Orleans Energy Announces 2005 Financial Results and Expanded Bank Facility

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CALGARY, ALBERTA--(CCNMatthews - March 29, 2006) - Orleans Energy Ltd. ("Orleans" or the "Company") (TSX VENTURE:OEX) is pleased to announce its audited financial results for the nine month fiscal period ended December 31, 2005. Calendar 2005 marks the Company's inaugural year as an explorer and producer of crude oil and natural gas. Successful development drilling of numerous geologic horizons, re-completion activities on existing wellbores, and concentrated acquisitions have enabled Orleans to significantly expand its oil and gas production throughout 2005. A summary of Orleans' accomplishments are detailed as follows:



Quarterly Comparison
Financial Highlights (1) Three Month Period Ended,
(6:1 oil equivalent Dec. 31, Sep. 30, Jun. 30, Mar. 31,
conversion) 2005 2005 2005 2005
----------- ----------- ----------- -----------
(amounts in Cdn.$ except
share data)
Petroleum and natural
gas revenue 8,452,550 6,980,395 3,982,385 2,595,920
Cash flow from
operations (2) 4,972,706 4,441,969 2,342,140 1,303,584
Per share - basic 0.33 0.30 0.16 0.12
- diluted 0.31 0.28 0.15 0.11
Operating netback (3)
($/boe) 41.76 42.78 34.21 30.10
Corporate netback (3)
($/boe) 39.22 40.23 30.92 25.87
Net earnings (4) 16,203,026 2,406,655 855,785 69,456
Per share - basic 1.07 0.16 0.06 0.01
- diluted 1.01 0.15 0.05 0.01
Net debt (5)- period end 4,613,124 2,170,227 2,527,796 (3,415,482)
Weighted average
basic shares 15,084,264 15,057,036 15,054,047 11,335,241
Weighted average
diluted shares 15,979,723 15,861,948 15,749,603 11,859,756
Issued and outstanding
shares 15,099,047 15,079,047 15,054,047 15,054,047
Operating Highlights (1)
Average daily production:
Natural gas (mcf/d) 4,160 3,231 2,385 1,404
Liquids (Oil & NGLs)
(bbls/d) 685 662 435 325
Oil equivalent (boe/d) 1,378 1,200 832 559
Average sales price:
Natural gas ($/mcf) 11.61 9.71 7.71 7.73
Liquids (Oil & NGLs)
($/bbl) 63.64 67.25 58.33 55.40
Oil equivalent ($/boe) 66.67 63.23 52.58 51.62
Capital expenditures ($) 7,416,964 4,102,352 8,262,787 4,840,148


Nine Month
Period
Calendar Ended
Financial Highlights (1) Year Dec. 31,
(6:1 oil equivalent conversion) 2005 2005
----------- -----------
(amounts in Cdn.$ except share data) (audited)
Petroleum and natural gas revenue 22,011,250 19,415,330
Cash flow from operations (2) 13,060,399 11,756,815
Per share - basic 0.92 0.78
- diluted 0.88 0.74
Operating netback (3) ($/boe) 38.86 40.29
Corporate netback (3) ($/boe) 35.96 37.57
Net earnings (4) 19,534,922 19,465,466
Per share - basic 1.38 1.29
- diluted 1.32 1.23
Net debt (5)- period end 4,613,124 4,613,124
Weighted average basic shares 14,145,451 15,065,156
Weighted average diluted shares 14,836,572 15,854,191
Issued and outstanding shares 15,099,047 15,099,047
Operating Highlights (1)
Average daily production:
Natural gas (mcf/d) 2,804 3,262
Liquids (Oil & NGLs) (bbls/d) 528 594
Oil equivalent (boe/d) 995 1,138
Average sales price:
Natural gas ($/mcf) 9.75 10.04
Liquids (Oil & NGLs) ($/bbl) 62.44 63.70
Oil equivalent ($/boe) 60.60 62.04
Capital expenditures ($) 24,622,251 19,782,103

Notes:
(1) No comparison with prior year periods is provided as Orleans
commenced active oil and gas operations in December 2004. Orleans
changed its year-end to December 31, 2005 from previous March 31,
2005 and accordingly all reference to fourth quarter activity within
this news release pertains to the calendar period from October 1,
2005 to December 31, 2005.
(2) Cash flow from operations does not have any standardized meaning
prescribed by Canadian generally accepted accounting principles
("GAAP") and accordingly represents Funds from Operations before any
asset retirement obligation cash expenditures.
(3) Operating netback represents average sales price less royalties,
operating costs and transportation expenses. Corporate netback
represents operating netback less general and administrative costs
and interest expense (plus any interest income). Both measures are
not recognized measures under Canadian GAAP.
(4) Net earnings includes any income tax reductions or recoveries.
(5) Net Debt refers to outstanding bank debt plus any working capital
deficit or minus any working capital surplus (excluding any current
income tax non-cash asset). Net debt is not a recognized measure
under Canadian GAAP.

 


Financial highlights of Orleans' successful first calendar year include the following:

- Significant Cash Flow Generation.

Realized corporate cash flow netback of $35.96 per boe, resulting in total cash flow of $13.06 million or $0.88 per share (diluted).

- Strong Revenue Realization

Petroleum and natural gas revenue recognition of $22.01 million or $60.60 per boe.

- Cost Structure Improvements.

Cash expenses on an oil-equivalent unit basis, including operating, general and administrative and interest charges were $11.21 per boe, a 20 percent decrease from the initial first quarter 2005 cost structure.

- Financial Flexibility.

Year-end net debt of $4.61 million, representing 0.2 times annualized fourth quarter 2005 cash flow.

Bank Lending Facility

Pursuant to the annual review of the Company's year-end 2005 oil and gas reserves base by the Alberta Treasury Branch, Orleans is pleased to announce that the borrowing base limit associated with its revolving operating loan facility has been increased to $22.5 million, as compared to the pre-existing borrowing base limit of $8.0 million. This expanded bank credit facility provides financial flexibility with respect to any potential future acquisition opportunities.

Exploration & Development Update

Orleans is well positioned for growth in 2006, with a diverse inventory of projects in both core operating areas. The Company's high interest, operated prospects in both Halkirk in east-central Alberta and Pine Creek in west-central Alberta offer a variety of low-to-medium risk oil and gas drilling opportunities across a multitude of producing horizons. In all, Orleans is on track to drill a minimum 27 (21.5 net) wells in 2006.

Orleans is poised to commence drilling operations in Pine Creek subsequent to spring break-up, targeting long-lived, Cretaceous-aged gas reserves. The Company's high netback cash flow, generated from its Halkirk asset base, will facilitate the funding of its forthcoming capital activity plans at Pine Creek. The Company has initial plans to drill up to 4 (3.3 net) wells in 2006 at Pine Creek. However, with drilling success this area may require increased drilling density of two to four wells per section for optimal reserves recovery. As well, through recent successful crown land sales and complementary acquisitions, Orleans has added valuable land and drilling inventory in both the Halkirk and Pine Creek operating areas. Throughout 2006, Orleans will continue to expand its interests in both core areas as well as focusing on establishing an additional core area to the Company's asset portfolio.

Annual General Meeting of Shareholders

The Company plans to hold its annual meeting of shareholders on Wednesday, June 7, 2006 at 3:00 p.m. in the Devonian Room of the Calgary Petroleum Club located at 319 - 5th Avenue S.W., Calgary, Alberta, Canada.

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 audited financial statements for the nine month fiscal reporting period ended December 31, 2005 and the audited financial statements for the prior period ended March 31, 2005, available in printed form on request.

Orleans Energy Ltd. is a Calgary, Alberta-based crude oil and natural gas company. Orleans is incorporated under the laws of Alberta and its common shares are publicly listed and traded on the TSX Venture Exchange under the trading symbol "OEX". Effective, January 31, 2005, the Company's business was restructured to that of crude oil and natural gas exploration and production through a corporate plan of arrangement (the "Arrangement"). Through the completion of the Arrangement: (i) former shareholders of Orleans Resources Inc. became shareholders of Orleans, (ii) Orleans Resources Inc. became a wholly-owned subsidiary of Orleans, (iii) Orleans Resources Inc. ceased to be a reporting issuer; and, (iv) Orleans became a reporting issuer in each of the provinces of Alberta, British Columbia and Quebec.

Additionally, in conjunction with the Arrangement, the Company acquired all of the issued and outstanding shares of a private oil and gas company, 1133069 Alberta Ltd. ("1133069"), by way of a share exchange. The nature of this transaction resulted in 1133069 being deemed the acquirer of Orleans. 1133069 was incorporated on October 18, 2004 and commenced active oil and gas operations on December 22, 2004 through the acquisition of producing assets in the Halkirk area of east-central Alberta. As such, the disclosure within this MD&A reflects the continuation of 1133069's business from the date of its incorporation of October 18, 2004. Since Orleans only commenced active oil and gas operations on December 22, 2004, there is no available comparison of the financial and operating results for the nine month period ended December 31, 2005 with the corresponding 2004 nine month period. However, as a means of demonstrating the Company's significant growth profile, financial information for the abbreviated prior fiscal reporting period ended March 31, 2005 ("Period Ended March 31"), in addition to the 2005 calendar quarterly periods ended March 31 ("Cal Q105"), June 30 ("Cal Q205"), September 30 ("Cal Q305"), December 31 ("Cal Q405") and calendar 2005 year ("Cal Year 2005") are presented within this MD&A commentary along with the financial results for the nine month period ended December 31, 2005 ("Nine Month Period Ended December 31").

On April 1, 2005, the Company completed an amalgamation with its wholly-owned subsidiaries, 1133069 Alberta Ltd. and Islay Energy Ltd. Effective April 1, 2005, both entities, 1133069 Alberta Ltd. and Islay Energy Ltd., 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, 2005 onwards.

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

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

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

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, 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 29, 2006.

Corporate Overview

The Company is actively engaged in the exploration for, development and production of natural gas, crude oil and natural gas liquids reserves within the province of Alberta. Orleans' presently has a market capitalization of approximately $94 million. Current production is weighted approximately 55 percent sweet natural gas and 45 percent light oil and natural gas liquids. The Company's production base is generated from two core producing areas within central Alberta and is supported by quality crude oil and natural gas reserves with a proved plus probable reserve life index of approximately eight years. Orleans' operates approximately 81 percent of its total oil and gas production and holds a corporate average working interest of approximately 71 percent.



Selected Period End and Quarterly Financial Information

------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31 (1)
------- ------ ------ ------ -------- -------

Petroleum & natural
gas revenue 8,452 6,981 3,982 2,595 19,415 2,856
Cash flow from operations 4,973 4,442 2,342 1,304 11,757 1,424
Net earnings 16,203 2,406 856 69 19,465 78
Total assets - period end 50,684 32,196 28,795 24,216 50,684 24,216
------------------------------------------------------------------------

Note 1: The results for the Period Ended March 31 reflects Orleans'
activities for the period between October 18, 2004 (corporate
inception) and March 31, 2005. The petroleum and natural gas
activities included in the results of this period reflects oil
and gas operating activities since December 22, 2004. Prior to
this date, the Company was an inactive corporate entity. As
such, the Company's petroleum and natural gas results for the
Period Ended March 31 reflect operating activities over a 100
day period between December 22, 2004 and March 31, 2005.

 


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

Petroleum and Natural Gas Production

Calendar 2005 marks the Company's inaugural year as an explorer and producer of crude oil and natural gas within the province of Alberta. Successful development drilling of numerous geologic horizons, re-completion activities on existing well bores, and concentrated acquisitions have enabled Orleans to significantly expand its oil and gas production throughout 2005. Through to December 31, 2005, Orleans' participated in drilling 18 wells (16.5 net) and completed workovers on 14 existing wellbores at Halkirk, located in east-central Alberta. Production at Halkirk is now attained from a number of formations including: Edmonton, Horseshoe Canyon Coals, Viking, Glauconite and Ellerslie. At Pine Creek, the Company's second core area located in west-central Alberta, Orleans' established an initial presence in April 2005 through successful Crown land sale participation, acquiring a 100 percent working interest in 3.75 sections of land. Soon thereafter, the Company established a production base through the corporate acquisition of a private oil and gas company on June 1, 2005. This acquisition provided Orleans with approximately 75 boe per day of production (natural gas and associated liquids) and 2 (1.0 net) sections of land.

For the nine month fiscal period ended December 31, 2005, the Company's natural gas production averaged 3,262 mcf per day and crude oil and NGLs production averaged 594 bbls per day, resulting in a combined oil equivalent average daily rate of 1,138 boe per day. During Cal Q405, Orleans' average daily oil equivalent production was 1,378 boe per day, weighted 50 percent towards light gravity crude oil (33 degree API) and NGLs. On an oil-equivalent basis, Orleans' crude oil and natural gas sales volumes increased sequentially by 15 percent as compared to the preceding Cal Q305. The Company's natural gas sales for Cal Q405 averaged 4,160 mcf per day and crude oil and NGLs production averaged 685 bbls per day. Within the average daily production for Cal Q405, approximately 40 boe per day is attributable to a prior period adjustment relating to a well payout, whereby an Orleans' held 15 percent well gross overriding royalty interest was converted into a 30 percent working interest position retroactively effected February 1, 2005. The incremental working interest volumes, in excess of the recorded gross override royalty interest volumes, were not previously recognized in Cal Q205 or Cal Q305 periods.



------------------------------------------------------------------------
Average Daily Production
-------------------------------------------------
Natural Gas Crude Oil & NGLs Oil Equivalent
------------- ------------------ ----------------
(mcf/d) (bbls/d) (boe/d)
Cal Q105 1,404 325 559
Cal Q205 2,385 435 832
Cal Q305 3,231 662 1,200
Cal Q405 4,160 685 1,378

Cal Year 2005 2,804 528 995
Nine Month Period 3,262 594 1,138
------------------------------------------------------------------------

 


Petroleum and Natural Gas Revenue and Commodity Pricing

As a result of significant production growth, in conjunction with record commodity prices, Orleans' aggregate petroleum and natural gas revenue for the nine month fiscal period ended December 31, 2005 amounted to $19.42 million. Strong revenue realization was also achieved in Cal Q405, which amounted to $8.45 million (before royalties and transportation costs), representing a 21 percent increase from the preceding Cal Q305. Of this $1.47 million increase over Cal Q305, 74 percent is due to increased production volumes in Cal Q405 while 26 percent of this positive variance is attributable to increased commodity prices vis-a-vis Cal Q305 commodity pricing.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Crude oil & NGLs revenue 4,009 4,093 2,308 1,620 10,410 1,746
Natural gas revenue 4,444 2,887 1,674 976 9,005 1,110
------- ------ ------ ------ -------- -------
Gross revenue 8,453 6,980 3,982 2,596 19,415 2,856
------------------------------------------------------------------------

 


Orleans may utilize derivative instruments to hedge future prices on a portion of its oil and gas production in order to achieve more predictable cash flows to fund capital expenditures and to reduce exposure to downward commodity price fluctuations. The Company currently does not have any such contracts outstanding nor were there any outstanding during the nine month period ended December 31, 2005.

The market prices for both crude oil and natural gas in Cal Year 2005 reached record highs, supporting significant revenue recognition not only for Orleans but for the entire upstream oil and gas industry. A variety of market factors, primarily a combination of tight supply in North America for natural gas and globally for crude oil, and continued strong demand for both products, fuelled lofty commodity prices. The following table highlights Orleans' corporate realized commodity prices as well as benchmark market prices:



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period
Cal Ended
Cal Cal Cal Cal Year December
Q405 Q305 Q205 Q105 2005 31
------- ------ ------ ------ -------- -------
Orleans' prices:
Natural gas ($/mcf) 11.61 9.71 7.71 7.73 9.75 10.04
Crude oil and NGLs ($/bbl) 63.64 67.25 58.33 55.40 62.44 63.70
Oil equivalent ($/boe) 66.67 63.23 52.58 51.62 60.60 62.04
Industry benchmark prices:
WTI Cushing oil (US$/bbl) 60.02 63.31 53.22 50.03 56.60 58.85
Edmonton Par oil ($/bbl) 71.40 77.02 65.73 61.67 69.18 71.38
Nymex gas (US$/mmbtu) 12.88 9.73 6.95 6.50 9.01 9.85
AECO gas ($/mcf) 11.46 9.36 7.36 6.91 8.65 9.39
------------------------------------------------------------------------

 


Petroleum and Natural Gas Royalties

The Company's petroleum and natural gas royalties for the nine month fiscal period ended December 31, 2005 amounted to $3.96 million, resulting in a corporate effective royalty rate of 20.4 percent. Approximately 55 percent of the Company's total royalties for this period relate to Crown royalties with the residual 45 percent pertaining to freehold and overriding royalty encumbrances. During Cal Q405, total royalties amounted to $1.90 million, a 44 percent increase from Cal Q305. The aggregate increase of $581 thousand is attributable to two factors: i) higher production volumes realized in Cal Q405 as compared to Cal Q305, and ii) recognized year-end 2005 Crown-levied freehold mineral tax. The Company anticipates its corporate effective royalty rate for future periods to increase marginally to a range of 21 to 22 percent, taking into account the expected mid-2006 expiry of the deep gas Crown royalty holiday on the Pine Creek gas production.

Orleans was not eligible to receive the Alberta Royalty Tax Credit ("ARTC") recovery on crown royalties incurred on a majority of its production from the Halkirk property as these assets were originally acquired from an "above-limit corporation" claiming the maximum ARTC entitlement. Additionally, the Company's Pine Creek gas wells are currently exempt from Crown royalties due to their deep gas Crown royalty holiday status.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Crown 1,158 620 405 367 2,183 406
Freehold and overrides 745 702 334 181 1,781 201
------- ------ ------ ------ -------- -------
Total 1,903 1,322 739 548 3,964 607
------- ------ ------ ------ -------- -------
------- ------ ------ ------ -------- -------

Corporate royalty rate (%) 22.5% 18.9% 18.5% 21.3% 20.4% 21.3%
------------------------------------------------------------------------

 


Operating Expenses

The Company's aggregate field operating expenditures for the nine month fiscal period ended December 31, 2005 amounted to $2.52 million or $8.05 on an oil-equivalent per unit basis. During Cal Q405, Orleans' field costs amounted to $1.12 million, a 37 percent increase from Cal Q305. This aggregate increase of $302 thousand is attributable to the following factors: i) higher production volumes realized in Cal Q405, ii) higher field power costs due to a 75 percent increase in market electricity prices over Cal Q305, iii) a scheduled booster compressor turnaround at the Company's operated Halkirk gas plant, iv) unscheduled minor workovers on three wellbores, and v) increased compressor rental charges resulting from the November 2005 commissioning of a larger compressor unit at one the Company's operated battery installations. Orleans continues to operate a majority of its production, approximately 81 percent, thus enabling the Company to manage and control the timing, level and scope of its operating costs.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Total ($000s) 1,117 815 587 501 2,519 550
Per unit ($/boe) 8.81 7.38 7.75 9.81 8.05 9.81
------------------------------------------------------------------------

 


Transportation Expenses

The cost of transporting and distributing Orleans' crude oil and natural gas production to market delivery points during the nine month period ended December 31, 2005 amounted to $325 thousand or $1.04 on an oil-equivalent per unit basis. In Cal Q405, transportation expenses amounted to $139 thousand, as compared to $120 thousand incurred in Cal Q305. On a unit-of-production basis, transportation costs of $1.09 per boe in Cal Q405 mirrored the per unit charge in Cal Q305. Increased production volumes, supplemented with increased clean oil trucking rates and Nova gas pipeline fuel surcharges throughout calendar 2005 resulted in transportation cost increases, both on an aggregate and per-unit basis.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Total ($000s) 139 120 66 41 325 45
Per unit ($/boe) 1.09 1.09 0.87 0.82 1.04 0.80
------------------------------------------------------------------------

 


General & Administrative Expenses

The Company's general and administrative ("G&A") expenses during the nine month period ended December 31, 2005, excluding the non-cash stock-based compensation provision, amounted to $815 thousand or $2.60 on an oil-equivalent per unit basis. In Cal Q405, expensed G&A amounted to $300 thousand, as compared to $258 thousand incurred in Cal Q305. Gross G&A, net of operator recoveries, increased by $193 thousand in Cal Q405 as a result of year-end performance bonuses disbursed to employees of Orleans and accruals for costs associated with the year-end independent engineering reserves report and the annual financial statement accounting audit. Orleans presently employs ten head office personnel, including six geological and engineering technical personnel, and engages the services of three consultants on a part-time basis.

The Company applies the full cost method of accounting for its oil and gas operations. Accordingly, it capitalized employee compensation and associated direct overhead costs of its technical personnel in the amount of $521 thousand during the nine month period ended December 31, 2005. In Cal Q405, capitalized G&A amounted to $261 thousand.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Gross, net operator
recoveries 561 368 407 265 1,336 283
Capitalized (261) (110) (150) (103) (521) (103)
Expensed 300 258 257 162 815 180
------- ------ ------ ------ -------- -------
Per unit ($/boe) 2.36 2.34 3.39 3.21 2.60 3.21
------- ------ ------ ------ -------- -------
------- ------ ------ ------ -------- -------
% Capitalized 47% 30% 37% 39% 39% 36%
------------------------------------------------------------------------

 


Stock-Based Compensation

Orleans utilizes the fair value method for quantifying stock option expenses. During the nine month period and three month periods ended December 31, 2005, the Company recorded non-cash stock-based compensation charges of $369 thousand and $129 thousand, respectively. These provisions were recognized primarily in connection with the amortization of stock options granted in prior periods.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Stock-based compensation 129 97 143 247 369 247
------------------------------------------------------------------------

 


Interest Charges

In the nine month period ended December 31, 2005, Orleans incurred $37 thousand in interest charges relating to its outstanding bank indebtedness. For Cal Q405, debt servicing charges amounted to $22 thousand. At December 31, 2005, the Company had $719 thousand drawn against its bank facility, as compared to nil drawn at March 31, 2005.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Interest charges/(income) 22 23 (8) 40 37 51
------------------------------------------------------------------------

 


Depletion, Depreciation and Accretion

Orleans' depletion and depreciation expense for the nine month and three month periods ended December 31, 2005 amounted to $5.40 million and $2.23 million, respectively. Cal Q405 depletion and depreciation in absolute dollars was $343 thousand greater than Cal Q305, primarily the result of increased production volumes. On a unit-of-production rate basis, the depletion and depreciation provision for nine month and three month periods ended December 31, 2005 were $17.25 per boe and $17.55 per boe, respectively.

The Company's accretion expense relating to its asset retirement obligations ("ARO") amounted to $159 thousand for the nine month period ended December 31, 2005 and $51 thousand for Cal Q405.



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Depletion & depreciation 2,225 1,882 1,291 937 5,398 1049
ARO accretion 51 56 52 50 159 50
------- ------ ------ ------ -------- -------
Total 2,276 1,938 1,343 987 5,557 1,099
------- ------ ------ ------ -------- -------
------- ------ ------ ------ -------- -------
Per unit ($/boe) 17.96 17.55 17.73 19.61 17.76 19.62
------------------------------------------------------------------------

 


Income and Capital Taxes

Orleans follows the liability method of accounting for income taxes whereby future income taxes are calculated based on temporary differences arising from the variance between the tax basis of an asset or liability and its property, plant and equipment carrying value. Orleans presently has sufficient tax pools or basis in excess of its asset carrying value, thus reflecting an unrecognized future income tax asset. On June 1, 2005, the Company released a portion of its valuation allowance and eliminated a future income tax payable of $578 thousand associated with the acquisition of a private oil and gas company. As at December 31, 2005, the Company evaluated the criteria relating to the recognition of the previously unrecognized future income tax asset and concluded that the realization of such assets in future periods is more likely than not. A $13.64 million income tax reduction was recorded and recognized in the nine month period ended December 31, 2005.

During the nine month period ended December 31, 2005, the Company did not pay any corporate income tax. Due to the Company's significant tax pool balances, which aggregate to approximately $70.53 million, Orleans' does not expect to be subject to corporate cash income tax in the foreseeable future. Additionally, during the period Orleans was not liable for the payment of the large corporation capital tax since its stated book capitalization was less than $50 million.

The following table outlines the tax pools available to the Company at December 31, 2005:



------------------------------------------------------------------------
Access Rate Balance
------------- ---------
($ millions)
Canadian exploration expense (CEE) 100% $ 4.85
Canadian development expense (CDE) 30% 11.35
Canadian oil and gas property expense (COGPE) 10% 12.41
Undepreciated capital cost (UCC) 25% 6.84
Non-capital losses (NCL) 100% 33.87
Share issue costs and other 20% 1.21
------------------------------------------------------------------------
Total $ 70.53
------------------------------------------------------------------------

 


Operating Cash Flow and Net Earnings

In the nine month period ended December 31, 2005, Orleans recorded $11.76 million in cash flow from operations and $19.47 million in net earnings (includes a $13.64 million income tax reduction). For Cal Year 2005, the Company generated $13.06 million in cash flow from operations ($0.92 per basic share) and $19.53 million in net earnings ($1.38 per basic share).



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s except share data) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Cash flow from
operations (1) 4,973 4,442 2,342 1,304 11,757 1,424
Per share - basic 0.33 0.30 0.16 0.12 0.78 0.15
Per share - diluted 0.31 0.28 0.15 0.11 0.74 0.15

Net earnings 16,203 2,406 856 69 19,465 78
Per share - basic 1.07 0.16 0.06 0.01 1.29 0.01
Per share - diluted 1.01 0.15 0.05 0.01 1.23 0.01
------------------------------------------------------------------------

(1) Cash flow from operations does not have any standardized meaning
prescribed by Canadian GAAP and accordingly represents Funds from
Operations 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

In the nine month period ended December 31, 2005, the Company's capital investment expenditures amounted to $19.78 million. Throughout Cal Year 2005, Orleans was actively expanding its asset base and incurred $24.62 million in capital activities. At Halkirk, the Company drilled 16 (15.8 net) operated wells and participated in the drilling of 2 (0.7 net) joint venture wells. Additionally, Orleans expanded its land holdings both at Halkirk and at Pine Creek through Crown land sale participation and also established a producing asset presence at Pine Creek through the acquisition of a private oil and company on June 1, 2005 for total cash consideration $2.86 million (net of cash acquired of $346 thousand) and assumption of its working capital deficit of $154 thousand (excluding cash acquired).

The breakdown of Orleans' capital programs, by respective reporting periods, are outlined below:



------------------------------------------------------------------------
2005 Quarterly Comparison Nine
----------------------------- Month
Period Period
Ended Ended
Cal Cal Cal Cal December March
($000s) Q405 Q305 Q205 Q105 31 31
------- ------ ------ ------ -------- -------

Land 391 41 1,159 527 1,591 527
Seismic 858 - 7 34 865 34
Drilling & completions 4,594 2,607 3,084 2,480 10,285 2,480
Facilities & well
equipment 1,342 1,269 695 494 3,306 494
------- ------ ------ ------ -------- -------
Exploration & development 7,185 3,917 4,945 3,535 16,047 3,535
------- ------ ------ ------ -------- -------
Other 234 174 160 174 568 174
Property purchases (2) 11 142 559 151 13,474
Corporate acquisitions - - 3,016 572 3,016 572
------- ------ ------ ------ -------- -------
Total capital expenditures 7,417 4,102 8,263 4,840 19,782 17,755
------------------------------------------------------------------------

 


Liquidity and Capital Resources

At December 31, 2005, the Company was capitalized with a working capital deficit of $4.61 million (including bank debt of $0.72 million and excluding a current income tax asset of $6.63 million), and 15.1 million common shares outstanding with a book capitalization of $19.94 million and a market capitalization of $93.16 million.



------------------------------------------------------------------------
2005 Quarter End Comparison
---------------------------------------------

($000) Dec. 31 Sep. 30 Jun. 30 Mar. 31
---------- ---------- ---------- ----------
Bank debt 718.8 1,725.0 100.0 -
Working capital deficit /
(surplus) (1) 3,894.3 445.2 2,427.8 (3,415.5)
---------- ---------- ---------- ----------
Net Debt 4,613.1 2,170.2 2,527.8 (3,415.5)
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Net debt-to-book
capitalization (%) 23% 11% 13% -
Book capitalization (2) 19,937.7 19,912.3 19,881.7 19,881.7
Market capitalization (3) 93,161.1 87,458.5 56,302.1 54,194.6
------------------------------------------------------------------------

Note 1: Reflects current assets (excluding any current income tax
assets) less current liabilities (excluding any outstanding bank
debt).

Note 2: Reflects the book value of share capital, as reported on the
Company's respective balance sheets.

Note 3: Based on the market closing price of Orleans stock and the
outstanding number of common shares at period end.

 


The increase in the net debt position of the Company at December 31, 2005, as compared to September 30, 2005, is directly attributable to capital investments incurred in Cal Q405 exceeding the cash generated by operating activities within that period.

At December 31, 2005, the Company had borrowings of $0.72 million under its bank facility with a Canadian commercial bank and was in compliance with all covenant terms of the bank facility agreement. As a result of the Company's expanded oil and gas reserves base at year-end 2005, the bank facility borrowing base was recently increased to $22.5 million, as compared to the previous $8.0 million bank facility.

Orleans' main sources of liquidity are internally-generated cash flow from its oil and gas operations, undrawn bank credit facilities and access to equity capital markets. Because of the liquidity and capital resource alternatives available to the Company, including internally-generated cash flow, Orleans believes its liquidity is sufficient to fund operating, general and administrative and interest expenses, including planned spending on exploration and development projects and undeveloped acreage. The Company anticipates that public capital markets will serve as the principal source of capital to finance any future substantial corporate acquisitions and/or significant property purchases.



Common Share Information

------------------------------------------------------------------------
2005 Quarterly Comparison
-----------------------------------------------
Cal Q405 Cal Q305 Cal Q205 Cal Q105
----------- ----------- ----------- -----------
Share Price: High $ 6.35 $ 6.25 $ 3.90 $ 4.20
Low $ 5.60 $ 3.68 $ 3.21 $ 3.00
Close $ 6.17 $ 5.80 $ 3.74 $ 3.65
Avg. daily trading
volume (1) 25,624 95,242 33,320 85,336
Shares outstanding
- period end (2) 15,099,047 15,079,047 15,054,047 15,054,047
Weighted average basic 15,084,264 15,057,036 15,054,047 11,335,241
Weighted average diluted 15,979,723 15,861,948 15,749,603 11,859,756
------------------------------------------------------------------------

------------------------------------------------------------------------
Nine Month
Period
Cal Ended
2005 December 31
---------- ------------
Share Price: High $ 6.35 $ 6.35
Low $ 3.00 $ 3.21
Close $ 6.17 $ 6.17
Avg. daily trading volume (1) 57,807 35,004
Shares outstanding - period end (2) 15,099,047 15,099,047
Weighted average basic 14,145,451 15,065,156
Weighted average diluted 14,836,572 15,854,191
------------------------------------------------------------------------

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

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

Note 3: As of the date of this MD&A, total common shares issued and
outstanding are 15,099,047.

 


Contractual Obligations

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



------------------------------------------------------------------------
($000s) Less than 1 - 3 4 - 5 Beyond
1 Year Years Years 5 Years Total
----------- ------- ------- --------- -------
Bank debt (1) 719 - - - 719
Operating lease
obligations (2) 124 82 - - 206
Asset retirement
obligations (3) 147 450 676 4,582 5,855
----------- ------- ------- --------- -------
Total obligations 990 532 676 4,582 6,780
------------------------------------------------------------------------

Note 1: Revolving credit facility with a commercial bank. Refer to Note
5 to the audited financial statements for the nine month period
ended December 31, 2005.

Note 2: Operating lease obligations pertain to the Company's Calgary,
Alberta head office lease.

Note 3: As at December 31, 2005, total undiscounted future asset
retirement obligation costs to be accrued over the life of the
remaining total proved are estimated at $5.85 million (adjusted
for inflation). This estimate is subject to change based on
amendments to environmental laws and as new information with
respect to the Company's operations become available. Refer to
Note 6 to the audited financial statements for the nine month
period ended December 31, 2005.

 


Off-Balance Sheet Arrangements

The Company did not enter into any off-balance sheet transactions during the nine month period ended December 31, 2005.

Related Party Transactions

A director and the corporate secretary of the Company are partners at a law firm that provide legal services to the Company. During the nine month period ended December 31, 2005, the Company paid and accrued a total of $59 thousand to this firm for legal fees and disbursements.

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, 2005. 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.

Business Outlook

Since commencing active oil and gas operations in January 2005, Orleans has been able to efficiently and effectively expand its asset base in a profitable manner. In 2006, the Company plans to execute the previously disclosed 2006 Capital Budget of $24.5 million and drill a total of 27 wells (21.5 net). This program encompasses drilling 23 wells (18.2 net) on Orleans' asset base at Halkirk directed towards the continued development and exploitation of multi-zone reservoirs including: Mannville, Viking, Edmonton and Horseshoe Canyon Coal Bed Methane and an initial 4 well (3.3 net) program at Pine Creek pursuing multi-zone prospects, characterized by low decline, liquids-rich gas production and long-life reserves. The Company believes that the drilling and completion opportunities on its Halkirk property, in addition to the potentially higher impact prospects from Orleans' Pine Creek property, will provide continued stable growth throughout 2006 and into 2007.

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 possessing greater financial and personnel resources. The Company recognizes certain risks inherent in the oil and gas industry, such as access to oil and gas services, weather-related delays with drilling and operational plans, finding and developing oil and gas reserves at economic costs, drilling risks, producing oil and gas in commercial quantities, environmental and safety risks, and commodity price and political risks and uncertainties. Orleans has engaged professional management and technical personnel with many years of experience in the oil and gas business to address, prudently manage and mitigate these risks.

Application of Critical Accounting Policies and Estimates

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

Full-Cost Accounting

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

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

Asset Retirement Obligation

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

Income Tax Accounting

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

For further details on the Company's accounting policies, refer to Note 2 of the notes to the audited financial statements for the nine month period ended December 31, 2005.

The Company's audited financial statements for the nine month fiscal period ended December 31, 2005 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, expectations, 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
(audited) December 31, March 31,
2005 2005
------------ -------------
ASSETS

Current Assets

Cash and cash equivalents $ - $ 3,352,589
Accounts receivable 3,397,255 1,966,979
Prepaid expenses and deposits 305,762 240,796
Current income tax asset (Note 10) 6,633,855 -
------------ -------------
10,336,872 5,560,364

Property, plant and equipment (Note 4) 33,346,079 18,656,038

Future income tax asset (Note 10) 7,001,232 -
------------ -------------

$ 50,684,183 $ 24,216,402
------------ -------------
------------ -------------
LIABILITIES

Current Liabilities

Accounts payable and accrued
liabilities $ 7,597,341 $ 2,144,882
Bank loan (Note 5) 718,800 -
------------ -------------
8,316,141 2,144,882

Asset retirement obligations (Note 6) 2,484,234 2,057,064
------------ -------------

$ 10,800,375 $ 4,201,946
------------ -------------
------------ -------------
SHAREHOLDERS' EQUITY

Share capital (Note 7) 19,937,717 19,881,743
Contributed surplus (Note 8c) 565,359 217,447
Retained earnings (deficit) 19,380,732 (84,734)
------------ -------------

39,883,808 20,014,456
------------ -------------

$ 50,684,183 $ 24,216,402
------------ -------------
------------ -------------

Nature of Operations and Organization and Significant Accounting
Policies (Notes 1 & 2)
Commitments and Contingencies (Note 13)
Subsequent Events (Note 15)


On behalf of the Board of Directors:

(signed) " Barry Olson" (signed) "James Saunders"

Barry Olson James Saunders
Director Director

See accompanying notes to the financial statements.


ORLEANS ENERGY LTD.
Statements of Operations and Retained Earnings
(audited)
Nine Month
Period Ended Period Ended
December 31, March 31,
2005 2005
------------- -------------

Revenue
Petroleum and natural gas sales $ 19,415,330 $ 2,856,400
Royalties (3,963,632) (607,046)
------------- -------------

15,451,698 2,249,354
------------- -------------
Expenses
Operating 2,518,604 549,503
Transportation 324,987 44,619
General and administrative 814,612 180,010
Interest 36,680 51,280
Stock-based compensation 369,119 247,382
Depletion, depreciation and accretion 5,557,317 1,098,946
------------- -------------
$ 9,621,319 $ 2,171,740
------------- -------------

Earnings before taxes 5,830,379 77,614

Income taxes (reduction) (Note 10) (13,635,087) -
------------- -------------

Net earnings $ 19,465,466 $ 77,614

Retained earnings (deficit), beginning
of period (84,734) -

Capital transaction costs (Note 1) - (162,348)
------------- -------------

Retained earnings (deficit), end of period $ 19,380,732 $ (84,734)
------------- -------------
------------- -------------

Net earnings per share (Note 9)
Basic $ 1.29 $ 0.01
------------- -------------
------------- -------------

Diluted $ 1.23 $ 0.01
------------- -------------
------------- -------------

See accompanying notes to the financial statements.


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

Operating activities
Net earnings $ 19,465,466 $ 77,614
Items not affecting cash:
Depletion, depreciation and accretion 5,557,317 1,098,946
Stock-based compensation 369,119 247,382
Income taxes (reduction) (13,635,087) -
Asset retirement expenditures (38,086) -
------------- -------------

Funds from operations 11,718,729 1,423,942
Change in non-cash working capital
(Note 11) (119,622) (1,938,393)
------------- -------------
11,599,107 (514,451)
------------- -------------

Financing activities
Increase in bank loan 718,800 4,700,000
Repayment of bank loan - (4,700,000)
Exercise of stock options 36,000 50,817
Proceeds from share issues, net of issue
costs (1,232) 18,570,991
------------- -------------
753,568 18,621,808
------------- -------------
Investing activities
Corporate acquisition, net cash acquired
(Note 3) (2,861,229) -
Property, plant and equipment additions (16,920,874) (15,896,003)
Cash acquired through Arrangement
(Note 1) - 258,087
Change in non-cash working capital
(Note 11) 4,076,839 883,148
------------- -------------
(15,705,264) (14,754,768)
------------- -------------

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

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

Cash and cash equivalents, end of period $ - $ 3,352,589
------------- -------------

Supplemental Cash Flow Information (Note 11)

See accompanying notes to the financial statements.


ORLEANS ENERGY LTD.
Notes to the Audited Financial Statements
Nine month period ended December 31, 2005

 


1. Nature of Operations and Organization

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".

Effective, January 31, 2005, the Company's business was restructured to that of crude oil and natural gas exploration and production through a corporate plan of arrangement (the "Arrangement"). Through the completion of the Arrangement: (i) former shareholders of Orleans Resources Inc. became shareholders of Orleans, (ii) Orleans Resources Inc. became a wholly-owned subsidiary of Orleans, (iii) Orleans Resources Inc. ceased to be a reporting issuer; and, (iv) Orleans became a reporting issuer in each of the provinces of Alberta, British Columbia and Quebec.

Additionally, in conjunction with the Arrangement, the Company acquired all of the issued and outstanding shares of a private oil and gas company, 1133069 Alberta Ltd. ("1133069"), by way of a share exchange whereby all of the issued and outstanding shares of 1133069 were exchanged for shares of Orleans on the basis of one (1) common share of Orleans for four (4) common shares of 1133069. 1133069 Alberta Ltd. was incorporated on October 18, 2004 and commenced active oil and gas operations on December 22, 2004. This transaction was accounted for as a reverse take-over of Orleans by 1133069, resulting in 1133069 being the deemed acquirer of Orleans. While the balance sheet and share capital are of the Company as a legal entity, the assets, liabilities and dollar amounts attributed to share capital are those of 1133069 and the financial statements present a continuation of 1133069's business since its corporate inception of October 18, 2004. Prior to the Arrangement, Orleans did not constitute a business and consequently the reverse take-over has been accounted for as a capital transaction rather than a business combination. The net liabilities of Orleans prior to the Arrangement, in the amount of $162,348, was treated as a charge to the retained earnings of the combined enterprise. The value of the assets acquired was as follows:



------------------------------------------------------------------------
Cash $ 258,087
Working capital deficiency (420,435)
-------------
Charge to retained earnings (162,348)
------------------------------------------------------------------------
------------------------------------------------------------------------

 


On April 1, 2005, the Company completed an amalgamation with its wholly-owned subsidiaries, 1133069 Alberta Ltd. and Islay Energy Ltd. Effective April 1, 2005, both entities, 1133069 Alberta Ltd. and Islay Energy Ltd., 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, 2005 onwards.

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

2. Significant Accounting Policies

a) Principles of consolidation and basis of presentation

The financial statements have been prepared by Management in accordance with Canadian generally accepted accounting principles ("GAAP"). The financial statements include the accounts of the Company and its wholly-owned subsidiaries from the respective dates of acquisition of the subsidiary companies (when applicable). 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.

b) Measurement uncertainty

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

c) Petroleum and natural gas operations

i) Capitalized costs

The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Such capitalized costs may include lease acquisition costs, geological and geophysical expenses, costs of drilling both productive and non-productive wells, gathering and production facilities, lease rentals on non-producing properties, interest on debt directly related to certain acquisitions, and certain other overhead expenditures directly related to exploration and development activities. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation by 20 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 as determined by an independent qualified reserve engineering firm. In determining costs subject to depletion, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the costs of unproved properties. The costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties or until impairment occurs. For depletion and depreciation purposes, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six (6) thousand cubic feet of natural gas to one (1) barrel of crude oil. Depreciation on office furniture and other equipment is provided for over its useful lives using the declining balance method at a rate of 20 percent.

iii) Ceiling test

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

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

d) Asset retirement obligations ("ARO")

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

e) Flow-through shares

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

f) Per share amounts

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

g) Income taxes

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

h) Revenue recognition

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

i) Stock-based compensation plan

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

j) Derivative financial instruments

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

k) Dividend policy

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

l) Cash and cash equivalents

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

3. Corporate Acquisition

On June 1, 2005 the Company acquired all of the issued and outstanding shares of Mojo Energy Inc., a private company ("Privateco") involved in the exploration and production of natural gas and natural gas liquids in west-central Alberta for total cash consideration of $3.2 million. The acquisition was funded through the Company's available cash-on-hand.

This business combination has been accounted for using the purchase method with the results of operations of Privateco included in Orleans' financial results June 1, 2005 thereafter. The purchase price allocation did not result in an excess purchase price over the fair value of net assets acquired.



The allocation of the purchase price and consideration paid is as
follows:

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


Net assets acquired (allocated at
estimated fair values):
Property, plant and equipment $ 3,025,776
Current assets (includes $346,396 cash acquired) 754,269
Current liabilities (561,644)
Asset retirement obligation (10,776)
-------------
Total net assets acquired $ 3,207,625
------------------------------------------------------------------------
------------------------------------------------------------------------

 


Future income taxes payable of $578 thousand resulting from the temporary differences between the allocated fair values for Privateco's assets and liabilities and the associated tax basis were eliminated through the recognition of previously unrecognized future tax assets of Orleans.



4. Property, Plant and Equipment

------------------------------------------------------------------------
December 31, 2005 March 31, 2005
----------------------------------
Petroleum and natural gas properties $ 39,743,164 $ 19,663,483
Accumulated depletion (6,447,902) (1,058,380)
----------------------------------
33,295,262 18,605,103
----------------------------------

Office equipment and other 70,583 62,371
Accumulated depreciation (19,766) (11,436)
----------------------------------
50,817 50,935
----------------------------------

Net property, plant and equipment $ 33,346,079 $ 18,656,038
------------------------------------------------------------------------
------------------------------------------------------------------------

 


During the nine month period ended December 31, 2005, the Company capitalized, as part of property, plant and equipment, certain overhead expenses of $521 thousand (March 31, 2005: $103 thousand) directly related to exploration and development activities.

At December 31, 2005, property, plant and equipment included $2.72 million (March 31, 2005: $688 thousand) relating to unproved properties, which have been excluded from the depletion calculation. Future development costs related to proved non-producing developed reserves of $5.01 million (March 31, 2005: $955 thousand) have been included in the depletion calculation.
The Company performed a ceiling test calculation as at December 31, 2005 to assess the recoverable value of the property, plant and equipment. The oil and gas future prices are based on the December 31, 2005 price forecast of the Company's independent reserve evaluators with such information outlined in the following table. Based on these assumptions, the undiscounted value of future net revenues from the Company's estimated proved reserves exceeded the carrying value of property, plant and equipment as at December 31, 2005.



------------------------------------------------------------------------
WTI Edmonton Company's AECO-C Company's
Price - Price - Price - Price - Price - Exchange
Oil Oil Oil Gas Gas Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ($US/$Cdn)
------------------------------------------------------------------------

2006 60.81 70.07 63.35 11.58 12.26 0.8500
2007 61.61 70.99 64.31 10.84 11.32 0.8500
2008 54.60 62.73 56.07 8.95 9.47 0.8500
2009 50.19 57.53 50.90 7.87 8.41 0.8500
2010 47.76 54.65 48.03 7.57 8.26 0.8500
2011 48.48 55.47 48.85 7.70 8.49 0.8500
2012 49.20 56.31 49.69 7.83 8.70 0.8500
2013 49.94 57.16 50.54 7.96 8.90 0.8500
2014 50.69 58.02 51.39 8.09 9.19 0.8500
2015 51.45 58.89 52.28 8.23 9.34 0.8500
2016 52.22 59.78 53.16 8.37 9.49 0.8500
Escalated rate of
1.5% thereafter
------------------------------------------------------------------------

 


5. Bank Facility

As at December 31, 2005, the Company had a demand revolving credit facility of $8.0 million with a Canadian commercial bank. Amounts drawn on the bank facility bear interest at the lender's prime rate plus 0.25 percent per annum. At December 31, 2005, the Company had $719 thousand of bank debt outstanding (March 31, 2005: $nil). The bank facility is secured through a floating charge over all of the Company's assets and the lender reserves the right to require fixed charge security at its discretion. Under the terms of the banking arrangement, the Company is required to meet certain financial and engineering reporting requirements. The Company's banker is presently in the process of conducting their annual credit review.

6. 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, 2005, the estimated present value of the total amount required to settle the asset retirement obligations was $2.48 million (March 31, 2005: $2.06 million), based on a total undiscounted future liability amount of $5.85 million (inflation adjusted) (March 31, 2005: $5.10 million). These obligations are to be settled based on the economic lives of the underlying assets, which is currently projected to be from zero to 29 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.



------------------------------------------------------------------------
Asset retirement obligations - incorporation $ -
Liabilities incurred -
Liabilities acquired 2,007,409
Liabilities settled -
Accretion of discount 49,655
------------------------------------------------------------------------
Asset retirement obligations - March 31, 2005 $ 2,057,064
Liabilities incurred 295,013
Liabilities acquired 10,776
Liabilities settled (38,086)
Accretion of discount 159,467
------------------------------------------------------------------------
Asset retirement obligations - December 31, 2005 $ 2,484,234
------------------------------------------------------------------------
------------------------------------------------------------------------

 


For the nine month period ended December 31, 2005, the Company recognized depletion expense related to its Asset Retirement Cost of $348 thousand (March 31, 2005: $114 thousand).

7. Share Capital

a) Authorized

- Unlimited number of voting common shares.

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



b) Issued and outstanding

Number Number
of Voting of Non-Voting Total Number
Common Common of Common
Shares Shares Shares Amount
------------------------------------------------------------------------
Issued per
Arrangement
(Note 1):
To 1133069
shareholders 3,110,351 3,950,610 7,060,961 $ 6,780,000
To Orleans
shareholders 3,262,898 - 3,262,898 -
----------------------------------------------------
6,373,249 3,950,610 10,323,859 6,780,000
Issued on private
placement 4,666,667 - 4,666,667 14,000,000
Share issue costs - - - (979,010)
Exercise of stock
options 63,521 - 63,521 80,753
------------------------------------------------------------------------
Balance, March 31,
2005 11,103,437 3,950,610 15,054,047 $ 19,881,743
Share capital
reorganization
(Note 7a) 3,950,610 (3,950,610) - -
Share issue costs - - - (1,232)
Exercise of stock
options 45,000 - 45,000 57,206
------------------------------------------------------------------------
Balance,
December 31,
2005 15,099,047 - 15,099,047 $ 19,937,717
------------------------------------------------------------------------
------------------------------------------------------------------------

 


c) Shares in escrow

Of the total common shares issued through to December 31, 2005, 467,549 shares are currently held in escrow and may not be released from escrow and traded without the written consent of the appropriate regulatory authorities.

8. 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, 2005, 1,509,905 options with a weighted average exercise price of $1.77 were outstanding and exercisable at various dates through to December 20, 2010.



The following table summarizes outstanding stock options as at December
31, 2005:

Number Weighted Avg.
Exercise Price
-------------------------------
Outstanding - Incorporation - $ -
Granted 1,498,838 1.49
Exercised (63,521) 0.80
------------------------------------------------------------------------
Outstanding - March 31, 2005 1,435,317 $ 1.52
Granted 119,588 4.36
Exercised (45,000) 0.80
------------------------------------------------------------------------
Outstanding - December 31, 2005 1,509,905 $ 1.77
------------------------------------------------------------------------
------------------------------------------------------------------------

Options exercisable - December 31, 2005 277,939 $ 0.80
------------------------------------------------------------------------
------------------------------------------------------------------------


b) Exercise price range for options outstanding as at December 31, 2005:

------------------------------------------------------------------------
Outstanding Options Exercisable Options
------------------------------------------------------------------------
Weighted
Weighted Avg. Weighted
Avg. Remaining Avg.
Price Range Number Price Life Number Price
------------------------------------------------------------------------
$ 0.80 - 1.00 923,817 $ 0.80 4.07 years 277,939 $ 0.80
$ 3.00 - 3.75 536,588 $ 3.10 4.14 years - $ -
$ 5.25 - 6.00 49,500 $ 5.53 4.89 years - $ -
------------------------------------------------------------------------
Total 1,509,905 $ 1.77 4.12 years 277,939 $ 0.80
------------------------------------------------------------------------
------------------------------------------------------------------------


The Company determined the fair value of stock options granted during
the nine month period ended December 31, 2005 using the modified
Black-Scholes evaluation stock option pricing model under the
following assumptions:

------------------------------------------------------------------------
Period Ended Period Ended
December 31, 2005 March 31, 2005
-------------------------------------
Weighted-average fair value
($/option) 2.55 0.88
Risk-free interest rate (%) 3.70 3.68
Estimated hold period prior to
exercise (years) 5 5
Volatility in the price of
Orleans shares (%) 66.60 67.03
Dividend yield (%) Nil Nil
------------------------------------------------------------------------

c) Contributed surplus

The following table reconciles contributed surplus at December 31, 2005:

------------------------------------------------------------------------
Contributed surplus - Incorporation $ -
Stock-based compensation period recognition 247,382
Exercise of stock options (29,935)
------------------------------------------------------------------------
Contributed surplus - March 31, 2005 217,447
Stock-based compensation period recognition 369,119
Exercise of stock options (21,207)
------------------------------------------------------------------------
Contributed surplus - December 31, 2005 $ 565,359
------------------------------------------------------------------------
------------------------------------------------------------------------

 


9. 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.



------------------------------------------------------------------------
Period Ended Period Ended
December 31, 2005 March 31, 2005
-------------------------------------
Weighted average shares
outstanding:
Basic 15,065,156 9,392,387
Diluted 15,854,191 9,678,486
------------------------------------------------------------------------

 


10. 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:



------------------------------------------------------------------------
Period Ended Period Ended
December 31, 2005 March 31, 2005
-------------------------------------
Earnings before income taxes $ 5,830,379 $ 77,614
Combined federal and provincial
statutory tax rate 37.62% 38.07%
Calculated expected income taxes
(reduction) 2,193,389 29,548

Increase (decrease) resulting
from the tax effect of:
Non-deductible crown charges 539,515 107,476
Federal resource allowance (775,032) (107,406)
Stock-based compensation 138,863 94,190
Other (637,098) 1,163
Statutory rate change (344,695) (11,182)
Change in valuation allowance (14,750,029) (113,789)
Income taxes (reduction) $ (13,635,087) $ -
------------------------------------------------------------------------
------------------------------------------------------------------------

b) Income tax asset:

The components of the Company's income tax asset are as follows:

------------------------------------------------------------------------
December 31, March 31,
2005 2005
- ----------------------------
Future tax assets:
Capital assets (tax values in
excess of carrying value) $ 730,029 $ 72,135
Non-capital losses 11,724,177 14,250,635
Share issue costs and other 320,839 313,711
Asset retirement obligation 860,042 691,585
Valuation allowance - (15,328,066)
Net income tax asset $ 13,635,087 $ -
------------------------------------------------------------------------
------------------------------------------------------------------------
Allocated:
Current income tax asset 6,633,855 -
Future income tax asset 7,001,232 -
------------------------------------------------------------------------

 


As at December 31, 2005, the Company evaluated the criteria relating to the recognition of the previously unrecognized future income tax asset and the Company's Management concluded that the realization of such assets in future periods is more likely than not.

The Company's non-capital losses expire at various times from 2006 to 2014.



11. Supplemental Cash Flow Information

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

Period Ended Period Ended
December 31, 2005 March 31, 2005
----------------- --------------
Change in non-cash working
capital:
Accounts receivable and other
current assets $ (1,495,242) $ (1,920,551)
Accounts payable and accrued
Liabilities 5,452,459 865,306
----------------- --------------
$ 3,957,217 $ (1,055,245)
----------------- --------------
----------------- --------------

Changes in non-cash working
capital related to:
Operating activities $ (119,622) $ (1,938,393)
Investing activities 4,076,839 883,148
----------------- --------------
$ 3,957,217 $ (1,055,245)
----------------- --------------
----------------- --------------

b) Other cash flow information

Period Ended Period Ended
December 31, 2005 March 31, 2005
----------------- --------------

Interest paid (net of interest income) $ 36,680 $ 51,280
Income taxes paid - -
----------------- --------------
----------------- --------------

 


12. Financial Instruments and Risk Management

a) Commodity risk

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

The Company did not have any such contracts outstanding during the nine month period ended December 31, 2005 nor the prior period ended March 31, 2005, respectively. As well, there are no such contracts currently outstanding.

b) Credit risk

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

c) Interest rate risk

Financial instruments, which subject the Company to interest rate risk are limited to bank indebtedness. The Company's current operating credit facility agreement calculates interest based on the bank's prime lending rate plus 0.25 percent per annum.

d) Fair value of financial assets and liabilities

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

13. Commitments and Contingencies

The Company has various commitments through ordinary course of business.

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



------------------------------------------------------------------------
2006 2007
------------- --------------
Office Rental $ 123,720 $ 82,480
------------------------------------------------------------------------

 


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.


14. 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. During the nine month period ended December 31, 2005, the Company paid and accrued a total of $59,000 to this firm for legal fees and disbursements (March 31, 2005: $28,000).

15. Subsequent Events

On March 28, 2006, the Company's demand revolving credit facility ("Bank Facility") with a Canadian commercial bank was revised to reflect an increase in the Bank Facility's borrowing base to $22.5 million, pursuant to the scheduled annual credit review. Amounts drawn on the Bank Facility bear interest at the lender's prime rate or at prevailing guaranteed notes rate plus an applicable bank fee.


The TSX Venture Exchange does not accept responsibility for the adequacy or accuracy of this news release. Orleans Energy Ltd.
Barry Olson
President & CEO
(403) 215-2941
Email: bolson@orleansenergy.com

or

Orleans Energy Ltd.
Dean Bernhard
Vice President, Finance & CFO
(403) 215-2945
(403) 261-8850 (FAX)
Email: dbernhard@orleansenergy.com
Website: www.orleansenergy.com

or

Orleans Energy Ltd.
Suite 1250, 521-3rd Avenue S.W.
Calgary, Alberta, T2P 3T3