Orleans Energy Ltd.
TSX : OEX

Orleans Energy Ltd.

March 23, 2011 07:30 ET

Orleans Energy Announces 2010 Financial Results and Provides Operations Update

CALGARY, ALBERTA--(Marketwire - March 23, 2011) - Orleans Energy Ltd. ("Orleans" or the "Company") (TSX:OEX) today announced financial and operating results for the year ended December 31, 2010. For the year, Orleans reported cash flow from operations of $27.5 million ($0.42 per fully-diluted share) on revenue of $47.8 million and average daily production of 3,734 barrels of oil equivalent. Corporate highlights are as follows:



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Financial
Highlights Quarterly Summary
--------------------------------------------------------
(6:1 oil equivalent Dec. 31, Sep. 30, Jun. 30, Mar. 31,
conversion) 2010 2010 2010 2010
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(amounts in Cdn $
except share data)
Petroleum & natural
gas revenue (4) 11,940,546 12,664,428 11,185,919 11,979,519
Per share - basic
& diluted 0.18 0.19 0.17 0.18
Cash flow from
operations (1) 7,267,861 7,929,678 5,762,793 6,505,484
Per share - basic
& diluted 0.11 0.12 0.09 0.10
Operating netback
(2) ($/boe) 26.88 24.40 19.69 22.74
Corporate netback
(2) ($/boe) 23.22 21.88 16.01 19.87
Net loss (1,048,936) (1,651,240) (3,616,135) 1,403,105
Per share - basic
& diluted (0.02) (0.03) (0.06) 0.02
Net debt (3)-
period end 8,449,321 46,304,695 43,641,068 39,114,874
Weighted average
basic shares 65,774,455 65,279,181 65,175,706 65,175,706
Weighted average
diluted shares 65,774,455 65,279,181 65,175,706 65,648,751
Issued and
outstanding shares
(5) 65,784,310 65,770,977 65,175,706 65,175,706
Operating
Highlights
Average daily
production:
Natural gas
(mcf/d) 15,278 18,733 20,530 18,777
Liquids (oil and
NGLs) (bbls/d) 856 818 534 509
Oil equivalent
(boe/d) 3,402 3,940 3,956 3,638
Average sales price
(4):
Natural gas
($/mcf) 4.70 4.54 4.42 5.37
Liquids (oil &
NGLs) ($/bbl) 67.71 64.27 60.13 63.56
Oil equivalent
($/boe) 38.15 34.94 31.07 36.59
E&D capital
expenditures ($) 9,454,247 10,788,700 9,953,929 20,677,790
Total capital
expenditures (6)
($) (30,344,955) 11,284,135 10,506,930 21,448,163
Operating expenses
($/boe) 8.74 7.58 6.50 10.15
Wells drilled gross
(net) 1 (1.0) 1 (1.0) 1 (0.6) 5 (4.5)
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------------------------------------------------------------
Financial
Highlights Annual Summary
-----------------------------------------
(6:1 oil equivalent
conversion) Year 2010 Year 2009 % Change
-----------------------------------------
(amounts in Cdn $
except share data)
Petroleum & natural
gas revenue (4) 47,770,412 44,070,123 8
Per share - basic
& diluted 0.73 0.78 (6)
Cash flow from
operations (1) 27,465,816 15,227,189 80
Per share - basic
& diluted 0.42 0.27 56
Operating netback
(2) ($/boe) 23.32 14.36 62
Corporate netback
(2) ($/boe) 20.15 10.63 90
Net loss (4,913,206) (18,015,931) (73)
Per share - basic
& diluted (0.08) (0.32) (75)
Net debt (3)-
period end 8,449,321 24,435,914 (65)
Weighted average
basic shares 65,352,705 56,756,268 15
Weighted average
diluted shares 65,352,705 56,756,268 15
Issued and
outstanding shares
(5) 65,784,310 65,175,706 1
Operating
Highlights
Average daily
production:
Natural gas
(mcf/d) 18,321 19,233 (5)
Liquids (oil and
NGLs) (bbls/d) 681 719 (5)
Oil equivalent
(boe/d) 3,734 3,924 (5)
Average sales price
(4):
Natural gas
($/mcf) 4.75 4.30 10
Liquids (oil &
NGLs) ($/bbl) 64.42 52.94 22
Oil equivalent
($/boe) 35.05 30.77 14
E&D capital
expenditures ($) 50,874,666 44,113,703 15
Total capital
expenditures (6)
($) 12,894,273 26,051,021 (51)
Operating expenses
($/boe) 8.18 11.01 (26)
Wells drilled gross
(net) 8 (7.1) 5 (4.7) 60
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Notes:



1. Cash flow from operations or operating cash flow does not have any
standardized meaning prescribed by Canadian generally accepted
accounting principles ("GAAP"). Please refer to the Company's MD&A for
definition of cash flow from operations.
2. Operating netback represents average sales price less royalties,
operating costs and transportation expenses. Corporate netback
represents operating netback less interest expense and general and
administrative costs (excluding non-cash stock-based compensation
expense). These netback measures are not recognized measures under
Canadian GAAP.
3. Net debt refers to outstanding bank debt plus any working capital
deficit or minus any working capital surplus (excludes current
unrealized amounts pertaining to risk management contracts and current
future income taxes). Net debt is not a recognized measure under
Canadian GAAP.
4. Petroleum and natural gas revenue and pricing includes realized hedging
gains or losses from commodity contract settlements.
5. As of March 23, 2011, common shares outstanding are 65,787,643.
6. Total capital expenditures reported for 2010 are net of the $40.44
million disposition proceeds related to the disposition of the Company's
Waskahigan undeveloped, non-producing deep mineral rights and the minor
disposition of its North Pine Creek asset, both transactions closed in
December 2010.


Financial Highlights



-- Significantly Improved Financial Flexibility
-- Exited 2010 with net debt of $8.45 million as compared to December 31,
2009 net debt of $24.44 million, resulting in a net debt-to-trailing
operating cash flow ratio of only 0.31 times. The Company presently does
not have any drawn bank debt under its committed, revolving bank
facility with a borrowing base of $60.0 million.
-- Increased Light Oil and NGLs Production Weighting
-- As a result of successful delineation drilling of Orleans' Waskahigan
light oil Montney play, the Company's light oil and NGLs weighting in
the fourth quarter was 25%, as compared to the weighting of 14% in the
first quarter of 2010.
-- Operating Cost Reduction
-- Reduced operating costs to $8.74 per boe in the fourth quarter of 2010
from the fourth quarter 2009 cost of $9.67 per boe. The Company's
operating cost in 2010 was $8.18 per boe as compared to the per-unit
cost of $11.01 in 2009.
-- Cash Flow Expansion
-- Generated cash flow from operations of approximately $27.47 million,
representing an increase of 80% from the fiscal 2009 amount of $15.23
million.


Operations Update

Waskahigan

At Waskahigan in West Central Alberta, the Company continues to experience delineation drilling success with its 100% working interest Montney light oil property. Four (4.0 net) horizontal wells have been drilled to-date in 2011: three are awaiting tie-in with the fourth (9-35-63-23W5) recently stimulated and presently under going flow test operations. The 9-35 well commenced clean-up and flow testing on March 20, 2011 following a 14 stage (335 tonne) frac operation and as of early evening March 22, 2011 had already recovered 97% of the frac oil utilized in the operation (4,565 bbls total load oil). At that flow test time, the 9-35 well was testing at a rate of approximately 1,100 bbls/d of 43 degree API light oil (1,485 boe/d including associated solution gas).

Details of the final flow test results of the three wells awaiting tie-in are as follows:



------------------ ---------------------------------------------------------
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
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9-2-64-23W5 3,774 1,351 14 407 4,951 3.9
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16-30 -63-23W5 3,720 1,384 14 360 5,512 7.4
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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
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9-2-64-23W5 1,275 470 5.7 1,420
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16-30 -63-23W5 484 340 1.2 590
------------------------------------------------------


Note:



1. Final Flow Test Data based on last two hours of flow test and is after
100% recovery of frac fluid for both the 3-23 and 16-30 wells 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).


The completion results from these four "derisking and delineation" wells drilled in 2011, in conjunction with the production performance of the two (2.0 net) Montney discovery wells (4-36-63-23W5 and 5-25-63-23W5), have enhanced the Company's geological confidence in the play and confirmed the existence of a large, light oil resource. The 4-36 well, since start-up on June 19, 2010 through to February 28, 2011 (255 days), has produced approximately 37,000 bbls of 44 degree API light oil (65,000 boe including associated solution gas) with a field operating income netback of approximately $44 per boe over this time period. The 5-25 well, since start-up on September 20, 2010 through to February 28, 2011 (162 days), has produced approximately 43,000 barrels of 42 degree API light oil (54,000 boe including associated solution gas) with a field operating income netback of approximately $51 per boe. Enhancing the wellhead economics is the Alberta government's Horizontal Oil New Well incentive program, whereby the royalty rate for these horizontal wells are capped at 5% for the first 36 months of production, up to a maximum of 80,000 boe produced.

With the significant level of tested production volumes added as a result of Orleans' first quarter 2011 drilling activities, the Waskahigan field production will be temporarily restricted due to pipeline and field compression capacity limitations with its associated solution gas in a third-party-operated gathering system (approximately two mmcf/d). In order to accommodate the full production capabilities from these wells and future wells under an expanded, large-scale development drilling program, a 100% owned, Company-operated oil battery and compression facility, with designed-initial oil processing capacity of 2,500 bbls/d (4,200 boe/d including associated solution gas), is scheduled for completion and commissioning in October of this year.

Immediately following spring break-up and the lifting of related road bans, drilling activities will resume at Waskahigan with the intention to initially keep at least one drilling rig operational on a continuous basis. Prior to break-up, Orleans spud its seventh oil drilling location (12-34-63-23W5) and was able to drill and set surface casing; drilling of this well bore will resume post break-up. Based on assumed down-spacing to four wells per section, the Company estimates an additional 64 horizontal drilling locations.

Pine Creek

At North Pine Creek in West Central Alberta, the Company is realizing very favourable results from the liquids-rich, tight gas Wilrich formation. Pursuant to the previously-announced farm-out of three sections of lands in North Pine Creek, initial drilling and completion operations by the farmee has resulted in positive results. Both earning wells have now been successfully completed with flow test rates representative of Wilrich flow back performance, as disclosed by other area operators. The first earning well (12-31-55-19W5) was brought on-stream on February 21, 2011 at a controlled rate in order to maintain area gathering system equilibrium. The second well (4-5-56-19W5) recently completed an inline, clean-up flow period and is presently being tied-in with anticipated start-up within a couple of days. Orleans holds a 39.875% working interest on the lands under the farm-out arrangement. These lands have been granted regulatory approval to down space drill to four wells per section.

Kaybob South #3 Gas Plant

On March 11, 2011, the Company was notified by SemCAMS, the operator of the Kaybob South #3 Gas Plant ("K3 Gas Plant"), that a mechanical failure had occurred at the K3 Gas Plant. The K3 Gas Plant has been shut down and is expected to re-start after repairs are completed on or around March 28, 2011 (SemCAMS initial re-start schedule was March 22, 2011). As a result of having optionality to transport and process hydrocarbons volumes to either the K3 Gas Plant or the Kaybob Amalgamated Gas Plant ("KA Gas Plant"), Orleans has been able to partially mitigate the impact to its operations of the K3 Gas Plant shut down. Approximately 510 boe/d of the Company's Kaybob field production (approximately 28% of the field output capability) has been diverted north to the KA Gas Plant.

As a result of the K3 Gas Plant shut down and assuming the re-start on or about March 28, 2011, the Company's forecasted first quarter 2011 and annual 2011 average daily production is expected to be reduced by approximately 290 boe/d and 70 boe/d, respectively.

RMP Energy Acquisition and Reorganization

On March 13, 2011, the Company announced that it has signed an arrangement agreement with RMP Energy Ltd. (a private company) ("RMP"), which provides for the acquisition by Orleans of all of the issued and outstanding common shares and preferred shares of RMP (collectively "RMP Shares") on the basis of 2.25 common shares of Orleans ("Orleans Shares") for each 1.0 RMP Shares. The Company will be renamed "RMP Energy Inc."

After the completion of the RMP Transaction, the combined Company will be led by Craig Stewart as Executive Chairman, John Ferguson as President & Chief Executive Officer, Brent DesBrisay as Vice President, Geosciences, Jon Grimwood as Vice President, Exploration, Ross MacDonald as Vice President, Engineering and Bruce McFarlane as Vice President, Business Development (collectively, "RMP Management"). The new Board of Directors of the Company will include members from both Orleans' and RMP's existing Boards of Directors and will be comprised of Craig Stewart, Doug Baker, John Brussa, John Ferguson, Andrew Hogg, Jim Saunders and Lloyd Swift.

Prior to the transaction, RMP will undertake a private placement to certain service providers consisting of $0.75 million in common shares of RMP and to management, directors and RMP's existing private equity investors consisting of a total of $5.75 million in units, each unit consisting of (i) one RMP common share which, with respect to certain subscribers, will be issued on a flow-through basis pursuant to the Income Tax Act (Canada); and (ii) one warrant to purchase RMP common shares, each whole RMP warrant entitling the holder to acquire one RMP common share at a price of $4.50 for a period of five years; provided that the RMP Warrants shall vest only if the common shares of the Company trade at a price greater than $3.00 per share for a period of 30 consecutive days. The RMP units will also be subject to an 18 month escrow with a third of the RMP units being released from escrow every six months.

The transaction is subject to stock exchange, court, regulatory and shareholder approval. The respective meetings of shareholders of both Orleans and RMP is scheduled for May 10, 2011.

RMP Management has a proven history of per share growth stemming from prudent capital allocation and technical expertise. In light of current depressed natural gas prices, the major focus will be directed towards the 100%-owned, Montney light oil resource development at Waskahigan in West Central Alberta. The first phase of development of the pool will consist of 28 horizontal wells being drilled with a spacing of two wells per section. The second phase drilling, with down-spacing to four wells per section, will add an additional 36 locations. Similar analog oil pools are being developed with eight wells per section by regional industry players, implying a further doubling of horizontal drilling locations at Waskahigan.

Annual Information Form Filing

The Company announces that it has filed its Annual Information Form ("AIF") for the year ended December 31, 2010. The AIF contains the information and reports concerning the Company's crude oil, natural gas and natural gas liquids reserves in addition to other oil and gas information required to be provided under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

The Company's audited financial statements and associated Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2010 will be available on Orleans' website at www.orleansenergy.com located within "Investor Relations" under "Financial Reports". Additionally, these documents will be filed, in due course, on the System for Electronic Document Analysis and Retrieval ("SEDAR"). These documents can be retrieved electronically from the SEDAR system by accessing Orleans' public filings under "Search for Public Company Documents" within the "Search Database" module at www.sedar.com.

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.

The following are abbreviations that may be contained within this news release:



----------------------------------------------------------------------------
Crude Oil and Natural Gas Liquids Natural Gas and Natural Gas Liquids
----------------------------------------------------------------------------
thousand cubic feet
bbl barrel mcf/d per day
----------------------------------------------------------------------------
barrels of oil million cubic feet
boe or BOE equivalent mmcf/d per day
----------------------------------------------------------------------------
bbls/d barrels per day GJ gigajoule
----------------------------------------------------------------------------
barrels of oil
boe/d equivalent per day NGLs natural gas liquids
----------------------------------------------------------------------------


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 "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.

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.

Field operating income netbacks refers to realized wellhead revenue less royalties, operating expenses and transportation costs per barrel of oil equivalent ("boe").

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