Orleans Energy Ltd.
TSX VENTURE : OEX

Orleans Energy Ltd.

March 19, 2008 17:30 ET

Orleans Energy Announces 2007 Financial Results

CALGARY, ALBERTA--(Marketwire - March 19, 2008) - Orleans Energy Ltd. ("Orleans" or the "Company") (TSX VENTURE:OEX) is pleased to announce its results for the year ended December 31, 2007. Highlights of the Company's third year of active oil and gas operations are outlined as follows:



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Quarterly Comparison
Financial Highlights Three Month Period Ended,
(6:1 oil equivalent Dec. 31, Sep. 30, Jun. 30, Mar. 31,
conversion) 2007 2007 2007 2007
------------ ----------- ----------- -----------
(amounts in Cdn.$ except
share data)
Petroleum and natural gas
revenue (6) 13,412,861 11,904,704 11,635,732 12,187,656
Per share - basic 0.36 0.32 0.35 0.37
- diluted 0.35 0.32 0.34 0.36
Cash flow from
operations (1) 5,624,646 4,491,667 5,143,032 6,066,434
Per share - basic 0.15 0.12 0.16 0.18
- diluted 0.15 0.12 0.15 0.18
Operating netback (2)
($/boe) 24.27 20.29 28.35 32.09
Corporate netback (2)
($/boe) 19.52 16.27 22.97 26.10
Net loss (3,5) (2,095,503) (3,073,828) (128,025) (912,767)
Per share - basic (0.06) (0.08) - (0.03)
- diluted (0.06) (0.08) - (0.03)
Net debt (4)- period end 48,188,497 44,537,047 53,181,270 48,403,405
Weighted average basic
shares 37,571,100 37,014,430 33,209,828 33,148,659
Weighted average diluted
shares 38,019,052 37,526,046 33,833,429 33,743,616
Issued and outstanding
shares (7) 37,571,372 37,546,372 33,225,889 33,148,659
Operating Highlights
Average daily production:
Natural gas (mcf/d) 14,655 14,002 10,673 10,665
Liquids (Oil & NGLs)
(bbls/d) 689 668 681 805
Oil equivalent (boe/d) 3,132 3,002 2,460 2,583
Average sales price (net
hedging) (6):
Natural gas ($/mcf) 6.78 6.11 7.79 8.01
Liquids (Oil & NGLs)
($/bbl) 67.40 65.76 65.61 62.07
Oil equivalent ($/boe) 46.55 43.11 51.97 52.43
E&D capital expenditures ($) 8,972,802 14,683,044 10,835,960 10,989,379
Total capital
expenditures ($) 9,483,866 15,146,269 10,209,005 11,417,668
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Annual Summary
Financial Highlights Year Year
(6:1 oil equivalent conversion) 2007 2006
----------- ------------
(amounts in Cdn.$ except share data)
Petroleum and natural gas revenue (6) 49,140,953 32,447,221
Per share - basic 1.39 1.33
- diluted 1.37 1.29
Cash flow from operations (1) 21,325,779 17,218,936
Per share - basic 0.60 0.71
- diluted 0.60 0.69
Operating netback (2) ($/boe) 25.68 31.06
Corporate netback (2) ($/boe) 20.90 26.96
Net loss (3,5) (6,210,123) (17,837,566)
Per share - basic (0.18) (0.73)
- diluted (0.18) (0.73)
Net debt (4)- period end 48,188,497 43,225,843
Weighted average basic shares 35,252,993 24,362,187
Weighted average diluted shares 35,772,226 25,136,494
Issued and outstanding shares (7) 37,571,372 33,148,659
Operating Highlights
Average daily production:
Natural gas (mcf/d) 12,514 6,406
Liquids (Oil & NGLs) (bbls/d) 710 682
Oil equivalent (boe/d) 2,796 1,750
Average sales price (net hedging) (6):
Natural gas ($/mcf) 7.06 6.95
Liquids (Oil & NGLs) ($/bbl) 65.10 65.00
Oil equivalent ($/boe) 48.15 50.80
E&D capital expenditures ($) 45,481,185 46,256,146
Total capital expenditures ($) 46,256,808 159,722,758
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Notes:
(1) 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.
(2) Operating netback represents average sales price less royalties,
operating costs and transportation expenses. Corporate netback
represents operating netback less general and administrative costs and
interest expense. Both measures are not recognized measures under
Canadian GAAP.
(3) Net loss includes: (i) non-cash income tax reductions and (ii) non-cash
goodwill impairment.
(4) Net debt refers to outstanding bank debt plus working capital deficit
(excludes current unrealized amounts pertaining to risk management
commodity contracts). Net debt is not a recognized measure under
Canadian GAAP.
(5) The reported net loss in Year 2006 includes a $16.62 million non-cash
goodwill impairment. This goodwill resulted from the acquisition of
Morpheus Energy Corporation in June 2006.
(6) Petroleum and natural gas revenue and pricing includes realized hedging
results from commodity contract settlements.
(7) Current common shares outstanding are 44,571,372, as a result of the
equity financing closed on March 13, 2008.


2007 Highlights

- Strong Internally-Generated "Drill Bit" Performance

Drilled 18 wells (15.8 net), on an exploration and development ("E&D") capital program of approximately $46 million, with an overall success rate of 100%. Operational momentum carry-forwarded into the new year with four (3.7 net) wells drilled in 2008 at various stages of completion.

- Significant Year-over-Year Production

Increased the Company's average daily production to 2,796 boe per day in 2007, a 60% increase from 1,750 boe per day in 2006. Exceeded its year-end exit production target of 3,500 boe per day. Fourth quarter 2007 production averaged 3,132 boe per day.

- Strong Revenue and Cash Flow Growth

Generated petroleum and natural gas revenues of $49.1 million in 2007, an increase of 51% over 2006. Cash flow from operations increased by 24% to $21.3 million.

- Land and Drilling Inventory Expansion in Core Focus Areas

In June 2007, significantly expanded its land holdings at Kaybob in West Central Alberta through a successful Alberta Crown land sale. Orleans acquired 11.5 sections (100% working interest) of land, doubling its ownership presence within the Kaybob asset base. Orleans has now amassed 27.5 (25.0 net) sections of key, concentrated lands providing for the exploration and development of a "deep basin", resource-style natural gas prospect in the Triassic Montney formation.

- Financial Flexibility

Additionally, in July 2007, closed a $20.2 million "bought-deal" equity financing, enabling the Company to selectively expand its capital expenditures in 2007 on strategic projects and further foster its financial flexibility. In April 2007, increased its operating credit facility to $60 million, transitioning its banking requirements to a major Canadian chartered bank.

Operations Update

As a result of a strong drilling program undertaken in 2007, Orleans' exceeded its forecasted year-end production exit target of 3,500 barrels of oil equivalent ("boe") per day. In 2007, the Company drilled 18 wells (15.8 net), yielding promising results, with all the well bores cased and completed, encompassing 13 gas wells and five oil wells. Orleans drilled wells across the majority of its focus areas, including: 10 gas wells (9.5 net) in Kaybob, three horizontal oil wells (3.0 net) in Leo, two gas wells (0.75 net) in Pine Creek, two oil wells (1.5 net) in Gordondale and one gas well (1.0 net) at Gilby. Thus far in 2008, the Company has drilled a total of four (3.7 net) wells, including three (2.7 net) horizontal wells in Kaybob and one (1.0 net) well in Gilby.

Kaybob, West Central Alberta

Throughout 2007, Orleans' primary focus was on its West Central Alberta Kaybob property, wherein the Company has expanded its land base from six sections (4.4 net) to 27.5 sections (25.0 net), via Crown land acquisitions and strategic farm-ins, focusing on the exploration and development of the "deep basin" resource-style natural gas prospect in the Triassic Montney formation. Currently, on 10 sections of land in Kaybob, the Company has approval to drill on reduced spacing up to three wells per section, and has applied for reduced spacing to three wells per section on its remaining 17.5 sections. Presently, Orleans has only one section of land where it is producing on reduced spacing from three wells.

The Company has undertaken a number of operational initiatives, including horizontal drilling along with the application of improved and larger fracture stimulation technology, utilizing the "Packer Plus" multi-stage fracture assembly. Orleans is also incorporating common lease pad drilling as a means to improve productivity and reserves recovery and minimize lease construction, pipeline costs and surface disturbance. The Company's first horizontal well (1.0 net), drilled in the fourth quarter of 2007, was stimulated with a five-stage fracture treatment including 150 tonnes of proppant being displaced along the horizontal section. The well was placed on-stream in December at an initial "flush" production rate of 3.8 mmcfe per day and an average daily production rate in the month of January 2008 of approximately 3.3 mmcfe per day.

In 2007, Orleans drilled a total of 10 (9.5 net) Montney gas wells, with seven (6.5 net) wells on-stream, and three (3.0 net) wells tested and awaiting tie-in. Thus far in 2008, the Company has drilled three (2.7 net) horizontal wells and is currently drilling an additional horizontal well (1.0 net). One (1.0 net) well has been completed and is currently being tested, and the other two horizontals drilled are awaiting completion. Orleans is very encouraged by the early completion results on the first horizontal well drilled on its Eastern Kaybob lands. The horizontal well was fracture stimulated in seven-stages with a total of 160 tonnes of proppant being displaced along the approximate 1,000 metre horizontal leg.

In 2008, Orleans intends to initially drill eight (6.7 net) horizontal wells on its Kaybob lands, with five (3.7 net) targeting the Western acreage block and three (3.0 net) on the Eastern block. The majority of these wells will be drilled off common lease pads, allowing for more rapid turnaround to on-stream production.

Leo, Central Alberta

Commencing in July 2007, Orleans drilled three (3.0 net) multi-leg horizontal wells in the light gravity crude (36 degree API) Upper Mannville D & E oil pools. The wells were brought on-stream in August of 2007, increasing the pool production in excess of 200 boe per day. In 2008, the Company intends to initiate a waterflood scheme to enhance oil production and reserves recoveries from the pool. The Company has an additional three (3.0 net) horizontal locations to drill in the pool.

Pine Creek, West Central Alberta

In the third quarter of 2007, the Company participated in the drilling of two (0.75 net) gas wells in joint venture with area partners, targeting deep Cretaceous-aged, multi-zone sweet natural gas. One well (0.25 net) was completed and commingled in four separate intervals and was brought on-stream in November. The second well (0.5 net) was completed in early 2008 and tested in three separate zones and is anticipated to be tied-in prior to the end of the first quarter of 2008.

Gilby, Central Alberta

In December 2007, the Company drilled a Gilby Edmonton Sand well (1.0 net), encountering multiple pay sections. This well was tied-in and brought on-stream mid-January 2008. Also in December, Orleans received approval to drill on reduced spacing, up to four wells per section on 14.5 sections of Company lands, yielding a future drilling inventory in excess of 40 Edmonton Sand wells. Orleans also received approval to drill on reduced spacing in the Mannville, allowing for three wells per section in the Glauconite formation and two wells per section in the Lower Mannville formation, across eight sections of Orleans' acreage.

Thus far in 2008, the Company drilled and cased a 100% working interest well with multi-zone potential in the Edmonton Sand, Glauconite and Ellerslie zones. The well is anticipated to be completed in the second quarter of 2008.

2008 Capital Budget and Market Guidance

As a result of the $25.2 million "bought-deal" equity financing, which closed on March 13, 2008, the Company intends to expand its 2008 capital investment budget. Orleans expects to provide details on its expanded 2008 capital expenditure plans in addition to updated market guidance on or about March 28, 2008.

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 financial statements for the year ended December 31, 2007 and the consolidated financial statements for the prior year ended December 31, 2006, available in printed form on request. Within this MD&A, the financial and operating results for the year ended December 31, 2007 ("Year 2007") is compared to the prior year ended December 31, 2006 ("Year 2006").

In this MD&A, production and reserves 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 shareholders and/or 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 changes in non-cash operating activities 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 March 18, 2008.

Business Overview

Orleans Energy Ltd. is an independent, Alberta-based crude oil and natural gas company actively engaged in the exploration for, development and production of natural gas, crude oil and natural gas liquids reserves within the province of Alberta. 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". As of the March 18, 2008, Orleans' market capitalization is approximately $160 million. Current production is weighted approximately 80% natural gas and 20% light oil and NGLs. The Company's production base is generated from five core producing areas throughout Central Alberta (Gilby and Halkirk/Leo), West Central Alberta (Kaybob and Pine Creek) and the Peace River Arch (Gordondale). 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 57,000 acres of high working interest (81%) undeveloped acreage offering geologic play diversity, (iii) a long-life, proved plus probable reserves base at December 31, 2007 of approximately 13.72 million boe with a reserve life index exceeding 10 years and, (iv) an operated production base allowing for year-round access.



Selected Period End and Quarterly Financial Information

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2007 Quarterly Comparison Annual Summary
----------------------------------- -----------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
-------- -------- -------- -------- -------- --------

Petroleum & natural
gas revenue (1) 13,413 11,905 11,635 12,188 49,141 32,447
Cash flow from
operations 5,625 4,492 5,143 6,066 21,326 17,219
Net loss (2,096) (3,074) (128) (913) (6,210) (17,838)
Total assets - period
end 203,751 201,795 194,076 191,627 203,751 188,325
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2006 Quarterly Comparison
--------------------------------------
($000s) Q406 Q306 Q206 Q106
-------- --------- --------- ---------

Petroleum & natural gas revenue (1) 11,038 9,777 5,912 5,720
Cash flow from operations 5,461 5,219 3,362 3,177
Net earnings (loss) (17,006) (128) (1,346) 642
Total assets - period end 188,325 192,609 180,598 55,109
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(1) Petroleum & natural gas revenue includes realized hedging results from
commodity contract settlements.


The following commentary will assist in providing the reader with factors that have caused variations over the aforementioned quarterly and annual results.

Petroleum and Natural Gas Production

For the year ended December 31, 2007, the Company's natural gas production averaged 12,514 mcf per day and crude oil and NGLs production averaged 710 bbls per day, resulting in a combined oil equivalent average daily rate of 2,796 boe per day. The execution of a successful drilling program in 2007 enabled the Company to increase its average daily production by 60% over the 1,750 boe per day generated in the prior year ended December 31, 2006. In 2007, Orleans drilled 18 wells (15.8 net). The Company's drilling program in 2007 yielded very favourable results, with 100% of the well bores cased and completed, encompassing 13 gas wells and five oil wells. During the fourth quarter ended December 31, 2007, the Company's average daily oil equivalent production was 3,132 boe per day, weighted 78% towards natural gas and 22% percent light gravity crude oil and NGLs. On an oil-equivalent basis, Orleans' crude oil and natural gas sales volumes increased by 4% as compared to the preceding third quarter ended September 30, 2007.



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Average Daily Production Natural Gas Crude Oil & NGLs Oil Equivalent
(mcf/d) (bbls/d) (boe/d)
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Q105 1,404 325 559
Q205 2,385 435 832
Q305 3,231 662 1,200
Q405 4,160 685 1,378
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Calendar Year 2005 2,804 528 995
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Q106 3,426 576 1,147
Q206 4,334 552 1,274
Q306 8,349 789 2,181
Q406 9,428 809 2,380
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Calendar Year 2006 6,406 682 1,750
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Q107 10,665 805 2,583
Q207 10,673 682 2,460
Q307 14,002 668 3,002
Q407 14,655 689 3,132
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Calendar Year 2007 12,514 710 2,796
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Area Natural Gas Crude Oil & NGLs Oil Equivalent
(mcf/d) (bbls/d) (boe/d)
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Halkirk/Leo 2,304 437 821
Gilby/Medicine River 3,394 154 720
Pine Creek 1,831 54 359
Kaybob 3,819 43 679
Pembina 623 - 104
Gordondale/Grimshaw 543 22 113
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Year 2007 12,514 710 2,796
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Petroleum and Natural Gas Revenue and Commodity Pricing

Orleans' petroleum and natural gas revenues may vary significantly from period-to-period as a result of changes in commodity prices and/or production volumes. The Company's 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 its control. Historically, these prices have been volatile and unpredictable.

Orleans takes the majority of its working interest production "in kind" and it is marketed and sold through various commodity purchasers. Orleans' crude oil is marketed under short-term evergreen contract with a major North American crude oil marketer and purchaser. Orleans' crude oil has an average stream gravity of approximately 35 degrees to 39 degrees API. A majority of Orleans' natural gas sales are sold as spot gas through a significant North American natural gas marketer.

The Company's crude oil price, including the effect of realized commodity contract settlements, averaged $67.04 per barrel in the year ended December 31, 2007, an increase of approximately 1% from the oil price of $66.65 per barrel realized in the prior year. Orleans' natural gas price realization in 2007 was marginally higher than the previous year of $6.95 per mcf, averaging $7.06 per mcf, with an average high of $8.72 per mcf in March 2007 and a monthly average low of $6.03 per mcf in September 2007.

The Company's total petroleum and natural gas revenue for the three-month period ended December 31, 2007 amounted to $13.41 million, representing a 22% increase from the corresponding fourth quarter 2006 sales amount of $11.04 million. Increased production volumes were the primary reason for higher realized revenues in the fourth quarter of 2007 vis-a-vis the same quarter in 2006.

As a result of a marked increase in the Company's oil and gas production in 2007, Orleans' aggregate petroleum and natural gas revenue for year ended December 31, 2007, including the impact of realized hedging activities, amounted to $49.14 million as compared to $32.45 million generated in the prior year.



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2007 Quarterly Comparison
----------------------------
($000s) Q407 Q307 Q207 Q107 Year 2007 Year 2006
------ ------ ------ ------ --------- ----------
(includes realized hedging)
Crude oil & NGLs revenue 4,274 4,040 4,069 4,497 16,880 16,188
Natural gas revenue 9,139 7,865 7,566 7,691 32,261 16,259
------ ------ ------ ------ --------- ----------
Gross revenue 13,413 11,905 11,635 12,188 49,141 32,447
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Commodity Price Risk Management

The prices the Company receives for its crude oil and natural gas production may have a significant impact on its revenues and cash flow from operations. Any significant price decline in commodity prices would adversely affect the amount of funds available for capital reinvestment purposes. As such, Orleans utilizes a risk management program to partially mitigate that risk and to ensure adequate funds are available for planned capital activities and other commitments. As such, from time to time, the Company may employ derivative financial instruments and physical arrangements, primarily commodity price contracts, to manage fluctuations in oil and gas market prices, which are generally put in-place with investment grade counter-parties that Orleans believes present minimal credit risks. The Company does not utilize derivative financial instruments for speculative trading purposes.

Orleans periodically uses swaps and collars to hedge crude oil and natural gas prices. Commodity swaps are settled monthly based on differences between the prices specified in the financial instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Orleans receives a settlement from the counter-party based on the difference multiplied by the volume hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Orleans pays the counter-party based on the difference. The Company generally receives a settlement from the counter-party for collars when the applicable settlement price is less than the floor price specified in the contract and pays a settlement to the counter-party when the settlement price exceeds the cap or ceiling. No settlement occurs when the settlement price falls between the floor and ceiling.

Consequently, Orleans' realized petroleum and natural gas sales are impacted by the settlement of these transactions. The various hedge contracts in-place throughout 2007 resulted in a realized net gain of $1.29 million (2006: $344 thousand), comprised of a $1.55 million increase in natural gas revenue ($0.34 per mcf) and a $260 thousand decrease in crude oil and NGLs sales ($1.00 per bbl).



The following table outlines the realized results of the Company's commodity
price risk management activities in 2007:

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Year 2007 Year 2006
------------- --------------
Crude oil gain (loss) $ (260,304) $ 344,232
Natural gas gain 1,550,402 -
----------------------------
Realized gain (loss) on commodity contracts $ 1,290,098 $ 344,232
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As further described in Note 3 to the financial statements for the year ended December 31, 2007, the Company recognizes the fair value of its commodity contracts on the balance sheet each reporting period with the change in fair value being recognized as an unrealized gain or loss on the statement of operations. On January 1, 2007 the fair value of the commodity contracts was an asset of $605,903 and resulted in an increase to accumulated other comprehensive income and future tax liability of $425,405 and $180,498, respectively. The entire amount recognized in accumulated other comprehensive income was fully amortized over the term of the contracts in 2007 through other comprehensive income with a corresponding unrealized gain on financial instruments on the statement of operations. As a result, $425,405 net of tax, was charged during the year to other comprehensive income with a corresponding unrealized gain on financial instruments of $605,903 and a charge to future income tax liability of $180,498. As at December 31, 2007, the fair value of the financial commodity contracts was a liability of approximately $432 thousand, resulting in an unrealized loss for the year of $432,470, net of the aforementioned unrealized gain of $605,903.



The following table reconciles the Company's unrealized gain (loss) on
commodity contracts:
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Year Ended Year Ended
December 31, 2007 December 31, 2006
------------------ ------------------
Change in fair value of commodity
contracts $ (1,038,373) $ -
Unrealized gain charged to
accumulated other comprehensive
income 605,903 -
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Unrealized gain (loss) on
commodity contracts $ (432,470) $ -
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The following table outlines the financial commodity price contracts that
were outstanding as at December 31, 2007, in addition to commodity contracts
entered into subsequent to December 31, 2007.

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Daily
Notional
Commodity Contract Date Type Term Volume Index Price
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Jan '08 - US$ 81.56
Crude Oil Oct. 15, 2007 Swap Jun '08 200 bbls W.T.I. /bbl
Jul '08 - US$ 90.00 -
Crude Oil (1) Mar. 3, 2008 Collar Dec '08 100 bbls W.T.I. $116.25/bbl
Nov '07 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.545/GJ
Jan '08 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.71/GJ
Jan '08 -
NatGas Oct. 31, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.67/GJ
Apr '08 -
NatGas Dec. 18, 2007 Swap Dec '08 2,000 GJs AECO-C C$ 6.55/GJ
Apr '08 -
NatGas (1) Jan. 2, 2008 Swap Dec '08 2,000 GJs AECO-C C$ 6.81/GJ
Apr '08 -
NatGas (1) Jan. 4, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.61/GJ
Apr '08 -
NatGas (1) Jan. 7, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.72/GJ
Apr '08 -
NatGas (1) Jan. 10, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.01/GJ
Nov '08 - C$ 7.00 -
NatGas (1) Feb. 13, 2008 Collar Mar '09 2,000 GJs AECO-C $9.70/GJ
Apr '08 -
NatGas (1) Feb. 14, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.52/GJ
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(1) These contracts were entered into subsequent to December 31, 2007.


The following table highlights Orleans' corporate realized commodity prices
as well as market prices:
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2007 Quarterly Comparison
---------------------------- Year Year
Q407 Q307 Q207 Q107 2007 2006
------ ------ ------ ------ ------- -------
Orleans' prices (1):
Natural gas ($/mcf) 6.78 6.11 7.79 8.01 7.06 6.95
Crude oil and NGLs ($/bbl) 67.40 65.76 65.61 62.07 65.10 65.00
Oil equivalent ($/boe) 46.55 43.11 51.97 52.43 48.15 50.80
Industry benchmark prices:
WTI Cushing oil (US$/bbl) 90.49 75.22 64.95 58.09 72.41 66.09
Edmonton Par oil ($/bbl) 86.89 80.67 72.69 67.61 76.17 73.25
Nymex gas (US$/mmbtu) 7.39 6.24 7.65 7.18 6.83 6.98
AECO gas ($/mcf) 6.01 5.07 6.94 7.26 6.85 6.38
Exchange rate (US$/C$) 1.0198 0.9562 0.9111 0.8534 0.9311 0.8817
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(1) Orleans' reported prices include realized commodity contract
settlements.


Petroleum and Natural Gas Royalties

The Company's petroleum and natural gas royalties for the year ended December 31, 2007 amounted to $9.26 million, resulting in a corporate effective royalty rate of 19%. Approximately 68% of Orleans' total royalties for 2007 relate to Crown royalties with the residual 32% attributable to freehold and overriding royalty encumbrances. The royalty rate in 2007 was marginally higher than the rate realized in the prior year ended December 31, 2006 due to a higher weighting of production derived from Crown lands vis-a-vis freehold acreage. Typically, effective royalty rates associated with production on Crown lands is higher than that of freehold-based production. During the fourth quarter of 2007, total royalties amounted to $2.5 million, resulting in a corporate effective royalty rate of 19%.

On October 25, 2007, the Alberta government released The New Royalty Framework report which summarizes the government's decisions on Alberta's new royalty regime. The Alberta government's changes to their royalty structure on all Crown mineral rights owned by the Province of Alberta and leased by oil and gas producers such as Orleans is scheduled to take effect on January 1, 2009 upon legislation enactment. The Company is currently awaiting finalization of the royalty implementation regulations, however, it expects that its 2009 and thereafter Alberta Crown royalty payments will increase as a result of the proposed royalty changes. Please refer to the section New Alberta Royalty Regime contained within hereafter.



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2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------

Crown (net ARTC) 1,706 1,703 1,363 1,508 6,280 3,106
Freehold and overrides 795 795 611 780 2,981 2,618
------- ------- ------- ------- ------- -------
Total 2,501 2,498 1,974 2,288 9,261 5,724
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------

Corporate royalty rate (%) 19% 21% 17% 19% 19% 18%
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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 components, 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 elements of operating expenses have been increasing throughout the oil and gas industry for several years due to industry inflationary pressures.

The Company's total field operating expenses for the year ended December 31, 2007 amounted to $12.58 million or $12.32 on an oil-equivalent per unit basis. In addition to inflationary pressures exerted on Orleans' operating cost profile, a higher level of well-bore production optimization activity and the off-lined production at Gordondale for seven and one-half months in 2007 resulted in a sharp per-unit increase in field production costs vis-a-vis the year ended December 31, 2006 of $9.89 per boe. In 2007, in comparison to the prior year, the Company was very active with well-bore maintenance activity, resulting in higher per-unit operating costs. At Gordondale, Orleans incurred fixed operating costs throughout 2007 despite the complete curtailment of production from this field due to the main sales gas pipeline being offline, between May 1 and November 29, and for the balance of the year December 18, 2007 thereafter. Shut-in production during 2007 at Gordondale contributed to the higher per-unit operating costs, thus placing upward pressure on fiscal 2007 operating costs.

In the fourth quarter of 2007, Orleans' field production costs on an oil-equivalent basis were $12.57 per boe, a marginal reduction from the per-unit cost of $12.79 realized in the preceding quarterly period ended September 30, 2007. The off-line production at Gordondale continued to negatively impact the Company's per-unit operating costs in the quarter. Orleans incurred fixed operating costs at Gordondale throughout the fourth quarter despite the curtailment of production from this field for most of the fourth quarter due to the main sales gas pipeline being off-line.



----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------

Total ($000s) 3,621 3,531 3,046 2,378 12,576 6,316
------- ------- ------- ------- ------- -------
Per unit ($/boe) 12.57 12.79 13.61 10.23 12.32 9.89
----------------------------------------------------------------------------


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, 2007 amounted to $1.1 million or $1.08 on an oil-equivalent per unit basis. Increased production volumes, supplemented with increased clean oil trucking rates and Nova gas pipeline fuel surcharges throughout 2007 resulted in transportation cost increases on an aggregate and per-unit basis.



----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------

Total ($000s) 299 274 269 255 1,098 568
Per unit ($/boe) 1.04 0.99 1.20 1.10 1.08 0.89
----------------------------------------------------------------------------


General & Administrative Expenses

The Company's general and administrative ("G&A") expenses during the year ended December 31, 2007, excluding the non-cash stock-based compensation provision, amounted to $2.19 million or $2.15 on an oil-equivalent per unit basis. In the fourth quarter of 2007, expensed G&A amounted to $651 thousand, as compared to $484 thousand incurred in the third quarter of 2007. Gross G&A, net of operator recoveries, increased by $373 thousand in the fourth quarter over the third quarter of 2007 as a result of accrued costs associated with the year-end independent engineering reserves report and the annual financial statement accounting audit, in addition to year-end performance bonuses paid to employees. Orleans presently employs 17 head office personnel, an increase from 11 staff members employed this time last year, including eight geological and engineering technical personnel. The Company also engages the services of three consultants on a part-time, as needed, basis. In April 2007, the Company took occupancy of its new head office premises, in order to accommodate the expanded office operations necessary to effectively and efficiently manage the Company's larger asset base.

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 $1.01 million during the year ended December 31, 2007 (December 31, 2006: $623 thousand)



----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------

Gross, net of operator
recoveries 1,037 664 757 744 3,202 2,013
Capitalized (386) (180) (241) (204) (1,011) (623)
------- ------- ------- ------- ------- -------
Expensed 651 484 516 540 2,191 1,390
------- ------- ------- ------- ------- -------
Per unit ($/boe) 2.26 1.75 2.30 2.32 2.15 2.18
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
% Capitalized 37% 27% 32% 27% 32% 31%
----------------------------------------------------------------------------


Stock-Based Compensation

Orleans utilizes the fair value method for measuring stock-based compensation expenses. Compensation cost is measured at the grant date based on the fair value of the option using a Black-Scholes option pricing model and is recognized over the option vesting period. Some of the inputs to the option valuation model are subjective, including assumptions regarding expected stock price volatility. The Company's stock-based compensation relates entirely to the granting of stock options. During the year ended December 31, 2007, the Company recorded stock-based compensation expense of $729 thousand (2006: $555 thousand), which was charged to general and administration expense and presented as such on the Company's statement of operations. In 2007, the Company capitalized $905 thousand of its stock-based compensation charges (2006: $720 thousand). As of December 31, 2007, total unrecognized compensation cost of $2.43 million, related to 1.97 million unvested Orleans' stock options, is expected to be recognized in future periods over the remaining vesting terms.

Interest Charges

During the year ended December 31, 2007, Orleans incurred $2.46 million in interest charges relating to its outstanding bank indebtedness, net of $32 thousand of interest income. As at December 31, 2007, the Company had $44.14 million of bank debt, as compared to $38.78 million of outstanding bank indebtedness at December 31, 2006. Orleans' bank debt increased in 2007 primarily as a result of exploration and development capital investments exceeding its generated cash flow from operations. In addition to bank debt interest incurred in 2007, the Company accrued for the federal government's levied interest charges related to Orleans' November 2006 flow-through financing exploration expenditure deductions, previously renounced under the "look back" rules. In 2007, this interest charge was accrued in the amount of $198 thousand and was disbursed in the first quarter of 2008.

In the fourth quarter of 2007, Orleans incurred $645 thousand in interest expenses relating to the debt servicing of its outstanding bank indebtedness and accrued $36 thousand for the aforementioned November 2006 flow-through financing, the federal government's levied interest charges.



----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------

Interest charges (net
interest income) 681 626 688 660 2,655 1,231
----------------------------------------------------------------------------


Depletion, Depreciation and Accretion

Orleans' depletion and depreciation expense for the year and three month periods ended December 31, 2007 amounted to $28.82 million and $7.80 million, respectively. On a unit-of-production rate basis, the depletion and depreciation provision for year ended December 31, 2007 was $28.24 per boe, as compared to the $26.04 per boe provision recognized for the year ended December 31, 2006.

The depletion and depreciation rate is a useful measure for evaluating finding and development costs on proved reserves basis since the rate generally considers all acquisition, exploration and development capital costs. The rate also considers any additional future development costs associated with proved non-producing reserves. Orleans' ability to efficiently discover and develop proved oil and gas reserves in a cost-effective manner is reflected in the Company's decreasing depletion and deprecation rate provision throughout 2007. Orleans' depletion and deprecation rate in the first quarter of 2007 was $28.68 per boe (excluding ARO accretion), decreasing to $27.08 per boe for the fourth quarter ended December 31, 2007.

The Company's accretion expense relating to its asset retirement obligations ("ARO") amounted to $465 thousand for the year ended December 31, 2007 and $111 thousand for the fourth quarter of 2007.



----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------

Depletion & depreciation (1) 7,802 7,753 6,602 6,666 28,823 16,633
ARO accretion (2) 111 120 118 116 465 353
Total 7,913 7,873 6,720 6,782 29,288 16,986
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Per unit ($/boe) 27.46 28.51 30.02 29.18 28.70 26.59
----------------------------------------------------------------------------

(1): Includes depletion of the capitalized portion of the asset retirement
obligation which was capitalized to the PP&E balance and is being
depleted over the life of the Company's proved reserves.

(2): Represents the accretion expense on the asset retirement obligation
during the year.


Ceiling Test

Orleans calculates a ceiling test whereby the carrying value of property, plant and equipment ("PP&E") is compared to estimated future cash flow from production of proved reserves. The ceiling test is performed under a two-step process in accordance with the requirements of the Canadian Institute of Chartered Accountants ("CICA") AcG-16 "Oil and Gas Accounting - Full Cost". The Company performed a ceiling test calculation as at December 31, 2007, resulting in undiscounted cash flows from proved reserves and the unproved properties not exceeding the carrying value of its PP&E. Consequently, Orleans performed step two of the ceiling test assessing whether discounted future cash flows from the production of proved plus probable reserves plus the carrying cost of unproved properties, net of any impairment allowance, exceeds the carrying value of its PP&E. Based on the step two ceiling test calculation results, no write-down of the Company's carrying value of PP&E was required as at December 31, 2007.

Asset Retirement Obligations

As at December 31, 2007, Orleans recorded an ARO of $5.45 million for estimated future costs to plug and abandon the Company's oil and gas wells and to dismantle and remove associated production facilities, as compared to $5.02 million at December 31, 2006. For the year ended December 31, 2007, the ARO liability increased by a total of $431 thousand as a result of accretion expense of $465 thousand, $185 thousand in liabilities incurred on development drilling activities, offset by $186 thousand of liabilities released on property dispositions and $33 thousand on an ARO liability settlement.

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 PP&E carrying value. For the year ended December 31, 2007, the Company recorded a future income tax reduction of $2.88 million, as compared to an $895 thousand income tax expense recognized in year ended December 31, 2006. During the year ended December 31, 2007, the Company's effective future income tax rate was reduced primarily due to income tax rate reductions enacted or substantively enacted in Canada during both the second and fourth quarters of 2007, and adjustments to future tax expense related to the final phase-in of 100% deductibility of Crown royalties and the elimination of the Federal resource allowance in 2007.

During the year ended December 31, 2007, Orleans was not subject to any corporate income tax due to the Company's significant tax pool balances, which aggregate to approximately $175 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. The following table outlines Orleans' tax pools as at December 31, 2007:



----------------------------------------------------------------------------
Access Rate Balance
($ millions)
----------------------------------------------------------------------------
Canadian exploration expense (CEE) 100% $ 30.5
Canadian development expense (CDE) 30% 53.1
Canadian oil and gas property expense (COGPE) 10% 35.7
Undepreciated capital cost (UCC) 25% 41.6
Non-capital losses (NCL) 100% 8.3
Share issue costs and other 20% 5.9
----------------------------------------------------------------------------
Total $ 175.1
----------------------------------------------------------------------------


Reconciliation of Non-GAAP Measures

----------------------------------------------------------------------------
($000s except share data) Year 2007 Year 2006
----------------------------------------------------------------------------
Net loss (6,210) (17,838)
Non-cash items:
Depletion & depreciation 28,823 16,633
ARO accretion 465 353
Stock-based compensation 729 555
Unrealized loss on commodity contracts 432 -
Future income taxes (reduction) (2,880) 895
Goodwill impairment - 16,620
Asset retirement expenditures (33) -
----------------------------------------------------------------------------
Cash flow from operations 21,326 17,219
----------------------------------------------------------------------------
Per share - basic 0.60 0.71
----------------------------------------------------------------------------


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, 2007, Orleans recorded $21.33 million in cash flow from operations and posted a net loss of $6.21 million. As compared to the prior 2006 year of generated cash flow of $17.22 million and a recorded net loss of $17.84 million, which included the non-cash, goodwill impairment charge of $16.62 million.



----------------------------------------------------------------------------
($000s except 2007 Quarterly Comparison
share data) Q407 Q307 Q207 Q107 Year 2007 Year 2006
----------------------------------------------------------------------------
Cash flow from
operations (1) 5,625 4,492 5,143 6,066 21,326 17,219
Per share -
basic 0.15 0.12 0.16 0.18 0.60 0.71
Per share -
diluted 0.15 0.12 0.15 0.18 0.60 0.69
Net loss (2,095) (3,074) (128) (913) (6,210) (17,838)
Per share -
basic (0.06) (0.08) - (0.03) (0.18) (0.73)
Per share -
diluted (0.06) (0.08) - (0.03) (0.18) (0.73)
----------------------------------------------------------------------------

(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 involve 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.

In the year ended December 31, 2007, the Company's total capital investment expenditures amounted to $46.26 million. Collectively in 2007, the Company drilled 18 wells (15.8 net), of which only three (1.25 net) were non-operated. Orleans drilled wells across the majority of its focus areas, including: 10 gas wells (9.5 net) in Kaybob, three horizontal oil wells (3.0 net) in Leo, two gas wells (0.75 net) in Pine Creek, two oil wells (1.5 net) in Gordondale and one gas well (1.0 net) at Gilby. Additionally, in June 2007, the Company significantly expanded its land holdings at Kaybob in West Central Alberta through successful participation at a strategic Alberta Crown land sale. Orleans acquired 11.5 sections (100% working interest) of land for $5.64 million, essentially doubling its ownership presence at Kaybob.

Orleans continued to be active with the drill bit in the fourth quarter of 2007, incurring approximately $6.4 million of drilling and completion expenditures through the drilling five wells (4.5 net), including two gas wells brought on-stream in December 2007 and January 2008 and three gas wells awaiting tie-in.

Orleans' 2007 capital investment program enabled the Company to expand its total proved plus probable oil and gas reserves to 13.7 million boe at December 31, 2007 from 11.4 million boe at December 31, 2006, resulting in a 2007 finding and development cost of $19.20 per proved plus probable boe (includes change in undiscounted future development costs).

Orleans' management closely monitors the exploration and development capital program in relation to estimated cash flow from operations and expects to incur capital expenditures initially of approximately $30 million, excluding acquisitions, during 2008. Please refer to the section 2008 Business Outlook contained within hereafter. Actual spending may vary due to a variety of factors, including drilling results, natural gas and oil prices, economic conditions, equipment availability, permitting 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.



The breakdown of Orleans' capital programs are outlined below:
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Land 60 430 5,691 37 6,218 6,608
Seismic 70 - (33) 260 297 558
Drilling & completions 6,369 11,215 3,780 6,728 28,092 29,788
Facilities & well
equipment 2,473 3,038 1,398 3,965 10,874 9,302
------- ------- ------- ------- ------- -------
Exploration & development 8,972 14,683 10,836 10,990 45,481 46,256
------- ------- ------- ------- ------- -------
Other (1) 661 463 512 428 2,064 1,469
Property purchases
(dispositions) (150) - (1,139) - (1,289) 1,180
Corporate acquisitions (2) - - - - - 110,817
------- ------- ------- ------- ------- -------
Total capital expenditures 9,483 15,146 10,209 11,418 46,256 159,722
----------------------------------------------------------------------------

(1): Year 2007 includes capitalized G&A of $1.01 million (2006: $623
thousand) and non-cash capitalized stock-based compensation of $905
thousand (2006: $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, 2007: nil). 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, 2007, the Company was capitalized with a working capital deficit of $48.19 million (December 31, 2006: $43.23 million), including bank debt of $44.14 million (December 31, 2006: $38.78 million) and 37.57 million common shares outstanding with a book capitalization of $137.73 million and a market capitalization of approximately $83 million.



----------------------------------------------------------------------------
2007 Quarter End Comparison
($000) Dec. 31 Sep. 30 Jun. 30 Mar. 31
----------------------------------------------------------------------------
Bank debt 44,137 34,794 53,281 47,333
Working capital
deficit / (surplus) (1) 4,052 9,743 (99) 1,070
----------------------------------------------------------------------------
Net Debt 48,189 44,537 53,182 48,403
----------------------------------------------------------------------------
Book capitalization (2) 137,732 137,736 118,329 118,231
Market capitalization (3) 83,033 102,877 132,239 122,650
----------------------------------------------------------------------------

(1): Reflects current assets (excluding non-cash commodity risk management
asset) less current liabilities (excluding non-cash commodity risk
management liability and outstanding bank debt).
(2): Reflects the book value of share capital, as reported on the
Company's respective balance sheets.
(3): Based on the market closing price of Orleans stock and the outstanding
number of common shares at period-end.


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.

At December 31, 2007, the Company had borrowings of $44.14 million (December 31, 2006: $38.78 million) under its bank facility with a Canadian chartered 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 2007, as compared to year-end 2006, is attributable to capital investments incurred in 2007 exceeding the cash generated through operating activities within that period.

On July 12, 2007, the Company closed a "bought-deal" equity financing (the "2007 Financing"). Pursuant to the 2007 Financing, Orleans issued 1.5 million flow-through common shares at a price of $5.45 per share and 2.8 million common shares at a price of $4.30 per share, for total gross proceeds of $20,215,000. Proceeds from the flow-through share component of the 2007 Financing, in the amount of $8,175,000, will be used to incur Canadian exploration expenditures prior to December 31, 2008, with such expenditures to be renounced to the subscribers of the flow-through common shares in the fiscal year ended December 31, 2007.

On March 13, 2008, the Company closed a "bought-deal" equity financing (the "2008 Financing"). Pursuant to the terms of the 2008 Financing, the Company issued 7.0 million common shares at a price of $3.60 per share for total gross proceeds of $25.2 million.

With respect to the asset-backed commercial paper ("ABCP") market liquidity issues, which occurred during the third quarter of 2007 in the global credit markets as a result of the deterioration of the U.S. sub-prime mortgage market and resulted in numerous companies, including those within the oil and gas sector, not being able to access their funds when the ABCP became ordinarily due, the Company has never held funds in ABCP and is not directly impacted by the current market liquidity crunch.

In 2008, as in 2007, 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

----------------------------------------------------------------------------
2007 Quarterly Comparison Year Year
Q407 Q307 Q207 Q107 2007 2006
----------------------------------------------------------------------------
Share
Price: High $ 3.10 $ 4.00 $ 4.55 $ 4.05 $ 4.55 $ 6.99
Low $ 2.05 $ 2.54 $ 3.53 $ 2.75 $ 2.05 $ 3.37
Close $ 2.21 $ 2.74 $ 3.98 $ 3.70 $ 2.21 $ 3.45
Avg. daily
trading
volume(1) 90,524 49,887 89,663 64,247 73,732 43,145
Shares
outstanding
- period
end(2) 37,571,372 37,546,372 33,225,889 33,148,659 37,571,372 33,148,659
Weighted
average
basic 37,571,100 37,014,430 33,209,828 33,148,659 35,252,993 24,362,187
Weighted
average
diluted 38,019,052 37,526,046 33,833,429 33,743,616 35,772,226 25,136,494
----------------------------------------------------------------------------


(1): The common shares of Orleans commenced trading on the TSX Venture
Exchange on January 31, 2005. In 2008, the Company intends to
undertake the process of graduating the listing of its common shares
to the Toronto Stock Exchange ("TSX"). It is anticipated the listing
of Orleans' common shares on the TSX will provide the Company with
access to Canada's largest stock exchange while enhancing Orleans'
trading liquidity and visibility within the North American capital
markets. This graduation process to the TSX is expected to be
finalized in the second quarter of 2008.
(2): As of the date of this MD&A, total common shares issued and
outstanding are 44,571,372.


Orleans has never paid cash dividends on its common stock. The Company presently intends to retain any earnings for the operation and expansion of its business and does not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of the Company's operations, capital investment requirements, Orleans' financial condition and such other factors the Company's board of directors may deem relevant. In addition, the Company is restricted under its bank credit facility from paying or declaring cash dividends.

Commitments Obligations and Commitments

In the normal course of business, the Company has entered into various commitments that will have an impact on Orleans' future operations. These commitments primarily relate to debt repayments, operating leases relating to head office space and natural gas field equipment and drilling rig contractual obligations. The following table summarizes the Company's various contractual obligations and commitments as at December 31, 2007:



----------------------------------------------------------------------------
($000s) Less than 1 - 3 Years 4 - 5 Years Beyond 5
1 Year Years Total
----------------------------------------------------------------------------
Bank debt (1) 44,137 - - - 44,137
Head office lease
obligations (2) 649 1,979 1,360 227 4,215
Field equipment
operating leases (3) 254 20 - - 274
Drilling contract (4) 371 - - - 371
----------------------------------------------------------------------------
Total obligations 45,411 1,999 1,360 227 48,997
----------------------------------------------------------------------------

(1): Demand revolving operating credit facility with a Canadian chartered
bank. Refer to Note 8 to the financial statements for the year ended
December 31, 2007. This facility has no specific terms of repayment
aside from the bank's right of demand and periodic review.
(2): Pertains to lease payments associated with the Company's Calgary,
Alberta head office lease entered into on February 16, 2007, including
an estimate of the Company's share of operating, utilities, property
taxes and parking for the duration of the office lease.
(3): Pertains to various monthly and short-term operating leases for nine
field natural gas compressors and one separator.
(4): The Company has committed to a short-term drilling program with a
major drilling contractor. As at December 31, 2007, the Company is
obligated to utilize the contractor's rig for a period of
approximately 44 days, prior to April 30, 2008.


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 10 c) to the financial statements for the year ended December 31, 2007, which outlines the Company's requirements to incur by December 31, 2008 flow-through share eligible Canadian Exploration Expenditures, as defined in the Income tax Act (Canada).

Off-Balance Sheet Arrangements

The Company has no off-balance sheet arrangements, special purpose entities, financing partnerships or guarantees, other than as disclosed in this section. Orleans has certain lease agreements, as disclosed in the aforementioned Contractual Obligations and Commitments table, which were entered into in the normal course of business operations. All leases have been treated as operating leases or rental arrangements whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases on the balance sheet as at December 31, 2007.

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, 2007, Orleans paid and accrued a total of $133 thousand to this firm for legal fees and disbursements (December 31, 2006: $326 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, 2007. 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, 2007, 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.

Change in Accounting Policies

The following standards regarding financial instruments were effective for January 1, 2007; section 3855 "Financial Instruments - Recognition and Measurement", section 3861 "Financial Instruments - Disclosure and Presentation", section 1530 "Comprehensive Income", and section 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 records the fair value of its crude oil and natural gas derivative contracts under its risk management program on the Company's balance sheet. No restatement of prior periods occurred as a result of these new standards.

New Accounting Pronouncements

Two new accounting standards were issued by the CICA, section 3862 "Financial Instruments - Disclosures", and section 3863 "Financial Instruments - Presentation". These sections will replace section 3861 "Financial Instruments - Disclosure and Presentation" once adopted. The objective of section 3862 is to provide users with information to evaluate the significance of the financial instruments on the entity's financial position and performance, the nature and extent of risks arising from financial instruments, and how the entity manages those risks. The provisions of section 3863 deal with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These new sections are effective for the Company beginning January 1, 2008.

In December 2006, the Canadian Accounting Standards Board ("AcSB") issued section 1535, "Capital Disclosures", requiring disclosure of information about an entity's capital and the objectives, policies, and processes for managing capital. The standard is effective for annual periods beginning on or after October 1, 2007 and will require additional disclosure at that time.

In February 2008, the AcSB issued section 3064, "Goodwill and Intangible Assets", and amended section 1000, "Financial Statement Concepts" clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for annual years beginning on or after October 1, 2008 and early adoption is permitted. The Company is presently evaluating the impact these sections will have on its results of operations and/or financial position.

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards ("IFRS") in 2011. IFRS will replace Canadian GAAP with the official 'change-over' to IFRS to occur for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. The Company continues to monitor and assess the impact of these convergence efforts.

2008 Business Outlook

In December 2007, Orleans' Board of Directors approved an initial 2008 exploration and development capital expenditure program (net risked) of approximately $30 million (the "2008 Capital Budget"). In light of the uncertain outlook for natural gas prices, Orleans decided to initially execute a conservative capital budget whereby its total budgeted capital investments are anticipated not to significantly exceed budgeted cash flow from operations. Notwithstanding this initial, cautious capital expenditures level, anticipated to facilitate continued financial flexibility, the 2008 Capital Budget is programmed to deliver approximately 30% growth in average daily production year-over-year and advance the continued development of Orleans' West Kaybob asset base in concert with the continued exploration and delineation of its East Kaybob acreage position.

The 2008 Capital Budget encompasses the drilling of 11 operated wells, with an approximate 86% working interest, including eight (6.7 net) horizontal wells at Kaybob targeting the prolific Triassic Montney gas formation. The drilling and completion expenditure component of Orleans' 2008 Capital Budget is projected to approximate $22 million, with the remaining budgeted funds allocated towards investments in field facilities of approximately $7 million and undeveloped land expansion and seismic programs of approximately $1.5 million. In terms of geographic area allocation of the budgeted drilling, completion and field facilities capital expenditures, approximately $21 million is expected to be deployed at Kaybob, with the residual capital allocated across the Company's other core areas.

Based on the budgeted capital expenditures anticipated within the initial 2008 Capital Budget, average daily production for fiscal 2008 is projected at approximately 3,600 to 3,700 boe per day, weighted 80% natural gas and 20% light crude oil and natural gas liquids. This forecasted production range represents a 30% increase over Orleans' 2007 average daily production of approximately 2,800 boe per day and a 109% increase over the Company's 2006 average daily production level of 1,750 boe per day. Orleans' year-end 2008 exit production rate is anticipated to range 3,900 to 4,000 boe per day. The Kaybob drilling program will be the primary driver of the robust economic production growth that the Company expects to realize in 2008.

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.

New Greenhouse Gas and Air Emissions Legislation

The Alberta Government has introduced legislation that will enable the Province of Alberta to regulate emissions of "greenhouse gases". The regulations require facilities that emit over 100,000 tonnes of greenhouse gases a year to reduce their emissions intensity by 12% starting July 1, 2007 or pay a fee based on emissions in excess of the targeted reductions. The Federal Government has also released its regulatory framework to reduce emissions of both greenhouse gases and four smog-forming pollutants with targets coming into force in 2010 and 2015, respectively. Clarification surrounding the regulations is expected in the next year with the regulations to be finalized by 2010. There are multiple compliance mechanisms under both the Alberta and Federal plans including making contributions to technology funds, emissions trading and offset credits. The Company is in the process of fully evaluating the impact of these regulations, but Orleans believes that the cost and impact on its operations will be minor.

New Alberta Royalty Regime

On October 25, 2007, the Alberta government released The New Royalty Framework report ("NRF"), which summarizes the government's decisions on Alberta's new royalty regime. The NRF was the Alberta government's response to a report issued September 18, 2007 by the Alberta Royalty Review Panel ("ARRP"), which was commissioned by the Government of Alberta to perform a review of the province's royalty system. The NRF, in its entirety, is available at www.energy.gov.ab.ca.

As a result of the Alberta government's changes to their royalty structure on all Crown mineral rights owned by the Province of Alberta and leased by oil and gas producers such as Orleans, scheduled to take effect on January 1, 2009 upon legislation enactment, the Company would like to make the following observations:

- The Company's geographic, geologic and individual well production diversity of its asset base within Alberta, in conjunction with the production revenue derived from its freehold leases which are not impacted by the proposed new Crown royalties, is anticipated to temper the overall impact to Orleans of the announced changes to Crown royalties;

- Royalties determined under the NRF will be determined based on commodity prices, well productivity and depth of wells. A significant portion of the Company's wells are lower productivity wells that on a relative basis are less significantly impacted by the NRF than higher productivity wells; and,

- The Company is currently awaiting finalization of the royalty implementation regulations. The Alberta government is currently reviewing certain possible "unintended consequences" of NRF and the Company expects further clarification from the government in the near future. Notwithstanding, Orleans expects that its 2009 and thereafter Alberta Crown royalty payments will increase as a result of the proposed royalty changes.

It should be noted that the actual effect of the Alberta Crown royalty rate changes on Orleans will be determined subsequent to January 1, 2009, based on, among other things, the actual legislation to be enacted, well production rates and drilling depths, prevailing commodity prices, foreign exchange rates, and the Company's commodity composition of its production profile.

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.

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 f 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 financial statements for the year ended December 31, 2007

The Company's financial statements for the year ended December 31, 2007 are enclosed at the end of this news release.

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.



----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Balance Sheets
----------------------------------------------------------------------------
December 31, December 31,
2007 2006
-------------- --------------
ASSETS

Current Assets
Cash and cash equivalents $ 65,564 $ 273,165
Accounts receivable 9,038,271 11,072,319
Prepaid expenses and deposits 984,200 749,873
-------------- --------------
10,088,035 12,095,357

Property, plant and equipment (Note 6) 193,662,669 176,229,557

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

$ 203,750,704 $ 188,324,914
-------------- --------------
-------------- --------------
LIABILITIES

Current Liabilities
Accounts payable and accrued liabilities $ 14,139,553 $ 16,539,909
Commodity risk management (Note 15b) 432,470 -
Bank loan (Note 8) 44,136,979 38,781,291
-------------- --------------
58,709,002 55,321,200

Asset retirement obligations (Note 9) 5,454,294 5,023,743

Future income tax liability (Note 13) 3,708,329 2,197,469
-------------- --------------

67,871,625 62,542,412
-------------- --------------
SHAREHOLDERS' EQUITY

Share capital (Note 10) 137,732,354 122,736,373
Contributed surplus (Note 11c) 2,813,682 1,502,963
Retained earnings (deficit) (4,666,957) 1,543,166
-------------- --------------

135,879,079 125,782,502
-------------- --------------

$ 203,750,704 $ 188,324,914
-------------- --------------
-------------- --------------

Description of Business and Significant Accounting Policies (Notes 1 & 2)
Commitments and Contingencies (Note 16)
Subsequent Events (Notes 15b and 19)

On behalf of the Board of Directors:

Barry Olson, Director

Doug Baker, Director

The accompanying notes to the financial statements are an integral part of
these statements.


----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Statements of Operations and Comprehensive Loss
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------
Revenue
Petroleum and natural gas sales $ 47,850,855 $ 32,102,989
Royalties (9,261,378) (5,724,333)
-------------- --------------
38,589,477 26,378,656
Realized gain on commodity contracts
(Note 15b) 1,290,098 344,232
Unrealized loss on commodity contracts
(Note 3, 15b) (432,470) -
-------------- --------------

39,447,105 26,722,888
-------------- --------------
Expenses
Operating 12,576,372 6,315,676
Transportation 1,097,650 567,579
General and administrative (Note 11) 2,920,843 1,945,261
Interest 2,654,962 1,230,922
Depletion, depreciation and accretion 29,287,615 16,985,754
Goodwill impairment (Note 7) - 16,619,991
-------------- --------------
48,537,442 43,665,183
-------------- --------------

Loss before taxes (9,090,337) (16,942,295)

Future income taxes (reduction) (Note 13) (2,880,214) 895,271
-------------- --------------

Net loss (6,210,123) (17,837,566)

Changes in cash flow hedges, net of tax
(Note 3) (425,405) -
-------------- --------------

Comprehensive loss $ (6,635,528) $ (17,837,566)
-------------- --------------
-------------- --------------

Net loss per share (Note 12)
Basic $ (0.18) $ (0.73)
-------------- --------------
-------------- --------------

Diluted $ (0.18) $ (0.73)
-------------- --------------
-------------- --------------

The accompanying notes to the financial statements are an integral part of
these statements.


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ORLEANS ENERGY LTD.
Statements of Retained Earnings (Deficit)
----------------------------------------------------------------------------

Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------

Retained earnings, beginning of year $ 1,543,166 $ 19,380,732
Net loss (6,210,123) (17,837,566)
-------------- --------------
Retained earnings (deficit), end of year $ (4,666,957) $ 1,543,166
-------------- --------------
-------------- --------------


----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Statements of Accumulated Other Comprehensive Income ("AOCI")
----------------------------------------------------------------------------
(audited)
Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------

AOCI, beginning of year $ - $ -
Impact of new cash flow accounting standards
on January 1, 2007 (net of tax of $180,498)
(Note 3) 425,405 -
Reclassification to earnings of net gains on
commodity contracts (net of tax of $180,498) (425,405) -
-------------- --------------
AOCI, end of year $ - $ -
-------------- --------------
-------------- --------------

The accompanying notes to the financial statements are an integral part of
these statements.


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ORLEANS ENERGY LTD.
Statements of Cash Flows
----------------------------------------------------------------------------

Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------
Cash provided from (used in):

Operating activities
Net loss $ (6,210,123) $ (17,837,566)
Items not affecting cash:
Depletion, depreciation and accretion 29,287,615 16,985,754
Stock-based compensation (Note 11) 729,399 555,486
Unrealized loss on commodity contracts
(Note 15b) 432,470 -
Future income taxes (reduction) (2,880,214) 895,271
Goodwill impairment (Note 7) - 16,619,991
Asset retirement obligations expenditures (33,368) -
-------------- --------------

Funds generated from operations 21,325,779 17,218,936
Change in non-cash working capital (Note 14) 913,241 2,926,942
-------------- --------------
22,239,020 20,145,878
-------------- --------------

Financing activities
Increase in bank loan 5,355,688 14,416,735
Exercise of stock options 98,170 202,432
Proceeds from share issues, net issue costs 18,965,601 50,013,510
-------------- --------------
24,419,459 64,632,677
-------------- --------------
Investing activities
Corporate acquisitions (Note 5) - (39,517,224)
Property, plant and equipment additions (46,642,127) (48,185,416)
Property dispositions 1,289,924 -
Change in non-cash working capital (Note 14) (1,513,877) 3,197,250
-------------- --------------
(46,866,080) (84,505,390)
-------------- --------------

Increase (decrease) in cash and cash
equivalents (207,601) 273,165

Cash and cash equivalents, beginning of year 273,165 -
-------------- --------------

Cash and cash equivalents, end of year $ 65,564 $ 273,165
-------------- --------------
-------------- --------------

Supplemental Cash Flow Information (Note 14)

The accompanying notes to the financial statements are an integral part of
these statements.


ORLEANS ENERGY LTD.

Notes to the Annual Financial Statements

Years ended December 31, 2007 and 2006

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".

2. Significant Accounting Policies

a) Principles of consolidation and basis of presentation

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

On April 1, 2007, the Company completed an amalgamation with its wholly-owned subsidiaries, Morpheus Energy Corporation, Orleans Oil and Gas Ltd. and Orleans Petroleum Ltd. Effective April 1, 2007, these subsidiary entities ceased to exist as separate legal entities and the Company as the amalgamated entity, assumed all operational and contractual obligations of the subsidiary companies from April 1, 2007 onwards.

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 of changes in such estimates on the 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 - 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 percent 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 (before royalties) as determined by the Company's independent qualified reserves 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 percent.

iii) Ceiling test

Oil and gas assets are evaluated in each reporting period in order 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 both 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 11. 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. The Company's commodity price risk management contracts are derivatives and accounted for as held-for-trading financial instruments and are recorded at fair value.

k) Cash and cash equivalents

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


l) 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. Changes in Accounting Policies

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") handbook section 1530 "Comprehensive Income", section 3251 "Equity", section 3855 "Financial Instruments - Recognition and Measurement", section 3861 "Financial Instruments - Disclosure and Presentation", and section 3865 "Hedges". These standards result in changes in the accounting for financial instruments and hedges as well as introduce comprehensive income as a separate component of shareholders' equity. The Company has adopted these standards prospectively and the comparative financial statements have not been restated. Except for the adjustments described below, the adoption of these standards had no material impact on the Company's net earnings or cash flows. At January 1, 2007, the following adjustments were made to the balance sheet to adopt the aforementioned new standards:




----------------------------------------------------------------------------
January 1, 2007
-----------------
Commodity risk management asset $ 605,903
Future income taxes (180,498)
Accumulated other comprehensive income (425,405)
----------------------------------------------------------------------------


The $425 thousand of net derivative gains in accumulated other comprehensive income at January 1, 2007 was reclassified to earnings in 2007 over the remaining life of the related commodity contracts. From that date forward, the changes in fair value of such derivatives will be recognized in net earnings when incurred.

Comprehensive Income (section 1530)

Comprehensive income is comprised of net earnings or loss and other comprehensive income ("OCI"). OCI represents the change in equity for a period that arises from unrealized gains and losses on available-for-sale investment securities and changes in the fair market value of derivative instruments designated as cash flow hedges. The standard requires a new statement of comprehensive income, which is comprised of net earnings and other comprehensive income. The Company has combined this new statement with the statement of operations.

Equity (section 3251)

This section establishes the standards for presentation of equity and changes in equity during the period. It requires separate presentation of changes in equity for the period arising from net income, OCI, contributed surplus, retained earnings, share capital and reserves. Accumulated OCI would be included in the balance sheet as a separate component of shareholders' equity.

Financial Instruments - Recognition and Measurement (section 3855)

Section 3855 establishes standards for the recognition and measurement of financial instruments, which is comprised of financial assets, financial liabilities, derivatives and non-financial derivatives. All financial instruments must be classified into one of these five categories: (i) held-for-trading; (ii) held-to-maturity instruments; (iii) loans and receivables; (iv) available-for-sale financial assets; and, (v) other financial liabilities. The new standard requires all financial instruments within its scope, including all derivatives, to be recognized on the balance sheet initially at fair market value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available-for-sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income until the investment is derecognized or impaired at which time the amounts would be recorded in earnings.

The Company's cash and cash equivalents are designated as "held-for-trading" and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. The Company's accounts receivable are designated as "loans and receivables", and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. The Company's accounts payable and accrued liabilities and bank debt are designated as "other financial liabilities". The Company's commodity risk management contracts are accounted for as "held-for-trading" and are recorded at fair value.

Derivatives (section 3855)

A derivative is a financial instrument whose value changes in response to a specified variable, requires little or no net investment and it is settled at a future date. A non-financial derivative is a contract that can be settled net in cash or through another financial instrument. Currently, the Company's commodity price risk management contracts are derivatives and accounted for as held-for-trading financial instruments and are recorded at fair value.

An embedded derivative is a derivative that is part of a non-derivative contract and not directly related to that contract. Under Section 3855, embedded derivatives must be accounted for as a separate financial instrument. On adoption, the Company elected to recognize, as separate assets and liabilities, only for those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. The Company did not identify any material embedded derivatives, which required separate recognition and measurement.

Hedge Accounting (section 3865)

Section 3865 establishes standards for when and how hedge accounting may be applied. Hedge accounting continues to be optional and the Company may not designate the hedging instrument as a hedge for accounting purposes. To qualify for hedge accounting, the hedging relationship between the hedged item and hedging instrument must be designated and formally documented at the inception of the contract. The documentation includes the risk management policy, the risk management objectives, the hedging relationships between the hedged items and the hedging items and the methods for testing the effectiveness of the hedge (i.e. whether or not the hedging relationship is effective in offsetting the changes associated with the hedged risk). Effectiveness must be tested on an ongoing basis throughout the life of the hedging relationship. For cash flow hedges that have been terminated or cease to be effective, prospective gains or losses on the derivative are recognized in earnings. Any gain or loss that has been included in accumulated other comprehensive income at the time the hedge is discontinued continues to be deferred in accumulated other comprehensive income until the original hedged transaction is recognized in earnings. If the likelihood of the original hedged transaction occurring is no longer probable, the entire gain or loss in accumulated other comprehensive income related to this transaction is immediately reclassified to earnings.

In conjunction with the adoption of these new standards, the Company elected not to use hedge accounting for its crude oil and natural gas derivative contracts under its risk management program. Prior to January 1, 2007, the Company applied hedge accounting to its commodity price risk management contracts. On January 1, 2007 the Company discontinued hedge accounting for all existing hedge instruments. The Company has chosen not to designate any of its current commodity contracts as hedges for the purposes of this section and has classified them as held-for-trading and recorded the fair value of these instruments on the balance sheet. The fair value of the commodity contracts is recognized at each reporting period with the change in fair value being classified as an unrealized gain or loss on the statement of operations. The impact in fair value is disclosed in Note 15b.

4. New Accounting Pronouncements

Two new accounting standards were issued by the CICA, section 3862 "Financial Instruments - Disclosures", and section 3863 "Financial Instruments - Presentation". These sections will replace section 3861 "Financial Instruments - Disclosure and Presentation" once adopted. The objective of section 3862 is to provide users with information to evaluate the significance of the financial instruments on the entity's financial position and performance, the nature and extent of risks arising from financial instruments, and how the entity manages those risks. The provisions of section 3863 deal with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These new sections are effective for the Company beginning January 1, 2008.

In December 2006, the Canadian Accounting Standards Board ("AcSB") issued section 1535, "Capital Disclosures", requiring disclosure of information about an entity's capital and the objectives, policies, and processes for managing capital. The standard is effective for annual periods beginning on or after October 1, 2007 and will require additional disclosure at that time.

In February 2008, the AcSB issued section 3064, "Goodwill and Intangible Assets", and amended section 1000, "Financial Statement Concepts" clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for annual years beginning on or after October 1, 2008 and early adoption is permitted. The Company is presently evaluating the impact these sections will have on its results of operations and/or financial position.

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada are expected to converge with the International Financial Reporting Standards (IFRS) by 2011. IFRS will replace Canadian GAAP with the official 'change-over' to IFRS to occur for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. The Company continues to monitor and assess the impact of these convergence efforts.

5. 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 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 obligations (525,631)
Future income tax liability (1,135,840)
----------------------------------------------------------------------------
Total net assets acquired $ 19,526,342
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 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 obligations (1,275,664)
Future income tax liability (13,091,118)
----------------------------------------------------------------------------
Total net assets acquired $ 72,946,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------

6. Property, Plant and Equipment

----------------------------------------------------------------------------
December 31, 2007 December 31, 2006
-------------------------------------
Petroleum and natural gas properties $ 245,355,653 $ 199,171,180
Accumulated depletion (51,851,778) (23,060,662)
-------------------------------------
193,503,875 176,110,518
-------------------------------------
Office equipment and other 230,327 158,769
Accumulated depreciation (71,533) (39,730)
-------------------------------------
158,794 119,039
----------------------------------------------------------------------------
Property, plant and equipment $ 193,662,669 $ 176,229,557
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the year ended December 31, 2007, certain general and administrative overhead expenses of $1.86 million (December 31, 2006: $1.34 million) directly related to exploration and development activities were capitalized. Included in this amount is capitalized stock-based compensation of $905 thousand (December 31, 2006: $720 thousand), with such amount including the future income tax liability associated with the capitalized stock-based compensation of $266 thousand (December 31, 2006: $219 thousand).

At December 31, 2007, property, plant and equipment included $10.29 million (December 31, 2006: $13.23 million) relating to unproved properties, which have been excluded from the depletion calculation. Future development costs related to proved non-producing reserves of $20.08 million (December 31, 2006: $22.28 million) have been included in the depletion calculation.

The Company performed a ceiling test calculation as at December 31, 2007 to assess the recoverable value of property, plant and equipment. The oil and gas future prices are based on the December 31, 2007 price forecast of the Company's independent qualified reserve engineering 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, 2007.



----------------------------------------------------------------------------
Company's AECO-C Company's
WTI Edmonton Price Price Price Exchange
Price - Oil Price - Oil - Oil - Gas - Gas Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ($US/$Cdn)
----------------------------------------------------------------------------
2008 89.61 88.17 83.60 6.51 6.75 1.000
2009 86.01 84.54 80.13 7.22 7.51 1.000
2010 84.65 83.16 79.00 7.69 8.03 1.000
2011 82.77 81.26 76.98 7.70 8.03 1.000
2012 82.26 80.73 75.92 7.61 7.96 1.000
2013 82.81 81.25 76.10 7.78 8.15 1.000
2014 84.46 82.88 77.58 7.96 8.35 1.000
2015 86.15 84.55 79.24 8.14 8.55 1.000
2016 87.87 86.25 81.08 8.32 8.75 1.000
2017 89.63 87.98 82.87 8.51 8.96 1.000
Escalated rate of 1.00
2.0% thereafter (1) thereafter(1)
----------------------------------------------------------------------------

(1) Percentage change represents the change in each year after 2017 to the
end of the reserve life.


7. 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 was recorded as a non-cash charge to income as of December 31, 2006. This goodwill resulted from the acquisition of Morpheus.


8. Bank Facility

As at December 31, 2007, the Company had a demand revolving credit facility of $60 million with a Canadian chartered bank (the "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. At December 31, 2007, the Company had $44.14 million of bank debt outstanding (December 31, 2006: $38.78 million).

9. 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, 2007, the estimated present value of the total amount required to settle the Company's asset retirement obligations was $5.45 million (December 31, 2006: $5.02 million), based on a total undiscounted future liability amount of $13.09 million (inflation adjusted) (December 31, 2006: $12.48 million). These obligations are to be settled based on the economic lives of the underlying assets, which is currently projected to be up 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, 2006: credit-adjusted risk free rate of 10 percent and an inflation rate of 1.5 percent).



----------------------------------------------------------------------------
December 31, 2007 December 31, 2006
--------------------------------------
Asset retirement obligations -
beginning $ 5,023,743 $ 2,484,234
Liabilities incurred on development
activities 185,255 385,186
Liabilities acquired through corporate
acquisitions - 1,801,295
Liabilities released on property
dispositions (186,031) -
Liabilities settled (33,368) -
Accretion expense 464,695 353,028
----------------------------------------------------------------------------
Asset retirement obligations - ending $ 5,454,294 $ 5,023,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the year ended December 31, 2007, the Company recognized depletion expense related to its asset retirement cost of $495 thousand (December 31, 2006: $410 thousand).

10. Share Capital

a) Authorized - Unlimited number of voting common shares.

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.



b) Issued and outstanding

----------------------------------------------------------------------------
Total Number
of Common Shares Amount
----------------------------------------------------------------------------
Balance, December 31, 2005 15,099,047 $ 19,937,717
Issued on flow-though private
placements 3,300,000 20,147,500
Issued on equity private placement 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 5) 1,623,719 9,579,942
Issued on acquisition of Morpheus
(Note 5) 7,351,727 43,375,189
Exercise of stock options 174,166 321,381
Flow through shares tax adjustment - (1,528,103)
----------------------------------------------------------------------------

Balance, December 31, 2006 33,148,659 $ 122,736,373
Issued on flow-through financing 1,500,000 8,175,000
Issued on equity financing 2,800,000 12,040,000
Combined issue costs, net tax effect of
$379,373 - (870,026)
Exercise of stock options 122,713 156,000
Flow through shares tax adjustment - (4,504,993)
----------------------------------------------------------------------------

Balance, December 31, 2007 37,571,372 $ 137,732,354
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 was committed to spend 100 percent 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. The future income tax effect and reduction to share capital was recorded in the year ended December 31, 2006, the period in which the Company filed the renouncement documents with the tax authorities.

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 was committed to spend 100 percent of the gross proceeds on qualifying exploration expenditures prior to December 31, 2007. As at December 31, 2007, the Company had fully incurred and discharged these expenditures commitments associated with this private placement. The future income tax effect and reduction to share capital was recorded in the first quarter of 2007, the period in which the Company filed the renouncement documents with the tax authorities.

On July 12, 2007, the Company issued 1,500,000 flow-through common shares on a "bought-deal" basis at a price of $5.45 per share for gross proceeds of $8.175 million. Under the terms of the flow-through share agreement, the Company is committed to spend 100 percent of the gross proceeds on qualifying exploration expenditures prior to December 31, 2008. As at December 31, 2007, the Company had incurred approximately $2.37 million of qualifying expenditures associated with this equity issue with the balance of $5.805 million to be incurred by December 31, 2008.

11. 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, 2007, 3,118,026 options with a weighted average exercise price of $3.30 were outstanding and exercisable at various dates through to December 3, 2012.

Subsequent to December 31, 2007, the Company granted stock options to its officers, directors and employees in an aggregate quantity of 639,000 options with an exercise price of $2.21 per stock option. The stock options were granted pursuant to the Company's stock option plan and will vest over a three-year period with a five-year expiry.



The following table summarizes outstanding stock options as at December 31,
2007:

----------------------------------------------------------------------------
Weighted Avg.
Number Exercise Price
------------------------------
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
Granted 917,500 3.33
Exercised (122,713) 0.80
Forfeited (375,500) 4.91
----------------------------------------------------------------------------
Outstanding -- December 31, 2007 3,118,026 $ 3.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options exercisable -- December 31, 2007 1,146,100 $ 2.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------

b) Exercise price range for options outstanding as at December 31, 2007:

----------------------------------------------------------------------------
Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted Avg. Weighted
Price Range Number Avg. Price Remaining Life Number Avg. Price
----------------------------------------------------------------------------
$ 0.80 - 1.00 655,271 $ 0.80 2.07 years 449,708 $ 0.80
$ 2.30 - 3.74 1,570,255 $ 3.24 3.56 years 402,392 $ 3.16
$ 3.90 - 5.87 892,500 $ 5.23 3.49 years 294,000 $ 5.33
-------------- --------- - -------- ------------------ --------- - --------
Total 3,118,026 $ 3.30 3.23 years 1,146,100 $ 2.79
-------------- --------- - -------- ------------------ --------- - --------
-------------- --------- - -------- ------------------ --------- - --------


The Company recorded stock-based compensation expense of $729,399 for the year ended December 31, 2007 (December 31, 2006: $555,486), which was charged to general and administration expense and presented as such on the Company's statement of operations.

The Company determined the fair value of stock options granted during the fiscal period ended December 31, 2007 using the modified Black-Scholes evaluation stock option pricing model under the following assumptions:



----------------------------------------------------------------------------
December 31, 2007 December 31, 2006
------------------------------------
Weighted-average fair value ($/option) 1.62 2.40
Risk-free interest rate (%) 4.13 4.06
Estimated hold period prior to exercise
(years) 5 5
Volatility in the price of Orleans
shares (%) 49.7 50.4
Dividend yield (%) Nil Nil
----------------------------------------------------------------------------

c) Contributed surplus

----------------------------------------------------------------------------
Contributed surplus - December 31, 2005 $ 565,359
Stock-based compensation, before capitalization 1,056,553
Exercise of stock options (118,949)
----------------------------------------------------------------------------
Contributed surplus - December 31, 2006 1,502,963
Stock-based compensation, before capitalization 1,368,549
Exercise of stock options (57,830)
----------------------------------------------------------------------------
Contributed surplus - December 31, 2007 $ 2,813,682
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. 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.

For the year ended December 31, 2007, 2.04 million stock options (December 31, 2006: 1.41 million) were excluded in calculating the weighted average number of diluted common shares outstanding, as they were determined to be anti-dilutive.



----------------------------------------------------------------------------
Year Ended Year Ended
December 31, 2007 December 31, 2006
---------------------------------------
Weighted average shares outstanding:
Basic 35,252,993 24,362,187
Diluted 35,772,226 25,136,494
----------------------------------------------------------------------------


13. 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, 2007 December 31, 2006
----------------------------------------

Loss before income taxes $ (9,090,337) $ (16,942,295)
Combined federal and provincial
statutory tax rate 32.12% 34.50%
Calculated expected income taxes
(reduction) (2,919,816) (5,845,092)

Increase (decrease) resulting from
the tax effect of:
Non-deductible crown charges (net
ARTC) - 203,734
Federal resource allowance - (240,532)
Non-deductible stock-based
compensation 234,283 191,643
Goodwill Impairment - 5,733,897
Other 95,179 17,306
Statutory rate change (1) (289,860) 834,315
----------------------------------------------------------------------------
Income taxes (reduction) $ (2,880,214) $ 895,271
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Reflects Canadian Federal income tax rate reductions and other
legislative changes enacted or substantively enacted in the second and
fourth quarters of 2007.

b) Future income tax:

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

December 31, 2007 December 31, 2006
----------------------------------------
Future income tax:
Capital assets $ (8,987,391) $ (11,058,776)
Non-capital losses 2,453,652 8,433,831
Share issue costs and other 1,374,568 1,374,553
Asset retirement obligations 1,450,842 1,507,123
Partnership deferral - (2,454,200)
----------------------------------------------------------------------------
Net future income tax liability $ (3,708,329) $ (2,197,469)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company's non-capital losses of $8.32 million expire at various times
from 2008 to 2026.

14. Supplemental Cash Flow Information

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

December 31, 2007 December 31, 2006
----------------------------------------
Change in non-cash working
capital:
Accounts receivable and other
current assets $ 1,799,720 $ (411,218)
Accounts payable and accrued
liabilities (2,400,356) 6,535,410
----------------------------------------------------------------------------
$ (600,636) $ 6,124,192
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Changes in non-cash working
capital related to:
Operating activities $ 913,241 $ 2,926,942
Investing activities (1,513,877) 3,197,250
----------------------------------------------------------------------------
$ (600,636) $ 6,124,192
----------------------------------------------------------------------------
----------------------------------------------------------------------------

b) Other cash flow information

December 31, 2007 December 31, 2006
----------------------------------------

Interest paid (net of interest
income) $ 2,456,920 $ 1,159,363


15. Financial Instruments and Risk Management

a) Balance sheet financial instruments:

The Company's exposure under its financial instruments is limited to financial assets and liabilities, all of which are included in the financial statements. The Company's financial instruments recognized in the balance sheet consist of cash and cash equivalents, accounts receivable, derivative contracts and current liabilities. Unless otherwise noted, carrying values reflect the current fair value of the Company's financial instruments. The estimated fair values of recognized financial instruments have been determined based on the Company's assessment of available market information and appropriate methodologies, or through comparisons to similar instruments.

b) Commodity price risk management contracts

The prices the Company receives for its crude oil and natural gas production may have a significant impact on its revenues and cash provided from operating activities. Any significant price decline in commodity prices would adversely affect the amount of funds available for capital reinvestment purposes. As such, the Company utilizes a risk management program to partially mitigate that risk and to ensure adequate funds are available for planned capital activities and other commitments. From time-to-time, the Company may employ financial instruments to manage fluctuations in oil and gas market prices. The Company does not utilize derivative financial instruments for speculative purposes. The Company has elected to not designate its commodity price risk management contracts as accounting hedges under Canadian GAAP.

As described in Note 3, the Company recognizes the fair value of its commodity contracts on the balance sheet each reporting period with the change in fair value being recognized as an unrealized gain or loss on the statement of operations. On January 1, 2007 the fair value of the commodity contracts was an asset of $605,903 and resulted in an increase to accumulated other comprehensive income and the future tax liability of $425,405 and $180,498, respectively. The entire amount recognized in accumulated other comprehensive income has been fully amortized over the term of the contracts through other comprehensive income with a corresponding unrealized gain on financial instruments on the statement of operations. As a result, $425,405 net of tax, was charged during the year to other comprehensive income with a corresponding unrealized gain on financial instruments of $605,903 and a charge to future income tax liability of $180,498. As at December 31, 2007, the fair value of the financial commodity contracts was a liability of approximately $433 thousand, resulting in an unrealized loss for the year of $432,470 net of the amortization of the accumulated other comprehensive income.



The following table reconciles the Company's unrealized gain (loss) on
commodity contracts:

Year Ended Year Ended
December 31, 2007 December 31, 2006
----------------------------------------
Change in fair value of commodity
contracts $ (1,038,373) $ -
Amortization of accumulated other
comprehensive income 605,903 -
----------------------------------------------------------------------------
Unrealized loss on commodity
contracts $ (432,470) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table outlines the commodity agreements that were outstanding
as at December 31, 2007, in addition to commodity contracts entered into
subsequent to December 31, 2007.

Daily
notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Jan '08 -
Crude Oil Oct. 15, 2007 Swap Jun '08 200 bbls W.T.I. US$ 81.56/bbl
Jul '08 - US$ 90.00 -
Crude Oil (1) Mar. 3, 2008 Collar Dec '08 100 bbls W.T.I. 116.25/bbl
Nov '07 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.545 /GJ
Jan '08 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.71 /GJ
Jan '08 -
NatGas Oct. 31, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.67 /GJ
Apr '08 -
NatGas Dec. 18, 2007 Swap Dec '08 2,000 GJs AECO-C C$ 6.55 /GJ
Apr '08 -
NatGas (1) Jan. 2, 2008 Swap Dec '08 2,000 GJs AECO-C C$ 6.81 /GJ
Apr '08 -
NatGas (1) Jan. 4, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.61 /GJ
Apr '08 -
NatGas (1) Jan. 7, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.72 /GJ
Apr '08 -
NatGas (1) Jan. 10, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.01 /GJ
Nov '08 - C$ 7.00 -
NatGas (1) Feb. 13, 2008 Collar Mar '09 2,000 GJs AECO-C 9.70 /GJ
Apr '08 -
NatGas (1) Feb 14, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.52 /GJ
----------------------------------------------------------------------------

(1) These contracts were entered into subsequent to December 31, 2007.



c) 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. The carrying value of accounts receivable reflects Management's assessment of the credit risk associated with these customers.

d) Interest rate risk

Financial instruments, which subject the Company to interest rate risk, are limited to the bank loan. The Company's current Credit Facility agreement with its banker calculates interest based on the bank's prime lending rate plus an applicable margin (see Note 8).


16. Commitments and Contingencies

In the normal course of business, the Company has entered into various commitments that will have an impact on the Company's future operations. These commitments primarily relate to debt repayments, operating leases relating to head office space and natural gas field equipment, and drilling rig contractual obligations. The following table summarizes the Company's commitments as at December 31, 2007:



2008 2009 2010 2011 2012 Thereafter
----------- -------- -------- -------- -------- ----------
Bank debt $44,136,979 $ - $ - $ - $ - $ -
Head office
operating lease 649,458 649,458 649,458 680,013 680,013 906,683
Field equipment
operating leases 254,225 20,203 - - - -
Drilling rig
commitment 370,685 - - - - -
Total $45,411,347 $669,661 $649,458 $680,013 $680,013 $ 906,683
----------------------------------------------------------
----------------------------------------------------------


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 10 c), which outlines the Company's requirements to incur flow-through share eligible Canadian Exploration Expenditures, as defined in the Income tax Act (Canada).

17. Related Party Transactions

During the year ended December 31, 2007, the Company paid a total of $133 thousand (December 31, 2006: $326 thousand) for legal services provided by a firm in which a current director and the Company's corporate secretary are partners of. These payments were made 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.

18. Comparative Balances

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

19. Subsequent Event

On March 13, 2008, the Company closed a bought-deal equity financing (the "Financing"). Pursuant to the terms of the Financing, the Company issued, on an underwritten basis, 7.0 million common shares at a price of $3.60 per share for total gross proceeds of $25.2 million. The Company granted the underwriters an over allotment option to purchase up to an additional 1,050,000 common shares at a price of $3.60 per common share for a period of 30 days from the closing date for additional gross proceeds of $3.78 million.

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

Contact Information