Rock Energy Inc.
TSX : RE

Rock Energy Inc.

March 16, 2007 08:12 ET

Rock Energy 2006 Year End Results

CALGARY, ALBERTA--(CCNMatthews - March 16, 2007) - Rock Energy Inc. (TSX:RE) is pleased to report its financial and operating results for the three month and twelve month periods ending December 31, 2006. Today the Company filed its Annual Information Form which includes Rock's reserves data and other oil and gas information for the year ended December 31, 2006 as mandated by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators. Copies of Rock's Annual Information Form may be obtained on www.sedar.com or by contacting Rock.

Rock is a Calgary, Alberta, Canada based crude oil and natural gas exploration, development and production company.

During 2006 Rock accomplished the following:

- Initiated and concluded an asset rationalization program;

- Consolidated our asset base into two core areas and increased our average working interest and operatorship;

- Strengthened our balance sheet through the sale process in July;

- Demonstrated the capability of our technical team by drilling 33 wells with a 96 percent success rate;

- Added more than 3.6 million boe of proved plus probable reserves with a finding and development cost of $11.28/boe and generated a re-cycle ratio of 1.6;

- Increased our production rate from 1,400 boe per day following the disposition in July to a rate in March 2007 exceeding 2,200 boe per day while averaging 2,098 boe per day for the year (an 87 percent increase from the year before);

- Generated cash flow of $13.9 million ($0.71 per share) for the year, a 21% increase over the prior year despite lower product prices;

- Increased our net asset value per share by 42 percent to $5.34 per basic share; and

- Built a strong inventory of drilling prospects, totalling more than 80 drilling locations, to drive our future growth.

The past year was one of transformation for Rock. This time last year we were managing an asset base that was largely non-operated and was spread across the entire Western Canada Sedimentary Basin. These assets were acquired in 2005 and provided us with a diverse portfolio of opportunity. We took that portfolio and determined where we thought we should focus and apply our resources to build a strong, viable company with the right mix. Our plan last year was to rationalize Rock's asset base and engage our grassroots exploration program. We did what we set out to do. We have restored Rock's production level and reserve base, focused into two core areas, and have accumulated a large inventory of drilling locations.

Rock engaged in a rationalization program in the first half of last year that reduced our production base to 1,400 boe per day by July. We emerged with two core areas that gave us increased focus, higher working interests and increased operatorship. Though we originally intended to only sell a net 200-300 boe per day while engaging in a swap of producing assets, it became evident during the process that our drilling inventory was superior to the assets being offered for swap. In addition, the offers for our assets were above our estimates of value and provided an 80 percent rate of return on our investment. We had acquired the assets for $20.6 million, had generated $6.2 million in cash flow after capital costs, and were now being offered $30.9 million to sell them. At that point we decided on a larger disposition and to reinvest the extra funds into our drilling program.

Our drilling program has added 3.6 million boe of proven plus probable reserves and increased our total reserve base to 7.9 million boe (proven plus probable) after accounting for the sale of properties and the production during the year, and restore our production level to it's current rate of over 2,200 boe per day.

Rock has emerged from its year of transformation with the "right mix" of; production (heavy oil, light oil and natural gas) ; risk and reward; geographic locations; and financial capability. The heavy oil component of our opportunity base provides a large inventory, exceeding 50 drilling locations, of low-risk projects that generate solid economic returns, and can be drilled and brought on-stream quickly. In our West Central region we have identified 25-30 drilling locations for natural gas. Though these gas targets have longer cycle times to bring on production, they also possess larger reserve potential and upside. It is the combination of projects that positions our company to generate growth in production and value.

2007 drilling program

Rock's Board of Directors has approved an initial capital budget of $22 million for 2007 (of which $2.0 million was spent in December 2006). During the remainder of the year the Company expects to drill approximately 18 (13.6 net) wells and increase production to exit the year at 2,600-2,800 boe per day. This would achieve 20-25 percent growth in exit volumes, before any significant contribution from our exploration projects.

The drilling program will be made up of 8-10 heavy oil wells and, two natural gas wells in our Plains region, and six to eight natural gas wells in our West Central region. Of the West Central region wells; two will be high-impact exploration wells at Kakwa and the rest will be lower-risk exploration wells in the Greater Kaybob and Musreau areas.

So far this year we have drilled three (3.0 net) heavy oil wells and one (1.0 net) abandoned well in the Plains region, and two natural gas wells in the West Central region, one (0.12 net) well at Waskahigan, and one (0.30 net) at Kakwa. The gas well at Waskahigan was completed with disappointing results and is currently a standing cased gas well; the well at Kakwa is cased and is being completed with production testing to likely occur following spring break-up.

Assuming average commodity prices $US65.00 per bbl of W.T.I. crude oil and Cdn$7.50 per mcf of natural gas at AECO, Rock's 2007 capital program will generate cash flow of $15 million ($0.76/share). The capital program is expected to be funded with our cash flow and our newly established $23 million debt facility.

Two-thousand seven will be an exciting year for Rock. We have a strong drilling program that is capable of growing our production by 25 percent by the year-end, plus an exploration program that could significantly impact Rock for 2008. The industry's structural landscape has changed, and that is providing opportunities as well as challenges for our company. The new environment should serve Rock well. We believe it will prompt the consolidation of smaller oil and natural gas companies, especially those that may have been banking on an early exit, possibly at lower acquisition metrics due to the energy trusts' increased cost of capital. This would provide Rock with increased opportunities for mergers and acquisitions. We believe we are well-positioned to take advantage of the opportunities and will continue to work hard to do so.



Corporate Summary

Twelve Twelve Three Three
months months months months
ended ended ended ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
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Financial
Oil and natural gas
revenue ($000) $ 33,156 $ 22,873 $ 7,535 $ 11,760
Funds from operations
($000) (1) $ 13,867 $ 11,433 $ 2,644 $ 6,020
Per share - basic $ 0.71 $ 0.74 $ 0.13 $ 0.31
- diluted $ 0.71 $ 0.74 $ 0.13 $ 0.31
Net income (loss) ($000) $ (884) $ 1,510 $ (119) $ 747
Per share - basic $ (0.05) $ 0.10 $ (0.01) $ 0.04
- diluted $ (0.05) $ 0.10 $ (0.01) $ 0.04
Capital expenditures,
net ($000) $ 2,004 $ 84,237 $ 6,223 $ 7,768
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As at As at
December 31, December 31,
2006 2005
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Working capital including bank debt ($000) $ (12,580) $ (24,442)
Common shares outstanding (000) 19,637 19,637
Options outstanding (000) 1,767 1,120
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Twelve Twelve Three Three
months months months months
ended ended ended ended
December 31, December 31, December 31, December 31,
2006 2005 2006 2005
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Operations
Average daily
production
Light crude oil
(bbls/d) 179 133 206 207
Heavy crude oil
(bbls/d) 792 187 1,168 480
NGL (bbls/d) 57 56 42 75
Natural gas (mcf/d) 6,421 4,476 3,528 8,147
Total (boe/d) 2,098 1,122 2,004 2,120
Average product
prices
Light crude oil
(Cdn$/bbl) $ 64.46 $ 64.95 $ 57.77 $ 63.63
Heavy crude oil
(Cdn$/bbl) $ 38.35 $ 27.44 $ 34.86 $ 24.81
NGL (Cdn$/bbl) $ 61.35 $ 56.19 $ 65.47 $ 58.80
Natural gas
(Cdn$/mcf) $ 7.07 $ 10.22 $ 7.45 $ 12.06
BOE (Cdn$/boe) $ 43.27 $ 55.85 $ 40.73 $ 60.29
Operating netback
(Cdn$/boe) $ 22.21 $ 31.98 $ 19.22 $ 34.79
(1) Funds from operations and funds from operations per share are not
terms under generally accepted accounting principles (GAAP), and
represent cash generated from operating activities before changes
in non-cash working capital. Rock considers it a key measure as it
demonstrates the Company's ability to generate the cash necessary to
fund future growth through capital investment. Funds from operations
may not be comparable with the calculation of similar measures for
other companies. Funds from operations per share is calculated using
the same share basis which is used in the determination of net income/
(loss) per share.


Management's Discussion & Analysis

ROCK ENERGY INC. ("ROCK" OR THE "COMPANY") is a publicly traded energy company engaged in the exploration for and the 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 natural gas exploration and production company through internal operations and acquisitions.

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

Rock faces competition in the oil and natural gas industry for resources, including 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 to control operating and administrative cost structures. Rock also seeks to obtain the best commodity price available based on the quality of its produced commodities.

The following discussion and analysis is dated March 15, 2007 and is management's assessment of Rock's historical, financial and operating results, together with future prospects, and should be read in conjunction with the audited consolidated financial statements of Rock for the 12 months ended December 31, 2006.

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 are a key measure that demonstrates the ability to generate cash to fund expenditures. Funds from operations are calculated by taking the cash provided by operations from the consolidated statement of cash flows and adding back changes in non-cash working capital. Funds from operations per share are calculated using the same share basis which is used in the determination of net income per share. 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.

All barrels of oil equivalent (boe) conversions in this report are derived by converting natural gas to oil at the ratio of six thousand cubic feet (mcf) of natural gas to one barrel (bbl) of oil. Certain financial values are presented on a boe basis and such measurements may not be consistent with those used by other companies. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.

Certain statements and information contained in this document, including but not limited to management's assessment of Rock's plans and future operations, production, reserves, revenue, commodity prices, operating and administrative expenditures, future income taxes, wells drilled, acquisitions and dispositions, funds from operations, capital expenditure programs and debt levels, contain forward-looking statements. All statements other than statements of historical fact may be forward-looking statements. These statements, by their nature, are subject to numerous risks and uncertainties, some of which are beyond Rock's control, including the effect of general economic conditions, industry conditions, regulatory and taxation regimes, volatility of commodity prices, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel, any of which may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such forward-looking statements, 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 and, therefore, should not unduly be relied on. These statements speak only as of the date of this document. Rock does not intend and does not assume any obligation to update these forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law.

All financial amounts are in thousands of Canadian dollars unless otherwise noted.

GUIDANCE AND OUTLOOK

The Company issued guidance on November 7, 2006 for projected 2006 and 2007 results. The table below provides the guidance for 2006 with actual results.



2006 Guidance
2006 Guidance Actual Change
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2006 Production (boe/d)
Annual 2,100 2,098 0%
Exit 2,200-2,400 2,200 (4)%
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2006 Funds from Operations
Annual $13.5 million $13.9 million 3%
Annual (per share) $0.69 $0.71 3%
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2006 Capital Budget
Expenditures $ 30 million $ 33 million 10%
Gross wells drilled 31 33 6%
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Total net debt at year end $ 11 million $12.6 million 15%
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Pricing (Fourth Quarter)
Oil - WTI US$60.00/bbl US$60.21/bbl 0%
Natural gas - AECO $ 6.67/mcf $ 6.69/mcf 0%
US/Cdn dollar exchange rate 0.90 0.88 (2)%
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Production averages for the year and the exit rate were within the guidance range. Funds flow from operations was above guidance as higher pricing (lower than budgeted heavy oil differentials and higher realized natural gas prices) more than offset higher operating costs. Capital expenditures were higher than forecast as $2 million of the 2007 capital budget was accelerated into December 2006 in order to take advantage of rig availability and operational efficiencies to drill four (4.0 net) heavy oil wells. As a result debt levels at year-end were slightly above guidance.

Guidance for 2007 has been updated to reflect higher operating costs experienced by the Company and industry and acceleration of the 2007 capital budget into December 2006. The table below updates the Company's previous guidance that was issued November 7, 2006.



2007 Previous 2007 Revised
Guidance Guidance Change
----------------------------------------------------------------------------
2007 Production (boe/d)
Annual 2,200 2,200-2,400 5%
Exit 2,600-2,800 2,600-2,800 0%
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2007 Funds from Operations
Annual $15 million $15 million 0%
Annual - (per share) $0.76 $0.76 0%
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2007 Capital Budget
Expenditures $22 million $20 million (9)%
Gross wells drilled 20-25 16-21 (18)%
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Total net debt at year-end $18 million $18 million 0%
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Pricing (Annual)
Oil - WTI US$65.00/bbl US$65.00/bbl 0%
Natural gas - AECO Cdn$7.50/mcf Cdn$7.50/mcf 0%
US/Cdn dollar exchange rate 0.90 0.90 0%
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Operating costs have been trending up and, as a result, Rock has increased the per boe cost by $0.50/boe to approximately $11.25 per boe including transportation costs. The acceleration of capital into December 2006 has caused management to implement an annual average range for production as the wells drilled came on-stream in the first quarter instead of the third quarter. The annual cash flow associated with the increased production has been offset by the increase in operating costs. As a result, the year's cash flow and year-end debt levels have not been affected. While light oil pricing has initially been lower than forecast for 2007, heavy oil differentials have improved and, as a result, we have not altered our oil price. The Company has put in a new debt facility which increased the bank line from $18 million to $23 million. Capital expenditures in excess of funds from operations are projected to be $5 million and can be funded through this facility. The year-end debt to cash flow ratio is projected to be approximately 1.2:1. The Company will continue to monitor its funds from operations, capital program and debt levels and make adjustments to ensure the projected debt to cash flow ratio does not exceed 1.5:1.



Production by Product

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Natural gas (mcf/d) 6,421 4,476 43% 3,528 8,147 (57)%
Oil (bbls/d) 179 133 35% 206 207 (1)%
Heavy Oil (bbls/d) 792 187 324% 1,168 480 143%
NGL (bbls/d) 57 56 2% 42 75 (44)%
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Total (boe/d) (6:1) 2,098 1,122 87% 2,004 2,120 (5)%
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Production by Area

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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West Central
Alberta (boe/d) 972 598 63% 652 1,189 (45)%
Plains (boe/d) 795 242 229% 1,171 510 130%
Other (boe/d) 331 282 17% 181 421 (57)%
----------------------------------------------------------------------------
Total (boe/d) (6:1) 2,098 1,122 87% 2,004 2,120 (5)%
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Production increases for the year ended December 31, 2006 primarily came from two sources. First are the ELM/Optimum/Qwest acquisitions that were completed in stages and closed in April and June 2005, partially offset by the sale of approximately 820 boe per day of production in July 2006. Second, the Company's operated grassroots drilling program contributed the heavy oil additions in the Plains area and additional production from drilling on the acquired properties. Early in January 2007 Rock's production exceeded 2,200 boe per day.

Production decreased by 5 percent in the fourth quarter of 2006 from the same period last year as the property dispositions in the third quarter more than offset the additions from operational activities. Production additions in the quarter primarily came from the Plains core area, which added heavy oil production, and the workovers completed at Medicine River, which added light oil production. As a result of these activities the Company's product mix shifted more towards heavy oil.



Product Prices

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Realized Product
Prices
Natural gas ($/mcf) 7.07 10.22 (31)% 7.45 12.06 (38)%
Oil ($/bbl) 64.46 64.95 (1)% 57.77 63.63 (9)%
Heavy oil ($/bbl) 38.35 27.44 40% 34.86 24.81 41%
NGL ($/bbl) 61.35 56.19 9% 65.47 58.80 11%
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Combined average
($/boe) (6:1) 43.27 55.85 (23)% 40.73 60.29 (32)%
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12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Average Reference
Prices
Natural gas
- Henry Hub
Daily Spot
(US$/mcf) 6.75 8.89 (24)% 6.69 12.27 (45)%
Natural gas
- AECO C
Daily Spot
($/mcf) 6.54 8.77 (25)% 6.99 11.43 (39)%
Oil - WTI
Cushing,
Oklahoma
(US$/bbl) 66.22 56.56 17% 60.21 60.02 0%
Oil - Edmonton
Light ($/bbl) 72.77 68.72 6% 64.49 71.17 (9)%
Heavy Oil
- Lloydminster
blend ($/bbl) 50.07 42.99 16% 43.84 41.81 5%
US/Cdn $ exchange
rate 0.882 0.826 7% 0.878 0.852 3%
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For the year and quarter ended December 31, 2006 the Company experienced higher heavy oil prices (approximately 40 percent increase) and lower natural gas prices (more than 30 percent reduction) than in the prior year's periods. Higher heavy oil prices resulted from higher WTI prices for the year and a significant decrease in the heavy oil to light oil differential. Structural changes in the marketplace such as pipeline reversals that have taken more heavy crude production out of Alberta to refineries in the mid-continent United States have contributed to the improvement in the heavy oil differential. The Company expects that these and other structural changes will continue to benefit the heavy oil market price. Natural gas prices have suffered from high storage levels as winter was delayed and the fourth quarter of 2006 was warmer than average. The combination of lower natural gas prices and the increase in heavy oil production in Rock's product mix over 2005 has caused the Company's weighted average per boe price to decrease by 23 percent for the year and 32 percent for the fourth quarter from the prior year's periods.

REVENUE

The vast majority of the Company's revenue is derived from oil and natural gas operations. Other income is primarily royalty and sulphur revenue.



Oil and Natural Gas Revenue

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Natural gas $ 16,560 $ 16,695 (1)% $ 2,408 $ 9,043 (73)%
Oil 4,195 3,152 33% 1,073 1,214 (12)%
Heavy Oil 11,124 1,871 495% 3,790 1,095 246%
NGL 1,277 1,155 11% 264 408 (35)%
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33,156 22,873 45% 7,535 11,760 (36)%
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Other revenue $ 198 $ 317 (38)% $ 42 $ 100 (58)%
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Oil and natural gas revenue increased by 45 percent for the year ended December 31, 2006 over 2005 due to higher production levels, particularly of heavy oil, which more than offsett the decline in product prices, particularly of natural gas. For the fourth quarter of 2006 oil and natural gas revenue decreased by 36 percent from the same period in 2005 as lower natural gas production and prices more than offset the increase in heavy oil production and prices. Other revenue decreased in 2006 from 2005 as the Company sold the property that was generating sulphur as part of the asset rationalization program in the third quarter of 2006.



Royalties

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Royalties $ 6,881 $ 5,027 37% $ 1,452 $ 2,666 (46)%
As a percentage
of oil and
natural gas
revenue 20.8% 22.0% (5)% 19.3% 22.7% (15)%
Per boe (6:1) $ 8.98 $ 12.28 (27)% $ 7.88 $ 13.67 (42)%
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Royalties increased for the year ended December 31, 2006 over the prior year due to higher production levels partially offset by lower natural gas prices and the benefit of Alberta Royalty Tax Credit (ARTC). For the fourth quarter of 2006 royalties decreased from the fourth quarter of 2005 due to lower production, lower natural gas prices and the ARTC benefit. Royalties as a percentage of revenue and on a per-boe basis decreased in the 2006 periods from the 2005 periods primarily due to lower natural gas prices, ARTC benefit and the Company's production mix including a higher heavy oil component, which generally has a lower associated royalty rate. The Company is forecasting a royalty rate of 22 percent for 2007 as the ARTC program has been eliminated effective January 1, 2007.



Operating Expenses

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Operating
expense $ 8,947 $ 4,470 100% $ 2,429 $ 2,149 13%
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Transportation
costs 308 275 12% 83 158 (47)%
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9,255 4,745 95% 2,512 2,307 9%
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Per boe (6:1) $ 12.08 $ 11.59 4% $ 13.63 $ 11.83 15%
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Operating costs for the year ended December 31, 2006 have increased over 2005 primarily due to higher production. Operating expenses for both the year ended December 31, 2006 and the fourth quarter of 2006 include approximately $200 of natural gas processing costs related to 2005. Excluding these prior-period processing costs, operating costs for 2006 are $11.83 per boe, a 2 percent increase over 2005, and $12.56 per boe for the fourth quarter of 2006, a 6 percent increase over the prior period. Compared to the third quarter of 2006, fourth quarter per boe operating expenses have decreased by 4 percent once the 2005 processing costs are excluded. Operating costs per boe did not decrease as much as expected in the fourth quarter in part due to higher service costs associated with heavy oil operations and higher road and lease maintenance costs.

Heavy oil unit costs tend to be higher in the first several months of producing operations (the "clean-up period") due to high initial sand production, additional fuel costs incurred until the operation is capable of running on casing-head gas and injected load oil being used during the clean-up period, which reduces the sales volume from the operations. Heavy oil operating costs have decreased year-over-year by about 20 percent to about $13.00 per boe as the base level of production has increased and start-up operations have less of an impact on overall costs. The Company expects heavy oil costs per boe to continue to decrease in 2007. Transportation costs for the fourth quarter of 2006 decreased from the prior year's period as a result of the properties sold in the third quarter of 2006. Operating expenses per boe, including transportation expense, are forecast to be approximately $11.25 per boe in 2007.



General and Administrative (G&A) Expense

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Gross $ 3,905 $ 2,275 69% $ 1,085 $ 814 27%
Per boe (6:1) 5.10 5.55 (9)% 5.89 4.17 34%
Capitalized 1,627 864 83% 395 288 19%
Per boe (6:1) 2.12 2.11 (2)% 2.14 1.47 26%
Net 2,278 1,411 61% 690 526 31%
Per boe (6:1) $ 2.97 $ 3.44 (14)% $ 3.74 $ 2.70 39%
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G&A expense increased on an absolute basis in 2006 over 2005 as the Company's operations continued to grow and new staff was added. G&A expense on a per-boe basis for the year ended December 31, 2006 dropped from the prior year's period as production increased. For the fourth quarter of 2006, G&A expense per boe increased over 2005 as production decreased as a result of the property dispositions in the third quarter of 2006, because costs for year-end activities increased and because approximately $56 ($0.30 per boe) of bad debt related to the ELM/Optimum/Qwest acquisition was written off. Rock capitalizes certain G&A expenses based on personnel involved in the exploration and development initiatives, including salaries and related overhead costs. G&A expenses are expected to rise in 2007 on an absolute basis as industry costs increase.



Interest Expense

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Interest expense
(recovery) $ 924 $ 457 100% $ 141 $ 261 (46)%
Per boe (6:1) $ 1.21 $ 1.12 8% $ 0.76 $ 1.34 (43)%
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Interest expense for 2006 doubled over 2005 as a result of higher average bank debt for the year. For the fourth quarter of 2006 interest expense was about half of interest expense for the same period of 2005 as bank debt was reduced in the third quarter of 2006 with proceeds from the asset rationalization program. Interest expense is expected to increase in 2007 due to higher average bank debt but to be approximately the same on a per boe basis as in 2006.



Depletion, Depreciation, and Accretion (DD&A)

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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D&D expense $ 13,989 $ 8,211 70% $ 2,707 $ 3,994 (32)%
Per boe (6:1) $ 18.27 $ 20.05 (9)% $ 14.69 $ 20.48 (28)%
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Accretion expense $ 129 $ 76 70% $ 34 $ 31 10%
Per boe (6:1) $ 0.17 $ 0.19 (11)% $ 0.18 $ 0.16 13%
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Depletion and depreciation expense for year ended December 31, 2006 increased over the prior year due to higher production but decreased for the fourth quarter of 2006 from the 2005 period primarily as Company reserves increased faster than the cost base. Reserve additions in 2006 also caused the depletion and depreciation expense per boe to decrease in 2006 from 2005.

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 percent.

Accretion represents the change in the time value of 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 year ended December 31, 2006 capital programs increased the underlying ARO by $413 (December 31, 2005 - $1,583) and actual expenditures on abandonments were $104 (December 31, 2005 - $44).

INCOME TAX

The Company began to pay capital taxes in 2005 as its capital base increased significantly following the acquisitions in 2005. Federal large corporations tax was eliminated beginning in 2006; however, the Company pays Saskatchewan resource capital taxes based on its production in the province. Rock does not have current income tax payable and does not expect to pay current income taxes in 2007 as the Company and its subsidiaries have estimated resource and other pools available at December 31, 2006 (after the allocation of deferred partnership income) of approximately $55.2 million as set out below:



CEE $ 14.9 million
CDE $ 25.9 million
UCC $ 12.8 million
Loss carry-forwards $ 0.3 million
Other $ 1.3 million
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Total $ 55.2 million


Funds from Operations and Net Income

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
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Funds from
operations $ 13,867 $ 11,433 21% $ 2,644 $ 6,020 (56)%
Per boe (6:1) $ 18.11 $ 27.92 (35)% $ 14.35 $ 30.86 (54)%
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Per share:
Basic $ 0.71 $ 0.74 (4)% $ 0.13 $ 0.31 (58)%
Diluted $ 0.71 $ 0.74 (4)% $ 0.13 $ 0.31 (58)%
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Net income (loss) $ (884) $ 1,510 (159)% $ (119) $ 747 (116)%
Per boe (6:1) $ (1.15) $ 3.69 (131)% $ (0.65) $ 3.83 (117)%
----------------------------------------------------------------------------
Per share:
Basic $ (0.05) $ 0.10 (150)% $ (0.01) $ 0.04 (125)%
Diluted $ (0.05) $ 0.10 (150)% $ (0.01) $ 0.04 (125)%
----------------------------------------------------------------------------
Weighted average
shares outstanding:
Basic 19,637 15,437 27% 19,637 19,596 0%
Diluted 19,655 15,501 27% 19,637 19,682 0%
----------------------------------------------------------------------------


The Company did not issue any shares in 2006. In 2005 the majority of shares issued were for the acquisitions completed in the second quarter of 2005, when 10.3 million shares were issued.

Funds from operations for the year ended December 31, 2006 increased by 21 percent over 2005 as the increase in production more than offset the decrease in realized prices, primarily for natural gas, and the increase in royalties, operating, G&A and interest costs. On a per-boe basis 2006 funds from operations decreased by 35 percent from 2005 primarily as the reduction in realized prices more than offset the reduction in royalties. For the fourth quarter of 2006 funds from operations decreased by approximately 56 percent on an absolute and 54 percent on a per boe-basis from to the prior year's periods as the reduction in prices (primarily for natural gas) and increase in operating and G&A costs more than offset the reduction in royalties. The Company generated a net loss for the year and quarter ended December 31, 2006 as the level of depletion and increase in stock-based compensation exceeded funds from operations.



Capital Expenditures

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
($000) 12/31/06 12/31/05 Change 12/31/06 12/31/05 Change
----------------------------------------------------------------------------

Land $ 4,822 $ 3,737 29% $ 120 $ 1,664 (93)%
Seismic 1,081 1,761 (39)% 127 878 (86)%
Drilling and
completions 25,130 16,801 50% 5,758 5,783 0%
Capitalized G&A 1,627 865 88% 395 288 37%
Gas gathering
systems 247 7 3,429% - 35 (99)%
----------------------------------------------------------------------------
Total operations $ 32,907 $ 23,171 42% $ 6,400 $ 8,648 (26)%
----------------------------------------------------------------------------
Property
acquisitions
(dispositions) (30,874) 60,593 (151)% Nil Nil n/a
Well site
facilities
inventory (165) 401 (141)% (206) (895) (77)%
Office equipment 136 72 89% 39 15 160%
----------------------------------------------------------------------------
Total (net of
acquisitions and
dispositions) $ 2,004 $ 84,237 (98)% $ 6,233 $ 7,768 (20)%
----------------------------------------------------------------------------


Capital expenditures for operations increased for the year ended December 31, 2006 over 2005 as Rock drilled the same number of gross wells (33) but more net wells (28.3 in 2006 versus 22.4 in 2005) as the Company gained more control over its operations. The Company participated in more West Central core area operations, including re-completions and, as a result, drilling and completions costs increased by 50 percent. In total Rock participated in nine (6.1 net) re-completions, which included one (0.8 net) natural gas well in the Musreau area which is expected to be tied-in in the fourth quarter of 2007, when third-party facilities are expanded, and one (1.0 net) oil well at Medicine River, which was brought on-production in the fourth quarter of 2006.

Land expenditures increased as the Company continued to build its West Central core area presence. Seismic expenditures decreased as the number of programs shot in the Plains core area decreased with Rock's shift to the West Central core area. Total net capital expenditures were reduced to $2 million in 2006 from $84 million in 2005 as the proceeds from the Company's asset rationalization program essentially offset capital expenditures from operations. In 2005 the Company completed the ELM/Optimum/Qwest acquisitions which significantly increased total capital expenditures.

During 2006, Rock drilled 27 (27.0 net) operated wells and six (1.3 net) non-operated wells, achieving a 96 percent success rate, compared to 20 (20.0 net) operated wells and 13 (2.1 net) non-operated wells and an 82 percent success rate in 2005. In the Plains core area Rock drilled 25 (25.0 net) heavy oil wells and one (1.0 net) dry hole. All of the wells were operated and all successful wells were on-production at year end except four (4.0 net) wells drilled in December 2006, which were brought on-production in the first quarter of 2007. Rock had no production from the Plains area at the beginning of 2005 and exited with approximately 670 boe per day in 2005 and 1,250 boe per day in 2006. In the West Central Alberta core area in 2006 Rock drilled two (0.9 net) oil wells in the Niton area, three (1.2 net) natural gas wells and one (0.1 net) dry hole. Of the three gas wells two (1.1 net) were drilled in the Musreau area and are expected to be tied-in in the fourth quarter of 2007 along with the re-completed well. In aggregate the Musreau-area wells are projected to initially increase Rock's production by 300 boe per day once tied-in. For the fourth quarter of 2006 capital expenditures decreased by approximately $2 million from 2005 levels as land and seismic activity decreased in the quarter.

LIQUIDITY AND CAPITAL RESOURCES

Rock's current approved capital budget for 2007 projects spending of $20 million. In 2007 funds from operations are expected to be approximately $15 million. The capital spending in excess of cash flow is intended to be funded through bank debt. Subsequent to year-end the Company arranged a new $23 million bank facility with a different chartered bank to replace its existing bank facility. With year-end debt of $12.6 million Rock has room to fund the $5 million of capital expenditures in excess of expected cash flow for 2007. The new bank facility will be reviewed by April 30, 2007 with the Company's 2006 independent reserve report. Based on the drilling in the fourth quarter of 2006, Rock expects, subject to any changes to the bank's commodity price forecast, an increase to the borrowing base. The Company will continue to monitor capital expenditures, cash flow from operations and debt levels and make adjustments, in order to ensure the projected debt to cash flow ratio does not exceed 1.5:1.

The Company has a demand operating loan facility with a Canadian chartered bank. This facility was put in place subsequent to year-end with a new lender and the Company's previous facility was repaid. The new facility is subject to the bank's valuation of the Company's oil and natural gas assets and the credit currently available is $23 million. The facility bears interest at the bank's prime rate or at the prevailing bankers' acceptance rate plus an applicable bank fee, which varies depending on the Company's debt to funds from operations ratio. The facility also bears a standby charge for un-drawn amounts. The facility is secured by a first ranking floating charge on all real property of the Company, its subsidiary and partnership and a general security agreement. The facility is currently under its annual review. As at March 15, 2007 approximately $14.7 million was drawn under the facility.

SELECTED ANNUAL DATA

The following table provides selected annual information for Rock. The Company changed its year-end at December 31, 2004 from March 31, 2004. In order to make comparisons of periods compatible, information presented for the 12-month period ended December 31, 2004 has been compiled by combining the nine-month period ended December 31, 2004 with the three-month period ended March 31, 2004.



12 Months 12 Months 12 Months
Ended Ended Ended
12/31/06 12/31/05 12/31/04
----------------------------------------------------------------------------
Production (boe/d) 2,098 1,122 181
Oil and natural gas revenues ($000) $ 33,156 $ 22,873 $ 2,845
----------------------------------------------------------------------------
Average realized price ($/boe) $ 43.27 $ 55.85 $ 43.02
Royalties ($/boe) $ 8.98 $ 12.28 $ 9.89
Operating expense ($/boe) $ 12.08 $ 11.59 $ 7.97
Operating netback ($/boe) $ 22.21 $ 31.98 $ 25.16
Net G&A expense ($000) $ 2,278 $ 1,411 $ 959
Stock-based compensation ($000) $ 1,188 $ 485 $ 202
----------------------------------------------------------------------------
Funds from operations ($000) $ 13,867 $ 11,433 $ 1,218
Per share - basic $ 0.71 $ 0.74 $ 0.14
Per share - diluted $ 0.71 $ 0.74 $ 0.14
----------------------------------------------------------------------------
Net income (loss) $ (884) $ 1,510 $ 571
Per share - basic $ (0.05) $ 0.10 $ 0.06
Per share - diluted $ (0.05) $ 0.10 $ 0.06
----------------------------------------------------------------------------
As at As at As at
12/31/06 12/31/05 12/31/04
----------------------------------------------------------------------------
Total assets $ 85,306 $ 99,604 $ 25,057
Total liabilities $ 24,827 $ 39,385 $ 2,693
----------------------------------------------------------------------------


SELECTED QUARTERLY DATA

The following table provides selected quarterly information for Rock:

3 Months 3 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/06 09/30/06 06/30/06 03/31/06
----------------------------------------------------------------------------

Production (boe/d) 2,004 1,613 2,190 2,594
Oil and natural gas revenues
($000) $ 7,535 $ 7,023 $ 8,774 $ 9,824
Average realized price ($/boe) $ 40.73 $ 47.30 $ 44.01 $ 42.08
Royalties ($/boe) $ 7.88 $ 5.27 $ 8.97 $ 12.26
Operating expense ($/boe) $ 13.63 $ 13.13 $ 10.55 $ 11.55
Operating netback ($/boe) $ 19.22 $ 28.90 $ 24.49 $ 18.27
Net G&A expense ($000) $ 690 $ 477 $ 462 $ 649
Stock-based compensation
($000) $ 295 $ 308 $ 305 $ 280
Funds from operations ($000) $ 2,644 $ 3,791 $ 4,028 $ 3,404
Per share - basic $ 0.13 $ 0.19 $ 0.21 $ 0.17
Per share - diluted $ 0.13 $ 0.19 $ 0.21 $ 0.17
Net income (loss) ($000) $ (119) $ 891 $ (583) $ (1,074)
Per share - basic $ (0.01) $ 0.05 $ (0.03) $ (0.05)
Per share - diluted $ (0.01) $ 0.05 $ (0.03) $ (0.05)
Capital expenditures ($000) $ 6,223 $ 12,520 $ 4,397 $ 9,728
----------------------------------------------------------------------------

As at As at As at As at
12/31/06 09/30/06 06/30/06 03/31/06

----------------------------------------------------------------------------
Working capital ($000) $(12,580) $ (8,990) $(31,135) $(30,766)
----------------------------------------------------------------------------


3 Months 3 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/05 09/30/05 06/30/05 03/31/05
----------------------------------------------------------------------------

Production (boe/d) 2,120 1,343 693 309
Oil and natural gas revenues
($000) $ 11,760 $ 7,030 $ 2,924 $ 1,159
Average realized price ($/boe) $ 60.29 $ 56.90 $ 46.36 $ 41.65
Royalties ($/boe) $ 13.67 $ 11.61 $ 10.39 $ 9.73
Operating expense ($/boe) $ 11.83 $ 13.19 $ 8.62 $ 9.49
Operating netback ($/boe) $ 34.79 $ 32.10 $ 27.35 $ 22.43
Net G&A expense ($000) $ 526 $ 329 $ 282 $ 274
Stock-based compensation
($000) $ 257 $ 131 $ 55 $ 42
Funds from operations ($000) $ 6,020 $ 3,552 $ 1,469 $ 392
Per share - basic $ 0.31 $ 0.18 $ 0.11 $ 0.04
Per share - diluted $ 0.31 $ 0.18 $ 0.11 $ 0.04
Net income (loss) ($000) $ 747 $ 634 $ 77 $ 51
Per share - basic $ 0.04 $ 0.03 $ 0.01 $ 0.01
Per share - diluted $ 0.04 $ 0.03 $ 0.01 $ 0.01
Capital expenditures ($000) $ 7,768 $ 7,920 $ 66,411 $ 2,138
----------------------------------------------------------------------------

As at As at As at As at
12/31/05 09/30/05 06/30/05 03/31/05

----------------------------------------------------------------------------
Working capital ($000) $(24,442) $(22,643) $(18,093) $ 10,297
----------------------------------------------------------------------------


Production has grown over the last two quarters of 2006 subsequent to the asset rationalization program which was completed in the third quarter of 2006. Immediately following these dispositions Rock's production was approximately 1,400 boe per day. Production growth has primarily come from drilling operations in the Plains core area and well recompletions at the Medicine River property near Sylvan Lake. Over the same period corporate average product prices have decreased as natural gas and oil prices declined. Heavy oil prices decreased in the fourth quarter, as expected, due to seasonality but in general were higher than 2005 levels. Royalty rates have generally improved in 2006 as Rock's product mix became more heavily weighted to oil, which usually has a lower royalty rate than gas, and because of Rock receiving the ARTC benefit.

Operating costs per boe have fluctuated depending on the amount of heavy oil start-up operations in any particular period, and the fourth quarter of 2006 included $200,000 relating to 2005 gas processing cost adjustments. Without these costs fourth quarter operating costs per boe would have decreased to $12.57 per boe. Field netbacks generally declined in 2006 from 2005 due to lower product prices. G&A expenses continued to rise as staffing levels increased throughout the period as the Company's activity levels grew. Funds from operations and net income or loss have been primarily affected by the change in product prices as changes in operating costs and royalty rates tended to offset each other. Net capital expenditures were significantly impacted by the asset rationalization program in the third quarter of 2006, which generated proceeds of $30.9 million, and by the acquisitions in the second quarter of 2005, which incurred costs of $60.5 million. The second quarter of the year tends to be a slower operational period with respect to capital investments due to the effects of spring break-up.

Reserves

Rock's reserves have been independently evaluated by GLJ Petroleum Consultants Ltd. (GLJ) at year-end 2006. This is the third year in which GLJ has evaluated the Company's reserves. The reserves as at December 31, 2006 and 2005 have been evaluated in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 51-101). The following tables provide a reconciliation of the Company's reserves between year-end 2005 and year-end 2006. NI 51-101 requires reserves to be reconciled on a net basis (after deducting royalties but including any royalty interests) ("net interest"). In addition, in the tables below Rock has also provided a reserve reconciliation on a gross basis (before deducting royalties and without including any royalty interest) ("gross interest").

Rock's gross interest reserves at year-end 2006 are 4.4 million boe of proved reserves and 7.3 million boe of proved plus probable reserves. The growth in gross interest reserves resulted from oil and natural gas operations (net of revisions) which added 2.0 million boe of proved reserves and 3.6 million boe of proved plus probable reserves.

RESERVES RECONCILIATION

The following table is a reconciliation of Rock's gross interest reserves at December 31, 2006 using GLJ's forecast pricing and cost estimates as at December 31, 2006.



Reconciliation of Company Gross Interest Reserves by Principal Product Type
(Forecast Prices and Costs)

Oil NGL Heavy Oil
----------------------------------------------------------------------------
Proved Proved Proved
Plus Plus Plus
Proved Probable Proved Probable Proved Probable
Factors (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
----------------------------------------------------------------------------
December 31, 2005 331 427 111 146 1,128 2,096
Additions(1) 121 197 22 53 1,734 2,500
Technical revisions(2) 36 41 8 6 132 (8)
Acquisitions 0 0 0 0 0 0
Dispositions (10) (12) (1) (1) 0 0
Production (65) (65) (21) (21) (289) (289)
----------------------------------------------------------------------------
December 31, 2006 413 588 118 183 2,705 4,299
----------------------------------------------------------------------------


Total oil
Natural Gas equivalent
----------------------------------------------------------------------------
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (mmcf) (mmcf) (mboe) (mboe)
----------------------------------------------------------------------------
December 31, 2005 14,427 19,657 3,974 5,946
Additions(1) 1,825 5,240 2,181 3,624
Technical revisions(2) (218) (613) 140 (65)
Acquisitions 0 0 0 0
Dispositions (6,186) (8,358) (1,042) (1,406)
Production (2,342) (2,342) (765) (765)
----------------------------------------------------------------------------
December 31, 2006 7,506 13,584 4,488 7,334
----------------------------------------------------------------------------
(1) Additions include discoveries, extensions, infill drilling and improved
recovery.
(2) Technical revisions include technical revisions and economic factors.
Note: Figures may not add due to rounding.

The following table is a reconciliation of Rock's net interest reserves at
December 31, 2006 using GLJ's forecast pricing and cost estimates as at
December 31, 2006.

Reconciliation of Company Net Interest Reserves by Principal Product Type
(Forecast Prices and Costs)
Oil NGL Heavy Oil
----------------------------------------------------------------------------
Proved Proved Proved
Plus Plus Plus
Proved Probable Proved Probable Proved Probable
Factors (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
----------------------------------------------------------------------------
December 31, 2005 286 371 78 102 926 1,712
Additions(1) 88 144 17 39 1,397 2,010
Technical revisions(2) 17 22 7 4 144 27
Acquisitions 0 0 0 0 0 0
Dispositions (8) (8) 0 0 0 0
Production (30) (30) (18) (18) (260) (260)
----------------------------------------------------------------------------
December 31, 2006 353 499 84 128 2,207 3,489
----------------------------------------------------------------------------


Total oil
Natural Gas equivalent
----------------------------------------------------------------------------
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (mmcf) (mmcf) (mboe) (mboe)
----------------------------------------------------------------------------
December 31, 2005 10,648 14,608 3,065 4,621
Additions(1) 1,531 4,192 1,757 2,891
Technical revisions(2) (234) (570) 128 (43)
Acquisitions 0 0 0 0
Dispositions (4,406) (5,924) (742) (995)
Production (1,588) (1,588) (572) (572)
----------------------------------------------------------------------------
December 31, 2006 5,951 10,719 3,636 5,902
----------------------------------------------------------------------------
(1) Additions include discoveries, extensions, infill drilling and improved
recovery.
(2) Technical revisions include technical revisions and economic factors.
Note: 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 natural gas reserve
volumes along with the value of future net revenue utilizing GLJ's forecast
pricing and cost estimates as at December 31, 2006.

Reserves
Oil NGL Heavy Oil Natural Gas
----------------------------------------------------------------------------
Reserves Gross Net Gross Net Gross Net Gross Net
Category (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf)
----------------------------------------------------------------------------

Proved
Proved Producing 371 315 101 72 2,180 1,788 4,909 3,790
Proved
Non-Producing 42 38 18 12 106 84 2,250 1,910
Proved
Undeveloped 0 0 0 0 419 335 348 251
----------------------------------------------------------------------------
Total Proved 413 353 119 84 2,705 2,207 7,507 5,951
Probable
Additional 175 145 63 44 1,594 1,282 6,084 4,768
----------------------------------------------------------------------------
Total Proved Plus
Probable 588 499 183 128 4,299 3,489 13,591 10,719
----------------------------------------------------------------------------
Note: Figures may not add due to rounding.


Net Present Value of Future Net Revenue
Before Income Taxes
----------------------------------------------------------------------------
Discounted at (% per year)
----------------------------------------------------------------------------
0 5 10 15 20
Reserves Category
----------------------------------------------------------------------------
Proved
Proved Producing 78,425 67,396 59,563 53,638 48,959
Proved Non-Producing 12,887 10,303 8,588 7,345 6,395
Proved Undeveloped 5,665 4,925 4,307 3,786 3,343
----------------------------------------------------------------------------
Total Proved 96,977 82,624 72,457 64,769 58,697
Probable Additional 60,052 43,397 33,231 26,839 21,486
----------------------------------------------------------------------------
Total Proved
Plus Probable 157,029 126,021 105,688 91,158 80,183
----------------------------------------------------------------------------

After Income Taxes
----------------------------------------------------------------------------
Discounted at (% per year)
----------------------------------------------------------------------------
0 5 10 15 20
Reserves Category
----------------------------------------------------------------------------
Proved
Proved Producing 70,150 60,789 54,048 48,909 44,829
Proved Non-Producing 8,729 6,839 5,601 4,715 4,044
Proved Undeveloped 3,717 3,112 2,626 2,229 1,899
----------------------------------------------------------------------------
Total Proved 82,596 70,740 62,276 55,853 50,773
Probable Additional 40,801 29,124 21,982 17,718 13,744
----------------------------------------------------------------------------
Total Proved
Plus Probable 123,397 99,864 84,257 73,031 64,517
----------------------------------------------------------------------------
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 natural gas reserves along with the value of future net revenue utilizing GLJ's constant pricing and costs estimates. Pricing was based on benchmark reference prices posted at or near December 31, 2006 with adjustments for oil differential and natural gas heating values applied to arrive at a company average. Capital and operating costs were not inflated.



Reserves
Oil NGL Heavy Oil Natural Gas
----------------------------------------------------------------------------
Reserves Gross Net Gross Net Gross Net Gross Net
Category (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf)
----------------------------------------------------------------------------
Proved
Proved Producing 375 319 101 71 2,180 1,790 4,928 3,804
Proved Non-
Producing 42 38 18 12 106 84 2,238 1,939
Proved
Undeveloped 0 0 0 0 419 335 348 254
----------------------------------------------------------------------------
Total Proved 417 357 119 84 2,705 2,209 7,514 5,996
Probable Additional 175 146 63 44 1,594 1,284 6,026 4,713
----------------------------------------------------------------------------
Total Proved Plus
Probable 592 503 182 128 4,299 3,493 13,540 10,709
----------------------------------------------------------------------------
Note: Figures may not add due to rounding.


Net Present Value of Future Net Revenue

Before Income Taxes
----------------------------------------------------------------------------
Discounted at (% per year)
----------------------------------------------------------------------------
0 5 10 15 20
Reserves Category
----------------------------------------------------------------------------
Proved
Proved Producing 72,077 62,251 55,181 49,783 45,492
Proved Non-Producing 9,858 8,027 6,739 5,775 5,024
Proved Undeveloped 5,131 4,447 3,875 3,393 2,983
Total Proved 87,067 74,726 65,795 58,951 53,500
Probable Additional 48,533 35,925 27,897 22,330 18,256
----------------------------------------------------------------------------
Total Proved
Plus Probable 135,600 110,651 93,693 81,281 71,756
----------------------------------------------------------------------------

After Income Taxes
----------------------------------------------------------------------------
Discounted at (% per year)
----------------------------------------------------------------------------
0 5 10 15 20
Reserves Category
----------------------------------------------------------------------------
Proved
Proved Producing 65,890 57,307 51,063 46,266 42,436
Proved Non-Producing 6,657 5,297 4,353 3,657 3,122
Proved Undeveloped 3,365 2,796 2,340 1,968 1,659
Total Proved 75,912 65,400 57,757 51,891 47,218
Probable Additional 32,952 24,026 18,341 14,407 11,536
----------------------------------------------------------------------------
Total Proved
Plus Probable 108,864 89,425 76,098 66,298 58,753
----------------------------------------------------------------------------
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 and Cost Rate Assumptions at December 31, 2006
- Constant Prices and Costs

Edmonton
Par Oil
Price AECO Edmonton Edmonton Edmonton Spec EXCHANGE
40 API Gas Price Pentane Propane Butane Ethane RATE
(Cdn$/bbl)(Cdn$/mcf) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/bbl) (US$/Cdn$)

----------------------------------------------------------------------------
67.58 6.07 71.55 43.25 54.06 20.43 0.8581
----------------------------------------------------------------------------


Summary of Pricing and Cost Rate Assumptions at December 31, 2006
- Forecast Prices and Costs

Oil NGL
----- -----
Medium Hardisty
Edmonton 29 Heavy 12
WTI Reference degrees degrees Edmonton Edmonton Edmonton
Cushing Price API API Propane Butane Pentane
Year (US$/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl)
----------------------------------------------------------------------------

2007 62.00 70.25 61.25 39.25 45.00 56.25 71.75
2008 60.00 68.00 59.25 40.00 43.50 50.25 69.25
2009 58.00 65.75 57.25 39.75 42.00 48.75 67.00
2010 57.00 64.50 56.00 39.75 41.25 47.75 65.75
2011 57.00 64.50 56.00 40.25 41.25 47.75 65.75
2012 57.50 65.00 56.50 41.50 41.50 48.00 66.25
2013 58.50 66.25 57.75 42.50 42.50 49.00 67.50
2014 59.75 67.75 59.00 43.50 43.25 50.25 69.00
2015 61.00 69.00 60.00 44.25 44.25 51.00 70.50
2016 62.25 70.50 61.25 45.25 45.00 52.25 72.00
2017 63.50 71.75 62.50 46.00 46.00 53.00 73.25
2018+ +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr
----------------------------------------------------------------------------


Natural Gas
-------------
Cost
US$/Cdn$ Inflation
Ethane AECO-C Exchange Rate
Year ($/bbl) ($/mcf) Rate (%/year)
----------------------------------------------------------------------------

2007 24.25 7.20 0.87 2
2008 25.25 7.45 0.87 2
2009 26.25 7.75 0.87 2
2010 26.50 7.80 0.87 2
2011 26.50 7.85 0.87 2
2012 27.75 8.15 0.87 2
2013 28.25 8.30 0.87 2
2014 29.00 8.50 0.87 2
2015 29.50 8.70 0.87 2
2016 30.00 8.90 0.87 2
2017 30.75 9.10 0.87 2
2018+ +2%/yr +2%/yr 0.87 2
----------------------------------------------------------------------------


FINDING, DEVELOPMENT AND ACQUISITION COSTS

The following table summarizes Rock's finding, development and acquisition costs for the years ended December 31, 2006 and 2005 and the nine months ended 2004, including future development costs. Due to the change in the Company's year-end in 2004 only nine-month data is shown for finding and development costs for 2004, given the availability of independent reserve information for that period.



12 months 12 months 9 months
ended ended ended Period
Dec. 31, Dec. 31, Dec. 31, Cumulative
2006 2005 2004 Total
----------------------------------------------------------------------------
Oil and Natural Gas
Operations:
Proved finding and
development costs
Capital expenditures(1)
($000) $ 32,907 $ 22,912 $ 5,876 $ 61,695
Future capital costs ($000) 2,939 962 1,174 5,075
----------------------------------------------------------------------------
Total capital ($000) $ 35,846 $ 23,874 $ 7,050 $ 66,877
----------------------------------------------------------------------------
Reserve additions(2) (mboe) 2,181 1,188 294 6,663
Proved finding and
development costs ($/boe) $ 16.44 $ 20.10 $ 23.98 $ 18.23
----------------------------------------------------------------------------
Proved Plus Probable
finding and development costs
Capital expenditures(1)
($000) $ 32,907 $ 22,912 $ 5,876 $ 61,695
Future capital costs ($000) 7,986 3,900 $ 3,051 $ 14,937
----------------------------------------------------------------------------
Total capital ($000) $ 40,893 $ 26,812 $ 8,927 $ 76,739
----------------------------------------------------------------------------
Reserve additions(2) (mboe) 3,624 2,201 551 6,376
Proved Plus Probable
finding and development
costs ($/boe) $ 11.28 $ 12.18 $ 16.20 $ 12.02
----------------------------------------------------------------------------
Acquisitions/Dispositions:
Proved finding and
development costs -
Acquisitions (Dispositions)
Capital expenditures(1)
($000) $(30,878) $ 60,853 - $ 29,975
Future capital costs ($000) (2,400) 3,647 - 1,247
----------------------------------------------------------------------------
Total capital ($000) $(33,278) $ 64,500 - $ 31,222
----------------------------------------------------------------------------
Reserve additions (mboe) (1,042) 2,397 - 1,355
Proved finding and
development costs ($/boe) $ (31.94) $ 26.91 - $23.04
----------------------------------------------------------------------------
Proved Plus Probable finding
and development costs -
Acquisitions
(Dispositions)
Capital expenditures(1)
($000) $(30,878) $ 60,853 - $ 29,975
Future capital costs ($000) (2,400) 3,733 - 1,333
----------------------------------------------------------------------------
Total capital ($000) $(33,278) $ 64,586 - $ 31,308
----------------------------------------------------------------------------
Reserve additions (mboe) (1,406) 3,154
Proved + Probable finding
and development costs
($/boe) $ (23.67) $ 20.48 - $ 17.91
----------------------------------------------------------------------------
Total Activities:
Proved finding and
development costs
Capital expenditures(1)
($000) $ 2,029 $ 83,765 $ 5,876 $ 91,670
Future capital costs ($000) 539 4,609 1,174 6,322
----------------------------------------------------------------------------
Total capital ($000) $ 2,568 $88,374 $ 7,050 $ 98,099
----------------------------------------------------------------------------
Reserve additions(3) (mboe) 1,279 3,620 273 5,172
Total Proved finding and
development costs ($/boe) $ 2.01 $ 24.41 $ 25.82 $ 18.95
----------------------------------------------------------------------------
Proved Plus Probable
finding and development costs
Capital expenditures(1)
($000) $ 2,029 $ 83,765 $ 5,876 $ 91,670
Future capital costs ($000) 5,586 7,633 3,051 16,270
----------------------------------------------------------------------------
Total capital ($000) $ 7,615 $ 91,398 $ 8,927 $108,047
----------------------------------------------------------------------------
Reserve additions(3) (mboe) 2,153 5,284 422 7,859
Total Proved Plus Probable
finding and development
costs ($/boe) $ 3.54 $ 17.30 $ 21.15 $ 13.73
----------------------------------------------------------------------------

(1) Capital expenditures include capitalized G&A which has been allocated
between oil and natural gas operations and acquisitions, and exclude
purchases of equipment still held in inventory and administrative
capital expenditures.
(2) Reserve additions exclude revisions.
(3) Reserve additions include revisions.
(4) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in
estimated future development costs generally will not reflect total
finding and development costs related to reserve additions for that
year.


Finding and development costs are broken down according to oil and natural gas operations, acquisitions and dispositions, and total activities. Oil and natural gas operations include all capital activities in which the Company participated, including operations on the acquired properties after their respective closing dates, but exclude reserve revisions. Finding and development costs on operations improved in 2006 compared to 2005 and 2004 primarily as Rock's grassroots exploration and development program gained momentum. Capital costs on operations for 2005 and 2004 included a relatively high land and seismic component, 23 percent and 48 percent of expenditures respectively, which increased finding and development costs.

Rock's 2007 capital budget has approximately 25 percent of the spending allocated to land and seismic as the Company continues to build its grassroots program, particularly in the West Central Alberta core area. Finding and development costs on the acquired properties are based on the reserve evaluation as at December 31, 2005 and were increased by the amount of production from the closing date to December 31, 2005 to provide an estimate of the reserves purchased. Finding and development costs on the disposed properties are based on the reserve evaluation as at December 31, 2005 and were decreased by the amount of production to the closing date. Finding and development costs for total activities include operations, acquisitions, dispositions and reserve revisions.



LAND HOLDINGS

The following table summarizes Rock's land holdings as at December 31, 2006
and 2005:

(acres) Dec. 31, 2006 Dec. 31, 2005 Change
----------------------------------------------------------------------------
Developed - Gross 63,085 79,188 (20)%
- Net 23,566 31,378 (25)%
----------------------------------------------------------------------------
Undeveloped - Gross 76,030 79,666 (5)%
- Net 39,429 36,898 7%
----------------------------------------------------------------------------
Total - Gross 139,115 158,854 (12)%
- Net 62,995 68,276 (8)%
----------------------------------------------------------------------------


NET ASSET VALUE

The following table summarizes Rock's net asset value and net asset value
per share as at December 31, 2006 and December 31, 2005:

($000 except number of shares December 31, December 31,
and net asset value per share) 2006 2005 Change
----------------------------------------------------------------------------
Proved plus probable reserves(1) 105,688 87,315 21%
Undeveloped land(2) 8,220 8,448 (3)%
Seismic(3) 3,550 2,617 36%
Working capital including debt (12,580) (24,442) 49%
Option proceeds 7,405 5,053 47%
----------------------------------------------------------------------------
Net Asset Value (Diluted) 112,283 78,991 42%
Diluted shares (000) 21,405 20,758 3%
----------------------------------------------------------------------------
Net asset value per share $ 5.25 $ 3.81 38%
----------------------------------------------------------------------------
(1) Proved plus probable reserves value is based on the net present value of
future net revenue from gross reserves using GLJ Petroleum Consultants
Ltd.'s January 2006 and 2005 forecast pricing and costs estimates and
using a discount rate ot 10 percent.
(2) Undeveloped land value is based on the actual cost of land purchased at
land sales; land acquired from ELM/Optimum/Qwest in the second quarter
of 2005 has been valued at $100 per acre.
(3) Seismic value is based on actual cost of seismic acquired or purchased.


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; and

- lease obligations for office premises.



Obligations with a fixed term are as follows:

2007 2008 2009 2010 2011
----------------------------------------------------------------------------

Office premise leases $ 676 $ 895 $ 828 $ 828 $ 828
Demand bank loan(1) $ 10,965
----------------------------------------------------------------------------
(1) The demand bank loan is currently under its annual review and is
expected to remain in place.


OUTSTANDING SHARE DATA

At December 31, 2006 and to date, Rock had 19,637,321 common shares outstanding. At December 31, 2006 the Company had 1,767,277 stock options outstanding with an average exercise price of $4.19 per share.

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.

RELATED-PARTY TRANSACTIONS

The Company has not entered into any related-party transactions during the reporting period.

DISCLOSURE CONTROLS AND PROCEDURES

The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of the disclosure controls and procedures as at December 31, 2006 and, based on that evaluation, believe them to be effective given the size and nature of the Company's operations. All control systems by their nature have inherent limitations and, therefore, Rock's disclosure controls and procedures are believed to provide reasonable, but not absolute, assurance that:

- the communications by the Company with the public are timely, factual and accurate and broadly disseminated in accordance with all applicable legal and regulatory requirements;

- non-publicly disclosed information remains confidential; and

- trading of the Company's securities by directors, officers and employees remains in compliance with applicable securities laws.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Chief Executive Officer and the Chief Financial Officer have supervised the design of internal controls over financial reporting and these controls were in place as at December 31, 2006. The Chief Executive Officer and the Chief Financial Officer believe the internal controls, including compensating controls to overcome the lack of certain segregation of duties, are designed appropriately given the nature and size of the Company's operations, and that a material deficiency in design does not exist. Because of their inherent limitations, internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control systems are met.

CHANGE IN ACCOUNTING POLICIES

There has been no change in accounting policies since the Company's last fiscal year-end.

NEW ACCOUNTING PRONOUNCEMENTS

Comprehensive Income

The Canadian Institute of Chartered Accountants (CICA) issued CICA Handbook section 1530, Comprehensive Income. The section is effective for fiscal years beginning on or after October 1, 2006. It describes how to report and disclose comprehensive income and its components. An integral part of the accounting standards on recognition and measurement of financial instruments is the ability to present certain gains and losses outside net income, in other comprehensive income. This standard requires that a company present comprehensive income and its components in a financial statement displayed with the same prominence as other financial statements that constitute a complete set of financial statements, in both annual and interim financial statements.

The CICA also made changes to CICA Handbook section 3250, Surplus, and reissued it as section 3251, Equity. The section is also effective for fiscal years beginning on or after October 1, 2006. The changes in how to report and disclose equity and changes in equity are consistent with the new requirements of section 1530, Comprehensive Income.

Rock will adopt this section effective January 1, 2007 but the Company does not expect this section to have a material impact on its consolidated financial statements.

Financial Instruments - Recognition and Measurement

The CICA issued CICA Handbook section 3855, Financial Instruments - Recognition and Measurement. The section is effective for fiscal years beginning on or after October 1, 2006. It describes the standards for recognizing and measuring financial assets, financial liabilities and non-financial derivatives. This section requires that all financial assets be measured at fair value, with some exceptions; all financial liabilities be measured at fair value if they are derivatives or classified as held for trading purposes (other financial liabilities are measured at their carrying value); and all derivative financial instruments be measured at fair value, even when they are part of a hedging relationship.

Rock will adopt this section effective January 1, 2007 but does not expect this section to have a material impact on its consolidated financial statements.

Hedges

The CICA issued CICA Handbook section 3865, Hedges. The section is effective for fiscal years beginning on or after October 1, 2006, and describes when and how hedge accounting can be used. Hedging is an activity used by a company to change an exposure to one or more risks by creating an offset between changes in the fair value of a hedged item and a hedging item; changes in the cash flows attributable to a hedged item and a hedging item; or changes resulting from a risk exposure relating to a hedged item and a hedging item. Hedge accounting ensures that all gains, losses, revenues and expenses from the derivative and the item it hedges are recorded in the income statement in the same period.

Rock will adopt this section effective January 1, 2007 but does not expect this section to have a material impact on its consolidated financial statements.

CRITICAL ACCOUNTING ESTIMATES

A summary of the Company's 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 Rock's control. The following is a discussion of the accounting estimates that are critical to the financial statements.

Oil and Natural Gas Accounting - Reserves Recognition - Rock retained independent petroleum engineering consultants GLJ Petroleum Consultants Ltd. (GLJ) to evaluate its 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 Natural 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, are amortized using the unit-of-production method based on estimated proved oil and natural 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 natural 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, a process known as 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 natural gas properties.

Asset Retirement Obligations - The Company recognizes the estimated fair value of 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 the Black-Scholes option pricing model. The 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.

Goodwill - The Company recognized goodwill in conjunction with the Elm/Optimum/Qwest acquisitions that occurred in the second quarter of 2005. In assessing if goodwill has been impaired the Company assesses the fair value of its assets and liabilities. This assessment takes into consideration such factors as: the estimated fair value of the Company's reserves and unproven properties; the current trading value of the common shares; and recent market transactions for similar types of assets. If the Company's common share trading value were to deteriorate from current levels an impairment to goodwill might exist.

BUSINESS RISKS

Rock is exposed to a number of business risks, some of which are beyond its control, as are all companies in the oil and natural 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 natural 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. Rock attempts to mitigate these risks by employing highly qualified staff and operating in areas where employees have expertise. In addition the Company outsources certain activities to be able to lever industry expertise, without having the burden of hiring full-time staff given the current scope of operations. Typically the Company has outsourced the marketing and certain land functions. Rock is attempting to acquire oil and natural 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 Rock will attempt to mitigate this risk by utilizing existing relationships.

Financial risks include commodity prices, the Canadian/US dollar exchange rate and interest rates, all of which are largely beyond the Company's control. Currently Rock has not used any financial instruments to mitigate these risks. The Company would consider using these financial instruments depending on the operating environment. The Company also will require access to capital. Currently Rock has a debt facility in place and intends to use its debt capacity in the future in conjunction with capital expenditures including acquisitions. It intends to use prudent levels of debt to fund capital programs based on the expected operating environment. It also intends 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.

ADDITIONAL INFORMATION

Further information regarding the Company, including the Company's Annual Information Form, can be accessed under the Company's public filings found on SEDAR at www.sedar.com. Information can also be obtained by contacting the Company at Rock Energy Inc., Suite 1800, 700 - 9th Avenue S.W., Calgary, Alberta, T2P 3V4.



Consolidated Balance Sheets

(000s of dollars)

As at December 31, 2006 December 31, 2005
----------------------------------------------------------------------------

Assets
Current assets
Cash and cash equivalents $ - $ 145
Accounts receivable 4,753 7,093
Prepaid expenses 532 385
----------------------------------------------------------------------------
5,285 7,623
Property, plant and equipment (note 4) 97,229 95,271
Accumulated depletion and
depreciation (22,882) (8,893)
----------------------------------------------------------------------------
74,347 86,378
Goodwill 5,748 5,602
----------------------------------------------------------------------------
$ 85,380 $ 99,603
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 6,900 $ 9,090
Bank debt (note 5) 10,965 22,976
----------------------------------------------------------------------------
17,865 32,066
Future tax liability (note 9) 4,942 5,204
Asset retirement obligation (note 6) 2,094 2,115
Shareholders' equity
Share capital (note 7) 57,326 57,369
Contributed surplus (note 8) 1,641 453
Retained earnings 1,512 2,396
----------------------------------------------------------------------------
60,479 60,218
----------------------------------------------------------------------------
Commitments (note 11)
Subsequent event (note 12)
----------------------------------------------------------------------------
$ 85,380 $ 99,603
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

Approved by the Board:

Consolidated Statements of Operations and Retained Earnings

(000s of dollars, except per share amounts)

Years ended December 31, 2006 December 31, 2005
----------------------------------------------------------------------------

Revenues:
Oil and natural gas revenue $ 33,156 $ 22,873
Royalties, net of Alberta Royalty
Tax Credit (6,881) (5,027)
Other income 198 317
----------------------------------------------------------------------------
26,473 18,163

Expenses:
General and administrative 2,278 1,411
Operating 9,255 4,745
Interest 924 457
Stock-based compensation (note 8) 1,188 485
Depletion, depreciation, and
accretion 14,118 8,287
----------------------------------------------------------------------------
27,763 15,385
----------------------------------------------------------------------------
Income (loss) before income taxes (1,290) 2,778

Income taxes
Current (note 9) 45 73
Future income taxes (reduction) (note 9) (451) 1,196
----------------------------------------------------------------------------
Net income (loss) for the year (884) 1,509
Retained earnings, beginning of year 2,396 887
----------------------------------------------------------------------------
Retained earnings, end of year $ 1,512 $ 2,396
Diluted and basic net income (loss)
per share (note 7) $ (0.05) $ 0.10
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


Consolidated Statements of Cash Flows

(000s of dollars)

Years ended December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Cash provided by (used in):

Operating:
Net income (loss) for the year $ (884) $ 1,509
Add: Non-cash items:
Depletion, depreciation, and
accretion 14,118 8,287
Actual abandonment costs (104) (44)
Stock-based compensation 1,188 485
Future income taxes (reduction) (451) 1,196
----------------------------------------------------------------------------
13,867 11,433
Changes in non-cash working capital 2,571 (4,319)
----------------------------------------------------------------------------
16,438 7,114
Financing:
Issuance of common shares - 217
Bank debt (12,011) 22,976
Repurchase of stock options - (185)
----------------------------------------------------------------------------
(12,011) 23,008

Investing:
Property, plant and equipment (32,879) (23,644)
Acquisition of property, plant and
equipment (note 3) - (23,880)
Disposition of property, plant and
equipment 30,874 -
Changes in non-cash working capital (2,567) 8,915
----------------------------------------------------------------------------
(4,572) (38,609)
----------------------------------------------------------------------------
Decrease in cash and cash
equivalents (145) (8,487)
Cash and cash equivalents, beginning
of year 145 8,632
----------------------------------------------------------------------------
Cash and cash equivalents, end of
year $ - $ 145
----------------------------------------------------------------------------
Interest and taxes paid and
received:
Interest paid 960 428
Interest received 32 42
Taxes paid $ 25 $ 57
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


Notes to Consolidated Financial Statements

Years ended December 31, 2006 and 2005

1. Nature of Operations

Rock Energy Inc. (the "Company" or "Rock") is actively engaged in the exploration, production and development of oil and natural 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 (GAAP).

The preparation of financial statements in conformity with GAAP 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) CONSOLIDATION

These consolidated financial statements include the accounts of Rock Energy Inc., Rock Energy Ltd. and Rock Energy Production Partnership. All inter-company transactions and balances have been eliminated upon consolidation.

(B) CASH AND CASH EQUIVALENTS

Cash and cash equivalents are comprised of cash and short-term investments with a maturity date of 12 months or less.

(C) JOINT OPERATIONS

A substantial portion of the Company's oil and natural 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.

(D) PROPERTY, PLANT AND EQUIPMENT

Capitalized costs: The Company follows the full cost method of accounting 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 natural 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 percent 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 percent.

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. 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 natural 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.

(E) GOODWILL

Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the fair value for accounting purposes of the net identifiable assets and liabilities of the acquired business. Goodwill is stated at cost less any impairment and is not amortized. The goodwill balance is subject to an impairment test whereby the book value of the Company's equity is compared to its fair value. If the fair value of the Company's equity is less than book value, impairment is measured by allocating the fair value of the identifiable assets and liabilities at their fair values. The difference between the Company's fair value and book value of identifiable assets and liabilities is the fair value of goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount. Impairment is charged to income in the period in which it occurs. The impairment test is carried out annually, or more frequently if circumstances occur that are more likely than not to reduce the fair value of the acquired business below its carrying amount.

(F) 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 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 when the temporary differences are expected to reverse.

(G) 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.

(H) STOCK-BASED COMPENSATION

The Company grants options to purchase common shares to employees and directors under its stock option plan. The Company follows 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 the 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.

(I) 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.

(J) 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, future costs and timing. 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.

(K) PER SHARE AMOUNTS

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 ELM/Optimum/Qwest

On March 14, 2005 the Company agreed to acquire, in two separate closings from 14 different entities (six private companies and eight drilling fund partnerships), petroleum and natural gas properties mainly through their various subsidiary companies. The transactions have been accounted for using the purchase method with the results of operations for each transaction included in the financial statements from the date of acquisition.

The first closing of the ELM/Optimum/Qwest properties occurred on April 7, 2005. The Company purchased all of the outstanding shares of 1143734 Alberta Ltd. and assets were purchased directly from three private entities and four drilling fund partnerships. The final purchase price equation is as follows:



($000)
----------------------------------------------------------------------------
Property, plant and equipment $ 16,483
Note payable(1) (309)
Asset retirement obligation (373)
----------------------------------------------------------------------------
$ 15,801
----------------------------------------------------------------------------
Consideration provided:
Cash $ 4,575
Common shares (3,091,483) 10,944
Transaction costs 282
----------------------------------------------------------------------------
$ 15,801
----------------------------------------------------------------------------
(1) Paid to vendors on final adjustments


The second closing of the ELM/Optimum/Qwest properties occurred on June 17, 2005. The Company purchased all of the outstanding shares of 1156168 Alberta Ltd., 1159203 Alberta Ltd. and 1140511 Alberta Ltd. The purchase price equation is as follows:



($000)
----------------------------------------------------------------------------
Property, plant and equipment $ 45,490
Note receivable(1) 148
Goodwill 4,593
Future income taxes (4,593)
Asset retirement obligation (1,007)
----------------------------------------------------------------------------
$ 44,631
----------------------------------------------------------------------------
Consideration provided:
Cash $ 18,504
Common shares (7,234,005) 25,609
Transaction costs 518
----------------------------------------------------------------------------
$ 44,631
----------------------------------------------------------------------------
(1) Paid by vendors on final adjustments


The purchase price allocations for both transactions were initially based on estimates of the fair values of the assets and liabilities as of the closing date, purchase price adjustments, transaction costs and holdback amounts.



4. Property, Plant and Equipment

($000) December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 96,887 $ 95,160
Other assets 342 111
----------------------------------------------------------------------------
97,229 95,271
Accumulated depletion and depreciation (22,882) (8,893)
----------------------------------------------------------------------------
$ 74,347 $ 86,378
----------------------------------------------------------------------------


In the third quarter of 2006, the Company disposed of four non-operated producing properties for total proceeds of approximately $30.9 million. The properties disposed of included Wild River, Highland/Hudson and Chestermere. As the change in the depletion rate was less than 20 percent, no gain has been booked into the financial statements.

At December 31, 2006, petroleum and natural gas properties included $8,220, (December 31, 2005 - $6,265 of unproved property costs which have been excluded from the depletable base.

During the year ended December 31, 2006, $1,627 (Year ended December 31, 2005 - $865) of administrative costs relating to exploration and development activities were capitalized as part of property, plant and equipment.

At December 31, 2006, the Company applied the ceiling test calculation to its petroleum and natural gas properties using expected future market prices. These expected future market prices were forecast by the Company's independent reserve evaluators and then adjusted for commodity price differentials specific to the Company's production. The following table exhibits the benchmark prices used in the ceiling test:


Heavy Oil
Oil Oil Natural gas at Hardesty Currency
WTI (Cushing, Edmonton AECE-C spot (12 degrees exchange
Oklahoma) par (40 API) price API) rate
(US$/bbl) (Cdn$/bbl) (Cdn$/mmbtu) (CDn$/bbl) (US$/CDN$)
----------------------------------------------------------------------------
2007 62.00 70.25 7.20 39.25 0.87
2008 60.00 68.00 7.45 40.00 0.87
2009 58.00 65.75 7.75 39.75 0.87
2010 57.00 64.50 7.80 39.75 0.87
2011 57.00 64.50 7.85 40.25 0.87
2012 57.50 65.00 8.15 41.50 0.87
2013 58.50 66.25 8.30 42.50 0.87
2014 59.75 67.75 8.50 43.50 0.87
2015 61.00 69.00 8.70 44.25 0.87
2016 62.25 70.50 8.90 45.25 0.87
2017 63.50 71.75 9.10 46.00 0.87
Thereafter
(escalation) 2.0%/yr 2.0%/yr 2.0%/yr 2.0%/yr 0.87
----------------------------------------------------------------------------


5. Bank Debt

At December 31, 2006 the Company has a demand operating facility with a Canadian chartered bank subject to the bank's valuation of the Company's oil and natural gas properties. The current limit under the facility is $18 million. The facility is secured by a first ranking floating charge on all real property of the Company, its subsidiary and partnership and a general security agreement. The facility bears interest at the bank's prime rate or at prevailing bankers' acceptance rate plus an applicable bank fee. The facility also bears a standby charge for un-drawn amounts. The facility was replaced in March 2007 (see note 12, Subsequent Event).

6. Asset Retirement Obligation

The Company's 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, 2006 is approximately $3,666 (December 31, 2005 - $3,385), which will be incurred between 2007 and 2019. A credit-adjusted risk-free rate of 8 percent and an annual inflation rate of 1.5 percent were used to calculate the future asset retirement obligation.



A reconciliation of the asset retirement obligations is provided below:

December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Balance, beginning of year $ 2,115 $ 500
Liabilities incurred/acquired during year 413 1,583
Dispositions (459) -
Accretion 129 76
Actual retirement costs (104) (44)
----------------------------------------------------------------------------
Balance, end of year $ 2,094 $ 2,115
----------------------------------------------------------------------------



7. 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 Rock Number Amount ($000)
----------------------------------------------------------------------------
Issued and outstanding as at
December 31, 2004 9,259,453 $ 21,276
Redemption (i) (448) (2)
Future tax effect of flow-through share
renouncements (ii) (723)
Issued for property acquisitions 10,325,488 36,552
Issued for flow-through shares (iii) 22,263 115
Issued for stock options exercised 30,565 151
----------------------------------------------------------------------------
Issued and outstanding as at
December 31, 2005 19,637,321 $ 57,369
Future tax effect of flow-through share
renouncements (iii) - (43)
Issued and outstanding as at
December 31, 2006 19,637,321 $ 57,326
----------------------------------------------------------------------------

(i) In accordance with the terms of the 30-for-1 share consolidation
shareholders holding 1,000 or fewer pre-consolidated common shares
redeemed their shares for cash based on the value of $0.1129 per
pre-consolidated share.
(ii) The Company has renounced resource expenditures on flow-through shares
issued by predecessor companies. At March 31, 2004, the Company was
committed to spending $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 the Company completed the renouncements in February 2005.
(iii) In accordance with the Company's stock option plan, some options were
exercised in exchange for flow-through shares of the Company. By
February 2, 2006 all of the renouncements were made.

As at December 31, 2006 and 2005 no preference shares were outstanding.


(C) STOCK OPTIONS

The Company has a stock option plan under which it may grant options to directors, officers and employees for the purchase of up to 10 percent of the issued and outstanding common shares of the Company. 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 majority of options vest yearly in one-third tranches beginning on the first anniversary of the grant date and expire one year after vesting. Options expiring are usually replaced with another grant that vests in two years and expire in three years. At the Company's discretion the options can be exercised for cash. The following table summarizes the status of the Company's stock option plan as at December 31, 2006 and December 31, 2005 and changes during the year ended on those dates:



December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price ($) Options Price ($)
----------------------------------------------------------------------------

Outstanding, beginning of year 1,120,332 $ 4.51 532,387 $ 3.49
Granted 677,779 $ 3.66 777,944 $ 4.95
Exercised - - (135,629) $ 3.39
Forfeited - - (54,370) $ 3.58
Expired (30,834) $ 3.87 - -
----------------------------------------------------------------------------
Outstanding, end of year 1,767,277 $ 4.19 1,120,332 $ 4.51
----------------------------------------------------------------------------

Options outstanding and exercisable under the stock option plan are
summarized below as at December 31, 2006:

Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Number of Exercise Years to Number of Exercise
Options Price Expiry Options Price ($)
----------------------------------------------------------------------------

$ 3.15 - $ 3.90 754,333 $ 3.30 1.83 155,777 $ 3.47
$ 4.00 - $ 5.11 1,012,944 $ 4.86 1.76 217,667 $ 4.93
----------------------------------------------------------------------------
1,767,277 $ 4.19 1.79 373,444 $ 4.32
----------------------------------------------------------------------------


(D) PER SHARE AMOUNTS

The weighted average number of common shares outstanding during the year ended December 31, 2006 of 19,637,321 (year ended December 31, 2005 - 15,436,835) was used to calculate 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, 2006. As at December 31, 2006, an additional 17,660 (December 31, 2005 - 64,127) common shares were used to calculate diluted earnings per share.

8. Stock-Based Compensation

Options granted to employees and non-employees after March 31, 2003 are accounted for using the fair value method. The fair value of common share options granted for the year ended December 31, 2006 was estimated to be $976 (year ended December 31, 2005 - $1,658) as at the grant date using the Black-Scholes option pricing model and the following assumptions:



Risk-free interest rate 4.00% - 6.00%
Expected life Three-year average
Expected volatility 30% - 60%
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. The change in the contributed surplus account is reconciled in the table below:



December 31, 2006 December 31, 2005
----------------------------------------------------------------------------

Balance, beginning of year $ 453 $ 202
Stock-based compensation expense 1,188 485
Net benefit on options exercised(1) - (234)
----------------------------------------------------------------------------
Balance, end of year $ 1,641 $ 453
----------------------------------------------------------------------------
(1) The benefit of options exercised is recorded as a reduction of
contributed surplus and an increase to share capital.


9. Income Taxes

The provision for income taxes in the consolidated statements of operations 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 33.70 percent (December 31, 2005 - 37.62 percent). The principal reasons for differences between such "expected" income tax expense and the amount actually recorded are as follows:



December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Net income before income taxes $ (1,290) $ 2,778
Statutory income tax rate 33.7% 37.62%
----------------------------------------------------------------------------
Expected income taxes $ (435) $ 1,045
Add (deduct):
Stock-based compensation 400 182
Non-deductible Crown charges 330 1,038
Change in enacted rates (311) -
Other 180 19
Resource allowance (615) (888)
Acquisition - 12,133
Change in valuation allowance - (12,333)
----------------------------------------------------------------------------
Provision for income taxes $ (451) $ 1,196
Capital tax 45 73
----------------------------------------------------------------------------
Provision for (recovery of) income taxes $ (406) $ 1,269
----------------------------------------------------------------------------

Future income tax assets or liabilities recognized on the consolidated
balance sheets are comprised of temporary differences. The after-tax effect
of these temporary differences are summarized as follows:

December 31, 2006 December 31, 2005
----------------------------------------------------------------------------
Loss carry-forwards $ 4,941 $ 9,097
Property, plant and equipment (6,218) (11,542)
Non-coterminous year-ends (3,859) (3,049)
Share issuance costs 263 360
Asset retirement obligation 649 719
----------------------------------------------------------------------------
Calculated future income tax liability (4,224) (4,415)
Valuation allowance (718) (789)
----------------------------------------------------------------------------
Future income taxes (liability) $ (4,942) $ (5,204)
----------------------------------------------------------------------------


At December 31, 2006, Rock and its subsidiary have tax pools aggregating $69.0 million prior to the allocation of deferred partnership income and $55.2 million (December 31, 2005 - $65.5 million) after the allocation of deferred partnership income. The non-capital losses prior to the allocation of deferred partnership income expire as follows:



----------------------------------------------------------------------------
2011 $ 479
2026 13,656
----------------------------------------------------------------------------
$ 14,135
----------------------------------------------------------------------------


10. Financial Instruments

Rock's financial instruments included in the consolidated balance sheets are comprised of cash and cash equivalents, accounts receivable, refundable deposits, bank debt, 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. A substantial portion of Rock's accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risks. Interest rates directly impact interest costs as the Company's current debt facility is based on floating rates. Crude oil sales are referenced to the U.S. dollar, thus the Canadian price realized is directly impacted by Canadian and U.S. dollar exchange rates.



11. Commitments

Obligations with a fixed term are as follows:

2007 2008 2009 2010 2011
----------------------------------------------------------------------------
Lease of office premises $ 676 $ 895 $ 828 $ 828 $ 828
----------------------------------------------------------------------------


12. Subsequent Event

Subsequent to year-end the Company entered into a new demand operating facility with a different Canadian chartered bank. The new facility has a borrowing limit of $23 million, up from the current limit of $18 million. The new loan is based on the Company's 2005 reserve report by GLJ Petroleum Consultants Ltd. (GLJ) and internal estimates at September 30, 2006. The new facility will be reviewed before April 30, 2007 utilizing the current GLJ reserve report as at December 31, 2006.

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, except as required by applicable law.

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.

Contact Information

  • 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