Orleans Energy Announces Kaybob Deep Rights Disposition, Provides Waskahigan Operations Update, Announces 2011 Capital Budget and Year-End Corporate Reserves and Appoints New Board Member

CALGARY, ALBERTA--(Marketwire - Feb. 15, 2011) - Orleans Energy Ltd. ("Orleans" or the "Company") (TSX:OEX) is pleased to provide the following information and announcements: Deep Minerals Rights Disposition Orleans has accepted an offer to dispose of its deep mineral rights at Kaybob to an arm's-length party for a total transaction cash value of $10.7 million, subject to certain customary conditions (the "Deep Rights Disposition"). The Deep Rights Disposition involves the disposition of the Company's undeveloped, non-producing deep mineral working interest rights located in the Kaybob area of West Central Alberta. Upon satisfying certain conditions, the Deep Rights Disposition is scheduled to close on or about February 18, 2011. The Deep Rights Disposition encompasses only the deep mineral rights Below Base Mississippian at Kaybob; it does not include Orleans' 100% working interest in the Montney rights. This disposition will not result in a decrease to the existing $60 million borrowing base associated with the Company's bank credit facility and will assist in funding Orleans' 2011 capital expenditures program. Waskahigan Operations Update Orleans continues to experience operational success with its Waskahigan delineation drilling program. Two (2.0 net) additional wells have been successfully completed thus far in 2011 with a third, 100% working interest well recently drilled, cased and awaiting completion. The combined final flow test rate of the two completed wells was approximately 970 barrels per day ("bbls/d") of light gravity sweet oil (43 to 45 API) and 8.7 million cubic feet per day ("mmcf/d") of associated sweet natural gas for an overall oil equivalent rate of approximately 2,420 barrels of oil equivalent per day ("boe/d"). Details of the completion results are as follows: /T/ ---------------------------------------------------------------------------- Well Completion Information ---------------------------------------------------------------------------- Clean-Up Total HZ Sand - Total & Flow- Measured Section # Total Frac Oil Test Well Depth (m) (m) Stages Tonnes (bbls) Days ---------------------------------------------------------------------------- 3-23-63-23W5 3,943 1,455 13 366 5,646 8.8 ---------------------------------------------------------------------------- 9-2-64-23W5 3,774 1,351 14 407 4,951 3.9 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Final Flow Test Data (1) ---------------------------------------------------------------------------- Tubing Pressure Oil Gas BOE Well (psi) (bbls/d) (mmcf/d) (boe/d) ---------------------------------------------------------------------------- 3-23-63-23W5 685 500 3.0 1,000 ---------------------------------------------------------------------------- 9-2-64-23W5 1,275 470 5.7 1,420 ---------------------------------------------------------------------------- Note: (1) Final Flow Test Data based on last two hours of flow test and is after 100% recovery of frac fluid for the 3-23 well and 84% recovery of frac fluid for the 9-2 well (the well was shut-in once the maximum volumes under the flare permit were reached). /T/ Although the well site infrastructure is expected to be finalized by April 1, 2011 for both wells, the 3-23 and 9-2 are anticipated to be brought on-stream in June 2011 after road bans relating to spring break-up surface conditions are lifted. The initial well rates will be subject to gas gathering and compression capacity limitations upstream of a third-party-operated facility. Both the 3-23 and 9-2 will qualify for the Alberta Government's Horizontal Oil New Well royalty rate of 5% for the first 36 months of production, up to a maximum of 80,000 barrels of oil equivalent produced. Both the 3-23 and 9-2 are follow-up delineation wells to Orleans' 4-36 and 5-25 Montney oil discoveries in 2010. The following table outlines the production performance of these oil wells: /T/ ---------------------------------------------------------------------------- 30 Day IP Rate (1) ---------------------------------------------------------------------------- On-Stream Oil Gas BOE (2) Well Date (bbls/d) (mmcf/d) (boe/d) ---------------------------------------------------------------------------- 4-36-63-23W5 Jun.19, 2010 473 1.45 736 5-25-63-23W5 Sep.20, 2010 671 0.79 815 Three Month IP Rate (1) Current Rate (1) ---------------------------------------------------------------------------- Oil Gas BOE (2) Oil Gas BOE (2) Well (bbls/d) (mmcf/d) (boe/d) (bbls/d) (mmcf/d) (boe/d) ---------------------------------------------------------------------------- 4-36-63-23W5 262 0.97 438 67 321 126 ---------------------------------------------------------------------------- 5-25-63-23W5 380 0.52 474 148 310 205 ---------------------------------------------------------------------------- Notes: (1) IP Rate refers to initial average production rate during the stated period. Both IP Rates and Current Rates based on field estimates. (2) BOE rate includes natural gas liquids ("NGLs") associated with the produced natural gas at an estimated yield of 15 bbls per mmcf. /T/ Orleans is encouraged by the initial flow test rates and production profiles of its Montney delineation oil wells to-date, and although early-stage, is excited by the potential of the play to offer a repeatable resource opportunity. As a result of its successful Montney drilling program, the Company estimates it has delineated a minimum of six sections of its eastern acreage. However, only three sections (3.0 net) of land had assigned reserves as of December 31, 2010. Refer to Year-End 2010 Corporate Reserves - Waskahigan Reserves section disclosed hereafter. The Company is of the opinion that there exists a significant Montney oil and gas accumulation at Waskahigan with the ultimate areal extent still undefined. Drilling in 2011 will be focused on further expansion of these boundaries. 2010 Corporate Results In 2010, Orleans drilled eight company-operated wells (7.1 net) at an 88% success rate. The Company drilled five horizontal gas wells (4.1 net) at Kaybob and three oil wells (3.0 net) at Waskahigan, including the two Montney oil discovery wells at 4-36-63-23W5M and 5-25-63-23W5M. Orleans' average daily production for fiscal 2010 was 3,734 boe/d, 3% lower than the mid-point of the Company's market guidance target range of 3,800 to 3,900 boe/d. Projected cash flow from operations for 2010 is estimated at $27.5 million or $0.42 per basic share outstanding (unaudited). For the fourth quarter of 2010, combined oil equivalent average daily production was 3,402 boe/d, weighted 25% towards light oil and NGLs, as compared to the oil and NGLs weighting of only 14% during the first quarter of 2010. Fourth quarter 2010 production was affected by the following variables: i) Disposition of certain North Pine Creek assets on December 9, 2010, which were producing approximately 110 boe/d; ii) Higher than anticipated "flush" declines primarily on two Kaybob wells (1.4 net) brought on-stream in 2010; iii) Lower gas-to-oil ratio with the Waskahigan 5-25 well resulting in lower forecasted barrels of oil equivalent; and, iv) No new wells were brought on-stream in the fourth quarter. 2011 Capital Budget and Market Guidance The following guidance is subject to all the cautionary statements and limitations described at the end of this news release. Capital Investments For fiscal 2011, Orleans intends to invest approximately $62 million in capital project activities (the "2011 Capital Budget"). The 2011 Capital Budget involves a continued focus on "value capture and validation" of light oil and tight gas, liquids-rich projects. The Company is planning significant drilling and infrastructure investments in its Waskahigan Montney property during 2011, essentially building on the positive oil play delineation momentum from 2010. This strategic "delineation and de-risking" objective, in contrast to a conventional approach skewed solely towards production growth, is expected to enhance the Company's understanding, reserve capture potential and value of its Waskahigan property this year, thus positioning this asset base for future, larger-scale development. Additionally, funds will be deployed towards the horizontal development of the Wilrich gas play at Pine Creek, wherein one well (0.4 net) has recently been drilled, cased and is awaiting completion (12-31-55-19W5M) with a second well (0.4 net) presently drilling (4-5-56-19W5M). Funds will also be directed towards Orleans' Boundary Lake light oil play at Gordondale and the Montney oil play at Ante Creek. The 2011 Capital Budget is primarily oil-focused and includes the drilling of 13 wells (9.8 net), including six (6.0 net) horizontal wells at Waskahigan, targeting the Montney formation. Also included is the drilling of one (1.0 net) vertical exploration well testing another internally-generated Montney oil prospect at Ante Creek, five (2.0 net) horizontal Wilrich gas wells at Pine Creek and one (0.8 net) horizontal Boundary Lake oil well at Gordondale. The drilling and completion expenditure component of Orleans' 2011 Capital Budget is projected at $41 million, with the remaining budgeted funds allocated towards investments in field facilities and seismic programs. Orleans' drilling campaign at Waskahigan has continued with another horizontal well at 16- 30-63-22W5M (100% working interest) recently cased and awaiting completion. The 16-30 well is located approximately 1.6 kilometers east of the original 4-36-63-23W5M discovery well and is expected to be completed by the end of February 2011. Additionally, Orleans is expecting to commence drilling its sixth horizontal location (9-35-63-23W5M) in the oil fairway by February 19, 2011. Production resulting from the successful delineation of the Waskahigan eastern acreage will be affected by spring break-up surface conditions and infrastructure capacity limitations. The Waskahigan field production will be off-line during seasonal spring break-up due to road bans, as the Company presently trucks its oil production to a third-party facility. Additionally, with potential production volumes added as a result of first quarter 2011 drilling, Waskahigan field production will be curtailed due to pipeline and field compression capacity limitations in a third-party-operated gathering system (approximately two mmcf/d). In order to facilitate the compression and processing of production resulting from a large-scale development drilling program, Orleans is planning to construct an oil battery and compressor facility, with an anticipated commissioning date in early fourth quarter 2011. The Company has completed a preliminary evaluation and design of the infrastructure, including a gathering system which would facilitate the transportation of hydrocarbons to a third-party operated gas plant located at 15-7-64-23W5M. The oil battery, compressor facility and connection to this gas plant is budgeted with a preliminary cost estimate of $11 million and would provide Orleans with the following operational advantages: i) Year-round production capability; ii) Substantially greater oil and gas handling capacity; iii) Facilitation of a direct tie-in to an independent oil sales pipeline adjacent to the 15-7 gas plant, thus precluding the need to truck clean oil to handling facilities; iv) Improved operating conditions through a pipeline system utilizing company-operated compression; and, v) Operational control of infrastructure. Forecasted Production Based on the 2011 Capital Budget, Orleans' average daily production for 2011 is projected to approximate 3,600 boe/d, weighted 25% towards light oil and NGLs, with a forecasted exit rate of 4,500 boe/d, weighted 30% light oil and NGLs. These forecasts assume the commissioning of new Waskahigan field infrastructure in early fourth quarter 2011. First half 2011 average daily production is estimated at 3,000 boe/d. As discussed above, Waskahigan production will be tempered due to third-party infrastructure capacity limitations and spring break-up surface conditions, with imposed trucking road bans resulting in an estimated 550 boe/d less realized production during the second quarter of 2011, with anticipated significant growth in production and reserves by the end of 2011 and into 2012. Forecasted Net Debt and Cash Flow The Company intends to internally fund the 2011 Capital Budget with forecasted cash flow from operations and draw downs on its bank credit facility, which is presently only drawn approximately $3.8 million against a borrowing base capacity limit of $60 million. Based on the 2011 Capital Budget and cash flow projection, Orleans' year-end 2011 net debt balance is estimated at $33 million or 1.15 times (115%) of forecasted 2011 cash flow from operations. Based on the annualized fourth quarter 2011 cash flow projection, year-end 2011 net debt is projected at 0.65 times (65%) of cash flow. With its under-leveraged net debt position of $8.4 million (unaudited) entering 2011, in conjunction with the anticipated $10.7 million deep rights disposition at Kaybob, Orleans is well-positioned to withstand any prolonged weakness in gas prices while executing its oil-focused 2011 Capital Budget. Projected cash flow from operations for 2011, utilizing the current forward strip commodity price assumptions of an AECO gas price of C$3.40 per gigajoule, a West Texas Intermediate oil price of US$94.50 per bbl, and an exchange rate of 1C$ = 1.01US$, is estimated at $28.5 million or $0.43 per share (basic outstanding). The Company presently does not have any commodity price hedging contracts in-place for 2011. Year-End 2010 Corporate Reserves The Company also provides the following information on its oil and gas reserves as of December 31, 2010, as evaluated by the independent reserve engineering firm, Sproule Associates Limited ("Sproule"). The evaluation of Orleans' petroleum and natural gas reserves was conducted pursuant to National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook reserves definitions. A summary of the Company's reserves and corresponding net present values as of December 31, 2010 are as follows: /T/ ---------------------------------------------------------------------------- December 31, 2010 Reserves Summary (Company interest before royalties) ---------------------------------------------------------------------------- (December 31, 2010 escalated Crude Oil price forecast) NatGas Oil NGLs Equivalent ---------------------------------------------------------------------------- (Columns may not add due to rounding) (Bcf) (Mbbls) (Mbbls) (Mboe) (6:1) ---------------------------------------------------------------------------- Proved developed producing 21.497 159.6 523.6 4,266.1 ---------------------------------------------------------------------------- Proved developed non-producing 0.459 - 10.6 87.0 ---------------------------------------------------------------------------- Proved undeveloped 31.148 256.9 733.1 6,181.3 ---------------------------------------------------------------------------- Total Proved 53.104 416.4 1,267.3 10,534.5 ---------------------------------------------------------------------------- Probable 29.117 615.4 681.5 6,149.6 ---------------------------------------------------------------------------- Total Proved plus Probable 82.221 1,031.8 1,948.7 16,684.0 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- December 31, 2010 Net Present Values ("NPV") Summary (Company interest before royalties) ---------------------------------------------------------------------------- (December 31, 2010 escalated price forecast) Present value of cash flows before-tax ($000s) ---------------------------------------------------------------------------- (Columns may not add due to rounding) 0% 10% 15% 20% ---------------------------------------------------------------------------- Proved developed producing $ 92,108 $ 63,733 $ 55,623 $ 49,580 ---------------------------------------------------------------------------- Proved developed non-producing 1,827 1,228 1,030 874 ---------------------------------------------------------------------------- Proved undeveloped 113,068 49,847 34,401 23,877 ---------------------------------------------------------------------------- Total Proved 207,003 114,807 91,054 74,331 ---------------------------------------------------------------------------- Probable 173,324 81,134 62,442 50,087 ---------------------------------------------------------------------------- Total Proved plus Probable $ 380,327 $ 195,942 $ 153,495 $ 124,418 ---------------------------------------------------------------------------- /T/ In 2010, the Company added 3.36 million boe of proved plus probable reserves through its drilling operations, representing a 2.5 times (247%) production replacement (before reserves revisions and dispositions). However, as a result of Orleans' increased focus on its Waskahigan Montney oil play and the presently depressed gas price environment curbing short-term gas project economics, at year-end 2010, the Company chose to remove 25 (18.3 net) future drilling locations with 1.34 million boe of proved plus probable undeveloped reserves, consisting primarily of historical vertical drilling locations associated with its Gilby Edmonton and Glauconite/Ellerslie gas and Gordondale Boundary Lake oil formations. Although these projects are economically viable, Orleans does not anticipate undertaking these projects in the near term and therefore chose to remove them from the corporate reserves. At year-end 2010, the Company has 35% less proved plus probable undeveloped locations than at year-end 2009. Total proved plus probable future development capital is forecasted at $97.57 million ($81.95 million proved), as compared to year-end 2009 of $111.82 million and $71.5 million, respectively. Additionally, at year-end 2010, the Company experienced downward technical revisions at Kaybob with its Montney gas play. In general, although the production profile of the Kaybob Montney proved producing gas wells in the year-end 2010 reserves have exhibited "leveling off" behavior; they have not flattened as fast as the "type curve" forecast predicted in the year-end 2009 reserve report. Consequently, the negative reserve revisions were primarily associated with only the probable component of these proved producing wells. Additionally, an updated "type curve" has been applied and utilized for booked future proved undeveloped and probable locations at Kaybob, resulting in additional downward reserve revisions. Orleans' proved plus probable reserves base was further reduced at year-end 2010 by 1.42 million boe (753 thousand boe proved), as a result of the North Pine Creek property disposition and farm-out arrangement transacted in December 2010. A reconciliation of Company's proved and proved plus probable reserves as of December 31, 2010, as compared to December 31, 2009, is as follows: /T/ ---------------------------------------------------------------------------- Reserves Reconciliation ---------------------------------------------------------------------------- Total Proved ---------------------------------------------------------------------------- (Columns may not add Crude Oil due to rounding) NatGas Oil NGLs Equivalent ---------------------------------------------------------------------------- (Bcf) (Mbbls) (Mbbls) (Mboe) (6:1) ---------------------------------------------------------------------------- December 31, 2009 57.7 173 1,549 11,330 ---------------------------------------------------------------------------- Extensions 1.7 198 32 509 ---------------------------------------------------------------------------- Discoveries 0.6 188 9 298 ---------------------------------------------------------------------------- Infill Drilling 4.8 - 101 909 ---------------------------------------------------------------------------- Economic Factors (0.9) (3) (23) (171) ---------------------------------------------------------------------------- Technical Revisions (0.1) (51) (155) (225) ---------------------------------------------------------------------------- Dispositions (1) (4.0) (11) (76) (753) ---------------------------------------------------------------------------- Production (6.6) (78) (170) (1,363) ---------------------------------------------------------------------------- December 31, 2010 53.1 416 1,267 10,534 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Total Proved Plus Probable ---------------------------------------------------------------------------- (Columns may not add Crude Oil due to rounding) NatGas Oil NGLs Equivalent ---------------------------------------------------------------------------- (Bcf) (Mbbls) (Mbbls) (Mboe) (6:1) ---------------------------------------------------------------------------- December 31, 2009 101.0 415 2,652 19,903 ---------------------------------------------------------------------------- Extensions 4.9 621 94 1,536 ---------------------------------------------------------------------------- Discoveries 1.0 321 15 510 ---------------------------------------------------------------------------- Infill Drilling 7.0 - 144 1,317 ---------------------------------------------------------------------------- Economic Factors (1.4) (4) (36) (271) ---------------------------------------------------------------------------- Technical Revisions (16.2) (227) (607) (3,532) ---------------------------------------------------------------------------- Dispositions (1) (7.6) (16) (143) (1,416) ---------------------------------------------------------------------------- Production (6.6) (78) (170) (1,363) ---------------------------------------------------------------------------- December 31, 2010 82.2 1,032 1,949 16,684 ---------------------------------------------------------------------------- Note: (1) Dispositions include reserves adjustment at Pine Creek to reflect farm-out arrangement entered into in December 2010. A summary of Sproule's escalated price forecast assumptions as of December 31, 2010 are as follows: ---------------------------------------------------------------------------- Edmonton Natural WTI Par Gas NGLs NGLs NGLs Cushing Price AECO-C Edmonton Edmonton Edmonton Exchange Oklahoma 40 API Price Propanes Butanes Pentanes Inflation Rate Year (US$/bbl)(C$/bbl)(C$/mmbtu) (C$/bbl) (C$/bbl) (C$/bbl) Rate(%)(US$/C$) ---------------------------------------------------------------------------- Forecast ---------------------------------------------------------------------------- 2011 88.40 93.08 4.04 55.20 62.44 95.32 1.5 0.932 ---------------------------------------------------------------------------- 2012 89.14 93.85 4.66 55.66 62.95 96.11 1.5 0.932 ---------------------------------------------------------------------------- 2013 88.77 93.43 4.99 55.41 62.67 95.68 1.5 0.932 ---------------------------------------------------------------------------- 2014 88.88 93.54 6.58 55.47 62.75 95.79 1.5 0.932 ---------------------------------------------------------------------------- 2015 90.22 94.95 6.69 56.31 63.69 97.24 1.5 0.932 ---------------------------------------------------------------------------- 2016 91.57 96.38 6.80 57.16 64.65 98.71 1.5 0.932 ---------------------------------------------------------------------------- 2017 92.94 97.84 6.91 58.02 65.63 100.20 1.5 0.932 ---------------------------------------------------------------------------- 2018 94.34 99.32 7.02 58.90 66.62 101.71 1.5 0.932 ---------------------------------------------------------------------------- 2019 95.75 100.81 7.14 59.79 67.63 103.25 1.5 0.932 ---------------------------------------------------------------------------- 2020 97.19 102.34 7.26 60.69 68.65 104.81 1.5 0.932 ---------------------------------------------------------------------------- Thereafter Escalation rate of 1.5% ---------------------------------------------------------------------------- /T/ Waskahigan Reserves Based on the independent reserves evaluation, 1.44 million boe of proved plus probable reserves (0.52 million boe proved) have been assigned to Orleans' Montney asset base at Waskahigan in West Central Alberta as at December 31, 2010, representing only 9% of the Company's year-end reserves booking (5% on a proved basis). The Montney reserves assignment at Waskahigan encompasses only three gross (3.0 net) sections of land or 9% of the Company's total 35 gross (35.0 net) sections of land. Reserves were assigned to three sections on the oil-prone eastern acreage with an average of 2.0 wells booked per section, consisting of two proved producing wells, two proved undeveloped locations and two probable undeveloped locations. The December 31, 2010 Waskahigan reserves assignment does not include any reserves booking for the 3-23-63-23W5M and 9-2-64-23W5M wells, as they were successfully completed subsequent to year-end 2010. A summary of the reserves booking assigned to the oil-bearing eastern Waskahigan acreage as of December 31, 2010 is as follows: /T/ ---------------------------------------------------------------------------- Reserves (1) (Company interest Net Present Waskahigan Reserves before royalties) Value (2) ---------------------------------------------------------------------------- Crude Solution Oil & Oil December 31, 2010 Gas NGLs Equivalent PV10% PV15% ---------------------------------------------------------------------------- (Columns may not add due to rounding) (Bcf) (Mbbls) (Mboe)(6:1) ($000s) ($000s) ---------------------------------------------------------------------------- Proved developed producing 0.425 124.4 195.2 $ 6,302 $ 5,901 ---------------------------------------------------------------------------- Proved undeveloped 0.718 208.0 327.7 5,099 4,340 ---------------------------------------------------------------------------- Total Proved 1.143 332.3 522.9 11,401 10,240 ---------------------------------------------------------------------------- Probable developed producing 0.435 139.4 211.9 3,891 3,052 ---------------------------------------------------------------------------- Probable undeveloped 1.538 444.9 701.3 13,697 11,535 ---------------------------------------------------------------------------- Total Probable 1.973 584.3 913.1 17,588 14,586 ---------------------------------------------------------------------------- Total Proved plus Probable 3.116 916.7 1,436.0 $ 28,989 $ 24,827 ---------------------------------------------------------------------------- Notes: (1) Waskahigan acreage with reserves assignment includes section 25-63-23W5, section 36-63-23W5 and section 35-63-23W5. (2) Net Present Value represents present value of cash flows before taxes based on escalated price forecast. Corporate Net Asset Value /T/ Corporate Net Asset Value The Company's intrinsic value as of December 31, 2010, as measured by its net asset value, is detailed in the following table. This net asset value determination is a "point-in-time" measurement and does not take into account the possibility of Orleans being able to recognize additional reserves through successful future capital investment in its existing properties beyond those included in the 2010 year-end reserves report. /T/ ---------------------------------------------------------------------------- December 31, 2010 NPV 10% NPV 15% ---------------------------------------------------------------------------- (per share figures based on fully-diluted shares) ($000s) $/share ($000s) $/share ---------------------------------------------------------------------------- Proved plus probable reserves NPV (1,2) $ 195,942 $ 2.72 $ 153,495 $ 2.13 ---------------------------------------------------------------------------- Undeveloped acreage (3) 51,717 0.72 51,717 0.72 ---------------------------------------------------------------------------- Net debt (4) (8,449) (0.12) (8,449) (0.12) ---------------------------------------------------------------------------- Proceeds from stock options (5) 15,259 0.21 15,259 0.21 ---------------------------------------------------------------------------- Net Asset Value (fully-diluted) $ 254,469 $ 3.53 $ 212,022 $ 2.94 ---------------------------------------------------------------------------- Notes: (1) Evaluated by Sproule as at December 31, 2010. Net present value ("NPV") of future net revenue does not represent fair market value of the reserves. (2) Net present values are before tax and based on Sproule's December 31, 2010 escalated price forecast. (3) Undeveloped net land of 54,652 acres was independently evaluated as at December 31, 2010 by a qualified third-party evaluator. At year-end 2010, Orleans' Waskahigan Montney mineral rights were fair market valued at $30.0 million (20,160 net acres). (4) Net debt as at December 31, 2010, including working capital deficit (estimated and unaudited). (5) Fully-diluted shares at December 31, 2010 total 72,012,560, including outstanding common shares of 65,784,310 and 6,228,250 stock options. /T/ Finding, Development and Acquisitions Cost The following highlights the finding, development and acquisition costs during 2010, in addition to the comparative fiscal year 2009 and the Company's average over the three-year period of 2008 to 2010: /T/ ---------------------------------------------------------------------------- Finding, Development & Acquisitions ("FD&A") Costs ---------------------------------------------------------------------------- Fiscal 2010 Fiscal 2009 2008 - 2010 Average ---------------------------------------------------------------------------- (amounts in $000s except reserve Proved Proved + Proved Proved + Proved Proved + units and unit costs) Probable Probable Probable ---------------------------------------------------------------------------- Total capital expenditures (1) $ 11,899 $ 11,899 $25,312 $ 25,312 $105,757 $105,757 ---------------------------------------------------------------------------- Future capital - Ending Period (2) 81,953 97,573 71,502 111,820 81,953 97,573 ---------------------------------------------------------------------------- Future capital - Beginning Period (2) (71,502) (111,820) (41,746) (72,925) (20,081) (52,762) ---------------------------------------------------------------------------- All-in total, including change in future capital (3) $ 22,350 $ (2,348) $55,068 $ 64,207 $167,629 $150,568 ---------------------------------------------------------------------------- Total reserve additions (Mboe) 567.3 (1,856.3) 2,092.0 3,340.6 7,445.8 7,290.2 ---------------------------------------------------------------------------- FD&A Cost ($/boe) $ 39.40 $1.26 (4) $ 26.32 $ 19.22 $ 22.51 $ 20.65 ---------------------------------------------------------------------------- Notes: (1) Total capital expenditures for fiscal 2010 are estimated and unaudited; it includes $11.7 million of Waskahigan Crown acreage acquisitions and is net of the capital proceeds associated with the Company's 2010 dispositions of $40.7 million (unaudited). Total capital expenditures exclude non-cash capitalized stock-based compensation expense. (2) Future capital expenditures required to convert proved non-producing and probable reserves to proved producing. (3) The aggregate of the exploration and development costs estimated to be incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. (4) The Company views the Fiscal 2010 proved plus probable FD&A metric as anomalous due to its 2010 dispositions and year-end technical revisions resulting in negative all-in net capital and negative net reserve additions. /T/ New Board of Director Member Orleans is pleased to announce the appointment of Andrew Hogg to the Board of Directors of Orleans. Mr. Hogg is currently the President and Chief Executive Officer of Coda Petroleum Inc. Prior thereto, he was the President and Chief Executive Officer of Rondo Petroleum Inc., a private oil and gas company and President and Chief Executive Officer of Grand Petroleum Inc. which traded on the TSX Venture Exchange. Mr. Hogg was an Oil and Gas Analyst with two national independent brokerage firms from 1997 to 2002. He began his oil and gas career in 1985 as a Geologist with Norcen Energy Resources Ltd. He is currently a director of Coda Petroleum Inc., and the Foothills Acoustic Music Institute, a not-for-profit society. Mr. Hogg received his Bachelor of Science with Honors (Geological Sciences) from Queens University in Kingston in 1984, and his Masters of Business Administration from the University of Calgary in 1992. Mr. Hogg is registered as a Professional Geologist with the Association of Professional Engineers, Geologists and Geophysicists of Alberta ("APEGGA"). Orleans anticipates releasing its audited annual financial statements for the year ended December 31, 2010 on or about March 23, 2011. Orleans Energy Ltd. is a Calgary, Alberta-based crude oil and natural gas company, with common shares trading on the Toronto Stock Exchange under the symbol "OEX". Orleans commenced active oil and gas operations in January 2005 and is committed to maximizing value for its shareholders through successful drilling of internally-generated prospects supplemented with strategic and focused property and/or corporate acquisitions. Orleans has several operated, high working interest, light oil and liquids-rich natural gas "resource plays" in West Central Alberta, specifically the Montney in Kaybob, Waskahigan and Ante Creek, along with the Wilrich in Pine Creek. /T/ The following are abbreviations that are contained within this news release: ---------------------------------------------------------------------------- Crude Oil and Natural Gas Liquids Natural Gas and Natural Gas Liquids ---------------------------------------------------------------------------- bbl barrel mcf/d thousand cubic feet per day ---------------------------------------------------------------------------- boe barrels of oil equivalent mmcf/d million cubic feet per day ---------------------------------------------------------------------------- Mboe thousand barrels of oil mmbtu million British Thermal Units equivalent ---------------------------------------------------------------------------- Mbbls thousand barrels Bcf Billion cubic feet of gas ---------------------------------------------------------------------------- bbls/d barrels per day GJ gigajoule ---------------------------------------------------------------------------- boe/d barrels of oil equivalent NGLs natural gas liquids per day /T/ The information in this news release contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "appear", "seek", "anticipate", "plan", "continue", "estimate", "approximate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar expressions. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond the Company's control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions, of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry ; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and obtaining required approvals of regulatory authorities. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that the Company will derive from them. 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. Except as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statements. 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. As an indicator of the Company's performance, the term cash flow from operations or operating cash flow contained within this news release should not be considered as an alternative to, or more meaningful than, cash flow from operating, financing or investing activities, as determined in accordance with Canadian generally accepted accounting principles ("GAAP"). This term does not have a standardized meaning, nor is it a financial measure, under GAAP. Cash flow from operations is widely accepted as a financial indicator of an exploration and production company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by shareholders and investors in the valuation, comparison and investment recommendations of companies within the natural gas and crude oil exploration and production industry. Cash flow from operations, as disclosed within this news release, represents cash flow from operating activities before any asset retirement obligation cash expenditures and 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. Additionally, net debt refers to outstanding bank debt plus working capital deficit (excludes current unrealized amounts pertaining to risk management commodity contracts) plus long-term accounts receivables. Net debt is not a recognized measure under Canadian GAAP. Any references in this news release to initial and/or final raw test or production rates and/or "flush" production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.

Contact Information: Orleans Energy Ltd. Barry Olson President & CEO (403) 215-2941 bolson@orleansenergy.com or Orleans Energy Ltd. Dean Bernhard Vice President, Finance & CFO (403) 215-2945 dbernhard@orleansenergy.com www.orleansenergy.com