Masters Energy Inc.

Masters Energy Inc.

March 04, 2005 09:00 ET

Masters Energy Inc. Reports 2004 Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: MASTERS ENERGY INC.

TSX SYMBOL: MSY

MARCH 4, 2005 - 09:00 ET

Masters Energy Inc. Reports 2004 Results

CALGARY, ALBERTA--(CCNMatthews - March 4, 2005) - Masters Energy Inc.
(TSX:MSY) ("Masters" or the "Company" is pleased to report financial and
operating results for the year ended December 31, 2004. Several
significant accomplishments were achieved during the year;

- The amalgamation of Masters and Terraquest Energy Corporation on
February 26, 2004.

- Completion of a reservoir simulation study at our Little Bow property
which indicates incremental oil recovery with infill drilling and
waterflood optimization.

- The drilling or recompletion of 19 wells resulting in 10 natural gas
wells

- Increasing total proved and probable reserves 101 percent to 2.8
million boe at December 31, 2004 from 1.4 million boe at January 1, 2004.

- Exit 2004 production of 1,100 boe per day compared to 455 boe per day
at the beginning of the year.

- An increase in net asset value per share of 44 percent throughout the
year.




HIGHLIGHTS(a)
Years ended December 31 2004 2003(a)
------------------------------------------------------------------------
Financial ($ thousands, except per share amounts)
Gross revenue 11,709 192

Cash flow from operations 5,634 (67)
Per share - basic 0.42 (0.02)
- diluted 0.41 (0.02)

Net earnings (loss) 428 (110)
Per share - basic 0.03 (0.03)
- diluted 0.03 (0.03)

Capital expenditures 10,920 7,393

Working capital (deficit) (4,116) 9,390

Operations
Production
Crude oil (bbls/d) 558 426
NGL (bbls/d) 7 1
Natural gas (mcf/d) 1,706 171
Total production (boe/d at 6:1) 849 455

Average sales price
Crude oil ($/bbl) 36.51 27.72
NGL ($/bbl) 44.25 43.34
Natural gas ($/mcf) 6.59 7.19

(a) Masters oil and gas operations commenced December 22, 2003 with the
acquisition of the Little Bow property in Southern Alberta. 2003
average daily production reported from date of acquisition.


Presidents Message to the Shareholders

Since December 21, 2003 until the end of the 2004 year we have taken
Masters from a company with no operations, $17 million in cash and
technical expertise to an oil and gas company with production of 1,100
boe/d and an undeveloped land base of approximately 83,000 acres. The
acquisition of the producing Little Bow property in Southern Alberta and
the merger with Terraquest Energy Corporation, provided the framework by
which the former team from Sunfire Energy Corporation could apply their
technical expertise.

Investing in exploration and development activities, inclusive of
acquisitions, since December 21, 2003 has added 2.5 million boe of
proven reserves and 3.1 million boe of proven and probable reserves at
an all-in finding and development cost of $14.96 per boe proven and
$12.05 per boe proven and probable. Based on our average 2004 operating
netbacks of $21.63 per boe this resulted in an investment recycle ratio
of 1.8 times since the commencement of oil and gas operations. The 2004
capital program, excluding acquisitions, of $10.9 million resulted in
proved plus probable drilling additions of 0.6 million boe. Production
was replaced 1.9 times while the reserve life index was 7.8 years at
year-end. As this was a year of identifying and establishing potential
core areas the drilling drilling prospects we pursued tended to be more
exploration in nature as several new exploration ideas were tested on
the recently acquired land base.

Production for 2004 averaged 849 boe per day. Fourth quarter production
averaged 1,002 boe per day, an increase of eight percent over the third
quarter production. The exit rate for 2004 production was 1,100 boe per
day as a result of several tie-ins completed in the latter portion of
the fourth quarter.

At Little Bow, 3 (3.0 net) successful oil wells were drilled in January
2005 and are on production at 200 boe per day. Currently, total
corporate production is approximately 1,300 boe per day (65% crude oil)
with an additional 200 boe per day behind pipe. The initial drilling
supports the reservoir simulation study performed in 2004 and additional
drilling activity after spring break-up is contemplated.

The 2004 capital program was the initial year for the Company to explore
and develop opportunities on its land base in Alberta. Through the
efforts of this program the Company was able to establish a large
inventory of future drilling opportunities. For 2005 approximately 25
wells will be drilled and the Company will operate a majority of the
prospects identified for drilling.

Based on forecast average production of 1,500 boe per day; commodity
prices of $35.00(US) per bbl for WTI crude and a natural gas wellhead
price of $6.50(CDN) per mcf; the US to Canadian foreign exchange of
$0.80(US) and costs remaining at historical levels, 2005 cash flow is
anticipated to be approximately $11 million.

The Company's 2005 capital program is forecast to be $12 million with an
approximate allocation of $2.3 million for land and seismic, $6.9
million on drilling and completions and $1.5 million for facilities. The
net debt at December 31, 2004 was approximately $4.1 million and is
forecast to be approximately $5.0 million at 2005 year-end.

ANNUAL GENERAL MEETING

The Company's Annual General Meeting is scheduled for 2:00 PM (Calgary
Time) on Tuesday May 3, 2005 at the Metropolitan Centre - 333, 4th
Avenue SW Calgary, Alberta.

OUTLOOK

The acquisitions of Terraquest and the Little Bow properties have
created a strong production base from which the Company can grow. With
an experienced technical team, a strong balance sheet, a large
undeveloped land base (83,000 net acres) and a number of internally
generated prospects, the Company is well positioned for growth. The
Company believes it can deliver production growth averaging 1,500 boe
per day in 2005 from the Company's internally generated exploration and
development program. The Board of Directors has approved a $12 million
capital program. The 2005 capital program will be spent on developing
existing internal opportunities, exploring new prospects and continuing
to build an inventory of exploration and development opportunities that
will provide growth in 2006 and beyond.

In addition to the ongoing exploration and development program, Masters
has a strong desire to grow through acquisitions and will continue to
seek acquisitions that are strategic and add future value to the
Company. Our strong balance sheet allows ample flexibility to complete
potential acquisitions, which could be material to the Company.



On behalf of the Board of Directors,

Geoff C. Merritt
President and Chief Executive Officer
March 3, 2005



MANAGEMENT'S DISCUSSION AND ANALYSIS

ADVISORIES

Management's discussion and analysis ("MD&A") of Masters Energy Inc.
("Masters or the Company"), provided as of March 3, 2005, should be read
in conjunction with the audited financial statements presented within
this annual report.

Basis of Presentation - The financial data presented below has been
prepared in accordance with Canadian generally accepted accounting
principles ("GAAP"). The reporting and the measurement currency is the
Canadian dollar.

Non-GAAP Measurements - The MD&A contains the term cash flow from
operations, which should not be considered an alternative to, or more
meaningful than net earnings or cash flow from operating activities as
determined in accordance with GAAP as an indicator of the Company's
performance. Masters' determination of cash flow from operations and
cash flow per share may not be comparable to that reported by other
companies. The reconciliation between net earnings and cash flow from
operations can be found in the statements of cash flows in the audited
financial statements. The Company presents cash flow from operations per
share which is prohibited under GAAP. Per share amounts are calculated
using weighted average shares outstanding consistent with the
calculation of earnings per share.

BOE Presentation - The calculations of barrels of oil equivalent ("boe")
are based on a conversion rate of six thousand cubic feet ("mcf") of
natural gas to one barrel ("bbl") of crude oil. Boe's 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.

Forward Looking Information - This MD&A contains forward looking or
outlook information with regard to Masters within the meaning of
applicable securities laws. Forward looking statements may include
estimates, plans, expectation, forecasts, guidance or other statements
that are not statements of fact. Masters believes the expectations
reflected in such forward looking statements are reasonable. However, no
assurance can be given that such expectations will prove to be correct.
These statements are subject to certain risks and uncertainties and may
be based on assumptions that could cause actual results to differ
materially from those anticipated or implied in the forward looking
statements. These risks include but are not limited to: crude oil and
natural gas price volatility, exchange rate and interest rate
fluctuations, availability of services and supplies, market competition,
uncertainties in the estimates of reserves, the timing of development
expenditures, production levels and the timing of achieving such levels,
the Company's ability to replace and expand oil and gas reserves, the
sources and adequacy of funding for capital investments, future growth
prospects and current and expected financial requirements of the
Company, the cost of future reclamation and site restoration, the
Company's ability to enter into or renew leases, the Company's ability
to secure adequate product transportation, changes in environmental and
other regulations and general economic conditions. These statements
speak only as of the date of this MD&A and the Company does not
undertake an obligation to update our forward looking statements except
as required by law.

ACQUISITION

Masters acquired Terraquest Energy Corporation ("Terraquest") by way of
a plan of arrangement whereby Terraquest and Masters amalgamated
effective February 26, 2004. At the time of the acquisition, Terraquest
was producing approximately 400 boe per day, 60 percent of which was
natural gas. The attraction to Masters in acquiring Terraquest was an
extensive base of undeveloped land with a significant number of drilling
prospects. Terraquest had 84,000 net acres of undeveloped land, operated
primarily by Terraquest, with an average working interest of 60 percent.

The Terraquest purchase was valued based on the discounted proved plus
probable reserves acquired as determined by an independent reserve
evaluation. Land cost values were estimated by Masters staff. The cost
of the purchase, based on the above valuation methods, was as follows:



($ thousands)
-----------------------------------------------------------
Property and equipment $19,584
Future tax asset 903
Working capital deficiency (694)
Fair value of hedging commitment (199)
Bank debt (7,032)
Asset retirement obligation (1,770)
--------
Total purchase price $10,792
--------
--------


OVERVIEW

Masters Energy Inc. was incorporated under the Alberta Business
Corporations Act on August 28, 2003. During the fall of 2003 Masters
completed a private placement of 17,752,000 special warrants for gross
proceeds of $17.8 million. On December 22, 2003 Masters closed the
acquisition of producing oil and gas properties in the Little Bow area
of southern Alberta. At the time of acquiring the property, daily
production was approximately 450 boe per day with a composition of 90
percent oil and 10 percent gas.

On February 26, 2004, Masters and Terraquest, a public company listed on
the Toronto Stock Exchange, amalgamated and the combined company
("Amalco") continued under the name and management of Masters Energy
Inc. The transaction saw Terraquest shareholders receive one Amalco
Common Share for every 12 common shares of Terraquest and Masters
shareholders received one Amalco Common Share for every 2 common shares
of Masters. After giving effect to the transaction, Amalco has
approximately 14.4 million Common Shares outstanding.

The consequence of the reverse take-over and amalgamation of Terraquest
on February 26, 2004 was the loss of any relevant comparative analysis
for Masters in the 2003 accounting period. Year over year operational
and financial comparatives will provide useful information with the
publishing of the 2005 annual report.

In 2004, Masters has been actively drilling in the Southern and Central
regions of Alberta. Of 19 wells drilled or recompleted in 2004, 10 were
successful natural gas wells.

During the fourth quarter of 2004 four wells (2.4 net) were drilled
resulting in one natural gas well and three abandoned wells. At the end
of the 2004 year three wells were waiting for pipeline tie-ins. The well
tie-ins are expected to be completed during the early part of 2005.

FOR THE YEAR ENDED DECEMBER 31, 2004 AND THE PERIOD AUGUST 28, 2003 to
DECEMBER 31, 2003

PRODUCTION

Production volumes from the Terraquest properties have been included in
Masters' 2004 results from the date of amalgamation, February 26, 2004.
This report incorporates Masters' results from January 1 to February 26,
2004 plus the results of the amalgamated entity from February 26 to
December 31, 2004.



Production Summary
2004 2003(1)
---------------------
Annual Production
Crude oil (bbl) 204,049 4,259
Natural gas liquids ("NGL") (bbl) 2,550 6
Natural gas (mcf) 624,536 1,713
Total equivalent 310,688 4,551
Daily Production
Crude oil (bbl/d) 558 426
NGL (bbl/d) 7 1
Natural gas (mcf/d) 1,706 171
Total equivalent (boe/d) 849 455

(1)Operations commenced December 22, 2003 upon closing the acquisition
of the Little Bow property in southern Alberta, therefore the daily
production is calculated from the date operation began until the 2003
year-end.


Volume for the year ended December 31, 2004 averaged 849 boe per day
with a production mix of 67 percent oil and NGL and 33 percent natural
gas. The average production for the month of December 2004 was 1,055 boe
per day, of which 57% was oil and NGL and the balance natural gas.
Production increased during the 2004 year as a result of successful
natural gas wells being drilled and tied-in.

2003 oil and gas production began December 22nd with the acquisition of
the Little Bow property in southern Alberta. From the date of
acquisition until the 2003 year-end production averaged 456 boe per day
with a production mix of 94% oil and NGL and the remainder of natural
gas.

Based on the drilling activity budgeted for 2005 and production expected
from existing producing properties, the Company is forecasting a
production rate of 1,500 boe per day with a liquids versus natural gas
production mix of 58 percent and 42 percent, respectively.



PRICES

Commodity Prices
2004 2003
-------------------
Crude oil - before hedging ($/bbl) 37.66 27.72
Hedging settlement ($/bbl) (1.15) -
-------------------
Crude oil - after hedging ($/bbl) 36.51 27.72
-------------------
-------------------
NGL ($/bbl) 44.25 43.34
-------------------
-------------------
Natural gas ($/mcf) 6.59 7.19
-------------------
-------------------


The commodity prices recorded in the above table are net of hedging
settlements of $0.2 million. The hedging contract was obtained with the
acquisition of Terraquest Energy Corporation. The loss recorded for the
year was the balance in excess of the fair value of the hedging contract
liability recorded at the time of the acquisition.

West Texas Intermediate ("WTI") is the benchmark for North American oil
prices and is the crude type that the NYMEX futures contracts are priced
against. Canadian crude oil prices are based on refiners' postings at
hubs such as Edmonton and Hardisty, Alberta. The Canadian postings are
based on the WTI price at Cushing, Oklahoma less a transportation
differential, the US/Canadian currency exchange rate, adjusted for
relative quality and regional market conditions.

During 2004 North America saw historically high price levels for WTI
crude oil due to concerns over supply. As a result, the average price
for a barrel of WTI crude during 2004 increased over $10.00(US) to
$41.42(US). The Canadian dollar strengthened relative to the US dollar
during the course of the year. The average currency exchange rate for
$1.00 Canadian increased from $0.71(US) in 2003 to $0.77(US) in 2004. As
a result this lowered the price received for delivery of crude within
Canadian markets. The quality price differential postings on medium type
crudes also experienced a negative effect during 2004. The average
differential between Edmonton light sweet crude postings and Hardisty
Bow River medium crude was approximately $15.00 per bbl versus the
historical average of $9.00 per bbl.

Masters' average field price in 2004 was $37.66 per bbl versus $52.90
per bbl for light sweet postings at Edmonton, Alberta. Overall Masters'
2004 crude oil production was 84 percent medium and 16 percent lighter
gravity crude.

US natural gas prices are typically referenced off NYMEX at Henry Hub,
Louisiana while Canadian prices are referenced at Nova Inventory
Transfer ("NIT") or the AECO Hub. All of Masters' 2004 natural gas was
sold to the spot market according to the AECO reference price. Masters
did not enter into any fixed or hedged type gas sales contracts during
2004.

The prices received for 2003 was limited to the period of production for
the final 10 days of the calendar year.

The forecasted prices used for the Company's 2005 budget was $35.00(US)
per bbl of WTI crude oil and $6.50(CDN) per mcf of natural gas at the
wellhead. The 2005 forecasted US/Canadian foreign currency exchange rate
is estimated to average $0.80(US) per $1.00(CDN).



REVENUES

Revenue Summary
($ thousands) 2004 2003
------------------------------------------------------------------------
Crude oil revenue 7,685 118.0
Hedging charge (234) -
---------------------
Crude oil revenue, after hedging charge 7,451 118.0
NGL revenue 113 0.3
Natural gas revenue 4,116 12.3
---------------------
Total resource revenue 11,680 130.6
Interest and other revenue 29 61.5
---------------------
Total revenue 11,709 192.1
---------------------
Total revenue per boe ($) 37.69 42.21
---------------------
---------------------


Resource revenues for the 2004 year, totaled $11.7 million as commodity
prices remained strong and production volumes continued to grow. Oil
revenues were partially offset with a $0.2 million loss recorded for the
balance remaining on the hedge contract assumed through the acquisition
of Terraquest. The hedging contract expired on December 31, 2004. The
oil and natural gas revenue for 2003 was $0.1 million as sales from
operations were limited from the time the Little Bow property was
acquired.

Interest and other income earned on surplus cash totaled $29,264 during
2004 versus $61,471 for 2003. During 2004 surplus cash was invested in
exploration and development capital spending and acquisitions and as a
result interest income was lower.

Based on the forecasted production volumes and commodity prices the
Company expects the oil and gas revenues to increase 70 to 75 percent
during 2005.



ROYALTIES

Royalties Summary
($ thousands, except per boe) 2004 2003
------------------------------------------------------------------------
Crown 2,122 23.5
ARTC (184) -
---------------------
Crown, net of ARTC 1,938 23.5
Freehold and other 172 0.2
---------------------
Net royalties 2,110 23.7
---------------------
---------------------
Per boe ($) 6.79 5.20
Average royalty rate, before hedge charge (%) 17.7 18.1
Average royalty rate, after hedge charge (%) 18.1 18.1


For the 2004 year, royalties, net of Alberta royalty tax credit, totaled
$2.1 million for an average royalty rate relative to oil and gas
revenues of 18 percent. The composition of the royalty expense incurred
during the year was 92 percent paid to crown and the balance to freehold
royalty owners. On a boe basis, royalties for the year were $6.79 per
boe.

For 2003 the royalty rate averaged 18 percent of oil and gas revenues.
There was no ARTC during the period as the Little Bow property was
considered a restricted resource property for ARTC purposes.

Forecasted royalty rates for 2005 are anticipated to be consistent with
historical rates. The Company anticipates maximizing its ARTC claim on
Crown royalties during 2005.



OPERATING EXPENSES

Operating Expense Summary

Operating Expense Summary
($ thousands except per boe amount) 2004 2003
------------------------------------------------------------------------
Production expenses 2,816 37.0
Transportation costs 37 -
---------------------
Total operating expenses 2,853 37.0
---------------------
---------------------
Per boe ($) 9.18 8.13


Operating expenses for the year ended December 31, 2004 was $2.9
million. This equated to an average cost of $9.18 per boe produced. The
operating expenses were higher than anticipated due to well servicing,
plant turnaround and maintenance activities carried out at the Little
Bow facilities during the 2004 summer. Included in 2004 operating
expenses are transportation costs incurred on contracted natural gas
deliveries.

The operating expenses for 2003 were limited to the production from the
Little Bow field.

Operating expenses per boe are expected to decrease with higher
production volumes as fixed costs are spread over a larger production
base for 2005. This will be partially offset with increased variable
costs such as utility and service fees due to increased industry demand.



Netback Analysis
($ per boe) 2004 2003
------------------------------------------------------------------------
Oil and gas revenues, before hedge charge 38.35 28.70
Hedge charge (0.75) -
---------------------
Oil and gas revenues, after hedge charge 37.60 28.70
Royalties, net of ARTC (6.79) (5.20)
Operating expenses (9.18) (8.13)
---------------------
Netback 21.63 15.37
---------------------
---------------------


GENERAL and ADMINISTRATIVE

General and Administrative Expense Summary
($ thousands) 2004 2003
------------------------------------------------------------------------
Gross general and administrative 1,529 192
Operating recoveries (121) -
Capitalized expenses (504) -
---------------------
General and administrative, before stock
based compensation 904 192
Future stock based compensation expense 173 38
---------------------
Total general and administrative expense 1,077 230
---------------------
---------------------
General and administrative expense per boe ($) 3.47 50.48
---------------------
---------------------


During the 2004 year, net general and administrative expense totaled
$1.1 million. General and administrative costs averaged $3.47 per boe
for the year ended December 31, 2004. During the year $0.5 million of
general and administrative costs associated with exploration and
development activities were capitalized. Masters capitalizes general and
administrative expense related to exploration and development activities
as these costs are associated with adding reserves. General and
administrative expenses for the period include a non-cash provision of
$0.2 million for future stock based compensation. General and
administrative expenses for the year included several one-time costs
associated with the start-up and amalgamation.

General and administrative expenses for 2003 were for the period from
incorporation of the Company in August 2003 until December 31, 2003. The
general and administrative expense per boe is high due to oil and
natural gas production occurring from December 22, 2003 to the year-end,
December 31, 2003.

Total general and administrative expenses for 2005 are anticipated to be
similar to 2004. Based on forecasted production and capital spending,
2005 staff levels are anticipated to be similar to 2004. Costs per boe
are expected to decrease as new production is brought onstream.

INTEREST EXPENSE

At year end 2004 Masters had $3.4 million bank debt. The average debt
outstanding during the year was approximately $1.2 million. The change
in the year-end balance over the average borrowing level was a result of
the increased exploration and development activities during the latter
half of the year. The average interest rate to borrow during the year
was 4.18%. Included with interest expense was $56 thousand of Part XlI
tax on the unspent portion of 2003 flow through share funding received
and held after February 2004. All 2003 flow through share funds were
fully spent in 2004.

Anticipated debt levels and interest rates for 2005 are forecast to be
similar to 2004. For the 2005 year the debt to cash flow ratio is
anticipated to be approximately 0.4 to one.



DEPLETION, DEPRECIATION and ACCRETION

Depletion, Depreciation and Accretion Summary
($ thousands except per boe amount) 2004 2003
------------------------------------------------------------------------
Depletion 4,283 34
Depreciation 13 5
Accretion on asset retirement obligations 171 -
---------------------
Total depletion, depreciation
and accretion expense 4,467 39
---------------------
---------------------
Depletion, depreciation and
accretion expense per boe 14.38 8.60
---------------------
---------------------


Depletion, depreciation and accretion expense for the 2004 year was $4.5
million or $14.38 per boe produced during the period. The depletion was
high as a result of the capital costs to acquire Terraquest and the
recording of associated asset retirement obligations of the acquired
operations.

Masters performs an annual ceiling test in accordance with the Canadian
Institute Chartered Accountants' full cost accounting guidelines, using
forecasted prices determined by the independent reservoir engineering
firm that evaluates the Company's reserves. Also Masters performs a
quarterly ceiling test using adjusted prices received at period end. At
December 31, 2004, the impairment recognition portion of the ceiling
test indicated the estimated undiscounted future cash flows from proven
reserves exceeded the carrying values of producing petroleum and natural
gas properties and therefore a ceiling test adjustment was not required.



INCOME TAXES

Income Tax Summary
($ thousands) 2004 2003
------------------------------------------------------------------------
Future income taxes (reduction) 662 (34)
Capital taxes - 6
---------------------
Total income taxes (reduction) 662 (28)
---------------------
---------------------
Effective tax rate (%) 60.7 24.8
---------------------
---------------------


The future income tax expense of $0.7 million for the 2004 year is due
to earnings for the period culminating from higher commodity prices and
production volumes and a reduction in provincial income tax rates that
have been enacted. Based on available tax pools, forecasted capital
spending levels and commodity prices, the Company forecasts not to be
currently taxable for the 2005 year.

The Company has approximately $31.9 million in tax pools to shelter
taxable income in the future years. The 2004 estimated tax pools are as
follows;



($ thousands)
-----------------------------------------------------------
Canadian Exploration Expense 5,473
Canadian Development Expense 2,917
Canadian Oil and Gas Property Expense 14,630
Undepreciated Capital Cost 6,039
Non capital losses 1,580
Other 1,286
--------
Total 31,925
--------
--------


NET EARNINGS (LOSS)

Net earnings after taxes for the year ended December 31, 2004 was $0.4
million or $0.03 per weighted average shares outstanding as a result of
higher commodity prices and production volumes.



Earnings Ratios

2004 2003
---------------------
Net earnings (loss) ($ thousands) 428 (110)
Earnings ratios (%)
Return on capital (1) 2.3 (1.3)
Return on investment (2) 2.0 (0.4)
Return on shareholder equity (3) 1.9 (1.3)

(1) Net earnings (loss) plus after-tax financing charges on debt divided
by average of opening and closing capital employed. Capital employed
is a total of equity and bank debt.
(2) Net earnings (loss) plus after-tax financing charges on debt divided
by average net investment. Net investment is total assets less
current liabilities. Return on investment is calculated using the
average opening and closing net investment.
(3) Net earnings (loss) are divided by average shareholders' equity.


Net Earnings (Loss) per BOE

($/boe) 2004 2003
---------------------
Total revenues (after hedge charges) 37.69 42.21
Royalties (6.79) (5.20)
Operating expenses (9.18) (8.13)
---------------------
Net operating income 21.72 28.88
General and administrative
(excluding stock-based compensation expense) (2.91) (42.30)
Interest expense (0.36) -
---------------------
Cash flow from operations 18.45 (13.42)
Depletion, depreciation and accretion (14.38) (8.60)
Stock based compensation (0.56) (8.28)
Future taxes (2.13) 6.16
---------------------

Net earnings (loss) 1.38 (24.14)
---------------------
---------------------


SHARE CAPITAL

The basic weighted average shares outstanding, for the three month
period ended December 31, 2004 was 14,363,647 (diluted - 14,613,521).
For the year ended December 31, 2004 the basic weighted average shares
outstanding was 13,521,707 (2003 - 3,812,834) and the diluted average
shares outstanding was 13,716,226 (2003 - 3,812,834). Shares issued and
outstanding, as at December 31, 2004, were 14,363,647 (2003 - 8,876,000)
after recording the effect of the reverse takeover and amalgamation of
Terraquest on February 26, 2004. As of the date of the MD&A there was no
change to the number of shares issued and outstanding.



2004 2003(1)
---------------------
Outstanding Common Shares (thousands)
Weighted average outstanding common shares
- Basic 13,522 3,813
- Diluted 13,716 3,813
Outstanding securities at December 31
- Common shares 14,364 8,876
- Common share options 1,255 575
- Common share warrants 1,000 1,000
- Diluted securities outstanding 16,619 10,451

($ thousands except per share amounts)
Per Share Information
Net earnings (loss) 428 (110)
Net earnings (loss) per share
- Basic 0.03 (0.03)
- Diluted 0.03 (0.03)
Cash flow from operations 5,634 (67)
Cash flow from operations per share
- Basic 0.42 (0.02)
- Diluted 0.41 (0.02)
Total asset book value 37,291 18,288
Total asset book value per share(2)
- Basic 2.60 2.06
- Diluted 2.24 1.75
Book value (shareholders' equity) (2) 27,570 16,473
Book value per share
- Basic 1.92 1.86
- Diluted 1.66 1.58
Proved plus probable reserves (mboe) 2,834 1,408
Reserves per 100 shares (boe) (2)
- Basic 19.7 15.9
- Diluted 17.1 13.5

(1) for comparative purposes the 2003 share amounts take into account
the consolidation of shares upon the amalgamation with Terraquest
on February 2004.
(2) Calculated using outstanding common shares, options and warrants
at year-end.


Net Asset Value

Masters' net asset value per share at December 31, 2004 increased by 45
percent to $2.80 per basic share compared to $1.93 per share in 2003 and
on a diluted basis 34 percent to $2.80 per share in 2004 compared to
$2.09 per share in 2003.



($ thousands) 2004 2004 2003
---------------------------------
Constant Forecast Forecast
Price Price(1) Price
Proved plus probable reserve value
(10% discount before tax) 32,013 36,127 7,700
Undeveloped acreage (2) 8,245 8,245 48
Net working capital (debt) (4,116) (4,116) 9,389
---------------------------------
Basic net asset value 36,142 40,256 17,137
Projected proceeds on exercise of
options and warrants 6,309 6,309 4,700
---------------------------------
Fully diluted net asset value 42,451 46,565 21,837
---------------------------------
---------------------------------
Common shares outstanding (000's)
- Basic 14,364 14,364 8,876
- Diluted 16,619 16,619 10,451
Net asset value per common share ($)
- Basic (3) 2.52 2.80 1.93
- Diluted (3) 2.55 2.80 2.09

(1) The 2004 reserve values are based on before tax future cash flows as
evaluated by the Company's independent reservoir evaluators,
McDaniel & Associates Consultants Ltd. using their future commodity
price forecast.
(2) The land values are determined using an estimated value of $100 per
undeveloped acre.
(3) Calculated using outstanding common shares, options and warrants at
year-end.


CAPITAL EXPENDITURES

Total capital expenditures during 2004 were $30.5 million which included
$10.9 million spent on exploration and development expenditures and
$19.6 million for the acquisition and merger of Terraquest Energy
Corporation on February 26, 2004. During 2003 all capital expenditures
were spent in the last quarter of the year and included $7.0 million for
the acquisition of the Little Bow property in Southern Alberta and $0.4
million on exploration and development activities. The 2004 exploration
and development activity resulted in 19 gross wells drilled or
recompleted and acquisition of 6,471 net acres of undeveloped land. Most
of the capital was spent on exploration and development activities at
various locations in Southern and Central Alberta.




($ thousands) 2004 2003
------------------------------------------------------------------------
Land 889 109
Geological and geophysical 620 84
Drilling and completions 6,652 149
Equipping and facilities 2,757 -
Other 2 41
------------------------------------------------------------------------

Total exploration and development capital 10,920 383
Producing property acquisition - 7,010
Terraquest Energy Corporation 19,584 -
------------------------------------------------------------------------
Total capital expenditures 30,504 7,393
------------------------------------------------------------------------
------------------------------------------------------------------------


Undeveloped Land Holdings

Masters acquired approximately 84,000 undeveloped acres with the
acquisition of Terraquest during 2004. The average working interest of
the undeveloped lands held at December 31, 2004 was 52 percent. The
planned drilling for 2005 will primarily be done on undeveloped lands
held at the 2004 year-end.



Alberta (acres) 2004 2003
------------------------------------------------------------------------
Gross Net Gross Net
------------------------------------------------------------------------
Southern 28,813 20,432 - -
Central 62,560 27,974 1,600 480
Northern 66,483 35,020 - -
------------------------------------------------------------------------

Total undeveloped land 157,856 83,426 1,600 480
------------------------------------------------------------------------
------------------------------------------------------------------------


Finding and Development Costs

During the 2004 year the exploration and development program resulted in
total proved reserve additions, after prior year revisions, of 572,000
boe, (588,000 boe on a proved plus probable basis) resulting in total
exploration and development program finding and development costs of
$19.09 per proved boe and $18.57 per proved and probable boe. Including
the change of future development capital, finding and development costs
were $19.40 per proved boe and $19.06 per proved and probable boe.

The combined 2003 and 2004 capital programs including the acquisitions
of Little Bow and Terraquest resulted in finding and development costs
$14.96 per proved boe and $12.05 per proved and probable boe. After
adding in the change of future development capital, finding and
development costs were $15.03 per proved boe and $12.14 per proved and
probable boe.

The reserves disclosed for 2004 and 2003 conform with the requirements
of National Instrument 51-101, Standards of Disclosure for Oil and Gas
Activities.



2004 Finding & Development (F&D) and Net Acquisition (FD&A) Costs

Proved
plus Proved
Proved Probable plus
Capital Reserve Proved Reserve Probable
Expenditures Additions Costs Additions Costs
------------------------------------------------------------------------
($ thousands) (mboe) ($/boe) (mboe) ($/boe)
F&D exploration
and development
programs before
revisions 10,920 343 31.84 420 26.00
------------------------------------------------------------------------
------------------------------------------------------------------------
F&D exploration
and development
program after
revisions (a) 10,920 572 19.09 588 18.57
------------------------------------------------------------------------
------------------------------------------------------------------------
Change in proved
future development
capital (b) 178 n/a n/a n/a n/a
------------------------------------------------------------------------
Change in proved
plus probable
future development
capital (c) 288 n/a n/a n/a n/a
------------------------------------------------------------------------
Proved F&D
including change
in future
development
capital
(d)equals(a+b) 11,098 572 19.40 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus
probable F&D
including change
in future
development
capital
(e)equals(a+c) 11,208 n/a n/a 588 19.06
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition
activity (f) 19,584 840 23.31 1,149 17.04
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2004 FD&A
costs before
future development
costs (a+f) 30,504 1,412 21.60 1,737 17.56
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2004 proved
FD&A costs
including future
development costs
(d+f) 30,682 1,412 21.73 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2004 proved
plus probable FD&A
costs including
future development
costs (e+f) 30,792 n/a n/a 1,737 17.73
------------------------------------------------------------------------
------------------------------------------------------------------------


2003 Finding & Development (F&D) and Net Acquisition (FD&A) Costs

Proved
plus Proved
Proved Probable plus
Capital Reserve Proved Reserve Probable
Expenditures Additions Costs Additions Costs
------------------------------------------------------------------------
($ thousands) (mboe) ($/boe) (mboe) ($/boe)
F&D exploration
and development
programs before
revisions 383 - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------
F&D exploration
and development
program after
revisions (a) 383 - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------
Change in proved
future development
capital (b) n/a n/a n/a n/a n/a
------------------------------------------------------------------------
Change in proved
plus probable
future development
capital (c) n/a n/a n/a n/a n/a
------------------------------------------------------------------------
Proved F&D
including change
in future
development
capital
(d)equals(a+b) 383 - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus
probable F&D
including change
in future
development
capital
(e)equals(a+c) 383 - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition
activity (f) 7,010 1,121 6.25 1,408 4.98
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 FD&A
costs before
future development
costs (a+f) 7,393 1,121 6.60 1,408 5.25
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 proved
FD&A costs
including future
development costs
(d+f) 7,393 1,121 6.60 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 proved
plus probable FD&A
costs including
future development
costs (e+f) 7,393 n/a n/a 1,408 5.25
------------------------------------------------------------------------
------------------------------------------------------------------------


Combined 2003 and 2004 Finding & Development (F&D) and Net Acquisition
(FD&A) Costs

It should be noted that the Masters Energy Inc. commenced operations
December 22, 2003 with the acquisition of the Little Bow property in
Southern Alberta. The combined 2003 and 2004 results are more
representative of managements efforts and therefore is presented in the
table below.



Proved
plus Proved
Proved Probable plus
Capital Reserve Proved Reserve Probable
Expenditures Additions Costs Additions Costs
------------------------------------------------------------------------
($ thousands) (mboe) ($/boe) (mboe) ($/boe)
F&D exploration
and development
programs before
revisions 11,303 343 32.95 420 26.91
------------------------------------------------------------------------
------------------------------------------------------------------------
F&D exploration
and development
program after
revisions (a) 11,303 572 19.76 588 19.22
------------------------------------------------------------------------
------------------------------------------------------------------------
Change in proved
future development
capital (b) 178 n/a n/a n/a n/a
------------------------------------------------------------------------
Change in proved
plus probable
future development
capital (c) 288 n/a n/a n/a n/a
------------------------------------------------------------------------
Proved F&D
including change
in future
development
capital
(d)equals(a+b) 11,481 572 20.07 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Proved plus
probable F&D
including change
in future
development
capital
(e)equals(a+c) 11,591 n/a n/a 588 19.71
------------------------------------------------------------------------
------------------------------------------------------------------------
Net acquisition
activity (f) 26,594 1,961 13.56 2,557 10.40
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 and 2004
FD&A costs
before future
development costs
(a+f) 37,897 2,533 14.96 3,145 12.05
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 and 2004
proved FD&A costs
including future
development costs
(d+f) 38,075 2,533 15.03 n/a n/a
------------------------------------------------------------------------
------------------------------------------------------------------------
Total 2003 and 2004
proved plus
probable FD&A
costs including
future development
costs (e+f) 38,185 n/a n/a 3,145 12.14
------------------------------------------------------------------------
------------------------------------------------------------------------


Reserve Replacement

The Company's 2004 exploration and development capital expenditure
program replaced production by a factor of 1.8 times on a proved basis
and 1.9 times on a proved and probable basis.



2004
------------------------------------------------------------------------
Production (mboe) 311
Proved reserve additions after revisions (mboe) 572
Proved replacement ratio 1.84
Proved plus probable reserve additions after revisions (mboe) 588
Proved plus probable replacement ratio 1.89


Drilling Results

During the 2004 year the Company drilled or recompleted 19 wells
resulting in 10 natural gas wells for an overall success rate of 53
percent.



(wells) Gross Net
------------------------------------------------------------------------

Natural Gas 10 6.4
Dry and abandoned 9 6.6
---------------------
Total 19 13.0
---------------------
---------------------
Success rate (%) 53 49
---------------------
---------------------


LIQUIDITY and CAPITAL RESOURCES

The Company's total capitalization at December 31, 2004 was $44.5
million with the market value of common shares representing 84 percent
of total capitalization. Net debt represented nine percent and asset
retirement obligations and future income taxes accounted for eight
percent.



Total Market Capitalization

($ thousands except per share amounts) 2004 %
------------------------------------------------------------------------
Common shares outstanding (thousands) 14,364
Share price, December 31, 2004 2.60
---------------------
Total market capitalization 37,346 84
---------------------
Working capital deficiency, excluding bank debt 692
Bank debt 3,424
---------------------
Net debt 4,116 9
---------------------
Asset retirement obligation 3,044 7
Future income taxes 30 -
---------------------
Total capitalization 44,536 100
---------------------
Net debt to total capitalization 9%
---------------------
---------------------


At December 31, 2004 the Company had borrowed approximately $3.4 million
and had a working capital deficit of $0.7 million totaling $4.1 million
of total net debt. This net debt amount represents approximately 0.7
times 2004 cash flow from operations of $5.6 million and approximately
0.4 times budgeted 2005 cash flow from operations.

The Company has a bank demand revolving facility of $8.5 million to fund
future activities. The facility is a borrowing base facility that is
determined by the Company's latest reserve assessment, results of
operations, current and forecasted commodity prices and the prevailing
economic market. The facility is reviewed annually in May of each year.
As at December 31, 2004, the Company had drawn $3.4 million of the
demand revolving facility and the amount is recorded as a current
liability.

The Company's future investing activities, which consist primarily of
capital expenditures on oil and gas activities, will be funded with
working capital, cash flow from operations and a limited amount of bank
debt.

SELECTED QUARTERLY INFORMATION

The financial data presented below has been prepared in accordance with
Canadian generally accepted accounting principles. The reporting and
measurement currency is the Canadian dollar. The Company commenced oil
and gas operations after acquiring the Little Bow property on December
22, 2003.



2004 2003
------------------------------------------------------------------------
Operations Q4 Q3 Q2 Q1 Q4
------------------------------------------------------------------------
Production
- Oil (bbl/d) 588 597 556 488 426
- NGL (bbl/d) 13 5 9 2 1
- Natural Gas (mcf/d) 2,406 1,980 1,653 800 171
- Equivalent (boe/d) 1,002 932 841 619 456
Pricing
- Oil, before hedging ($/bbl) 36.91 42.40 37.10 33.60 27.72
- Hedging costs (0.01) (4.25) - - -
------------------------------------------------------------------------
- Oil, after hedging ($/bbl) 36.90 38.15 37.10 33.60 27.72
- NGL ($/bbl) 50.72 40.20 36.86 45.11 43.34
- Natural Gas ($/mcf) 6.62 6.24 6.51 7.35 7.19
- Equivalent ($/boe) 38.09 37.90 37.95 35.82 28.70
------------------------------------------------------------------------
Financial
------------------------------------------------------------------------
($ thousands except share
and per share amounts)
Total revenue 3,501 3,258 2,922 2,028 131
Cash flow from operations 1,676 1,513 1,391 1,055 (67)
Net earnings (loss) (124) 79 (49) 521 (110)
- basic per share (0.01) 0.01 - 0.05 (0.03)
- diluted per share (0.01) 0.01 - 0.05 (0.03)
Capital spending
- Exploration and development 3,240 2,531 2,761 2,388 383
- Acquisitions - - - 20,174 7,010
Total assets 37,291 35,518 34,833 34,271 18,288
Working capital deficiency
(surplus) 4,116 2,551 1,533 163 (9,389)
Long-term debt - - - - -
Shareholders' equity 27,570 27,639 27,504 27,508 16,472
Weighted average common
shares outstanding (thousands)
- basic 14,364 14,364 14,364 10,987 3,813
- diluted 14,614 14,553 14,505 11,184 3,813


Factors that caused variations over the quarters -

- The Company completed two acquisitions since its initial financing in
the fourth quarter of 2003 which has impacted production growth:

-- The acquisition of the Little Bow property in Southern Alberta on
December 22, 2003 added approximately 450 boe per day consisting of
approximately 90 percent crude oil production. Proved and probable
reserves acquired were approximately 1.4 million boe with an estimated
reserve life index of 8.6 years.

-- The acquisition of Terraquest Energy Corporation on February 26, 2004
added production of approximately 400 boe per day consisting of
approximately 60 percent natural gas. Proved and probable reserves
acquired were approximately 1.1 million boe with an estimated reserve
life index of 7.9 years based on the production at the time of
acquisition.

- Production subsequent to the acquisitions is a result of the Company's
exploration and development activities. The timing of production is
subject to timing of drilling and facility construction.

- The growth in revenue and cash flow is the combination of increased
production and strong commodity prices. Generally commodity prices were
consistently strong throughout 2004 with WTI light quality crude
averaging $41.42(US) per bbl and AECO natural gas spot price of $6.87
per mcf. Oil prices for medium grade quality crude experienced a large
drop in the latter portion of the fourth quarter 2004 due to wider than
historical quality differentials. This impacted the prices received by
Masters during the fourth quarter of 2004 as a majority of the crude
production is of medium quality.

- The net earnings are influenced by depletion, depreciation, accretion
and future income taxes. The Company estimates its reserves every
quarter based on its acquisition and drilling activities. The annual
reserves are determined by independent reservoir engineers the results
of which can affect fourth quarter reserve additions. Future income
taxes have been impacted with the enacted changes to the federal and
provincial income tax rates for the oil and gas industry.

- Capital spending increased over the year with the development of
future drilling prospects. The capital spending was funded through cash
flow and bank debt.



FOURTH QUARTER ANALYSIS

% Change % Change
Q4 2004 Q4 2004
Q4 Q3 Q4 vs vs
2004 2004 2003 Q3 2004 Q4 2003
------------------------------------------------------------------------
Operations Results
Production
- Crude oil (bbls/d) 588 597 426 (2) 38
- NGL (bbls/d) 13 5 1 160 1,200
- Natural Gas (mcf/d) 2,406 1,980 171 21 1,307
- Equivalent (boe/d) 1,002 932 456 8 120
Pricing (after hedging)
- Crude oil ($/bbl) 36.90 38.15 27.72 (3) 33
- NGL ($/bbl) 50.72 40.20 43.34 26 17
- Natural gas ($/mcf) 6.62 6.24 7.19 6 (8)

Selected Financial Results
---------------------------
($ thousands except share
and per share amounts)
Total revenue 3,501 3,258 131 7 2,573
Royalties (647) (595) (24) 9 2,596
Operating expense (809) (889) (37) (9) 2,086
General and administrative (334) (266) (230) 26 45
Cash flow from operations 1,676 1,513 (67) 11 2,601
Depletion, depreciation
and accretion 1,309 1,275 39 3 3,256
Net earnings (loss) (124) 79 (110) (257) (13)
- basic per share (0.01) 0.01 (0.03) (200) 67
- diluted per share (0.01) 0.01 (0.03) (200) 67
Capital spending
- exploration and
development 3,240 2,531 383 28 746
- acquisitions - - 7,010 - (100)
Total capital spending 3,240 2,531 7,393 28 (57)
Working capital
deficiency (surplus) 4,116 2,551 (9,389) 61 144
Shareholders' equity 27,570 27,639 16,472 - 67
Weighted average common
shares outstanding
- basic 14,364 14,364 3,813 - 276
- diluted 14,614 14,553 3,813 1 283


PRODUCTION

Production volumes from the Terraquest properties have been included in
Masters' 2004 results from the date of amalgamation, February 26, 2004.
Production volume for the fourth quarter was 1,002 boe per day with a
production mix of 60 percent oil and NGL and the balance natural gas.
Production for the fourth quarter 2004 increased eight percent compared
to the third quarter and 120 percent compared to the fourth quarter of
2003. The production increase is a result of drilling activity in the
third quarter and the acquisition of Terraquest in February 2004.

REVENUES

Oil and natural gas revenues for the fourth quarter 2004 totaled $3.5
million, up seven percent from the third quarter as commodity prices
remained strong and production volumes continued to increase. The
revenues for the fourth quarter of 2003 were from the date of acquiring
the Little Bow property on December 22, 2003 until year-end.

ROYALTIES

Royalties for the fourth quarter of 2004 increased nine percent to $0.6
million over the third quarter 2004. Average royalty rate relative to
resource revenues has remained constant at 18 percent for 2004 and 2003.
The majority of royalty expense incurred during the quarter were payable
to the Crown. Royalties for the fourth quarter 2004 were $7.02 per boe
in comparison to $6.94 per boe for the third quarter 2004 and $5.20 per
boe for the fourth quarter of 2003.

OPERATING EXPENSES

Operating expenses for the fourth quarter of December 31, 2004 decreased
nine percent to $0.8 million from the third quarter 2004 expense of $0.9
million. Operating expenses for the fourth quarter averaged $8.78 per
boe compared to an average cost of $10.38 per boe for the third quarter
2004 and $8.13 per boe for the fourth quarter of 2003. The operating
expenses were higher than anticipated in the third quarter of 2004 due
to well servicing, plant turnaround and annual maintenance activities
carried out during the summer. Operating costs are forecast to average
approximately $8.50 per boe during 2005.

GENERAL and ADMINISTRATIVE

The fourth quarter 2004 net general and administrative expense increased
26 percent to $0.3 million from the third quarter 2004 and 45 percent
from the fourth quarter of 2003. General and administrative expenses
averaged $3.62 per boe for the fourth quarter compared to $3.10 per boe
in the third quarter of 2004 and $50.58 per boe in the fourth quarter
2003. The 2004 fourth quarter general and administrative expenses
include annual provisions for the annual audit and reserve reports.
General and administrative expenses for 2005, including a non-cash
provision for future stock based compensation of approximately $0.2
million, are forecast to be approximately $2.10 per boe.

DEPLETION, DEPRECIATION and ACCRETION

Depletion, depreciation and accretion expense for the fourth quarter of
2004 was $1.3 million compared to $1.3 million for the third quarter of
2003 and $39 thousand for the fourth quarter 2003. The depletion,
depreciation and accretion provision for the fourth quarter was $14.27
per boe compared to $14.88 per boe in the third quarter of 2004 and
$8.60 per boe for the fourth quarter of 2003. The depletion rate per boe
for the fourth quarter of 2004 was down due to year end adjustments for
reserves. The increase in the depletion rate since the fourth quarter of
2003 was due to the acquisition of Terraquest in February 2004 and the
exploration and development activities throughout 2004.

INCOME TAXES

The future income tax provision for the fourth quarter of 2004 was $0.5
million compared to $0.1 million for the third quarter of 2004 and a
combined future income tax and capital tax recovery of $28,000 for the
fourth quarter of 2003. The provision for the 2004 fourth quarter
increased as result of matching future forecasted cash flows, determined
by the independent reservoir engineers, to the changes in corporate
federal income tax rates over the next few years.

NET EARNINGS

Net loss after future taxes for the fourth quarter of 2004 was $0.1
million compared to earnings of $0.1 million for the third quarter of
2004 and a loss of $0.1 million during the fourth quarter of 2003. The
change in net earnings is mainly due to higher production and commodity
prices.

CAPITAL EXPENDITURES

During the fourth quarter of 2004 the Company spent $3.2 million on
exploration and development capital including $0.5 in land, $0.3 million
in seismic, $1.8 million in drilling and completions and $0.7 million in
facilities. During the quarter the company drilled four wells resulting
in one gas well; acquired 2,920 (1,351 net) acres of undeveloped land;
and at the Little Bow property, completed an independent reservoir
simulation study and shot a 3D seismic program over exploration acreage.

Capital spending during the fourth quarter was $3.2 million compared to
$2.5 million in the third quarter of 2004 and $7.4 million in the fourth
quarter of 2003. During the fourth quarter of 2003 the Company acquired
the Little Bow property for $7.0 million.



RESERVES DATA

Reserves Data - Constant Prices and Costs

Summary of oil and gas reserves and net present values of future net
revenues as of December 31, 2004.

RESERVES
----------------------------------
LIGHT
AND NATURAL
MEDIUM GAS NATURAL
OIL LIQUIDS GAS BOE
------------------------------------------------------------------------
RESERVES Gross Gross Gross Gross
CATEGORY (mbbl) (mbbl) (mmcf) (mboe)
------------------------------------------------------------------------

PROVED
Developed Producing 1,318 12 3,252 1,872
Developed Non-Producing 40 12 1,627 323
Undeveloped - - - -
----------------------------------
TOTAL PROVED 1,358 24 4,879 2,195

PROBABLE 336 8 1,573 607
----------------------------------

TOTAL PROVED PLUS PROBABLE 1,695 32 6,452 2,802
----------------------------------
----------------------------------


NET PRESENT VALUES OF FUTURE NET REVENUE
------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
------------------------------------------
RESERVES
CATEGORY 0 5 10 15 20
------------------------------------------------------------------------
($ millions)
PROVED
Developed Producing 26.4 22.8 20.0 17.9 16.2
Developed Non-Producing 7.4 6.5 5.8 5.3 4.8
Undeveloped - - - - -
------------------------------------------
TOTAL PROVED 33.8 29.3 25.8 23.1 21.0

PROBABLE 10.9 8.0 6.2 4.9 4.1
------------------------------------------

TOTAL PROVED PLUS PROBABLE 44.7 37.3 32.0 28.1 25.1
------------------------------------------
------------------------------------------


Reserves Data - Forecast Prices and Costs

Summary of oil and gas reserves and net present values of future net
revenue as of December 31, 2004.

RESERVES
----------------------------------
LIGHT
AND NATURAL
MEDIUM GAS NATURAL
OIL LIQUIDS GAS BOE
------------------------------------------------------------------------
RESERVES Gross Gross Gross Gross
CATEGORY (mbbl) (mbbl) (mmcf) (mboe)
------------------------------------------------------------------------

PROVED
Developed Producing 1,342 12 3,261 1,898
Developed Non-Producing 41 12 1,630 325
Undeveloped - - - -
------------------------------------------
TOTAL PROVED 1,383 24 4,892 2,222


PROBABLE 342 8 1,571 611
------------------------------------------

TOTAL PROVED PLUS PROBABLE 1,725 32 6,463 2,834
------------------------------------------
------------------------------------------


NET PRESENT VALUES OF FUTURE NET REVENUE
------------------------------------------
BEFORE INCOME TAXES DISCOUNTED AT (%/year)
------------------------------------------
RESERVES
CATEGORY 0 5 10 15 20
------------------------------------------------------------------------
($ millions)
PROVED
Developed Producing 32.2 28.8 24.5 21.9 19.9
Developed Non-Producing 6.7 5.9 5.3 4.8 4.4
Undeveloped - - - - -
------------------------------------------
TOTAL PROVED 38.9 33.7 29.8 26.7 24.3

PROBABLE 11.9 8.4 6.3 5.0 4.1
------------------------------------------

TOTAL PROVED PLUS PROBABLE 50.7 42.2 36.1 31.7 28.4
------------------------------------------
------------------------------------------


Summary of pricing and inflation rate assumptions as of December 31,
2004.

FORECAST PRICES AND COSTS

OIL
--------------------------------
Edmonton
Edmonton Bow River NATURAL
WTI Par Price Medium NATURAL GAS
Cushing 40 degrees 25 degrees GAS AECO LIQUIDS
Oklahoma API API Gas Price Mix
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/GJ)($Cdn/BBL)
--------------------------------------------------------------

Forecast
2005 42.00 49.60 37.00 6.45 37.20
2006 39.50 46.60 37.10 6.20 35.10
2007 37.00 43.50 34.60 6.05 33.00
2008 35.00 41.10 32.70 5.80 31.20
2009 34.50 40.50 32.20 5.70 30.80
2010 34.30 40.20 32.00 5.60 30.50
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr

Summary of pricing assumptions as of December 31, 2004.
Constant prices and costs.

OIL
--------------------------------
NATURAL Edmonton
Edmonton Bow River GAS NATURAL
WTI Par Price Medium Alberta GAS
Cushing 40 degrees 25 degrees Average LIQUIDS EXCHANGE
Oklahoma API API Gas Price Mix RATE
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu) ($Cdn/BBL)($US/$Cdn)
------------------------------------------------------------------------

Historical
2005+ 43.45 46.51 25.03 6.62 35.30 0.8319


Reconciliations of Changes in Gross Reserves by Principal Product Type

LIGHT AND MEDIUM OIL
------------------------------
Proved
Plus
Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl)
------------------------------------------------------------------------

December 31 2003 1,027 262 1,289

Extensions - - -
Improved Recovery - - -
Technical Revisions 216 (39) 177
Discoveries 15 3 18
Acquisitions 330 116 446
Dispositions - - -
Economic Factors - - -
Production (204) - (204)
------------------------------

December 31, 2004 1,383 342 1,725
------------------------------
------------------------------

NATURAL GAS LIQUIDS
------------------------------
Proved
Plus
Proved Probable Probable
FACTORS (mbbl) (mbbl) (mbbl)
------------------------------------------------------------------------

December 31 2003 - 1 1

Extensions - - -
Improved Recovery - - -
Technical Revisions (28) 1 (27)
Discoveries 39 - 39
Acquisitions 16 6 18
Dispositions - - -
Economic Factors - - -
Production (3) - (3)
------------------------------

December 31, 2004 24 8 32
------------------------------
------------------------------

ASSOCIATED AND NON-ASSOCIATED GAS
---------------------------------
Proved
Plus
Proved Probable Probable
FACTORS (mmcf) (mmcf) (mmcf)
------------------------------------------------------------------------

December 31 2003 561 145 706

Extensions - - -
Improved Recovery - - -
Technical Revisions 252 (133) 139
Discoveries 1,734 438 2,172
Acquisitions 2,970 1,121 4091
Dispositions - - -
Economic Factors - - -
Production (625) - (625)
------------------------------

December 31, 2004 4,892 1,571 6,463
------------------------------
------------------------------


Masters Energy Inc.
Balance Sheets
As at December 31,
------------------------------------------------------------------------
($ thousands) 2004 2003

Assets
Current assets
Cash and cash equivalents $ - $ 9,515
Accounts receivable 2,116 172
Prepaid expenses and deposits 415 49
----------------------
2,531 9,736

Property and equipment (note 4) 34,760 8,552
----------------------
$ 37,291 $ 18,288
----------------------
----------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 3,223 $ 346
Bank debt (note 5) 3,424 -
----------------------
6,647 346
Asset retirement obligations (note 6) 3,044 1,198
Future income taxes (note 10) 30 271
----------------------
9,721 1,815
----------------------
Shareholders' Equity
Share capital and warrants(note 7) 27,042 16,545
Contributed surplus (note 8) 210 38
Retained earnings (deficit) 318 (110)
----------------------
27,570 16,473
----------------------
$ 37,291 $ 18,288
----------------------
----------------------

See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Earnings (Loss) and Retained Earnings (Deficit)
For the year ended December 31, 2004 and the period August 28, 2003 to
December 31, 2003
------------------------------------------------------------------------
($ thousands except share and per share amounts) 2004 2003

Revenue
Petroleum and natural gas sales $ 11,709 $ 192
Royalties, net of Alberta Royalty Tax Credit (2,110) (24)
------------------------
9,599 168
------------------------
Expenses
Operating 2,853 37
General and administrative 1,077 230
Interest 112 -
Depletion, depreciation and accretion 4,467 39
------------------------
8,509 306
------------------------
Earnings (loss) before income taxes 1,090 (138)
Capital taxes (note 10) - 6
Future income taxes (reduction) (note 10) 662 (34)
------------------------
662 (28)
------------------------
Net earnings (loss) 428 (110)
Retained earnings (deficit), beginning of period (110) -
------------------------
Retained earnings (deficit), end of period $ 318 $ (110)
------------------------
------------------------
Earnings (loss) per share - basic and diluted
(note 9) $ 0.03 $ (0.03)
------------------------
------------------------
Weighted average number of shares outstanding
Basic 13,521,707 3,812,834
------------------------
------------------------
Diluted 13,716,226 3,812,834
------------------------
------------------------

See accompanying notes to the financial statements.


Masters Energy Inc.
Statements of Cash Flows
For the year ended December 31, 2004 and the period August 28, 2003 to
December 31, 2003
------------------------------------------------------------------------
($ thousands) 2004 2003

Operating activities
Net earnings (loss) $ 428 $ (110)
Add (deduct) non-cash items
Depletion, depreciation and accretion 4,467 39
Asset retirement expenditures (95) -
Future income tax expense (reduction) 662 (34)
Stock-based compensation expense 172 38
------------------------
5,634 (67)
Changes in non-cash working capital 731 (142)
------------------------
6,365 (209)
------------------------
Financing activities
Proceeds on share issue - 16,850
Repayment of bank loan (note 1) (7,032) -
------------------------
(7,032) 16,850
Changes in non-cash working capital 3,424 146
------------------------
(3,608) 16,996
------------------------
Investing activities
Property and equipment (10,920) (7,393)
Costs related to the acquisition of
Terraquest (note 1) (295) -
------------------------
(11,215) (7,393)
Changes in non-cash working capital (1,057) 121
------------------------
(12,272) (7,272)

Increase (decrease) in cash (9,515) 9,515

Cash and cash equivalents, beginning of period 9,515 -
------------------------

Cash and cash equivalents, end of period $ - $ 9,515
------------------------
------------------------

Supplemental Cash Flow Information
Interest income received $ 28 $ 55
Interest paid $ 56 -
Capital taxes paid $ 34 -
------------------------------------------------------------------------

See accompanying notes to the financial statements.


Masters Energy Inc.
Notes to the Financial Statements
For the year ended December 31, 2004 and the period August 28, 2003 to
December 31, 2003
(Tabular amounts in $ thousands except share and per share amounts)
------------------------------------------------------------------------


1. Description of the Company and business combination

On February 26, 2004, Masters Energy Inc. ("the Company"), a private
company incorporated under the Alberta Business Corporations Act on
August 28, 2003 and Terraquest Energy Corporation, a public company
listed on the Toronto Stock Exchange, amalgamated and the combined
company ("Amalco") continued under the name and management of Masters
Energy Inc. The transaction saw Terraquest shareholders receive one
Amalco Common Share for every 12 common shares of Terraquest and Masters
shareholders receive one Amalco Common Share for every 2 common shares
or special warrants of Masters. After giving effect to the transaction,
Amalco had approximately 14.4 million Common Shares outstanding, of
which former Masters' securityholders owned approximately 62 percent and
former Terraquest shareholders owned approximately 38 percent. The name
of the combined company is "Masters Energy Inc.". The comparative
figures are those of Masters Energy Inc.

The business combination has been accounted for using the purchase
method as a reverse takeover of Terraquest by the Company and earnings
of Terraquest are recognized from the closing date of February 26, 2004.

The Terraquest purchase was valued based on the discounted proved plus
probable reserves acquired as determined by an independent reserves
evaluation. Land cost values were estimated by Masters staff. The share
consideration value of acquiring Terraquest was based on Masters common
share fair value at the date of amalgamation. The purchase price was
allocated as follows:



Property and equipment $ 19,584
Future tax asset 903
Working capital deficiency (694)
Fair value of hedging commitment (199)
Bank debt (7,032)
Asset retirement obligations (1,770)
-----------------
$ 10,792
-----------------
-----------------

Purchase price
Share consideration $ 10,497
Acquisition costs 295
-----------------
$ 10,792
-----------------
-----------------


The Company is engaged in the exploration, development and production of
petroleum and natural gas in Western Canada.

2. Significant accounting policies

(a) Basis of presentation

The financial statements are stated in Canadian dollars and have been
prepared in accordance with Canadian generally accepted accounting
principles.

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that effect the reported amounts of assets and liabilities
at the date of the financial statements and the reported amounts of
revenues and expenses during the period. Actual results could differ
from those estimates.

(b) Cash and cash equivalents

Cash and cash equivalents consisted of amounts on deposit with banks and
term deposits with original maturities of less than 90 days.

(c) Property and equipment

The Company follows the full cost method for accounting for petroleum
and natural gas operations whereby all costs related to the exploration
for and the development of petroleum and natural gas reserves are
capitalized. Costs capitalized include land acquisition costs,
geological and geophysical expenditures, rentals on undeveloped
properties, costs of drilling productive and non-productive wells,
together with overhead directly related to exploration and development
activities and production and well equipment.

Costs capitalized together with future capital costs are depleted and
depreciated using the unit-of-production method based upon gross proved
petroleum and natural gas reserves as determined by independent
qualified reserves evaluators at future prices and costs. Production and
reserves of petroleum and natural gas are converted to common units of
measure based on their relative energy content, where one barrel of oil
is equivalent to six thousand cubic feet of natural gas.

The cost of significant unproved properties are excluded from the
depletion and depreciation base until it is determined whether proved
reserves are attributable to the properties, or impairment has occurred.

The Company performs a ceiling test for impairment for each cost centre
in a two-stage test undertaken at least annually.

(i) Impairment is recognized if the carrying value of the petroleum and
natural gas properties, less accumulated depletion and depreciation,
exceeds the estimated future cash flows from proved oil and natural gas
reserves, on an undiscounted basis, using forecast prices and costs and
the lower of cost and fair value of unproven properties. Future cash
flows are calculated before interest, general and administrative
expenses and income taxes.

(ii) If impairment is indicated by applying the calculations described
in (i) above, the Company will measure the amount of the impairment by
comparing the carrying value of the petroleum and natural gas properties
less accumulated depletion and depreciation to the estimated future cash
flows from the proved and probable oil and natural gas reserves,
discounted at a risk-free rate of interest, using forecast prices and
costs and the lower of cost and fair value of unproven properties. Any
impairment recognized is recorded as additional depletion and
depreciation expense.

Gains or losses are not recognized upon disposition of petroleum and
natural gas properties unless such a disposition would alter the rate of
depletion and depreciation by 20% or more.

The costs of corporate and other office equipment are amortized at rates
approximating their useful life on a declining balance basis of 30
percent per year.

(d) Joint ventures

Substantially all of the Company's exploration and production activities
are conducted jointly with others and, accordingly, these financial
statements reflect only the Company's proportionate interest in such
activities.

(e) Asset retirement obligations

The Company recognizes the liability for retirement obligations
associated with the abandonment of petroleum and natural gas wells,
related facilities, compressors and plants, removal of equipment from
leased acreage and returning such land to its original condition. The
fair value of each asset retirement obligation is recorded in the period
a well or related asset is drilled, constructed or acquired. Fair value
is estimated using the present value of the estimated future cash
outflows to abandon the asset at the Company's credit-adjusted risk-free
interest rate. The obligation is reviewed regularly by Company
management based on current regulations, costs, technologies and
industry standards. The discounted obligation is initially capitalized
as part of the carrying amount of the related oil and natural gas
properties, and a corresponding liability is recognized. This component
of the increase in petroleum and natural gas properties is depleted and
depreciated on the same basis as the remainder of the petroleum and
natural gas properties. The liability is adjusted for accretion charged
to income until the obligation is settled or sold and for revisions to
the estimated cash flows. Actual costs incurred upon settlement of the
obligations are charged against the liability.

(f) Flow-through shares

From time to time, the Company issues flow-through shares to finance a
portion of its capital expenditure program. Pursuant to the terms of the
flow-through share agreements, the tax deductions associated with the
expenditures are renounced to the subscribers. Accordingly, share
capital is reduced and a future tax liability is recorded equal to the
estimated amount of future income taxes payable by the Company as a
result of the renunciations, when the expenditures are renounced.

(g) Stock-based compensation

The Company issues stock options and performance warrants to directors,
officers, employees and other service providers. Compensation cost,
attributable to stock options and performance warrants granted, is
measured by the fair value method of accounting at the date of grant and
expensed over the vesting period with a corresponding increase in
contributed surplus. When stock options or performance warrants are
exercised, the cash proceeds together with the amount previously
recorded as contributed surplus are recorded as share capital. The
Company does not incorporate an estimated forfeiture rate for stock
options and performance warrants that will not vest, but accounts for
forfeitures as they occur.

(h) Revenue recognition and operating expenses

Revenue from the sale of oil and natural gas is recognized based on
volumes delivered to customers at contractual delivery points and rates.
The costs associated with the delivery, including operating and
maintenance costs, transportation and production-based royalty expenses
are recognized in the same period in which the related revenue is earned
and recorded.

(i) Income taxes

Future income taxes are accounted for using the liability method of
income tax allocation. Under the liability method, income tax assets and
liabilities are recorded to recognize future tax income inflows and
outflows arising from the settlement or recovery of assets and
liabilities at the carrying values. Income tax assets are also
recognized for the benefits from tax losses and deductions that cannot
be identified with particular assets or liabilities, provided those
liabilities are more likely than not to be realized. Future income tax
assets and liabilities are determined based on the income tax laws and
rates that are anticipated to apply in the period of reversal.

(j) Per share amounts

Basic per share amounts are calculated using the weighted average number
of common shares outstanding during the year. The Company utilizes the
treasury stock method for the calculation of diluted per share amounts.
This method assumes that the proceeds from the exercise of in-the-money
stock options and warrants plus the unamortized stock based compensation
are used to repurchase Company shares at the weighted average market
price during the period.

(k) Measurement uncertainty

The amounts recorded for depletion and depreciation of oil and gas
properties, the asset retirement obligation and the ceiling test are
based on estimates. These estimates include proved and probable
reserves, production rates, future petroleum and natural gas prices,
future costs and other relevant assumptions.

The amounts disclosed relating to the fair value of stock options and
performance warrants issued and the resulting income effect are based on
estimates of the future volatility of the Company's share price,
expected lives of the options, expected dividends and other relevant
assumptions.

By their nature, these estimates are subject to measurement uncertainty
and the effect on the financial statements of changes in such estimates
in future periods could be material.

(l) Financial instruments

The Company has a price risk management program whereby the commodity
price associated with a portion of its future production can be fixed.
The Company is able to sell forward a portion of its future production
through a combination of fixed price sale contracts with customers and
commodity swap agreements with financial counterparties. The forward and
future contracts are subject to market risk from fluctuating commodity
prices and exchange rates; however, gains or losses on the contracts are
offset by changes in the value of the Company's production and
recognized in income in the same period and category as the hedged item.

3. Change in Accounting Policy

Effective January 1, 2004, and consistent with the adoption of the new
Canadian accounting standard for generally accepted accounting
principles, transportation costs are presented as an operating expense
in the Statement of Earnings and Retained Earnings. The new standard
defines the sources of Generally Accepted Accounting Principles ("GAAP")
and effectively eliminates industry practice as a source of GAAP.
Previously, as was industry practice, transportation costs were deducted
from petroleum and natural gas revenue.



4. Property and equipment

Accumulated
Depletion
and Net Book
As at December 31, 2004 Cost Depreciation Value
------------------------------------------------------------------------

Petroleum and natural gas
properties and well equipment $ 39,052 $ 4,317 $ 34,735
Office equipment 42 17 25
------------------------------------------
$ 39,094 $ 4,334 $ 34,760
------------------------------------------
------------------------------------------

As at December 31, 2003

Petroleum and natural gas
properties and well equipment $ 8,550 $ 34 $ 8,516
Office equipment 41 5 36
------------------------------------------
$ 8,591 $ 39 $ 8,552
------------------------------------------
------------------------------------------


The value of undeveloped lands excluded from costs subject to depletion
was $5.5 million at December 31, 2004 ($nil - December 31, 2003).

As at December 31, 2004, $0.5 million ($nil - December 31, 2003) of
general and administrative costs were capitalized.

The benchmark and Company prices on which the December 31, 2004 ceiling
test for impairment is based, are as follows:



Oil Natural Gas Natural Gas Liquids
---------------------- -------------------- ---------------------
Bow River AECO
Medium Spot Edmonton
Benchmark Company Benchmark Company Benchmark Company
($/bbl) ($/bbl) ($/GJ) ($/mcf) ($/bbl) ($/bbl)

2005 $ 37.00 $ 37.37 $ 6.45 $ 6.63 $ 37.20 $ 41.59
2006 37.10 36.89 6.20 6.40 35.10 39.12
2007 34.60 33.99 6.05 6.38 33.00 39.63
2008 32.70 31.65 5.80 5.99 31.20 37.44
2009 32.20 30.73 5.70 5.83 30.80 35.76
2010 32.00 30.45 5.60 5.64 30.50 33.41


Prices increase at a rate of approximately 2 percent per year for oil,
natural gas and natural gas liquids after 2010. Adjustments were made to
the benchmark prices, for purposes of the ceiling test, to reflect
varied delivery points and quality differentials in the products
delivered.

5. Bank debt

The Company has access to a demand revolving credit facility with a
Canadian chartered bank to a maximum of $8.5 million. The facility may
be drawn down or repaid at any time and bears interest at prime plus 0.2
percent per annum. The credit will revolve until May 25, 2005, at which
time a review of the facility will occur.

The Company has available a $2.5(USD) million demand swap facility, to
assist in financing the contingent exposure of settlement for financial
commodity swaps. The facility bears interest at a US base rate plus 0.2
percent per annum on amounts drawn.

As of December 31, 2004, $3.4 million ($nil - December 31, 2003) has
been drawn against the revolving credit facility.

Security pledged for the facilities consists of a general assignment of
book debts, a $25.0 million demand debenture, secured by a first
floating charge over all the assets of the Company. The nature of the
lending facility is such that it is recognized as a current liability.
The Company is not in breach of any covenants under its credit facility.

6. Asset retirement obligation

The following table summarizes changes in the asset retirement
obligation for the years ended December 31, as indicated:



2004 2003
----------------------
Asset retirement obligation, beginning of period $ 1,198 $ -
Adjustments (119) -
Liabilities acquired 1,770 1,198
New drilling 119 -
Asset retirement expenditures (95) -
Accretion expense 171 -
----------------------
Asset retirement obligation, end of period $ 3,044 $ 1,198
----------------------
----------------------


The total estimated, undiscounted cash flows required to settle the
obligations, before considering salvage, is $4.4 million which has been
discounted using a weighted average credit-adjusted risk-free interest
rate of 6.90 percent. The Company expects these obligations to be
settled in approximately 1 to 14 years.



7. Share capital and warrants

(a) Authorized

Unlimited number of voting common shares, without nominal or
par value
Unlimited number of preferred shares, issuable in series, with
rights and privileges to be determined at the time of issuance
by the Board of Directors

(b) Issued

Number Amount
-------------------------
Common shares
Issued on incorporation 1 $ -
Special Warrants
Common special warrants issued pursuant
to private placements 16,002,000 16,002
Flow-through special warrants issued,
pursuant to private placements
(net of future taxes of $630,000) 1,750,000 1,120
-------------------------
17,752,001 17,122
Issuance costs (net of future taxes
of $325,000) - (577)
Warrants and Shares Balance,
December 31, 2003 17,752,001 16,545
Warrants and shares exchanged per
plan of arrangement (17,752,001) -
Issued to Masters Energy Inc. shareholders
on reverse takeover of Terraquest (Note 1) 8,876,000 -
Issued to Terraquest shareholders at
date of acquisition (Note 1) 5,487,647 10,497
-------------------------
Balance, December 31, 2004 14,363,647 $ 27,042
-------------------------
-------------------------


On October 28 and November 25, 2003, the Company closed private
placements of 16,002,000 common special warrants and 1,750,000
flow-through special warrants for gross proceeds of $17.8 million. Both
the common special warrants and flow-through special warrants were
issued at $1.00 per special warrant, were convertible to common shares
at a rate of one warrant to one common share at no additional cost upon
either demand, or the Company obtaining a public listing. If the
Company's shares were not listed on a public exchange within one year of
issuance, the warrants would be automatically converted at a rate of one
warrant for 1.1 common shares. The Company has renounced expenditures
relating to the 1,750,000 flow-through special warrants effective
December 31, 2003. All of the required expenditures were incurred during
2004. Effective February 26, 2004, all special warrants were converted
into common shares.

(c) Terraquest flow - through share program

The Company was required to incur $1.8 million of qualifying
expenditures during the balance of 2004 to fulfill the obligations of a
Terraquest flow-though share program entered into in 2003. All of the
required expenditures were incurred during 2004.

8. Stock-based compensation plans

On February 26, 2004, the Company's stock - based compensation plans
were revised to conform with the one for two share consolidation related
to the acquisition of Terraquest Energy Corporation. This had the effect
of halving the number of options and warrants that had been issued and
doubling their exercise price. The plans are described below:

(a) Stock options

The Company's stock option plan allows for options to be granted to
employees, officers, directors and other service providers. The number
of shares which may be issued, and that have been reserved, under the
plan is 1,435,042 common shares. The maximum number of shares that may
be reserved for issuance to any one person under the plan is limited to
5 percent per year of the issued and outstanding Common Shares and
Special Warrants for employees, officers and directors and 2 percent for
other service providers. The plan also provides that the price at which
options may be granted cannot be less than the market price of the
common shares at the date of grant. Options granted under the plan have
a maximum life of 5 years and vest at an equal amount over three years
on the anniversary date of the grant or as determined by the Board of
Directors.

The following tables summarizes information about the Company's stock
options outstanding at December 31, 2004:



Weighted Average
Number of Options Exercise Price ($)
----------------------------------------
Balance, December 31, 2003 575,000 2.00
Granted, April 26, 2004 655,000 2.35
Granted, December 23, 2004 25,000 2.60
--------------------
Balance, December 31, 2004 1,255,000 2.19
--------------------
--------------------


Weighted Average
Exercise Price per Share ($) Options Outstanding Years to Expiry
----------------------------------------
2.00 575,000 4.0
2.35 655,000 4.3
2.60 25,000 5.0
--------------------
2.00 - 2.60 1,255,000 4.2
--------------------
--------------------


As of December 31, 2004, 191,667 stock options have vested at an
exercise price of $2.00 per option and none of the vested options have
been exercised.

The Company has recorded compensation expense of $0.2 million as at
December 31, 2004, ($37,000 - December 31, 2003) for options and
warrants vested during the period. Using the Black-Scholes model,
assuming the expected life of the options and warrants are 5 years and
no expected future dividends, the following table summarizes the total
fair value of options and warrants granted.



Options and Risk-free
Warrants Expected Interest Total Fair
Grant Date Granted Volatility Rate Value
------------------------------------------------------------------------
(%) (%) ($ thousands)

December 23, 2004 25,000 33 3.40 21
April 26, 2004 655,000 26 3.40 455
December 22, 2003 1,575,000 nil 3.95 207


(b) Performance warrants

The Company's Performance Warrants Plan allows for Performance Warrants
to be granted to employees, officers and directors. The maximum number
of shares which may be issued, and that have been reserved, under the
plan is 1,000,000 common shares. Performance Warrants granted under the
plan have a five year life, vest immediately and have no performance
criteria other than the escalating exercise price. All 1,000,000
Performance Warrants have been granted, expiring December 22, 2008, with
the following exercise prices:



Performance Average Exercise
Warrants Price per
Outstanding Warrant ($)
---------------------------------------
100,000 2.00
100,000 2.50
150,000 3.00
150,000 3.50
250,000 4.00
250,000 4.50
--------------
1,000,000 3.55
--------------
--------------


No performance warrants were exercised during the reporting period.

9. Per share amounts

Earnings per share has been calculated using the basic weighted average
number of common shares outstanding of 13,521,707 (3,812,834 - 2003)
during the year ended December 31, 2004. As at December 31, 2004, a
total of 194,519 (nil - 2003) were added to the total to take into
account the dilutive effect of the options for the year. For comparative
reporting purposes the 2003 weighted average number of shares indicate
the consolidation effect on the common shares that resulted from the
acquisition of Terraquest Energy Corporation.

10. Taxes

(a) The provision for income tax expense differs from that which would
be expected from applying the combined effective Canadian federal and
provincial income tax rate of 38.62% (40.62% - 2003) to income before
income taxes. The difference results from the following:




2004 2003
----------------------
Expected income tax expense (reduction) $ 423 $ (56)

Increase (decrease) resulting from:
Non-deductible crown payments 565 9
Resource allowance (480) (8)
Change in effective tax rate applied (111) 6
Stock based compensation expense 67 15
Other 198 -
Capital tax - 6
----------------------
Total tax expense (reduction) $ 662 $ (28)
----------------------
----------------------


(b) The components of the future income tax liability at December 31 are
as follows:
2004 2003
----------------------
Carrying value of property and equipment
in excess of available tax deductions $2,141 $ 1,108
Asset retirement obligation (987) (402)
Non-capital loss carryforwards (640) (133)
Share issuance costs (484) (302)
----------------------
$ 30 $ 271
----------------------
----------------------


11. Commitments

As at December 31, 2004, the Company is committed under a lease on its
office premises expiring August 2005 for future annual minimum rental
payments excluding estimated operating costs of $30,000.

12. Financial instruments

(a) Fair values

The fair values of the Company's accounts receivable, accounts payable
and accrued liabilities and bank debt approximate their carrying values
due to their short-term maturity.

(b) Credit risk

The Company's credit risk is limited to the carrying amount of its
accounts receivable, which are due primarily from other entities
involved in the oil and gas industry. These amounts are subject to the
same risks as the industry as a whole.

(c) Interest rate risk

The Company is exposed to interest rate risk to the extent the changes
in market interest rates will impact the Company's debts that have a
floating interest rate.

13. Related party transactions

During the year ended December 31, 2004, the Company incurred legal fees
related to general corporate administration and the acquisition of
Terraquest of $0.2 million ($0.1 million - December 31, 2003) to a law
firm in which a director of the Company is a partner. This transaction
has been recorded at the exchange amount, which is the amount agreed to
by the parties.

Masters Energy Inc. is an Alberta based corporation engaged in the
business of acquiring or exploring for and developing oil and natural
gas reserves in western Canada. Masters' common shares are listed on the
Toronto Stock Exchange under the trading symbol "MSY".

ADVISORY

The Toronto Stock Exchange has neither approved nor disapproved of the
information contained herein. Certain information regarding the Company,
including management's assessment of future plans and operations, may
constitute forward-looking statements under applicable securities law
and necessarily involve risks associated with oil and gas exploration,
production, marketing and transportation such as loss of market,
volatility of prices, currency fluctuations, impression of reserve
estimates, environmental risks, competition from other producers and
ability to access sufficient capital from internal and external sources:
as a consequence, actual results may differ materially from those
anticipated. The Company assumes no obligation to update the
forward-looking statements or to update the reasons why actual results
could differ from those contemplated by the forward-looking statements.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Masters Energy Inc.
    Geoff Merritt
    President and CEO
    (403) 290-1785
    or
    Masters Energy Inc.
    Randall Boyd
    Chief Financial Officer
    (403) 290-1785
    Website: www.mastersenergy.com