deducting all interests owned by
others. Table 1 is a summary of the gross and net reserves estimated in this report.



This report presents values that were estimated for proved and proved-plus-probable reserves using prices and costs as of the date the estimate was made. Prices and costs were provided in United Kingdom pounds
sterling (U.K.£) and United States dollars (U.S.$). Where applicable,



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economic calculations were performed in U.K.£ and converted to U.S.$ using an exchange rate of U.S.$1.916 per U.K.£1.00. All monetary values
shown in this report are expressed in U.S.$ unless specified otherwise. A detailed explanation of future price and cost assumptions is included in the Valuation of Reserves section of this report. The summary of future net revenue estimated in this
report is shown in Table 2.



Values for proved and
proved-plus-probable reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue to be realized from the sale of the net reserves. Future
net revenue is defined as the future gross revenue less royalties, host government taxes, direct operating expenses, abandonment costs, and capital costs. Direct operating expenses include field operating costs, transportation costs, and estimated
expenses of direct supervision. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate
of 10 percent are reported in detail and values using discount rates of 5 and 15 percent are reported as totals.



Estimates of oil, gas, and NGL reserves and future net revenue should be regarded only as estimates that may change as further production history and
additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental
factors in interpreting such information.



Authority



This report was authorized by Mr.
Robert McNamara, Manager of Engineering, CMI.



Source of Information



Information used in the
preparation of this report was obtained from CMI. In the preparation of this report we have relied, without independent verification, upon information furnished by CMI with respect to property interests, production from such property, current costs
of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the property
was not considered necessary for the purposes of this report.



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CLASSIFICATION of RESERVES



Petroleum reserves included in this report are
classified by degree of proof as proved or probable. Proved reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory
practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production under existing economic and operating conditions using prices and costs as
of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:



Proved  Reserves that have been proved to a high
degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. Commercial productivity has been established by actual production, successful testing, or in certain
cases by favorable core analyses and electrical-log interpretation when the producing characteristics of the formation are known from nearby fields. Volumetrically, the structure, areal extent, volume, and characteristics of the reservoir are well
defined by a reasonable interpretation of adequate subsurface well control and by known continuity of hydrocarbon-saturated material above known fluid contacts, if any, or above the lowest known structural occurrence of hydrocarbons.



Developed  Reserves that are recoverable from existing wells
with current operating methods and expenses.



Developed
reserves include both producing and nonproducing reserves. Estimates of producing reserves assume recovery by existing wells producing from present completion intervals with normal operating methods and expenses. Developed nonproducing reserves are
in reservoirs behind the casing or at minor depths below the producing zone and are considered proved by production from other wells in the field, by successful drill-stem tests, or by core analyses from the particular zones. Nonproducing reserves
require only moderate expense to be brought into production.



Undeveloped  Reserves that are recoverable from additional wells yet to be drilled.



Undeveloped reserves are those considered proved for production by reasonable geological interpretation of adequate subsurface control in reservoirs that
are producing or proved by other wells but are not recoverable from existing wells. This classification of reserves requires drilling of additional wells, major



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deepening of existing wells, or installation of enhanced recovery or other facilities.



Reserves recoverable by enhanced recovery methods, such as injection of external fluids to provide energy not inherent in
the reservoirs, may be classified as proved developed or proved undeveloped reserves depending upon the extent to which such enhanced recovery methods are in operation. These reserves are considered to be proved only in cases where a successful
fluid-injection program is in operation, a pilot program indicates successful fluid injection, or information is available concerning the successful application of such methods in similar reservoirs in the general area.



Probable  Reserves susceptible of being proved that are based
on reasonable evidence of producible hydrocarbons within the limits of a structure or reservoir above known or inferred fluid contacts but are defined to a lesser degree of certainty because of more limited well control and/or the lack of definitive
production tests. Probable reserves may include extensions of proved reservoirs or other reservoirs that have not been tested at commercial rates of flow.



The extent to which probable reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and well performance.
The degree of risk to be applied in evaluating probable reserves is influenced by economic and technological factors as well as the time element. Probable reserves in this report have not been adjusted in consideration of these additional risks and
therefore are not comparable with proved reserves.



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ESTIMATION of RESERVES



Estimates of reserves were prepared by the use of
standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality
and completeness of basic data, and production history.



When
applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume.
Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances
justified, material-balance and other engineering methods were used to estimate OOIP or OGIP.



For those fields where the volumetric method was applied, estimates of ultimate recovery were obtained by applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of
energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the reservoirs, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. In such
cases, an analysis of reservoir performance, including production rates, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.



For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics,
reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic
conditions.



In certain cases, when the previously named
methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.



The reserves estimates presented herein are based on consideration of data available through December 31, 2004. When applicable, estimated cumulative
production, as of December 31, 2004, was deducted from the gross ultimate recovery to determine the estimated gross reserves.



Gas volume estimates reported herein are expressed as wet gas, marketable gas, and sales gas at a temperature base of 15.6 degrees Centigrade (60 degrees



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Fahrenheit) and a pressure base of 14.696 pounds per square inch absolute. Wet gas is defined as the total gas to be produced from the reservoirs prior to
separation or processing and includes the gas equivalent of condensate. Marketable gas is the wet gas measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Sales gas
is the marketable gas volume that is sold. There are no gas sales expected from the West Heather Area of the Broom field.



Oil volumes estimated herein are those to be recovered by normal field separation. NGL volume estimates reported herein are condensate and other
hydrocarbon liquids recovered by normal field separation. Estimates of oil and NGL are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 U.S. gallons.



The Broom field is a new-development satellite of the mature main Heather field in blocks 2/4 and 2/5 (Figure 1), in which
CMI owns an 8.0-percent interest. The field produces from the Brent series of reservoirs (Figure 2). In 2003, the United Kingdom Government designated the West Heather and North Terrace Areas as one new field called the Broom field. This evaluation
considers only the West Heather Area of the Broom field.



The
West Heather Area of the Broom field is planned to produce through the Heather field facility. The Heather field currently produces about 5,000 barrels of oil per day and produces from a fixed platform. With the planned connection of the West
Heather Area of the Broom satellite field, the life of the Heather field will be extended by sharing operating expenses.



The West Heather Area of the Broom field is being developed by drilling. In 2004, the 2/521 and 2/522 injector wells were drilled. The field
utilizes subsea completions and tie-backs to the Heather platform. Production and injection began in the third quarter of 2004. Full development of the West Heather Area of the Broom field will utilize three producers and two injectors. Figure 3 is
a structure map on the top of Brent, and Figures 4 and 5 are net oil isopach maps. The proved reserves reflect performance of existing wells plus a volumetric estimate of OOIP based on the net oil isopach shown on Figure 4. Figure 5 represents the
net oil isopach used to estimate the OOIP associated with the proved and probable reserves. Tables 3 and 4 detail the volumetric evaluation.



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The estimated gross and net proved and probable reserves, as of December 31, 2004, of the West Heather
Area of the Broom field are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):



|          |  |                  |  |                 |  |                    |  |                 
|--------- |  | ---------------- |  | --------------- |  | ------------------ |  | ----------------
|          |  | Gross Reserves   |  | Net Reserves   
|          |  | Oil andNGL(Mbbl) |  | SalesGas (MMcf) |  | Oil and NGL (Mbbl) |  | Sales Gas (MMcf)
|Proved    |  | 32,048           |  | 0               |  | 2,564              |  | 0               
|Probable* |  | 11,104           |  | 0               |  | 888                |  | 0               



|* | Probable reserves have not been adjusted for risk.
|- | --------------------------------------------------



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VALUATION of RESERVES



Revenue values for proved and proved-plus-probable
reserves in this report were estimated using initial prices and costs provided by CMI. Future prices were estimated using guidelines established by the United States Securities and Exchange Commission (SEC) and the Financial Accounting Standards
Board (FASB). The initial and future prices used in this report have been reviewed by CMI and it has represented that the prices used herein are those that CMI received on December 31, 2004.



Values for proved and proved-plus-probable reserves were based on projections
of estimated future production and revenue prepared for these properties with no risk adjustment applied to the probable reserves. Probable reserves involve substantially higher risks than proved reserves. Revenue values for proved-plus-probable
reserves have not been adjusted to account for such risks; this adjustment would be necessary in order to make proved-plus-probable reserves values comparable with values for proved reserves.



The following assumptions were used in estimating future prices and costs:



Oil and NGL Prices



An oil and NGL price of U.S.$40.07 per barrel was used for estimating future
net revenue from proved and proved-plus-probable reserves. Oil and NGL prices were held constant for the life of the properties.



Operating Expenses



Current operating expenses and operating expense forecasts provided by CMI were used in estimating future expenses required to operate the fields. In
certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions, but they did not include any general escalation that might result from inflation. Historical
operating expenses, 2005 work program and budget information, asset operating plans, and experience in the operating area were considered in estimating future operating expenses for this evaluation. CMI pays the Heather field owners a tariff of
U.K.£2.39 per barrel for throughput into the Heather facilities. This tariff also accounts for a marketing fee and a past-cost reimbursement fee from CMI to the Heather owners. CMI also pays a U.K.£1.02 per barrel processing fee to the
Sullom Voe Terminal owners. In addition to these variable charges, a gross fixed expense of U.K.£1.4 to 1.75 million per year was estimated for the field. Fixed



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annual expenses were adjusted up or down as necessary to account for changes in activity level. Details of the life-of-field net operating expenses are
presented in the economic analysis in Tables 5 and 6.



Capital Costs



Future capital expenditures
were estimated using current capital cost forecasts provided by CMI and were not adjusted for inflation. Historical capital costs, 2005 work program and budget information, asset development plans, and experience in the operating areas were
considered in estimating future capital costs for this evaluation. For the West Heather Area of the Broom field, the same gross capital cost of U.K.£0.5 million was used for the proved and proved-plus-probable reserves cases.



United Kingdom Taxes



The West Heather Area of the Broom field, having gained development sanction
post-March 1993, will not be subject to the petroleum revenue tax. The field is, however, subject to a United Kingdom corporation tax. Changes to the corporation tax laws were announced as part of the 2004 United Kingdom national budget. These
changes called for the increase in the statutory tax rate for oil and gas companies from 30 percent to 40 percent effective April 2004. Corporation tax was calculated on a field basis considering a past cost basis net to CMIs interest of
U.S.$8.6 million. The West Heather Area of the Broom field is not subject to royalty.



Exchange Rate



The
exchange rate used to convert values from U.K.£ to U.S.$. was U.S.$1.916 per U.K.£1.00.



Abandonment Costs



CMIs share of the West Heather Area of the Broom abandonment liability of gross U.K.£3.7 million associated with the proved and
proved-plus-probable reserves has been included in the costs estimated herein.



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Under the aforementioned assumptions concerning future prices and costs, estimated revenue and present
worth, expressed in thousands of U.S. dollars (M U.S.$), attributable to CMIs interests in the proved and the proved-plus-probable reserves, as of December 31, 2004, in the West Heather Area of the Broom field are summarized as follows:



|                                     |  |        |  |                      
|------------------------------------ |  | ------ |  | ---------------------
|                                     |  | Proved |  | Proved plus Probable*
|Future Net Revenue, M U.S.$          |  | 54,086 |  | 71,702               
|Present Worth at 10 Percent, M U.S.$ |  | 39,441 |  | 49,156               



|* | Values associated with probable reserves have not been adjusted for risk.
|- | -------------------------------------------------------------------------



In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated
future net revenue from proved reserves of oil, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 1013, 15, and 30(a)(b) of Statement of Financial Accounting Standards No. 69 (November
1982) of the FASB and Rules 410(a) (1)(13) of Regulation SX and Rule 302(b) of Regulation SK of the SEC; provided, however, that (i) certain estimated data have not been provided with respect to changes in reserves
information and (ii) future United States income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein. These rules and regulations also contain specific provisions that prohibit
the reporting of probable reserves; therefore, the reporting and filing with the SEC of the probable reserves or values associated with probable reserves contained herein would not be in conformity with such rules and regulations and should not,
under any circumstances, be used or relied upon to meet the requirements thereof.



To the extent that the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of our report, we are necessarily unable to express an
opinion as to whether the above-described information is in accordance therewith or sufficient therefor.



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SUMMARY and CONCLUSIONS



CMI owns an 8-percent interest in the West Heather
Area of the Broom field located offshore the United Kingdom. The field is currently under development and first production began in the third quarter of 2004.



The estimated gross proved and probable reserves, as of December 31, 2004, of the West Heather Area of the Broom field and net reserves attributable to
CMIs interests are summarized as follows, expressed in thousands of barrels (Mbbl) or millions of cubic feet (MMcf):



|          |  |                  |  |                  |  |                  |  |                 
|--------- |  | ---------------- |  | ---------------- |  | ---------------- |  | ----------------
|          |  | Gross Reserves   |  | Net Reserves    
|          |  | Oil andNGL(Mbbl) |  | Sales Gas (MMcf) |  | Oil andNGL(Mbbl) |  | Sales Gas (MMcf)
|Proved    |  | 32,048           |  | 0                |  | 2,564            |  | 0               
|Probable* |  | 11,104           |  | 0                |  | 888              |  | 0               



|* | Probable reserves have not been adjusted for risk.
|- | --------------------------------------------------



Under the aforementioned assumptions concerning future prices and costs, estimated revenue and present worth, expressed in thousands of U.S. dollars (M
U.S.$), attributable to CMIs interests in the proved and proved-plus-probable reserves, as of December 31, 2004, are summarized as follows:



|                                     |  |        |  |                      
|------------------------------------ |  | ------ |  | ---------------------
|                                     |  | Proved |  | Proved plus Probable*
|Future Net Revenue, M U.S.$          |  | 54,086 |  | 71,702               
|Present Worth at 10 Percent, M U.S.$ |  | 39,441 |  | 49,156               



|* | Values associated with probable reserves have not been adjusted for risk.
|- | -------------------------------------------------------------------------



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Summary projections of estimated annual future net production and revenue are shown in Table 5 for proved
reserves and in Table 6 for proved-plus-probable reserves.



Submitted,/s/ Degolyer And MacnaughtonDeGOLYER and MacNAUGHTON




SIGNED: February 28, 2005



/s/    LLOYD W. CADE,
P.E.Lloyd W. Cade, P.E.Senior Vice President DeGolyer and MacNaughton




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[Tables and Figures Omitted]