Grey Wolf Exploration Inc.

Grey Wolf Exploration Inc.

March 30, 2005 16:18 ET

Grey Wolf Reports Significant Advancements in 2004 Year End Results and Updates 2005 Drilling Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: GREY WOLF EXPLORATION INC.

TSX SYMBOL: GWE

MARCH 30, 2005 - 16:18 ET

Grey Wolf Reports Significant Advancements in 2004
Year End Results and Updates 2005 Drilling Results

CALGARY, ALBERTA--(CCNMatthews - March 30, 2005) -

NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN
THE UNITED STATES

Dollar amounts shown are in Canadian currency unless otherwise stated.

Grey Wolf Exploration Inc. (TSX:GWE) ("Grey Wolf") is pleased to report
its operating and financial results for the year ended December 31,
2004. Highlights are as follows:



Highlights (audited) 2004 2003 Change
------------------------------
Financial (thousands,
except per share amounts)
Crude oil and natural gas revenue $ 23,943 $ 8,942 +168%
Cash flow from operations 12,696 3,498 +263%
Per share - basic and fully diluted 0.98 0.31 +216%
Net earnings (loss) 3,283 (135)
Per share - basic and fully diluted 0.25 (0.01)
Capital expenditures 14,760 12,792 +15%
Total assets 63,416 52,287 +21%

Operating
Production
Crude oil (barrels per day) 121 90 +34%
Natural gas (Mcf per day) 8,171 2,595 +215%
NGLs (barrels per day) 153 36 +325%
Barrels of oil equivalent per day 1,636 559 +193%


2005 Drilling Update

Grey Wolf also reports today that it has recently completed the drilling
of three wells:

Pouce Coupe 12-32-077-10 W6M (GWE 12.5% Working Interest) was
successfully drilled and cased for potential in the Montney and Doig
zones. The Montney zone was completed and fracture-stimulated and
initial flow test indicated commercial quantities of gas at a
preliminary rate of 910 Mcf per day, which is expected to stabilize at
approximately 400 to 500 Mcf per day. The completion of the well will
continue after Spring break up with the perforation, stimulation and
testing of the Doig zone. Pipeline operations have commenced to tie in
the well as a dual Montney/Doig producer.

Caroline 06-05-033-06 W5M (GWE 40% Working Interest - after completion)
was successfully drilled and cased as a potential Viking gas well. The
lower Viking interval was completed and fracture-stimulated and initial
flow test indicated commercial quantities of gas at a preliminary rate
of 950 Mcf per day, which is expected to stabilize at approximately 400
Mcf per day. A second upper Viking interval will be completed after
Spring break up. Pipeline operations have commenced to tie in the lower
Viking for production.

Caroline 16-03-034-07 W5M (GWE 38% Working Interest - after completion)
was successfully drilled and cased as a potential Cardium gas well. The
Cardium "B" interval was completed and fracture-stimulated with no
commercial gas observed. The lower Cardium "A" interval was completed,
fracture-stimulated and tested. This well was tied in and commenced
production on March 6 at a rate of 200 Mcf per day. The primary target,
and best pay zone in the well, the Upper Cardium "A", will be completed
at a later date.



Grey Wolf Exploration Inc.
Balance Sheets

As at December 31 2004 2003
------------------------------------------------------------------------
($ 000) ($ 000)
Assets

Current
Cash $ 835 $ 637
Accounts receivable 3,504 1,563
------------------------------
4,339 2,200

Deferred financing costs 2,311 -

Future income tax asset 1,976 4,076

Property and equipment 54,790 46,011
------------------------------
$ 63,416 $ 52,287
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current
Accounts payable and accrued
liabilities $ 6,346 $ 2,550
Due to parent company 1,256 9,420
Current portion of long term debt 2,111 -
------------------------------
9,713 11,970

Long term debt 40,106 -
Asset retirement obligation 2,075 816
------------------------------
51,894 12,786
------------------------------

Share capital (Note 8) 15,926 47,188
Deficit (4,404) (7,687)
------------------------------
11,522 39,501
------------------------------
$ 63,416 $ 52,287
------------------------------------------------------------------------
------------------------------------------------------------------------



Grey Wolf Exploration Inc.
Statements of Operations and Deficit

For the twelve For the initial
month period 390 day period
ended December ended December
$ 000 except per share amounts 31, 2004 31, 2003
------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales 23,943 $ 8,942
Royalties, net of royalty tax credits (3,894) (1,599)
------------------------------
20,049 7,343
------------------------------

Expenses
Depletion, depreciation and accretion 7,707 3,272
General and administrative 1,761 1,515
Production 4,113 1,145
Interest 915 (13)
Transportation 536 217
Settlement of legal dispute - 900
Amortization of deferred financing costs 80 -
------------------------------
15,112 7,036
------------------------------

Income before other income and
income taxes 4,937 307

Other income
Foreign exchange gain (loss) 456 (6)

------------------------------
Income before income taxes 5,393 301
------------------------------

Income taxes
Large corporation tax 10 75
Future 2,100 361
------------------------------
2,110 436
------------------------------

Net income (loss) for the period 3,283 (135)

Deficit, beginning of period (7,687) -

Excess of purchase price paid over
carrying value for purchase of the
Grey Wolf Properties - (7,552)
------------------------------
Deficit, end of period $ (4,404) $ (7,687)
------------------------------------------------------------------------
------------------------------------------------------------------------
Basic and diluted earnings
(loss) per share $ 0.25 $ (0.01)
Basic and diluted weighted average
number of shares outstanding 13,002,360 11,400,620
------------------------------------------------------------------------
------------------------------------------------------------------------

Grey Wolf Exploration Inc.
Statement of Cash Flows

For the twelve For the initial
month period 390 day period
ended December ended December
31, 2004 31, 2003
------------------------------------------------------------------------
Cash flows from operating activities ($ 000) ($000)
Net income (loss) for the period $ 3,283 $ (135)
Adjustments for:
Depletion, depreciation and accretion 7,707 3,272
Future income taxes 2,100 361
Amortization of deferred financing costs 80 -
Unrealized foreign exchange (gain) loss (474) -
------------------------------
12,696 3,498
Changes in non-cash working capital
related to operating items (870) 1,287
------------------------------
11,826 4,785
------------------------------

Cash flows from financing activities
Payment of reduction in stated capital (31,262) 10,138
Repayment to parent company (8,035) -
Advance from term loan 42,690 -
Deferred financing costs (2,391) -
------------------------------
1,002 10,138
------------------------------

Cash flows from investing activities
Purchases of property and equipment, net (14,760) (12,792)
Payment of purchase price adjustment - (2,189)
Changes in non-cash working capital
related to capital items 2,598 1,170
Site restoration incurred (468) (475)
------------------------------
(12,630) (14,286)
------------------------------

Increase in cash 198 637

Cash, beginning of period 637 -
------------------------------
------------------------------

Cash, end of period $ 835 $ 637
------------------------------
Supplementary cash flow information:

Interest paid $ 922 $ -
Income taxes paid $ - $ -

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


Notes to Financial Statements

December 31, 2004 and 2003

1. Nature of Operations

Grey Wolf Exploration Inc. ("the Company") is engaged primarily in the
exploration for and production of petroleum and natural gas reserves in
Western Canada. The Company was incorporated on December 6, 2002 and
acquired certain properties called the Grey Wolf Properties on January
23, 2003 and commenced operations. The Grey Wolf Properties were
recorded at their carrying values as they were purchased from two sister
companies (Note 3).

2. Summary of Significant Accounting Policies

The financial statements of the Company have been prepared by management
in accordance with Canadian generally accepted accounting principles.
The preparation of financial statements in conformity with Canadian
generally accepted accounting principles requires management to make
estimates and assumptions that affect the amounts reported in the
financial statements and accompanying notes. Actual results could differ
from those estimates. The financial statements have, in management's
opinion, been properly prepared using careful judgment with reasonable
limits of materiality and within the framework of the significant
accounting policies summarized below:

(a) Property and Equipment

The Company follows the full cost method of accounting for oil and gas
operations whereby all costs of exploring for and developing oil and gas
reserves are initially capitalized. Such costs include land acquisition
costs, geological and geophysical expenses, carrying charges on
non-producing properties, costs of drilling and overhead charges
directly related to acquisition and exploration activities.

Costs capitalized, together with the costs of production equipment, are
depleted and amortized on the unit-of-production method based on the
estimated gross proved reserves as determined by independent petroleum
engineers. Petroleum products and reserves are converted to a common
unit of measure, using 6 MCF of natural gas to 1 barrel of oil.

Costs of acquiring and evaluating unproved properties are initially
excluded from depletion calculations. These unevaluated properties are
assessed periodically to ascertain whether impairment has occurred. When
proved reserves are assigned or the property is considered to be
impaired, the cost of the property or the amount of the impairment is
added to costs subject to depletion calculations.

Proceeds from a sale of petroleum and natural gas properties are applied
against capitalized costs, with no gain or loss recognized, unless such
a sale would significantly alter the rate of depletion by more than 20%.
Alberta Royalty Tax Credits are netted against royalties paid.

The Company applies an impairment test ("ceiling test") to determine if
capitalized costs are not recoverable and exceed their fair value.
Capitalized costs are not recoverable if they are greater than the
estimated undiscounted cash flows from future production of proven
reserves plus the cost (net of impairment) of unproved properties.
Commodity prices used in calculating estimated cash inflows are based on
quoted benchmark prices in the futures market. Costs used in estimating
cash outflows are based on expected future production and other costs
and include abandonment and site restoration costs. An impairment loss
is recognized if capitalized costs are greater than their recoverable
amount. The impairment loss is measured as the amount by which
capitalized costs exceed the fair value of proved and probable reserves
plus the cost (net of impairment) of unproved properties. Fair value is
determined based on the present value of future cash flows, after
deducting abandonment and site restoration costs, discounted at a
risk-free interest rate. Any impairment loss is charged to earnings.

Office equipment is recorded at cost. Amortization is provided on a
declining balance basis at 20%.

(b) Joint Venture Operations

All of the Company's petroleum and natural gas exploration activities
are conducted jointly with others. These financial statements reflect
only the Company's proportionate interest in such activities.

(c) Future Income Taxes

The Company uses the liability method of tax allocation in accounting
for income taxes. Under this method, future tax assets and liabilities
are determined based on differences between financial reporting and tax
bases of assets and liabilities and measured using substantially enacted
tax rates and laws that will be in effect when the differences are
expected to reverse. Future tax assets are recognized when it is more
likely than not that these assets will be realized.

(d) Financial Instruments

The Company holds various forms of financial instruments. The nature of
these instruments and the Company's operations expose the Company to
commodity price, interest rate, foreign currency, and credit risks. The
Company manages its exposure to these risks by operating in a manner
that minimizes its exposure to the extent practical. Unless otherwise
disclosed the carrying values of the Company's financial instruments
approximates their carrying values.

(e) Measurement Uncertainty

The amounts recorded for depletion and amortization of petroleum and
natural gas properties and equipment and the provision for accretion of
asset retirement obligations are based on estimates. The ceiling test is
based on estimates of proved reserves, production rates, oil and gas
prices, future costs and other relevant assumptions. By their nature,
these estimates are subject to measurement uncertainty and the effect on
the financial statements of changes and estimates in future periods
could be significant.

The financial statements include accruals based on the Company's
interpretation of the terms of existing joint venture agreements. Due to
varying interpretations of the definition of terms in these agreements
the accruals made by management in this regard may be significantly
different from those determined by the Company's joint venture partners.
The effect on the financial statements resulting from such adjustments,
if any will be reflected prospectively.

The amounts recorded for future income tax assets is based on estimates.
By their nature, these estimates are subject to measurement uncertainty,
and the impact on the financial statements of future changes in such
estimates could be material.

(f) Per Share Amounts

Basic earnings per common share are computed by dividing earnings from
operations by the weighted average number of common shares outstanding
for the period. Diluted per share amounts reflect the potential dilution
that could occur if securities or other contracts to issue common shares
were exercised or converted to common shares. The treasury stock method
is used to determine the dilutive effect of stock options and other
dilutive instruments.

(g) Revenue Recognition

Revenues associated with the sale of commodities represent the Company's
share of petroleum production during the period (the entitlement
method). Differences between production and amounts sold are not
significant. Product inventories are valued at the lower of average cost
and net realizable value on a first-in, first-out basis.

(h) Foreign Currency

Foreign currency transactions are translated into Canadian dollars as
follows:

At the transaction date, each asset, liability, revenue and expense is
translated into Canadian dollars by the use of the exchange rate in
effect at that date. At the year end date, monetary assets and
liabilities are translated into Canadian dollars by using the exchange
rate in effect at that date. The resulting foreign exchange gains and
losses are included in income in the current period.

(i) Full Cost Accounting Guideline

In September 2003, the Canadian Institute of Chartered Accountants
("CICA") issued Accounting Guideline 16 "Oil and Gas Accounting - Full
Cost" to replace CICA Accounting Guideline 5. The new guideline revised
the calculations for the ceiling test calculations. The new guideline is
required to be adopted for fiscal years beginning on or after January 1,
2004. These statements reflect the implementation of this new guideline
for 2003 in accordance with the transitional provisions that encouraged
early adoption.

(j) Stock Based Compensation and Other Stock Based Payments

In September 2003, the CICA issued an amendment to section 3870 "Stock
based compensation and other stock based payments". The amended section
is effective for fiscal years beginning on or after January 1, 2004. The
amendment requires that companies measure all stock based payments using
the fair value method of accounting and recognize the compensation
expense in their financial statements. The Company implemented this
standard on commencement of operations.

(k) Asset Retirement Obligations

The new CICA standard dealing with accounting for asset retirement
obligations changes the method of accruing for certain site-restoration
costs. Under the new standard, the fair values of asset retirement
obligations are recorded as liabilities on a discounted basis when they
are incurred, which is typically when the related assets are
acquired/installed. Amounts recorded for the related assets are
increased by the amount of these obligations. Over time the liabilities
will be accreted for the change in their present value and the initial
capitalized costs will be depleted and amortized over the useful lives
of the related assets. There are no asset retirement liabilities set up
for those assets, which have an indeterminate useful life.

(l) Deferred Financing Costs

Deferred financing costs represent fees incurred in establishing and
renegotiating the company's credit facilities. These costs are being
amortized over the term of the facilities.

(m) Hedging

Effective January 1, 2004, the Company has implemented CICA Accounting
Guideline (AcG-13), "Hedging Relationships", which is effective for
fiscal years beginning on or after July 1, 2003. AcG-13 addresses the
identification, designation, documentation and effectiveness of hedging
transactions for the purposes of applying hedge accounting. It also
established conditions for applying or discontinuing hedge accounting.
Under the new guideline, hedging transactions must be documented and it
must be demonstrated that the hedges are sufficiently effective in order
to continue accrual accounting for position hedges with derivatives. The
Company has no contracts on hand at December 31, 2004.

3. Business Acquisition

The Grey Wolf Properties were acquired from related parties (Note 1) and
have been accounted for by the purchase method from January 23, 2003,
based on the carrying values of the assets as follows:



($ 000)
-----------
Property and equipment (1) $ 33,795
Accounts receivable 3,438
Future tax asset 4,437
Asset retirement obligation (784)
Agreed to exchange amount settled via issuance of shares (48,438)
-----------
Excess of purchase price paid over carrying value $ (7,552)
-----------
-----------

(1) The purchase price adjustment from the effective date of October 1,
2002 to January 23, 2003 was included in the related parties'
carrying value of the property and equipment acquired at January 23,
2003.

4. Property and Equipment

Accumulated Net
Depletion and Book
Cost Amortization Value
------------------------------------
($ 000) ($ 000) ($ 000)
December 31, 2004
Petroleum and natural gas
properties $ 73,041 $ 18,251 $ 54,790
------------------------------------

December 31, 2003
Petroleum and natural gas
properties $ 48,776 $ 2,765 $ 46,011
------------------------------------


As at December 31, 2004, the unproved property costs excluded from the
depletion base was $3,575,349 (2003 - $5,517,782). The Company has also
capitalized $677,451 (2003 - $667,936) in general and administrative
costs.

An impairment calculation was performed on the Company's property, plant
and equipment at December 31, 2004 in which the estimated undiscounted
future net cash flows associated with the proved and probable reserves
exceeded the carrying amount of the Company's property, plant and
equipment.

The following table outlines the Company's realilzed prices used in the
impairment test:



Oil Gas
Year Cdn$/bbl Cdn$/Mcf
------------------------------------------------------------------------
2004 53.06 6.85
2005 54.00 6.87
2006 48.78 6.67
2007 43.34 6.45
2008 40.93 5.87
2009 38.40 5.51
Thereafter 39.17 - 44.11 5.42 - 6.08


5. Due to Parent Company

The Company is a wholly owned subsidiary of Abraxas Petroleum
Corporation (the "Parent Company"). The Parent Company funds the
Company's activity through an inter-company loan arrangement. Currently
the Parent Company does not charge the Company any interest on this
inter-company loan. The loan is unsecured and has no terms of repayment.
The fair value of the loan is not readily determinable. On February 28,
2005, the inter-company loan of $1.26 million was repaid to Abraxas from
the net proceed of the Company's Initial Public Share Offering.



December December
31, 2004 31, 2003
------------------------
($ 000) ($ 000)

Due to parent company $ 1,256 $ 9,420
------------------------
------------------------

Corporate service charge in the period (Note 11) $ 122 $ 129
------------------------
------------------------


6. Long Term Debt

On October 28, 2004, the Company entered into a Term Loan Agreement in
the amount of US $35,000,000. This amount bears interest at a base rate
plus spread, collateralized as detailed below and due 5 years from
October 28, 2004. The base rate is defined as the prime rate of interest
specified as Bloomberg "PRIMBB Index", however, if such rate is not
available, the rate of interest as is publicly announced by Citibank,
New York. The spread is 6.25% and will increase by 0.75% on April 29,
2005 and every six months thereafter. The effective interest rate for
the year ended December 31, 2004 was 11%. Principal payments are due as
follows:



on the first anniversary, US$1,750,000;
on the second anniversary, US$1,750,000;
on the third anniversary, US$1,750,000;
on the fourth anniversary, US$3,500,000; and
(v) on the fifth anniversary (maturity date), the remaining
principal and any other amounts.


The proceeds of the Term Loan were paid to the Parent Company to settle
outstanding inter-corporate debt, on account of a return of paid up
capital, and in consideration for the release of the Company from all
obligations relating to, or arising under, the loan obligations to the
Parent Company.

The Company's obligations under the Term Loan are collateralized by the
Company and by each of the Company's future subsidiaries by a first
priority perfected security interest, subject to certain permitted
encumbrances, in all of the Company's and each of its subsidiaries'
material property and assets, including substantially all of their
natural gas and crude oil properties and all of the shares in the
capital stock of any entity owned by the Company and its subsidiaries.

Subsequent to the year end, the term loan has been repaid (Note 13(d)).

Financing costs in the amount of $2,390,633 have been deferred and are
amortized over the term of the loan. $79,688 of amortization has been
recorded for 2004. These financing costs were paid for by the Parent
Company and have reduced the reduction of stated capital to the Parent
Company (Note 8(b)).



7. Asset Retirement Obligation

The schedule below is a reconciliation of the Corporation's liability:

December December
31, 2004 31, 2003
------------------------
($ 000) ($ 000)

Beginning balance $ 816 $ -
Acquisitions - 784
Liabilities incurred 1,521 -
Liabilities settled (468) (475)
Accretion 206 507
------------------------
$ 2,075 $ 816
------------------------
------------------------


Costs attributable to these commitments and contingencies are expected
to be incurred over an extended period of time and are to be funded
mainly from the Corporation's cash provided by operating activities.
Although the ultimate impact of these matters on net earnings cannot be
determined at this time, it could be material for any one quarter or
year.

The undiscounted amount of expected cash flows required to settle the
asset retirement obligations is estimated to be $2,816,400 as at
December 31, 2004 (December 31, 2003 - $1,183,708). The liability for
the expected cash flows, as reflected in the financial statements, has
been discounted at 11% pursuant to a completed refinancing by the parent
company.



8. Share Capital

(a) Authorized

Unlimited number of common shares with participating rights upon
liquidation or distribution of the assets of the Company.

(b) Issued

December 31, 2004 December 31, 2003
---------------------------------------
Number Number
of shares Amount of shares Amount
---------------------------------------
($ 000) ($ 000)

Common shares
Balance, beginning of period 13,002,360 $47,188 - $ -
Issued for cash - - 269,200 -
Issued for Grey Wolf Properties
(Note 3) - - 12,733,160 48,438
Reduction of stated capital (1) - (31,262) - (1,250)
---------------------------------------
Balance, end of period 13,002,360 $15,926 13,002,360 $47,188
---------------------------------------

(1) By special resolution of the sole shareholder, the Company reduced
its stated capital by $1,250,000 and $31,262,000 on January 24, 2003
and October 28, 2004 respectively.


The number of shares has been recalculated to reflect a 2,692 for 1
split on January 13, 2005.

(c) Options & Warrants

The Company has no issued or outstanding options or warrants as of
December 31, 2004 and 2003.

The Company created a stock option plan to grant options to directors,
officers and employees of the Company on March 1, 2005. Options granted
under the option plan will have an exercise price that is not less than
the price allowed by regulatory authorities and will be exercisable for
a period not to exceed 5 years. The aggregate number of common shares
subject to the options under the plan will not exceed 10% of the common
shares then outstanding.



9. Income Taxes

The effective rate of income tax varies from the statutory rate as
follows:

December December
31, 2004 31, 2003
------------------------
($ 000) ($ 000)

Combined tax rates 38.62% 40.12%
------------------------

Expected income tax provision at statutory rate $ 2,083 $ 121
Federal resource allowance (672) (249)
Crown charges 1,250 634
Alberta Royalty Tax Credits (173) -
Other differences, including change in future
tax rate (388) (145)
------------------------
Actual income tax provision $ 2,100 $ 361
------------------------
------------------------

At the end of the period, subject to confirmation by income tax
authorities, the Company has approximately the following undeducted tax
pools:

December December
31, 2004 31, 2003
------------------------
($ 000) ($ 000)

Cumulative Canadian development expenses $ 8,567 $ 4,298
Cumulative Canadian exploration expenses 4,453 3,783
Cumulative Canadian oil and gas property expenses 32,455 35,428
Undepreciated capital cost 12,268 11,122
Unutilized loss carryforwards - 1,248
------------------------
$57,743 $55,879
------------------------
------------------------


These pools are deductible from future income at rates prescribed by the
Income Tax Act (Canada).

The components of the Company's future income tax asset are a result of
the origination and reversal of temporary differences and are comprised
of the following:



Nature of temporary differences December December
31, 2004 31, 2003
------------------------
($ 000) ($ 000)

Property, plant and equipment $ 1,829 $ 3,748
Non-capital loss carryforwards - 462
Other 147 122
------------------------
1,976 4,332
Valuation allowance - (256)
------------------------
Future income tax asset $ 1,976 $ 4,076
------------------------
------------------------


10. Financial Instruments

As disclosed in Note 2(d), the Company holds various forms of financial
instruments. The nature of these instruments and the Company's
operations expose the Company to commodity price, credit, interest rate
and foreign currency risks. The Company manages its exposure to these
risks by operating in a manner that minimizes its exposure to the extent
practical.

(a) Commodity price risk

The Company will be subject to commodity price risk for the delivery of
natural gas and crude oil under the contract detailed as per Note 13(a).
The Corporation enters into these contracts for the purpose of
protecting its future earnings and cash flow from operations from the
volatility of crude oil and natural gas commodity prices. The swap
contracts reduce the fluctuations in petroleum and natural gas revenues
by locking in fixed forward prices on a portion of the Corporation's
crude oil and natural gas production.

(b) Credit risk

The Company is or may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture
partners, marketers of its petroleum and natural gas production and
other parties. In the event such entities fail to meet their contractual
obligations to the Company, such failures could have a material adverse
effect on the Company and its cash flow from operations. In addition,
poor credit conditions in the industry and of joint venture partners may
impact a joint venture partner's willingness to participate in the
Company's ongoing capital program, potentially delaying planned programs
and related results.

The Company's cash is held at one institution and as a result of this
and the nature of its operations, the Company has concentrations of
credit risk.

(c) Interest rate risk management

The Company's term loan is subject to floating rates. The floating rate
debt is subject to interest rate cash flow risk, as the required cash
flows to service the debt will fluctuate as a result of changes in
market rates.

As at December 31, 2004, the increase or decrease in net earnings before
taxes for each 1% change in interest rates on floating rate debt amounts
to approximately $422,000 (2003 - $nil) per annum. The related
disclosure regarding this debt instrument is included in Note 6 of these
financial statements. Subsequent to year end, the term loan was repaid
(see Note 13(d)).

11. Related Party Transaction

Except as disclosed elsewhere in these financial statements, the Company
had the following related party transaction:

Pursuant to the Corporate Service Agreement, Grey Wolf reimbursed
US$100,000 (2003 - US$100,000) to its parent company for its personnel
to conduct the business affairs in Canada (Note 5). The agreement is
renewed on a yearly basis.

Transactions with related parties are in the normal course of operations
and have been recorded at the exchange amounts, which is the amount of
consideration established and agreed by the related parties and which
are similar to those negotiable with third parties.

12. Commitments

(a) As of January 1, 2004, the Company was committed to a 5-year lease
for the rental of its office space. The lease expires on December 31,
2008. The lease calls for base monthly payments of $8,575, plus a
proportional share of operating costs.

(b) The Company has entered into two compressor leases. One calls for
monthly payments of $12,125 per month for one year (expiring November
2005) and the other lease calls for monthly payments of $16,325 for two
years (expiring November, 2006).

(c) The Company has entered into a farmout agreement with PrimeWest
Energy Trust ("PrimeWest") for their Caroline property. Under the terms
of the farmout agreement, PrimeWest is also granted an option,
exercisable within 180 days of rig release of the last option well
drilled to contract depth, to purchase that portion of the Caroline
property which has been assigned proved reserves or probable additional
reserves by a third-party engineer in accordance with National Policy 2B
for a purchase price equal to the fair market value thereof less
$1,000,000. The fair market value is deemed by the Caroline Farmout
Agreement to be the present value of the estimated future net cash flows
from such properties, before tax, from proven reserves and 50% of
probable additional reserves, at a discount rate of 10% per annum,
employing an escalating price forecast. In the event the fair market
value is determined to be less than or equal to $1,000,000, PrimeWest
may purchase the portion of the Caroline Property with assigned proved
or probable additional reserves for $1.

(d) Employment contracts

Subsequent to the period ended December 31, 2004, the Company has
entered into employment agreements with certain officers ("officers") of
the Company.

The Employment Agreements specify that officers are entitled to a lump
sum payment ranging from six to 24 months base salary plus an amount
that reflects the value of lost benefits for the same period together
with a pro rata amount of any bonus earned to the date of termination in
the event they are terminated without cause.

The Employment Agreements also provide that each officer is entitled to
a lump sum payment ranging from 12 to 36 months of base salary plus an
amount which reflects the value of lost benefits for the same period
together with a pro rata amount of any bonus earned to the date of
termination in the event a change of control of Grey Wolf occurs and
within six months thereafter is terminated without cause or is
constructively dismissed.

The Company has also entered into an executive termination agreement
with an officer of the Company. In the event that this individual is
terminated without just cause or the Company undergoes a change of
control, the Company is obligated to pay this individual a lump sum
payment that is equal to 24 months of the salary of the President of
Grey Wolf plus an amount equal to the cost of benefits provided by the
Corporation to the individual for the same period.

13. Subsequent Events

(a) The Company has incurred a firm obligation to deliver 3,000 GJ/d for
a period of six months commencing on January 1, 2005. This amount
represents approximately 30% of the Company's current daily production
of 1,658Boe/d. The price received for such production shall fluctuate at
a slight discount to the market price but in no event shall be less than
$5.79 per GJ.

(b) On February 28, 2005, the Company completed an initial public
offering of 17.8 million common shares and a secondary offering of 9.1
million common shares which are being offered by the Parent Company, at
a price in each case of $2.80 per common share. The Company and the
Parent Company have agreed to proportionately pay a commission to the
Underwriters equal to 6% of the gross amount raised from the offering,
of which the Company's portion is approximately $3 million. Estimated
expenses of the offering will also be shared proportionately by the
Company and the Parent Company, of which the Company's share is
approximately $900,000.

(c) Subsequent to the period ended December 31, 2004, the Company has
obtained a $10.0 million revolving credit facility with a Canadian
Chartered bank. Under the terms of the facility, it bears interest at
the bank's prime rate plus 25 basis points per annum. The revolving
credit facility is subject to semi-annual review and the Company has
pledged a $30.0 million floating charge debenture over all its present
and after-acquired properties.

(d) On February 28, 2005, the Term Loan of US$35.0 million was repaid in
its entirety with interest from the net proceeds of the Treasury
offering. As a result, the deferred financing costs of $2.3 million
related to the term-loan were expensed during the first quarter of 2005.
In order to minimize the foreign exchange fluctuations, the Company
entered into a foreign exchange contract whereby the Company purchased
US$46.5 million at a rate of 1.232. However, the Company was required to
translate the US$35 million term loan into Canadian currency in the
February financial statements prior to repayment of the loan. As a
results, the Company recorded a non-recurring foreign exchange loss of
$0.9 million during the first quarter of 2005, due to the change in the
exchange rate from December 31, 2004 to February 28, 2005.

OVERVIEW

Grey Wolf Exploration Inc. ("Grey Wolf" or the "Corporation") was
incorporated pursuant to the Alberta Business Corporations Act on
December 6, 2002. On January 13, 2005, Grey Wolf filed Articles of
Amendment to remove private company and share transfer restrictions and
to implement the stock split of the Common Shares on the basis of 2,692
Common Shares for each previously outstanding Common Share.

On February 28, 2005, pursuant to its Initial Public Offering (the
"Offering"), Grey Wolf issued a total of 17,800,000 Common Shares at a
price of $2.80 per common share for gross proceeds of $49,840,000. In
addition, Abraxas Petroleum Corporation, Grey Wolf's sole shareholder
("Abraxas"), sold an aggregate of 9,100,000 common shares of Grey Wolf,
offered on a secondary basis at a price of $2.80 per common share for
gross proceeds of $25,480,000. The net proceeds from the Offering were
partially used by Grey Wolf to repay inter-company debt owing to Abraxas
and to repay the outstanding balance of a term loan. The remaining net
proceeds of the Offering were used to eliminate Grey Wolf's working
capital deficiency. After the completion of the share offering on
February 28, 2005, Grey Wolf became an independent junior oil and gas
company and began trading on the Toronto Stock Exchange under the symbol
"GWE".

The following discussion outlines Grey Wolf management's review of the
unaudited quarter ended December 31, 2004 operating and financial
results, compared to the unaudited quarter ended December 31, 2003, and
the audited years ended December 31, 2004 and 2005, including its
financial condition, liquidity and capital resources, capital
expenditure program, reserve additions and forward-looking operating and
financial estimates.

This discussion should be read in conjunction with Grey Wolf's audited
Financial Statements dated December 31, 2004 and 2003. All dollar
amounts are presented in Canadian dollars. The calculation of barrels of
oil equivalent ("boe") is based on a conversion ratio of six thousand
cubic feet of natural gas to one barrel of oil to estimate relative
energy content and does not represent a value equivalency. Boes may be
misleading, particularly if used in isolation.

Certain information regarding the Corporation contained herein may
constitute forward-looking statements under applicable securities laws.
Such statements are subject to known or unknown risks and uncertainties
that may cause actual results to differ materially from those
anticipated or implied in the forward-looking statements.



SUMMARY OF FINANCIAL AND OPERATING RESULTS

(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands except per
share and boe amounts)
Oil and natural gas revenue $ 6,943 $ 3,108 $23,943 $ 8,942
Cash flow from operations 3,896 1,340 12,696 3,498
Per share - basic and
fully diluted 0.30 0.11 0.98 0.31
--------- --------- --------- ---------
Net earnings (loss) 1,673 (41) 3,283 (135)
Per share - basic and
fully diluted 0.13 (0.00) 0.25 (0.01)
--------- --------- --------- ---------
Operating netback - $/boe 30.22 20.97 25.72 27.44
Average daily sales - boed 1,868 938 1,636 559
Capital expenditures 6,670 2,080 14,760 12,792
--------- --------- --------- ---------
Total assets 63,416 52,287
Net debt including working capital 45,480 9,770
--------- ---------


"Cash flow from operations", "Cash flow from operations per share -
basic", and "Cash flow from operations per share - diluted", are not
measures that have any standardized meaning prescribed by Canadian
generally accepted accounting principles ("GAAP") and are considered
non-GAAP measures. Therefore, these measures may not be comparable to
similar measures presented by other issuers. These measures have been
described and presented in this Management's Discussion and Analysis in
order to provide shareholders and potential investors with additional
information regarding the Corporation's liquidity and its ability to
generate funds to finance its operations.

Management utilizes "Cash flow" as a key measure to assess the ability
of the Corporation to finance operating activities and capital
activities. All references to cash flow from operations throughout this
report are based on cash flow before changes in non-cash working capital.



DETAILED REVIEW OF FINANCIAL RESULTS

Net Earnings and Cash Flow

(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars except
per share amounts)
Net earnings (loss) $ 1,673 $ (41) $ 3,283 $ (135)
Per share 0.13 (0.00) 0.25 (0.01)
Cash flow 3,896 1,340 12,696 3,498
Per share 0.30 0.11 0.98 0.31


Net income for the year increased substantially to $3.3 million ($0.25
per share) compared to a net loss of $0.1 million ($0.01 per share) in
2003. Cash flow from operations increased 263% to $12.7 million ($0.98
per share). The increase in both net income and cash flow from
operations were mainly due to increase in production volumes in 2004.



Revenue
(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars except
per barrel, Mcf and boe)
Crude oil and NGLs $ 1,502 $ 977 $ 4,855 $ 1,930
Per barrel 52.81 37.90 48.40 39.17
Natural gas 5,430 2,129 19,067 7,006
Per Mcf 6.31 5.86 6.38 6.92
Other revenue 11 2 21 6

Total gross revenue $ 6,943 $3,108 $23,943 $ 8,942
Per boe 40.39 35.99 39.99 41.02


Sales Volumes
(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------

Crude oil (barrels per day) 147 226 121 90
Natural gas (Mcf per day) 9,356 3,949 8,171 2,595
NGLs (barrels per day) 162 54 153 36
Barrels of oil equivalent
per day 1,868 938 1,636 559


Crude oil and natural gas revenues increased by $15.0 million to $23.9
million for the year ended December 31, 2004, representing a 168%
increase over the comparable period in 2003. Higher production volumes
accounted for $15.6 million of the increase which was offset slightly by
lower commodity prices of $0.6 million. The Corporation still maintains
its focus on development of natural gas production. Natural gas and gas
liquids revenues contributed 93% of the total revenues in 2004.

Production increased 193% to average 1,636 boe per day in 2004 due to
our successful drilling programs in the Caroline area and the tie-in of
two shut-in gas wells at Widewater in late 2003. In December 2004, the
Corporation recorded a prior period royalty income adjustment of 85 boe
per day at Valhalla. The Corporation's actual production before the
adjustments for the year and fourth quarter of 2004 were 1,578 and 1,556
boe per day respectively. Grey Wolf's production increase was restricted
somewhat by allowables in the Knopcik area. Subsequent to year-end, a
waterflood application was approved by the AEUB and all wells are
currently producing at their full capacity.



Royalties
(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars except
per barrel, Mcf, boe & %)
Crude oil and NGLs $ 283 $ 184 $ 778 $ 330
Per barrel 9.94 7.15 7.76 6.70
Percentage of revenue 18.8 18.9 16.0 17.1

Natural gas $ 711 $ 431 $ 3,116 $ 1,269
Per Mcf 0.83 1.19 1.04 1.25
Percentage of revenue 13.1 20.2 16.3 18.1

Total royalties $ 994 $ 615 $ 3,894 $ 1,599
Per boe 5.78 7.12 6.50 7.33
Percentage of revenue 14.3 19.8 16.3 17.9


Royalties, net of Alberta Royalty Tax Credit, increased to $3.9 million
in 2004, up 141% from $1.6 million when compared to 2003. The increase
was primarily due to higher crude oil and natural gas revenues. On a
barrel of equivalent basis, royalties actually decreased to $6.44 per
boe from $7.33 per boe in 2003. During 2004, some of the new well
production in the Caroline area qualified for Deep Gas Royalty
Exemption, which contributed to the decrease in royalties in 2004.
However, some of these gas royalty exemptions will be expired in 2005
and none of the wells planned to be drill in 2005 will qualify for the
exemption. We expect that royalty payment, as a percentage of total
revenues, will rise in 2005.



Production Expense

(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars except
boe)
Total production expense $ 646 $ 644 $4,113 $1,145
Per boe 3.76 7.47 6.87 5.25


Operating costs increased by $3.0 million to $4.1 million in 2004
primarily due to increases in production volumes and transportation and
gathering fees of $1.27 million incurred with respect to the pipeline
payout account in the Widewater area. The pipeline costs were fully paid
in June 2004. The operating cost, excluding the transportation and
gathering fees, would reduce the unit cost from $6.87 to $4.85 per boe
in 2004. The prior period royalty income adjustment of $1.2 million,
which was not subject to operating costs, was the main contributing
factor to the lower operating cost of $3.76 per boe in the fourth
quarter of 2004. The unit operating cost in 2005 is expected to remain
approximately the same as 2004.



Netbacks (per boe)
(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------

Revenue $40.39 $35.99 $39.99 $41.02
Royalties (5.78) (7.12) (6.50) (7.33)
Production expense (3.76) (7.47) (6.87) (5.25)
Transportation expense (0.63) (0.43) (0.90) (1.00)
--------- --------- --------- ---------

Netback $30.22 $20.97 $25.72 $27.44
--------- --------- --------- ---------


Operating netbacks decreased by 6% to $25.79 per boe as a result of
higher production in the Widewater area during 2004. When compared to
2003, Widewater's share of the corporate production total increased from
7% in 2003 to 29% in 2004. Since the Widewater natural gas is of a lower
than average heating content, the production increase had the effect of
decreasing the corporate average price per Mcf received. The average
2004 price realized in Widewater was 37% lower than the average price
received in our other core areas. The one time payment of $1.27 million
in facility fees incurred in Widewater also contributed to a higher
operating cost per boe and lower netbacks in 2004, and the fees were
paid out in June 2004.



General and Administrative Expense

(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars except
per boe)
General and administrative
expense $ 352 $ 434 $ 1,761 $ 1,515
Per boe 2.05 5.03 2.94 6.95


General and administrative costs increased slightly from $1.5 million to
$1.8 million in 2004. This increase was principally related to the $0.3
million bonus payment made in 2004. As a result of higher production,
the general and administrative expense decreased substantially from
$6.95 to $2.94 per boe in 2004. The higher production level recorded in
the fourth quarter of 2004 further reduced the unit cost to $2.05 per
boe. General and administrative expense is expectd to increase in 2005
due to an increase in staffing levels and costs associated with becoming
a public Corporation.

Interest Expense

Interest expense of $914,855 was mainly related to the US$35 million
Term Loan secured on October 28, 2004. The actual interest rate paid on
the loan on December 31, 2004 was 11%. Pursuant to the terms of the Loan
Agreement, the Corporation is also responsible for the 10% withholding
tax on interest payments to non-residents and such amount was included
in interest expense. Subsequent to year-end, the Term Loan was repaid on
February 28, 2005. We do not anticipate having any interest expense for
the remainder of 2005.



Depletion, Depreciation and Accretion Expense

(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars except
per boe)
Depletion, depreciation and
accretion $ 1,909 $ 1,261 $ 7,707 $ 3,272
Per boe 11.11 14.61 12.87 15.01


Depletion and depreciation provisions for 2004 increased by 136% to $7.7
million primarily due to higher production volumes. The cost of
acquiring undeveloped land through land sales and property acquisitions
in the amount of $3.6 million (2003 - $5.5 million) have been excluded
from depletion calculation. The depletion and depreciation rate per boe
has remained relatively constant from year to year.

Income Taxes

At December 31, 2004, subject to confirmation by income tax authorities,
the Corporation had the following undeducted tax pools:



December 31, 2004
($000)
-------------------

Cumulative Canadian development expenses $ 8,567
Cumulative Canadian exploration expenses 4,453
Cumulative Canadian oil and gas property expenses 32,455
Undepreciated capital cost 12,268
Unutilized loss carry forwards 0
-------------------
$57,743
-------------------
-------------------


These pools are deductible from future income at rates prescribed by the
Income Tax Act (Canada).

The provision of future taxes for 2004 increased to $2.1 million from
$0.4 million a year ago. The increase was in line with the increase in
net income before income tax. Capital taxes decreased from $75 thousand
to $10 thousand in 2004 mainly due to the increase in capital tax
exemption from $10.0 million to $50.0 million in 2004. At December
31,2004, the Corporation has approximately $57.7 million tax pools
available to shelter against future income. The Corporation does not
anticipate that it will be cash taxable in the near future.



SUMMARY OF QUARTERLY RESULTS (unaudited)

2003
Q1 Q2 Q3 Q4
-------- ------- ------- --------
(Thousands except per share and boe)
Net oil and gas revenue $ 1,325 $ 1,748 $ 1,778 $ 2,492
Operating cash flow 811 1,130 217 1,340
Net earnings (loss) 799 228 (1,117) (45)
Per share - basic and fully diluted 0.08 0.02 (0.09) (0.00)
Operating netback - $/boe 35.96 33.67 27.41 20.97
Average sales - boed 483 501 583 938
Capital expenditures 3,691 3,456 3,564 2,081

2004
Q1 Q2 Q3 Q4
-------- ------- ------- --------
(Thousands except per share and boe)
Net oil and gas revenue $ 4,065 $ 5,262 $ 4,773 $ 5,949
Operating cash flow 2,116 3,071 3,613 3,896
Net earnings (loss) 384 11 1,215 1,673
Per share - basic and fully diluted 0.03 0.00 0.09 0.13
Operating netback-$/boe 19.18 24.00 28.29 30.22
Average sales - boed 1,445 1,718 1,511 1,868
Capital expenditures 2,691 2,046 3,353 6,670


LIQUIDITY AND CAPITAL RESOURCES

During 2003 and 2004, Grey Wolf Exploration Inc. was a wholly-owned
subsidiary of Abraxas Petroleum Corporation (the "Parent Company"). In
addition to cash flow, the Corporation funded its capital program
through an inter-company loan arrangement with the Parent Company.
During 2003 and 2004, the Parent Company did not charge Grey Wolf any
interest on this inter-company loan. The balance at December 2004 was
$1,255,700 (2003 - $9,420,000). On October 28, 2004, the Corporation
entered into a Term Loan Agreement in the amount of US $35,000,000
bearing interest at a base rate (identified as PRIMBB index) plus spread
of 6.25%. The spread would increase by 1.75% on April 29, 2005 and every
six months thereafter. The proceeds of the Term Loan were paid to the
Parent Company to settle outstanding inter-company debt, on account of a
return of paid up capital, and in consideration for the release of the
Corporation from all obligations relating to or arising under the loan
obligations of the Parent Company. Subsequent to year-end, the
Corporation repaid the US $35.0 million Term Loan in its entirety with
interest from the proceeds of its initial public share offering.

After the initial public share offering in early 2005, the Corporation
secured a $10.0 million revolving credit facility with a Canadian
Chartered Bank. Under the terms of the facility, it bears interest at
the Bank's prime rate plus 25 basis points per annum. The Corporation
intends to fund its 2005 exploration and development activities entirely
from internally generated cash flow, however, the existing credit
facility allows the Corporation the flexibility to expand its capital
program in the event that an excellent investment opportunity arises.

CONTRACTUAL OBLIGATIONS AND CONTINGENCIES

The Corporation has entered into a farmout agreement with PrimeWest
Energy Trust ("PrimeWest") for their Caroline property. Under the terms
of the farmout agreement, PrimeWest is also granted an option,
exercisable within 180 days of rig release of the last option well
drilled to contract depth, to purchase that portion of the Caroline
property which has been assigned proved reserves or probable additional
reserves by a third-party engineer in accordance with National Policy 2B
for a purchase price equal to the fair market value thereof less
$1,000,000. The fair market value is deemed by the Caroline Farmout
Agreement to be the present value of the estimated future net cash flows
from such properties, before tax, from proven reserves and 50% of
probable additional reserves, at a discount rate of 10% per annum,
employing an escalating price forecast. In the event the fair market
value is determined to be less than or equal to $1,000,000, PrimeWest
may purchase the portion of the Caroline Property with assigned proved
or probable additional reserves for $1.

Grey Wolf's commitment related to office lease and to compressor leases
are as follows:



Expected Payment Date
---------------------
2005 2006 2007 2008 Total
------ ----- ----- ----- -------
Contractual obligations ($000's)
Office lease (1) $ 207 $ 207 $ 207 $207 $ 828
Compressor leases 341 180 - - 521

Total $ 548 $ 387 $ 207 $ 207 $1,349

Note: (1) Including estimated operating costs.

CAPITAL EXPENDITURES
(unaudited) (unaudited) (audited) (audited)
Three Three 390 Day
Months Months Year Period
Ended Ended Ended Ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2004 2003 2004 2003
--------- --------- --------- ---------
(thousands of dollars)
Land and seismic $ 566 $ 168 $ 1,931 $ 2,551
Drilling and completion 3,691 700 8,345 9,046
Facilities and equipment 2,413 1,222 4,484 2,141
Property acquisition
(disposition) 0 (10) 0 (946)
--------- --------- --------- ---------

Total capital expenditures $6,670 $2,080 $14,760 $12,792
--------- --------- --------- ---------


Capital expenditures for the year totaled $14.8 million, a slight
increase from the $12.8 million spent in 2003. Of the total amount,
approximately $8.3 million was spent on the drilling and completions at
the Caroline and Knopcik areas, $4.5 million and $1.9 million were spent
on facility construction and land and seismic respectively. The capital
expenditures for both 2004 and 2003 were restricted somewhat by the debt
covenants.

RESERVES

Each year, Grey Wolf engages an independent qualified reserve evaluator
to prepare a report on 100 percent of the Corporation's oil and natural
gas reserves. The Corporation has a Reserves Committee, containing a
majority of independent board members, which has been mandated to review
the qualifications and appoint the independent qualified reserve
evaluator. In addition, the committee's mandate will include the review
of procedures whereby information is passed from the Corporation to the
evaluator. The tables below set forth certain information relating to
the oil, natural gas and NGL reserves of Grey Wolf and the net present
value of future net revenue associated with such reserves as at December
31, 2004. The information set forth below is derived from the DeGoyler &
MacNaughton Report (the "D&M Report"), which has been prepared by
DeGoyler & MacNaughton in accordance with the standards, policies and
procedures contained in NI 51-101 and the COGE Handbook. The D&M Report
is the initial independent engineering report commissioned by Grey Wolf
in respect of the Corporation's reserves prepared in accordance with NI
51-101 or its predecessor, National Policy 2B. Consequently, it is not
possible to provide a reconciliation of changes in reserves and future
net revenue from estimates from the previous financial year.



SUMMARY OF OIL AND NATURAL GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004

CONSTANT PRICES AND COSTS

Light and Natural Gas
Medium Oil Natural Gas Liquids
------------- ------------ -------------
Gross Net Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
------ ----- ------ ------ ----- ------
Proved
Developed Producing 332 283 11,133 9,725 272 227
Developed Non-Producing 0 0 2,198 1,652 66 43
Undeveloped 0 0 2,345 1,682 14 9

Total Proved 332 283 15,676 13,059 352 279
Probable 405 340 9,963 7,421 193 127
------ ----- ------ ------ ----- ------

Total Proved Plus Probable 737 623 25,638 20,480 545 406
------ ----- ------ ------ ----- ------
------ ----- ------ ------ ----- ------


NET PRESENT VALUES OF FUTURE NET REVENUE
CONSTANT PRICES AND COSTS

Before Income Taxes After Income Taxes
Discounted at (%/year) Discounted at %/year)
0 5 10 15 20 0 5 10 15 20
Reserves Category (MM$) (MM$)(MM$)(MM$)(MM$) (MM$)(MM$)(MM$)(MM$)(MM$)
------ ----- ---- ---- ---- ----- ---- ---- ---- -----
Proved
Developed Producing 81.0 64.2 53.8 46.9 41.6 74.1 58.3 48.6 42.1 37.3
Developed
Non-Producing 11.6 7.7 5.7 4.3 3.5 7.9 5.2 3.8 2.9 2.3
Undeveloped 6.9 5.3 4.1 3.2 2.5 4.5 3.4 2.6 2.0 1.5
------ ----- ---- ---- ---- ----- ---- ---- ---- -----

Total Proved 99.5 77.2 63.6 54.4 47.6 86.5 66.9 55.0 47.0 41.1
Probable 57.8 37.8 26.6 19.6 14.8 39.2 25.3 17.6 12.8 9.6
------ ----- ---- ---- ---- ----- ---- ---- ---- -----

Total Proved
Plus Probable 157.3 115.0 90.2 74.0 62.4 125.7 92.2 72.6 59.8 50.7
------ ----- ---- ---- ---- ----- ---- ---- ---- -----
------ ----- ---- ---- ---- ----- ---- ---- ---- -----


SUMMARY OF OIL AND NATURAL GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2004

FORECAST PRICES AND COSTS

RESERVES

Light and Natural Gas
Medium Oil Natural Gas Liquids
------------- ------------ -------------
Gross Net Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl)
------ ----- ------ ------ ----- ------
Proved
Developed Producing 327 277 11,108 9,647 271 225
Developed Non-Producing 0 0 2,208 1,659 66 44
Undeveloped 0 0 2,345 1,682 14 9

Total Proved 327 277 15,661 12,988 351 278
Probable 395 335 9,953 7,416 192 129
------ ----- ------ ------ ----- ------

Total Proved Plus Probable 722 612 25,614 20,404 543 407
------ ----- ------ ------ ----- ------
------ ----- ------ ------ ----- ------


FORECAST PRICES AND COSTS

NET PRESENT VALUE OF FUTURE NET REVENUE

Before Income Taxes After Income Taxes
Discounted at (%/year) Discounted at %/year)
0 5 10 15 20 0 5 10 15 20
Reserves Category (MM$) (MM$)(MM$)(MM$)(MM$) (MM$)(MM$)(MM$)(MM$)(MM$)
------ ----- ---- ---- ---- ----- ---- ---- ---- -----
Proved
Developed Producing 70.3 56.7 48.5 42.8 38.7 65.8 52.5 44.4 38.9 35.0
Developed
Non-Producing 9.7 6.4 4.7 3.6 2.9 7.4 4.8 3.5 2.7 2.1
Undeveloped 5.2 4.0 3.1 2.4 1.8 3.4 2.6 2.0 1.5 1.1
------ ----- ---- ---- ---- ----- ---- ---- ---- -----

Total Proved 85.2 67.1 56.3 48.8 43.4 76.6 59.9 49.9 43.1 38.2
Probable 46.0 29.7 20.7 15.3 11.5 31.1 19.8 13.7 9.9 7.3
------ ----- ---- ---- ---- ----- ---- ---- ---- -----

Total Proved
Plus Probable 131.2 96.8 77.0 64.1 54.9 107.7 79.7 63.6 53.0 45.5
------ ----- ---- ---- ---- ----- ---- ---- ---- -----


Table Notes:

(1) "Developed Non-Producing Reserves" are those Reserves that either
have not been on production, or have previously been on production, but
are shut-in, and the date of resumption of production is unknown.

"Developed Producing Reserves" are those Reserves that are expected to
be recovered from completion intervals open at the time of the estimate.
These Reserves may be currently producing or, if shut-in, they must have
previously been on production, and the date of resumption of production
must be known with reasonable certainty.

"Developed Reserves" are those Reserves that are expected to be
recovered from existing wells and installed facilities or, if facilities
have not been installed, that would involve a low expenditure (e.g.,
when compared to the cost of drilling a well) to put the Reserves on
production. The developed category may be subdivided into producing and
non-producing.

"Gross" means Grey Wolf's total working interest share before deduction
of royalties and without including any royalty interests of Grey Wolf.

"Net" means Grey Wolf's total working interest share after the deduction
of royalty obligations plus Grey Wolf's royalty interests in reserves.

"Probable Reserves" are those additional Reserves that are less certain
to be recovered than Proved Reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than the
sum of the estimated Proved plus Probable Reserves. At least a 50%
probability that the quantities actually recovered will equal or exceed
the sum of the estimated Proved plus Probable Reserves is the targeted
level of certainty.

"Proved Reserves" are those Reserves that can be estimated with a high
degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated Proved
Reserves. At least a 90% probability that the quantities actually
recovered will equal or exceed the estimated Proved Reserves is the
targeted level of certainty.

"Reserves" are the estimated remaining quantities of oil and natural gas
and related substances anticipated to be recoverable from known
accumulations, from a given date forward, based on: analysis of
drilling, geological, geophysical and engineering data; the use of
established technology; and specified economic conditions, which are
generally accepted as being reasonable. Reserves are classified
according to the degree of certainty associated with the estimates.

"Royalties" refers to royalties paid to others. The royalties deducted
from the reserves are based on the percentage royalty calculated by
applying the applicable royalty rate or formula. In the case of Crown
royalties each product's royalty rate is determined by the applicable
formula utilizing prevailing published government prices and deductions.
For the Constant Price Case, Crown royalty volumes were estimated on the
basis of formulas and published prices provided by the provincial Crown.
For the Forecast Price Case, Crown published prices were adjusted by the
ratio of the Constant price to the Forecast price.

"Undeveloped Reserves" are those Reserves expected to be recovered from
known accumulations where a significant expenditure (e.g., when compared
to the cost of drilling a well) is required to render them capable of
production. They must fully meet the requirements of the Reserves
classification (proved, probable, possible) to which they are assigned.

(2) Effective on January 1, 1995, the ARTC rate ranges from a maximum of
75% of $2,000,000 when the royalty tax credit reference is below $100/m3
to a minimum of 25% of $2,000,000 when the royalty tax credit reference
is above $210/m3.

(3) The extent and character of all factual data supplied to D&M were
accepted by D&M as represented. The oil and natural gas reserve
calculations and any projections upon which the D&M Report is based were
determined in accordance with generally accepted evaluation practices.
No field inspection was conducted. Well abandonment and lease
reclamation costs, net of salvage values for facilities, have been
included in the D&M Report.

OFF-BALANCE SHEET ARRANGEMENTS

Grey Wolf did not enter into any off-balance sheet arrangements.

ACCOUNTING POLICIES

Grey Wolf's accounting policies are stated in note 2 to the audited
Financial Statements for December 31, 2004 and 2003. Grey Wolf follows
policies that are in accordance with Canadian generally accepted
accounting principles.

Impact of New Accounting Pronouncements

In November 2002, the Canadian Institute of Chartered Accountants
amended its accounting guidelines on hedging relationships. The
guideline specifies certain criteria that must be met for an item to be
accounted for as a hedge. The criteria included ensuring the hedge meets
the risk management objective and strategy, the instrument must be
designated as a hedge and the hedge must be effective. The guideline is
effective for years beginning on or after July 1, 2003. There will
potentially be more volatility in earnings as a result of the adoption
of this guideline. Grey Wolf did not have a hedging program outstanding
at December 31, 2004.

In December 2002, the Canadian Institute of Chartered Accountants
approved a standard on accounting for asset retirement obligations
effective for fiscal years beginning on January 1, 2004. The standard
requires the recognition of a liability for obligations associated with
the retirement of property, plant and equipment when the liability is
incurred. The liability would be recognized initially at fair value (the
obligation is discounted using the credit-adjusted risk free interest
rate) and the resulting amount would be capitalized as part of the
asset. In subsequent periods, the Corporation would recognize "interest"
on the liability and adjust the carrying amount of the asset and the
liability for changes in estimates of the amount or timing of cash flow.
Under existing standards the liability for future site restoration and
abandonment costs is recognized using a cost-accumulation measurement
over the estimated useful life of the assets accrued over the life of
the asset and the obligation is not discounted. Grey Wolf adopted this
guideline in January 2003.

In 2003, the Canadian Institute of Chartered Accountants approved a
standard on Stock-Based Compensation effective for fiscal years
beginning on or after January 1, 2004. The standard requires all
employee stock options to be expensed at fair value. Under existing
standards, companies have the option of disclosing this information in
the notes to the financial statements rather than expensing employee
stock options. The Corporation had no issued or outstanding options as
of December 31, 2004.

In 2003, the Canadian Institute of Chartered Accountants issued an
amendment to its accounting guideline "Full Cost Accounting in the Oil
and Gas Industry" effective for fiscal years beginning on or after
January 1, 2004. Under the new guideline, the ceiling test would involve
a two-step process. The first step would determine whether a write-down
is required by comparing the carrying value of the properties to the
undiscounted cash flow of the proved reserves (based on management's
best estimate of future prices) plus the lower of cost and market value
of unproved properties. If a Company fails the first step, the carrying
value of the properties will be written down to the discounted value of
the proved plus probable reserves (based on management's best estimate
of future prices) plus lower of cost and market of unproved properties.
Under existing standards, the undiscounted cash flow amount is based on
commodity prices existing at the balance sheet date. Grey Wolf has
adopted this guideline as of December 31, 2003.

RISKS AND UNCERTAINTIES

The Corporation is subject to normal industry credit risk on its
accounts receivable with customers and joint venture partners. The
Corporation mitigates these risks by maintaining credit management
policies.

The Corporation is exposed to fluctuations in commodity prices for
natural gas, crude oil and natural gas liquids. Commodity prices are
affected by many factors including supply and demand. The Corporation's
inter-company loan with the Parent Company is dependant on the Parent
Company's ability to generate capital to forward to Grey Wolf. The
Corporation monitors these risks and when appropriate, utilizes
financial instruments to manage its exposure to these risks.

The Corporation, in its normal course of business, does not intend to
hedge any of its production, however, under certain circumstances and
upon receipt of approval from the Board of Directors of Grey Wolf,
hedging contracts may be entered into for specific reasons.

OUTLOOK

Grey Wolf's strategy is to employ its core competence in its major areas
of operations and to continue its record of rapid growth. As commodity
prices are forecast to remain strong throughout 2005, the increased
production resulting from this strategy will translate into healthy cash
flow. We intend to use this cash flow to fund our planned activities,
and access to capital markets and existing credit facilities will enable
us to respond swiftly and positively to newly identified investment
opportunities. Grey Wolf continues to add staff as needed to realize
optimal performance.

Grey Wolf is an Alberta-based oil and natural gas company involved in
the development and production of natural gas and crude oil in the
Western Canadian Sedimentary Basin. It's common shares trade on the
Toronto Stock Exchange under the symbol "GWE".

Forward-Looking Statements - Certain information set forth in this
document, including management's assessment of Grey Wolf's future plans
and operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond Grey Wolf's control, including
the impact of general economic conditions, industry conditions,
volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other industry
participants, the lack of availability of qualified personnel or
management, stock market volatility and ability to access sufficient
capital from internal and external sources. Readers are cautioned that
the assumptions used in the preparation of such information, although
considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Grey Wolf's actual results, performance or
achievement could differ materially from those expressed in, or implied
by, these forward-looking statements. No assurance can be given that any
of the events anticipated will transpire or occur, or if any of them do
so, what benefits Grey Wolf will derive from them. Grey Wolf disclaims
any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.

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Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Grey Wolf Exploration Inc.
    Dawne L. Stirling
    Manager, Investor Relations and Corporate Secretary
    (403) 218-1473
    Email: dstirling@greywolf.ca
    Website: www.greywolf.ca