Rock Energy Inc.
TSX : RE

Rock Energy Inc.

March 12, 2008 23:58 ET

Rock Energy 2007 Year End Results

CALGARY, ALBERTA--(Marketwire - March 12, 2008) - 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, 2007. 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, 2007 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 2007 Rock accomplished the following key goals:

- Acquired Greenbank Energy Ltd.

On September 28, 2007 Rock closed the acquisition of Greenbank Energy Ltd. for total consideration of $28.1 million plus $0.4 million of allocated capitalized G&A. Rock acquired 1.9 million boe of proved plus probable reserves, 500 boe/d of production (92 percent natural gas), more than 25,000 net acres of undeveloped land and 25-30 drilling locations. This strategic acquisition represented a natural extension of Rock's exploration program in the Deep Basin. It extends our activities northwest from Kaybob, into an area where the stacked Cretaceous gas plays are shallower , drilling costs are lower, gas processing capacity is readily available, and surface operations can be completed year-round (except during spring break-up).

- Drilling Results

In 2007 Rock participated in 16 (12.2 net) wells, resulting in 8 (8.0 net) heavy oil wells, 6 (3.1 net) natural gas wells and 2 (1.1 net) dry and abandoned wells, for a success rate of 91 percent on net wells. Our exploration program established commercial reservoirs at Saxon, Kakwa, and Elmworth. These areas will provide exploitation and development programs for 2008 and 2009. So far in 2008 Rock has drilled 4 (1.98 net) natural gas wells at Saxon, Girouxville, Markerville, and Tony Creek, all successful.

- Infrastructure Construction

A key accomplishment in 2007 was the construction of pipelines, gas plants and compressor stations to tie-in our gas wells at Musreau and Kakwa. This critical infrastructure has been brought on-stream during the first quarter of 2008 and our production is now beginning to increase. These facilities plus the work we are currently doing in the Saxon area improve the profitability of future drilling locations and will speed future tie-ins.

- Reserves and Net Asset Value

Rock has increased total Company reserves by 27 percent on a proved plus probable basis, from 7.3 million boe at year-end 2006 to 9.3 million boe at year-end 2007. Proved reserves were increased by 18 percent over the same timeframe, from 4.5 million boe to 5.3 million boe. All-in finding, development and acquisition (FD&A) costs incurred in 2007 averaged $24.42/boe (proved plus probable). This is higher than we consider acceptable. The reason stems from negative technical revisions at our heavy oil properties and high future capital costs associated with our acquisition of Greenbank and at our newly discovered gas properties in Kakwa and Saxon, which have limited reserve bookings to date. The Company expects to increase reserve bookings as we get more production history from the new wells and the full exploration cycle is completed. Our three-year all-in FD&A cost was $16.35/boe (proved plus probable), which is more representative of true full-cycle costs.

The reserve report by GLJ Petroleum Consultants Ltd. has indicated a reserve value of $152 million (net present value discounted at 10%, before tax) under the existing royalty regime and $145-152 million under an assumed range of Alberta's proposed new royalty regime. Under the proposed royalty regime calculation, Rock's net asset value becomes $4.99 -$5.28 per share (basic), assuming year-end debt of $29.1 million, land of 61,718 net acres at the acquired cost of $13.4 million, no value for seismic, and 25.9 million basic shares outstanding.

- Production Results

Rock's daily production in 2007 averaged 2,198 boe/d for the year, and during the fourth quarter we averaged 2,672 boe/d. Although our average production rate for the year was essentially flat (compared to 2006), Rock's 2007 activities laid the foundation for production growth in 2008. The exploration cycle in the Deep Basin can take two to three years, especially when we are dealing with winter-access areas and processing facility limitations. We are now emerging from the exploration cycle and estimate our current daily production to be about 2,900 boe/d - compared to only 2,114 boe/d at this time last year. We expect our production to average 3,400 boe/d this year, a 55 percent increase from 2007.

- Financial Results

In 2007 Rock generated funds from operations of $15.2 million ($0.72 per share) and net income of $561,000 ($0.03 per share). The Company had capital expenditures of $53.7 million, of which $28.1 million was for the Greenbank Energy Ltd. acquisition, financed through the issuance of common shares. Total debt was $29.1 million at year-end, against bank lines of $36 million. Our borrowing base is currently being reviewed in light of our 2007 activity, and we expect our bank lines to be increased from $36 million to $38 million, plus a development facility of $6 million.

2008 Capital Program

Rock's Board of Directors has approved an increase to our capital budget from $24 million to $30 million for 2008. The program's goals are to prove up and tie-in the exploration wells at Saxon and Kakwa during the first quarter (which is now underway), drill the heavy oil wells and Elmworth exploitation gas wells during the second and third quarters, and embark on the winter development drilling program at Musreau, Saxon and Kakwa during the fourth quarter. The additional $6 million is required to construct the gathering system and processing facility at Saxon. This strategic infrastructure will allow Rock to expand the development of our program in the area.

This year we aim to drill 18-22 wells, nine of which would be heavy oil wells. These heavy oil wells again will aim to replace natural declines and hold production at 1,300 boe/d, with excess cash flow directed to the West Central core area. This capital program is expected to yield average production of 3,400-3,600 boe/d and an exit rate of 3,900-4,100 boe/d. Cash flow is forecast at $28 million ($1.08 per share), assuming average commodity prices of US$85.00/bbl of WTI oil and $7.25/mcf of AECO natural gas, and a Canada-U.S. dollar exchange rate of par. Under these plans and working assumptions the Company's debt by the end of the first quarter will reach $39 million, but by year end will have dropped to $31.5 million, which would be equal to 1 times fourth quarter annualized cash flow.

Conclusion

In a challenging environment, we find the opportunity. Rock used the opportunities that 2007 presented to set the stage for growth and prosperity in 2008 and beyond. Though our production in 2007 did not grow significantly over 2006, our opportunity base and capability did. We completed the acquisition of Greenbank Energy Inc., capturing a foothold in the Elmworth area with 25-30 drilling locations and transforming ourselves into a larger, more robust operating company. In addition we demonstrated our exploration capabilities in the Alberta Deep Basin through drilling success at Saxon, Kakwa, and Elmworth, plus installed the infrastructure to get these wells on-stream. With a large inventory of drilling locations, a strong management team, and new infrastructure in place Rock is prepared to deliver solid production growth in 2008.

As we look at 2008 we believe the cycle has begun to turn again. Natural gas prices are improving and oil prices are more solid than ever. But the market has evolved. We believe it is important to continue an aggressive growth program that includes acquisitions and grassroots exploration. As the company grows it will be able to attract more support from the market and capture more opportunity to deliver value growth for its shareholders. We are pursuing these opportunities now.




Corporate Summary
Twelve Twelve Three Three
months months months months
ended ended ended ended
December December December December
31, 2007 31, 2006 31, 2007 31, 2006
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Financial
Oil and natural gas revenue ($000) $ 36,042 $ 33,156 $ 11,124 $ 7,535
Funds from operations ($000) (1) $ 15,189 $ 13,867 $ 4,735 $ 2,644
Per share - basic $ 0.72 $ 0.71 $ 0.18 $ 0.13
- diluted $ 0.72 $ 0.71 $ 0.18 $ 0.13
Net income (loss) ($000) $ 561 $ (884) $ 290 $ (119)
Per share - basic $ 0.03 $ (0.05) $ 0.01 $ (0.01)
- diluted $ 0.03 $ (0.05) $ 0.01 $ (0.01)
Capital expenditures, net ($000) $ 53,702 $ 2,004 $ 7,488 $ 6,223
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As at As at
December December
31, 2007 31, 2006
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Working capital including bank debt ($000) $(29,072) $(12,580)
Common shares outstanding (000) 25,878 19,637
Options outstanding (000) 2,308 1,767
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Twelve Twelve Three Three
months months months months
ended ended ended ended
December December December December
31, 2007 31, 2006 31, 2007 31, 2006
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Operations
Average daily production
Light crude oil (bbls/d) 215 179 206 206
Heavy crude oil (bbls/d) 1,194 792 1,323 1,168
NGL (bbls/d) 79 57 81 42
Natural gas (mcf/d) 4,261 6,421 6,372 3,528
Total (boe/d) 2,198 2,098 2,672 2,004
Average product prices
Light crude oil (Cdn$/bbl) $ 70.69 $ 64.46 $ 81.66 $ 57.77
Heavy crude oil (Cdn$/bbl) $ 41.18 $ 38.35 $ 42.56 $ 34.86
NGL (Cdn$/bbl) $ 60.00 $ 61.35 $ 67.81 $ 65.47
Natural gas (Cdn$/mcf) $ 6.96 $ 7.07 $ 6.64 $ 7.45
BOE (Cdn$/boe) $ 44.93 $ 43.27 $ 45.26 $ 40.73
Operating netback (Cdn$/boe) $ 23.79 $ 22.21 $ 24.77 $ 19.22
(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 and 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 Management's Discussion and Analysis is dated March 12, 2008 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, 2007.

Basis of Presentation

Financial measures referred to in this discussion, such as funds from operations and funds from operations per share, are not prescribed by generally accepted accounting principles (GAAP). Funds from operations is a key measure that demonstrates the ability to generate cash to fund expenditures. Funds from operations is 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 is 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 12, 2007 for projected 2007 and 2008 results. The table below provides the guidance for 2007 with actual results.




2007 Guidance
2007 Guidance Actual Difference
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2007 Production (boe/d)
Annual 2,150-2,250 2,198 0%
Exit (December average) 2,600-2,800 2,617 (3)%
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2006 Funds from Operations
Annual $15 million $15.2 million 1%
Annual (per share) $0.71 $0.72 1%
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2006 Capital Budget
Expenditures $26 million $25.6 million (2)%
Gross wells drilled 16 16 0%
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Total net debt at year end $29 million $29.1 million 0%
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Pricing (Fourth Quarter)
Oil - WTI US$85.00/bbl US$90.68/bbl 7%
Natural gas - AECO $6.25/mcf $6.15/mcf (2)%
US/Cdn dollar exchange rate 1.05 1.02 (3)%
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Production averages for the year and the exit rate were within the guidance range. Funds flow from operations was slightly above guidance as lower royalties offset higher G&A costs. Capital expenditures and debt levels were also at guidance levels.

Guidance for 2008 has been updated to reflect results from the winter drilling program and higher expected commodity prices. The table below updates the Company's previous guidance that was issued November 12, 2007.




2008 Previous 2008 Revised
Guidance Guidance Change
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2008 Production (boe/d)
Annual 3,200-3,400 3,400-3,600 6%
Exit 3,700-3,900 3,900-4,100 5%
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2008 Funds from Operations
Annual $22 million $28 million 27%
Annual - (per share) $0.86 $1.08 26%
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2008 Capital Budget
Expenditures $24 million $30 million 25%
Gross wells drilled 18-22 18-22 0%
Total net debt at year-end $31 million $31 million 0%
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Pricing (Annual)
Oil - WTI US$75.00/bbl US$85.00/bbl 13%
Natural gas - AECO Cdn$6.75/mcf Cdn$7.25/mcf 7%
US/Cdn dollar exchange rate 1.00 1.00 0%
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Rock anticipates production from the Saxon winter program to begin by June 2008 versus the previous guidance of October 2008. The Company did not farm out this prospect and retained a 100 percent working interest versus a budgeted 70 percent working interest. As a result, average annual and exit production rates have increased by about 200 boe per day. Capital expenditures have also increased by $6 million to reflect the higher working interest at Saxon and additional infrastructure costs. In the previous guidance the majority of the Saxon infrastructure was to be owned by a third party however, Rock has decided to keep control of this infrastructure. The majority of the increased capital spending is projected to be incurred by June 2008.

Based on the strength of commodity prices to date in 2008, we have increased the reference price of WTI to US$85.00 per barrel and natural gas at AECO to Cdn$7.25 per mcf. Royalty rates are assumed to be approximately 22.5 percent, operating costs per boe have been held at the same rate as previous guidance of $12.20 per boe, G&A costs have decreased to $2.30 per boe based on increased production, and interest costs have been increased reflecting higher average debt levels in the first half of 2008. Funds from operations for 2008 are projected to increase $6 million to $28 million ($1.08 per basic share) based on increased production and commodity prices and other changes noted above.

Rock's bank is reviewing its borrowing base based on the 2007 year-end reserve report. We expect an increase in the loan facility to $38 million from $36 million and to put in place a $6 million development facility which will allow us to finance the increased capital expenditures at Saxon. Given the timing of the capital expenditures and on-stream production date for Saxon, the Company's debt-to-funds flow ratio (based on annualized quarterly funds from operations) is projected to rise to 1.9:1 in the first quarter of 2008 but then fall throughout the year to 1:1 by year-end. 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 by year-end.



PRODUCTION and PRICES

Production by Product
12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 4,261 6,421 (34)% 6,372 3,528 81%
Oil (bbls/d) 215 179 20% 206 206 0%
Heavy oil (bbls/d) 1,194 792 51% 1,323 1,168 13%
NGL (bbls/d) 79 57 39% 81 42 93%
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Total (boe/d) (6:1) 2,198 2,098 5% 2,672 2,004 33%
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Production by Area
12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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West Central Alberta
(boe/d) 642 972 (34)% 1,041 652 60%
Plains (boe/d) 1,196 795 50% 1,325 1,171 13%
Other (boe/d) 360 331 9% 306 181 69%
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Total (boe/d) (6:1) 2,198 2,098 5% 2,672 2,004 33%
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Production increased 5 percent for the year ended December 31, 2007 over the prior year as the increase in heavy oil production more than offset the reduction in natural gas production. Heavy oil production increases were driven by drilling activity in 2007 and the latter half of 2006. Heavy oil production was negatively affected by natural gas migration issues at Edam in the second half of 2007 as natural gas appears to have permeated the oil zone. We are in the process of remediating the issue and hope to produce the natural gas from the oil zone by concurrently producing it with the oil starting in the second quarter of 2008.

Dispositions in July 2006 of approximately 820 boe per day reduced the natural gas production base for most of 2007 which was partially offset by the Greenbank acquisition that closed at the end of the third quarter in 2007. The Greenbank properties added approximately 500 boe per day of predominately natural gas production. The majority of the drilling in the West Central core area is directed at natural gas and the successful wells were not brought on-stream until the first quarter of 2008. Rock's current production is approximately 2,900 boe per day.

Production increased by 33 percent in the fourth quarter of 2007 from the same period last year as the Greenbank acquisition added production in the quarter while the property dispositions in July 2006 reduced production in the prior-year period. Post-2007 break-up drilling activities increased heavy oil production despite the loss of production from the natural gas migration issues at Edam. As a result of these activities the Company's natural gas weighting has increased from 29 percent in the fourth quarter of 2006 to 40 percent in the fourth quarter of 2007.



Product Prices
12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Realized Product
Prices
Natural gas ($/mcf) 6.96 7.07 (2)% 6.64 7.45 (11)%
Oil ($/bbl) 70.69 64.46 10% 81.66 57.77 41%
Heavy oil ($/bbl) 41.18 38.35 7% 42.56 34.86 22%
NGL ($/bbl) 60.00 61.35 (2)% 67.81 65.47 4%
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Combined average
($/boe) (6:1) 44.93 43.27 4% 45.26 40.73 11%
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12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Average Reference
Prices
Natural gas -
Henry Hub
Daily Spot
(US$/mmbtu) 6.98 6.75 3% 7.01 6.69 5%
Natural gas - AECO C
Daily Spot ($/mcf) 6.45 6.54 (2)% 6.15 6.99 (12)%
Oil - WTI Cushing,
Oklahoma (US$/bbl) 72.31 66.22 9% 90.68 60.21 51%
Oil - Edmonton Light
($/bbl) 76.35 72.77 5% 86.42 64.49 34%
Heavy oil -
Lloydminster blend
($/bbl) 51.63 50.07 3% 55.49 43.84 27%
US/Cdn $ exchange rate 0.935 0.882 6% 1.019 0.878 16%
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For the year and quarter ended December 31, 2007 the Company experienced higher oil prices and lower natural gas prices compared to the prior year periods. Rock's weighted average price per boe increased from the prior year which was driven by a higher overall oil weighting in the production mix. For the quarter the significant increase in oil pricing more than offset the reduction in natural gas pricing despite the increase in natural gas production in the overall production mix.

Heavy oil prices were stronger in both periods in 2007 compared to 2006 as WTI prices increased - more so in the fourth quarter of 2007. However, differentials widened in the fourth quarter of 2007 due to temporary pipeline issues, refinery turnarounds, higher condensate prices for blend and a stronger Canadian dollar. Oil prices have continued to remain strong in the first quarter of 2008 and the differential has narrowed and condensate prices have improved from fourth quarter 2007 levels. As a result Rock has been receiving more than $55 per barrel at the wellhead for heavy oil thus far in 2008.

Canadian natural gas prices for the year and fourth quarter of 2007 were below 2006 levels as the stronger Canadian dollar more than offset the modest increase in U.S. natural gas prices for these periods. Natural gas prices have improved in the first quarter of 2008 - currently over $8.00 per mcf - as colder weather has been experienced in North America and strong European and Asian pricing has reduced LNG shipments to North America. Reduced drilling activity in Canada should help support natural gas prices as supply is expected to decline. Natural gas prices traditionally decrease in the summer months as overall demand is reduced. Summer natural gas prices will be influenced by the amount of storage that needs to be replenished for the winter season, cooling demand and the amount of LNG that is imported into North America due to price differentials and demand in the European and Asian markets. The general lack of storage facilities in those markets could also impact the amount of LNG shipped to North America.

REVENUE

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



Oil and Natural Gas Revenue

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Natural gas $10,830 $16,560 (35)% $ 3,890 $ 2,408 61%
Oil 5,538 4,195 31% 1,547 1,073 39%
Heavy oil 17,951 11,124 62% 5,180 3,790 38%
NGL 1,724 1,277 36% 507 264 100%
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36,042 33,156 9% 11,124 7,535 48%
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Other revenue $ 79 $ 198 (60)% $ 12 $ 42 (71)%
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Oil and natural gas revenue increased by 9 percent for the year ended December 31, 2007 over 2006 due to higher production levels, particularly heavy oil, which more than offset lower natural gas production. For the fourth quarter of 2007 oil and natural gas revenue increased by 48 percent from the same period in 2006 as higher production, particularly natural gas, and higher oil prices more than offset the decrease in natural gas prices.



ROYALTIES
12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Royalties $7,035 $6,881 2% $2,017 $1,452 39%
As a percentage of
oil and natural gas
revenue 19.5% 20.8% (6)% 18.1% 19.3% (6)%
Per boe (6:1) $8.77 $8.98 (2)% $8.21 $7.88 4%
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Royalties increased for the year and quarter ended December 31, 2007 over the prior year periods due to higher production levels. The fourth quarter of 2007 included Alberta Royalty Tax Credits (ARTC) of $459. Although the ARTC program was cancelled effective January 1, 2007, the Alberta Government passed legislation late in 2007 allowing companies with off-calendar (non-December 31) tax year-ends to benefit from a full calendar year of ARTC. Without the ARTC benefit the royalty rates for 2007 would have been 22.2 percent for the quarter and 20.8 percent for the year. The Company is forecasting a royalty rate of approximately 22.5 percent for 2008.




OPERATING EXPENSES
12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Operating expense $ 9,505 $ 8,947 6% $ 2,889 $ 2,429 19%
Transportation costs 420 308 36% 130 83 57%
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9,925 9,255 7% 3,019 2,512 20%
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Per boe (6:1) $12.37 $12.08 2% $ 12.28 $ 13.63 (10)%
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Operating costs for the year and quarter ended December 31, 2007 have increased over 2006 primarily due to higher production. Operating expenses per boe were up slightly for the year ended 2007 compared to 2006 but down about 10 percent in the fourth quarter of 2007 versus the same period in 2006. Lower cost properties from the Greenbank acquisition benefitted fourth quarter 2007 results, while the fourth quarter of 2006 included prior period processing costs. Transportation costs have increased as a result of the acquired properties.

Heavy oil unit costs in 2007 decreased slightly year-over-year to $12.90 from $13.02 per boe and quarter-over-quarter to $13.61 from $14.33 per boe. Costs in the last half of 2007 trended up due to remediation efforts at Edam and 2006 costs were high due to the start-up costs as the result of significant heavy oil drilling that occurred in that year. Total Company operating expenses, including transportation expense, are forecast to be approximately $12.20 per boe in 2008.




GENERAL and ADMINSTRATIVE (G&A) EXPENSE

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Gross $ 4,791 $ 3,905 23% $ 1,593 $ 1,085 47%
Per boe (6:1) 5.97 5.10 17% 6.48 5.89 10%
Capitalized and
overhead recoveries 2,052 1,627 26% 638 395 62%
Per boe (6:1) 2.56 2.12 21% 2.60 2.14 21%
Net 2,739 2,278 20% 955 690 38%
Per boe (6:1) 3.41 2.97 15% 3.88 3.74 4%
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G&A expense increased on an absolute and per boe basis in 2007 over 2006 due to a higher overall cost environment and in particular the fourth quarter of 2007 also includes $300 of one-time costs associated with management changes and transition costs related to the Greenbank acquisition. Rock capitalizes certain G&A expenses based on personnel involved in the exploration and development initiatives, including salaries and related overhead costs. Gross G&A expenses are expected to be flat on an absolute on an absolute basis in 2008 but decrease on a per boe basis as production is expected to increase.



INTEREST EXPENSE

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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Interest expense
(recovery) $ 1,157 $ 924 25% $ 417 $ 141 195%
Per boe (6:1) $ 1.44 $ 1.21 20% $ 1.70 $ 0.76 121%
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Interest expense has increased for the year and fourth quarter of 2007 over the 2006 periods due to higher average bank debt as capital expenditures, excluding acquisitions, exceeded funds from operations and were funded through the Company's bank facility. Interest expense is expected to increase again in 2008 due to higher average bank debt and increase approximately 20 percent on a per boe basis.



DEPLETION, DEPRECIATION, and ACCRETION (DD&A)

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
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D&D expense $ 13,989 $ 13,989 0% $ 5,021 $ 2,707 85%
Per boe (6:1) $ 17.44 $ 18.27 (5)% $ 20.42 $ 14.69 39%
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Accretion expense $ 154 $ 129 20% $ 48 $ 34 41%
Per boe (6:1) $ 0.19 $ 0.17 14% $ 0.20 $ 0.18 11%
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Depletion and depreciation expense for the year ended December 31, 2007 equalled the prior year despite higher production and increased for the fourth quarter of 2007 from the 2006 period due to higher production and an increase in the per boe expense. The fourth quarter 2007 per boe depletion and depreciation expense increased as a result of negative reserve revisions recorded at Edam for the natural gas migration issue; reserves in the Greenbank acquisition which were at a higher cost than the existing base and increased capital activities in the West Central core area, which has relatively higher costs than the Plains core area.

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, constructing facilities or acquiring operations. Similarly, this obligation can also be reduced as a result of abandonment work undertaken and reducing future obligations. During the year ended December 31, 2007 capital programs and acquisitions increased the underlying ARO by $1,592 (December 31, 2006 - $413) and actual expenditures on abandonments were nil (December 31, 2006 - $104).

INCOME TAX

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 2008 as the Company and its subsidiaries have estimated resource and other pools available at December 31, 2007 (after the allocation of deferred partnership income) of approximately $106.1 million as set out below:



CEE $ 42.0 million
CDE $ 28.5 million
COGPE $ 4.7 million
UCC $ 14.9 million
Loss carry-forwards $ 14.5 million
Other $ 1.5 million
----------------------------------------------------------------------------
Total $ 106.1 million


FUNDS FROM OPERATIONS and NET INCOME/(LOSS)

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
----------------------------------------------------------------------------

Funds from
operations $15,189 $13,867 10% $ 4,735 $ 2,644 79%
Per boe (6:1) $ 18.93 $ 18.11 5% $ 19.26 $ 14.35 34%
----------------------------------------------------------------------------
Per share:
Basic $ 0.72 $ 0.71 1% $ 0.18 $ 0.13 38%
Diluted $ 0.72 $ 0.71 1% $ 0.18 $ 0.13 38%
----------------------------------------------------------------------------
Net income
(loss) $ 561 $ (884) 165% $ 290 $ (119) 344%
Per boe (6:1) $ 0.70 $ (1.15) 161% $ 1.18 $ (0.65) 279%
----------------------------------------------------------------------------
Per share:
Basic $ 0.03 $ (0.05) 160% $ 0.01 $ (0.01) 200%
Diluted $ 0.03 $ (0.05) 160% $ 0.01 $ (0.01) 200%
----------------------------------------------------------------------------
Weighted average
shares
outstanding:
Basic 21,239 19,637 8% 25,847 19,637 32%
Diluted 21,239 19,655 8% 25,847 19,637 32%
----------------------------------------------------------------------------


The Company issued 6.1million shares at September 28, 2007 to acquire Greenbank and issued 0.1 million flow-through shares at November 1, 2007 to new management appointments. The Company did not issue any shares in 2006.

Funds from operations for the year ended December 31, 2007 increased by 10 percent over 2006 as the increase in production and realized prices more than offset the increase in royalties, operating, G&A and interest costs. On a per-boe basis, 2007 funds from operations increased by 5 percent from 2006 primarily for the same reasons except for the reduction in royalties. For the fourth quarter of 2007 funds from operations increased by 79 percent on an absolute basis and 34 percent on a per boe basis from the prior year's periods primarily as the increase in production and prices more than offset the increase in royalties, G&A and interest costs. On a per share basis, funds from operations was essentially flat in 2007 versus 2006 but increased 38 percent in the fourth quarter of 2007 over the same quarter in 2006. The Company generated net income for the year and quarter ended December 31, 2007 versus net losses in the prior year periods primarily as a result of booking future income tax recovery in 2007, compared to an expense in 2006, and as a result of the reduction in the future tax rate and the tax pools associated with the Greenbank acquisition. As a result net income per share also increased over the prior year periods.



CAPITAL EXPENDITURES

12 Months 12 Months 3 Months 3 Months
Ended Ended Ended Ended Quarterly
($000) 12/31/07 12/31/06 Change 12/31/07 12/31/06 Change
----------------------------------------------------------------------------

Land $ 3,723 $ 4,822 (23)% $ 457 $ 120 280%
Seismic 1,359 1,081 26% 56 127 (56)%
Drilling and
completions 16,689 25,130 (34)% 5,567 5,758 (3)%
Capitalized G&A 2,004 1,627 23% 589 395 49%
Natural gas
gathering systems 694 247 181% 665 _ n/a
----------------------------------------------------------------------------
Total operations $24,469 $32,907 (26)% $ 7,334 $ 6,400 15%
----------------------------------------------------------------------------
Property
acquisitions
(dispositions)(1) 28,127 (30,874) 191% Nil Nil n/a
Well site
facilities
inventory 94 (165) 157% (19) (206) (91)%
Office equipment 1,012 136 644% 173 39 342%
----------------------------------------------------------------------------
Total (net of
acquisitions and
dispositions) $53,702 $ 2,004 2,580% $ 7,488 $ 6,233 20%
----------------------------------------------------------------------------
(1) Property acquisition for 2007 have been restated from the third quarter
report to be presented as the amount allocated to property plant and
equipment versus the consideration paid.


Capital expenditures for operations decreased for the year ended December 31, 2007 compared to 2006 as Rock drilled 16 (12.2 net) wells in 2007 versus 33 (28.3 net) wells in 2006. While the number of wells decreased the average cost per well increased as the Company participated in relatively more West Central core area operations than Plains core area operations in 2007. West Central core area targets tend to be deeper multi-zone natural gas targets which are more expensive than shallower heavy oil drilling that occurs in the Plains core area. Natural gas gathering expenditures also increased as tie-in operations were commenced in the Musreau and Kakwa areas and the resulting production came on-stream in the first quarter of 2008.

Land expenditures decreased as the Company focused more on drilling prospects that have been generated in the West Central core area. Seismic expenditures increased as additional seismic was acquired over the Elmworth area. Total net capital expenditures were increased to $54 million in 2007 from $2 million in 2006 as the Company completed the Greenbank acquisition in 2007 and divested properties in 2006.

During 2007, Rock drilled 11 (10.9 net) operated wells and five (1.3 net) non-operated wells, achieving a 91 percent success rate, compared to 27 (27.0 net) operated wells and six (1.3 net) non-operated wells and a 96 percent success rate in 2006. In the Plains core area Rock drilled 8 (8.0 net) heavy oil wells, one (0.9 net) natural gas well and one (1.0 net) dry hole. All of the wells were operated and all successful wells were on-production at year-end. The natural gas well was drilled at Edam and is part of the remediation efforts to remove natural gas from the oil zone. Plains core area production remained relatively flat in 2007 despite limited drilling and production problems at Edam. In the West Central Alberta core area Rock drilled five (2.2 net) natural gas wells and one (0.1 net) dry hole. Of the five natural gas wells drilled two (0.7 net) were at Kakwa, one (0.2 net) at Musreau, one (0.3 net) at Elmworth and one (1.0 net) at Saxon. The three wells at Kakwa and Musreau were tied-in in the first quarter of 2008 and the Elmworth and Saxon wells are expected to be tied-in the second quarter of 2008. Since year end one (1.0 net) additional natural gas well has been drilled at Saxon. The two Saxon wells and the Elmworth well are expected to add more than 800 boe per day of production once they are on stream.

LIQUIDITY AND CAPITAL RESOURCES

At the end of the third quarter of 2007, Rock completed the acquisition of Greenbank Energy by issuing 3.1 million shares and 3.0 million shares in a private placement to fund the cash portion of the transaction. Capital expenditures, excluding acquisitions, of $25.6 million in 2007 were primarily funded through cash from operations of $14.2 million and bank debt.

Rock's current approved capital budget for 2008 projects spending of $30 million. In 2008 funds from operations are expected to be approximately $28 million. The capital spending in excess of cash flow is intended to be funded through bank debt. Approximately half of the capital budget is expected to be spent in the first four months of the year as the Saxon infrastructure is put in place which should allow the associated production to be on-stream by June. The timing of expenditures will likely cause the Company to temporarily exceed its borrowing base and we expect the bank will provide a $6 million development facility to finance the capital requirements associated with the Saxon infrastructure. At year-end 2007 Rock had debt of $29.1 million against bank lines of $36 million. The bank is currently reviewing the borrowing base and we expect an increase in operating line to $38 million. The Company's debt-to-funds from operations ratio was 1.9:1 at year-end based on annual 2007 results; however this ratio includes all the debt from the Greenbank acquisition but only one quarter of the funds from operations. Based on annualized fourth quarter cash flow, the debt-to-funds from operations ratio was 1.5:1. With the current capital investemnt occurring in the West Central core area, Rock expects the debt-to-funds from operations ratio to increase to 1.9:1 in the first quarter of 2008 and then be reduced as production is brought on stream ending the year at 1.0:1.

The Company has a demand operating loan facility with a Canadian chartered bank. The facility is subject to the bank's valuation of the Company's oil and natural gas assets and the credit currently available is $36 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 undrawn 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 next interim review for the facility is scheduled to be completed by April 30, 2008. As at March 11, 2008 approximately $30.1 million was drawn under the facility.



SELECTED ANNUAL DATA

The following table provides selected annual information for Rock:

12 Months 12 Months 12 Months
Ended Ended Ended
12/31/07 12/31/06 12/31/05
----------------------------------------------------------------------------

Production (boe/d) 2,198 2,098 1,122
Oil and natural gas revenues ($000) $ 36,042 $ 33,156 $ 22,873
----------------------------------------------------------------------------
Average realized price ($/boe) $ 44.93 $ 43.27 $ 55.85
Royalties ($/boe) $ 8.77 $ 8.98 $ 12.28
Operating expense ($/boe) $ 12.37 $ 12.08 $ 11.59
Operating netback ($/boe) $ 23.79 $ 22.21 $ 31.98
Net G&A expense ($000) $ 2,739 $ 2,278 $ 1,411
Stock-based compensation ($000) $ 928 $ 1,188 $ 485
----------------------------------------------------------------------------
Funds from operations ($000) $ 15,189 $ 13,867 $ 11,433
Per share - basic $ 0.72 $ 0.71 $ 0.74
Per share - diluted $ 0.72 $ 0.71 $ 0.74
----------------------------------------------------------------------------

Net income (loss) $ 561 $ (884) $ 1,510
Per share - basic $ 0.03 $ (0.05) $ 0.10
Per share - diluted $ 0.03 $ (0.05) $ 0.10
----------------------------------------------------------------------------
As at As at As at
12/31/07 12/31/06 12/31/05
----------------------------------------------------------------------------

Total assets $130,495 $ 85,380 $ 99,603
Total liabilities $ 44,301 $ 24,901 $ 39,385
----------------------------------------------------------------------------

SELECTED QUARTERLY DATA

The following table provides selected quarterly information for Rock:

3 Months 3 Months 3 Months 3 Months
Ended Ended Ended Ended
12/31/07 09/30/07 06/30/07 03/31/07
----------------------------------------------------------------------------
Production (boe/d) 2,672 1,965 2,036 2,114
Oil and natural gas revenues ($000) $ 11,126 $ 8,106 $ 8,279 $ 8,533
Average realized price ($/boe) $ 45.26 $ 44.85 $ 44.66 $ 44.84
Royalties ($/boe) $ 8.21 $ 9.18 $ 9.23 $ 8.66
Operating expense ($/boe) $ 12.28 $ 12.38 $ 12.10 $ 12.75
Operating netback ($/boe) $ 24.77 $ 23.29 $ 23.33 $ 23.43
Net G&A expense ($000) $ 955 $ 528 $ 530 $ 726
Stock-based compensation ($000) $ 213 $ 207 $ 241 $ 267
Funds from operations ($000) $ 4,735 $ 3,397 $ 3,536 $ 3,521
Per share - basic $ 0.18 $ 0.17 $ 0.18 $ 0.18
Per share - diluted $ 0.18 $ 0.17 $ 0.18 $ 0.18
Net income (loss) ($000) $ 290 $ 15 $ (117) $ 373
Per share - basic $ 0.01 $ 0.00 $ (0.01) $ 0.02
Per share - diluted $ 0.01 $ 0.00 $ (0.01) $ 0.02
Capital expenditures ($000) $ 7,488 $ 8,367 $ 2,552 $ 7,184
----------------------------------------------------------------------------
As at As at As at As at
12/31/07 09/30/07 06/30/07 03/31/07
----------------------------------------------------------------------------
Working capital ($000) ($29,072) ($26,589) ($15,268) ($16,242)
----------------------------------------------------------------------------


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)
----------------------------------------------------------------------------


Production was relatively flat over the first three quarters of 2007 as activities were primarily directed at West Central core area projects that are expected to be on-stream in the first half of 2008. Production increased in the fourth quarter of 2007 as a result of the Greenbank acquisition. The operating netback was also relatively stable over the first three quarters of 2007 resulting in a constant level of funds from operations. Improved pricing and lower royalties (due to the ARTC benefit) in the fourth quarter of 2007 increased the operating netback slightly and with higher production, funds from operations improved about 40 percent over the previous quarter.

G&A expenses were higher in the fourth quarter of 2007 due to costs associated with year-end reporting, management changes and Greenbank transition costs. Net capital expenditures were low in the second quarter of 2007 due to spring breakup conditions as the Company did not drill any wells. A significant portion of Rock's West Central core area activities are winter-access only and as a result these operations tend to be concentrated in the December to March timeframe. The Company usually undertakes Plains core area and Elmworth activities in the third quarter of the year. Negative working capital increased significantly in the last half of 2007 as Rock drilled 4 (4.0 net) heavy oil wells in the Plains core area and began operations in the West Central core area, particularly at Kakwa, Musreau, Elmworth and Saxon.

Reserves

Rock's reserves have been independently evaluated by GLJ Petroleum Consultants Ltd. (GLJ) at year-end 2007. This is the fourth year in which GLJ has evaluated the Company's reserves. The reserves as at December 31, 2007 and 2006 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 2006 and year-end 2007 on a gross basis (before deducting royalties and without including any royalty interest) (gross interest).

Rock's gross interest reserves at year-end 2007 are 5.3 million boe of proved reserves and 9.3 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 0.7 million boe of proved reserves and 0.9 million boe of proved plus probable reserves and the Greenbank acquisition which added 1.0 million of proved reserves and 1.9 million of proved plus probable reserves.

RESERVES RECONCILIATION

The following table is a reconciliation of Rock's gross interest reserves at December 31, 2007 using GLJ's forecast pricing and cost estimates as at December 31, 2007.



Light and
Medium 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, 2006 413 588 119 183 2,705 4,299
Additions(1) 0 0 72 113 378 532
Technical revisions(2) 7 (3) (3) (9) (359) (617)
Acquisitions 45 69 45 98 0 0
Dispositions 0 0 0 0 0 0
Production (81) (81) (26) (26) (450) (450)
----------------------------------------------------------------------------
December 31, 2007 383 572 207 360 2,275 3,764
----------------------------------------------------------------------------
Total
Natural Gas Oil Equivalent
----------------------------------------------------------------------------
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (mmcf) (mmcf) (mboe) (mboe)
----------------------------------------------------------------------------

December 31, 2006 7,507 13,591 4,488 7,334
Additions(1) 2,986 5,167 949 1,506
Technical revisions(2) 472 73 (278) (617)
Acquisitions 5,289 10,383 971 1,898
Dispositions 0 0 0 0
Production (1,536) (1,536) (812) (812)
----------------------------------------------------------------------------
December 31, 2007 14,717 27,677 5,318 9,309
----------------------------------------------------------------------------
(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; mbbl equals 1,000 bbl, mmcf
equals 1,000 mcf, mboe equals 1,000 boe.

RESERVES AND NET PRESENT VALUE (FORECAST PRICES AND COSTS)

The following tables summarize Rock's remaining gross interest reserves
volumes along with the value of future net revenue utilizing GLJ's forecast
pricing and cost estimates as at December 31, 2007.

Reserves
Light and Natural Total Oil
Medium Oil NGL Heavy Oil Gas Equivalent
----------------------------------------------------------------------------
Reserves Category (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
----------------------------------------------------------------------------
Proved
Proved producing 323 99 1,919 7,230 3,545
Proved non-producing 60 91 124 5,440 1,183
Proved undeveloped 0 17 232 2,047 590
----------------------------------------------------------------------------
Total proved 383 207 2,275 14,717 5,318
Probable additional 189 152 1,489 12,960 3,991
----------------------------------------------------------------------------
Total proved plus probable 572 360 3,764 27,677 9,309
----------------------------------------------------------------------------
Note: Figures may not add due to rounding; mbbl equals 1,000 bbl, mmcf
equals 1,000 mcf, mboe equals 1,000 boe. .


Net Present Value of Future Net Revenue

Before Income Taxes
----------------------------------------------------------------------------
($000) Discounted at (% per year)
----------------------------------------------------------------------------
Reserves Category 0 5 10 15 20
----------------------------------------------------------------------------
Proved
Proved producing 95,480 82,548 73,339 66,361 60,844
Proved non-producing 29,247 24,258 20,840 18,304 16,333
Proved undeveloped 6,439 4,508 3,106 2,058 1,254
----------------------------------------------------------------------------
Total proved 131,166 111,314 97,285 86,722 78,431
Probable additional 94,553 70,100 55,135 45,009 37,702
----------------------------------------------------------------------------

Total proved plus probable 225,719 181,414 152,420 131,731 116,133
----------------------------------------------------------------------------

After Income Taxes
----------------------------------------------------------------------------
($000) Discounted at (% per year)
----------------------------------------------------------------------------
Reserves Category 0 5 10 15 20
----------------------------------------------------------------------------
Proved
Proved producing 95,480 82,548 73,339 66,361 60,844
Proved non-producing 24,015 20,477 17,923 15,998 14,469
Proved undeveloped 4,623 2,948 1,754 875 211
----------------------------------------------------------------------------
Total proved 124,118 105,943 93,016 83,234 75,524
Probable additional 69,250 51,177 39,998 32,469 27,063
----------------------------------------------------------------------------
Total proved plus probable 193,639 157,121 133,014 115,703 102,587
----------------------------------------------------------------------------
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 forecast prices and costs evaluation.




Summary of Pricing and Cost Rate Assumptions at December 31, 2007 - Forecast
Prices and Costs


Oil
---------------------------------------------------
Edmonton Cromer Hardisty
WTI Reference Medium Heavy
Cushing Price 29 degree API 12 degree API
Year (US$/bbl) ($/bbl) ($/bbl) ($/bbl)
----------------------------------------------------------------------------
2008 92.00 91.10 79.26 54.02
2009 88.00 87.10 75.78 51.61
2010 84.00 83.10 72.30 49.19
2011 82.00 81.10 70.56 47.98
2012 82.00 81.10 70.56 47.98
2013 82.00 81.10 70.56 49.04
2014 82.00 81.10 70.56 50.09
2015 82.00 81.10 70.56 51.15
2016 82.02 81.12 70.57 52.21
2017 83.66 82.76 72.00 53.29
2018 85.33 84.42 73.44 54.36
2019+ +2%/yr +2%/yr +2%/yr +2%/yr
----------------------------------------------------------------------------


Natural
NGL Gas
-------------------------------------- ----------
Cost
Edmonton Edmonton Edmonton US$/Cdn$ Inflation
Propane Butane Pentane Ethane AECO-C Exchange Rate
Year ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/mcf) Rate (%/year)
----------------------------------------------------------------------------
2008 58.30 72.88 92.92 22.73 6.75 1.00 2
2009 55.74 69.68 88.84 25.49 7.55 1.00 2
2010 53.18 66.48 84.76 25.66 7.60 1.00 2
2011 51.90 64.88 82.72 25.66 7.60 1.00 2
2012 51.90 64.88 82.72 25.66 7.60 1.00 2
2013 51.90 64.88 82.72 25.66 7.60 1.00 2
2014 51.90 64.88 82.72 26.35 7.80 1.00 2
2015 51.90 64.88 82.72 26.94 7.97 1.00 2
2016 51.91 64.89 82.74 27.52 8.14 1.00 2
2017 52.97 66.21 84.42 28.11 8.31 1.00 2
2018 54.03 68.20 86.11 28.67 8.48 1.00 2
2019+ +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 1.00 2
----------------------------------------------------------------------------

FINDING, DEVELOPMENT AND ACQUISITION COSTS

The following table summarizes Rock's finding, development and acquisition
costs for the years ended December 31, 2007, 2006 and 2005, including
future development costs.

12 months 12 months 12 months 3 Year
ended ended ended Cumulative
Dec. 31, 2007 Dec. 31, 2006 Dec. 31, 2005 Total
----------------------------------------------------------------------------
Oil and Natural Gas
Operations:
Proved finding and
development costs
Capital expenditures(1)
($000) $24,163 $32,907 $22,912 $ 79,982
Change in future
capital costs ($000) 3,501 2,939 962 7,402
----------------------------------------------------------------------------
Total capital ($000) $27,664 $35,846 $23,874 $ 87,384
----------------------------------------------------------------------------
Reserve additions(2) (mboe) 949 2,181 1,188 4,318
Proved finding and
development costs
($/boe) $ 29.15 $ 16.44 $ 20.10 $ 20.24
----------------------------------------------------------------------------
Proved plus probable
finding and development
costs
Capital expenditures(1)
($000) $24,163 $32,907 $22,912 $ 79,982
Change in future
capital costs ($000) 3,930 7,986 $ 3,900 $ 15,816
----------------------------------------------------------------------------
Total capital ($000) $28,093 $40,893 $26,812 $ 95,798
----------------------------------------------------------------------------
Reserve additions(2) (mboe) 1,506 3,624 2,201 7,331
Proved plus probable
finding and development
costs ($/boe) $ 18.66 $ 11.28 $ 12.18 $ 13.07
----------------------------------------------------------------------------
Acquisitions/Dispositions:
Proved finding and
development costs -
acquisitions
(dispositions)
Capital expenditures(1)
($000) $28,524 $(30,878) $60,853 $ 58,499
Change in future
capital costs ($000) 4,136 (2,400) 3,647 5,383
----------------------------------------------------------------------------

Total capital ($000) $32,660 $(33,278) $64,500 $ 63,882
----------------------------------------------------------------------------

Reserve additions
(mboe) 971 (1,042) 2,397 2,326
Proved finding and
development costs
($/boe) $33.64 $(31.94) $26.91 $ 27.46
----------------------------------------------------------------------------

Proved plus probable
finding and development
costs - acquisitions
(dispositions)
Capital expenditures(1)
($000) $28,524 $(30,878) $60,853 $ 58,499
Change in future
capital costs ($000) 11,417 (2,400) 3,733 12,750
----------------------------------------------------------------------------
Total capital ($000) $39,941 $(33,278) $64,586 $ 71,249
----------------------------------------------------------------------------
Reserve additions (mboe) 1,898 (1,406) 3,154 3,646
Proved plus probable finding
and development costs
($/boe) $ 21.05 $ (23.67) $ 20.48 $ 19.54
----------------------------------------------------------------------------

Total Activities:
Proved finding and
development costs
Capital expenditures(1)
($000) $52,687 $ 2,029 $83,765 $138,481
Change in future capital
costs ($000) 7,637 539 4,609 12,785
----------------------------------------------------------------------------

Total capital ($000) $60,324 $ 2,568 $88,374 $151,266
----------------------------------------------------------------------------

Reserve additions(3) (mboe) 1,643 1,279 3,620 6,542
Total proved finding and
development costs ($/boe) $ 36.72 $ 2.01 $ 24.41 $ 23.12
----------------------------------------------------------------------------
Proved plus probable finding
and development costs
Capital expenditures(1)
($000) $52,687 $ 2,029 $83,765 $138,481
Change in future capital
costs ($000) 15,347 5,586 7,633 28,566
----------------------------------------------------------------------------

Total capital ($000) $68,034 $ 7,615 $91,398 $167,047
----------------------------------------------------------------------------

Reserve additions(3) (mboe) 2,786 2,153 5,284 10,223
Total Proved plus probable
finding and development
costs ($/boe) $ 24.42 $ 3.54 $ 17.30 $ 16.34
----------------------------------------------------------------------------
(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, development and acquisition ("FD&A") 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. FD&A costs on the acquired properties are based on the reserve evaluation as at each respective year end less new reserves from operations post closing and were increased by the amount of production from the closing date to December 31 of the respective year to provide an estimate of the reserves purchased. FD&A 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. FD&A costs for total activities include operations, acquisitions, dispositions and reserve revisions.

Finding and development costs on operations increased in 2007 compared to 2006 and 2005 as Rock spent more capital in the higher cost West Central core area versus the relatively less expensive Plains core area in order to test the Company's exploration prospects, particularly Saxon and Kakwa. While the operations were successful these projects did not come on stream in 2007 and as a result reserve bookings, in management's view, are conservative given the lack of production history. In addition a significant amount of land, seismic and infrastructure costs (including future capital) are incurred for these projects. Future drilling locations should benefit from these expenditures. Rock completed the Greenbank acquisition at the end of the third quarter of 2007 and the reserve report contains a significant amount of future capital given the down spacing opportunities that exist on this land base. The FD&A calculations in the table above do not exclude any amounts for undeveloped land, valued at $5 million at the time of closing. Overall FD&A costs are high for 2007 and include significant technical revisions in our heavy oil properties particularly at Edam where the Company experienced the natural gas migration issue. Remediation efforts are currently underway to remove the natural gas from the oil zones and further restore production. If successful, management would expect to see a positive reserve revision in the future. On a three year basis the FD&A costs are in our view more reflective of the progress made in growing the Company and generate recycle ratios (FD&A divided by operating netback) of 1.9:1 for operations and 1.5:1 overall.



LAND HOLDINGS
The following table summarizes Rock's land holdings as at December 31, 2007
and 2006:

Dec. 31, Dec. 31,
(acres) 2007 2006 Change
----------------------------------------------------------------------------
Developed - Gross 87,882 63,085 39%
- Net 32,406 23,566 38%
----------------------------------------------------------------------------
Undeveloped - Gross 135,069 76,030 78%
- Net 61,718 39,429 57%
----------------------------------------------------------------------------
Total - Gross 222,951 139,115 60%
- Net 94,123 62,995 49%
----------------------------------------------------------------------------


NET ASSET VALUE

The following table summarizes Rock's net asset value and net asset value
per share as at December 31, 2007 and December 31, 2006:

($000 except number of shares and net asset December December Change
value per share) 31, 2007 31, 2006
----------------------------------------------------------------------------
Proved plus probable reserves(1) (2) 152,420 105,688 44%
Undeveloped land(3) 13,380 8,220 63%
Working capital including debt (29,094) (12,580) 132%
----------------------------------------------------------------------------
Net asset value (Basic) 136,706 101,328 35%
Basic shares (000) 25,878 19,637 32%
----------------------------------------------------------------------------
Net asset value per share (basic) $5.28 $5.16 2%
----------------------------------------------------------------------------
Option proceeds 7,893 7,405 7%
----------------------------------------------------------------------------
Net asset value (Diluted) 144,599 108,733 33%
Diluted shares (000) 28,185 21,405 32%
----------------------------------------------------------------------------
Net asset value per share (diluted) $5.13 $5.08 1%
----------------------------------------------------------------------------
(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 2007 and 2006 forecast pricing and costs estimates and
using a discount rate at 10 percent.
(2) Reserve values are based on the existing Alberta royalty regime.
(3) 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 and land acquired through the
Greenbank acquisition in the third quarter of 2007 has been valued at
$200 per acre.


Reserve values in the above table are based on the existing Alberta royalty regime. GLJ Petroleum Consultants Ltd. prepared high and low sensitivity cases under the proposed Alberta royalty regime based on assumptions that all independent consulting firms agreed to use in their evaluations. The low royalty sensitivity case assumes that a heavy oil par price is used in the royalty calculations, solution natural gas royalties are calculated using the same rate and price basis as non-associated natural gas, and the deep natural gas royalty adjustment is applied to all existing and future wells. The high royalty sensitivity case assumes that a light oil par price is used in the royalty calculations for heavy oil, solution natural gas royalties are calculated using the same rate and price basis as non-associated natural gas but restricted to no less than the current royalty rate of 30 percent on solution natural gas, and the deep natural gas royalty adjustment is applied only to wells drilled after 2008.

The following table summarizes Rock's proved and probable reserve values, net asset value and net asset value per share as at December 31, 2007 under the different royalty assumptions:




December December December
31, 2007 31, 2007 31, 2007
($000 except number of shares and net asset Existing Low High
value per share) Royalty Royalty Royalty
----------------------------------------------------------------------------
Proved plus probable reserves(1) 152,420 152,420 144,747
----------------------------------------------------------------------------
Net asset value (Basic) 136,706 136,706 129,033
Basic shares (000) 25,878 25,878 25,878
----------------------------------------------------------------------------
Net asset value per share (basic) $5.28 $5.28 $4.99
----------------------------------------------------------------------------
Net asset value (Diluted) 144,599 144,599 136,926
Diluted shares (000) 28,185 28,185 28,185
----------------------------------------------------------------------------
Net asset value per share (diluted) $5.13 $5.13 $4.86
----------------------------------------------------------------------------
(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 2007 forecast pricing and costs estimates and using a
discount rate at 10 percent.


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:

2008 2009 2010 2011 2012
----------------------------------------------------------------------------
Office premise leases $ 895 $ 828 $ 828 $ 828 $ 552
Processing agreements 450 360 288 238 159
Demand bank loan(1) $27,405
----------------------------------------------------------------------------
(1) The demand bank loan is currently under its annual review and is
expected to remain in place.


OUTSTANDING SHARE DATA

At December 31, 2007 and to date, Rock had 25,877,642 common shares outstanding. At December 31, 2007 the Company had 2,307,822 stock options outstanding with an average exercise price of $3.42 per share. As of the date hereof Rock has 2,145,363 options outstanding.

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 Company has a corporate disclosure policy that is distributed to and made available to staff through the corporate computer network. The policy is reviewed by the Chief Executive Officer, Chief Financial Officer and the Board of Directors annually. Procedures were developed and put in place in support of the disclosure policy. The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of the disclosure controls and procedures as at December 31, 2007 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, 2007. The Company acquired Greenbank at the end of the third quarter of 2007 and assimilated the accounts into Rock's existing accounts and as a result there was no material change to the design of internal controls over financial reporting. In addition the Company did not make any other material change to internal controls in 2007. 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

As of January 1, 2007 the Company adopted new policies to implement the pronouncements from the Canadian Institute of Chartered Accountants in respect of financial instruments - presentation and disclosures, hedging and other comprehensive income. The new standards require certain financial instruments to be recognized on the balance sheet at their fair value. The application of these policies did not result in changes to amounts reported in the consolidated financial statements for the period ended December 31, 2007.

NEW ACCOUNTING PRONOUNCEMENTS

Capital Disclosures

The Canadian Institute of Chartered Accountants (CICA) issued CICA Handbook section 1535, Capital Disclosures. The section is effective for fiscal years beginning on or after October 1, 2007. It requires disclosure on objectives, policies and processes for managing capital.

Rock will adopt this section effective January 1, 2008.

Financial Instruments - Disclosures and Presentation

The Canadian Institute of Chartered Accountants (CICA) issued CICA Handbook section 3862, Financial Instruments - Disclosures and section 3863, Financial Instruments - Presentation which replace section 3861, Financial Instruments - Disclosures and Presentation. These sections are effective for fiscal years beginning on or after October 1, 2007. Section 3863 does not change the presentation requirements of the previous section 3861 however, section 3862 places new increased emphasis on the nature and extent of risks arising from financial instruments and how they are managed. Rock will adopt this section effective January 1, 2008.

International Financial Reporting Standards

The Canadian Institute of Chartered Accountants proposed to implement International Financial Reporting Standards ("IFRS") as part of Canadian GAAP. The adoption of IFRS in Canada will result in significant changes to current Canadian GAAP and to financial reporting practices followed by Rock. IFRS accounting standards are scheduled to be implemented for years beginning after December 31, 2010. Rock will be required to adopt the standard for the year beginning January 1, 2011. Currently, the application of IFRS in Canada and particularly to the oil and natural gas industry requires further clarification and as a result the effect of IFRS adoption on the Company's accounting policies and reporting standards and practices is not presently determinable.

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 judgements 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 judgement 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. Judgements 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 was 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 engineering and 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 competitive nature of the industry, 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. Increased public and political concern regarding climate change issues will likely result in increased regulation regarding emissions standards. Given that the Company produces hydrocarbons, such regulation could cause Rock to alter the way it operates and also result in additional costs and taxes associated with climate change regulation which could have a material effect on the Company.

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 800, 607 - 8th Avenue S.W., Calgary, Alberta, T2P 0A7.

Management's Report

To the Shareholders of Rock Energy Inc.:

The financial statements of Rock Energy Inc. were prepared by management in accordance with appropriately selected generally accepted accounting principles in Canada. Management has used estimates and careful judgement, particularly in those circumstances where transactions affecting current periods are dependent on information not known until a future period. The financial and operational information contained in this annual report is consistent with that reported in the financial statements.

Management is responsible for the integrity of the financial and operational information contained in this report. The Company has designed and maintains internal controls to provide reasonable assurance that assets are properly safeguarded and that the financial records are well maintained and provide relevant, timely and reliable information to management. The financial statements have been prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized in the notes to the financial statements.

External auditors appointed by the shareholders have conducted an independent examination of the corporate and accounting records in order to express their opinion on the financial statements. The Audit Committee has met with the external auditors and management in order to determine if management has fulfilled its responsibilities in the preparation of the financial statements. The Board of Directors has approved the financial statements on the recommendation of the Audit Committee.

Allen J. Bey

President and Chief Executive Officer

March 12, 2008

Peter D. Scott

Vice President, Finance and Chief Financial Officer

March 12, 2008

Auditors' Report

We have audited the consolidated balance sheets of Rock Energy Inc. as at December 31, 2007 and 2006 and the consolidated statements of income (loss), comprehensive income (loss) and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

KPMG LLP

Chartered Accountants

Calgary, Canada

March 12, 2007



Consolidated Balance Sheets

(000s of dollars)

December December
As at 31,2007 31, 2006
----------------------------------------------------------------------------
Assets
Current assets
Accounts receivable $ 8,473 $ 4,753
Prepaid expenses 1,383 532
----------------------------------------------------------------------------
9,856 5,285
Property, plant and equipment (note 5) 151,762 97,229
Accumulated depletion and depreciation (36,871) (22,882)
----------------------------------------------------------------------------
114,891 74,347
Goodwill 5,748 5,748
----------------------------------------------------------------------------
$ 130,495 $ 85,380
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 11,523 $ 6,900
Bank debt (note 6) 27,405 10,965
----------------------------------------------------------------------------
38,928 17,865
Future tax liability (note 10) 1,533 4,942
Asset retirement obligation (note 7) 3,840 2,094
Shareholders' equity
Share capital (note 8) 81,600 57,326
Contributed surplus (note 9) 2,521 1,641
Retained earnings 2,073 1,512
----------------------------------------------------------------------------
86,194 60,479
----------------------------------------------------------------------------
Commitments (note 12)
----------------------------------------------------------------------------
$ 130,495 $ 85,380
See accompanying notes to consolidated financial statements.
Approved by the Board:

James K. Wilson Allen J. Bey
Director Director


Consolidated Statements of Income (Loss), Comprehensive Income (Loss) and
Retained Earnings

(000s of dollars, except per share amounts)

Years ended December December
31, 2007 31, 2006
----------------------------------------------------------------------------
Revenues:
Oil and natural gas revenue $ 36,042 $ 33,156
Royalties (7,035) (6,881)
Other income 79 198
----------------------------------------------------------------------------
29,086 26,473
Expenses:
General and administrative 2,739 2,278
Operating 9,925 9,255
Interest 1,157 924
Stock-based compensation (note 9) 931 1,188
Depletion, depreciation, and accretion 14,143 14,118
----------------------------------------------------------------------------
28,895 27,763
----------------------------------------------------------------------------
Income (loss) before taxes 191 (1,290)

Taxes
Provincial capital taxes (note 10) 76 45
Future income taxes (reduction) (note 10) (446) (451)
----------------------------------------------------------------------------
Net income (loss) and comprehensive income (loss) for
the year 561 (884)
Retained earnings, beginning of year 1,512 2,396
----------------------------------------------------------------------------
Retained earnings, end of year $ 2,073 $ 1,512
----------------------------------------------------------------------------
Diluted and basic net income (loss) per share (note 8) $ 0.03 $ (0.05)
----------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.


Consolidated Statements of Cash Flows

(000s of dollars)

Years ended December December
31, 2007 31, 2006
----------------------------------------------------------------------------
Cash provided by (used in):

Operating:
Net income (loss) for the year $ 561 $ (884)
Add: Non-cash items:
Depletion, depreciation, and accretion 14,143 14,118
Actual abandonment costs - (104)
Stock-based compensation 931 1,188
Future income taxes (reduction) (446) (451)
----------------------------------------------------------------------------
15,189 13,867
Changes in non-cash working capital (1,035) 2,571
----------------------------------------------------------------------------
14,154 16,438

Financing:
Issuance of common shares 12,456 -
Bank debt 10,903 (12,011)
Repurchase of stock options (51) -
----------------------------------------------------------------------------
23,308 (12,011)

Investing:
Property, plant and equipment (25,575) (32,879)
Acquisition of property, plant and equipment (note 4) (12,644) -
Disposition of property, plant and equipment - 30,874
Changes in non-cash working capital 757 (2,567)
----------------------------------------------------------------------------
(37,462) (4,572)
----------------------------------------------------------------------------
Decrease in cash and cash equivalents - (145)
Cash and cash equivalents, beginning of year - 145
----------------------------------------------------------------------------
Cash and cash equivalents, end of year $ - $ -
----------------------------------------------------------------------------
Interest and taxes paid and received:
Interest paid $ 1,190 $ 960
Interest received 34 32
Taxes paid 142 25
----------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.


Notes to Consolidated Financial Statements

Years ended December 31, 2007 and 2006

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

(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. Accounting Policies Changes and Pending Changes

(A) FINANCIAL INSTRUMENTS

As of January 1, 2007 the Company adopted new policies to implement the pronouncements from the Canadian Institute of Chartered Accountants (CICA) in respect of financial instruments - presentation and disclosures, hedging and other comprehensive income. The application of these policies did not result in changes to amounts reported in the consolidated financial statements for the year ended December 31, 2007.

On initial recognition all financial instruments, including derivatives, are recorded at fair value and subsequent measurement is based on the financial instruments classification: held for trading, held to maturity, loans and receivables, available for sale and other liabilities.

The Company has designated its cash and cash equivalents as held for trading which are measured at fair value. Accounts receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities and bank debt are classified as other liabilities which are measured at amortized cost, using the effective interest method.

The Company is exposed to fluctuations in commodity prices, foreign exchange rates and interest rates. Derivative instruments may be used by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. If derivatives instruments were used they would be classified as held for trading and recorded on the balance sheet at fair value, with changes in the fair value recognized in income, unless specific hedge criteria were met. The fair values of derivative instruments would be based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity. Proceeds and costs realized from holding derivative instruments would be recognized in income at the time each transaction under a contract was settled.

The Company has elected to account for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-financial derivatives instruments.

The Company measures and recognizes embedded derivatives separately from the host contracts when the economic characteristics and risks of the embedded derivative are not closely related to those of the host contract, when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded derivatives are recorded at fair value.

The Company applies trade-date accounting for the recognition of a purchase or sale of cash equivalents and derivative instruments. The Company expenses all transaction costs incurred in relation to the acquisition of a financial asset or liability.

The CICA has issued two new financial instruments standards: Section 3862, Financial Instruments - Disclosures, and Section 3863, Financial Instruments - Presentation. The new disclosure standards effective January 1, 2008 may increase the Company's disclosures on risks related to financial instruments and how those risks are managed.

(B) COMPREHENSIVE INCOME

A new standard adopted requires statements of comprehensive income and accumulated other comprehensive income to temporarily provide for gains, losses and other amounts arising from changes in fair value until they are realized and recorded in income. The Company had no items that would affect comprehensive income or accumulated other comprehensive income for the year ended December 31, 2007.

(C) CAPITAL DISCLOSURES

As of January 1, 2008, the Company will be required to adopt Section 1535, Capital Disclosures, which require disclosure of the Company's objectives, policies and processes for managing capital.

(D) GOODWILL

As of January 1, 2009, the Company will be required to adopt Section 3064, Goodwill and Intangible Assets, which defines the criteria for the recognition of intangible assets.

(E) INTERNATIONAL REPORTING STANDARDS

The CICA has confirmed the effective date of January 1, 2001 for the convergence of Canadian GAAP to International Financial Reporting Standards. The Canadian Securities Administrators are currently examining changes to securities laws as a consequence of this initiative.

4. Acquisition of Greenbank Energy Ltd.

On July 31, 2007 the Company agreed to acquire a private company by way of a plan of arrangement for cash and shares of the Company. The transaction closed on September 28, 2007 and has been accounted for using the purchase method and the results of operations for the transaction are included in the financial statements beginning in the fourth quarter of 2007.



The purchase price equation is as follows:

($000)
----------------------------------------------------------------------------
Property, plant and equipment $ 28,127
Bank debt (5,537)
Working capital deficiency (330)
Asset retirement obligation (761)
Future income tax asset 2,963
----------------------------------------------------------------------------
$ 24,462
----------------------------------------------------------------------------
Consideration provided:
Cash from private placement $ 12,144
Common shares (3,143,167) 11,818
Transaction costs 500
----------------------------------------------------------------------------
$ 24,462
----------------------------------------------------------------------------


The preliminary purchase price allocations were based on certain estimates such as the fair values of the assets and liabilities as of the closing date. The items to be finalized in the purchase price allocation relate to working capital deficiency and transaction costs.



5. Property, Plant and Equipment

($000) December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 150,408 $ 96,887
Other assets 1,354 342
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151,762 97,229
Accumulated depletion and depreciation (36,871) (22,882)
----------------------------------------------------------------------------
$ 114,891 $ 74,347
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At December 31, 2007, the depletable base for the petroleum and natural gas properties included $14,404 (December 31, 2006 - $6,767) of future capital costs and excluded $13,380 (December 31, 2006 - $8,220) of unproved property costs.

During the year ended December 31, 2007, $2,004 (year ended December 31, 2006 - $1,627) of administrative costs relating to exploration and development activities were capitalized as part of property, plant and equipment.

At December 31, 2007, 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 Hardisty
WTI (Cushing, Edmonton AECE-C Spot (12 degrees Currency
Oklahoma) par (40 API) Price API) Exchange Rate
(US$/bbl) (CDN$/bbl) (CDN$/mmbtu) (CDN$/bbl) (US$/CDN$)
----------------------------------------------------------------------------
2008 92.00 91.10 6.75 54.02 1.00
2009 88.00 87.10 7.55 51.61 1.00
2010 84.00 83.10 7.60 49.19 1.00
2011 82.00 81.10 7.60 47.98 1.00
2012 82.00 81.10 7.60 47.98 1.00
2013 82.00 81.10 7.60 49.04 1.00
2014 82.00 81.10 7.80 50.09 1.00
2015 82.00 81.10 7.97 51.15 1.00
2016 82.02 81.12 8.14 52.21 1.00
2017 83.66 82.76 8.31 53.29 1.00
2018 85.33 84.42 8.48 54.36 1.00
Thereafter
(escalation) 2.0%/yr 2.0%/yr 2.0%/yr 2.0%/yr 1.00
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6. Bank Debt

At December 31, 2007 the Company had 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 limit under the facility at December 31, 2007 was $36 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, 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 next review is to be completed before April 30, 2008.

7. 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, 2007 was approximately $6,474 (December 31, 2006 - $3,666), which will be incurred between 2008 and 2020. 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.



December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of year $ 2,094 $ 2,115
Liabilities incurred/acquired during year 1,592 413
Dispositions - (459)
Accretion 154 129
Actual retirement costs - (104)
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Balance, end of year $ 3,840 $ 2,094
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8. 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, 2005 19,637,321 $ 57,369
Future tax effect of flow-through share
renouncements (i) (43)
----------------------------------------------------------------------------
Issued and outstanding as at December 31, 2006 19,637,321 $ 57,326
Issued for flow-through shares (ii) 10,007 42
Issued in private placement 2,998,623 12,144
Issued for property acquisitions 3,143,167 11,818
Issued for flow-through shares (iii) 88,524 270
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Issued and outstanding as at December 31, 2007 25,877,642 $ 81,600
----------------------------------------------------------------------------
(i) 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.
(ii) In accordance with the Company's stock option plan, some options were
exercised in exchange for flow-through shares of the Company.
(iii) The Company issued flow-through shares to employees.


(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 expires 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, 2007 and December 31, 2006 and changes during the year ended on those dates:



December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Options Exercise Options Exercise
Price ($) Price ($)
----------------------------------------------------------------------------
Outstanding, beginning
of year 1,767,277 $4.19 1,120,332 $ 4.51
Granted 1,258,366 $2.79 677,779 $ 3.66
Exercised (82,485) $3.49 - -
Forfeited (286,890) $4.23 - -
Expired (348,446) $4.36 (30,834) $ 3.87
----------------------------------------------------------------------------
Outstanding, end of year 2,307,822 $3.42 1,767,277 $ 4.19
----------------------------------------------------------------------------


Options outstanding and exercisable under the stock option plan are
summarized below as at December 31, 2007:

Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Number of Exercise Years to Number of Exercise
Options Price Expiry Options Price ($)
----------------------------------------------------------------------------
$2.43 - $3.41 1,634,870 $ 2.87 2.50 150,130 $ 3.25
$3.78 - $5.11 672,952 $ 4.76 1.10 347,955 $ 4.78
----------------------------------------------------------------------------
2,307,822 $ 3.42 2.09 498,085 $ 4.32
----------------------------------------------------------------------------


(D) PER SHARE AMOUNTS

The weighted average number of common shares outstanding during the year ended December 31, 2007 of 21,238,886 (year ended December 31, 2006 - 19,637,321) 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, 2007. As at December 31, 2007 no additional (December 31, 2006 - 17,660) common shares were used to calculate diluted earnings per share.

9. 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, 2007 was estimated to be $1,434 (year ended December 31, 2006 - $976) as at the grant date using the Black-Scholes option pricing model and the following assumptions:



Risk-free interest rate 4.00% - 6.25%
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, 2007 December 31, 2006
----------------------------------------------------------------------------
Balance, beginning of year $ 1,641 $ 453
Stock-based compensation expense 931 1,188
Net benefit on options exercised(1) (51) -
----------------------------------------------------------------------------
Balance, end of year $ 2,521 $ 1,641
----------------------------------------------------------------------------
(1) The benefit of options exercised is recorded as a reduction of
contributed surplus and an increase to share capital.


10. 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 32.40 percent (December 31, 2006 - 33.70 percent). The principal reasons for differences between such "expected" income tax expense and the amount actually recorded are as follows:



December 31, 2007 December 31, 2006
----------------------------------------------------------------------------
Net income before income taxes $ 191 $ (1,290)
Statutory income tax rate 32.4% 33.7%
----------------------------------------------------------------------------
Expected income taxes $ 62 $ (435)
Add (deduct):
Stock-based compensation 302 400
Non-deductible Crown charges - 330
Change in enacted rates (365) (311)
Other (375) 180
Resource allowance - (615)
Change in valuation allowance (70) -
----------------------------------------------------------------------------
Provision for income taxes $ (446) $ (451)
Capital tax 76 45
----------------------------------------------------------------------------
Provision for (recovery of) income taxes $ (370) $ (406)
----------------------------------------------------------------------------


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, 2007 December 31, 2006
----------------------------------------------------------------------------
Loss carry-forwards $ 4,587 $ 4,941
Property, plant and equipment (2,070) (6,218)
Non-coterminous year-ends (4,808) (3,859)
Share issuance costs 331 263
Asset retirement obligation 1,075 649
----------------------------------------------------------------------------
Calculated future income tax liability (885) (4,224)
Valuation allowance (648) (718)
----------------------------------------------------------------------------
Future income taxes (liability) $ (1,533) $ (4,942)
----------------------------------------------------------------------------


At December 31, 2007, Rock and its subsidiaries had tax pools totalling $122.9 million prior to the allocation of deferred partnership income and $106.1 million (December 31, 2006 - $55.2 million) after the allocation of deferred partnership income. The non-capital losses prior to the allocation of deferred partnership income expire as follows:



----------------------------------------------------------------------------
2014 $ 1,320
2015 1,031
2026 8,323
2027 3,830
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$ 14,504
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11. 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.



12. Commitments

Obligations with a fixed term are as follows:

2008 2009 2010 2011 2012
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Lease of office premises $ 895 $ 828 $ 828 $ 828 $ 552
Processing arrangements $ 450 $ 360 $ 288 $ 238 $ 159
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Advisory

Certain statements and information contained in this press release, including but not limited to management's assessment of Rock's future plans and operations, production, reserves, revenue, commodity prices, operating and administrative expenditures, 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, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, 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 that may cause actual results or events to differ materially from those anticipated in the 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 should not unduly be relied on. These statements speak only as of the date of this press release. 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.

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