Orleans Energy Ltd.
TSX VENTURE : OEX

Orleans Energy Ltd.

April 11, 2007 18:13 ET

Orleans Energy Announces 2006 Financial Results, Year-End Reserves and New Bank Facility

CALGARY, ALBERTA--(CCNMatthews - April 11, 2007) - Orleans Energy Ltd. ("Orleans" or the "Company") (TSX VENTURE:OEX) is pleased to announce its results for the year ended December 31, 2006. Highlights of the Company's second year of operations as an active oil and gas company include:

- Simultaneous Corporate Acquisitions.

Significant expansion of the Company's undeveloped land, reserves, production and drilling inventory, via two concurrent private corporate acquisitions, adding approximately 1,200 barrels of oil equivalent ("boe") per day production, 4.62 million boe of conventional proved plus probable oil and gas reserves and more than 29,000 net acres of undeveloped land across five high working interest, operated properties.

- Strong "Drill Bit" Performance and Capital Efficiency.

Drilled 28 wells (20.8 net), on an exploration and development ("E&D") capital program of approximately $46 million, for an overall success rate of 82%. E&D capital investments resulted in a finding and development ("F&D") cost of $17.06 per proved plus probable boe (including future capital). Orleans' overall finding, development and acquisition ("FD&A") cost in 2006, including the corporate acquisitions, was $22.56 per proved plus probable boe (including future capital), with a re-investment recycle ratio of 1.4 times.

- Significant Year-over-Year Production and Reserves Growth.

Increased the Company's average daily production to 1,750 boe per day in 2006, a 76% increase from 995 boe per day in calendar 2005. Successfully executed its "acquire and exploit" strategy, expanding its corporate reserves life index from 7.5 to greater than 10 years and increasing both the Company's aggregate proved plus probable reserves from 3.77 million boe to 11.34 million boe and its proved plus probable reserves per outstanding common share from 0.25 to 0.34.

- Strong Revenue and Cash Flow Growth.

Generated petroleum and natural gas revenues of $32.5 million in 2006, an increase of 47% over calendar 2005. Cash flow from operations increased by 32% to $17.2 million, resulting in an operating netback of $31.06 per boe and a corporate cash flow netback of $26.96 per boe.

- Implemented a Strategic Commodity Hedging Program.

Initiated a strategic commodity hedging program, mitigating risks of precipitous commodity price declines and providing assurances of cash flow preservation for capital re-investment purposes.

- Increase in Bank Lines.

The Company recently entered a new credit agreement with a major Canadian chartered bank, providing for an increased $60 million operating credit facility, further enhancing Orleans' financial flexibility.



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Quarterly Comparison
Financial Highlights (1) Three Month Period Ended,
(6:1 oil equivalent Dec. 31, Sep. 30, Jun. 30, Mar. 31,
conversion) 2006 2006 2006 2006
------------ ----------- ------------ -----------
(amounts in Cdn.$ except
share data)
Petroleum and natural gas
revenue 11,039,154 9,776,954 5,911,434 5,719,679
Per share - basic 0.35 0.32 0.30 0.38
- diluted 0.34 0.31 0.29 0.36
Cash flow from operations
(2) 5,460,497 5,219,360 3,361,986 3,177,093
Per share - basic 0.17 0.17 0.17 0.21
- diluted 0.17 0.17 0.16 0.20
Operating netback (3)
($/boe) 30.23 29.81 32.78 33.32
Corporate netback (3)
($/boe) 24.94 26.02 29.00 30.78
Net earnings / (loss)
(4,6) (17,005,919) (127,759) (1,345,606) 641,718
Per share - basic (0.53) - (0.07) 0.04
- diluted (0.52) - (0.07) 0.04
Net debt (5)- period end 43,225,843 47,756,144 36,218,786 9,085,857
Weighted average basic
shares 31,890,833 30,498,276 19,708,637 15,099,047
Weighted average diluted
shares 32,533,845 31,293,929 20,759,015 16,047,634
Issued and outstanding
shares 33,148,659 30,518,659 30,459,493 15,099,047
Operating Highlights (1)
Average daily production:
Natural gas (mcf/d) 9,428 8,349 4,334 3,426
Liquids (Oil & NGLs)
(bbls/d) 809 789 552 576
Oil equivalent (boe/d) 2,380 2,181 1,274 1,147
Average sales price (net
hedging):
Natural gas ($/mcf) 7.57 6.04 6.34 8.29
Liquids (Oil & NGLs)
($/bbl) 60.10 70.81 67.91 61.06
Oil equivalent ($/boe) 50.41 48.73 50.99 55.41
E&D capital expenditures
($) 14,792,334 16,449,174 8,701,972 6,312,666
Total capital
expenditures ($) 15,828,031 16,782,550 119,462,351 7,649,826
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Calendar Calendar
Financial Highlights (1) Year Year
(6:1 oil equivalent conversion) 2006 2005
------------ ------------
(amounts in Cdn.$ except share data)
Petroleum and natural gas revenue 32,447,221 22,011,250
Per share - basic 1.33 1.56
- diluted 1.29 1.48
Cash flow from operations (2) 17,218,936 13,060,399
Per share - basic 0.71 0.92
- diluted 0.69 0.88
Operating netback (3) ($/boe) 31.06 38.86
Corporate netback (3) ($/boe) 26.96 35.96
Net earnings / (loss) (4,6) (17,837,566) 19,534,922
Per share - basic (0.73) 1.38
- diluted (0.71) 1.32
Net debt (5)- period end 43,225,843 4,613,124
Weighted average basic shares 24,362,187 14,145,451
Weighted average diluted shares 25,136,494 14,836,572
Issued and outstanding shares 33,148,659 15,099,047
Operating Highlights (1)
Average daily production:
Natural gas (mcf/d) 6,406 2,804
Liquids (Oil & NGLs) (bbls/d) 682 528
Oil equivalent (boe/d) 1,750 995
Average sales price (net hedging):
Natural gas ($/mcf) 6.95 9.75
Liquids (Oil & NGLs) ($/bbl) 65.00 62.44
Oil equivalent ($/boe) 50.80 60.60
E&D capital expenditures ($) 46,256,146 19,582,151
Total capital expenditures ($) 159,722,758 24,622,251
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Notes:
------
(1) Orleans' 2006 financial and operating results for the calendar year
ended December 31, 2006 includes the operating activities associated
with the acquisitions of: (i) Mercury Energy Corporation from June 2,
2006 onwards and (ii) Morpheus Energy Corporation from June 6, 2006
onwards.
(2) Cash flow from operations does not have any standardized meaning
prescribed by Canadian generally accepted accounting principles
("GAAP"). Please refer to the enclosed MD&A for definition of cash flow
from operations.
(3) Operating netback represents average sales price less royalties,
operating costs and transportation expenses. Corporate netback
represents Operating netback less general and administrative costs and
net interest expense. Both measures are not recognized measures under
Canadian GAAP.
(4) Net earnings / (loss) includes: (i) non-cash income tax reductions or
recoveries and (ii) non-cash goodwill impairment.
(5) Net debt refers to outstanding bank debt plus any working capital
deficit or minus any working capital surplus (excluding any non-cash
current income tax asset). Net debt is not a recognized measure under
Canadian GAAP.
(6) The reported net loss in Calendar Year 2006 reflects a $16.62 million
non-cash goodwill impairment. This goodwill resulted from the
acquisition of Morpheus Energy Corporation, whereby Orleans' shares
issued as part of the acquisition consideration were valued at $5.90 per
share, as compared to the Company's year-end 2006 closing market price
of $3.45 per share.


Operations Update

As previously disclosed, in June 2006, Orleans acquired two private oil and gas companies, Morpheus Energy Corporation and Mercury Energy Corporation, for an aggregate capital investment of approximately of $111 million. Both corporation acquisitions provided Orleans with strategic assets within the Company's existing growth and focus areas in addition to providing Orleans with valuable undeveloped assets on the Peace River Arch. Orleans increased its focus areas from two to six, all of which are Company-operated and are characterized as multi-zone, year-round access with relatively low-to-moderate risk drilling opportunities, with production processed through either Orleans' operated infrastructure or underutilized, third party mid-stream processors.

In 2006, the Company drilled or participated in the drilling of 28 wells (20.8 net), resulting in 17 gas wells, six oil wells, one standing well and four dry holes for an overall success rate of 82%. Since closing the aforementioned corporate acquisitions in June 2006, the Company embarked on an aggressive and strategic drilling program for the balance of the year, drilling 18 wells (14.6 net) across all six of Orleans' properties at a 78% success rate, successfully "proving-up" and delineating several promising prospects.

Central Alberta

At Halkirk, in 2006, Orleans drilled 10 wells (6.0 net), targeting a number of horizons, including Horseshoe Canyon Coals, Ellerslie gas and Mannville oil zones. Orleans has also developed a significant inventory of drill locations, with potential for Mannville Coal Bed Methane, which the Company expects to drill in a stronger gas price environment.

At Leo, Orleans drilled a horizontal oil well (100% working interest) in the Upper Mannville D&E oil pool in the fourth quarter. Independent engineering estimates indicate up to 9.2 million barrels of light oil-in-place (36 degree API) with only approximately four hundred thousand barrels or 4% recovered to-date. Hydrocarbon recoveries from nearby analogous pools under waterflood range from 15 to 50%. In 2007, the Company plans to drill up to four horizontal wells of a total eight well program.

At Gilby, in 2006, the Company successfully drilled four gas wells (2.2 net), targeting the Edmonton sands and Horseshoe Canyon Coals. Orleans intends to drill three Edmonton Sand gas wells on primary spacing in 2007. Over 30 Edmonton sand infill locations have been identified and are waiting on down-spacing approval to four wells per section, anticipated for the third quarter of 2007.

At Pembina, the Company drilled a Belly River gas well (100% working interest) in December 2006. The well was recently completed with favourable results and is awaiting tie-in to nearby processing facilities following spring break-up.

West Central Alberta

At Pine Creek, in the latter half of 2006, the Company successfully drilled and brought on-stream four (4.0 net) multi-zone gas wells and has established a significant drilling inventory of 15 to 20 wells based upon reduced spacing to four wells per section. Pine Creek is truly a multi-zone, long reserve life, liquids rich, sweet natural gas property where Orleans holds 7.75 sections (6.75 net) of operated lands with diverse mineral rights generally to the base of the Cretaceous. Orleans has received reduced spacing to four wells per section across the majority of its lands in the area. In 2007, Orleans initially intends to drill two gas wells (0.75 net), targeting multiple horizons.

At Kaybob, the Company successfully commenced drilling operations in a 100% working interest Triassic Montney gas well on December 28, 2006. To-date, Orleans has successfully drilled three wells (2.7 net), with two wells (2.0 net) currently producing and one well (0.7 net) awaiting tie-in following spring break-up. Orleans has amassed 12 sections (9.9 net) of land within this liquids-rich gas prone fairway and has developed a 15 to 20 well drilling inventory. The Company recently received approval to drill, on reduced spacing, three wells per section across the majority of its lands in Kaybob.

Peace River Arch

At Gordondale, Orleans is developing a light gravity crude oil prospect in the Boundary Lake horizon. Orleans has amassed 20.5 sections (11.5 net) of contiguous Company-operated lands with rights generally to the base of Triassic. In the third quarter of 2006, Orleans drilled three oil wells (2.0 net) and completed an additional suspended gas well for production from the Boundary Lake. In the fourth quarter the Company brought on-stream five wells (3.0 net) to a newly constructed gathering system and modified Company-operated oil battery. Orleans has drilled two successful wells (1.5 net) in the first quarter of 2007 and plans to drill an additional five to seven wells in 2007 to further delineate this oil pool. Three of Orleans' wells are awaiting GPP ("Good Production Practice") approval and are currently restricted to Energy Utilities Board ("EUB") allowables. The Company anticipates receiving this approval within the first half of 2007.

At Grimshaw, the Company has 16 sections (12.6 net) of land with rights generally to the base of Bluesky Bullhead. In 2006, Orleans drilled three wells (2.5 net), with one well being placed on-stream in the fourth quarter and an additional well brought on-stream in the first quarter of 2007.

In this current period of volatile and uncertain commodity prices, the Company has prudently initiated a systematic commodity hedging strategy, as outlined in the Company's MD&A contained within this news release under the section "Petroleum and Natural Gas Revenue and Commodity Pricing". Orleans believes these hedges, primarily a combination of short-term fixed physical price arrangements, swaps and costless collars, assist in mitigating the risk of commodity price decline and facilitates the preservation of the Company's cash flow required for re-investment into its diverse capital projects.

The Company is extremely optimistic about the "value creation" potential 2007 holds for the shareholders of Orleans, as it is confident that the Company's actions in 2006 have firmly established operational momentum, as evidenced by Orleans' initial 2007 capital program, which is demonstrating solid results and increasing potential. The Company is adding to its professional, technical and geosciences staff in order to ensure that this established momentum continues.

Oil and Gas Reserves

The following tables provide information on Orleans' crude oil and natural gas reserves as of December 31, 2006, as evaluated by the Company's independent reserve engineering firm, Sproule Associates Limited ("Sproule"). The evaluation of the Company's petroleum and natural gas reserves was conducted pursuant to National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and was reviewed and approved by Orleans' Board of Directors. The Company's production profile is supported by a high-quality reserves base, weighted 66% natural gas and 34% light crude oil and natural gas liquids, with a reserve life index exceeding 10 years (proved plus probable).



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December 31, 2006 Reserves Summary (Company interest before royalties)

(per Sproule's December 31, Crude Oil
2006 escalated price forecast) Natural Gas Oil & Ngls Equivalent
------------- ------------ ------------
(Bcf) (Mbbls) (Mboe)(6:1)
Proved developed producing 16.567 1,437.1 4,198.3
Proved developed non-producing 1.666 54.4 332.1
Proved undeveloped 6.990 585.0 1,750.0
------------- ------------ ------------
Total Proved 25.223 2,076.5 6,280.4
Probable 19.736 1,803.5 5,093.0
------------- ------------ ------------
Total Proved plus Probable 44.959 3,880.0 11,373.4
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December 31, 2006 Net Present Values Summary (Company interest before
royalties)

(per Sproule's December 31, Present value of cash
2006 escalated price forecast) flows before-tax ($000s)
(amounts in $000s) 0% 8% 10% 15%
---------- ---------- ---------- ----------
Proved developed producing $ 126,186 $ 97,420 $ 92,638 $ 82,974
Proved developed non-producing 7,687 5,732 5,374 4,632
Proved undeveloped 34,470 20,246 17,999 13,621
---------- ---------- ---------- ----------
Total Proved 168,343 123,398 116,011 101,227
Probable 151,189 75,218 66,021 49,792
---------- ---------- ---------- ----------
Total Proved plus Probable $ 319,532 $ 198,616 $ 182,032 $ 151,019
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Capital Efficiency

The following tables highlight the efficiency of Orleans' capital
expenditures during the calendar year ended December 31, 2006.

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Finding & Development Costs ("F&D") - excluding effect of acquisitions

Calendar Year 2006
--------------------
(amounts in $000s except reserve
units and unit costs) Proved Proved + Probable
------------ -------------------
Capital expenditures (1) $ 47,726 $ 47,726
Future capital - December 31, 2006 (2) 14,683 22,253
Future capital - December 31, 2005 (2) (5,014) (8,184)
------------ -------------------
All-in total, including change
in future capital $ 57,395 $ 61,795
Total reserve additions (mboe) 2,266.7 3,621.6
F&D Cost ($/boe) $ 25.32 $ 17.06

Notes:
------
(1) Includes E&D capital expenditures in addition to $1.47 million related
to capitalized G&A, capitalized non-cash stock-based compensation and
office equipment.
(2) Future capital expenditures required to convert proved and probable
reserves to proved producing.
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Finding, Development & Acquisitions Costs ("FD&A") - including effect of
acquisitions

Calendar Year 2006
--------------------
(amounts in $000s except reserve
units and unit costs) Proved Proved + Probable
------------ -------------------
Total capital expenditures $ 159,722 $ 159,722
Future capital - December 31, 2006 (1) 22,277 34,328
Future capital - December 31, 2005 (1) (5,014) (8,184)
------------ -------------------
All-in total, including change in
future capital $ 176,985 $ 185,866
Total reserve additions (mboe) 4,989.7 8,239.6
FD&A Cost ($/boe) $ 35.47 $ 22.56

Notes:
------
(1) Future capital expenditures required to convert proved and probable
reserves to proved producing.
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Production Replacement Calendar Year
2006
------
Total reserve additions (proved plus probable) (mboe) 8,239.6
Total production (mboe) 638.8
Production Replacement 12.9
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Reinvestment Recycle Ratio Calendar Year
2006
------
Operating netback ($ per boe) $ 31.06
FD&A all-in cost ($ per proved plus probable boe) $ 22.56
Recycle Ratio 1.4
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Net Asset Value

Orleans' intrinsic value at year-end 2006, as measured by the Company's net
asset value, is as follows:

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December 31, 2006 NPV 8% NPV 10%
------- --------
(per share figures based on
fully-diluted shares) ($000s) $/share ($000s) $/share
----------- ---------- ---------- ----------
Proved plus probable
reserves (1,2) $ 198,616 $ 5.54 $ 182,032 $ 5.08
Undeveloped acreage (3) 13,000 0.36 13,000 0.36
Net debt (4) (43,226) (1.21) (43,226) (1.21)
Seismic (5) 2,859 0.08 2,859 0.08
Proceeds from stock options 9,176 0.26 9,176 0.26
----------- ---------- ---------- ----------
Net Asset Value (fully-diluted) $ 180,425 $ 5.03 $ 163,841 $ 4.57

Notes:
------
(1) Reserves independently evaluated by Sproule Associated Limited
("Sproule") as at December 31, 2006.
(2) Net present values ("NPV") are before tax and based on Sproule's
December 31, 2006 escalated price forecast.
(3) Internally evaluated.
(4) Net debt as at December 31, 2006, including working capital deficit.
(5) Internally estimated market value of proprietary seismic only.
(6) Fully-diluted shares at December 31, 2006 total 35,847,398, including
outstanding shares of 33,148,659 and 2,698,739 stock options.
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New Bank Lending Facility

Orleans is pleased to announce that it has entered into an increased $60 million credit agreement with BMO Capital Markets, which will further enhance the Company's financial flexibility, as compared to the previous credit facility of $53 million in-place with another financial institution. The Company would like to take this opportunity to acknowledge and extend appreciation to its predecessor financial institution, ATB Financial, for their valued service contributions provided during Orleans' initial start-up and development phase as an active oil and gas company.

Annual General Meeting of Shareholders

The Company plans to hold its annual meeting of shareholders on Wednesday, June 6, 2007 at 3:00 p.m. in the Cardium Room of the Calgary Petroleum Club located at 319 - 5th Avenue S.W., Calgary, Alberta, Canada.

Head Office Address Change

In order to accommodate the expanded office operations necessary to effectively and efficiently manage the Company's larger asset base, effective April 1, 2007, Orleans moved its Calgary head office location to: Altius Centre, Suite 1200, 500 - 4th Avenue S.W., Calgary, Alberta, T2P 2V6.

Management's Discussion & Analysis ("MD&A")

The following discussion is intended to assist the reader in understanding the business and results of operations and financial condition of Orleans Energy Ltd. (the "Company" or "Orleans"). This MD&A should be read in conjunction with the consolidated financial statements for the fiscal twelve-month period ended December 31, 2006 and the financial statements for the prior fiscal nine-month period ended December 31, 2005, available in printed form on request.

Orleans Energy Ltd. is a Calgary, Alberta-based crude oil and natural gas company. Orleans is incorporated under the laws of Alberta and its common shares are publicly listed and traded on the TSX Venture Exchange under the trading symbol "OEX". On April 11, 2005, the Company filed notice under National Instrument 51-102 stating the Company's intention to change the date of its fiscal reporting year-end to December 31 from March 31, with the next year-end occurring December 31, 2005. This change was effected in order to have a year-end consistent with that of other companies in the oil and gas industry. As such, within this MD&A, the financial and operating results for the fiscal twelve-month period ended December 31, 2006 ("Fiscal 2006") is compared to the prior fiscal nine-month period ended December 31, 2005 ("Fiscal 2005").

In this MD&A, production data is commonly stated in barrels of oil equivalent ("boe") using a six (6) to one (1) conversion ratio when converting thousands of cubic feet of natural gas ("mcf") to barrels of oil ("bbl") and a one-to-one conversion ratio for natural gas liquids ("NGLs" or "ngls"). Such conversion may be misleading, particularly if used in isolation. A boe conversion ratio of six (6) mcf: one (1) bbl is based on energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

As an indicator of the Company's performance, the term cash flow from operations or operating cash flow contained within the MD&A should not be considered as an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with Canadian generally accepted accounting principles ("GAAP"). This term does not have a standardized meaning under GAAP and may not be comparable to other companies. Orleans believes that cash flow from operations is a useful supplementary measure as investors may use this information to analyze operating performance, leverage and liquidity. Cash flow from operations, as disclosed within this MD&A, represents cash flow from operating activities before any asset retirement obligation cash expenditures and is expressed before changes in non-cash working capital. The Company presents cash flow from operations per share whereby per share amounts are calculated consistent with the calculation of earnings per share. Please refer to the table, Reconciliation of Non-GAAP Measures, contained within this MD&A.

Certain information regarding the Company contained herein may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking statements may include estimates, plans, expectations, opinions, forecasts, projections, anticipates, guidance or other similar statements that are not statements of fact. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. These statements are subject to certain risks and uncertainties and may be based on assumptions that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The Company's forward-looking statements are expressly qualified in their entirety by this cautionary statement.

For additional information relating to Orleans, please refer to other filings as filed on SEDAR at www.sedar.com. All amounts are reported in Canadian dollars, unless otherwise stated. This MD&A includes information up to and including April 11, 2007.

Corporate Overview

Orleans is actively engaged in the exploration for, development and production of natural gas, crude oil and natural gas liquids reserves within the province of Alberta. As of April 10, 2007, Orleans' market capitalization is approximately $127 million. Current production is weighted approximately 70% natural gas and 30% light oil and NGLs. As a result of the two corporate acquisitions, which closed in early June 2006 and described hereafter, Orleans has substantially increased its inventory of drilling opportunities in Alberta. The Company's production base is generated from six principal producing areas throughout Central Alberta (Gilby and Halkirk/Leo), West Central Alberta (Pine Creek and Kaybob) and the Peace River Arch (Gordondale and Grimshaw). Orleans' asset base possesses all the prerequisites for a solid growth platform including: (i) an extensive, operated drilling inventory providing exposure to both light oil and natural gas prospects within a West Central Alberta geographic corridor, (ii) access to approximately 75,000 acres of high working interest (80%) undeveloped acreage offering geologic play diversity, (iii) a long-life, proved plus probable reserves base at year-end 2006 of approximately 11.4 million barrels of oil equivalent with a reserve life index exceeding 10 years and (iv) an operated production base allowing for year-round access across six producing areas exclusively within the province of Alberta.

Significant Acquisitions

On June 2, 2006 the Company acquired all of the issued and outstanding shares of Mercury Energy Corporation ("Mercury"), a private oil and gas company. Total consideration paid by Orleans for the Mercury shares included 1,623,719 of Orleans' common shares and $9.835 million cash. This business combination has been accounted for using the purchase method with the results of Mercury's operations included in Orleans' financials results June 2, 2006 thereafter.

Additionally, on June 6, 2006 the Company acquired all of the issued and outstanding shares of Morpheus Energy Corporation ("Morpheus"), a private oil and gas company. Total consideration paid by Orleans for the Morpheus shares included 7,351,727 of Orleans' common shares and $29.203 million cash. The cash consideration component was funded through the net proceeds of the Company's previously disclosed $38.065 million bought-deal private placement financing which closed on April 27, 2006. This business combination has been accounted for using the purchase method with the results of Morpheus' operations included in Orleans' financials results June 6, 2006 thereafter.



Selected Period End and Quarterly Financial Information

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2006 Quarterly Comparison
--------------------------------
Twelve Nine Month
Cal Cal Cal Cal Months Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------
Petroleum &
natural gas
revenue 11,038 9,777 5,912 5,720 32,447 19,415
Cash flow from
operations 5,461 5,219 3,362 3,177 17,219 11,757
Net earnings /
(loss) (17,006) (128) (1,346) 642 (17,838) 19,466
Total assets -
period end 188,325 192,609 180,598 55,109 188,325 50,684
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2005 Quarterly Comparison
-----------------------------------------
Cal Cal Cal Cal
($000s) Q405 Q305 Q205 Q105
-------- -------- -------- --------

Petroleum & natural gas revenue 8,453 6,980 3,982 2,596
Cash flow from operations 4,973 4,442 2,342 1,304
Net earnings 16,203 2,406 856 69
Total assets - period end 50,684 32,196 28,795 24,216
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The following commentary will assist in providing the reader with factors that have caused variations over the aforementioned quarterly, annual and period-end results.

Petroleum and Natural Gas Production

For the year ended December 31, 2006, the Company's natural gas production averaged 6,406 mcf per day and crude oil and NGLs production averaged 682 bbls per day, resulting in a combined oil equivalent average daily rate of 1,750 boe per day. The execution of its "acquire and exploit" strategy enabled the Company to increase its average daily production in Fiscal 2006 by 76% over the 995 boe per day generated in the calendar twelve month period ended December 31, 2005. Successful development drilling of numerous geologic horizons, in conjunction with the strategic acquisitions of both Morpheus and Mercury, enabled Orleans to significantly expand its oil and gas production throughout 2006. In 2006, the Company drilled or participated in the drilling of 28 wells (20.6 net), resulting in 17 gas wells, six oil wells, one standing well and four dry holes for an overall success rate of 82%.

During the quarterly three month period ended December 31, 2006 ("Cal Q406"), Orleans' average daily oil equivalent production was 2,380 boe per day, weighted 66% towards natural gas and 34% percent light gravity crude oil (33 degree API) and NGLs. On an oil-equivalent basis, Orleans' crude oil and natural gas sales volumes increased by 9% as compared to the preceding third quarter ended September 30, 2006. The Company's natural gas sales for Cal Q406 averaged 9,428 mcf per day and crude oil and NGLs production averaged 809 bbls per day.



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Average Daily Production
---------------------------------------------------
Natural Gas Crude Oil & NGLs Oil Equivalent
------------- ------------------ ----------------
(mcf/d) (bbls/d) (boe/d)

Cal Q105 1,404 325 559
Cal Q205 2,385 435 832
Cal Q305 3,231 662 1,200
Cal Q405 4,160 685 1,378
Cal Q106 3,426 576 1,147
Cal Q206 4,334 552 1,274
Cal Q306 8,349 789 2,181
Cal Q406 9,428 809 2,380

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Fiscal 2006 6,406 682 1,750
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Petroleum and Natural Gas Revenue and Commodity Pricing

Orleans' commodity prices are driven by the prevailing worldwide price for crude oil, spot prices applicable to its natural gas production, and many other factors beyond the Company's control. Historically, these prices have been volatile and unpredictable, and 2006 was no exception. The Company's Fiscal 2006 crude oil price realizations averaged $66.65 per barrel, an increase of 3% from the Fiscal 2005 oil price of $64.56 per barrel, ranging from an average monthly low of $58.52 per barrel in February 2006 to a high of $76.76 per barrel in July 2006. Orleans' natural gas price realizations were 31% lower in 2006 than the previous year, averaging $6.95 per mcf, with a high of $9.41 per mcf in January 2006 and a low of $5.01 per mcf in September 2006.

As a result of significant production growth, notwithstanding a substantial decrease in realized natural gas prices in 2006, Orleans' aggregate petroleum and natural gas revenue for year ended December 31, 2006 amounted to $32.5 million. Strong revenue realization was also achieved in Cal Q406, which amounted to $11.0 million, representing a 13% increase from the preceding third quarter of 2006.



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2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------
Crude oil & NGLs
revenue 4,472 5,141 3,410 3,165 16,188 10,410
Natural gas
revenue 6,566 4,636 2,502 2,555 16,259 9,005
------- ------- ------- ----- ------------ ------------
Gross revenue 11,038 9,777 5,912 5,720 32,447 19,415
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The prices Orleans receives for its oil and natural gas production may have a significant impact on its revenues and operating cash flows. While significant price declines in 2007 would adversely affect the amount of cash flow generated from operations, the Company utilizes a hedging program to partially mitigate that risk and facilitate the generation of more predictable cash flows to fund its capital expenditures. As such, from time to time, the Company may employ derivative financial instruments and physical arrangements, primarily commodity price hedges, to manage fluctuations in oil and gas market prices. Orleans may use fixed physical price arrangements, futures contracts, swaps, and collars, which are generally put in-place with investment grade counter-parties that the Company believes present minimal credit risks. Orleans' hedge arrangements are not held for trading purposes. Gains and losses related to its hedge contracts are deferred and recognized in product revenues upon sale of the related hedged production.

The following table outlines the financial hedge agreements that were outstanding during the year ended December 31, 2006. The aggregate fair value the financial hedge agreements that were outstanding as at December 31, 2006 was an unrealized gain of approximately C$ 606 thousand.



----------------------------------------------------------------------------
Daily
Notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Jul '06 - US$ 73.62
Crude Oil Jun. 9, 2006 Swap Dec '06 125 bbls W.T.I. /bbl
Aug '06 - US$ 77.25
Crude Oil Jul. 6, 2006 Swap Jul '07 125 bbls W.T.I. /bbl
Nov '06 - C$ 6.50 -
NatGas Oct. 17, 2006 Collar Mar '07 2,000 GJs AECO-C 8.50 /GJ
Dec '06 - C$ 7.00 -
NatGas Nov. 9, 2006 Collar Mar '07 2,000 GJs AECO-C 8.75 /GJ
----------------------------------------------------------------------------


Subsequent to December 31, 2006, the Company has entered into the following
financial hedge agreements:

----------------------------------------------------------------------------
Daily
Notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Feb '07 - C$ 6.50 -
NatGas Jan. 23, 2007 Collar Dec '07 1,000 GJs AECO-C 9.08 /GJ
Apr '07 - C$ 6.50 -
NatGas Jan. 23, 2007 Collar Oct '07 1,000 GJs AECO-C 8.52 /GJ
Apr '07 - C$ 7.00 -
NatGas Jan. 31, 2007 Collar Dec '07 1,000 GJs AECO-C 9.00 /GJ
Apr '07 - C$ 7.00 -
NatGas Feb. 5, 2007 Collar Dec '07 1,000 GJs AECO-C 9.08 /GJ
Apr '07 -
NatGas Feb. 22, 2007 Swap Oct '07 1,000 GJs AECO-C C$ 7.70 /GJ
Apr '07 - US$ 59.30 -
Crude Oil Mar. 26, 2007 Collar Dec '07 150 bbls W.T.I. 70.00/bbl
----------------------------------------------------------------------------


The following table highlights Orleans' corporate realized commodity prices
as well as benchmark market prices:

----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------
Orleans' prices
(net of hedging):
Natural gas
($/mcf) 7.57 6.04 6.34 8.29 6.95 10.04
Crude oil and
NGLs ($/bbl) 60.10 70.81 67.91 61.06 65.00 63.70
Oil equivalent
($/boe) 50.41 48.73 50.99 55.41 50.80 62.04
Industry benchmark
prices:
WTI Cushing oil
(US$/bbl) 59.96 70.48 70.51 63.34 66.09 58.85
Edmonton Par oil
($/bbl) 64.94 79.69 79.06 69.25 73.25 71.38
Nymex gas
(US$/mmbtu) 7.24 6.18 6.65 7.66 6.98 9.85
AECO gas ($/mcf) 6.04 5.58 5.87 7.45 6.38 9.39
----------------------------------------------------------------------------


Petroleum and Natural Gas Royalties

The Company's petroleum and natural gas royalties for the year ended December 31, 2006 amounted to $5.72 million, resulting in a corporate effective royalty rate of 18%. Approximately 54% of the Company's total royalties for Fiscal 2006 relate to Crown royalties with the residual 46% pertaining to freehold and overriding royalty encumbrances. The royalty rate in Fiscal 2006 was marginally lower than the rate realized in Fiscal 2005 due to the recognized Alberta Royalty Tax Credit ("ARTC") recovery on Crown royalties associated with production from wells that the Company drilled and brought on-stream throughout 2006 and the 2006 drilled Pine Creek gas wells which are currently exempt from Crown royalties due to their deep gas Crown royalty holiday status. During Cal Q406, total royalties amounted to $1.85 million, a 10% increase from the third quarter of 2006.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Crown (net ARTC) 1,067 815 564 660 3,106 2,183
Freehold and
overrides 782 873 419 544 2,618 1,781
------- ------- ------- ----- ------------ ------------
Total 1,849 1,688 983 1,204 5,724 3,964
------- ------- ------- ----- ------------ ------------
------- ------- ------- ----- ------------ ------------

Corporate royalty
rate (%) 17% 17% 17% 21% 18% 20%
----------------------------------------------------------------------------


Operating Expenses

Orleans' field operating expenses, on an oil-equivalent per unit basis, are generally impacted by the level of well-bore maintenance activity, geographic location of the Company's properties, whether oil and gas is produced, and the underlying commodity price levels. Commodity prices directly affect operating cost elements such as power, fuel and chemicals. The remaining primary elements, which include among other things, field labour, services and equipment, are indirectly impacted by high price environments, which drive up activity and demand and therefore, increase costs. All components of operating expenses have been increasing throughout the oil and gas industry for several years in concert with historically strong commodity prices, and 2006 was not immune to this inflationary trend.

The Company's aggregate field operating expenditures for the year ended December 31, 2006 amounted to $6.31 million or $9.89 on an oil-equivalent per unit basis. During Cal Q406, Orleans' field costs amounted to $2.35 million or $10.74 on an oil-equivalent per unit basis. Orleans continues to operate a majority of its production, thus enabling the Company to better manage the timing, level and scope of certain components of its operating cost profile.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Total ($000s) 2,351 1,970 1,025 970 6,316 2,519
Per unit ($/boe) 10.74 9.82 8.84 9.39 9.89 8.05
----------------------------------------------------------------------------


Transportation Expenses

The cost of transporting and distributing Orleans' crude oil and natural gas production to market delivery points during the year ended December 31, 2006 amounted to $568 thousand or $0.89 on an oil-equivalent per unit basis. In Cal Q406, transportation expenses amounted to $221 thousand or $1.00 on a unit-of-production basis. Increased production volumes, supplemented with increased clean oil trucking rates and Nova gas pipeline fuel surcharges throughout 2006 resulted in transportation cost increases on an aggregate.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Total ($000s) 221 138 103 106 568 325
Per unit ($/boe) 1.00 0.69 0.89 1.03 0.89 1.04
----------------------------------------------------------------------------


General & Administrative Expenses

The Company's general and administrative ("G&A") expenses during the year ended December 31, 2006, excluding the non-cash stock-based compensation provision, amounted to $1.39 million or $2.18 on an oil-equivalent per unit basis. In Cal Q406, expensed G&A amounted to $522 thousand, as compared to $329 thousand incurred in the third quarter of 2006. Gross G&A, net of operator recoveries, increased by $233 thousand in Cal Q406 over the third quarter as a result of year-end performance bonuses disbursed to employees and accruals for costs associated with the year-end independent engineering reserves report and the annual financial statement accounting audit. Orleans presently employs 11 head office personnel, including six geological and engineering technical personnel, and anticipates employing in the very near future an additional two senior technical personnel (geologist and exploitation engineer). The Company also engages the services of five consultants on a part-time, as needed, basis.

The Company applies the full cost method of accounting for its oil and gas operations. Accordingly, it capitalized employee G&A and associated direct overhead costs of its technical personnel in the amount of $623 thousand during the year ended December 31, 2006. In Cal Q406, capitalized G&A amounted to $176 thousand.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Gross, net operator
recoveries 698 464 499 352 2,013 1,336
Capitalized (176) (135) (172) (140) (623) (521)
------- ------- ------- ----- ------------ ------------
Expensed 522 329 327 212 1,390 815
------- ------- ------- ----- ------------ ------------
Per unit ($/boe) 2.38 1.64 2.82 2.06 2.18 2.60
------- ------- ------- ----- ------------ ------------
------- ------- ------- ----- ------------ ------------
% Capitalized 25% 29% 34% 40% 31% 39%
----------------------------------------------------------------------------


Stock-Based Compensation

Orleans utilizes the fair value method for measuring stock-based compensation expenses. The Company's stock-based compensation relates entirely to the granting of stock options. During the year ended December 31, 2006, the Company recorded non-cash stock-based compensation expense of $556 thousand, as compared to $369 thousand recognized in the fiscal period ended December 31, 2005. These provisions were recognized primarily in connection with the amortization of stock options granted in prior periods. In 2006, the Company capitalized $501 thousand of its stock-based compensation charges and in Fiscal 2005 no stock-based compensation was capitalized.

Interest Charges

In the year ended December 31, 2006, Orleans incurred $1.23 million in interest charges relating to its outstanding bank indebtedness, net of $155 thousand of interest income. As at December 31, 2006, the Company had $38.8 million of bank debt, as compared to $0.72 million of outstanding bank indebtedness at December 31, 2005. Orleans' bank debt increased in 2006 primarily as a result of the bank indebtedness assumed through the acquisitions of both Morpheus and Mercury and exploration and development capital investments in excess of Fiscal 2006 operating cash flow. For Cal Q406, bank debt servicing charges amounted to $637 thousand or $2.91 per boe.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Interest charges
(net interest
income) 637 433 111 50 1,231 37
----------------------------------------------------------------------------


Depletion, Depreciation and Accretion

Orleans' depletion and depreciation expense for the year and three month periods ended December 31, 2006 amounted to $16.63 million and $6.38 million, respectively. On a unit-of-production rate basis, the depletion and depreciation provision for year ended December 31, 2006 was $26.04 per boe, as compared to the $17.25 per boe provision recognized for the nine month fiscal year ended December 31, 2005. The relatively higher cost of acquiring the proved reserves of both Morpheus and Mercury resulted in a higher depletion and depreciation rate in Fiscal 2006 as compared to Fiscal 2005.

The Company's accretion expense relating to its asset retirement obligations ("ARO") amounted to $353 thousand for the year ended December 31, 2006 and $118 thousand for Cal Q406.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------
Depletion &
depreciation 6,376 4,841 3,553 1,863 16,633 5,398
ARO accretion 117 105 73 58 353 159
------- ------- ------- ----- ------------ ------------
Total 6,493 4,946 3,626 1,921 16,986 5,557
------- ------- ------- ----- ------------ ------------
------- ------- ------- ----- ------------ ------------
Per unit ($/boe) 29.65 24.65 31.28 18.61 26.59 17.76
----------------------------------------------------------------------------


Income Taxes

Orleans follows the liability method of accounting for income taxes whereby future income taxes are calculated based on temporary differences arising from the variance between the tax basis of an asset or liability and its property, plant and equipment carrying value. For the year ended December 31, 2006, the Company recorded a future income tax expense of $895 thousand, as compared to a $13.64 million income tax reduction recognized in the fiscal nine month period ended December 31, 2005. As at December 31, 2005, the Company evaluated the criteria relating to the recognition of the previously unrecognized future income tax asset and concluded that the realization of such assets in future periods is more likely than not.

During the year ended December 31, 2006, the Company was not subject to any corporate income tax due to the Company's significant tax pool balances, which aggregate to approximately $173 million. As a result of Orleans' sizeable tax pool position, the Company does not expect to be subject to corporate cash income tax in the foreseeable future. Additionally, during the year ended December 31, 2006, the Company was not liable for the payment of the large corporation capital tax as this tax was retroactively eliminated at January 1, 2006 by the Federal government.



The following table outlines Orleans' tax pools as at December 31, 2006:

----------------------------------------------------------------------------
Access Rate Balance
------------- ------------
($ millions)
Canadian exploration expense (CEE) 100% $ 19.59
Canadian development expense (CDE) 30% 53.94
Canadian oil and gas property expense (COGPE) 10% 31.29
Undepreciated capital cost (UCC) 25% 34.16
Non-capital losses (NCL) 100% 27.74
Share issue costs and other 20% 6.20
----------------------------------------------------------------------------
Total $ 172.92
----------------------------------------------------------------------------


Reconciliation of Non-GAAP Measures

----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
($000s except Cal Cal Cal Cal Period Ended Period Ended
share data) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Net earnings
(loss) (17,006) (128) (1,346) 642 (17,838) 19,466
Non-cash items:
Depletion &
Depreciation 6,376 4,841 3,553 1,863 16,633 5,398
ARO accretion 117 105 73 58 353 159
Stock-based
compensation (139) 364 202 128 555 369
Future income
taxes (507) 37 879 486 895 (13,635)
Goodwill
impairment 16,620 - - - 16,620 -
------- ------- ------- ----- ------------ ------------
Cash flow from
operations 5,461 5,219 3,362 3,177 17,219 11,757
Per share -
basic 0.17 0.17 0.15 0.21 0.71 0.78
----------------------------------------------------------------------------


Operating Cash Flow and Net Earnings

Orleans' profitability and cash flow generation is primarily a function of commodity prices, the cost to add reserves through drilling and acquisitions and the cost to produce the Company's reserves. In the year ended December 31, 2006, Orleans recorded $17.2 million in cash flow from operations and posted a net loss of $17.84 million. Included in the net loss is the non-cash, accounting goodwill impairment of $16.62 million.



----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
($000s except Cal Cal Cal Cal Period Ended Period Ended
share data) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------

Cash flow from
operations (1) 5,461 5,219 3,362 3,177 17,219 11,757
Per share
- basic 0.17 0.17 0.15 0.21 0.71 0.78
Per share
- diluted 0.17 0.17 0.15 0.20 0.69 0.74

Net earnings
(loss) (17,006) (128) (1,346) 642 (17,838) 19,466
Per share
- basic (0.53) - (0.07) 0.04 (0.73) 1.29
Per share
- diluted (0.52) - (0.07) 0.04 (0.71) 1.23
----------------------------------------------------------------------------

(1) Cash flow from operations does not have any standardized meaning
prescribed by Canadian GAAP and accordingly represents cash flow from
operating activities before any asset retirement obligation cash
expenditures. As an indicator of the Company's performance, the term
cash flow from operations or operating cash flow contained within should
not be considered as an alternative to, or more meaningful than, cash
flow from operating activities as determined in accordance with Canadian
GAAP.


Capital Expenditures

The Company's capital investments encompass exploration, development and acquisition activities, which generally include the following:

- Drilling and completing new natural gas and oil wells;

- Constructing and installing new field production infrastructure;

- Acquiring and maintaining the Company's lease acreage position and its seismic resources;

- Enhancing existing natural gas and oil wells through well-bore re-completions;

- Acquiring additional natural gas and oil reserves and producing properties; and,

- General and administrative costs directly associated with exploration and development activities, including payroll and other overhead expenses attributable solely to the Company's technical employees.

The Company's exploration and development capital expenditure program for 2007 has been set at an initial range of $30 to $35 million. Actual spending may vary due to a variety of factors, including drilling results, natural gas and oil prices, economic conditions and any future acquisitions. The timing of most of the Company's capital expenditures is discretionary because Orleans does not have any material capital expenditure commitments. Consequently, the Company has a significant degree of flexibility to adjust the level of it capital investments as circumstances warrant. Additionally, to enhance flexibility of the Company's capital program, Orleans typically does not enter into material long-term obligations with any of its drilling contractors or service providers with respect to its operated natural gas and oil properties.

In the year ended December 31, 2006, the Company's total capital investment expenditures amounted to $159.7 million. In addition to executing the strategic corporate acquisitions of both Morpheus and Mercury for a total of $110.8 million, in 2006 the Company was active with exploration and development activities. The Company drilled or participated in the drilling of 28 wells (20.6 net), resulting in 17 gas wells, six oil wells, one standing well and four dry holes for an overall success rate of 82%.



The breakdown of Orleans' capital programs are outlined below:

----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------
Twelve Month Nine Month
Cal Cal Cal Cal Period Ended Period Ended
($000s) Q406 Q306 Q206 Q106 December 31 December 31
------- ------- ------- ----- ------------ ------------
Land 887 243 3,011 2,467 6,608 1,591
Seismic (44) 400 14 188 558 865
Drilling &
completions 10,642 11,599 4,569 2,978 29,788 10,285
Facilities &
well equipment 3,307 4,207 1,108 680 9,302 3,306
------- ------- ------- ----- ------------ ------------
Exploration &
development 14,792 16,449 8,702 6,313 46,256 16,047
------- ------- ------- ----- ------------ ------------
Other (1) 928 183 209 149 1,469 568
Property
purchases 16 6 (30) 1,188 1,180 151
Corporate
acquisitions
(2) 92 144 110,581 - 110,817 3,016
------- ------- ------- ----- ------------ ------------
Total capital
expenditures 15,828 16,782 119,462 7,650 159,722 19,782
----------------------------------------------------------------------------

(1) Fiscal 2006 includes capitalized G&A of $623 thousand and non-cash
capitalized stock-based compensation of $720 thousand.
(2) Includes total consideration paid (cash, shares issued and transactions
costs) for acquisitions and working capital and assumption of debt.


Goodwill

In the year ended December 31, 2006, the Company recorded goodwill of approximately $16.62 million in connection with the acquisition of Morpheus Energy Corporation (December 31, 2005: nil). The carrying value of the Company's recorded goodwill is not amortized, however, it is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. The Company conducted the prescribed impairment test at December 31, 2006, resulting in a non-cash accounting impairment of the full $16.62 million goodwill amount since the fair value of Orleans' goodwill did not exceed the goodwill carrying amount.

Liquidity and Capital Resources

At December 31, 2006, the Company was capitalized with a working capital deficit of $43.2 million (December 31, 2005: $4.61 million), including bank debt of $38.8 million (December 31, 2005: $0.72 million) and 33.1 million common shares outstanding with a book capitalization of $122.74 million and a market capitalization of $114.36 million.



----------------------------------------------------------------------------
2006 Quarter End Comparison
------------------------------------------
($000) Dec. 31 Sep. 30 Jun. 30 Mar. 31
--------- --------- --------- ---------
Bank debt 38,781 40,378 34,212 7,460
Working capital deficit
/ (surplus) (1) 4,445 7,378 2,006 1,626
--------- --------- --------- ---------
Net Debt 43,226 47,756 36,219 9,086
--------- --------- --------- ---------
--------- --------- --------- ---------

Book capitalization (2) 122,736 109,800 109,723 19,938
Market capitalization (3) 114,363 123,601 178,188 95,879
----------------------------------------------------------------------------

Note 1: Reflects current assets (excluding any current income tax assets)
less current liabilities (excluding any outstanding bank debt).
Note 2: Reflects the book value of share capital, as reported on the
Company's respective balance sheets.
Note 3: Based on the market closing price of Orleans stock and the
outstanding number of common shares at period end.


At December 31, 2006, the Company had borrowings of $38.8 million (December 31, 2005: $0.72 million) under its bank facility with a Canadian commercial bank and was in compliance with all covenant terms of the credit agreement. The increase in the bank debt position of the Company at year-end 2006, as compared to year-end 2005, is attributable to capital investments incurred in the Fiscal 2006 period exceeding the cash generated through operating activities within that period and the assumption of the bank indebtedness of both Morpheus and Mercury.

On April 10, 2007, the Company entered into a new credit agreement with a major Canadian chartered bank. The new credit agreement increased the borrowing base of the revolving demand facility to $60 million. The borrowing base, which is re-determined semi-annually, represents the amount that can be borrowed from a credit standpoint based on, among other things, the Company's current reserve report, results of operations, current and forecasted commodity prices and the current economic environment, as confirmed by the bank.

In 2007, as in 2006, the Company expects its cash flow from operations to be its primary source of liquidity to meet operating, general and administrative and interest expenses, and fund planned spending on exploration and development capital projects and undeveloped acreage. The aforementioned $60 million revolving bank credit facility will provide another source of liquidity. The Company anticipates that public capital markets will serve as the principal source of funds to finance any future substantial corporate acquisitions and/or significant property purchases. Orleans has sold equity securities in the past, and the Company expects that this source of capital will be available in the future for acquisition purposes.



Common Share Information

----------------------------------------------------------------------------
2006 Quarterly Comparison
-------------------------------------------------
Cal Q406 Cal Q306 Cal Q206 Cal Q106
------------ ----------- ------------ -----------
Share Price: High $ 4.52 $ 6.60 $ 6.50 $ 6.99
Low $ 3.37 $ 3.45 $ 5.11 $ 5.05
Close $ 3.45 $ 4.05 $ 5.85 $ 6.35
Avg. daily trading
volume (1) 48,200 51,083 25,109 25,560
Shares outstanding
- period end (2) 33,148,659 30,518,659 30,459,493 15,099,047
Weighted average basic 31,890,833 30,498,276 19,708,637 15,099,047
Weighted average diluted 32,533,845 31,293,929 20,759,015 16,047,634
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Nine Month
Period
Fiscal Ended
2006 December 31
----------- ------------
Share Price: High $ 6.99 $ 6.35
Low $ 3.37 $ 3.21
Close $ 3.45 $ 6.17
Avg. daily trading volume (1) 43,145 35,004
Shares outstanding - period end (2) 33,148,659 15,099,047
Weighted average basic 24,362,187 15,065,156
Weighted average diluted 25,136,494 15,854,191
----------------------------------------------------------------------------

Note 1: The common shares of Orleans commenced trading on the TSX Venture
Exchange on January 31, 2005.

Note 2: At the Company's June 15, 2005 Shareholders Meeting, the Company's
articles were amended to reorganize its authorized share capital.
Specifically, a resolution was approved to change the outstanding
3,950,610 non-voting common shares into voting common shares on a
1 for 1 basis and to reduce the maximum number of non-voting common
shares that the Company is authorized to issue to zero.

Note 3: As of the date of this MD&A, total common shares issued and
outstanding are 33,148,659.


Contractual Obligations

Orleans is committed to various contractual obligations and commitments in
the normal course of operations and financing activities. These are outlined
as follows:

----------------------------------------------------------------------------
Less than 1 - 3 4 - 5 Beyond 5
($000s) 1 Year Years Years Years Total
--------- ------- ------ --------- -------
Bank debt (1) 38,781 - - - 38,781
Operating lease obligations (2) 484 1,866 1,291 861 4,502
Asset retirement obligations (3) 172 1,360 1,271 9,684 12,487
--------- ------- ------ --------- -------
Total obligations 39,437 3,226 2,562 10,545 55,770
----------------------------------------------------------------------------

Note 1: Revolving credit facility with a commercial bank. Refer to Note 6 to
the consolidated financial statements for the year ended December
31, 2006.
Note 2: Operating lease obligations pertain to the Company's Calgary,
Alberta head office lease entered into on February 16, 2007.
Note 3: As at December 31, 2006, total undiscounted future asset retirement
obligation costs to be accrued over the life of the remaining total
proved are estimated at $12.48 million (adjusted for inflation).
This estimate is subject to change based on amendments to
environmental laws and as new information with respect to the
Company's operations become available. Refer to Note 7 to the
consolidated financial statements for the year ended December 31,
2006.


In 1996, a lawsuit was filed against the Company's predecessor, Orleans Resources Inc. and the "procureur general du Quebec". Since the Company is of the opinion that this lawsuit against Orleans Resources Inc. is unwarranted and will have no material adverse effect on the Company's financial position or on the results of operations, no provision has been recorded in this respect. If the Company has to pay any amount in this affair, this amount will be paid by issuing reserved common shares, at a price of $6.00 per share. The maximum number of common shares that would have to be issued would be 666,118 shares, representing the full lawsuit value amount of $3.996 million.

Additionally, refer to Note 8 c) to the consolidated financial statements for the year ended December 31, 2006, which outlines the Company's requirements to incur by December 31, 2007 flow-through share eligible Canadian Exploration Expenditures, as defined in the Income tax Act (Canada).

Off-Balance Sheet Arrangements

The Company does not presently utilize any off-balance sheet arrangements to enhance its liquidity and capital resource positions, or for any other purpose. During the year ended December 31, 2006 Orleans did not enter into any off-balance sheet transactions.

Related Party Transactions

A director and the corporate secretary of the Company are partners at a law firm that provides legal services to the Company. The services were conducted in the normal course of business operations and are measured at the exchange amount, which is established and agreed to by the related parties based on standard rates, time spent and costs incurred. During the year ended December 31, 2006, the Company paid and accrued a total of $326 thousand to this firm for legal fees and disbursements (December 31, 2005: $59 thousand).

Disclosure Controls and Procedures

Orleans' disclosure controls and procedures, as defined in Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", were reviewed by the Company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"). Based on this review and given the size and nature of the Company's operations, the Company's CEO and CFO believe the Company's disclosure controls and procedures to be effective as of December 31, 2006. All control systems by their nature have inherent limitations and therefore Orleans' disclosure controls and procedures are believed to provide reasonable, but not absolute assurance, that: i) the Company's communications with the public are timely, factual and accurate and broadly disseminated in accordance with all applicable legal and regulatory requirements, ii) non-publicly disclosed information remains confidential, and iii) trading of the Company's common shares by Orleans' directors, officers and employees remain in compliance with applicable securities laws.

Internal Controls Over Financial Reporting

The Company's CEO and CFO are responsible for designing the internal controls over financial reporting ("ICOFR") or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. As at December 31, 2006, the CEO and CFO evaluated the design and implementation of the Company's ICOFR. In part, this evaluation was based on a third party specialist who was engaged by the Company, under the CFO's supervision, to formally document Orleans' ICOFR. Based on this evaluation, the CEO and the CFO have concluded that the design of internal control over financial reporting is sufficiently effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.

It should be recognized, however, that control systems over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control systems are met. The Company, due to its relatively small size and organizational structure, does have potential weaknesses in its internal control over financial reporting. These include:

- Comprehensive segregation of duties may not be sufficiently adequate. Specifically, certain duties within the accounting function were not ideally segregated due to the small number of individuals employed in this area. This deficiency was not believed to be a material weakness since, at the present time, the CEO and the CFO oversee all material transactions and related accounting records and there is daily oversight by the senior personnel of the Company. In addition, Orleans' Audit Committee reviews on a quarterly basis the financial statements and key risks of the Company and queries management about significant transactions. It should be noted though, as the Company continues to grow, it plans to expand the number of individuals involved in the accounting function to facilitate comprehensive segregation of duties.

- The Company does not presently retain staff with specialized, complex and non-routine accounting expertise, which may present a risk of misstatements. The Company reports current and future income tax expenses and liabilities and other complex accounting calculations based on management's estimates, however there is no guarantee that a material misstatement would be prevented. The Company will attempt to remediate this potential internal control weakness by utilizing outside consultants with the appropriate expertise when the need arises or by developing in-house expertise or recruiting the necessary personnel with the expertise.

New Accounting Standards in 2007

Financial Instruments

The following standards regarding financial instruments are effective for January 1, 2007; 3855 "Financial Instruments - Recognition and Measurement", 3861 "Financial Instruments - Disclosure and Presentation", 1530 "Comprehensive Income", and 3865 "Hedges". The standards require all financial instruments other than held-to-maturity investments, loans and receivables to be included on a company's balance sheet at their fair value. Held-to-maturity investments, loans and receivables would be measured at their amortized cost. The standards create a new statement for comprehensive income that will include changes in the fair value of certain financial instruments. As a result of these new standards, the Company will record the fair value of its crude oil and natural gas derivative contracts under its risk management program on the Company's consolidated balance sheet. No restatement of prior periods is expected as a result of these new standards.

Business Outlook for 2007

In January 2007, the Company's Board of Directors approved an initial 2007 exploration and development capital expenditure program in a range of $30 to $35 million (the "2007 Capital Budget"), range-bound to account for the unpredictable crude oil and natural gas price market. The 2007 Capital Budget encompasses the drilling of 24 to 29 wells, with an approximate 74% working interest, including seven to eight gas wells at Kaybob, seven to nine oil wells at Gordondale, two to four oil wells at Leo, three gas wells at Gilby, two gas wells at Pine Creek, two exploration gas wells at Jack on the Peace River Arch and one oil well at Pembina. The drilling expenditure component of Orleans' 2007 Capital Budget is projected between $22 to $26 million, with the remaining budgeted funds directed towards capital investments in field facilities of $5 to $6 million and land acreage expansion and seismic programs of approximately $3 million. In terms of geographic allocation of the budgeted drilling and field facilities capital expenditures, approximately $11 to $12 million will be deployed at Kaybob, $6 to $8 million at Gordondale, $3 to $5 million at Leo/Halkirk, $3 million at Gilby, $2 million at Pine Creek and $2 million at Jack and Pembina. Based on the capital investment activities anticipated within the initial 2007 Capital Budget, preliminary average daily production for calendar 2007 is projected between 3,100 to 3,200 boe per day, weighted 65% natural gas and 35% light crude oil and natural gas liquids. The median of this forecasted production range represents an 80% increase over the Company's 2006 average daily production of 1,750 boe per day and a 217% increase over Orleans' calendar 2005 average daily production level of 995 boe per day. Orleans' year-end 2007 exit rate is anticipated to range between 3,300 to 3,400 boe per day.

Business Risks and Uncertainties

The Company's exploration and development activities are focused in the Western Canada Sedimentary Basin within the province of Alberta, which is characterized as being highly competitive with competitors varying in size from small junior producers to significantly larger, fully-integrated energy companies and oil and gas royalty trusts possessing greater financial and personnel resources. The Company recognizes certain risks inherent in the oil and gas industry, such as access to oil and gas services, weather-related delays with drilling and operational plans, finding and developing oil and gas reserves at economic costs, drilling risks, producing oil and gas in commercial quantities, environmental and safety risks, and commodity price and political risks and uncertainties. Orleans has engaged professional management and technical personnel with many years of experience in the oil and gas business to address, prudently manage and mitigate these risks.

Application of Critical Accounting Policies and Estimates

The preparation of the Company's financial statements in accordance with Canadian GAAP requires Orleans' management to make estimates, assumptions and judgments that affect the reported amounts of assets, liabilities, revenue and expenses. The basis for these estimates is historical experience and various other assumptions that the Company believes to be reasonable. Actual results could differ from these estimates under different assumptions and conditions. The following assessment of significant accounting polices is not meant to be exhaustive or all-inclusive. The Company might realize different results from the application of new accounting standards put forth, from time to time, by various rule-making bodies.

Full-Cost Accounting

The Company follows the full cost method of accounting for its crude oil and natural gas operations, whereby all costs related to the exploration for and development of oil and gas reserves are capitalized and depleted and depreciated using the unit-of-production method based upon the gross proved petroleum and natural gas reserves as determined by an independent qualified reserve engineering firm. In determining costs subject to depletion, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the costs of unproved properties. The costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or until impairment occurs.

In applying the full cost accounting method, a ceiling test is performed to ensure that the capitalized costs are recoverable in the future. Oil and gas assets are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. The calculation of undiscounted cash flows in the ceiling test can be significantly impacted by fluctuations in any of these estimates.

Asset Retirement Obligation

The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the asset retirement requires an estimate of the future costs to abandon and reclaim wells, pipelines and facilities discounted to its present value using the Company's credit adjusted risk-free interest rate. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings. Revisions to the estimated timing of cash flows or to the original undiscounted cost could also result in an increase or decrease to the obligation. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

Income Tax Accounting

The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, any income tax liability or asset, as well as any income tax recoveries or reductions, may differ from that estimated and recorded by the Company's management.

Purchase Price Allocation

Business acquisitions are accounted for by the purchase method of accounting. Under this method, the purchase price is allocated to the assets acquired and the liabilities assumed based on the fair value at the time of acquisition. The excess purchase price over the fair value of identifiable assets and liabilities acquired is goodwill. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant and equipment acquired generally require the most judgment and include estimates of reserves acquired, future commodity prices and discount rates. Future net earnings can be affected as a result of changes in future depletion and depreciation, asset impairment or goodwill impairment.

Goodwill Impairment

Goodwill is subject to impairment tests annually, or as economic events dictate, by comparing the fair value of the reporting entity to its carrying value, including goodwill. If the fair value of the reporting entity is less than its carrying value, a goodwill impairment loss is recognized as the excess of the carrying value of the goodwill over the implied fair value of the goodwill. The determination of fair value requires management to make assumptions and estimates about recoverable reserves, future commodity prices, operating costs, production profiles and discount rates. Changes in any of these assumptions, such as a downward revision in reserves, a decrease in future commodity prices, an increase in operating costs or an increase in discount rates could result in an impairment of all or a portion of the goodwill carrying values in future periods.

Accounting for Stock Options

The Company recognizes compensation expense on options granted pursuant to its stock option plan. Compensation expense is based on the theoretical fair value of each option at its grant date, the estimation of which requires management to make assumptions about the future volatility of the Company's stock price, future interest rates and the timing of optionee's decisions to exercise the options. The effects of a change in one or more of these variables could result in a materially different fair value.

For further details on the Company's accounting policies, refer to Note 2 of the Notes to the consolidated financial statements for the year ended December 31, 2006

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The Company's consolidated financial statements for the fiscal twelve-month period ended December 31, 2006 are enclosed at the end of this news release.

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Orleans Energy Ltd. is a Calgary, Alberta-based emerging crude oil and natural gas company, with common shares trading on the TSX Venture Exchange under the symbol "OEX". Orleans is a team of dedicated, experienced professionals focused on the creation of shareholder value via acquisition and development of crude oil and natural gas assets in Alberta.

Certain information regarding the Company contained herein may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking statements may include estimates, plans, anticipations, expectations, intentions, opinions, forecasts, projections, guidance or other similar statements that are not statements of fact. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. These statements are subject to certain risks and uncertainties and may be based on assumptions that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The Company's forward-looking statements are expressly qualified in their entirety by this cautionary statement.

In this news release, reserves and production data are commonly stated in barrels of oil equivalent ("boe") using a six to one conversion ratio when converting thousands of cubic feet of natural gas ("mcf") to barrels of oil ("bbl") and a one to one conversion ratio for natural gas liquids ("NGLs" or "ngls"). Such conversion may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.



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ORLEANS ENERGY LTD.
Consolidated Balance Sheets
----------------------------------------------------------------------------
December 31, December 31,
2006 2005
--------------- --------------
ASSETS

Current Assets
Cash and cash equivalents $ 273,165 $ -
Accounts receivable 11,072,319 3,397,255
Prepaid expenses and deposits 749,873 305,762
Current income tax asset (Note 11) - 6,633,855
--------------- --------------
12,095,357 10,336,872

Property, plant and equipment (Note 4) 176,229,557 33,346,079

Future income tax asset (Note 11) - 7,001,232
--------------- --------------

$ 188,324,914 $ 50,684,183
--------------- --------------
--------------- --------------

LIABILITIES

Current Liabilities
Accounts payable and accrued liabilities $ 16,539,909 $ 7,597,341
Bank loan (Note 6) 38,781,291 718,800
--------------- --------------
55,321,200 8,316,141

Asset retirement obligations (Note 7) 5,023,743 2,484,234

Future income tax liability (Note 11) 2,197,469 -
--------------- --------------

$ 62,542,412 $ 10,800,375
--------------- --------------
--------------- --------------

SHAREHOLDERS' EQUITY

Share capital (Note 8) 122,736,373 19,937,717
Contributed surplus (Note 9c) 1,502,963 565,359
Retained earnings 1,543,166 19,380,732
--------------- --------------

125,782,502 39,883,808
--------------- --------------

$ 188,324,914 $ 50,684,183
--------------- --------------
--------------- --------------

Description of Business and Significant Accounting Policies (Notes 1 & 2)
Commitments and Contingencies (Note 14)
Subsequent Event (Note 17)

On behalf of the Board of Directors:
Barry Olson, Director James Saunders, Director

See accompanying notes to the consolidated financial statements.


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ORLEANS ENERGY LTD.
Consolidated Statements of Operations and Retained Earnings
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Twelve Month Nine Month
Period Ended Period Ended
December 31, December 31,
2006 2005
--------------- --------------
Revenue
Petroleum and natural gas sales $ 32,447,221 $ 19,415,330
Royalties (5,724,333) (3,963,632)
--------------- --------------
26,722,888 15,451,698
Interest income 155,243 12,699
--------------- --------------

26,878,131 15,464,397
--------------- --------------
Expenses
Operating 6,315,676 2,518,604
Transportation 567,579 324,987
General and administrative 1,389,775 814,612
Interest 1,386,165 49,379
Stock-based compensation 555,486 369,119
Depletion, depreciation and accretion 16,985,754 5,557,317
Goodwill impairment (Note 5) 16,619,991 -
--------------- --------------
$ 43,820,426 $ 9,634,018
--------------- --------------

Earnings (loss) before taxes (16,942,295) 5,830,379
Future income taxes (reduction)
(Note 11) 895,271 (13,635,087)
--------------- --------------

Net earnings (loss) $ (17,837,566) $ 19,465,466
Retained earnings (deficit), beginning
of period 19,380,732 (84,734)
--------------- --------------

Retained earnings, end of period $ 1,543,166 $ 19,380,732
--------------- --------------
--------------- --------------
Net earnings (loss) per share (Note 10)
Basic $ (0.73) $ 1.29
--------------- --------------
--------------- --------------
Diluted $ (0.71) $ 1.23
--------------- --------------
--------------- --------------

See accompanying notes to the consolidated financial statements.


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ORLEANS ENERGY LTD.
Consolidated Statements of Cash Flow
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Twelve Month Nine Month
Period Ended Period Ended
December 31, December 31,
2006 2005
--------------- --------------
Cash provided from (used in):

Operating activities
Net earnings $ (17,837,566) $ 19,465,466
Items not affecting cash:
Depletion, depreciation and accretion 16,985,754 5,557,317
Stock-based compensation 555,486 369,119
Future income taxes (reduction) 895,271 (13,635,087)
Goodwill impairment (Note 5) 16,619,991 -
Asset retirement expenditures - (38,086)
--------------- --------------

17,218,936 11,718,729
Change in non-cash working capital
(Note 12) 2,926,942 (119,622)
--------------- --------------
20,145,878 11,599,107
--------------- --------------

Financing activities
Increase in bank loan 14,416,735 718,800
Exercise of stock options 202,432 36,000
Proceeds from share issues, net issue
costs 50,013,510 (1,232)
--------------- --------------
64,632,677 753,568
--------------- --------------

Investing activities
Corporate acquisitions (Note 3) (39,517,224) (2,861,229)
Property, plant and equipment additions (48,185,416) (16,920,874)
Change in non-cash working capital
(Note 12) 3,197,250 4,076,839
--------------- --------------
(84,505,390) (15,705,264)
--------------- --------------

Increase (decrease) in cash and cash
equivalents 273,165 (3,352,589)

Cash and cash equivalents, beginning of
period - 3,352,589
--------------- --------------

Cash and cash equivalents, end of period $ 273,165 $ -
--------------- --------------
--------------- --------------

Supplemental Cash Flow Information (Note 12)

See accompanying notes to the consolidated financial statements.


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ORLEANS ENERGY LTD.
Notes to the Consolidated Financial Statements
Year ended December 31, 2006
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1. Description of Business

Orleans Energy Ltd. (the "Company" or "Orleans") is actively engaged in the exploration for, and development and production of, natural gas, natural gas liquids and crude oil in the Western Canadian Sedimentary Basin. Orleans is incorporated under the laws of Alberta and its common shares are traded on the TSX Venture Exchange under the trading symbol "OEX".

On April 11, 2005, the Company filed notice under National Instrument 51-102 stating the Company's intention to change the date of its fiscal year-end to December 31 from March 31, with the next year-end occurring December 31, 2005. This change was effected in order to have a year-end consistent with that of other companies in the oil and gas industry.

2. Significant Accounting Policies

a) Principles of consolidation and basis of presentation

The consolidated financial statements have been prepared by the Company's Management in accordance with Canadian generally accepted accounting principles ("GAAP"). The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. A portion of the Company's exploration, development and production activities are conducted jointly with others and accordingly the consolidated financial statements reflect only the Company's proportionate working interest share in such activities.

b) Measurement uncertainty

Amounts recorded for depletion, depreciation and accretion, the provision for asset retirement obligations and the ceiling test calculation are based upon estimates of proved petroleum and natural gas reserves, production rates, commodity prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material. The Company's reserve estimates are evaluated annually by an independent qualified reserve engineering firm pursuant to the parameters and guidelines stipulated under National Instrument 51-101 ("NI 51-101") - Standards of Disclosure for Oil and Gas Activities.

c) Petroleum and natural gas operations

i) Capitalized costs

The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Such capitalized costs may include lease acquisition costs, geological and geophysical expenses, costs of drilling both productive and non-productive wells, gathering and production facilities, lease rentals on non-producing properties, interest on debt directly related to certain acquisitions, and certain other overhead expenditures directly related to exploration and development activities. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation by 20% or more.

ii) Depletion and depreciation

Capitalized costs under the full cost accounting method are depleted and depreciated using the unit-of-production method based upon the gross proved petroleum and natural gas reserves as determined by an independent qualified reserve engineering firm. In determining costs subject to depletion, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the costs of unproved properties. The costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or until impairment occurs. For depletion and depreciation purposes, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six (6) thousand cubic feet of natural gas to one (1) barrel of crude oil. Depreciation on office furniture and other equipment is provided for over its useful lives using the declining balance method at a rate of 20%.

iii) Ceiling test

Oil and gas assets are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre.

The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future commodity prices and costs with such cash flows discounted using a risk-free interest rate.

d) Asset retirement obligations ("ARO")

The Company recognizes the fair value of its asset retirement obligations associated with the retirement of tangible long-lived assets as a long-term liability in the period in which it is incurred, with a corresponding increase to the carrying amount of the related asset. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depreciation, depletion and amortization of the underlying asset. The obligations to be recognized are statutory, contractual or legal in nature. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the respective period. Revisions to the original estimated undiscounted cost or obligation would also result in an increase or decrease to the asset retirement obligation.

e) Flow-through shares

The Company may finance a portion of its exploration and development activities through the issuance of flow-through common shares. Under the terms of the flow-through share agreements, the resource expenditure deductions for income tax purposes are renounced to subscribers in accordance with the appropriate income tax legislation. A future tax liability is recorded and share capital is reduced by the estimated tax benefits transferred to the flow-through common share subscribers at the time when the qualifying expenditures are renounced to such subscribers.

f) Per share amounts

Basic per share amounts are computed using the weighted average number of common shares outstanding during the reporting period. Diluted per share amounts are calculated using the treasury stock method, which assumes that any proceeds from the exercise of stock options in addition to the unrecognized amount of stock-based compensation expense are used to purchase common shares of the Company at the average market price during the reporting period.

g) Income taxes

The Company follows the liability method of accounting for income taxes. Future income taxes are calculated based on temporary differences arising from the difference between the tax basis of an asset or liability and its carrying value on the balance sheet using tax rates anticipated to apply in the periods when the temporary differences are expected to reverse. The effect on future taxes for a change in tax rates is recognized in income in the period that includes the enactment date. Future income tax assets are recognized to the extent that realization of such assets is more likely than not.

h) Revenue recognition

Revenue associated with the sale of petroleum and natural gas production owned by the Company is recognized when ownership title passes from the Company to its customers and delivery has taken place.

i) Stock-based compensation plan

The Company has a stock-based compensation plan as described in Note 8. The fair value of stock options is charged to earnings over the vesting period with a corresponding increase in contributed surplus. The fair value of options granted is estimated at the date of the grant using the Black-Scholes evaluation model. Upon the exercise of the stock option, consideration paid by the option holder together with the amount previously recognized in contributed surplus, is credited to share capital.

j) Derivative financial instruments

The Company may use derivative financial or hedging instruments to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates, interest rates and power costs. The Company does not utilize derivative financial instruments for speculative purposes. Gains and losses related to derivative financial instruments designated as hedges are deferred and recognized in product revenues upon sale of the related hedged production.

k) Dividend policy

The Company has neither declared nor paid any dividends on its common shares. The Company intends to retain its earnings to finance growth and expand its operations and does not anticipate paying any dividends on its common shares in the foreseeable future.

l) Cash and cash equivalents

Cash and cash equivalents consist of cash-on-hand with commercial banks and investments in bankers acceptances or guaranteed notes issued by commercial banks with an original maturity of less than three months.

m) Goodwill

The Company records goodwill when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities acquired. Goodwill is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the segment is compared to its fair value. When the fair value of the segment exceeds its carrying amount, goodwill is considered not to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of the Company's goodwill exceeds its fair value, in which case the implied fair value of the Company's goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of the goodwill is determined in a business combination using the fair value of the Company as if it were the purchase price. When the carrying amount of the Company's goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess.

3. Corporate Acquisitions

Mercury Energy Corporation

On June 2, 2006 the Company acquired all the issued and outstanding shares of Mercury Energy Corporation ("Mercury"), a private company involved in the exploration and production of crude oil and natural gas in Central Alberta for total consideration of approximately $19.5 million. This business combination has been accounted for using the purchase method and the results of operations have been included in the consolidated financial statements from the date of acquisition. The allocation of the purchase price and consideration paid is as follows:



Consideration:
Issue of 1,623,719 common shares of Orleans (valued at
$5.90/share) $ 9,579,942
Cash 9,835,115
Transaction costs 111,285
---------------
Total consideration $ 19,526,342
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Assets Acquired (allocated at estimated fair values):
Property, plant and equipment $ 23,690,297
Current assets 1,289,872
Current liabilities (3,792,356)
Asset retirement obligation (525,631)
Future income tax liability (1,135,840)
---------------
Total net assets acquired $ 19,526,342
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Morpheus Energy Corporation

On June 6, 2006 the Company acquired 99.32% of the issued and outstanding shares of Morpheus Energy Corporation ("Morpheus"), a private company involved in the exploration and production of natural gas and natural gas liquids in West Central Alberta. Orleans acquired the remaining 0.67% on July 4, 2006 pursuant to the compulsory business acquisition provisions of the Business Corporations Act (Alberta). The total consideration paid by Orleans to acquire all of the issued and outstanding shares of Morpheus was approximately $72.9 million. This business combination has been accounted for using the purchase method and the results of operations have been included in the consolidated financial statements from the date of acquisition. The allocation of the purchase price and consideration paid is as follows:



Consideration:
Issue of 7,351,727 common shares of Orleans (valued at
$5.90/share) $ 43,375,189
Cash 29,202,548
Transaction costs 368,276
---------------
Total consideration $ 72,946,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Assets Acquired (allocated at estimated fair values):
Property, plant and equipment $ 86,535,276
Current assets 6,422,172
Current liabilities (22,264,644)
Goodwill 16,619,991
Asset retirement obligation (1,275,664)
Future income tax liability (13,091,118)
---------------
Total net assets acquired $ 72,946,013
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Mojo Energy Inc.

On June 1, 2005 the Company acquired all of the issued and outstanding shares of Mojo Energy Inc. ("Mojo"), a private company involved in the exploration and production of natural gas and natural gas liquids in West Central Alberta for total cash consideration of $3.2 million. The acquisition was funded through the Company's available cash-on-hand. This business combination has been accounted for using the purchase method and the results of operations have been included in the consolidated financial statements from the date of acquisition. The allocation of the purchase price and consideration paid is as follows:



Consideration:
Cash $ 3,192,625
Transaction costs 15,000
---------------
Total consideration $ 3,207,625
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net assets acquired (allocated at estimated fair values):
Property, plant and equipment $ 3,025,776
Current assets (includes $346,396 cash acquired) 754,269
Current liabilities (561,644)
Asset retirement obligation (10,776)
---------------
Total net assets acquired $ 3,207,625
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Future income taxes payable of $578 thousand resulting from the temporary differences between the allocated fair values for Mojo's assets and liabilities and the associated tax basis were eliminated through the recognition of previously unrecognized future tax assets of Orleans.



4. Property, Plant and Equipment

December 31, 2006 December 31, 2005
---------------------------------------
Petroleum and natural gas properties $ 199,171,180 $ 39,743,164
Accumulated depletion (23,060,662) (6,447,902)
---------------------------------------
176,110,518 33,295,262
---------------------------------------

Office equipment and other 158,769 70,583
Accumulated depreciation (39,730) (19,766)
---------------------------------------
119,039 50,817
---------------------------------------

Net property, plant and equipment $ 176,229,557 $ 33,346,079
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During the twelve month period ended December 31, 2006, certain general and administrative overhead expenses of $1.34 million (December 31, 2005: $521 thousand) directly related to exploration and development activities were capitalized. Included in this amount is capitalized stock-based compensation of $720 thousand (December 31, 2005: nil), with such amount including the future income tax liability associated with the capitalized stock-based compensation of $219 thousand (December 31, 2005: nil).

At December 31, 2006, property, plant and equipment included $13.23 million (December 31, 2005: $2.72 million) relating to unproved properties, which have been excluded from the depletion calculation. Future development costs related to proved non-producing developed reserves of $22.28 million (December 31, 2005: $5.01 million) have been included in the depletion calculation.

The Company performed a ceiling test calculation as at December 31, 2006 to assess the recoverable value of the property, plant and equipment. The oil and gas future prices are based on the December 31, 2006 price forecast of the Company's independent reserve evaluators with certain information outlined in the following table. Based on the ceiling test calculation results, no write-down of the Company's carrying value of property, plant and equipment was required as at December 31, 2006.



WTI Edmonton Company's AECO-C Company's Exchange
Price-Oil Price-Oil Price-Oil Price-Gas Price-Gas Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ($US/$Cdn)
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2007 65.73 74.10 65.69 7.72 8.02 0.87
2008 68.82 77.62 69.94 8.59 8.99 0.87
2009 62.42 70.25 63.02 7.74 8.10 0.87
2010 58.37 65.56 58.43 7.55 7.91 0.87
2011 55.20 61.90 54.81 7.72 8.11 0.87
2012 56.31 63.15 56.01 7.85 8.27 0.87
2013 57.43 64.42 57.20 7.99 8.43 0.87
2014 58.58 65.72 58.45 8.12 8.59 0.87
2015 59.75 67.04 59.60 8.26 8.75 0.87
2016 60.95 68.39 60.33 8.40 8.91 0.87
2017 62.17 69.76 60.67 8.54 9.09 0.87
Escalated rate of 2.0% thereafter


5. Goodwill

The Company reviewed the valuation of goodwill as of December 31, 2006. Based upon this review, an impairment charge of goodwill of $16.62 million has been recorded as a non-cash charge to income as of December 31, 2006. This goodwill resulted from the acquisition of Morpheus Energy Corporation, whereby Orleans' shares issued as part of the acquisition consideration were valued at $5.90 per share, as compared to the Company's year-end 2006 closing market price of $3.45 per share.

6. Bank Facility

As at December 31, 2006, the Company had a demand revolving credit facility of $53.0 million with a Canadian commercial bank. Amounts drawn on the bank facility bear interest at the lender's prime rate or guaranteed note rates plus scheduled margins. At December 31, 2006, the Company had $38.78 million of bank debt outstanding (December 31, 2005: $719 thousand). The bank facility is secured through a floating charge over all of the Company's assets and the lender reserves the right to require fixed charge security at its discretion. Under the terms of the banking arrangement, the Company is required to meet certain financial and engineering reporting requirements.

7. Asset Retirement Obligations

Orleans' asset retirement obligations are based on the Company's net ownership in wells and facilities and Management's estimate of the timing and expected future costs associated with site reclamation, facilities dismantlement, and the plugging and abandonment of wells.

At December 31, 2006, the estimated present value of the total amount required to settle the asset retirement obligations was $5.02 million (December 31, 2005: $2.48 million), based on a total undiscounted future liability amount of $12.48 million (inflation adjusted) (December 31, 2005: $5.85 million). These obligations are to be settled based on the economic lives of the underlying assets, which is currently projected to be from zero to 48 years. The Company used a credit-adjusted risk free rate of 10 percent and an inflation rate of 1.5 percent to calculate the present value of the asset retirement obligations (December 31, 2005: credit-adjusted risk free rate of 10 percent and an inflation rate of 1.5 percent).



December 31, 2006 December 31, 2005
--------------------------------------
Asset retirement obligations - opening $ 2,484,234 $ 2,057,064
Liabilities incurred 385,186 295,013
Liabilities acquired 1,801,295 10,776
Liabilities settled - (38,086)
Accretion of discount 353,028 159,467
--------------------------------------
Asset retirement obligations - ending $ 5,023,743 $ 2,484,234
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For the twelve month period ended December 31, 2006, the Company recognized depletion expense related to it's asset retirement cost of $410 thousand (December 31, 2005: $348 thousand).

8. Share Capital

a) Authorized

- Unlimited number of voting common shares.

At the Company's June 15, 2005 Shareholders Meeting, the Company's articles were amended to reorganize its authorized share capital. Specifically, a resolution was approved to change the outstanding 3,950,610 non-voting common shares into voting common shares on a 1 for 1 basis and to reduce the maximum number of non-voting common shares that the Company is authorized to issue to zero.



b) Issued and outstanding

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

Number
Number of Total
of Voting Non-Voting Number
Common Common of Common
Shares Shares Shares Amount
---------- ---------- ---------- ------------
Balance, March 31, 2005 11,103,437 3,950,610 15,054,047 $ 19,881,743
Share capital
reorganization (Note 7a) 3,950,610 (3,950,610) - -
Share issue costs - - - (1,232)
Exercise of stock options 45,000 - 45,000 57,206
----------------------------------------------------------------------------
Balance, December 31, 2005 15,099,047 - 15,099,047 $ 19,937,717
Issued on flow-though
private placements 3,300,000 - 3,300,000 20,147,500
Issued on equity private
placement 5,600,000 5,600,000 33,040,000
Combined issue costs, net
tax effect of $ 1,036,737 - - - (2,137,253)
Issue on acquisition of
Mercury (Note 3) 1,623,719 - 1,623,719 9,579,942
Issued on acquisition of
Morpheus (Note 3) 7,351,727 - 7,351,727 43,375,189
Exercise of stock options 174,166 - 174,166 321,381
Flow through shares tax
adjustment - - - (1,528,103)
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Balance, December 31, 2006 33,148,659 - 33,148,659 $ 122,736,373
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----------------------------------------------------------------------------


c) Flow Through Shares

On April 27, 2006, the Company issued 670,000 flow-through common shares on a private placement basis at a price of $7.50 per share for gross proceeds of $5.025 million. Under the terms of the flow-through share agreement, the Company is committed to spend 100% of the gross proceeds on qualifying exploration expenditures prior to December 31, 2007. As at December 31, 2006, the Company had fully incurred and discharged these expenditures commitments associated with this private placement.

On November 14, 2006, the Company issued 2,630,000 flow-through common shares on a private placement basis at a price of $5.75 per share for gross proceeds of $15.123 million. Under the terms of the flow-through share agreement, the Company is committed to spend 100% of the gross proceeds on qualifying exploration expenditures prior to December 31, 2007. As at December 31, 2006, the Company had incurred approximately $1.8 million of qualifying expenditures associated with this private placement.

9. Stock-Based Compensation

a) Outstanding stock options

The Company has a stock option plan for the benefit of its directors, officers, employees and certain consultants. The Company has granted options to purchase common shares, whereby each option permits the holder to purchase one share of the Company at the stated exercise price. The options vest over a two-to-three year term and are exercisable on a cumulative basis over five years. At December 31, 2006, 2,698,739 options with a weighted average exercise price of $3.40 were outstanding and exercisable at various dates through to December 21, 2011.



The following table summarizes outstanding stock options as at December 31,
2006:


Weighted Avg.
Number Exercise Price
---------------------------
Outstanding - March 31, 2005 1,435,317 $ 1.52
Granted 119,588 4.36
Exercised (45,000) 0.80
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Outstanding - December 31, 2005 1,509,905 $ 1.77
Granted 1,533,000 4.95
Exercised (174,166) 1.16
Forfeited (170,000) 5.30
----------------------------------------------------------------------------
Outstanding - December 31, 2006 2,698,739 $ 3.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Options exercisable - December 31, 2006 622,075 $ 1.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------

b) Exercise price range for options outstanding as at December 31, 2006:

Outstanding Options Exercisable Options
-----------------------------------------------------------
Weighted Weighted Weighted
Price Range Number Avg. Price Avg.Remaining Life Number Avg. Price
----------------------------------------------------------------------------
$ 0.80 - 1.00 777,984 $ 0.80 3.07 years 455,045 $ 0.80
$ 3.00 - 3.74 788,255 $ 3.21 3.79 years 150,530 $ 3.11
$ 5.25 - 5.87 1,132,500 $ 5.31 4.44 years 16,500 $ 5.53
----------------------------------------------------------------------------
Total 2,698,739 $ 3.40 3.85 years 622,075 $ 1.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company determined the fair value of stock options granted during the
fiscal period ended December 31, 2006 using the modified Black-Scholes
evaluation stock option pricing model under the following assumptions:

December 31, 2006 December 31, 2005
--------------------------------------
Weighted-average fair value ($/option) 2.40 2.55
Risk-free interest rate (%) 4.06 3.70
Estimated hold period prior to exercise
(years) 5 5
Volatility in the price of Orleans
shares (%) 50.4 66.6
Dividend yield (%) Nil Nil

c) Contributed surplus

Contributed surplus - March 31, 2005 $ 217,447
Stock-based compensation 369,119
Exercise of stock options (21,207)
----------------------------------------------------------------------------
Contributed surplus - December 31, 2005 565,359
Stock-based compensation 1,056,553
Exercise of stock options (118,949)
----------------------------------------------------------------------------
Contributed surplus - December 31, 2006 $ 1,502,963
----------------------------------------------------------------------------
----------------------------------------------------------------------------


10. Per Share Amounts

In the calculation of diluted per share amounts, options under the Company's stock option plan are assumed to have been converted or exercised on the later of the beginning of the year and the date granted. The treasury stock method is used to determine the dilutive effect of stock options. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options in addition to the unrecognised stock-based compensation expense are used to repurchase common shares at the average market price.



Twelve Month Nine Month
Period Ended Period Ended
December 31, 2006 December 31, 2005
--------------------------------------
Weighted average shares outstanding:
Basic 24,362,187 15,065,156
Diluted 25,136,494 15,854,191


11. Income Taxes

a) Reconciliation of effective tax rate to the Canadian federal tax rate

The provision for income taxes reflects an effective tax rate that differs from the results which would be obtained by applying the expected statutory income tax rate to earnings before taxes. The difference results from the following:



December 31, 2006 December 31, 2005
--------------------------------------
Earnings (loss) before income taxes $ (16,942,295) $ 5,830,379
Combined federal and provincial
statutory tax rate 34.50% 37.62%
Calculated expected income taxes
(reduction) (5,845,092) 2,193,389

Increase (decrease) resulting from the
tax effect of:
Non-deductible crown charges (net
ARTC) 203,734 539,515
Federal resource allowance (240,532) (775,032)
Non-deductible stock-based
compensation 191,643 138,863
Goodwill Impairment 5,733,897 -
Other 17,306 (637,098)
Statutory rate change 834,315 (344,695)
Change in valuation allowance - (14,750,029)
----------------------------------------------------------------------------
Income taxes (reduction) $ 895,271 $ (13,635,087)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

b) Future Income Tax:

The components of the Company's future income tax is as follows:

December 31, 2006 December 31, 2005
--------------------------------------
Future income tax:
Capital assets $ (11,058,776) $ 730,029
Non-capital losses 8,433,831 11,724,177
Share issue costs and other 1,374,553 320,839
Asset retirement obligation 1,507,123 860,042
Partnership deferral (2,454,200)
----------------------------------------------------------------------------
Net future income tax asset
/ (liability) $ (2,197,469) $ 13,635,087
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Allocated:
Current income tax asset / (liability) - 6,633,855
Future income tax asset / (liability) (2,197,469) 7,001,232

The Company's non-capital losses of $27.7 million expire at various times
from 2008 to 2015.

12. Supplemental Cash Flow Information

a) Increase (decrease) in non-cash working capital items

December 31, 2006 December 31, 2005
--------------------------------------
Change in non-cash working capital:
Accounts receivable and other current
assets $ (411,218) $ (1,495,242)
Accounts payable and accrued
liabilities 6,535,410 5,452,459
--------------------------------------
$ 6,124,192 $ 3,957,217
--------------------------------------
--------------------------------------

Changes in non-cash working capital
related to:
Operating activities $ 2,926,942 $ (119,622)
Investing activities 3,197,250 4,076,839
--------------------------------------
$ 6,124,192 $ 3,957,217
--------------------------------------
--------------------------------------

b) Other cash flow information

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

Interest paid (net of interest income) $ 1,159,363 $ 36,680
Income taxes paid - -


13. Financial Instruments and Risk Management

a) Commodity risk

From time to time, the Company may employ derivative financial instruments and physical arrangements, primarily commodity price hedges, to manage fluctuations in oil and gas market prices. The Company may use fixed physical price arrangements, futures contracts, swaps, collars and put options with respect to a portion of its oil and gas production in order to achieve a more predictable cash flow. The Company does not utilize derivative financial statements for speculative purposes. Gains and losses related to derivative financial instruments designated as hedges are deferred and recognized in product revenues upon sale of the related hedged production.

The following table outlines the financial hedge agreements that were outstanding during the year ended December 31, 2006. The aggregate fair value of the financial hedge agreements outstanding as at December 31, 2006 was a gain of approximately C$ 606 thousand.



Daily
Notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Crude Oil Jun. 6, 2006 Swap Aug '06
-Dec '06 125 bbls W.T.I. US$ 73.62/bbl

Crude Oil Jul. 6, 2006 Swap Aug '06
-Jul '07 125 bbls W.T.I. US$ 77.25/bbl

NatGas Oct. 17, 2006 Collar Nov '06 C$ 6.50
-Mar '07 2,000 GJs AECO-C -8.50/GJ

NatGas Nov. 9, 2006 Collar Dec '06 C$ 7.00
-Mar '07 2,000 GJs AECO-C -8.75/GJ
----------------------------------------------------------------------------


Subsequent to December 31, 2006, the Company had the following financial
hedge agreements outstanding:

Daily
Notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Crude Oil Jul. 6, 2006 Swap Aug '06
-Jul '07 125 bbls W.T.I. US$ 77.25/bbl

NatGas Oct. 17, 2006 Collar Nov '06 C$ 6.50
-Mar '07 2,000 GJs AECO-C -8.50/GJ

NatGas Nov. 9, 2006 Collar Dec '06 C$ 7.00
-Mar '07 2,000 GJs AECO-C -8.75/GJ

NatGas Jan. 23, 2007 Collar Feb '07 C$ 6.50
-Dec '07 1,000 GJs AECO-C -9.08/GJ

NatGas Jan. 23, 2007 Collar Apr '07 C$ 6.50
-Oct '07 1,000 GJs AECO-C -8.52/GJ

NatGas Jan. 31, 2007 Collar Apr '07 C$ 7.00
-Dec '07 1,000 GJs AECO-C -9.00/GJ

NatGas Feb. 5, 2007 Collar Apr '07 C$ 7.00
-Dec '07 1,000 GJs AECO-C -9.08/GJ

NatGas Feb. 22, 2007 Swap Apr '07
-Oct '07 1,000 GJs AECO-C C$ 7.70/GJ

Crude Oil Mar. 26, 2007 Collar Apr '07 US$ 59.30
-Dec '07 150 bbls W.T.I. -70.00/bbl


b) Credit risk

A substantial portion of the Company's accounts receivable are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks which may expose the Company to certain losses in the event that counterparties or customers default on payment or contract settlement. As such, the Company's customers are subject to an internal credit review to minimize risk of non-payment. The carrying value of accounts receivable reflects Management's assessment of the credit risk associated with these customers.

c) Interest rate risk

Financial instruments, which subject the Company to interest rate risk are limited to bank indebtedness. The Company's current operating credit facility agreement calculates interest based on the bank's prime lending rate.

d) Fair value of financial assets and liabilities

The fair value of financial instruments is determined by reference to various market data and other valuation techniques as appropriate. The Company's financial instruments consists of cash and cash equivalents, accounts receivable and accounts payable. The fair value of financial instruments is not estimated by Management to be materially different from the carrying values since these deemed financial instruments are near maturity.

14. Commitments and Contingencies

The Company has various commitments through ordinary course of business.

The Company is committed to the following approximate payments under an operating lease for head office space, which includes an estimate of the Company's share of operating, utilities, property taxes and parking for the duration of the office lease:



2007 $ 484,263
2008 $ 615,184
2009 $ 615,184
2010 $ 635,554
2011 $ 645,739
2012 and thereafter $ 1,506,724


In 1996, a lawsuit was filed against the Company's predecessor, Orleans Resources Inc. and the "procureur general du Quebec". Since the Company is of the opinion that this lawsuit against Orleans Resources Inc. is unwarranted and will have no material adverse effect on the Company's financial position or on the results of operations, no provision has been recorded in this respect. If the Company has to pay any amount in this affair, this amount will be paid by issuing reserved common shares, at a price of $6.00 per share. The maximum number of common shares that would have to be issued would be 666,118 shares, representing the full amount of the lawsuit or $3,996,713 in value.

Additionally, refer to Note 8 c), which outlines the Company's requirements to incur by December 31, 2007 flow-through share eligible Canadian Exploration Expenditures, as defined in the Income tax Act (Canada).

15. Related Party Transactions

A director and the corporate secretary of the Company are partners at a law firm that provides legal services to the Company. The services were conducted in the normal course of business operations and are measured at the exchange amount which is established and agreed to by the related parties based on standard rates, time spent and costs incurred. During the twelve month period ended December 31, 2006, the Company paid and accrued a total of $326 thousand to this firm for legal fees and disbursements (December 31, 2005: $59 thousand).

16. Comparative Balances

Certain of the comparative balances have been reclassified to conform to the current period's presentation.

17. Subsequent Event

On April 10 2007, the Company entered into a letter agreement with a Canadian chartered bank providing for a $60.0 million demand revolving operating credit facility ("Credit Facility"). The Credit Facility provides that advances may be made by way of direct advances, banker's acceptances, or standby letters of credit/guarantees. Direct advances bear interest at the bank's prime lending rate plus an applicable margin for Canadian dollar advances and at the bank's U.S. base rate plus an applicable margin for U.S. dollar advances. The applicable margin charged by the bank is dependent on the Company's debt-to-trailing cash flow ratio. The banker's acceptances bear interest at the applicable banker's acceptance rate plus a stamping fee, based on the Company's debt-to-trailing cash flow ratio. The Credit Facility is secured by a fixed and floating charge debenture on the assets of the Company. The borrowing base is subject to semi-annual review by the bank.

The TSX Venture Exchange does not accept responsibility for the adequacy or accuracy of this news release.

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