Rock Energy Inc.

Rock Energy Inc.

March 14, 2005 17:19 ET

Rock Energy Signs Agreements to Acquire Oil and Gas Properties from ELM/OPTIMUM/QWEST, Provides Operations Update and Reports Results for Nine Months Ended December 31, 2004


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: ROCK ENERGY INC.

TSX SYMBOL: RE

MARCH 14, 2005 - 17:19 ET

Rock Energy Signs Agreements to Acquire Oil and Gas
Properties from ELM/OPTIMUM/QWEST, Provides Operations
Update and Reports Results for Nine Months Ended
December 31, 2004

CALGARY, ALBERTA--(CCNMatthews - March 14, 2005) - Rock Energy Inc.
(TSX:RE) is pleased to announce that it has entered into agreements to
acquire oil and gas properties from six private corporations and eight
drilling fund partnerships or their related parties (collectively
referred to as "ELM/OPTIMUM/QWEST "), and to provide an operations
update and its results for the nine months ended December 31, 2004.

ACQUISITION OF ELM/OPTIMUM/QWEST

Rock has agreed to issue 10.3 million shares (subject to TSX
approval)and $25.4 million to acquire the producing properties from the
various parties represented in the ELM/OPTIMUM/QWEST transactions. The
cash will come out of existing balances and a borrowing facility
currently being arranged with the Royal Bank of Canada. The transactions
primarily have an effective date of January 1, 2005 and, as a result,
the respective purchase prices are subject to closing adjustments.
Following closing of the transactions Rock expects to have 19.6 million
shares outstanding (basic) and total debt of $14.5 million.

The ELM/OPTIMUM/QWEST properties represent non-operated working
interests ranging from 5% to 85% in a number of different plays across
the western Canadian sedimentary basin. ELM Energy Management Ltd.
("EEM") has managed the oil and gas investments on behalf of these
entities which have common interests in many of the same properties. The
average working interest based on reserve volumes is approximately 28%.
The properties can be characterized as assets early in their life cycle
with future development opportunities. The major properties (comprising
75% of the value) being acquired are:

- Wild River, Alberta (30% working interest),

- Northeast BC - Parkland, Cypress (12 - 45% working interest),

- Musreau, Alberta (7 - 20% working interest),

- Elmworth/Wapiti, Alberta ( 20 - 45% working interest),

- Girouxville, Alberta (45% working interest), and

- Niton, Alberta (45% working interest).

The properties are currently producing approximately 1,250 boe/d (90%
gas with the balance made up of light oil and liquids) and at January 1,
2005 have proven reserves of 2.899 million boe and proven plus probable
reserves of 4.058 million boe as evaluated by Gilbert, Laustsen Jung
Associates Ltd ("GLJ"). During the year, additional production is
expected to be brought on stream (due to well tie-ins and an interest
reversion) resulting in a target year end exit rate of 2,000 boe/d and
an average production rate for the year of 1,400 boe/d (based on
projected closing dates). These production additions are based on
capital spending of approximately $5 million. The acquisition also
includes approximately 19,600 net (72,000 gross) acres of undeveloped
land along with seismic data.

ELM/OPTIMUM/QWEST consists of the oil and gas assets of six private
corporations plus the following drilling fund partnerships and their
respective general partners:



- Optimum Qwest Q2 Limited Partnership ) (collectively the
- Optimum Qwest Q4 Limited Partnership ) "Optimum
- Optimum Qwest III Q2 Limited Partnership ) Partnerships");
- Optimum III Q4 Limited Partnership )

- Qwest Energy 2001 Limited Partnership ) (collectively the
- Qwest Energy Income Development Partnership ) "Qwest
- Qwest Energy II Limited Partnership ) Partnerships").
- Qwest Energy Development III Limited Partnership )


Rock expects to close the six private entity transactions and the
Optimum Partnerships within the next three weeks. Closing of any one of
the Optimum Partnerships is conditional on closing of all the Optimum
Partnerships unless waived by Rock.

An information circular is expected to be mailed to the limited partners
of the Qwest Partnerships in approximately 4 weeks after which partners'
meetings will be held (approximately 25 days post mailing) to vote on
the respective transactions. Closing of any one of the Qwest
Partnerships is conditional on closing of all the Qwest Partnerships
unless waived by Rock.

These transactions are a significant step in our growth strategy and
will allow Rock to increase its cash flow per share, capital budget for
2005, base production and acquire assets early in their life cycle. The
diverse nature of this asset base provides Rock with exposure to a
number of plays, and operators, across the entire basin at a time when
competition for land and plays has been intense.

Rock's next steps are to continue on with existing drilling programs as
well as to rationalize the asset base and gain higher working interests
and ultimately operatorship in certain areas. We will also continue to
pursue acquisitions (both corporate and asset) that complement our
exploration activities. Along with existing operations in the Plains
area, Rock intends to establish new core areas in West Central Alberta
and Northeast BC where our existing team of professionals have
significant experience, and have identified growth opportunities.

Rock will host a conference call to review the acquisitions on Tuesday
March 15, 2005 at 2:00 pm Mountain Standard Time. The call in numbers
are 416-695-9753 for Toronto callers and 1-866-902-2211 for all others.

OPERATIONS UPDATE

In addition to the ELM/OPTIMUM/QWEST acquisition, Rock is pleased to
provide an update of our exploration program which is beginning to
provide tangible results as highlighted below:

- Four (4.0 net) oil wells have been completed and equipped during the
quarter bringing current production to approximately 350 boe/d;

- The 100% gas well at Fleeinghorse, Alberta is expected to be tied-in
prior to the end of the first quarter adding an additional 100 boe/d of
production;

- Success at recent land sales has increased undeveloped acreage to over
13,500 net acres;

- Seismic is currently being shot and a 10 - 15 well (100% WI) drilling
program is expected to commence thereafter (subject to spring break-up
and rig availability);

The results achieved so far in the first quarter keep Rock on track to
meet its previous guidance of drilling 17 net wells, averaging 500 boe/d
of production for 2005 and exiting at 800 - 900 boe/d from its grass
roots operations.

2005 GUIDANCE

With the acquisition of the ELM/OPTIMUM/QWEST properties, and the
results of our exploration program, Rock anticipates showing significant
growth in reserves, production and cash flow for 2005. The table below
indicates reserves and acreage on a pro forma basis and compares Rock's
previous guidance (released December 16, 2004) with our new projected
results.



Rock stand alone Rock + ELM/OPTIMUM/QWEST(1)
------------------------------------------------------------------------
Dec 31, 2004 reserves:
proven 0.8 million boe 3.7 million boe
proven + probable 1.1 million boe 5.1 million boe
------------------------------------------------------------------------
March 2005 undeveloped
acreage:
gross 13,700 acres 85,700 acres
net 13,500 acres 33,100 acres
------------------------------------------------------------------------
2005 average production 500 boe/d 1,800 - 2,000 boe/d
------------------------------------------------------------------------
Exit 2005 production 800 - 900 boe/d 2,700 - 2,900 boe/d
------------------------------------------------------------------------
2005 Cash flow $2.3 million $11.7 million
(per share) ($0.25/share) ($0.71/share)
------------------------------------------------------------------------
Q4 2005 Cash $0.9 million $4.5 million
flow (per share) ($0.10/share) ($0.23/share)
------------------------------------------------------------------------
Basic shares
outstanding 9.26 million 16.5 million (average)
19.6 million (Q4)
------------------------------------------------------------------------
2005 Capital budget $11 million $16 million
------------------------------------------------------------------------
2005 Drilling (wells) 17 (17 Net) 26 (19 net)
------------------------------------------------------------------------
Total Debt (Dec 31/05) ($3 million) $16.5 million
------------------------------------------------------------------------

(1) The projected results based on an April 1, 2005 closing of the six
private corporations and four drilling fund partnerships
representing approximately 40% of the combined assets and a May 1,
2005 closing on the remaining four drilling partnership transactions
representing 60% of the combined assets (see details below).

(2) Rock + ELM/OPTIMUM/QWEST projected results based on WTI oil price of
US$40.00/bbl, AECO gas price of $6.25/mcf and Cdn/US dollar exchange
rate of 1.25.


NINE MONTH YEAR-END RESULTS

Rock Energy Inc. is also pleased to announce its results for the nine
months ended December 31, 2004. Specific oil and gas operational and
financial highlights during the year for Rock are:

- Achieved funds from operations of $917,400 ($0.10 per share) for the
nine months and $404,400 ($0.04 per share) for the final fiscal quarter,

- Realized net income of $412,700 ($0.05 per share) for the nine months
and $182,600 ($0.02 per share) for the final fiscal quarter,

- Drilled nine 100% wells (four oil, two gas, and three D&A),

- Developed a new core area in the Plains region of Alberta with a
prospect portfolio of over 25 projects,

- Grew our total proved reserves by 42 % and proved plus probable
reserves by 54%,

- Replaced production by 450% on a proven basis and 750% on a proven
plus probable basis,

- Proven plus probable working interest reserves prepared by Gilbert
Laustsen Jung Associates Ltd. in accordance with NI 51-101 as at
December 31, 2004 of 1,065,000 boe (758,000 proven) with a before tax
10% net present value of $9.9 million ($7.9 million proven),

- Spent capital of $5.9 million during the nine months ($2.7 million
land and seismic, $2.7 million drilling, and $0.5million G&A) with $3.9
million in the final fiscal quarter, and generated one year finding and
development costs of $21.52 per proven boe, and $13.89 per proven plus
probable boe,

- Realized production from our Medicine River property in central
Alberta averaging 179 boe/d for the nine months and 201 boe/d for the
final fiscal quarter,

- Moved from the TSX Venture Exchange to the TSX in July 2004,

- Strengthened our Board of Directors by adding Matt Brister and Jim
Wilson in October 2004, and

- Ended the fiscal year with 9,259,453 shares outstanding after giving
effect to the $1 million private placement on October 28, 2004.

The accomplishments of the last nine months of 2004 along with the
announced ELM/OPTIMUM/QWEST acquisition position Rock for a strong 2005.
The successful acquisition of these assets will give us a broader
foundation and an inventory of opportunity to move us toward our goal of
building Rock past 10,000 boe/d. We are looking forward to getting the
acquisitions closed over the next several months and taking the asset
base forward.

Advisory

This press release contains forward-looking statements that involve
known and unknown risks, uncertainties, assumptions and other factors,
some of which are beyond Rock's control that may cause actual results or
events to differ materially from those anticipated in such
forward-looking statements. Rock believes that the expectations
reflected in those forward-looking statements are reasonable at the time
made but no assurance can be given that these expectations will prove to
be correct and such forward-looking statements included in, or
incorporated by reference into, this press release should not be unduly
relied upon. These statements speak only as of the date of such
information, as the case may be, and may be superseded by subsequent
events. Rock does not intend, and does not assume any obligation, to
update these forward-looking statements.

This press release contains references to barrels of oil equivalent
(boe), boes maybe misleading, particularly if used in isolation. A boe
conversion of 6 mcf to 1 barrel of oil is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

Following are Rock's financial statements and notes for the nine-months
ended December 31, 2004, and Management Discussion and Analysis for the
same period.



ROCK ENERGY INC.

CONSOLIDATED BALANCE SHEETS

December 31, March 31,
2004 2004
------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 8,631,810 $ 16,293,473
Accounts receivable 484,714 302,351
Refundable deposit 5,000,000 -
Prepaids 119,154 126,989
Other assets - 127,723
------------------------------------------------------------------------
14,235,678 16,850,536
Property, plant and equipment (note 4) 9,450,555 3,313,866
Accumulated depletion and depreciation (681,225) (346,720)
------------------------------------------------------------------------
8,769,330 2,967,146
Goodwill (note 3) 2,051,967 2,051,967
------------------------------------------------------------------------
$ 25,056,975 $ 21,869,649

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 2,192,692 $ 785,582
Asset retirement obligation (note 5) 500,256 282,090
Shareholders' equity
Share capital (note 6) 21,275,627 20,281,602
Contributed surplus (note 7) 201,577 46,296
Retained earnings 886,823 474,079
------------------------------------------------------------------------
------------------------------------------------------------------------
22,364,027 20,801,977
Commitments (note 12)
------------------------------------------------------------------------
Subsequent event (note 13)
------------------------------------------------------------------------
$ 25,056,975 $ 21,869,649
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


Approved by the Board:

(signed) (signed)
Stuart G. Clark Allen J. Bey
Director Director


ROCK ENERGY INC.

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS


THE NINE MONTHS ENDED DECEMBER 31, MARCH 31,
AND YEAR ENDED 2004 2004
------------------------------------------------------------------------
Revenues:
Oil and gas revenue $ 2,178,563 $ 2,368,621
Royalties, net of Alberta Royalty
Tax Credit (465,602) (598,004)
Other income 198,469 195,192
------------------------------------------------------------------------
1,911,430 1,965,809

Expenses:
General and administrative 748,171 722,528
Operating 416,464 451,882
Interest (recovery) (108,057) 115,283
Stock-based compensation (note 7) 155,281 46,296
Depletion, depreciation, and accretion 349,411 306,567
------------------------------------------------------------------------
1,561,270 1,642,556
------------------------------------------------------------------------
Income before income taxes 350,160 323,253
Income taxes
Current (recovery) (note 8) (62,584) 69,783
------------------------------------------------------------------------
Net income for the period 412,744 253,470
Retained earnings, beginning of period 474,079 220,609
------------------------------------------------------------------------
Retained earnings, end of period 886,823 474,079
------------------------------------------------------------------------
Basic and diluted earnings per share $ 0.05 $ 0.05
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


ROCK ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

THE NINE MONTHS ENDED DECEMBER 31, MARCH 31,
AND YEAR ENDED 2004 2004
------------------------------------------------------------------------
Cash provided by (used in):
Operating
Net income for the period $ 412,744 $ 253,470
Add: Non-cash items:
Depletion, depreciation, and accretion 349,411 306,567
Stock-based compensation 155,281 46,296
------------------------------------------------------------------------
917,436 606,333
Changes in non-cash working capital 1,180,511 899,191
------------------------------------------------------------------------
2,097,947 1,505,524
Financing:
Issuance of common shares 994,025 14,800,328
Repayment of loans - (250,000)
Acquisition costs - (162,931)
Changes in non-cash working capital (79,923) (750,000)
------------------------------------------------------------------------
914,102 13,637,397
Investing:
Acquisition of property, plant
and equipment (5,933,429) (1,023,779)
Changes in non-cash working capital (4,740,283) -
------------------------------------------------------------------------
(10,673,712) (1,023,779)
------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents (7,661,663) 14,119,142
Cash and cash equivalents,
beginning of period 16,293,473 2,174,331
------------------------------------------------------------------------
Cash and cash equivalents, end of period 8,631,810 16,293,473
------------------------------------------------------------------------
------------------------------------------------------------------------

Interest paid and received:
Interest paid 937 5,812
Interest received 192,398 195,192
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


ROCK ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nine months ended December 31, 2004 and the year ended March 31, 2004

1. NATURE OF OPERATIONS

In 2004 Medbroadcast Corporation ("Medbroadcast"), a TSX Venture
Exchange listed company, entered into a licensing arrangement for all
its operating assets, raised $15 million of new equity and acquired a
private oil and gas company, Rock Energy Ltd. ("REL"). Following the
acquisition, Medbroadcast changed its name to Rock Energy Inc. (the
"Company" or "Rock") and became actively engaged in the exploration,
production and development of oil and gas in Western Canada.

2. SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements of Rock 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 Canadian
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amount of assets and
liabilities and disclosure of contingent 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.

(a) Cash and cash equivalents

Cash and cash equivalents are comprised of cash and short-term
investments with a maturity date of twelve months or less.

(b) Joint ventures

A substantial portion of the Company's oil and gas exploration and
development activities is conducted jointly with others, and
accordingly, these consolidated financial statements reflect only the
Company's proportionate interest in such activities.

(c) Property, plant and equipment

Capitalized costs: The Company follows Accounting Guideline 16, "Oil and
Gas Accounting - Full Cost" ("AcG-16") to account for its oil and
natural gas operations, whereby all costs related to the acquisition,
exploration and development of petroleum and natural gas reserves are
capitalized. Such costs include lease acquisition costs, geological and
geophysical costs, carrying charges on non-producing properties, costs
of drilling both productive and non-productive wells, the cost of
petroleum and natural gas production equipment and overhead charges
directly related to exploration and development activities. Proceeds
from the sale of oil and gas properties are applied against capital
costs, with no gain or loss recognized, unless such a sale would change
the rate of depletion and depreciation by 20% or more, in which case, a
gain or loss would be recorded.

Depletion, depreciation and amortization: The capitalized costs are
depleted and depreciated using the unit-of-production method based on
proved petroleum and natural gas reserves, as determined by independent
consulting engineers. Oil and natural gas liquids reserves and
production are converted into equivalent units of natural gas based on
relative energy content. Office furniture and equipment are recorded at
cost and depreciated on a declining balance basis using a rate of 20%.

Ceiling test: Rock calculates its ceiling test by comparing the carrying
value of oil and natural gas properties and production equipment to the
sum of undiscounted cash flows from proved reserves unproved properties.
If the carrying value is not fully recoverable, the amount of impairment
is measured by comparing the carrying value of property and equipment to
the estimated net present value of future cash flows from proved plus
probable reserves, using a risk free interest rate and expected future
prices, and unproved properties. Any excess carrying value above the net
present value of the future cash flows is recorded as a permanent
impairment.

Asset retirement obligations: The Company records the fair value of an
asset retirement obligation ("ARO") as a liability in the period in
which it incurs a legal obligation to restore an oil and gas property,
typically when a well is drilled or other equipment is put in place. The
associated asset retirement costs are capitalized as part of the
carrying amount of the related asset and depleted on a
unit-of-production method over the life of the proved reserves.
Subsequent to initial measurement of the obligations, the obligations
are adjusted at the end of each reporting period to reflect the passage
of time and changes in estimated future cash flows underlying the
obligation. Actual costs incurred on settlement of the ARO are charged
against the ARO.

(d) Income taxes

Income taxes are calculated using the liability method of tax
accounting. Temporary differences arising from the difference between
the tax basis of an asset or liability and its carrying value amount on
the balance sheet are used to calculate future income tax assets and
liabilities. Future income tax assets and liabilities are calculated
using tax rates anticipated to apply in the periods that the temporary
differences are expected to reverse.

(e) Flow-through shares

The resource expenditure deductions for income tax purposes related to
exploratory and development activities funded by flow-through share
arrangements are renounced to investors in accordance with income tax
legislation. Future tax liabilities and share capital are adjusted by
the estimated cost of the renounced tax deduction when the expenses are
renounced.

(f) Stock-based compensation

The Company grants options to purchase common shares to employees and
directors under its stock option plan. Effective April 1, 2003, the
Company prospectively adopted the Canadian accounting standard relating
to stock-based compensation and other stock-based payments as it applies
to other stock-based compensation granted to employees, officers and
directors. Under this standard, future awards are accounted for using
the fair value of accounting for stock-based compensation. Under the
fair value method, an estimate of the value of the option is determined
at the time of grant using a Black-Scholes option pricing model. The
fair value of the option is recognized as an expense and contributed
surplus over the vested life of the option.

(g) Revenue recognition

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, and production-based royalty expenses will be
recognized in the same period in which the related revenue is earned and
recorded.

Effective April 1, 2004, the Company adopted revised CICA section 1100,
"Generally Accepted Accounting Principles". Upon adoption, certain
transportation costs are being recorded as a cost of sales. This change
has been adopted prospectively.

(h) Measurement uncertainty

The amounts recorded for depletion and depreciation of property, plant
and equipment, the provision for asset retirement obligations and the
amounts used for ceiling test calculations are based on estimates of
reserves and/or future costs. The Company's reserve estimates are
reviewed annually by an independent engineering firm. The amounts
disclosed relating to fair values of stock options issued are based on
estimates of future volatility of the Company's share price, expected
lives of options, and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the impact on the
consolidated financial statements of changes in such estimates in future
periods could be material.

(i) Earnings per share

Basic per share amounts are calculated using the weighted average number
of shares outstanding during the year. Diluted per share amounts are
calculated based on the treasury stock method whereby the weighted
average number of shares is adjusted for the dilutive effect of options.

3. ACQUISITION OF ROCK ENERGY LTD.

In January 2004 Rock acquired all of the issued and outstanding shares
of Rock Energy Ltd. ("REL"), an Alberta private oil and natural gas
company, by issuing 3,875,040 common shares. The management team of REL
became the management team of Rock and two of the four Rock directors
became REL directors. As a result, for accounting purposes, REL was
identified as the acquirer.

Application of reverse takeover accounting results in the following:

(i) The Rock consolidated financial statements are a combination of REL
at historical cost and Rock at fair value.

(ii) Shareholders' equity is presented as a continuation of REL;
however, the capital structure is that of Rock.

(iii) The cost of the purchase was $15,958,356, being the aggregate of
the fair value of the equity interest in Rock deemed to be given by REL
to the shareholders of Rock and cash acquisition costs of $162,931. The
following table summarize the fair value of the assets and liabilities
of Rock:



----------------
Cash $ 14,155,719
Accounts receivable and other assets 270,975
Accounts payable (788,737)
Loans payable (250,000)
Goodwill 2,570,399
------------------------------------------------------------------------
Total $ 15,958,356
----------------
----------------


At the time of the acquisition, Medbroadcast had approximately $35
million in tax loss carryforwards and other deductions. While management
believes these loss carryforwards and other deductions have economic
value, this economic value could not be recorded as a future income tax
asset because it was not probable that the future tax asset would be
realized. Accordingly, the excess purchase price was recorded as
goodwill. As it becomes more likely than not that such future tax assets
will be realized, they will first be recognized as a reduction of
recorded goodwill until such goodwill has been reduced to $nil and
thereafter as a reduction to income tax expense.



4. PROPERTY, PLANT AND EQUIPMENT

DECEMBER 31, MARCH 31,
2004 2004
------------------------------------------------------------------------
Petroleum and natural gas properties $ 9,317,833 $ 3,238,732
Other assets 132,722 75,134
------------------------------------------------------------------------
9,450,555 3,313.866
Accumulated depletion and depreciation (681,225) (346,720)
------------------------------------------------------------------------
$ 8,769,330 $ 2,967,146
-------------------------------
-------------------------------


At December 31, 2004, petroleum and natural gas properties included
$1,940,887 (March 31, 2004, $41,208) of unproved property costs which
have been excluded from the depletable base.

During the nine months ended December 31, 2004 $402,604 (year ended
March 31, 2004, $263,108) of administrative costs relating to
exploration and development activities were capitalized as part of
property, plant and equipment.

At December 31, 2004, the Company applied the ceiling test calculation
to its petroleum and natural gas properties using expected future market
prices of: gas prices ranging from $6.60/mcf to $6.30/mcf, medium and
light oil prices ranging from $47.00/bbl to $38.63/bbl, heavy oil prices
ranging from $27.50/bbl to $25.75/bbl and natural gas liquids prices
ranging from $35.65/bbl to $29.94/bbl.

5. ASSET RETIREMENT OBLIGATION

The asset retirement obligations result from net ownership interests in
petroleum and natural gas assets including well sites, gathering systems
and processing facilities. The Company estimates the total undiscounted
amount of cash flows required to settle its asset retirement obligations
at December 31, 2004 is approximately $1,010,500 (March 31, 2004 -
$512,000), which will be incurred between 2006 and 2019. A credit
adjusted risk free rate of 8% was used to calculate the fair value of
the asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:



DECEMBER 31, MARCH 31,
2004 2004
------------------------------------------------------------------------
Balance, beginning of period $ 282,090 $ 232,414
Liabilities incurred during period 203,260 33,479
Accretion 14,906 16,197
------------------------------------------------------------------------
Balance, end of period $ 500,256 $ 282,090
-------------------------------
-------------------------------

6. SHARE CAPITAL

(a) Authorized:

Unlimited number of voting common shares, without stated par value.
300,000 preference shares, without stated par value.

(b) Common shares issued:

COMMON SHARES OF REL NUMBER AMOUNT
------------------------------------------------------------------------
Issued on incorporation 100 100
Flow-through shares 2,359,900 2,359,900
On acquisition (ii) 2,000,000 2,000,000
------------------------------------------------------------------------
Issued and outstanding on March 31, 2003 4,360,000 4,360,000
Exercise of warrants (iii) 500,000 700,000
------------------------------------------------------------------------
Issued and outstanding as at
January 7, 2004 4,860,000 $ 5,060,000
-------------------------------
-------------------------------

COMMON SHARES OF ROCK NUMBER AMOUNT
-------------------------------
Issued on business combination
of Rock and REL (i)
To former REL shareholders 3,875,040 $ 5,060,000
To former Rock shareholders 5,135,939 15,795,425
Redemption (iv) (17,827) (55,391)
Future tax effect of flow-through
share renouncements (v) (518,432)
------------------------------------------------------------------------
Issued and outstanding as at March 31, 2004 8,993,152 $ 20,281,602
Redemption (iv) (365) (448)
Issued in private placement (vi) 266,666 994,473
------------------------------------------------------------------------
Issued and outstanding as at
December 31, 2004 9,259,453 $ 21,275,627
------------------------------------------------------------------------
------------------------------------------------------------------------


(i) The number of shares has been restated to reflect the 30 for 1 share
consolidation which was effective February 18, 2004. Fractional shares
have been rounded.

(ii) In January 2003 REL acquired all of the shares of a private oil and
gas company. The cost of the purchase of $2,000,000 was assigned to
property plant and equipment, being all of the assets of the acquired
company.

(iii) In March 2003, 500,000 warrants to purchase 500,000 common shares
of REL were issued to four officers of REL. The warrants had an exercise
price of $1.40 per common share and were exercised prior to their
expiration date of January 31, 2004.

(iv) In accordance with the terms of the share consolidation,
shareholders holding 1,000 or less pre-consolidated common shares
redeemed their shares for cash based on the value of $0.1129 per
pre-consolidated share.

(v) The Company has renounced resource expenditures on flow-through
shares issued by predecessor companies. At March 31, 2004, the Company
was committed to spend $1.8 million on drilling and exploration
activities on or before January 31, 2005 to satisfy flow-through share
commitments. At December 31, 2004, all required expenditures had been
made and completed the renouncements in February 2005.

(vi) On October 28, 2004, the Company entered into a private placement
to issue 266,666 common shares at a price of $3.75 per share, or $1.0
million, to the outside directors of the Company.

As at December 31, 2004 no preference shares were outstanding.

(c) Stock options

The Company has a stock option plan (the "Plan") under which it may
grant options to directors, officers and employees for the purchase of
up to 865,617 common shares. Options are granted at the discretion of
the board of directors. The exercise price, vesting period and
expiration period are also fixed at the time of grant at the discretion
of the board of directors. The options vest yearly in one-third tranches
beginning on the first anniversary of the grant date and expire one year
after vesting. The following table summarizes the status of the
Company's stock option plan as at December 31, 2004 and March 31, 2004
and changes during the period ended on those dates:



DECEMBER 31, 2004 MARCH 31, 2004
------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Options Exercise Options Exercise
(000s) Price ($) (000s) Price ($)
------------------------------------------------------------------------
Outstanding at
beginning of period 418,848 $ 3.39
Granted 125,500 $ 3.79 418,848 $ 3.39
Cancelled (11,961) $ 3.39
------------------------------------------------------------------------
Outstanding at
end of period 532,387 $ 3.49 418,848 $ 3.39
------------------------------------------------------------------------
------------------------------------------------------------------------


(d) Per share amounts

The weighted average number of common shares outstanding during the nine
months ended December 31, 2004 of 9,054,879 (year ended March 31, 2004 -
4,790,196) was used to calculate earnings per share amounts. To
calculate diluted common shares outstanding, the treasury method was
used. Under this method, in-the-money options are assumed exercised and
the proceeds used to repurchase shares at the year end date of December
31, 2004. As at December 31, 2004, an additional 56,941 (March 31, 2004
- 52,652) common shares were used to calculate diluted earnings per
share.

7. STOCK-BASED COMPENSATION

Options granted to both employees and non-employees after March 31, 2003
are accounted for using the fair value method. The fair value of common
share options granted in the nine months ended December 31, 2004 was
estimated to be $120,000 (year ended March 31, 2004 - $326,000) as at
the grant date using a Black-Scholes option pricing model and the
following assumptions:



Risk free interest rate 4%
Expected life 3 year average
Expected volatility 30%
Expected dividend yield 0%


The estimated fair value of the options is amortized to expense and
credited to contributed surplus over the option vesting period on a
straight-line basis.

8. INCOME TAXES

The provision for income taxes in the consolidated statements of income
and retained earnings varies from the amount that would be computed by
applying the expected tax rate to net income before income taxes. The
expected tax rate used was 38.62% (March 31, 2004: 38.12%). The
principal reasons for differences between such "expected" income tax
expense and the amount actually recorded are as follows:



DECEMBER 31, MARCH 31,
2004 2004
------------------------------------------------------------------------
Net income before income taxes $ 350,160 $ 253,470
Statutory income tax rate 38.62% 38.12%
------------------------------------------------------------------------
Expected income taxes $ 135,232 $ 96,623
Add (deduct):
Stock-based compensation 59,970 17,648
Non-deductible crown charges 52,830 93,952
Resource allowance (30,425) (8,411)
Change in valuation allowance (217,607) (130,029)
------------------------------------------------------------------------
------------------------------------------------------------------------
Provision for income taxes $ - $ 69,783
Current tax recovery of prior period (62,584) -
------------------------------------------------------------------------
Provision for income taxes $ (62,584) $ 69,783
------------------------------------------------------------------------

Future income tax assets or liabilities recognized on the consolidated
balance sheets are comprised of temporary differences. These temporary
differences are summarized as follows:


DECEMBER 31, MARCH 31,
2004 2004
------------------------------------------------------------------------
Loss carryforwards $ 11,451,008 $ 11,183,647
Property, plant and equipment 1,579,570 1,751,356
Non-coterminous year ends (559,177) -
Share issuance costs 471,720 511,449
Asset retirement obligation 178,191 (107,533)
------------------------------------------------------------------------
Calculated future income tax asset 13,121,312 13,338,919
Valuation allowance (13,121,312) (13,338,919)
------------------------------------------------------------------------
Future income taxes $ - $ -
------------------------------------------------------------------------
------------------------------------------------------------------------


At December 31, 2004, Rock and its subsidiary have tax pools aggregating
$ 47.0 million (March 31, 2004 - $35.7 million) available for deduction
against future taxable income of which $ 27.9 (March 31, 2004 - $27.4
million) are non-capital losses. The non-capital losses expire as
follows:



2005 $ 4.3
2006 3.0
2007 6.9
2008 8.7
2009 3.9
2010 0.4
2011 0.7
-------------------
$ 27.9
-------------------
-------------------


9. FINANCIAL INSTRUMENTS

Rock's financial instruments included in the consolidated balance sheets
are comprised of cash and cash equivalents, accounts receivable, other
deposits, accounts payable and accrued liabilities and income taxes
payable. The fair values of these financial instruments approximate
their carrying amount due to the short-term nature of the instruments.

10. CREDIT RISK

A substantial portion of Rock's accounts receivable are with customers
in the oil and gas industry and are subject to normal industry credit
risks.

11. RELATED PARTY TRANSACTIONS

During the nine months ended December 31, 2004, there were no related
party transactions. During the year ended March 31, 2004, Rock:

(a) paid consulting fees of $77,430 to a director and former officer,
and

(b) paid interest, fees and loan principal of $237,638 to a shareholder.

12. COMMITMENTS

Obligations with a fixed term are as follows:



------------------------------------------------------------------------
2005 2006 2007 2008 2009
------------------------------------------------------------------------
Lease of office premises $ 154,569 $ 128,807 0 0 0
------------------------------------------------------------------------


13. SUBSEQUENT EVENT

On March 14, 2005 the Company agreed to acquire from 14 different
entities petroleum and natural gas properties for aggregate
consideration of 10.3 million shares and $25.4 million. The cash will
come out of the existing cash balances and expected borrowings from a
$25 million facility from a Canadian chartered bank currently being
finalized. The transactions are expected to close before May 31, 2005
and will be subjective to purchase price adjustments.

ROCK ENERGY INC.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Rock Energy Inc. ("Rock" or the "Company") is a public energy company
engaged in the exploration for and development and production of crude
oil and natural gas, primarily in Western Canada. Rock's corporate
strategy is to grow and develop an oil and gas exploration and
production company through internal operations and acquisitions. Rock's
philosophy is to operate and have a high working interest in the
majority of its production base.

Rock evaluates its performance based on net income, operating netback,
funds from operations and finding and development costs. Funds from
operations is used by the Company to analyze operations, performance,
leverage and liquidity. Operating netback is a benchmark used in the oil
and gas industry to measure the contribution of the oil and natural gas
operations following the deduction of royalties, transportation costs,
and operating expenses. Finding and development cost is another
benchmark used in the oil and gas industry to measure the capital costs
incurred by the Company to find and bring reserves on stream.

While there is greater competition in the oil and gas industry for
resources, both technical personnel and third party services, and
capital financing, the Company is addressing these issues through the
addition of personnel with the expertise to develop opportunities on
existing lands and control both operating and administrative cost
structures. Rock also seeks to obtain the best commodity price available
based on the quality of our produced commodities.

The following discussion and analysis is dated March 14, 2005 and is
management's assessment of Rock Energy Inc.'s historical, financial and
operating results, together with future prospects, and should be read in
conjunction with the audited consolidated financial statements of Rock
Energy Inc. for the nine months ended December 31, 2004. During the
year, Rock changed its year end from March 31 to December 31.

BASIS OF PRESENTATION

Financial measures referred to in this discussion, such as funds from
operations and funds from operations per share, are not prescribed by
generally accepted accounting principles ("GAAP"). Funds from operations
is a key measure that demonstrates the ability to generate cash flow
necessary to fund future growth through capital investment. These non
GAAP financial measures may not be comparable to similar measures
presented by other companies. These financial measures are not intended
to represent operating profits for the period nor should they be viewed
as an alternative to cash provided by operating activities, net income
or other measures of financial performance calculated in accordance with
GAAP. Funds from operations per share is calculated using the same share
basis which is used in the determination of net income per share.

Barrels of oil equivalent ("boe") may be misleading, particularly if
used in isolation. A boe conversion ratio of six mcf to one barrel
("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. All boe conversions in this report are derived by
converting natural gas to oil in the ratio of six thousand cubic feet of
gas to one barrel of oil. Certain financial values are presented on a
boe basis and such measurements may not be consistent with those used by
other companies.

This discussion contains forward-looking statements that involve risk
and uncertainties. Such information, although considered reasonable by
management at the time of preparation, may prove to be incorrect and
actual results may differ materially from those anticipated in the
statements made.

All financial amounts are in Canadian dollars unless otherwise noted.



Production

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
Gas (mcf/d) 525 507 665 542 23%
Oil (bbl/d) 74 73 71 89 (20%)
NGL (bbl/d) 18 19 19 20 (5%)
boe/d (6:1) 179 177 201 199 1%
----------------------------------------------------
----------------------------------------------------


Natural production declines during the year were offset by the
re-completed non-operated Nordegg gas well that was on production in
July 2004 (the Company agreed to equalize into this well late in the
year). Additional production declines are expected from Medicine River
as new capital is not planned for this area. However new production from
the Plains core area is expected as we tie-in the production from the
grass roots drilling program conducted in the last quarter of the year.



Product Prices

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
REALIZED PRODUCT
PRICES
Gas ($/mcf) 6.78 6.17 6.77 5.35 26%
Oil ($/bbl) 48.53 37.03 55.90 35.25 59%
NGL ($/bbl) 42.53 33.68 45.09 34.81 29%
----------------------------------------------------
boe (6:1) 44.14 36.64 46.48 33.79 38%
----------------------------------------------------
----------------------------------------------------

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
AVERAGE BENCHMARK
PRICES
Gas - NYMEX Daily
Spot (US$/mcf) 5.98 5.31 6.35 5.09 25%
Gas - AECO C Daily
Spot ($/mcf) 6.95 6.56 6.93 6.07 14%
Oil - WTI Cushing
(US$/bbl) 43.49 31.36 48.28 31.18 55%
Oil - Edmonton Light
($/bbl) 54.85 41.80 57.71 39.56 46%
US$/Cdn$ exchange
rate 0.773 0.740 0.819 0.760 8%
----------------------------------------------------


All of Rock's production is sold at spot price contracts; however, about
half of our natural gas production is tied to aggregator contracts which
contain a monthly pricing mechanism. Product prices for the fiscal year
averaged $44.14 per boe. Prices on a boe basis during the final fiscal
quarter were about 5% higher than the yearly average; and, 34% higher
than the same fiscal quarter of 2003.

Revenue

The vast majority of the Company's revenue is derived from oil and gas
operations. Other income represents interest income earned from cash
invested in term deposits.



Oil & gas revenue

--------------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
--------------------------------------------------------
Gas $ 978,217 $ 988,433 $416,123 $264,294 57%
Oil $ 990,708 $1,148,574 $366,865 $286,165 28%
NGL $ 209,638 $ 231,614 $ 80,302 $ 62,728 28%
--------------------------------------------------------
$2,178,563 $2,368,621 $863,290 $613,187 41%
--------------------------------------------------------
Other revenue $ 198,469 $ 195,192 $ 66,299 $ 16,118 311%
--------------------------------------------------------
--------------------------------------------------------


Oil and natural gas revenue increased approximately 41% in the final
fiscal quarter of 2004 from the same fiscal quarter of 2003, which is
consistent with the increase in price realizations and slight increase
in production. In the fiscal period ended December 31, 2004, the Company
did not enter into any hedges, fixed price or volume arrangements.

Other interest income increased 311% in the final fiscal quarter of 2004
as it included interest received from invested funds generated from the
January 2004 $15 million equity financing and from the $1 million
private placement common share financing completed in the final quarter.
Interest income is expected to decline over the next fiscal year as our
capital program will reduce cash balances.



Royalties

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
Royalties $465,602 $598,004 $69,118 $146,082 (53)%
As a percentage of
oil and gas revenue 21.4% 25.2% 8.02% 23.8% (66)%
Per boe (6:1) $ 9.43 $ 9.25 $ 3.73 $ 8.05 (54)%
----------------------------------------------------
----------------------------------------------------


Royalties for the final fiscal quarter of 2004 were lower on a per boe
and percentage of revenue basis compared to the same quarter in the
previous fiscal year due to a one time favourable Alberta Energy crown
adjustment relating to 2003 and 2004 production. All royalties for the
period were incurred in Alberta.



Operating Expenses

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
Operating expenses $416,464 $451,882 $157,254 $93,614 68%
Per boe (6:1) $ 8.44 $ 6.99 $ 8.48 $ 5.16 64%
----------------------------------------------------
----------------------------------------------------


Included in operating expenses for both the nine months ended and three
months ended December 31, 2004 are transportation costs at $0.34 per boe
and $0.89 per boe, respectively. Due to changes in marketing
arrangements for our oil which resulted in a change in the timing of
transfer of title of the commodity, separately recording transportation
costs became applicable for the final fiscal quarter of the year. The
remaining increase in operating costs for the final fiscal quarter of
2004 relates to unexpected repairs and maintenance on a pump at one of
the producing wells in Medicine River and higher production costs at the
recently re-completed Nordegg well at Medicine River. Operating costs on
a per boe basis for the nine months ended December 31, 2004 also
increased due to the declining production base and fixed portion of
costs associated with operations. Going forward, operating expense on a
per boe basis for the Medicine River property have been budgeted to
increase primarily due to natural production declines.



General and Administrative (G&A) Expense

------------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
------------------------------------------------------
Gross $1,150,774 $985,637 $519,287 $267,014 94%
Per boe (6:1) $ 23.32 $ 15.25 $ 28.02 $ 14.71 90%
Capitalized $ 402,603 $263,108 $158,114 $121,211 30%
Per boe (6:1) $ 8.16 $ 4.07 $ 8.53 $ 6.68 28%
Net $ 748,171 $722,529 $361,173 $145,803 148%


Per boe (6:1) $ 15.16 $ 11.18 $ 19.49 $ 8.03 143%
------------------------------------------------------
------------------------------------------------------


The Company continues to plan for future growth with the move into new
office space in October 2004 and the addition of personnel needed to
both the technical team and administrative team to achieve and control
the planned growth. With the Company moving to the Toronto Stock
Exchange in July 2004, additional fees were incurred thereby increasing
the gross and net amounts. The Company continues to capitalize certain
G&A expenses based on personnel involved in the exploration and
development initiatives, including certain salaries and related overhead
costs. G&A expenses are expected to rise in 2005 on an absolute basis as
the staff compliment is higher for the entire year, but fall on a per
boe basis as overall production increases.



Interest Expense

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
Interest expense
(recovery) $(108,057) $115,283 $ 231 $ 67,980 (100)%
Per boe (6:1) $ (2.19) $ 1.78 $ 0.00 $ 3.75 (100)%
----------------------------------------------------


Interest expense was recovered as a result of a reversal of an accrual
made in the prior fiscal period in conjunction with flow-through shares
issued. A filing position maintained by the Company was ultimately
accepted by Canada Revenue Agency resulting in the recovery.



Depletion, Depreciation, and Accretion (DD&A)

----------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
----------------------------------------------------
D&D expense $334,505 $290,370 $157,528 $ 77,109 104%
Per boe (6:1) $ 6.78 $ 4.49 $ 8.50 $ 4.25 100%
Accretion expense $ 14,906 $ 16,197 $ 6,013 $ 3,730 61%
Per boe (6:1) $ 0.30 $ 0.25 $ 0.32 $ 0.21 52%
----------------------------------------------------
----------------------------------------------------


New reserves were added for some of the successful wells drilled in the
period - proved reserves, used in the depletion calculation, increased
by 42%, while probable reserves increased by 94%. As future capital is
spent to tie-in the new wells and put production on stream, it is
expected that some of the probable reserves will move to proved and
reduce the depletion rate in the future.

The Company's asset retirement obligation ("ARO") represents the present
value of estimated future costs to be incurred to abandon and reclaim
the Company's wells and facilities. The discount rate used is 8%.

Accretion represents the change in the time value of the asset
retirement obligation ("ARO"). The underlying ARO may be increased over
a period based on new obligations incurred from drilling wells or
constructing facilities. Similarly this obligation can also be reduced
as a result of abandonment work undertaken and reducing future
obligations. During the nine months ended December 31, 2004 capital
programs increased the underlying ARO by $203,260 (March 31, 2004:
$33,479).

Income Tax

Rock does not have current income tax payable and does not expect to pay
current taxes in the near future as the Company has, on a consolidated
basis, resource pools and loss carryforwards available of approximately
$47.0 million as set out below.



CEE $ 4.4 million
CDE $ 2.2 million
COGPE $ 3.8 million
UCC $ 3.1 million
Loss carryforwards $ 33.5 million


No benefit has been recognized on the financial statements for the tax
assets in excess of book basis and a valuation allowance has been taken
as a result. With greater certainty on the utilization of the pools in
the future, the Company will recognize the benefit on the financial
statements.



Funds from Operations and Net Income

---------------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
---------------------------------------------------------
Funds from
operations $917,436 $606,333 $404,397 $105,465 283%
Per boe (6:1) $ 18.59 $ 9.38 $ 21.82 $ 5.81 276%
-----------------------------------------------------------------------
Per share
(shares
restated to
affect 30 for
1 share
consolidation) $ 0.10 $ 0.13 $ 0.04 $ 0.03 33%
Diluted $ 0.10 $ 0.13 $ 0.04 $ 0.03 33%
-----------------------------------------------------------------------
Net income $412,744 $253,470 $182,577 $ 25,203 624%
Per boe (6:1) $ 8.36 $ 3.92 $ 9.85 $ 1.39 609%
-----------------------------------------------------------------------
Per share
(shares
restated to
affect 30 for
1 share
consolidation) $ 0.05 $ 0.05 $ 0.02 $ 0.01 100%
Diluted $ 0.05 $ 0.05 $ 0.02 $ 0.01 100%
-----------------------------------------------------------------------
Weighted average
shares
outstanding,
basic 9,054,879 4,790,196 9,180,697 3,627,850 153%
Diluted 9,111,820 4,842,848 9,243,296 3,627,850 155%
---------------------------------------------------------
---------------------------------------------------------


Per share amounts have been restated for all periods for the 30 for 1
share consolidation that occurred in February 2004. Weighted average
shares outstanding increased for the fiscal year 2004 and the final
fiscal quarter of 2004 due to the private placement equity issue
completed in October 2004.

Funds from operations for the nine months ended December 31, 2004 were
$0.9 million or $0.10 per share. Funds from operations for the final
fiscal quarter of 2004 of $0.4 million or $0.04 per share improved 33%
over the same period last year primarily due to higher production
income, lower royalties and interest expense recovery. These positive
impacts were partially offset by higher operating costs and higher G&A
expenses.

Net income for the nine months ended December 31, 2004 was $0.4 million
or $0.05 per share. Net income for the final fiscal quarter of 2004 of
$0.2 million or $0.02 per share was 624% higher than the same fiscal
quarter of 2003 due to the higher production income, and interest and
income tax recovery.



Capital Expenditures

-----------------------------------------------------------
9 MONTHS 12 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED QUARTERLY
12/31/04 03/31/04 12/31/04 12/31/03 CHANGE
-----------------------------------------------------------
Land $2,157,443 $ 53,889 $1,102,522 $ 219 n/a
Seismic 577,112 280,311 274,500 67,755 305%
Exploration
drilling &
completion 1,173,612 - 702,264 - -
Development
drilling &
completion 1,041,351 358,590 1,041,351 (8,590) n/a
Capitalized
G&A 402,603 263,108 158,114 121,211 30%
-----------------------------------------------------------------------
Total
exploration
and
development $5,352,121 $ 955,898 $3,278,751 $180,595 1715%
Facilities 523,721 - 523,721 - n/a
-----------------------------------------------------------------------
Total
operations $5,875,842 $ 955,898 $3,802,472 $180,595 2006%
Office
equipment $ 57,587 67,881 49,750 12,030 313%
-----------------------------------------------------------
Total $5,933,429 $1,023,779 $3,852,222 $192,625 1899%
-----------------------------------------------------------
-----------------------------------------------------------


Capital expenditures on oil and gas operations for the nine months ended
December 31, 2004 include the drilling of 2.0 (2.0 net) gas wells, 4.0
(4.0 net) oil wells and 3.0 (3.0 net) dry and abandoned wells. Seven of
the wells were drilled in Saskatchewan and the remaining two in Alberta.
At December 31, 2004, no wells had been tied-in to facilities, but work
had begun to equip and bring the six successful wells on stream. Land
acquisitions resulted in the addition of 13,573 acres, 5,975 acres in
Saskatchewan and 7,598 acres in Alberta.

Finding and Development costs

The following table summarizes Rock's finding and development costs for
the period ended December 31, 2004.



TOTAL PROVED FINDING AND DEVELOPMENT COSTS 2004

Capital expenditures ($000) $ 5,876
Reserve additions (Mboe) 273
Total proven finding and development costs ($/boe) $ 21.52
-------------------------------------------------------------------------

TOTAL PROVED + PROBABLE FINDING AND DEVELOPMENT COSTS
Capital expenditures ($000) $ 5,876
Reserve additions (Mboe) 423
Total proven + probable finding and development costs ($/boe) $ 13.89


Finding and development costs are skewed higher by a land and seismic
component that represented about half of the capital spending for the
nine months ended December 31, 2004. Land and seismic spending was high
as percentage of capital as the Company was initiating its grass roots
exploration program. Finding and development costs do not include future
development costs from the Company's independent reserve report.

Liquidity and Capital Resources

Our net working capital position as at December 31, 2004 totaled $12.0
million ($16.0 million at March 31, 2004), consisting mostly of term
deposits, cash and refundable deposits. The decrease over March 31, 2004
levels primarily reflects the implementation of our grass roots
exploration and development program with the drilling of nine (net -
nine) wells. Rock had no debt at December 31, 2004 ($nil at March 31,
2004), other than trade payables of $2.2 million ($0.8 million at March
31, 2004).

Our current risked capital spending plan for 2005 is approximately $11.0
million on existing properties. Of this amount about $7.6 million or 68%
is allocated to drilling and completions, including tie-ins and
well-site facilities to bring production on stream. We were successful
in acquiring tracts of land and have identified a number of prospects to
continue our exploration and development program. This spending is split
evenly between the first and second half of the calendar year. The
balance of the spending plan is allocated to potential land acquisitions
and seismic programs as we work to further build our inventory of
prospects. Given our current working capital position and anticipated
cash flow, we expect to fund this spending plan without utilizing
outside sources of capital.

Rock announced on March 14, 2005, it has agreed to acquire non-operated
petroleum and natural gas properties from 14 different entities for
aggregate consideration of 10.3 million shares and $25.4 million. The
cash will come out of the existing balances and expected borrowings from
a $25 million facility currently being finalized with a Canadian
chartered bank. In aggregate, the properties are expected to be produce
approximately 1,250 boe/day in March 2005 and produce 2,000 boe/day in
December 2005. The reserves were evaluated by Gilbert Laustsen Jung and
Associates Ltd. effective January 1, 2005, totaling 2.899 million boe on
a proved basis and 4.058 million on a proved plus probable basis.
Included in the acquisitions are approximately 19,600 net (72,000 gross)
acres of undeveloped land and seismic data. Following closing of all the
transactions Rock expects to have $14.5 million of total debt. Currently
identified capital spending plans on the acquired properties total $5.0
million, which will be funded through the new borrowing facility. Rock
intends to rationalize the working interests in these properties through
acquisitions, divestitures and swapping of interests whereby Rock will
have higher working interests in the remaining properties and ultimately
work towards operating these properties. Through the rationalization
process, Rock plans to establish two new core areas in West Central
Alberta and Northeast British Columbia along with the Corporation's
existing Plains core area.

At December 31, 2004 and to date, Rock had 9,259,453 common shares
outstanding and 532,387 stock options with an average exercise price of
$3.49 per share.

Selected Quarterly Data

The following table provides selected quarterly information for Rock.



------------------------------------------------------------------------
3 MONTHS 3 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED
12/31/04 09/30/04 06/30/04 03/31/04
(UNAUDITED) (UNAUDITED) (UNAUDITED) (UNAUDITED)
------------------------------------------------------------------------
Production (boe/d) 201 165 171 186
Oil and gas revenues $ 863,290 $ 653,422 $ 661,851 $ 666,707
Price realizations
($/boe) $ 46.48 $ 42.90 $ 42.54 $ 39.48
Royalties ($/boe) $ 3.73 $ 14.70 $ 11.08 $ 11.16
Operating expense
($/boe) $ 7.59 $ 9.15 $ 7.67 $ 6.56
Field netback ($/boe) $ 34.27 $ 19.05 $ 23.79 $ 21.76
Net G&A expense $ 361,173 $ 226,623 $ 160,375 $ 211,021
Stock-based compensation $ 58,279 $ 50,708 $ 46,294 $ 46,296
Cash flow from
operations $ 404,397 $ 236,672 $ 276,367 $ 301,161
Per share
(basic & diluted) $ 0.04 $ 0.03 $ 0.03 $ 0.04
Net income $ 182,577 $ 85,047 $ 145,120 $ 158,282
Per share
(basic & diluted) $ 0.02 $ 0.01 $ 0.02 $ 0.02
Capital expenditures $3,852,222 $1,062,525 $1,018,682 $ 318,888
------------------------------------------------------------------------
------------------------------------------------------------------------

AS AT AS AT AS AT AS AT
12/31/04 09/30/04 06/30/04 03/31/04
------------------------------------------------------------------------
Working capital ($000) $ 12,043 $ 14,497 $ 15,323 $ 16,065
------------------------------------------------------------------------


------------------------------------------------------------------------
3 MONTHS 3 MONTHS 3 MONTHS 3 MONTHS
ENDED ENDED ENDED ENDED
12/31/03 09/30/03 06/30/03 03/31/03
(UNAUDITED) (UNAUDITED) (UNAUDITED) (UNAUDITED)
------------------------------------------------------------------------
Production (boe/d) 192 174 155 185
Oil and gas revenues $ 613,187 $ 564,491 $ 524,146 $ 782,649
Price realizations
($/boe) $ 34.78 $ 35.25 $ 37.13 $ 47.40
Royalties ($/boe) $ 8.36 $ 9.81 $ 7.54 $ 12.66
Operating expense
($/boe) $ 5.24 $ 7.91 $ 8.56 $ 9.60
Field netback ($/boe) $ 21.18 $ 17.53 $ 21.03 $ 25.14
Net G&A expense $ 145,803 $ 190,526 $ 175,093 $ 146,779
Stock-based compensation $ nil $ nil $ nil $ nil
Cash flow from
operations $ 105,465 $ 88,383 $ 111,324 $ 279 826
Per share
(basic & diluted) $ 0.03 $ 0.03 $ 0.04 $ 0.09
Net income $ 25,203 $ 12,178 $ 57,807 $ 220,609
Per share
(basic & diluted) $ 0.01 $ 0.00 $ 0.02 $ 0.07
Capital expenditures $ 192,625 $ 386,392 $ 125,874 $ 26,961
------------------------------------------------------------------------
------------------------------------------------------------------------

AS AT AS AT AS AT AS AT
12/31/03 09/30/03 06/30/03 03/31/03
------------------------------------------------------------------------
Working capital ($000) $ 2,881 $ 2,377 $ 2,675 $ 2,613
------------------------------------------------------------------------

Note: Quarterly information has been re-stated for the retroactive
adoption of the ARO accounting standard.


Contractual Obligations

In the course of its business, the Company enters into various
contractual obligations including the following:

- royalty agreements

- processing agreements

- right of way agreements

- lease obligations for office premises.



Obligations with a fixed term are as follows:

------------------------------------------------------------------------
2005 2006 2007 2008 2009
------------------------------------------------------------------------
Lease of office premises $ 154,569 $ 128,807 0 0 0
------------------------------------------------------------------------


Outstanding Share Data

There are no changes to Rock's outstanding share data at the date of
this report.

Off Balance Sheet Arrangements

Rock does not have any special purpose entities nor is it party to any
arrangement that would be excluded from the balance sheet.

Critical Accounting Estimates

Rock's financial statements have been prepared in accordance with
Canadian generally accepted accounting principles (GAAP). A
comprehensive discussion of our significant accounting policies is
contained in Note 2 to the audited consolidated financial statements.
These accounting policies are subject to estimates and key judgments
about future events, many of which are beyond our control. The following
is a discussion of the accounting estimates that are critical to the
financial statements.

Oil and Gas Accounting - Reserves Recognition Rock retained independent
petroleum engineering consultants Gilbert, Laustsen, Jung Associates
Ltd. to evaluate our oil and natural gas reserves, prepare an evaluation
report, and report to the Company's Reserves Committee. The process of
estimating oil and natural gas reserves is subjective and involves a
significant number of decisions and assumptions in evaluating available
geological, geophysical, engineering and economic data. These estimates
will change over time as additional data from ongoing development and
production activities becomes available and as economic conditions
affecting oil and natural gas prices and costs change. Reserves can be
classified as proved, probable or possible with decreasing levels of
certainty to the likelihood that the reserves will be ultimately
produced.

Oil and Gas Accounting - Full Cost Accounting Under the full cost method
of accounting for exploration and development activities, all costs
associated with these activities are capitalized. The aggregate net
capitalized costs and estimated future abandonment costs, less estimated
salvage values, is amortized using the unit-of-production method based
on estimated proved oil and gas reserves resulting in a depletion
expense. The depletion expense is most affected by the estimate of
proved reserves and the cost of unproved properties. Unproved costs are
reviewed quarterly to determine if proved reserves have been
established, at which point the associated costs are included in the
depletion calculation. Changes to any of these estimates may affect
Rock's earnings.

Under the full cost method of accounting, the Company's investment in
oil and gas assets is evaluated at least annually to consider whether
the investment is recoverable and the carrying amount does not exceed
the value of the properties, the "ceiling test". The carrying value of
oil and natural gas properties and production equipment is compared to
the sum of undiscounted cash flows expected to result from Rock's proved
reserves. If the carrying value is not fully recoverable, the amount of
impairment is measured by comparing the carrying value of property and
equipment to the estimated net present value of future cash flows from
proved plus probable reserves using a risk free interest rate. Any
excess carrying value above the net present value of the future cash
flows is recorded as a permanent impairment. Reserve, revenue, royalty
and operating cost estimates and the timing of future cash flows are all
critical components of the ceiling test. Revisions of these estimates
could result in a write down of the carrying amount of oil and gas
properties.

Asset Retirement Obligations The Company recognizes the estimated fair
value for an asset retirement obligation ("ARO") in the period in which
it is incurred as a liability, and records a corresponding increase in
the carrying value of the related asset. The future asset retirement
obligation is an estimate based on the Company's ownership interest in
wells and facilities and reflects estimated costs to complete the
abandonment and reclamation as well as the estimated timing of the costs
to be incurred in future periods. Estimates of the costs associated with
abandonment and reclamation activities require judgment concerning the
method, timing and extent of future retirement activities. The
capitalized amount is depleted on a unit-of-production method over the
life of the proved reserves. The liability amount is increased each
reporting period due to the passage of time and this accretion amount is
charged to earnings in the period. Actual costs incurred on settlement
of the ARO are charged against the ARO. Judgments affecting current and
annual expense are subject to future revisions based on changes in
technology, abandonment timing, costs, discount rates and the regulatory
environment.

Stock-based Compensation Stock options issued to employees and directors
under the Company's stock option plan are accounted for using the fair
value method of accounting for stock-based compensation. The fair value
of the option is recognized as stock-based compensation expense and
contributed surplus over the vesting period of the option. Stock-based
compensation expense is determined on the date of an option grant using
a Black-Scholes option pricing model. A Black-Scholes pricing model
requires the estimation of several variables including estimated
volatility of Rock's stock price over the life of the option, estimated
option forfeitures, estimated life of the option, estimated risk free
rate and estimated dividend rate. A change to these estimates would
alter the valuation of the option and would result in a different
related stock-based compensation expense.

Business Risks

Rock is exposed to a number of business risks, some of which are beyond
its control like all companies in the oil and gas exploration and
production industry. These risks can be categorized as operational,
financial and regulatory.

Operational risks include generating, finding and developing, and
acquiring oil and gas reserves on an economical basis (including
acquiring land rights or gaining access to land rights), reservoir
production performance, marketing, production, hiring and retaining
employees and accessing contract services on a cost effective basis. We
attempt to mitigate these risks by employing highly qualified staff and
operating in areas where employees have expertise. In addition we
outsource certain activities to be able to leverage on industry
expertise, without having the burden of hiring full time staff given the
current scope of operations. Typically the Company has outsourced the
marketing functions. Rock is attempting to acquire oil and gas
operations; however Rock will be competing against many other companies
for such operations many of which will have greater access to resources.
As a small company, gaining access to contract services may be difficult
given the high activity levels the industry has been experiencing, but
we will attempt to mitigate this risk by utilizing existing
relationships.

Financial risks include commodity prices, the Canadian/US exchange rate
and interest rates, all of which are largely beyond the Company's
control. Currently we have not used any financial instruments to
mitigate these risks. We would consider using these financial
instruments depending on the operating environment. The Company also
will require access to capital. Currently Rock has no long-term debt in
place but intends to use its debt capacity in the future in conjunction
with the announced acquisitions. We intend to use prudent levels of debt
to fund capital programs based on the expected operating environment. We
also intend to access equity markets to fund opportunities, however the
ability to access these markets will be determined by many factors, many
of which will be beyond the control of the Company.

Rock is subject to various regulatory risks, principally environmental
in nature. The Company has put in place a corporate safety program and a
site-specific emergency response program to help manage these risks. The
Company hires third party consultants to help develop and manage these
programs and help Rock comply with current environmental legislation.

Reserves

Rock's reserves have been independently evaluated by Gilbert, Laustsen,
Jung Associates Ltd. ("GLJ"). This is the first year GLJ has evaluated
these reserves. The reserves as at December 31, 2004 have been evaluated
in accordance with NI 51-101. The previous reserve report at March 31,
2004 followed this standard as well The following tables provide a
reconciliation of the reserves between the two reserve reports. NI
51-101 requires reserves to be reconciled on a net basis after royalty
interest ("net interest"). Below we have reported reserves on both a
working interest, before royalty interests, and net interest basis.

Reserves Reconciliation The following table is a reconciliation of
Rock's "Gross Interest" reserves at year-end December 31, 2004 using
GLJ's pricing and cost estimates.



RECONCILIATION OF COMPANY GROSS INTEREST RESERVES BY PRINCIPAL PRODUCT
TYPE FORECAST PRICES AND COSTS

OIL AND NGL GAS
--------------------------- ---------------------------
PROVED PROVED
PLUS PLUS
PROVED PROBABLE PROBABLE PROVED PROBABLE PROBABLE
FACTORS (MBBL) (MBBL) (MBBL) (MMCF) (MMCF) (MMCF)
--------------------------- ---------------------------
March 31, 2004 326 113 439 1,250 268 1,518
Extensions 186 160 346 650 573 1,223
Technical
revisions (35) (82) (117) 82 (148) (66)
Discoveries
Production (25) - (25) (144) - (144)
December 31, 2004 452 191 643 1,838 693 2,531
--------------------------- ---------------------------

EQUIVALENT BOE
---------------------------
PROVED
PLUS
PROVED PROBABLE PROBABLE
FACTORS (MBOE) (MBOE) (MBOE)
---------------------------
March 31, 2004 534 158 692
Extensions 294 257 551
Technical revisions (21) (108) (129)
Discoveries
Production (49) - (49)
December 31, 2004 758 307 1,065
---------------------------

Note:

(1) Figures may not add due to rounding.

The following table is a reconciliation of Rock' s "Net Interest"
reserves at year-end December 31, 2004 using GLJ's pricing and cost
estimates.

RECONCILIATION OF COMPANY NET INTEREST RESERVES BY PRINCIPAL PRODUCT
TYPE FORECAST PRICES AND COSTS


OIL AND NGL GAS
--------------------------- ---------------------------
PROVED PROVED
PLUS PLUS
PROVED PROBABLE PROBABLE PROVED PROBABLE PROBABLE
FACTORS (MBBL) (MBBL) (MBBL) (MMCF) (MMCF) (MMCF)
--------------------------- ---------------------------
March 31, 2004 271 90 361 960 205 1,165
Extensions 158 139 297 531 497 1,028
Technical
revisions (33) (63) (96) 40 (113) (73)
Discoveries
Production (19) - (19) (104) - (104)
December 31, 2004 377 166 544 1,427 589 2,016
--------------------------- ---------------------------

EQUIVALENT BOE
---------------------------
PROVED
PLUS
PROVED PROBABLE PROBABLE
FACTORS (MBOE) (MBOE) (MBOE)
---------------------------
March 31, 2004 431 124 555
Extensions 247 222 469
Technical revisions (26) (82) (108)
Discoveries
Production (36) - (36)
December 31, 2004 615 264 880
---------------------------

Note:

(1) Figures may not add due to rounding.


Reserves and Net Present Value (Forecast Prices and Costs)

The following tables summarize Rock's remaining oil and gas reserve
volumes along with the value of future net revenue utilizing GLJ's
pricing and cost estimates.



RESERVES

OIL AND NGL GAS
GROSS NET GROSS NET
RESERVES CATEGORY (MBBL) (MBBL) (MMCF) (MMCF)

Proved
Proved Producing 276 226 1,443 1,118
Proved Non-Producing 125 108 380 300
------------------------------------------------------------------------
Proved Undeveloped 52 43 14 10
------------------------------------------------------------------------
Total Proved 453 377 1,837 1,428
Probable Additional 191 166 692 589
------------------------------------------------------------------------
Total Proved Plus Probable 644 543 2,529 2,016


NET PRESENT VALUE OF FUTURE NET REVENUE

BEFORE INCOME TAXES
------------------------------------------------------------------------
DISCOUNTED AT (% PER YEAR)
------------------------------------------------------------------------
0 5 10 15 20
------------------------------------------------------------------------
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
------------------------------------------------------------------------
Proved
Proved Producing 8,693 6,972 5,813 4,994 4,391
Proved Non-Producing 2,152 1,965 1,805 1,666 1,545
Proved Undeveloped 371 317 271 233 200
------------------------------------------------------------------------
Total Proved 11,216 9,254 7,889 6,893 6,136
Probable Additional 3,502 2,571 2,009 1,633 1,363
------------------------------------------------------------------------
Total Proved Plus Probable 14,719 11,824 9,898 8,526 7,499


AFTER INCOME TAXES
------------------------------------------------------------------------
DISCOUNTED AT (% PER YEAR)
------------------------------------------------------------------------
0 5 10 15 20
------------------------------------------------------------------------
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
------------------------------------------------------------------------
Proved
Proved Producing 8,693 6,972 5,813 4,994 4,391
Proved Non-Producing - - - - -
Proved Undeveloped - - - - -
------------------------------------------------------------------------
Total Proved 11,217 9,254 7,889 6,893 6,136
Probable Additional 3,446 2,544 1,996 1,627 1,360
------------------------------------------------------------------------
Total Proved Plus Probable 14,663 11,798 9,885 8,520 7,496

Note: Figures may not add due to rounding.


Reserves and Net Present Value (Constant Prices and Costs) The following
tables summarize Rock's remaining oil and gas reserve volumes along with
the value of future net revenue utilizing GLJ's pricing based on
benchmark reference prices posted at or near December 31, 2004 with
adjustments for oil differential and gas heating values applied to
arrive at a company average. Capital and operating costs were not
inflated.



RESERVES

OIL AND NGL GAS
GROSS NET GROSS NET
RESERVES CATEGORY (MBBL) (MBBL) (MMCF) (MMCF)

Proved
Proved Producing 282 233 1,456 1,127
Proved Non-Producing - - - -
------------------------------------------------------------------------
Proved Undeveloped 176 158 395 309
------------------------------------------------------------------------
Total Proved 458 391 1,851 1,436
Probable Additional 183 165 698 593
------------------------------------------------------------------------
Total Proved Plus Probable 641 556 2,549 2,029


NET PRESENT VALUE OF FUTURE NET REVENUE

BEFORE INCOME TAXES
------------------------------------------------------------------------
DISCOUNTED AT (% PER YEAR)
------------------------------------------------------------------------
0 5 10 15 20
------------------------------------------------------------------------
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
------------------------------------------------------------------------
Proved
Proved Producing 9,790 7,541 6,107 5,133 4,403
Proved Undeveloped 1,354 1,201 1,072 960 862
------------------------------------------------------------------------
Total Proved 11,144 8,742 7,179 6,093 5,298
Probable Additional 3,058 2,041 1,472 1,112 866
------------------------------------------------------------------------
Total Proved Plus Probable 14,202 10,783 8,651 7,205 6,164


AFTER INCOME TAXES
------------------------------------------------------------------------
DISCOUNTED AT (% PER YEAR)
------------------------------------------------------------------------
0 5 10 15 20
------------------------------------------------------------------------
RESERVES CATEGORY ($000) ($000) ($000) ($000) ($000)
------------------------------------------------------------------------
Proved
Proved Producing 9,790 7,541 6,107 5,133 4,436
Proved Undeveloped 1,354 1,201 1,072 960 862
------------------------------------------------------------------------
Total Proved 11,144 8,742 7,179 6,093 5,298
Probable Additional 3,058 2,041 1,472 1,112 866
------------------------------------------------------------------------
Total Proved Plus Probable 14,202 10,783 8,651 7,205 6,164

Note: Figures may not add due to rounding.


Pricing Assumptions

The following benchmark prices, inflation rates and exchange rates were
used by GLJ for the Constant Prices and Costs evaluation and the
Forecast Prices and Costs evaluation.



SUMMARY OF PRICING ASSUMPTIONS AS OF DECEMBER 31, 2004
CONSTANT PRICE AND COSTS
----------------------------------------------------------------
EDMONTON
PAR OIL PRICE AECO
40 API GAS PRICE NGL
(CDN$/BBL) (CDN$/MCF) (CDN$/BBL)

46.54 6.79 37.73


SUMMARY OF PRICING AND COST RATE ASSUMPTIONS AS OF DECEMBER 31, 2004
FORECAST PRICES AND COSTS

OIL
-------------------------------------------------------
EDMONTON HARDISTY
WTI @ REFERENCE MEDIUM HEAVY
CUSHING PRICE 29 API 12 API
YEAR ($US/BBL) ($/BBL) ($/BBL) ($/BBL)
2005 42.00 50.25 43.75 27.50
2006 40.00 47.75 41.50 28.50
2007 38.00 45.50 39.50 28.75
2008 36.00 43.25 37.75 27.25
2009 34.00 40.75 35.50 25.50
2010 33.00 39.50 34.25 24.75
2011 33.00 39.50 34.25 24.75
2012 33.00 39.50 34.25 24.75
2013 33.50 40.00 34.75 24.75
2014 34.00 40.75 35.50 25.50
2015 34.50 41.25 36.00 25.75
2016+ +2%/yr +2%/yr +2%/yr +2%/yr


NGL
-------------------------------------------------------
EDMONTON EDMONTON EDMONTON SPEC
PROPANE BUTANE PENTANE ETHANE
YEAR ($/BBL) ($/BBL) ($/BBL) ($/BBL)
2005 32.25 37.25 50.75 22.00
2006 30.50 35.25 48.25 21.25
2007 29.00 33.75 46.00 20.50
2008 27.75 32.00 43.75 20.00
2009 26.00 30.25 41.25 20.00
2010 25.25 29.25 40.00 20.00
2011 25.25 29.25 40.00 20.00
2012 25.25 29.25 40.00 20.00
2013 25.50 29.50 40.50 20.25
2014 26.00 30.25 41.25 20.75
2015 26.50 30.50 41.75 21.00
2016+ +2%/yr +2%/yr +2%/yr +2%/yr


GAS
--------- COST
CDN/US INFLATION
AECO C EXCHANGE RATE
YEAR ($/MCF) RATE (%/YEAR)
2005 6.60 0.82 2
2006 6.35 0.82 2
2007 6.15 0.82 2
2008 6.00 0.82 2
2009 6.00 0.82 2
2010 6.00 0.82 2
2011 6.00 0.82 2
2012 6.00 0.82 2
2013 6.10 0.82 2
2014 6.20 0.82 2
2015 6.30 0.82 2
2016+ +2%/yr 0.82 2



-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Rock Energy Inc.
    Allen Bey
    President & CEO
    (403) 218-4380
    or
    Rock Energy Inc.
    Peter D. Scott
    Vice President, Finance & CFO
    (403) 218-4380
    Website: www.rockenergy.ca