Cordero Energy Inc.
TSX : COR

Cordero Energy Inc.

March 12, 2007 08:14 ET

Cordero Energy Reports Year End 2006 Reserves, Financial Results and Provides Update

CALGARY, ALBERTA--(CCNMatthews - March 12, 2007) - Cordero Energy Inc. (TSX:COR) is pleased to announce fourth quarter and year end 2006 results, independently evaluated reserve information and an operations update.

2006 Reserve and Production Highlights

- Production for 2006 averaged 3,103 boe/d, representing a 97% increase over 2005.

- Proved and probable reserves grew 38% to 13.3 million boe from 9.6 million boe at December 31, 2005.

- On a proved plus probable basis, finding, development and acquisition (FD&A) costs for 2006 were $17.80/boe and including a provision for the change in future capital, were $19.33/boe. FD&A costs since inception for proved plus probable reserves were $13.61/boe and including a provision for the change in future capital, were $15.96/boe.

- The Company replaced 2006 production by 4.2 times based on proved plus probable reserves.

- Cordero's reserve life index is 11.6 years for proved plus probable reserves and 7.8 years for proved reserves using annualized 2006 fourth quarter production of 3,150 boe/d.

- Diluted net asset value (NAV) per share at December 31, 2006 was $6.79/share based on proved plus probable reserves discounted at 10% before tax using Sproule prices at December 31, 2006, an assumed value of $150/acre for undeveloped land and net debt of $31.7 million.

Fourth Quarter 2006 Highlights

- Production for the quarter averaged 3,150 boe/d, representing a 55% increase over the same period last year. On a per share basis, production for the fourth quarter increased 46% to 95 boe/d per million shares, up from 65 boe/d per million shares during the fourth quarter of 2005.

- Funds flow(1) in the fourth quarter increased 12% to $7.8 million ($0.22/share diluted) compared to $7.0 million ($0.20/share) for the previous quarter.

- Operating expenses for the quarter averaged $3.78/boe versus $5.27/boe for the fourth quarter of 2005, representing a 28% year over year decrease.

- Royalties for the fourth quarter were 14%, down from 21% in the fourth quarter of 2005.

- Cordero closed a $10.6 million flow-through financing on November 9, 2006.

Operations Update

- During the fourth quarter, Cordero drilled 10 net natural gas wells, nine of which were commercially successful.

- The Company successfully doubled its undeveloped land position during the year from 61,600 net acres to 122,870 net acres.

- The Company significantly expanded its land holdings in the Malmo area, acquiring 19,700 acres and increasing its drilling inventory to over 130 locations.

- Cordero's stabilized behind pipe production is estimated at 850 boe/d, of which 450 boe/d is expected to be tied-in by the end of April 2007.

- Cordero drilled four wells (4.0 net) within its northern Alberta exploration region in the 2006/07 winter program. Three wells were dry and abandoned and the other was completed with tested gas from two zones.

- At this time one drilling rig is active in the Malmo area and is currently drilling the second of a 10-well development program.

- The Company entered into several derivative financial instrument contracts in February 2007 for the purpose of managing its exposure to fluctuations in natural gas prices. The details of these contracts are provided in note 12 of the Notes to Consolidated Financial Statements.

(1) See Management's Discussion and Analysis for calculation and further information on this measure.



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Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005(1)
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FINANCIAL
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Gross oil and natural gas revenue
($000s) 11,693 12,637 44,900 22,431

Funds flow from operations(2) ($000s) 7,776 8,175 29,418 13,884
Per share basic ($) 0.23 0.29 0.93 0.52
Per share diluted ($) 0.22 0.27 0.87 0.48

Net earnings ($000s) 1,884 3,453 4,675 4,526
Per share basic ($) 0.06 0.12 0.15 0.17
Per share diluted ($) 0.05 0.11 0.14 0.16

Net capital expenditures ($000s) 24,323 24,788 85,538 41,617
Net debt and working capital(3)
deficiency ($000s) 31,684 4,068 31,684 4,068

Shares outstanding (000s)
At period end 33,823 29,725 33,823 29,725
Weighted average during period, basic 33,314 28,057 31,603 26,795
Weighted average during period, diluted 35,498 30,435 33,767 28,979

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OPERATING
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Production
Natural gas (MMcf/d) 18.2 12.1 17.8 9.4
Oil and natural gas liquids (bbls/d) 119 21 139 8
Oil equivalent (boe/d) (6:1) 3,150 2,039 3,103 1,574

Average wellhead prices
Natural gas ($/Mcf) 6.58 11.22 6.36 9.69
Oil and natural gas liquids ($/bbl) 62.76 70.12 71.02 69.11
Oil equivalent ($/boe) (6:1) 40.34 67.38 39.65 58.18

Operating expenses ($/boe) (6:1) 3.78 5.27 3.55 5.67

Wells drilled (gross/net)
Natural gas 9/9.0 43/36.6 58/51.5 51/44.0
Oil - 1/1.0 2/2.0 1/1.0
Dry 1/1.0 1/1.0 5/5.0 1/1.0
Total 10/10.0 45/38.6 65/58.5 53/46.0

Net success rate (%) 90 97 91 98

Undeveloped land holdings (000s)
Gross acres 131 131 74
Net acres 123 123 62
Average working interest (%) 94 94 84
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(1) Represents the 246 day period from commencement of operations
April 30, 2005 to December 31, 2005.

(2) Funds flow from operations represents earnings before depletion,
depreciation, accretion, stock-based compensation and future income
taxes and does not have a standardized meaning prescribed by Canadian
GAAP and therefore is unlikely to be comparable to similar measures
presented by other companies.

(3) Net debt and working capital represents current assets less current
liabilities, debt and capital lease obligations. It does not have a
standardized meaning prescribed by Canadian GAAP and therefore is
unlikely to be comparable to similar measures presented by other
companies.


President's Message

Natural gas prices have improved and are showing signs of strengthening following a period of weakness through September and October 2006. This trend has been driven primarily by colder temperatures in the central and eastern United States resulting in higher draws from natural gas storage facilities.

The trend of significant cost inflation for oilfield services continued throughout 2006. Unprecedented activity levels strained an already tight labor force, particularly with the competition of the oil sands sector. The significant cost escalation combined with lower natural gas prices, has resulted in a recent slowing of natural gas exploration and development activity in western Canada. We expect natural gas prices to rise in the medium to long-term as the North American supply/demand situation re-balances.

Reserves Summary

Sproule Associates Limited (Sproule) completed their independent reserve evaluation as at December 31, 2006 pursuant to National Instrument 51-101 (NI 51-101). Year over year Company interest (including royalty interest) proved and probable (2P) reserves grew 38% to 13.3 million boe compared to 9.6 million boe in 2005. Proved (1P) reserves grew 24% to 9.0 million boe from 7.3 boe. The Company replaced its 2006 production by 4.2 times based on 2P reserve additions.

On a proved plus probable basis, finding, development and acquisition (FD&A) costs for 2006 were $17.80/boe and including a provision for the change in future capital, were $19.33/boe. FD&A costs since inception for proved plus probable reserves were $13.61/boe and including a provision for the change in future capital, were $15.96/boe.

Financial and Operating Results

Production for the fourth quarter averaged 3,150 boe/d, representing a 54% increase over the same period last year. On a per share basis, production for the fourth quarter increased 46% to 95 boe/d per million shares, up from 65 boe/d per million shares during the fourth quarter of 2005.

Funds flow from operations(1) (funds flow) for 2006 was $29.4 million ($0.87/share diluted). The realized average natural gas price for the fourth quarter of 2006 fell 41% to $6.58/Mcf compared to $11.22/Mcf for the same quarter in 2005. As a result, despite significantly higher production volumes, fourth quarter funds flow was $7.8 million ($0.22/share diluted), down 5% from $8.2 million ($0.27/diluted share) reported for the same quarter in 2005. The lower prices also contributed to reduced earnings of $1.9 million ($0.05/share diluted) for the quarter compared to $3.5 million ($0.11/share diluted) for the same period in 2005. Earnings for the full year 2006 were $4.7 million ($0.14/share diluted).

Cordero has continued to maintain one of the lowest cost profiles in the Western Canadian Basin. Its low operating, royalty, transportation and overhead cost structure, when combined, result in average total cash costs of $12.98/boe in 2006. In comparison, unit operating costs were $3.55/boe in 2006 versus $5.67/boe in 2005, a 37% reduction. Royalty rates averaged 16% in 2006 versus 19% in 2005. Transportation expenses decreased by 18% for the three months ($1.14/boe) and 14% for the period ended December 31, 2006 ($1.14/boe) when compared to the same period in 2005. General and administrative expenses were $2.08/boe in 2006 versus $3.52/boe in 2005, a 41% improvement.

Net capital expenditures for the fourth quarter totaled $24.3 million and $85.5 million for the year.

Malmo, Alberta

Malmo remained a key focus area for Cordero during 2006. The Company has significantly expanded its land holdings in the area, acquiring an additional 19,700 acres (30.8 net sections) during the year, primarily at Buffalo Lake (south Malmo). The Company continues to acquire prospective lands in the area to build its drilling inventory which currently stands at over 130 locations.

In conjunction with an active drilling program in the Malmo and Buffalo Lake area, a significant pipeline and compression facilities project has been initiated. When completed, Cordero will add approximately 450 boe/d of stabilized production and have solidified its position as a dominant shallow gas producer in this area.

During the fourth quarter, the Company drilled eight net natural gas wells in the Malmo / Buffalo Lake area. Two of the wells were vertical, two were conventional slant wells and four were a continuation of what Cordero has defined as its extended reach drilling program.

The extended reach drilling program has been a significant milestone for the Company as it has allowed development of several areas where surface access is not only difficult, but also too far away to be accessed with conventional slant-hole technology. The drilling experience has also allowed Cordero to develop in-house expertise. During earlier attempts at extended reach drilling by the Company, drilling costs were in the range of $600,000 to $700,000 per well. The results of this recent program have shown that the Company is capable of drilling these types of wells at lower costs ranging between $225,000 and $500,000 depending on the length of reach. The success of this program has significantly expanded the Company's drilling inventory.

Two vertical wells were drilled using an open-hole concept at north Malmo where in-situ water is a concern in the upper Horseshoe Canyon intervals. In these wells, surface casing was run down through the upper Horseshoe Canyon interval and the dryer lower Horseshoe Canyon section was contacted by air drilling. The production results were encouraging. The air drilling saves approximately $130,000 in completion costs while only adding $30,000 to the drilling cost. The Company remains convinced that, although the upper Horseshoe Canyon section in north Malmo is wet, it is gas charged in the more traditional style of coalbed methane production and therefore remains a future resource for Cordero.

The Company has also undertaken to complete higher density, lower porosity, thick carbonaceous shale intervals between the more productive Horseshoe Canyon coal intervals. This was attempted in two wells as a means of proving up the viability of this resource. The results were encouraging. Flow rates were 30 Mcf/d and 50 Mcf/d, indicating that these carbonaceous shale sections are productive. The potential of these shales may be significant as they should add to the long-term resource potential in the area. Through laboratory testing the Company has determined that these carbonaceous shales are gas charged, although with much lower porosity and permeability.

Conventional Exploration and Drilling Program

The Company's first well in the 2006/2007 winter program was drilled and cased at Colorado, located in northern Alberta. The well was subsequently completed and flow tested. Although further work is required, encouraging test rates totaling 330 boe/d were obtained from two intervals. Three exploration wells, drilled to the west of Colorado in the Clear and Rambling areas, were dry and abandoned. An exploration well was cased in Bigoray for the Nordegg interval. The interval was encountered, but deemed non-commercial upon completion. At Bonanza, a completion in the Taylor Flat interval was undertaken. Testing and reservoir evaluation is ongoing.

The highlight of the fourth quarter was the commencement of production in December 2006 from a well at Karr, Alberta (Cordero 49% net). The well is currently producing 190 net boe/d and work is underway to review options for a follow-up well.

Cordero remains focused on expanding its opportunity base for the future. The Company has several significant exploratory opportunities in its inventory at Goose River, Knopcik, Bigoray, Trutch and Tupper.

The Company has four sections of land on trend with the tight gas Montney exploration and development work that is on-going at Tupper in British Columbia. Cordero will assess development strategies for this land pending further results of ongoing industry activity.

Outlook

On February 15, 2007, the Company issued an operational update and a revision to its 2007 guidance. The Company is guiding to an average production range of 3,800-4,200 boe/d and a capital budget between $50 million and $55 million. Cordero remains focused on expanding its development potential and production base in the Malmo area and combined with its exploratory opportunities, the Company is well positioned for growth in 2007.

Thank you for your continued interest and support of Cordero.

On behalf of our dedicated staff and the Board of Directors,

David V. Elgie, President and CEO, March 9, 2007

(1) See Management's Discussion and Analysis for calculation and further information on this measure.

ADVISORY - In the interest of providing Cordero shareholders and potential investors with information regarding Cordero, including management's assessment of Cordero's future plans and operations, certain disclosures contained in this document are forward-looking. Forward-looking statements include, but are not limited to, Cordero's internal projections, expectations or beliefs concerning future operating results and various components thereof; the production and growth potential of its various assets, estimated total production and production growth for 2007 and beyond; the sources, deployment and allocation of expected capital in 2007 and beyond; and the success of future development drilling prospects. Readers are cautioned not to place undue reliance on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur which may cause Cordero's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. As a result, the actual oil and natural gas reserves and future production may be greater or less than the estimates provided in this document. In regards to finding, development and acquisition (FD&A) costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in the estimated future development costs generally will not reflect FD&A costs related to reserve additions for that year.

Reserves

Cordero's reserves were independently evaluated by Sproule Associates Limited (Sproule) as at December 31, 2006. Reserves included herein are stated on a company gross basis (before royalty burdens) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument 51-101 (NI 51-101). In addition to the information disclosed in this press release, more detailed reserve information will be included in Cordero's 2006 Renewal Annual Information Form which will be posted at www.sedar.com and www.corderoenergy.com prior to March 31, 2007.



Summary of Oil and Gas Reserves as of December 31, 2006
Forecast Prices and Costs
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Conventional Light and
Natural Gas Unconventional Medium Oil & Total
(associated & Natural Gas Natural Gas Barrels of
non-associated) (CBM) Liquids Oil Equivalent
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Gross Net Gross Net Gross Net Gross Net
Reserve Category (MMcf) (MMcf) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
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Proved
Developed
Producing 7,349 6,041 20,306 17,310 156 134 4,765 4,025
Developed
Non-Producing 5,105 4,212 2,970 2,482 25 19 1,371 1,135
Undeveloped 813 742 16,312 14,083 - - 2,854 2,471
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Total Proved 13,267 10,994 39,588 33,875 181 153 8,991 7,631
Probable 3,657 3,026 21,599 18,620 88 75 4,298 3,683
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Total Proved Plus
Probable 16,924 14,020 61,187 52,494 270 227 13,288 11,313
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Notes
- "Gross" represents company interest before royalties.
- "Net" represents company interest after royalties.
- Table may not add due to rounding.
- CBM is included in "Natural Gas (non-associated & associated)".

Reserve Life Index (RLI)

Cordero's RLI is calculated based on annualized fourth quarter 2006
production of 3,150 boe/d.

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Proved Plus
Proved Probable
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Reserves - Mboe 8,991 13,288
2006 fourth quarter annualized production - boe/d 3,150 3,150
RLI - years 7.8 11.6
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Net Present Value (NPV) Summary

Cordero's crude oil, natural gas and natural gas liquids reserves were evaluated using Sproule's product price forecasts effective December 31, 2006 prior to the provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the discounted future net production revenues estimated by Sproule represent the fair market value of the reserves.



Summary of Net Present Values of Future Net Revenue as of December 31, 2006
Forecast Prices and Cost

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Before Income Taxes
($000s) Discounted at (%/Year)
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Reserves Category 0 5 10 15 20
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Proved
Developed
Producing 160,009 140,079 124,808 112,782 103,095
Developed
Non-Producing 37,669 32,329 28,182 24,886 22,215
Undeveloped 61,403 45,742 34,563 26,347 20,155
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Total Proved 259,081 218,150 187,553 164,015 145,465
Probable 132,150 92,252 67,376 51,032 39,815
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Total Proved Plus
Probable 391,230 310,402 254,929 215,047 185,280
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After Income Taxes
Discounted at (%/Year)
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Reserves Category 0 5 10 15 20
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Proved
Developed
Producing 150,596 131,807 117,468 106,215 97,176
Developed
Non-Producing 26,721 22,635 19,501 17,038 15,061
Undeveloped 45,384 32,704 23,744 17,220 12,347
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Total Proved 222,700 187,145 160,713 140,473 124,584
Probable 97,130 66,790 48,103 35,939 27,652
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Total Proved Plus
Probable 319,830 253,935 208,815 176,411 152,236
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Notes:

- NPV of Future Net Revenue (FNR) include all resource income:
-- Sale of oil, gas, by-product reserves
-- Processing third party reserves
-- Other income

- Income Taxes
-- Includes all resource income
-- Applies appropriate income tax calculations
-- Includes prior tax pools

- Table may not add due to rounding


Summary of Pricing and Inflation rate Assumptions as of December 31, 2006
Forecast Prices and Costs

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Edmonton
Par Cromer Natural Pentanes
Price Medium Gas(1) Plus Butanes
WTI 40 29.3 AECO FOB F.O.B
Cushing degrees degrees Gas Field Field Inflation Exchange
Oklahoma API API Prices Gate Gate Rate(2) Rate(3)
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($Cdn/ ( $Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ ($US/
Year ($US/bbl) bbl) bbl) MMbtu) bbl) Bbl) (%/Yr) $Cdn)
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Historical
2002 26.09 40.12 35.46 4.04 40.80 25.39 2.7 0.637
2003 31.14 43.23 37.53 6.66 44.16 34.55 2.5 0.716
2004 41.42 52.91 45.72 6.87 53.91 41.37 1.3 0.770
2005 56.46 69.29 57.36 8.58 69.13 45.20 1.6 0.826
2006 66.09 73.31 62.35 7.16 75.03 59.32 2.0 0.882
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Forecast
2007 65.73 74.10 63.72 7.72 75.88 55.23 5.0 0.870
2008 68.82 77.62 66.75 8.59 79.49 57.85 4.0 0.870
2009 62.42 70.25 60.41 7.74 71.94 52.36 3.0 0.870
2010 58.37 65.56 56.38 7.55 67.14 48.87 2.0 0.870
2011 55.20 61.90 53.24 7.72 63.40 46.14 2.0 0.870
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Thereafter Various Escalation Rates
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(1) This summary table identifies benchmark reference pricing schedules
that might apply to a reporting issuer.
(2) Inflation rates for forecasting prices and costs.
(3) Exchange rates used to generate the benchmark reference prices in this
table.

Notes:
- Product sale prices will reflect these reference prices with further
adjustments for quality and transportation to point of sale.


NPV - Constant Pricing

The company interest reserves have also been evaluated using constant prices and costs effective December 31, 2006. Following are values determined using this constant price analysis.

Summary of Net Present Values of Future Net Revenue as of December 31, 2006 Constant Prices and Costs



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Before Income Taxes
($000s) Discounted at (%/Year)
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Reserves Category 0 5 10 15 20
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Proved
Developed
Producing 122,918 107,579 95,797 86,509 79,025
Developed
Non-Producing 27,212 23,221 20,121 17,658 15,664
Undeveloped 38,278 26,887 18,768 12,824 8,370
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Total Proved 188,408 157,687 134,686 116,991 103,059
Probable 95,560 66,839 48,700 36,671 28,357
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Total Proved Plus
Probable 283,968 224,526 183,386 153,661 131,416
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After Income Taxes
Discounted at (%/Year)
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Reserves Category 0 5 10 15 20
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Proved
Developed
Producing 122,918 107,579 95,797 86,509 79,025
Developed
Non-Producing 19,441 16,487 14,228 12,457 11,038
Undeveloped 28,447 18,869 12,120 7,230 3,603
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Total Proved 170,806 142,935 122,145 106,195 93,666
Probable 68,602 46,990 33,563 24,777 18,772
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Total Proved Plus
Probable 239,407 189,925 155,708 130,972 112,437
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Notes:
- NPV of Future Net Revenue (FNR) include all resource income:
-- Sale of oil, gas, by-product reserves
-- Processing third party reserves
-- Other income

- Income Taxes
-- Includes all resource income
-- Applies appropriate income tax calculations
-- Includes prior tax pools

- Table may not add due to rounding


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Constant Prices at December 31, 2006
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Cromer
Medium
Edmonton 29.3 Natural Pentanes Butanes
WTI Cushing Par degrees Gas at Plus at at Exchange
Oklahoma Price API AECO Edmonton Edmonton Rate
($US/bbl) ($Cdn/bbl)($Cdn/bbl)($Cdn/MMbtu)($Cdn/bbl)($Cdn/Bbl)($US/$Cdn)
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61.05 67.59 62.45 6.13 71.75 54.00 0.858
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Finding, Development and Acquisition (FD&A) Costs

FD&A Costs for the Year Ended December 31, 2006

The FD&A calculation below is based on capital spent in 2006, changes to future capital and reserve additions for the calendar year 2006.



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Proved Plus
Proved Probable
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Change in future capital - $000
December 31, 2006 36,366 47,111
December 31, 2005 (38,686) (39,736)
2006 Capital - $000 85,538 85,538
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83,218 92,913
Net reserve additions - Mboe 2,872 4,806

FD&A per boe - $/boe 28.98 19.33
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Prior to the introduction of NI 51-101, FD&A costs were calculated without provision for the change in future capital. FD&A costs, based on this historical method, are presented below for comparative purposes only.



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Proved Plus
Proved Probable
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FD&A, excluding provision for change in future capital
- $/boe 29.78 17.80
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FD&A Costs Inception-to-Date

The FD&A calculation below is based on capital spent from commencement of operations on April 30, 2005 to December 31, 2006. Pursuant to the plan of arrangement under which petroleum and natural gas interests were transferred to Cordero on April 29, 2005, Cordero was responsible for all costs net of revenues ("purchase adjustment") incurred on Cordero lands from January 1, 2005 to April 29, 2005. The purchase adjustment amounted to $14.5 million and is included in the calculation below, along with capital expenditures, changes to future capital and reserve additions since inception.



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Proved Plus
Proved Probable
----------------------------------------------------------------------------
Change in future capital - $000
December 31, 2006 36,366 47,111
December 31, 2004 (13,229) (22,664)
Inception-to-date capital - $000 141,700 141,700
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164,837 166,147
Net reserve additions - Mboe 8,728 10,410

FD&A per boe - $/boe 18.89 15.96
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FD&A costs, without provision for the change in future capital, for
comparative purposes only, are as follows:

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Proved Plus
Proved Probable
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FD&A, excluding provision for change in future
capital - $/boe 16.24 13.61
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Net Asset Value

The following net asset value (NAV) table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Company's reserves would be produced at forecast future prices and costs. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. The net asset value was $6.97/share using future prices at March 7, 2007 and assumptions as outlined in the table below. It should not be assumed that this NAV calculation represents the fair market value of the Company.



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Sproule
$millions, unless otherwise stated Forecast Price
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Net present value of pre-tax proved plus probable reserves
discounted at 10% 254.9
Undeveloped land (1) 18.4
Net debt (2) (31.7)
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Net asset value 241.6
Option and warrant conversion proceeds (3) 13.9
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255.5
Diluted shares - million (3) 37.6

Diluted NAV - $ / share 6.79
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(1) Management assumed a value of $150/acre.
(2) Includes working capital deficiency and long-term capital lease.
(3) Assumes conversion of all in-the-money options, warrants and performance
shares.

Reserve Replacement Ratio

The reserve replacement ratio measures the Company's ability to replace its
production based on proved and proved plus probable additions.

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Replacement
Mboe Ratio
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Production 1,133
Net reserve additions
1P 2,872 2.5
2P 4,806 4.2
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Recycle Ratio

The recycle ratio measures the Company's ability to reinvest the net cash
generated from the production of each barrel of oil equivalent to add
incremental reserves.

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Proved Plus Probable
Year-to-Date(1) Inception-to-Date(2)
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Operating netback(3) - $/boe 28.75 31.60
Corporate netback(3) - $/boe 25.97 28.52

FD&A - $/boe 19.33 15.96

Operating recycle ratio 1.5 2.0
Corporate recycle ratio 1.3 1.8
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(1) January 1, 2006 to December 31, 2006.
(2) April 30, 2005 to December 31, 2006.
(3) Operating netback is calculated as average unit sale price less
royalties, transportation costs and operating expenses and corporate
netback further deducts administrative and interest expense and current
income tax. Neither measure have a standardized meaning prescribed by
Canadian GAAP and therefore are unlikely to be comparable to similar
measures presented by other companies. See the Management's Discussion
and Analysis for further information regarding netbacks.


MANAGEMENT'S DISCUSSION AND ANALYSIS

March 9, 2007

Description of Business

Cordero Energy Inc. ("Cordero" or "the Company") is a junior oil and gas company pursuing oil and natural gas production and reserve growth through the development of its coalbed methane (CBM) and Belly River lands in central Alberta as well as conventional exploration in Alberta and British Columbia.

Cordero is based in Calgary, Alberta and was incorporated on March 30, 2005 under the Business Corporations Act (Alberta). The Company commenced operations on April 30, 2005 when certain oil and gas properties were transferred to Cordero in exchange for common shares of the Company under a plan of arrangement involving Resolute Energy Inc. (Resolute), Esprit Energy Trust, Esprit Exploration Ltd., Cordero and Cordero Finance Corp. Cordero commenced trading on the Toronto Stock Exchange on May 3, 2005 under the symbol "COR".

Reader Guidance

This Management's Discussion and Analysis (MD&A) of the financial condition and the results of operations should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2006 together with the related notes. Readers should be aware that historical results are not necessarily indicative of future performance. Additional information relating to the Company can be viewed or downloaded at www.corderoenergy.com or www.sedar.com.

Unless otherwise indicated, the discussion in this MD&A with respect to results for the year ended December 31, 2006 are compared with results for the 246-day period from commencement of operations on April 30, 2005 to December 31, 2005. As a result, daily or per unit amounts may provide more meaningful comparison than totals for the periods.

Production information is commonly reported in units of barrel of oil equivalent (boe) which may be misleading, particularly if used in isolation. For purposes of computing such units, barrel of oil equivalent amounts have been calculated using an energy equivalence conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1). The conversion ratio of 6:1 is based on an energy equivalency conversion method, which is primarily applicable at the burner tip. It does not represent equivalent wellhead value for the individual products.

The financial information presented has been prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The reporting and measurement currency is the Canadian dollar.

Forward-Looking Statements

The information herein contains forward-looking statements and assumptions, such as those relating to guidance, results of operations and financial condition, capital spending, financing sources, commodity prices, costs of production and the magnitude of oil and gas reserves. By their nature, forward-looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly, actual results may differ materially from those predicted. Cordero is exposed to numerous operational, technical, financial and regulatory risks and uncertainties, many of which are beyond its control and may significantly affect anticipated future results.

Operations may be unsuccessful or delayed as a result of competition for services, supplies and equipment, mechanical and technical difficulties, ability to attract and retain employees on a cost-effective basis, commodity and marketing risk and seasonality. The Company is subject to significant drilling risks and uncertainties including the ability to find oil and natural gas reserves on an economic basis and the potential for technical problems that could lead to well blowouts and environmental damage. The Company is also exposed to risks relating to the inability to obtain timely regulatory approvals, surface access, access to third party gathering and processing facilities, transportation and other third party related operational risks. Furthermore, there are numerous uncertainties in estimating the Company's reserve base due to the complexities in estimating future production, costs and timing of expenses and future capital. Financial risks Cordero is exposed to include, but are not limited to, access to debt or equity markets and fluctuations in commodity prices, interest rates and the Canadian/US dollar exchange rate. The Company is subject to regulatory legislation, the compliance with which may require significant expenditures and non-compliance with which may result in fines, penalties or production restrictions. For additional information on risk factors, refer to Cordero's 2006 Renewal Annual Information Form at www.sedar.com or www.corderoenergy.com.

The forward-looking statements contained herein are as of March 9, 2007 and are subject to change after this date. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Except as required by applicable securities laws, Cordero disclaims any intention or obligation to update or revise these forward-looking statements, whether as a result of new information, future events or otherwise.

Non-GAAP Measures

Cordero management uses and reports certain non-GAAP measures in the evaluation of operating and financial performance.

Funds flow from operations (funds flow), which represents earnings before depletion, depreciation, accretion, stock-based compensation and future income taxes is used by the Company to evaluate operating performance, leverage and liquidity. The following table reconciles funds flow from operations to cash flow from operating activities which is the most directly comparable measure calculated in accordance with GAAP:



----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
($000s) 2006 2005 2006 2005
----------------------------------------------------------------------------

Cash flow from operating activities 6,901 6,898 29,030 13,020
Changes in non-cash working capital 854 1,277 206 859
Asset retirement obligation expenditures 21 - 182 5
----------------------------------------------------------------------------
Funds flow from operations 7,776 8,175 29,418 13,884
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Operating netback is calculated as average unit sales price less royalties, transportation costs and operating expenses. Corporate netback further deducts administrative and interest expense and current income tax. These measures represent the cash margin for every barrel of oil equivalent sold and are a common benchmark used in the oil and gas industry. There is no GAAP measure that is reasonably comparable to netbacks. See "Operating Netbacks by Product" for calculations of operating netbacks for each commodity.

Net debt and working capital, which is current assets less debt, capital lease obligations and current liabilities, is used to assess efficiency and financial strength. There is no GAAP measure that is reasonably comparable to net debt and working capital.

The above measures do not have standardized meanings prescribed by Canadian GAAP and therefore are unlikely to be comparable to similar measures presented by other issuers.



2007 Guidance
----------------------------------------------------------------------------
Revised Initial
February, 2007 November, 2006
Low High Low High
----------------------------------------------------------------------------
Average production (boe/d) 3,800 4,200 4,200 4,600

Royalties (% of revenue) 17.5 19.5 17.5 19.5
Transportation ($/boe) 1.10 1.30 1.10 1.30
Operating ($/boe) 3.80 4.20 3.80 4.20
General and administrative ($/boe) 1.90 2.20 1.90 2.20
Capital expenditures ($ million) 50.0 55.0 50.0 55.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cordero recently adjusted its production guidance for 2007 to 3,800 - 4,200 boe/d. The decrease to the production guidance is the result of several factors: several Belly River wells declined faster than anticipated; initial rates for infill locations in the northern Malmo land block were lower than expected but the rates are not expected to affect reserves; exploration results were below expectations; and the timing of projects from drilling to tie-ins has been delayed to enable the Company to source the best services at competitive prices. All other parameters remain unchanged from original guidance.

Sensitivities

Based on the above assumptions, the following sensitivities are provided to demonstrate the impact of changes in commodity prices and the Canadian currency on funds flow from operations and net earnings:



----------------------------------------------------------------------------
Funds Flow From
($000s) Operations Net Earnings
----------------------------------------------------------------------------
Impact on the year ended December 31, 2007
Change in West Texas Intermediate oil price
by US $1.00/bbl 31 21
Change in average field price of natural gas
by Cdn$1.00/Mcf 7,141 4,784
Change in value of Cdn dollar compared to US
dollar by Cdn$0.01 429 287
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2006 Performance Compared to Guidance

The following table compares the Company's performance for the period ended
December 31, 2006 to the initial guidance provided in November 2005 and the
revised guidance in May and August 2006:

----------------------------------------------------------------------------
Revised Initial
2006 November 2006 November 2005
Actual Low High Low High
----------------------------------------------------------------------------
Average production (boe/d) 3,103 3,100 3,200 3,100 3,400

Royalties (% of revenue) 15.7 16.0 17.0 17.5 19.0
Transportation ($/boe) 1.14 1.10 1.20 1.40 1.50
Operating ($/boe) 3.55 3.40 3.60 5.80 6.30
General and administrative ($/boe) 2.08 2.10 2.40 2.10 2.40
Capital expenditures, net ($ million) 85.5 77.0 85.0 50.0 55.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cordero met its annual production guidance with average production of 3,103 boe/d. Approximately 850 boe/d of tested stabilized production from wells drilled during 2006 awaits tie-in and will help the Company to achieve its 2007 targets. All of the cost parameters compared to original guidance were significantly improved including transportation, royalties, operating, as well as general and administrative expenses (refer to Management's Discussion and Analysis for further details).

Capital Expenditures were $85.5 million for the year, representing approximately $30.0 million over initial guidance. Cordero, like the rest of the industry in western Canada experienced significantly higher prices for supplies and services during 2006 due to record activity levels. Furthermore, the Company expanded its land budget to take advantage of new opportunities as natural gas prices softened during the second half of 2006. Drilling activities were expanded and a significant investment was made in pipeline and facility expansion at Buffalo Lake to accommodate existing and future growth.

Overall Performance and Comparison of Selected Annual Information

The current year was the first full year of operations for Cordero as it commenced operations on April 30, 2005. The Company drilled 65 (58.5 net) wells during 2006 and increased annual average production per day by 97% compared to the period ended December 31, 2005. Natural gas prices had a significant effect on the Company's financial results as the commodity represented approximately 96% of total production for the current year. The realized price per Mcf for the Company's gas production was 34% lower in 2006 than in 2005. Throughout 2006 Cordero improved its unit cash costs, resulting in declines from 2005 in annual operating and administrative expenses of 37% and 41%, respectively. DD&A expense had a significant impact on 2006 net earnings which, on a boe basis, was 20% higher compared to 2005.



----------------------------------------------------------------------------
Period Ended
December 31 Percent
$000s except where otherwise indicated 2006 2005(1) Change
----------------------------------------------------------------------------
Gross oil and natural gas revenue 44,900 22,431 100

Funds flow from operations 29,418 13,884 112
Per share basic ($) 0.93 0.52 79
Per share diluted ($) 0.87 0.48 81

Net earnings 4,675 4,526 3
Per share basic ($) 0.15 0.17 (1)
Per share diluted ($) 0.14 0.16 (1)

Total assets 158,012 104,923 51
Total long-term liabilities 28,937 7,318 295
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Represents the 246 day period from commencement of operations April 30,
2005 to December 31, 2005.


Selected Quarterly Information

----------------------------------------------------------------------------
2006 2005
Q4 Q3 Q2 Q1 Q4 Q3 Q2(1)
----------------------------------------------------------------------------
Production
Natural gas
(MMcf/d) 18.2 18.7 17.5 16.8 12.1 8.5 6.6
Oil and natural
gas liquids
(bbls/d) 119 145 161 130 21 1 1
Barrels of oil
equivalent
(boe/d) 3,150 3,261 3,072 2,923 2,039 1,421 1,103

Financial ($000s
except as
indicated)
Petroleum and
natural gas
revenue 11,693 10,811 10,521 11,874 12,637 6,919 2,875
Revenue net of
royalties 9,999 9,117 9,150 9,600 10,029 5,710 2,359

Funds flow from
operations 7,776 6,967 7,178 7,498 8,175 4,268 1,440
Per share
basic ($) 0.23 0.21 0.24 0.25 0.29 0.16 0.06
Per share
diluted ($) 0.22 0.20 0.22 0.23 0.27 0.15 0.06

Net earnings 1,884 762 105 1,924 3,453 1,057 16
Per share
basic ($) 0.06 0.02 - 0.06 0.12 0.04 -
Per share
diluted ($) 0.05 0.02 - 0.06 0.11 0.04 -

Total assets 158,012 135,797 128,962 120,045 104,923 67,316 65,656
Net capital
expenditures 24,323 14,348 14,207 32,659 24,788 11,610 5,219
Net debt and
working capital
(deficiency) (31,684)(25,074) (17,536) (29,296) (4,068) (121) 7,176

Shares outstanding
(000s) 33,823 32,623 32,623 29,725 29,725 27,125 27,125

Per unit
information
Natural gas
($/Mcf) 6.58 5.68 5.92 7.37 11.22 8.82 7.12
Oil and natural
gas liquids
($/bbl) 62.76 77.33 75.99 65.30 70.12 51.13 41.40
Oil equivalent
($/boe) 40.34 36.03 37.63 45.14 67.38 52.93 42.73

Operating expenses
($/boe) 3.78 3.36 3.27 3.80 5.27 5.80 6.53

Operating netback
($/boe) 29.58 25.94 28.31 31.51 46.82 36.57 27.40

Net wells drilled
Natural gas 9.0 12.8 8.5 21.2 36.6 - 7.4
Oil - - - 2.0 1.0 - -
Dry 1.0 1.0 - 3.0 1.0 - -
Total 10.0 13.8 8.5 26.2 38.6 - 7.4

Net success
rate (%) 90 93 100 89 97 - 100

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

(1) Represents the 62-day period from commencement of operations April 30,
2005 to June 30, 2005.

See accompanying notes.


Quarterly Summary

Q2 2005(1) - Cordero commenced operations on April 30, 2005. At inception, production from the Company's coalbed methane and Belly River property in the Malmo area of central Alberta was 683 boe/d. Net earnings were negatively affected by high stock-based compensation expense and the resultant future income tax rate of 90%. Cordero was initially capitalized with a private placement of 1.9 million common shares for proceeds of $5.5 million and subsequent proceeds of $5.3 million from the exercise of 1.9 million warrants granted to former Resolute shareholders. Three million common shares were issued for proceeds of $14.0 million.

Q3 2005 - The improved financial results over the previous period reflected several factors including average production of 1,421 boe/d, slightly better commodity prices and lower per unit cash costs. In relation to the conventional exploration program, land and seismic expenditures were incurred in northwest Alberta and northeast British Columbia. The Company entered into a sale-leaseback transaction with a third party for the construction, sale and use of compression equipment resulting in a total obligation of $1.9 million at the end of the period. The Company expanded its $12.0 million credit facility to $25.0 million.

Q4 2005 - Funds flow from operations and net earnings were positively impacted by increased production volumes and higher commodity prices over the prior quarter. This quarter was the most capital-intensive of 2005 with 38.6 net wells drilled, completion work on 44 wells and compression installation for total net expenditures of $24.8 million. Cordero entered into two additional sale lease-back transactions increasing the total obligation to $5.1 million at the end of the period. The Company completed a share issuance for 2.6 million common shares for gross proceeds of $15.1 million.

Q1 2006 - Average daily production was increased 43% over the previous quarter. Funds flow from operations was 9% lower than the fourth quarter of 2005 due to declining natural gas prices. Partially offsetting the lower revenues were lower unit operating costs which improved 28% from the previous quarter. The Company drilled 17.5 net development wells and 8.7 net exploration wells at an 89% success rate. Tie-in and facilities work resulted in the addition of 24.1 net wells to the production profile, and over 18,000 net acres of land was purchased.

Q2 2006 - Declining natural gas prices exerted downward pressure on funds flow from operations again this quarter. Positively impacting earnings were low operating costs and a royalty rate of 13% resulting from a gas cost allowance adjustment. Negatively impacting earnings were DD&A expense of $17.62/boe which reflected the industry-wide increase in the cost of materials and services, and high future income tax expense as a result of the federal tax rate reductions for 2008 through 2010. The Company drilled 8.5 net wells at a 100% success rate and acquired an interest in over 17,000 net acres of land for exploration prospects. In April, the credit facility was expanded to $46 million and in June, an equity issue was completed for 2.8 million common shares and total gross proceeds of $19.9 million.

Q3 2006 - Funds flow was down 3% from the previous quarter as a result of declining natural gas prices. Net capital expenditures included 1.0 net exploration well, 12.8 net development wells and over 13,000 net undeveloped acres added to the Company's land inventory.

Q4 2006 - Natural gas prices improved slightly during the fourth quarter resulting in a 12% increase in funds flow compared to the third quarter. In November the Company completed a flow-through common share issuance for 1.2 million shares and total gross proceeds of $10.6 million. In conjunction with the financing, Cordero increased its 2006 capital program from $65-68 million to $77-85 million, spending $85.5 million. Also during the quarter, the credit facility was expanded from $46.0 million to $55.0 million. Net capital expenditures included costs for pipelining underneath Buffalo Lake and the addition of over 15,000 net acres of exploratory lands and almost 9,000 net acres in the Malmo area.

(1) Represents the 62-day period from commencement of operations April 30, 2005 to June 30, 2005.



Production
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Natural gas (Mcf/d) 18,189 12,107 17,784 9,393
Oil and NGLs (bbls/d) 119 21 139 8
----------------------------------------------------------------------------
Total (boe/d) 3,150 2,039 3,103 1,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production for the period ended December 31, 2006 averaged 3,103 boe/d representing an increase of 97% over the previous period. Production for the three months ended December 31, 2006 was 3,150 boe/d, an increase of 54% compared to the fourth quarter of 2005.

Substantially all production additions were natural gas and were attributable to Cordero's successful drilling program and timely implementation of compression equipment and pipeline facilities in the Malmo Buffalo Lake area. The Company was faced with several production-related challenges through the year including transportation and gathering system constraints, difficult surface access, high demand for oilfield surface equipment, some unfavorable results from the exploration program and higher than anticipated production declines. However, the Company also had several achievements in the Malmo area which contributed to the production growth. The Company experimented with and successfully gained the expertise to drill extended reach slant wells, which along with the increase in Buffalo Lake land holdings, helped increase the drilling inventory in the Malmo Buffalo Lake area to over 130 net wells. As well, the Company worked with third parties to resolve transportation issues and completed a pipeline project which involved crossing underneath a narrow portion of Buffalo Lake.

Cordero's stabilized behind-pipe production is estimated at 850 boe/d, of which 450 boe/d is expected to be tied-in by the end of April 2007. The Company is forecasting average production of 3,800 to 4,200 boe/d for 2007 however, actual production will be determined by overall drilling success, the time required to place new wells on production, individual well performance, transportation curtailments, access to gathering and processing facilities and ultimate recoveries on existing wells.



Petroleum & Natural Gas Revenue

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
($000s) 2006 2005 2006 2005
----------------------------------------------------------------------------

Natural gas 11,006 12,503 41,306 22,292
Oil and NGLs 687 134 3,594 139
----------------------------------------------------------------------------
Total 11,693 12,637 44,900 22,431
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Prices and Marketing
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
Benchmark Prices 2006 2005 2006 2005
----------------------------------------------------------------------------

AECO natural gas ($/MMbtu) 6.99 11.43 6.40 9.59
WTI oil (USD$/bbl) 60.21 60.02 68.22 59.50
CDN/USD foreign exchange rate 0.878 0.852 0.883 0.832
WTI oil (CDN equivalent $/bbl) 68.60 70.42 77.26 71.50
Edmonton Light ($/bbl) 64.49 71.17 75.53 71.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
Average Sale Price 2006 2005 2006 2005
----------------------------------------------------------------------------

Natural gas ($/Mcf) 6.58 11.22 6.36 9.69
Oil and NGLs ($/bbl) 62.76 70.12 71.02 69.11
----------------------------------------------------------------------------
Total ($/boe) 40.34 67.38 39.65 58.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As the Company's production profile is predominantly natural gas, revenues are largely determined by the AECO Hub in Alberta which is influenced by several factors including North American supply and demand balance, weather conditions, storage levels, and transportation, gathering and processing capacity constraints. Periodic imbalances between supply and demand for natural gas are common and can result in volatile pricing.

The Company's realized price for its natural gas production in the fourth quarter of 2006 was $6.58/Mcf, 41% lower than $11.22/Mcf reported for the same quarter in 2005. For the year ended December 31, 2006, the realized price of $6.36/Mcf was 34% less than the average realized price in the previous period. Supply uncertainties in 2005 caused by extreme hurricane activity, warmer summer weather and expectations for a cold winter resulted in record demand for natural gas and record high gas prices. In actuality, both the previous and current winters have been warmer than anticipated, creating downward pressure on natural gas prices commencing in early 2006. With the exception of the fourth quarter, Cordero's realized natural gas price in 2006 essentially mirrored the AECO daily index as approximately 88% of production for the year was sold at daily spot. In October the Company sold 35% of its production based on the monthly AECO index which was lower than what production sold for at daily AECO that month. Approximately 10% of production continues to be dedicated to an aggregator contract.

The Company participates in risk management activities in order to manage its exposure to fluctuations in oil and natural gas prices, with the objective of maintaining financial flexibility and a strong balance sheet. There were no contracts outstanding at December 31, 2006 however the Company entered into natural gas contracts in February 2007 for the purpose of ensuring adequate funding is available for planned capital activities. See note 12 in the "Notes to Consolidated Financial Statements" for a summary of these contracts.

Prices received for future production will be determined by the Company's marketing arrangements and overall commodity market conditions.



Royalties

Total Royalties
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
($000s) 2006 2005 2006 2005
----------------------------------------------------------------------------
Crown 823 2,206 4,470 3,594
Freehold and Gross Overriding Royalties
(GORR) 996 467 3,075 804
ARTC (125) (65) (513) (65)
----------------------------------------------------------------------------
Total royalties 1,694 2,608 7,032 4,333
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Royalty Rates
----------------------------------------------------------------------------
Percentage of Total Revenue
----------------------------------------------------------------------------
Crown 7.0 17.5 10.0 16.0
Freehold and GORR 8.5 3.7 6.9 3.6
ARTC (1.1) (0.6) (1.1) (0.3)
----------------------------------------------------------------------------
Total royalties 14.4 20.6 15.8 19.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total royalties in 2006 increased significantly from 2005 due to the growth in production volumes. Crown royalties of $4.5 million for 2006 resulted in a rate of 10% compared to $3.6 million and 16% in 2005. Crown royalties for the fourth quarter of 2006 were $0.8 million or 7% compared to $2.2 million or 18% in the same period of 2005. These royalty payments are calculated based on the Alberta Reference Price, which is calculated on a sliding scale determined by commodity prices. As a result royalty rates can fluctuate significantly in a volatile price environment. In 2006 the Alberta Reference Price was significantly lower than both the previous year and management's expectations, resulting in an actual Crown rate less than both the previous year and management guidance.

Freehold and GORR royalties have increased significantly over the prior year with the increase in production from freehold lands.

In 2006 the Company claimed the maximum Alberta Royalty Tax Credit (ARTC) of $0.5 million compared to $0.1 million in 2005. Crown royalties paid on wells acquired from Resolute were not eligible for ARTC and as eligible production was added from wells drilled by Cordero, the Company's ARTC increased proportionately from the first year of operations.

In 2006 the Alberta Government announced the elimination of ARTC effective January 1, 2007. As a result the Company's royalty rate in the first quarter of 2007 is expected to increase accordingly. Other factors which may determine royalty rates in subsequent periods include future reference prices relative to average wellhead prices, type of royalties (Crown vs. Freehold) and the proportion of production additions qualifying for royalty holidays.



Operating Expenses
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
($000s, except per boe) 2006 2005 2006 2005
----------------------------------------------------------------------------

Operating expenses (gross) 1,279 1,050 4,647 2,348
Processing income (183) (62) (628) (163)
----------------------------------------------------------------------------
Operating expenses (net, as reported) 1,096 988 4,019 2,185
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating expenses per boe (net) 3.78 5.27 3.55 5.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total operating expenses for the three months and year ended December 31, 2006 increased due to the number of producing wells compared to the prior year. Operating expenses on a boe basis for 2006 represented an improvement of 37% compared to the period ended December 31, 2005, primarily as a result of increased production volumes. The current quarter only showed improvement of 28% compared to the three months ended December 31, 2005 because production volumes were down slightly from the third quarter of 2006. The Company operates substantially all of its production and maintains a high level of ownership in gathering and processing facilities, allowing it to achieve operating costs on the lower end of the industry scale.

Processing income represents the recovery of processing costs incurred by third parties at Cordero's facilities. The increase compared to the same periods in the previous year is relative to the increase in the number of Cordero-owned facilities as well as an increase in applicable production going through these facilities.

In the future, anticipated conventional production additions and higher maintenance costs for aging equipment will likely increase per unit costs, the magnitude of which is unknown at this time. The cost of field supplies and services and the Company's future operatorship over gathering and processing facilities will also determine future operating expenses.



Transportation Expenses
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Transportation expenses - $000s 330 260 1,287 508
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Transportation expenses - $/boe 1.14 1.39 1.14 1.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On a unit basis, transportation expenses decreased by 18% and 14% for the three months and year ended December 31, 2006, compared to the three months and period ended December 31, 2005. The decrease is attributable to the increase in production volumes and the resultant opportunity to improve utilization of firm service contracts.

Future transportation expenses on a boe basis will depend on the type of production additions (oil versus natural gas), distance from wellhead to sales point, ownership of gathering and pipeline facilities, the amount of unutilized firm service contracted by the Company and the method of transporting oil (pipeline versus trucking).



General and Administrative Expenses (G&A)

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
($000s, except per boe) 2006 2005 2006 2005
----------------------------------------------------------------------------

G&A expenses (gross) 1,225 1,240 5,487 3,127
Overhead recoveries (321) (268) (1,284) (489)
----------------------------------------------------------------------------
904 972 4,203 2,638
Allocated to capital projects (401) (476) (1,850) (1,281)
----------------------------------------------------------------------------
G&A expenses 503 496 2,353 1,357
----------------------------------------------------------------------------
----------------------------------------------------------------------------

G&A expenses per boe 1.74 2.64 2.08 3.52
----------------------------------------------------------------------------
----------------------------------------------------------------------------


G&A expenses per boe improved significantly from the comparative prior periods; 34% for the quarter and 41% for the period ended December 31, 2006, predominantly as a result of increased production volumes.

G&A expenses are reported net of overhead recoveries and amounts allocated to capital. Overhead recoveries are the allocation and recovery from partners of G&A expenses on Cordero-operated properties and have increased each reporting period due to the increase in the Company's capital activities. G&A expenses allocated to capital projects represent salaries and other costs directly associated with property acquisition, exploration and development activities. This proportion capitalized is regularly reviewed by management and, in future periods, will depend on the type of actual capital activities carried out.

Future unit G&A expenses are expected to benefit from expected incremental production volumes but will be offset by lower overhead recoveries as the 2007 capital budget is currently forecasted to be significantly less than 2006 actual expenditures.



Stock-Based Compensation
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Stock-based compensation expense
- $000s 268 340 1,583 1,061
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Stock-based compensation expenses
- $/boe 0.92 1.81 1.40 5.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock based compensation expense represents the portion of the aggregate fair value of options, performance warrants and performance shares applicable to the period. The actual amount is primarily determined by the number of stock-based securities outstanding as well as the calculated fair value of those instruments and the vesting period. Contributing to higher expense in 2006 was 628,000 more options outstanding at the end of 2006, a higher weighted average fair value for options granted in 2006 and the fact that 2005 was not a full year. The expense recorded in 2005 included 135,000 options granted to independent directors, in conjunction with start-up compensation arrangements, that vested upon grant.



Depletion, Depreciation and Amortization (DD&A)
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Depletion, depreciation and
amortization - $000s 4,884 2,552 18,871 5,344
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Depletion, depreciation and
amortization - $/boe 16.85 13.61 16.66 13.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The oil and gas industry experienced unprecedented activity levels in the last two years which has inflicted upward pressure on the costs for services and supplies required to explore for and develop reserves in western Canada. As a result the Company's finding and development costs have increased and DD&A for the fourth quarter of 2006 was $16.85/boe or 24% higher than the fourth quarter of 2005. For the year ended December 31, 2006, DD&A per boe was $16.66; 20% higher than the period ended December 31, 2005. The increase in total DD&A expenses is reflective of the Company's increasing production and capital base. The per unit increase is a result of the rising cost for services and supplies relative to the addition of proved reserves.

Total costs subject to depletion included $36.4 million of estimated future development costs for proved reserves. Excluded from the depletable base was $22.5 million related to unproved properties and $1.5 million of drilling supplies for future exploration and development.

Cordero's DD&A expense in future periods will reflect finding, development and acquisition costs for proved reserves.



Accretion
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Accretion - $000s 96 38 336 92
----------------------------------------------------------------------------

Accretion - $/boe 0.33 0.20 0.30 0.24
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Accretion of Cordero's asset retirement obligations is calculated at the Company's credit-adjusted, risk-free rates of 7.15% and 7.50%. In 2006 the expense per boe increased 65% for the quarter and 25% year-to-date over the comparable periods in 2005 and will continue to increase with the obligation as additional wells are drilled and facilities are added.



Net Interest
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------

Interest expense, net - $000s 294 33 851 70
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Interest expense, net - $/boe 1.02 0.19 0.75 0.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net interest expense includes interest on the Company's credit facility and interest recorded for the three capital leases, net of interest revenue earned. Interest expense increased from $0.1 million for the period ended December 31, 2005 to $0.9 million for the comparable period in 2006 due to the increase in the Company's debt. As at December 31, 2005 the Company did not have any funds drawn on its credit facility and through the year earned more interest on surplus cash than in 2006. As well, capital leases entered into in 2005 were outstanding for the full year in 2006.

Income Taxes

During the year the federal large corporation tax (LCT) was eliminated effective January 1, 2006. As a result the Company reversed previously recorded amounts in the second quarter, resulting in a recovery of $60,000. Presently the Company does not expect to pay current income tax in 2007 or 2008. This estimate is based on existing tax pools, planned capital activities and current forecasts of taxable income however, several factors can affect this prediction including commodity prices, future production, corporate expenses and both the type and amount of capital expenditures incurred in future reporting periods.

Future tax expense for the three months ended December 31, 2006 was $0.6 million and for the year ended December 31, 2006 was $4.0 million. For the fourth quarter of 2005 future tax expense was $1.8 million and for the period ended December 31, 2005 it was $2.9 million. In the current year the Company made a one-time downward adjustment to the future tax asset to account for income tax rate reductions legislated in the second quarter, which resulted in a higher expense for the period.

Pursuant to a flow-through share issuance completed in November 2006 the Company is required to renounce $10.6 million of exploration costs to investors by December 31, 2007. In accordance with current accounting standards, the future tax liability is recorded in the financial statements when the costs are renounced to investors. This treatment results in the deferred recognition of a liability of approximately $0.8 million associated with $2.8 million of the obligation that has been fulfilled at December 31, 2006. The costs were renounced in February 2007. Cordero's 2007 capital budget and estimated future tax horizon reflect the remaining $7.8 million commitment. Estimated income tax pools available at January 1, 2007, adjusted for the $2.8 million, are as follows:



----------------------------------------------------------------------------
Annual Deduction
Available (%) ($000s)
----------------------------------------------------------------------------
Canadian oil and gas property expenses 10 58,647
Canadian development expenses 30 27,894
Canadian exploration expenses 100 21,958
Undepreciated capital costs 25 43,302
Financing costs 20 2,588
Other 7 101
----------------------------------------------------------------------------
154,490
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Net Earnings

Net earnings for the fourth quarter of 2006 were $1.9 million and year-to-date, were $4.7 million. Compared to the respective periods in the prior year, these results represent a decrease of 45% for the three months ended December 31, 2006 and an increase of 3% for the year ended December 31, 2006 as 2005 was a partial year. The significant factors contributing to the reduced net income in the fourth quarter of 2006 were lower natural gas prices and higher DD&A expense, which were offset by lower operating expenses, G&A costs and future income tax.




Operating Netbacks by Product

The following tables summarize the Company's operating netbacks for natural
gas, crude oil and NGLs.

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
Natural gas ($/Mcf) 2006 2005 2006 2005
----------------------------------------------------------------------------

Sales price 6.58 11.22 6.36 9.69
Royalties (0.93) (2.31) (0.95) (1.87)
Transportation costs (0.19) (0.23) (0.20) (0.22)
Operating expenses (0.62) (0.87) (0.58) (0.94)
----------------------------------------------------------------------------
Operating netback - natural gas 4.84 7.81 4.63 6.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
Crude oil ($/bbl) 2006 2005 2006 2005
----------------------------------------------------------------------------

Sales price 63.96 70.57 72.36 70.57
Royalties (12.65) (20.71) (16.89) (20.71)
Transportation costs (1.11) (1.39) (1.13) (1.39)
Operating expenses (9.06) (10.28) (5.55) (10.28)
----------------------------------------------------------------------------
Operating netback - crude oil 41.14 38.19 48.79 38.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
NGLs ($/bbl) 2006 2005 2006 2005
----------------------------------------------------------------------------

Sales price 51.79 57.67 55.54 52.38
Royalties (9.92) (26.78) (12.95) (16.00)
Transportation costs (1.49) (0.14) (1.44) (0.14)
Operating expenses (7.43) (8.70) (7.20) (8.82)
----------------------------------------------------------------------------
Operating netback - NGLs 32.95 22.05 33.95 27.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For wells that produce more than one commodity, revenues and costs are
allocated based on the relative production volumes.

Cash Netbacks

The Company's overall operating and corporate netbacks are as follows:

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
Total Netback ($/boe) 2006 2005 2006 2005
----------------------------------------------------------------------------

Sales price 40.34 67.38 39.65 58.18
Royalties (5.84) (13.90) (6.21) (11.23)
Transportation costs (1.14) (1.39) (1.14) (1.32)
Operating expenses (3.78) (5.27) (3.55) (5.67)
----------------------------------------------------------------------------
Operating netback 29.58 46.82 28.75 39.96
G&A (1.74) (2.64) (2.08) (3.52)
Interest (net) (1.02) (0.19) (0.75) (0.18)
Current income taxes - (0.41) 0.05 (0.24)
----------------------------------------------------------------------------
Corporate netback 26.82 43.58 25.97 36.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital Expenditures

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
($000s) 2006 2005 2006 2005
----------------------------------------------------------------------------

Land and lease retention 6,364 2,530 15,985 4,321
Geological and geophysical 294 1,879 2,907 3,227
Drilling and completions 7,849 11,978 40,923 16,678
Facilities and equipment 9,228 7,803 25,321 15,555
Property acquisitions - - - 753
Other 588 841 2,700 2,298
----------------------------------------------------------------------------
Total capital expenditures 24,323 25,031 87,836 42,832
Purchase price adjustment - 300 - 14,545
Dispositions - (243) (2,298) (1,215)
----------------------------------------------------------------------------
Net capital expenditures 24,323 25,088 85,538 56,162
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Total net capital expenditures for the fourth quarter of 2006 were $24.3 million. For the year ended December 31, 2006, capital expenditures of $85.5 million were on the high end of the Company's forecast of $77-85 million with the high costs for supplies and services and the expansion of the land budget to take advantage of opportunities resulting from the decline in natural gas prices. During the last three months of the year, Cordero drilled 10.0 net wells at a 90% success rate, completed a major pipeline and facilities project in Malmo which involved pipelining underneath Buffalo Lake and increased Malmo area and exploratory land holdings. The Company had a very ambitious capital program in 2006 with several accomplishments including the technology gained on extended reach slant drilling, the Buffalo Lake crossing, an almost 50% increase in Malmo area landholdings, exploratory land acquisitions and the required facilities to bring the 2005 Gething discovery at Karr on-stream. However, some of the exploration projects provided disappointing results and did not contribute to incremental production and reserves as had been anticipated; therefore finding and development costs for the period were higher than expected and higher than 2005. Current exploratory projects include a possible follow-up well at Karr and identified prospects at Goose River, Knopcik, Bigoray, Trutch and Tupper.

The 2007 capital budget is currently set at $50-55 million with approximately two-thirds dedicated to development at Malmo and the remainder allocated to exploration activities.

Liquidity and Capital Resources

In April 2006, Cordero's credit facility was expanded from $25.0 million to $46.0 million and in November it was further increased to $55.0 million. The additional funds from the credit facility were applied to the Company's capital program.

In June 2006 a bought-deal equity offering was completed whereby 2.8 million common shares were issued at $7.25/share for total gross proceeds of $19.9 million. In conjunction with the funds received from the financing, the capital budget was increased from $50-55 million to $65-68 million.

In November the Company closed a flow-through common share issuance for 1.2 million shares at $8.80/share for total gross proceeds of $10.6 million. The net proceeds from the financing were used to increase the capital budget to $77-85 million. Pursuant to this flow-through share issuance, the Company is required to incur $10.6 million in exploration costs prior to December 31, 2007. At December 31, 2006 approximately $2.8 million of costs required to fulfill the Company's flow-through share commitments have been incurred.

The nature of the oil and gas industry requires significant cash outlays to fund capital programs necessary to maintain and increase production and proved developed reserves and to acquire strategic oil and gas assets. Cordero expects to finance its 2007 capital program and all other commitments through a combination of internally generated cash flow and debt. Funding alternatives ultimately chosen by the Company will be influenced by the capital market environment for equity, the cost of debt and the nature and amount of actual expenditures being incurred.

The Company's net debt and working capital deficiency at December 31, 2006 was $31.7 million compared to $4.1 million at December 31, 2005. The primary reason for the difference from year to year is the Company's cash position. At December 31, 2005 the Company had cash of $11.0 million and its credit facility which was not drawn on. At December 31, 2006, the credit facility had an outstanding balance of $20.9 million.

In the normal course of operations the Company has entered into contracts and incurred obligations that will impact future liquidity. Based on current cash flow forecasts Cordero expects to fulfil its principal contractual obligations at December 31, 2006 as summarized below:



----------------------------------------------------------------------------
Less than 1-3 4-5 After 5
($000s) Total 1 Year Years Years Years
----------------------------------------------------------------------------
Operating lease obligations
(office space) 682 319 363 - -
Transportation obligations 3,726 1,417 2,041 268 -
Capital lease obligations 4,477 637 1,174 1,041 1,625
----------------------------------------------------------------------------
Total contractual obligations 8,885 2,373 3,578 1,309 1,625
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Outstanding Shares, Options and Warrants

----------------------------------------------------------------------------
Outstanding at period-end (000s) March 9, 2007 December 31, 2006
----------------------------------------------------------------------------

Common shares 33,823 33,823
Common shares issuable on conversion:
Stock options 1,734 1,734
Performance warrants 1,916 1,916
Performance shares 484 484
----------------------------------------------------------------------------
Total 37,957 37,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Share Trading Information

----------------------------------------------------------------------------
2006 2005
----------------------------------------------------------------------------
Trading volume (000s) 16,063 12,618
Daily average (000s) 64 76
Trading value ($000s) 106,638 69,095

Share price ($/share)
High 7.70 6.74
Low 5.50 3.51
Average 6.64 5.48

Market capitalization - at December 31
Shares outstanding (000s) 33,823 29,725
Year end share price ($/share) 6.83 6.50
Total ($000s) 231,011 193,213
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Industry Conditions and Risk Factors

The business of exploring for, developing, acquiring, producing and marketing crude oil and natural gas results in the exposure to several risk and uncertainties, several of which are beyond the Company's control.

Operational risks include exploration and development of economic crude oil and natural gas reserves, reservoir performance, safety and environmental concerns, access to cost effective contract services, product marketing and hiring and retaining qualified employees. Management attempts to mitigate the risk through employing experienced, qualified personnel for operational work, and obtaining as much expertise as possible in the areas of operations. High operatorship provides the Company with the ability to perform its operations under its strict safety standards. Cordero maintains an insurance program commensurate with its levels and scope of operations to protect against loss.

Estimates of economically recoverable reserves and the future net cash flow generated from the reserves are based on a number of factors and assumptions, known and unknown risks and uncertainties that contribute to the possibility that estimated reserves may vary materially from actual future production. The Company's reserves as at December 31, 2006 were evaluated by independent reservoir engineers and approved by the Board of Directors.

The Company is exposed to financial risks in the form of fluctuating commodity prices, interest rates and the U.S. dollar exchange rate. The Company actively monitors these risks and may use financial instruments to manage its commodity price exposure.

A comprehensive discussion of risks can be found in the Company's annual information form which will be on www.sedar.com and www.corderoenergy.com prior to March 31, 2007.

Critical Accounting Estimates

Management makes certain judgments and estimates in preparing financial statements in accordance with Canadian GAAP. Changes to these judgments and estimates could have a material effect on Cordero's financial statements and financial position.

Proved Petroleum and Natural Gas Reserves

Proved reserves, the estimated quantities of natural gas, crude oil and natural gas liquids that can be recovered in future years under future economic and operating conditions, are critical to many aspects of the Company's financial statements. These estimates are made with reasonable certainty using all available geological and reservoir data as well as historical production data and are subject to revisions based on changes in reservoir performance and the pricing environment.

Depletion Expense

In accordance with the full cost method of accounting for exploration and development activities, all costs associated with exploration and development are capitalized, whether successful or not. The aggregate of capitalized costs and future development costs, net of costs related to unproved properties, is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development costs have a direct impact on depletion expense.

Certain costs related to unproved properties may be excluded from costs subject to depletion until proved reserves have been determined or their value impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned or if impairment exists.

Full Cost Accounting Ceiling Test

The Company reviews the carrying value of all petroleum and natural gas assets for potential impairment on a quarterly basis. Impairment is indicated if the carrying value of the assets is not recoverable by the future undiscounted cash flows. This impairment test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. If impairment exists, the amount by which the carrying value exceeds the estimated fair value of the assets will be charged to earnings.

Asset Retirement Obligations

The provision for asset retirement obligations is estimated based on costs to abandon and reclaim wells and facilities, timing of abandonment and reclamation of wells and facilities, and inflation and discount rates over the life of the reserves. Changes to any assumptions used in the calculation will have an impact on the provision and the accretion expense included in earnings.

Stock-based Compensation Expense

Compensation costs attributable to stock options, performance warrants and performance shares granted by the Company are charged to earnings over the vesting period of the securities. The fair value calculation method adopted by the Company is the Black-Scholes model, which requires management to estimate the expected life of the securities and the expected volatility of Cordero's share price over the life of the options, performance warrants and performance shares. These estimates may be different than the actual life and volatility.

Income Taxes

The determination of the Company's income tax liabilities requires interpretation of complex laws and regulations and all tax filings are subject to audit and potential reassessment. Future income tax expense is calculated using tax rates based on the estimated timing of reversal of temporary differences between accounting and tax values of certain assets and liabilities. The actual current and future tax expenses recorded may differ from those actually incurred.

Future Accounting Standards Changes

Financial Instruments

In April 2005, the Canadian Institute of Chartered Accountants issued the following new Handbook Sections that the Company plans to adopt effective January 1, 2007:

1) Section 1530, Comprehensive Income;

2) Section 3251, Equity;

3) Section 3855, Financial Instruments - Recognition and Measurement; and

4) Section 3865, Hedges.

Implementation of these standards will require that all financial instruments, with the exception of financial instruments qualifying for hedge accounting, be included on the Company's balance sheet at fair value, with changes in fair value charged to earnings. Existing requirements for hedge accounting will be extended to specify how hedge accounting should be performed and gains and losses on financial instruments designated as hedges will be included in other comprehensive income.

These standards do not permit restatement of prior years' financial statements. The Company has not determined the future impact these standards will have on financial statements.

Financial Statement Disclosures

In December 2006, Financial Instruments - Disclosures (Section 3862) was issued to elaborate on disclosure surrounding financial instruments. These standards apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007.

Also in December 2006, Handbook Section 1535, Capital Disclosures was issued to establish standards for disclosing information about an entity's capital and how it is managed. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007 however earlier adoption is encouraged.

The Company does not anticipate a material impact to its existing disclosure upon implementation of these new policies.

Internal Controls Over Financial Reporting and Disclosure Controls and Procedures

Management, with the participation of the Company's Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of the Company's disclosure controls and procedures. Based on that evaluation, the Company's Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2006, the Company's disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed by the Company in its filings or other reports filed or submitted under applicable securities laws is:

1) recorded, processed, summarized and reported within the applicable legislated time periods; and

2) accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Management, with the participation of the Company's Chief Executive Officer and Chief Financial Officer, has evaluated the design of the Company's internal controls over financial reporting. Based on that evaluation, the Company's Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2006, the Company's internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's GAAP and includes those policies and procedures that:

1) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the Company's GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the Company; and

3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on the annual financial statements or interim financial statements.

Internal controls over financial reporting and disclosure controls and procedures, no matter how well designed, have inherent limitations. Therefore, internal control over financial reporting and disclosure controls and procedures can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect all misstatements or omissions of information. Due to the small size of the Company, management acknowledges there is lack of segregation of duties within several of the Company's processes. Management has identified the specific functions with the potential to compromise the Company's overall control objectives as outlined above. In response to the identified risks, appropriate compensating controls have been implemented to management's satisfaction.

The Company will evaluate the operating effectiveness of internal controls over financial reporting within the timelines required by relevant securities legislation.

There were no changes in the Company's internal control over financial reporting during the quarter ended December 31, 2006 that have materially affected, or are reasonably likely to affect, the Company's internal control over financial reporting.

Additional information about Cordero is available on the Canadian Securities Administrators' System for Electronic Distribution and Retrieval (SEDAR) at www.sedar.com.



Consolidated Balance Sheets

----------------------------------------------------------------------------
($000s) December 31, 2006 December 31, 2005
----------------------------------------------------------------------------

Assets

Current
Cash and cash equivalents - 11,027
Accounts receivable 8,594 8,799
----------------------------------------------------------------------------
8,594 19,826

Petroleum and natural gas interests
(note 3) 142,343 74,623

Future income tax asset (note 10) 7,075 10,474
----------------------------------------------------------------------------

158,012 104,923
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities

Current
Accounts payable and accrued liabilities 15,787 19,825
Current portion of obligations under
capital leases (note 5) 456 446
----------------------------------------------------------------------------
16,243 20,271

Long-term credit facility (note 4) 20,868 -

Obligations under capital leases (note 5) 3,167 3,623

Asset retirement obligations (note 6) 4,902 3,695

Shareholders' equity
Share capital (notes 7 and 8) 101,195 71,747
Contributed surplus (note 7) 2,436 1,061
Retained earnings 9,201 4,526
----------------------------------------------------------------------------
112,832 77,334
----------------------------------------------------------------------------

158,012 104,923
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes.


Consolidated Statements of Operations

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31(1) December 31
($000s, except per share amounts) 2006 2005 2006 2005(2)
----------------------------------------------------------------------------

Revenue
Gross oil and natural gas revenue 11,693 12,637 44,900 22,431
Royalties (1,694) (2,608) (7,032) (4,333)
----------------------------------------------------------------------------
9,999 10,029 37,868 18,098
----------------------------------------------------------------------------

Expenses
Operating 1,096 988 4,019 2,185
Transportation 330 260 1,287 508
General and administrative 503 496 2,353 1,357
Net interest (notes 4 and 5) 294 33 851 70
Depletion, depreciation and
amortization (note 3) 4,884 2,552 18,871 5,344
Accretion (note 6) 96 38 336 92
Stock-based compensation (note 8) 268 340 1,583 1,061
----------------------------------------------------------------------------
7,471 4,707 29,300 10,617
----------------------------------------------------------------------------

Earnings before income taxes 2,528 5,322 8,568 7,481

Income taxes (note 10)
Current income taxes (recovery) - 77 (60) 94
Future income taxes 644 1,792 3,953 2,861
----------------------------------------------------------------------------
644 1,869 3,893 2,955

----------------------------------------------------------------------------
Net earnings 1,884 3,453 4,675 4,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net earnings per share (note 9)
Basic 0.06 0.12 0.15 0.17
Diluted 0.05 0.11 0.14 0.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Consolidated Statements of Retained Earnings

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31(1) December 31
($000s) 2006 2005 2006 2005(2)
----------------------------------------------------------------------------
Retained earnings, beginning of period 7,317 1,073 4,526 -
Earnings for the period 1,884 3,453 4,675 4,526
----------------------------------------------------------------------------
Retained earnings, end of period 9,201 4,526 9,201 4,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Unaudited.
(2) Represents the 246-day period from commencement of operations April 30,
2005 to December 31, 2005.

See accompanying notes.


Consolidated Statements of Cash Flows

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31(1) December 31
($000s) 2006 2005 2006 2005(2)
----------------------------------------------------------------------------
Cash flows from the following:

Operating activities
Net earnings 1,884 3,453 4,675 4,526
Items not affecting cash
Depletion, depreciation and
amortization 4,884 2,552 18,871 5,344
Accretion 96 38 336 92
Future income taxes 644 1,792 3,953 2,861
Stock-based compensation 268 340 1,583 1,061
Asset retirement obligation
expenditures (note 6) (21) - (182) (5)
Changes in non-cash working capital
(note 11) (854) (1,277) (206) (859)
----------------------------------------------------------------------------
6,901 6,898 29,030 13,020
----------------------------------------------------------------------------

Financing activities
Issue of common shares 10,560 15,080 30,498 38,879
Share issue costs (602) (881) (1,811) (1,754)
Increase of bank indebtedness
(note 4) 7,582 - 20,868 -
Payment of capital lease obligations
(note 5) (112) (69) (446) (80)
Proceeds from sale-lease back
transactions - 2,735 - 4,239
----------------------------------------------------------------------------
17,428 16,865 49,109 42,284
----------------------------------------------------------------------------

Investing activities
Petroleum and natural gas
expenditures (24,323) (25,031) (87,836) (42,832)
Purchase of petroleum and natural
gas assets and equipment - (300) - (14,545)
Disposition of petroleum and natural
gas interests - 243 2,298 1,215
Changes in non-cash working capital
(note 11) (6) 10,896 (3,628) 11,885
----------------------------------------------------------------------------
(24,329) (14,192) (89,166) (44,277)
----------------------------------------------------------------------------

Increase (decrease) in cash and cash
equivalents - 9,571 (11,027) 11,027

Cash and cash equivalents, beginning
of period - 1,456 11,027 -
----------------------------------------------------------------------------

Cash and cash equivalents, end of
period - 11,027 - 11,027
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Unaudited.
(2) Represents the 246-day period from commencement of operations April 30,
2005 to December 31, 2005.

See accompanying notes.


CORDERO ENERGY INC.

Notes to Consolidated Financial Statements

For the three months (unaudited) and year ended December 31, 2006 (tabular amounts in thousands of dollars, except share and per share data):

1. Description of Business

Cordero Energy Inc. ("Cordero" or "the Company") is an independent exploration and development company pursuing conventional oil and natural gas production and reserves as well as coalbed methane development in western Canada. Cordero is based in Calgary, Alberta and was incorporated under the Business Corporations Act (Alberta) on March 30, 2005. The Company commenced operations on April 30, 2005 when certain oil and gas properties of Resolute Energy Inc. (Resolute) were transferred to Cordero under a plan of arrangement.

2. Significant Accounting Policies and Basis of Presentation

These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Cordero Finance Corporation which has no material assets or operations. All inter-company transactions and accounts have been eliminated. The consolidated financial statements are presented in accordance with Canadian Generally Accepted Accounting Principles (GAAP) and are expressed in Canadian dollars. The period ended December 31, 2005 represents the 246-day period from April 30, 2005 to December 31, 2005.

(a) Joint Venture Activities

A portion of the Company's exploration, development and production activities are conducted jointly with others. These financial statements reflect the Company's proportionate interest in such activities.

(b) Cash and Cash Equivalents

Cash includes cash on deposit and short-term investments with an initial maturity of 90 days or less at the time of issue.

(c) Petroleum and Natural Gas Interests

The Company follows the full cost method of accounting for petroleum and natural gas interests whereby all costs relating to exploration for and development of petroleum and natural gas reserves are capitalized in one cost centre. Such costs include land acquisition costs, geological and geophysical expenses, costs of drilling both productive and non-productive wells and tangible equipment and administrative costs directly related to acquisition, exploration and development activities. Gains or losses are not recognized upon disposition of oil and natural gas properties unless crediting the proceeds against accumulated costs would result in a 20% or higher change in the depletion rate.

Depletion and Depreciation

Petroleum and natural gas interests, including assets under capital lease, are depleted or depreciated using the unit-of-production method based on an independent engineering estimate of the Company's share of proved reserves, before royalties, with natural gas converted to its energy equivalent at a ratio of six thousand cubic feet of natural gas to one barrel of oil. Included in the depletion base are estimated future costs to be incurred in developing proved reserves and, excluded, are estimated salvage values and costs incurred acquiring and evaluating unproved properties.

Impairment

Petroleum and natural gas interests are evaluated quarterly to determine whether the costs capitalized are impaired. The costs are impaired if the carrying value of the assets exceeds the sum of the undiscounted cash flows expected from the production of proved reserves and the lower of cost and market of unproved properties. If the carrying value is assessed as impaired, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using expected future product prices and costs, discounted using a risk-free rate. Unproved properties are assessed for impairment in a separate impairment test.

Asset Retirement Obligations

The fair value of the liability for asset retirement obligations is recorded in the period when a reasonable estimate of the fair value can be determined, with a corresponding increase to the carrying amount of the related asset. Increases in the fair value of the asset retirement obligations due to the passage of time are recorded as accretion expense. Actual expenditures incurred are charged against the obligations.

(d) Revenue Recognition

Revenue is recognized when title passes to the customer.

(e) Hedging

The Company may use financial instruments to manage its exposure to fluctuations in oil and natural gas prices. The Company does not enter into derivative financial instruments for trading or speculative purposes.

Hedge accounting may be used when there is a high degree of correlation between price movements in the financial instrument and the underlying asset. Under hedge accounting, the fair value of the derivative instruments are not recognized on the balance sheet. Realized gains and losses on these contracts are recognized in petroleum and natural gas revenue and cash flows in the same period in which the revenues associated with the hedged transactions are recognized.

(f) Stock-Based Compensation Plans

The Company has stock-based compensation plans described in note 8 and accounts for its plans using the fair value method. Under this method, compensation cost attributable to stock options, performance warrants and performance shares granted to officers, directors and employees is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Consideration paid upon the exercise of stock options, performance warrants or performance shares, together with corresponding amounts previously recognized in contributed surplus, is recorded as an increase to share capital. In the event that vested options or warrants expire without being exercised, previously recognized compensation costs associated with such stock options are not reversed.

(g) Accounting for Leases

The evaluation of whether an arrangement is a lease, or contains a lease, is based on the substance of the arrangement and is considered as such if fulfillment of the arrangement is dependent on the use of a specific tangible asset or assets and the arrangement conveys a right to use the tangible asset or assets.

(h) Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using enacted or substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.

(i) Flow-through Shares

In accordance with Canadian tax legislation deductions for income tax purposes related to activities funded by flow-through share arrangements are renounced to investors. The estimated tax effect of the amounts renounced to shareholders is charged to share capital with a corresponding increase in future income tax liabilities when the expenditures are renounced to shareholders.

(j) Earnings per Share

Per share information is calculated on the basis of the weighted average number of common shares outstanding during the period. Diluted per share information is calculated using the treasury stock method which assumes that any proceeds received by the Company upon the exercise of in-the-money stock options, performance warrants and performance shares, plus unamortized stock compensation costs, would be used to buy back common shares at the average market price for the period.

(k) Measurement Uncertainty

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses, and disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

The amounts recorded for depletion and deprecation of petroleum and natural gas interests and for asset retirement obligations are based on estimates of petroleum and natural gas reserves and future costs. Proved reserves also provide the basis for determining whether the carrying value of petroleum and natural gas interests is impaired. The determination of stock-based compensation involves estimates of the volatility of the Company's common shares for future rates and expected life. Future income tax expense is calculated using tax rates based on the estimated timing of reversal of temporary differences between accounting and tax values of certain assets and liabilities and involves forecasting the amount of the future income tax asset that will be realized. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements of future periods could be material.



3. Petroleum and Natural Gas Interests

----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
At December 31, 2006 Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum and natural gas interests 160,052 (23,770) 136,282
Assets under capital leases (note 5) 4,149 (303) 3,846
Other assets 2,357 (142) 2,215
----------------------------------------------------------------------------
166,558 (24,215) 142,343
----------------------------------------------------------------------------

At December 31, 2005
----------------------------------------------------------------------------
Petroleum and natural gas interests 73,996 (5,092) 68,904
Assets under capital leases (note 5) 4,149 (180) 3,969
Other assets 1,822 (72) 1,750
----------------------------------------------------------------------------
79,967 (5,344) 74,623
----------------------------------------------------------------------------


As at December 31, 2006, unproved properties of $22.5 million (2005 - $12.0 million) and other petroleum and natural gas assets of $1.5 million (2005 - $1.2 million) which consisted of drilling supplies for future exploration and development, were not subject to depletion.

The Company capitalized direct overhead expenses of $0.4 million (2005 - $0.5 million) and $1.9 million (2005 - $1.3 million) relating to petroleum and natural gas exploration and development activities for the three months and period ended December 31, 2006, respectively.

Cordero performed a ceiling test calculation at December 31, 2006 to assess whether petroleum and natural gas interests are impaired. The future oil and gas prices are based on January 1, 2007 benchmark prices in the futures market. These prices have been adjusted for commodity price differentials, and transportation costs specific to Cordero.

The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, there was no impairment at December 31, 2006.



----------------------------------------------------------------------------
Foreign Edmonton
WTI Oil Exchange Light Crude Oil AECO Gas
Year (US$/bbl) Rate (Cdn$/bbl) (Cdn$/MMbtu)
----------------------------------------------------------------------------
2007 65.73 0.870 74.10 7.72
2008 68.82 0.870 77.62 8.59
2009 62.42 0.870 70.25 7.74
2010 58.37 0.870 65.56 7.55
2011 55.20 0.870 61.90 7.72
Escalate thereafter Various Escalation Rates
----------------------------------------------------------------------------


4. Credit Facility

During 2006 the Company's revolving term credit facility was increased from $25.0 million to $55.0 million. It is provided by a Canadian chartered bank, is subject to semi-annual review and is secured by an $80.0 million first floating charge debenture over all of the Company's assets. The facility revolves and fluctuates at Cordero's option until May 31, 2007. At this time Cordero may request a renewal or the loan will convert to a 366-day term loan.

Borrowings are made by way of prime loans with interest at the bank's prime lending rate, banker's acceptances or LIBOR advances at LIBOR plus a stamping fee of 1.10%. Interest paid on the facility for the three and twelve months ended December 31, 2006 was $0.2 million (2005 - $10,000) and $0.7 million (2005 - $16,000), respectively.

5. Obligations Under Capital Leases

The Company has three capital leases for compression equipment for a term of ten years. Future minimum lease payments under these leases are as follows:



----------------------------------------------------------------------------
Year Amount
----------------------------------------------------------------------------
2007 637
2008 604
2009 571
2010 537
2011 504
2012 471
Thereafter 1,153
----------------------------------------------------------------------------
Total minimum lease payments 4,477
Less amount representing interest at 5.18% to 5.91% 854
----------------------------------------------------------------------------
Present value of obligations under capital leases 3,623
Due within one year 456
----------------------------------------------------------------------------
Long-term portion of obligations under capital leases 3,167
----------------------------------------------------------------------------


Interest expense incurred on the obligations under capital leases was $52,000 (2005 - $31,000) and $224,000 (2005 - $38,000), respectively for the three months and period ended December 31, 2006. Leased assets are depreciated using the unit-of-production method (see note 3).

6. Asset Retirement Obligations

Asset retirement obligations are based on the Company's net ownership in all wells and facilities, management's estimate of costs to abandon and reclaim those wells and facilities and the potential future timing of the costs to be incurred.

Total undiscounted cash flows, escalated at 2.0%, required to settle the Company's asset retirement obligations are estimated to be $11.0 million. Payments to settle these obligations will occur over the operating lives of the underlying assets, estimated to be from 0 to 32 years, with the majority of costs expected to occur between 2014 and 2019. Estimated costs have been discounted at Cordero's credit-adjusted, risk-free interest rates of 7.15% and 7.50%.



----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------
Asset retirement obligations,
beginning of period 5,057 1,988 3,695 -
Liabilities transferred upon plan
of arrangement - - - 1,250
Obligations incurred in period 333 984 1,616 1,673
Revisions to obligations (563) 785 (563) 785
Obligations settled during period (21) - (182) (5)
Dispositions - (100) - (100)
Accretion 96 38 336 92
----------------------------------------------------------------------------
Asset retirement obligations,
end of period 4,902 3,695 4,902 3,695
----------------------------------------------------------------------------


7. Share Capital

(a) Authorized

At December 31, 2006, the Company had authorized an unlimited number of common shares and an unlimited number of preferred shares.

(b)

Issued and Outstanding



----------------------------------------------------------------------------
Common Shares Number Consideration
----------------------------------------------------------------------------
Issued on incorporation, March 30, 2005 1 1
Issued on completion of plan of arrangement 20,347,222 33,024
Initial private placement 1,916,376 5,500
Exercise of arrangement warrants 1,861,190 5,341
Equity offerings 5,600,000 29,030
Share issue costs (net of future tax effect) - (1,156)
----------------------------------------------------------------------------
Balance, December 31, 2005 29,724,789 71,740
----------------------------------------------------------------------------
Equity offering June 2, 2006 2,750,000 19,938
Equity offering November 9, 2006 1,200,000 10,560
Conversion of performance shares 148,124 2
Transfer from contributed surplus on exercise
of performance shares - 208
Share issue costs (net of future income tax effect) - (1,258)
----------------------------------------------------------------------------
Balance, December 31, 2006 33,822,913 101,190
----------------------------------------------------------------------------


On June 2, 2006, the Company closed a bought deal private placement whereby 2.75 million common shares were issued at a price of $7.25/share for total gross proceeds of $19.9 million. On November 9, 2006, the Company issued 1.2 million flow-through common shares at $8.80/share for total gross proceeds of $10.6 million.



----------------------------------------------------------------------------
Performance Shares Number Consideration
----------------------------------------------------------------------------
Balance, beginning of period 725,900 7
Granted
Exercised (241,967) (2)
----------------------------------------------------------------------------
Balance, end of period 483,933 5
----------------------------------------------------------------------------


Each performance share was issued for a price of $0.01/share and is convertible into the percentage of a Cordero common share equal to the closing trading price of the Cordero common shares less market value of $2.87 if positive, divided by the Cordero closing share price. The Cordero performance shares automatically convert into Cordero common shares as to one-third on each of the first, second, and third anniversaries of April 29, 2005 if the holder is a service provider on such date. In May 2006, 148,124 common shares were issued upon vesting and conversion of 241,967 performance shares.



(c) Contributed Surplus
----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------
Balance, beginning of period 2,168 721 1,061 -
Stock-based compensation expense 268 340 1,583 1,061
Exercise of performance shares - - (208) -
----------------------------------------------------------------------------
Balance, end of period 2,436 1,061 2,436 1,061
----------------------------------------------------------------------------


8. Stock-Based Compensation Plans

(a) Stock Option Plan

The Company has established a stock option plan whereby officers, directors and employees may be granted options to purchase common shares at a fixed price not less than the volume-weighted five-day average preceding grant. Vesting and expiry provisions vary for each grant and are determined at the date of grant. The aggregate number of common shares and any other security-based share compensation of Cordero reserved for issuance under the performance share and stock option plans is fixed at a rolling maximum of 10% of the issued and outstanding common shares calculated on a non-diluted basis.



The following table summarizes information regarding the Company's stock
option activity during the year ended December 31, 2006.

----------------------------------------------------------------------------
2006 2005
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price ($) Options Price ($)
----------------------------------------------------------------------------
Outstanding at beginning of period 1,105,800 4.69 - -
Granted 628,000 6.40 1,105,800 4.69
----------------------------------------------------------------------------
Outstanding at end of period 1,733,800 5.31 1,105,800 4.69
----------------------------------------------------------------------------

The following table summarizes information about the Company's stock options
outstanding and exercisable at December 31, 2006:

----------------------------------------------------------------------------
Remaining Weighted Remaining Weighted
Contractual Average Contractual Average
Exercise Options Life Exercise Options Life Exercise
Price($) Outstanding (Years) Price($) Exercisable (Years) Price($)
----------------------------------------------------------------------------
4.43-5.00 955,400 3.99 4.55 471,807 3.42 4.65
5.01-6.00 192,900 3.77 5.64 76,801 3.64 5.54
6.01-7.00 473,000 4.17 6.20 - - -
7.01-7.40 112,500 4.35 7.40 18,000 4.35 7.40
----------------------------------------------------------------------------
4.43-7.40 1,733,800 3.71 5.31 566,608 3.48 4.85
----------------------------------------------------------------------------


(b) Performance Warrants

At December 31, 2006 and 2005, there were 1,916,376 performance warrants outstanding. Each performance warrant is exercisable onto one common share of the Company at a price of $2.87/share. The performance warrants have a term of five years and one-third will vest on each of the first, second and third anniversaries of April 29, 2005 as long as the twenty day weighted average trading price of the common shares of Cordero reaches 1.5 times, 2.0 times and 2.5 times $2.87. As at December 31, 2006, all three performance clauses have been met and one third of the outstanding warrants have vested.

(c) Share Appreciation Rights Plan

At inception the Company established a share appreciation rights plan whereby share appreciation rights (rights) could be granted to directors, officers, employees and other individuals who perform services for the Company or any subsidiary of the Company. Rights under this plan were available for grant from the date of plan approval through October 29, 2006. As there were no share appreciation rights granted within the specified period the rights under this plan have been terminated.

(d) Stock-Based Compensation

The fair value of each stock option, performance warrant and performance share granted is estimated on the date of grant using the Black-Scholes option pricing model. Weighted average assumptions and resulting fair value for stock options granted during the three months and year ended December 31, 2006 are as follows:



----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------
Risk-free interest rate (%) 4.00 - 4.02 3.15
Expected life (years) 3.5 - 3.5 3.5
Expected volatility (%) 40 - 40 40
Dividend yield (%) - - - -

Weighted average fair value ($) 2.278 - 2.059 1.547
----------------------------------------------------------------------------


The aggregate fair value of the stock options, performance warrants and performance shares is expensed over the respective vesting periods, with a corresponding increase to contributed surplus.

9. Net Earnings per Share

The following reconciles the number of shares used in the basic and diluted net earnings per share calculations:



----------------------------------------------------------------------------
Three Months Ended Period Ended
Common Shares December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------
Weighted average basic 33,314,217 28,057,398 31,602,850 26,795,376
Dilutive securities
Stock options 547,823 425,565 557,956 324,071
Performance warrants 1,186,773 1,147,947 1,197,761 1,045,553
Performance shares 449,520 803,800 408,140 814,177
----------------------------------------------------------------------------
Weighted average diluted 35,498,333 30,434,710 33,766,707 28,979,177
----------------------------------------------------------------------------

10. Income Taxes

The future income tax provision reflects an effective tax rate which differs
from the expected statutory tax rate. Differences were accounted for as
follows:

----------------------------------------------------------------------------
Three Months Ended Period Ended
December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------
Earnings before income taxes 2,528 5,322 8,568 7,481

Expected income taxes at the statutory rate 872 2,002 2,955 2,814
Increase (decrease) resulting from:
Non-deductible Crown charges 88 535 499 869
Resource allowance (157) (561) (710) (872)
Stock-based compensation 92 128 546 399
Federal Large Corporation Tax - 77 (60) 94
Income tax rate reduction (213) (335) 595 (348)
Non-deductible amounts and other (38) 23 68 (1)
----------------------------------------------------------------------------
Income taxes 644 1,869 3,893 2,955
----------------------------------------------------------------------------

The major components of the future income tax asset are as follows:

----------------------------------------------------------------------------
As at As at
December December
31, 2006 31, 2005
----------------------------------------------------------------------------
Petroleum and natural gas interests less tax values 4,825 8,701
Asset retirement obligations 1,430 1,242
Share issue costs 791 508
Other 29 23
----------------------------------------------------------------------------
7,075 10,474
----------------------------------------------------------------------------


Pursuant to the flow-through share issuance completed in November 2006 the Company is committed to renounce $10.6 million of exploration costs to investors by December 2007. At December 31, 2006 $2.8 million of the obligation had been fulfilled, resulting in a deferred future tax liability of approximately $0.8 million. The costs were renounced to investors in February 2007 therefore, in accordance with current accounting standards the future tax liability will be recorded in the first quarter of 2007. The Company's capital budget for 2007 reflects the remaining commitment of $7.8 million.



11. Supplementary Information for Statement of Cash Flows

----------------------------------------------------------------------------
Three Months Ended Period Ended
Changes in non-cash working capital December 31 December 31
2006 2005 2006 2005
----------------------------------------------------------------------------
Accounts receivable (3,461) (5,351) 205 (8,745)
Accounts payable and accrued liabilities 2,601 14,970 (4,039) 19,771
----------------------------------------------------------------------------
Change in non-cash working capital
relating to: (860) 9,619 (3,834) 11,026
----------------------------------------------------------------------------
Operating activities (854) (1,277) (206) (859)
Investing activities (6) 10,896 (3,628) 11,885
----------------------------------------------------------------------------


12. Financial Instruments

Fair Value of Financial Instruments

The Company's exposure under its financial instruments is limited to financial assets and liabilities, all of which are included in these financial statements. The fair values of financial assets and liabilities that are included in the balance sheet approximate their carrying amounts.

Credit Risk

A substantial portion of the Company's accounts receivable are with customers in the energy industry and are subject to normal industry credit risk. The Company routinely assesses the financial strength of its customers.

Foreign Currency Exchange Risk

The Company is exposed to foreign currency fluctuations as crude oil and natural gas prices are referenced to U.S. dollar denominated prices.

Interest Rate Risk

The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest.

Commodity Price Contracts

The Company entered into several derivative financial instrument contracts in February 2007 for the purpose of managing its exposure to fluctuations in natural gas prices. The details of these contracts are as follows:



----------------------------------------------------------------------------
Contract Volume Pricing Price
Type (GJ/d) Point ($/GJ) Term
----------------------------------------------------------------------------
Fixed price 7,000 AECO 7.59 Mar-Jun 07
Collar 3,000 AECO 7.00 floor/8.75 ceiling Jul-Oct 07
Collar 4,000 AECO 7.00 floor/9.00 ceiling Jul-Oct 07
----------------------------------------------------------------------------

13. Commitments

The Company is committed to future minimum payments for natural gas
transportation contracts and office space. Payments required under these
commitments for each of the next five years are as follows:

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

Year 1 Year 2 Year 3 Year 4 Year 5
----------------------------------------------------------------------------
Office space (operating leases) 319 334 29 - -
Transportation 1,417 1,260 781 268 -
----------------------------------------------------------------------------
Total commitments 1,736 1,594 810 268 -
----------------------------------------------------------------------------


Board of Directors Officers

Brian K. Lemke David V. Elgie
Chairman President and Chief Executive Officer
Cordero Energy Inc.
Calgary, Alberta Richard Gleasure
Vice President, Engineering and
Donald P. Driscoll(1)(3) Chief Operating Officer
Corporate Director
Calgary, Alberta C. Dean Setoguchi
Vice President and Chief Financial
David V. Elgie Officer
President and Chief Executive
Officer Head Office
Cordero Energy Inc.
Calgary, Alberta 2400 Bow Valley Square 3
255 - 5(th) Avenue SW
S. Barry Jackson (2)(3) Calgary, Alberta T2P 3G6
Corporate Director Tel: (403) 265-7006
Calgary, Alberta Fax: (403) 265-7050
Email: info@corderoenergy.com
Douglas G. Manner (1)(2) Website: www.corderoenergy.com
President and Chief Executive
Officer Legal Counsel
Westside Energy Corporation
Dallas, Texas Parlee McLaws LLP
Calgary, AB
Robert R. Rooney (2)(3)
Corporate Director Banker
Calgary, Alberta
Canadian Imperial Bank of Commerce
Jeffrey T. Smith(1)(2)
Corporate Director Auditors
Calgary, Alberta
Deloitte & Touche LLP
Philip C. Swift(1)(3) Calgary, Alberta
Co-Chairman
ARC Financial Corporation Independent Reservoir Consultants
Calgary, Alberta
Sproule Associates Ltd.
Members of the following Calgary, Alberta
Committees:
(1) Audit and Finance Transfer Agent
(2) Technical
(3) Human Resources and Governance Valiant Trust Company
Calgary, Alberta

Stock Exchange Listing

Toronto Stock Exchange
Trading symbol: COR

Contact Information

  • Cordero Energy Inc.
    David V. Elgie
    President and Chief Executive Officer
    (403) 265-7006 or Toll Free: 1-888-266-6608
    or
    Cordero Energy Inc.
    C. Dean Setoguchi
    Vice President and Chief Financial Officer
    (403) 265-7006 or Toll Free: 1-888-266-6608
    Email: info@corderoenergy.com
    Website: www.corderoenergy.com