We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Register for Free to get streaming real-time quotes, interactive charts, live options flow, and more.
| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Orleans Energy Ltd Com Npv | TSXV:OEX | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0 | - |
Hot Features
Premium
Orleans Energy Ltd. ("Orleans" or the "Company") (TSX VENTURE:OEX) is pleased to
announce its results for the year ended December 31, 2007. Highlights of the
Company's third year of active oil and gas operations are outlined as follows:
----------------------------------------------------------------------------
Quarterly Comparison
Financial Highlights Three Month Period Ended,
(6:1 oil equivalent Dec. 31, Sep. 30, Jun. 30, Mar. 31,
conversion) 2007 2007 2007 2007
------------ ----------- ----------- -----------
(amounts in Cdn.$ except
share data)
Petroleum and natural gas
revenue (6) 13,412,861 11,904,704 11,635,732 12,187,656
Per share - basic 0.36 0.32 0.35 0.37
- diluted 0.35 0.32 0.34 0.36
Cash flow from
operations (1) 5,624,646 4,491,667 5,143,032 6,066,434
Per share - basic 0.15 0.12 0.16 0.18
- diluted 0.15 0.12 0.15 0.18
Operating netback (2)
($/boe) 24.27 20.29 28.35 32.09
Corporate netback (2)
($/boe) 19.52 16.27 22.97 26.10
Net loss (3,5) (2,095,503) (3,073,828) (128,025) (912,767)
Per share - basic (0.06) (0.08) - (0.03)
- diluted (0.06) (0.08) - (0.03)
Net debt (4)- period end 48,188,497 44,537,047 53,181,270 48,403,405
Weighted average basic
shares 37,571,100 37,014,430 33,209,828 33,148,659
Weighted average diluted
shares 38,019,052 37,526,046 33,833,429 33,743,616
Issued and outstanding
shares (7) 37,571,372 37,546,372 33,225,889 33,148,659
Operating Highlights
Average daily production:
Natural gas (mcf/d) 14,655 14,002 10,673 10,665
Liquids (Oil & NGLs)
(bbls/d) 689 668 681 805
Oil equivalent (boe/d) 3,132 3,002 2,460 2,583
Average sales price (net
hedging) (6):
Natural gas ($/mcf) 6.78 6.11 7.79 8.01
Liquids (Oil & NGLs)
($/bbl) 67.40 65.76 65.61 62.07
Oil equivalent ($/boe) 46.55 43.11 51.97 52.43
E&D capital expenditures ($) 8,972,802 14,683,044 10,835,960 10,989,379
Total capital
expenditures ($) 9,483,866 15,146,269 10,209,005 11,417,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Annual Summary
Financial Highlights Year Year
(6:1 oil equivalent conversion) 2007 2006
----------- ------------
(amounts in Cdn.$ except share data)
Petroleum and natural gas revenue (6) 49,140,953 32,447,221
Per share - basic 1.39 1.33
- diluted 1.37 1.29
Cash flow from operations (1) 21,325,779 17,218,936
Per share - basic 0.60 0.71
- diluted 0.60 0.69
Operating netback (2) ($/boe) 25.68 31.06
Corporate netback (2) ($/boe) 20.90 26.96
Net loss (3,5) (6,210,123) (17,837,566)
Per share - basic (0.18) (0.73)
- diluted (0.18) (0.73)
Net debt (4)- period end 48,188,497 43,225,843
Weighted average basic shares 35,252,993 24,362,187
Weighted average diluted shares 35,772,226 25,136,494
Issued and outstanding shares (7) 37,571,372 33,148,659
Operating Highlights
Average daily production:
Natural gas (mcf/d) 12,514 6,406
Liquids (Oil & NGLs) (bbls/d) 710 682
Oil equivalent (boe/d) 2,796 1,750
Average sales price (net hedging) (6):
Natural gas ($/mcf) 7.06 6.95
Liquids (Oil & NGLs) ($/bbl) 65.10 65.00
Oil equivalent ($/boe) 48.15 50.80
E&D capital expenditures ($) 45,481,185 46,256,146
Total capital expenditures ($) 46,256,808 159,722,758
----------------------------------------------------------------------------
Notes:
(1) Cash flow from operations does not have any standardized meaning
prescribed by Canadian generally accepted accounting principles
("GAAP"). Please refer to the enclosed MD&A for definition of cash flow
from operations.
(2) Operating netback represents average sales price less royalties,
operating costs and transportation expenses. Corporate netback
represents operating netback less general and administrative costs and
interest expense. Both measures are not recognized measures under
Canadian GAAP.
(3) Net loss includes: (i) non-cash income tax reductions and (ii) non-cash
goodwill impairment.
(4) Net debt refers to outstanding bank debt plus working capital deficit
(excludes current unrealized amounts pertaining to risk management
commodity contracts). Net debt is not a recognized measure under
Canadian GAAP.
(5) The reported net loss in Year 2006 includes a $16.62 million non-cash
goodwill impairment. This goodwill resulted from the acquisition of
Morpheus Energy Corporation in June 2006.
(6) Petroleum and natural gas revenue and pricing includes realized hedging
results from commodity contract settlements.
(7) Current common shares outstanding are 44,571,372, as a result of the
equity financing closed on March 13, 2008.
2007 Highlights
- Strong Internally-Generated "Drill Bit" Performance
Drilled 18 wells (15.8 net), on an exploration and development ("E&D") capital
program of approximately $46 million, with an overall success rate of 100%.
Operational momentum carry-forwarded into the new year with four (3.7 net) wells
drilled in 2008 at various stages of completion.
- Significant Year-over-Year Production
Increased the Company's average daily production to 2,796 boe per day in 2007, a
60% increase from 1,750 boe per day in 2006. Exceeded its year-end exit
production target of 3,500 boe per day. Fourth quarter 2007 production averaged
3,132 boe per day.
- Strong Revenue and Cash Flow Growth
Generated petroleum and natural gas revenues of $49.1 million in 2007, an
increase of 51% over 2006. Cash flow from operations increased by 24% to $21.3
million.
- Land and Drilling Inventory Expansion in Core Focus Areas
In June 2007, significantly expanded its land holdings at Kaybob in West Central
Alberta through a successful Alberta Crown land sale. Orleans acquired 11.5
sections (100% working interest) of land, doubling its ownership presence within
the Kaybob asset base. Orleans has now amassed 27.5 (25.0 net) sections of key,
concentrated lands providing for the exploration and development of a "deep
basin", resource-style natural gas prospect in the Triassic Montney formation.
- Financial Flexibility
Additionally, in July 2007, closed a $20.2 million "bought-deal" equity
financing, enabling the Company to selectively expand its capital expenditures
in 2007 on strategic projects and further foster its financial flexibility. In
April 2007, increased its operating credit facility to $60 million,
transitioning its banking requirements to a major Canadian chartered bank.
Operations Update
As a result of a strong drilling program undertaken in 2007, Orleans' exceeded
its forecasted year-end production exit target of 3,500 barrels of oil
equivalent ("boe") per day. In 2007, the Company drilled 18 wells (15.8 net),
yielding promising results, with all the well bores cased and completed,
encompassing 13 gas wells and five oil wells. Orleans drilled wells across the
majority of its focus areas, including: 10 gas wells (9.5 net) in Kaybob, three
horizontal oil wells (3.0 net) in Leo, two gas wells (0.75 net) in Pine Creek,
two oil wells (1.5 net) in Gordondale and one gas well (1.0 net) at Gilby. Thus
far in 2008, the Company has drilled a total of four (3.7 net) wells, including
three (2.7 net) horizontal wells in Kaybob and one (1.0 net) well in Gilby.
Kaybob, West Central Alberta
Throughout 2007, Orleans' primary focus was on its West Central Alberta Kaybob
property, wherein the Company has expanded its land base from six sections (4.4
net) to 27.5 sections (25.0 net), via Crown land acquisitions and strategic
farm-ins, focusing on the exploration and development of the "deep basin"
resource-style natural gas prospect in the Triassic Montney formation.
Currently, on 10 sections of land in Kaybob, the Company has approval to drill
on reduced spacing up to three wells per section, and has applied for reduced
spacing to three wells per section on its remaining 17.5 sections. Presently,
Orleans has only one section of land where it is producing on reduced spacing
from three wells.
The Company has undertaken a number of operational initiatives, including
horizontal drilling along with the application of improved and larger fracture
stimulation technology, utilizing the "Packer Plus" multi-stage fracture
assembly. Orleans is also incorporating common lease pad drilling as a means to
improve productivity and reserves recovery and minimize lease construction,
pipeline costs and surface disturbance. The Company's first horizontal well (1.0
net), drilled in the fourth quarter of 2007, was stimulated with a five-stage
fracture treatment including 150 tonnes of proppant being displaced along the
horizontal section. The well was placed on-stream in December at an initial
"flush" production rate of 3.8 mmcfe per day and an average daily production
rate in the month of January 2008 of approximately 3.3 mmcfe per day.
In 2007, Orleans drilled a total of 10 (9.5 net) Montney gas wells, with seven
(6.5 net) wells on-stream, and three (3.0 net) wells tested and awaiting tie-in.
Thus far in 2008, the Company has drilled three (2.7 net) horizontal wells and
is currently drilling an additional horizontal well (1.0 net). One (1.0 net)
well has been completed and is currently being tested, and the other two
horizontals drilled are awaiting completion. Orleans is very encouraged by the
early completion results on the first horizontal well drilled on its Eastern
Kaybob lands. The horizontal well was fracture stimulated in seven-stages with a
total of 160 tonnes of proppant being displaced along the approximate 1,000
metre horizontal leg.
In 2008, Orleans intends to initially drill eight (6.7 net) horizontal wells on
its Kaybob lands, with five (3.7 net) targeting the Western acreage block and
three (3.0 net) on the Eastern block. The majority of these wells will be
drilled off common lease pads, allowing for more rapid turnaround to on-stream
production.
Leo, Central Alberta
Commencing in July 2007, Orleans drilled three (3.0 net) multi-leg horizontal
wells in the light gravity crude (36 degree API) Upper Mannville D & E oil
pools. The wells were brought on-stream in August of 2007, increasing the pool
production in excess of 200 boe per day. In 2008, the Company intends to
initiate a waterflood scheme to enhance oil production and reserves recoveries
from the pool. The Company has an additional three (3.0 net) horizontal
locations to drill in the pool.
Pine Creek, West Central Alberta
In the third quarter of 2007, the Company participated in the drilling of two
(0.75 net) gas wells in joint venture with area partners, targeting deep
Cretaceous-aged, multi-zone sweet natural gas. One well (0.25 net) was completed
and commingled in four separate intervals and was brought on-stream in November.
The second well (0.5 net) was completed in early 2008 and tested in three
separate zones and is anticipated to be tied-in prior to the end of the first
quarter of 2008.
Gilby, Central Alberta
In December 2007, the Company drilled a Gilby Edmonton Sand well (1.0 net),
encountering multiple pay sections. This well was tied-in and brought on-stream
mid-January 2008. Also in December, Orleans received approval to drill on
reduced spacing, up to four wells per section on 14.5 sections of Company lands,
yielding a future drilling inventory in excess of 40 Edmonton Sand wells.
Orleans also received approval to drill on reduced spacing in the Mannville,
allowing for three wells per section in the Glauconite formation and two wells
per section in the Lower Mannville formation, across eight sections of Orleans'
acreage.
Thus far in 2008, the Company drilled and cased a 100% working interest well
with multi-zone potential in the Edmonton Sand, Glauconite and Ellerslie zones.
The well is anticipated to be completed in the second quarter of 2008.
2008 Capital Budget and Market Guidance
As a result of the $25.2 million "bought-deal" equity financing, which closed on
March 13, 2008, the Company intends to expand its 2008 capital investment
budget. Orleans expects to provide details on its expanded 2008 capital
expenditure plans in addition to updated market guidance on or about March 28,
2008.
Management's Discussion & Analysis ("MD&A")
The following discussion is intended to assist the reader in understanding the
business and results of operations and financial condition of Orleans Energy
Ltd. (the "Company" or "Orleans"). This MD&A should be read in conjunction with
the financial statements for the year ended December 31, 2007 and the
consolidated financial statements for the prior year ended December 31, 2006,
available in printed form on request. Within this MD&A, the financial and
operating results for the year ended December 31, 2007 ("Year 2007") is compared
to the prior year ended December 31, 2006 ("Year 2006").
In this MD&A, production and reserves data is commonly stated in barrels of oil
equivalent ("boe") using a six (6) to one (1) conversion ratio when converting
thousands of cubic feet of natural gas ("mcf") to barrels of oil ("bbl") and a
one-to-one conversion ratio for natural gas liquids ("NGLs" or "ngls"). Such
conversion may be misleading, particularly if used in isolation. A boe
conversion ratio of six (6) mcf: one (1) bbl is based on energy equivalency
conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead.
As an indicator of the Company's performance, the term cash flow from operations
or operating cash flow contained within the MD&A should not be considered as an
alternative to, or more meaningful than, cash flow from operating activities as
determined in accordance with Canadian generally accepted accounting principles
("GAAP"). This term does not have a standardized meaning under GAAP and may not
be comparable to other companies. Orleans believes that cash flow from
operations is a useful supplementary measure as shareholders and/or investors
may use this information to analyze operating performance, leverage and
liquidity. Cash flow from operations, as disclosed within this MD&A, represents
cash flow from operating activities before changes in non-cash operating
activities working capital. The Company presents cash flow from operations per
share whereby per share amounts are calculated consistent with the calculation
of earnings per share. Please refer to the table, Reconciliation of Non-GAAP
Measures, contained within this MD&A.
Certain information regarding the Company contained herein may constitute
forward-looking statements within the meaning of applicable securities laws.
Forward-looking statements may include estimates, plans, expectations, opinions,
forecasts, projections, anticipates, guidance or other similar statements that
are not statements of fact. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to be correct. These statements are
subject to certain risks and uncertainties and may be based on assumptions that
could cause actual results to differ materially from those anticipated or
implied in the forward-looking statements. The Company's forward-looking
statements are expressly qualified in their entirety by this cautionary
statement.
For additional information relating to Orleans, please refer to other filings as
filed on SEDAR at www.sedar.com. All amounts are reported in Canadian dollars,
unless otherwise stated. This MD&A includes information up to and including
March 18, 2008.
Business Overview
Orleans Energy Ltd. is an independent, Alberta-based crude oil and natural gas
company actively engaged in the exploration for, development and production of
natural gas, crude oil and natural gas liquids reserves within the province of
Alberta. Orleans is incorporated under the laws of Alberta and its common shares
are publicly listed and traded on the TSX Venture Exchange under the trading
symbol "OEX". As of the March 18, 2008, Orleans' market capitalization is
approximately $160 million. Current production is weighted approximately 80%
natural gas and 20% light oil and NGLs. The Company's production base is
generated from five core producing areas throughout Central Alberta (Gilby and
Halkirk/Leo), West Central Alberta (Kaybob and Pine Creek) and the Peace River
Arch (Gordondale). Orleans' asset base possesses all the prerequisites for a
solid growth platform including: (i) an extensive, operated drilling inventory
providing exposure to both light oil and natural gas prospects within a West
Central Alberta geographic corridor, (ii) access to approximately 57,000 acres
of high working interest (81%) undeveloped acreage offering geologic play
diversity, (iii) a long-life, proved plus probable reserves base at December 31,
2007 of approximately 13.72 million boe with a reserve life index exceeding 10
years and, (iv) an operated production base allowing for year-round access.
Selected Period End and Quarterly Financial Information
----------------------------------------------------------------------------
2007 Quarterly Comparison Annual Summary
----------------------------------- -----------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
-------- -------- -------- -------- -------- --------
Petroleum & natural
gas revenue (1) 13,413 11,905 11,635 12,188 49,141 32,447
Cash flow from
operations 5,625 4,492 5,143 6,066 21,326 17,219
Net loss (2,096) (3,074) (128) (913) (6,210) (17,838)
Total assets - period
end 203,751 201,795 194,076 191,627 203,751 188,325
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006 Quarterly Comparison
--------------------------------------
($000s) Q406 Q306 Q206 Q106
-------- --------- --------- ---------
Petroleum & natural gas revenue (1) 11,038 9,777 5,912 5,720
Cash flow from operations 5,461 5,219 3,362 3,177
Net earnings (loss) (17,006) (128) (1,346) 642
Total assets - period end 188,325 192,609 180,598 55,109
----------------------------------------------------------------------------
(1) Petroleum & natural gas revenue includes realized hedging results from
commodity contract settlements.
The following commentary will assist in providing the reader with factors that
have caused variations over the aforementioned quarterly and annual results.
Petroleum and Natural Gas Production
For the year ended December 31, 2007, the Company's natural gas production
averaged 12,514 mcf per day and crude oil and NGLs production averaged 710 bbls
per day, resulting in a combined oil equivalent average daily rate of 2,796 boe
per day. The execution of a successful drilling program in 2007 enabled the
Company to increase its average daily production by 60% over the 1,750 boe per
day generated in the prior year ended December 31, 2006. In 2007, Orleans
drilled 18 wells (15.8 net). The Company's drilling program in 2007 yielded very
favourable results, with 100% of the well bores cased and completed,
encompassing 13 gas wells and five oil wells. During the fourth quarter ended
December 31, 2007, the Company's average daily oil equivalent production was
3,132 boe per day, weighted 78% towards natural gas and 22% percent light
gravity crude oil and NGLs. On an oil-equivalent basis, Orleans' crude oil and
natural gas sales volumes increased by 4% as compared to the preceding third
quarter ended September 30, 2007.
----------------------------------------------------------------------------
Average Daily Production Natural Gas Crude Oil & NGLs Oil Equivalent
(mcf/d) (bbls/d) (boe/d)
----------------------------------------------------------------------------
Q105 1,404 325 559
Q205 2,385 435 832
Q305 3,231 662 1,200
Q405 4,160 685 1,378
----------------------------------------------------------------------------
Calendar Year 2005 2,804 528 995
----------------------------------------------------------------------------
Q106 3,426 576 1,147
Q206 4,334 552 1,274
Q306 8,349 789 2,181
Q406 9,428 809 2,380
----------------------------------------------------------------------------
Calendar Year 2006 6,406 682 1,750
----------------------------------------------------------------------------
Q107 10,665 805 2,583
Q207 10,673 682 2,460
Q307 14,002 668 3,002
Q407 14,655 689 3,132
----------------------------------------------------------------------------
Calendar Year 2007 12,514 710 2,796
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Area Natural Gas Crude Oil & NGLs Oil Equivalent
(mcf/d) (bbls/d) (boe/d)
----------------------------------------------------------------------------
Halkirk/Leo 2,304 437 821
Gilby/Medicine River 3,394 154 720
Pine Creek 1,831 54 359
Kaybob 3,819 43 679
Pembina 623 - 104
Gordondale/Grimshaw 543 22 113
----------------------------------------------------------------------------
Year 2007 12,514 710 2,796
----------------------------------------------------------------------------
Petroleum and Natural Gas Revenue and Commodity Pricing
Orleans' petroleum and natural gas revenues may vary significantly from
period-to-period as a result of changes in commodity prices and/or production
volumes. The Company's commodity prices are driven by the prevailing worldwide
price for crude oil, spot prices applicable to its natural gas production, and
many other factors beyond its control. Historically, these prices have been
volatile and unpredictable.
Orleans takes the majority of its working interest production "in kind" and it
is marketed and sold through various commodity purchasers. Orleans' crude oil is
marketed under short-term evergreen contract with a major North American crude
oil marketer and purchaser. Orleans' crude oil has an average stream gravity of
approximately 35 degrees to 39 degrees API. A majority of Orleans' natural gas
sales are sold as spot gas through a significant North American natural gas
marketer.
The Company's crude oil price, including the effect of realized commodity
contract settlements, averaged $67.04 per barrel in the year ended December 31,
2007, an increase of approximately 1% from the oil price of $66.65 per barrel
realized in the prior year. Orleans' natural gas price realization in 2007 was
marginally higher than the previous year of $6.95 per mcf, averaging $7.06 per
mcf, with an average high of $8.72 per mcf in March 2007 and a monthly average
low of $6.03 per mcf in September 2007.
The Company's total petroleum and natural gas revenue for the three-month period
ended December 31, 2007 amounted to $13.41 million, representing a 22% increase
from the corresponding fourth quarter 2006 sales amount of $11.04 million.
Increased production volumes were the primary reason for higher realized
revenues in the fourth quarter of 2007 vis-a-vis the same quarter in 2006.
As a result of a marked increase in the Company's oil and gas production in
2007, Orleans' aggregate petroleum and natural gas revenue for year ended
December 31, 2007, including the impact of realized hedging activities, amounted
to $49.14 million as compared to $32.45 million generated in the prior year.
----------------------------------------------------------------------------
2007 Quarterly Comparison
----------------------------
($000s) Q407 Q307 Q207 Q107 Year 2007 Year 2006
------ ------ ------ ------ --------- ----------
(includes realized hedging)
Crude oil & NGLs revenue 4,274 4,040 4,069 4,497 16,880 16,188
Natural gas revenue 9,139 7,865 7,566 7,691 32,261 16,259
------ ------ ------ ------ --------- ----------
Gross revenue 13,413 11,905 11,635 12,188 49,141 32,447
----------------------------------------------------------------------------
Commodity Price Risk Management
The prices the Company receives for its crude oil and natural gas production may
have a significant impact on its revenues and cash flow from operations. Any
significant price decline in commodity prices would adversely affect the amount
of funds available for capital reinvestment purposes. As such, Orleans utilizes
a risk management program to partially mitigate that risk and to ensure adequate
funds are available for planned capital activities and other commitments. As
such, from time to time, the Company may employ derivative financial instruments
and physical arrangements, primarily commodity price contracts, to manage
fluctuations in oil and gas market prices, which are generally put in-place with
investment grade counter-parties that Orleans believes present minimal credit
risks. The Company does not utilize derivative financial instruments for
speculative trading purposes.
Orleans periodically uses swaps and collars to hedge crude oil and natural gas
prices. Commodity swaps are settled monthly based on differences between the
prices specified in the financial instruments and the settlement prices of
futures contracts. Generally, when the applicable settlement price is less than
the price specified in the contract, Orleans receives a settlement from the
counter-party based on the difference multiplied by the volume hedged.
Similarly, when the applicable settlement price exceeds the price specified in
the contract, Orleans pays the counter-party based on the difference. The
Company generally receives a settlement from the counter-party for collars when
the applicable settlement price is less than the floor price specified in the
contract and pays a settlement to the counter-party when the settlement price
exceeds the cap or ceiling. No settlement occurs when the settlement price falls
between the floor and ceiling.
Consequently, Orleans' realized petroleum and natural gas sales are impacted by
the settlement of these transactions. The various hedge contracts in-place
throughout 2007 resulted in a realized net gain of $1.29 million (2006: $344
thousand), comprised of a $1.55 million increase in natural gas revenue ($0.34
per mcf) and a $260 thousand decrease in crude oil and NGLs sales ($1.00 per
bbl).
The following table outlines the realized results of the Company's commodity
price risk management activities in 2007:
----------------------------------------------------------------------------
Year 2007 Year 2006
------------- --------------
Crude oil gain (loss) $ (260,304) $ 344,232
Natural gas gain 1,550,402 -
----------------------------
Realized gain (loss) on commodity contracts $ 1,290,098 $ 344,232
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As further described in Note 3 to the financial statements for the year ended
December 31, 2007, the Company recognizes the fair value of its commodity
contracts on the balance sheet each reporting period with the change in fair
value being recognized as an unrealized gain or loss on the statement of
operations. On January 1, 2007 the fair value of the commodity contracts was an
asset of $605,903 and resulted in an increase to accumulated other comprehensive
income and future tax liability of $425,405 and $180,498, respectively. The
entire amount recognized in accumulated other comprehensive income was fully
amortized over the term of the contracts in 2007 through other comprehensive
income with a corresponding unrealized gain on financial instruments on the
statement of operations. As a result, $425,405 net of tax, was charged during
the year to other comprehensive income with a corresponding unrealized gain on
financial instruments of $605,903 and a charge to future income tax liability of
$180,498. As at December 31, 2007, the fair value of the financial commodity
contracts was a liability of approximately $432 thousand, resulting in an
unrealized loss for the year of $432,470, net of the aforementioned unrealized
gain of $605,903.
The following table reconciles the Company's unrealized gain (loss) on
commodity contracts:
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, 2007 December 31, 2006
------------------ ------------------
Change in fair value of commodity
contracts $ (1,038,373) $ -
Unrealized gain charged to
accumulated other comprehensive
income 605,903 -
----------------------------------------------------------------------------
Unrealized gain (loss) on
commodity contracts $ (432,470) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table outlines the financial commodity price contracts that
were outstanding as at December 31, 2007, in addition to commodity contracts
entered into subsequent to December 31, 2007.
----------------------------------------------------------------------------
Daily
Notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Jan '08 - US$ 81.56
Crude Oil Oct. 15, 2007 Swap Jun '08 200 bbls W.T.I. /bbl
Jul '08 - US$ 90.00 -
Crude Oil (1) Mar. 3, 2008 Collar Dec '08 100 bbls W.T.I. $116.25/bbl
Nov '07 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.545/GJ
Jan '08 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.71/GJ
Jan '08 -
NatGas Oct. 31, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.67/GJ
Apr '08 -
NatGas Dec. 18, 2007 Swap Dec '08 2,000 GJs AECO-C C$ 6.55/GJ
Apr '08 -
NatGas (1) Jan. 2, 2008 Swap Dec '08 2,000 GJs AECO-C C$ 6.81/GJ
Apr '08 -
NatGas (1) Jan. 4, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.61/GJ
Apr '08 -
NatGas (1) Jan. 7, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.72/GJ
Apr '08 -
NatGas (1) Jan. 10, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.01/GJ
Nov '08 - C$ 7.00 -
NatGas (1) Feb. 13, 2008 Collar Mar '09 2,000 GJs AECO-C $9.70/GJ
Apr '08 -
NatGas (1) Feb. 14, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.52/GJ
----------------------------------------------------------------------------
(1) These contracts were entered into subsequent to December 31, 2007.
The following table highlights Orleans' corporate realized commodity prices
as well as market prices:
----------------------------------------------------------------------------
2007 Quarterly Comparison
---------------------------- Year Year
Q407 Q307 Q207 Q107 2007 2006
------ ------ ------ ------ ------- -------
Orleans' prices (1):
Natural gas ($/mcf) 6.78 6.11 7.79 8.01 7.06 6.95
Crude oil and NGLs ($/bbl) 67.40 65.76 65.61 62.07 65.10 65.00
Oil equivalent ($/boe) 46.55 43.11 51.97 52.43 48.15 50.80
Industry benchmark prices:
WTI Cushing oil (US$/bbl) 90.49 75.22 64.95 58.09 72.41 66.09
Edmonton Par oil ($/bbl) 86.89 80.67 72.69 67.61 76.17 73.25
Nymex gas (US$/mmbtu) 7.39 6.24 7.65 7.18 6.83 6.98
AECO gas ($/mcf) 6.01 5.07 6.94 7.26 6.85 6.38
Exchange rate (US$/C$) 1.0198 0.9562 0.9111 0.8534 0.9311 0.8817
----------------------------------------------------------------------------
(1) Orleans' reported prices include realized commodity contract
settlements.
Petroleum and Natural Gas Royalties
The Company's petroleum and natural gas royalties for the year ended December
31, 2007 amounted to $9.26 million, resulting in a corporate effective royalty
rate of 19%. Approximately 68% of Orleans' total royalties for 2007 relate to
Crown royalties with the residual 32% attributable to freehold and overriding
royalty encumbrances. The royalty rate in 2007 was marginally higher than the
rate realized in the prior year ended December 31, 2006 due to a higher
weighting of production derived from Crown lands vis-a-vis freehold acreage.
Typically, effective royalty rates associated with production on Crown lands is
higher than that of freehold-based production. During the fourth quarter of
2007, total royalties amounted to $2.5 million, resulting in a corporate
effective royalty rate of 19%.
On October 25, 2007, the Alberta government released The New Royalty Framework
report which summarizes the government's decisions on Alberta's new royalty
regime. The Alberta government's changes to their royalty structure on all Crown
mineral rights owned by the Province of Alberta and leased by oil and gas
producers such as Orleans is scheduled to take effect on January 1, 2009 upon
legislation enactment. The Company is currently awaiting finalization of the
royalty implementation regulations, however, it expects that its 2009 and
thereafter Alberta Crown royalty payments will increase as a result of the
proposed royalty changes. Please refer to the section New Alberta Royalty Regime
contained within hereafter.
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Crown (net ARTC) 1,706 1,703 1,363 1,508 6,280 3,106
Freehold and overrides 795 795 611 780 2,981 2,618
------- ------- ------- ------- ------- -------
Total 2,501 2,498 1,974 2,288 9,261 5,724
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Corporate royalty rate (%) 19% 21% 17% 19% 19% 18%
----------------------------------------------------------------------------
Operating Expenses
Orleans' field operating expenses, on an oil-equivalent per unit basis, are
generally impacted by the level of well-bore maintenance activity, geographic
location of the Company's properties, whether oil and gas is produced, and the
underlying commodity price levels. Commodity prices directly affect operating
cost elements such as power, fuel and chemicals. The remaining primary
components, which include among other things, field labour, services and
equipment, are indirectly impacted by high price environments, which drive up
activity and demand and therefore, increase costs. All elements of operating
expenses have been increasing throughout the oil and gas industry for several
years due to industry inflationary pressures.
The Company's total field operating expenses for the year ended December 31,
2007 amounted to $12.58 million or $12.32 on an oil-equivalent per unit basis.
In addition to inflationary pressures exerted on Orleans' operating cost
profile, a higher level of well-bore production optimization activity and the
off-lined production at Gordondale for seven and one-half months in 2007
resulted in a sharp per-unit increase in field production costs vis-a-vis the
year ended December 31, 2006 of $9.89 per boe. In 2007, in comparison to the
prior year, the Company was very active with well-bore maintenance activity,
resulting in higher per-unit operating costs. At Gordondale, Orleans incurred
fixed operating costs throughout 2007 despite the complete curtailment of
production from this field due to the main sales gas pipeline being offline,
between May 1 and November 29, and for the balance of the year December 18, 2007
thereafter. Shut-in production during 2007 at Gordondale contributed to the
higher per-unit operating costs, thus placing upward pressure on fiscal 2007
operating costs.
In the fourth quarter of 2007, Orleans' field production costs on an
oil-equivalent basis were $12.57 per boe, a marginal reduction from the per-unit
cost of $12.79 realized in the preceding quarterly period ended September 30,
2007. The off-line production at Gordondale continued to negatively impact the
Company's per-unit operating costs in the quarter. Orleans incurred fixed
operating costs at Gordondale throughout the fourth quarter despite the
curtailment of production from this field for most of the fourth quarter due to
the main sales gas pipeline being off-line.
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Total ($000s) 3,621 3,531 3,046 2,378 12,576 6,316
------- ------- ------- ------- ------- -------
Per unit ($/boe) 12.57 12.79 13.61 10.23 12.32 9.89
----------------------------------------------------------------------------
Transportation Expenses
The cost of transporting and distributing Orleans' crude oil and natural gas
production to market delivery points during the year ended December 31, 2007
amounted to $1.1 million or $1.08 on an oil-equivalent per unit basis. Increased
production volumes, supplemented with increased clean oil trucking rates and
Nova gas pipeline fuel surcharges throughout 2007 resulted in transportation
cost increases on an aggregate and per-unit basis.
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Total ($000s) 299 274 269 255 1,098 568
Per unit ($/boe) 1.04 0.99 1.20 1.10 1.08 0.89
----------------------------------------------------------------------------
General & Administrative Expenses
The Company's general and administrative ("G&A") expenses during the year ended
December 31, 2007, excluding the non-cash stock-based compensation provision,
amounted to $2.19 million or $2.15 on an oil-equivalent per unit basis. In the
fourth quarter of 2007, expensed G&A amounted to $651 thousand, as compared to
$484 thousand incurred in the third quarter of 2007. Gross G&A, net of operator
recoveries, increased by $373 thousand in the fourth quarter over the third
quarter of 2007 as a result of accrued costs associated with the year-end
independent engineering reserves report and the annual financial statement
accounting audit, in addition to year-end performance bonuses paid to employees.
Orleans presently employs 17 head office personnel, an increase from 11 staff
members employed this time last year, including eight geological and engineering
technical personnel. The Company also engages the services of three consultants
on a part-time, as needed, basis. In April 2007, the Company took occupancy of
its new head office premises, in order to accommodate the expanded office
operations necessary to effectively and efficiently manage the Company's larger
asset base.
The Company applies the full cost method of accounting for its oil and gas
operations. Accordingly, it capitalized employee G&A and associated direct
overhead costs of its technical personnel in the amount of $1.01 million during
the year ended December 31, 2007 (December 31, 2006: $623 thousand)
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Gross, net of operator
recoveries 1,037 664 757 744 3,202 2,013
Capitalized (386) (180) (241) (204) (1,011) (623)
------- ------- ------- ------- ------- -------
Expensed 651 484 516 540 2,191 1,390
------- ------- ------- ------- ------- -------
Per unit ($/boe) 2.26 1.75 2.30 2.32 2.15 2.18
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
% Capitalized 37% 27% 32% 27% 32% 31%
----------------------------------------------------------------------------
Stock-Based Compensation
Orleans utilizes the fair value method for measuring stock-based compensation
expenses. Compensation cost is measured at the grant date based on the fair
value of the option using a Black-Scholes option pricing model and is recognized
over the option vesting period. Some of the inputs to the option valuation model
are subjective, including assumptions regarding expected stock price volatility.
The Company's stock-based compensation relates entirely to the granting of stock
options. During the year ended December 31, 2007, the Company recorded
stock-based compensation expense of $729 thousand (2006: $555 thousand), which
was charged to general and administration expense and presented as such on the
Company's statement of operations. In 2007, the Company capitalized $905
thousand of its stock-based compensation charges (2006: $720 thousand). As of
December 31, 2007, total unrecognized compensation cost of $2.43 million,
related to 1.97 million unvested Orleans' stock options, is expected to be
recognized in future periods over the remaining vesting terms.
Interest Charges
During the year ended December 31, 2007, Orleans incurred $2.46 million in
interest charges relating to its outstanding bank indebtedness, net of $32
thousand of interest income. As at December 31, 2007, the Company had $44.14
million of bank debt, as compared to $38.78 million of outstanding bank
indebtedness at December 31, 2006. Orleans' bank debt increased in 2007
primarily as a result of exploration and development capital investments
exceeding its generated cash flow from operations. In addition to bank debt
interest incurred in 2007, the Company accrued for the federal government's
levied interest charges related to Orleans' November 2006 flow-through financing
exploration expenditure deductions, previously renounced under the "look back"
rules. In 2007, this interest charge was accrued in the amount of $198 thousand
and was disbursed in the first quarter of 2008.
In the fourth quarter of 2007, Orleans incurred $645 thousand in interest
expenses relating to the debt servicing of its outstanding bank indebtedness and
accrued $36 thousand for the aforementioned November 2006 flow-through
financing, the federal government's levied interest charges.
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Interest charges (net
interest income) 681 626 688 660 2,655 1,231
----------------------------------------------------------------------------
Depletion, Depreciation and Accretion
Orleans' depletion and depreciation expense for the year and three month periods
ended December 31, 2007 amounted to $28.82 million and $7.80 million,
respectively. On a unit-of-production rate basis, the depletion and depreciation
provision for year ended December 31, 2007 was $28.24 per boe, as compared to
the $26.04 per boe provision recognized for the year ended December 31, 2006.
The depletion and depreciation rate is a useful measure for evaluating finding
and development costs on proved reserves basis since the rate generally
considers all acquisition, exploration and development capital costs. The rate
also considers any additional future development costs associated with proved
non-producing reserves. Orleans' ability to efficiently discover and develop
proved oil and gas reserves in a cost-effective manner is reflected in the
Company's decreasing depletion and deprecation rate provision throughout 2007.
Orleans' depletion and deprecation rate in the first quarter of 2007 was $28.68
per boe (excluding ARO accretion), decreasing to $27.08 per boe for the fourth
quarter ended December 31, 2007.
The Company's accretion expense relating to its asset retirement obligations
("ARO") amounted to $465 thousand for the year ended December 31, 2007 and $111
thousand for the fourth quarter of 2007.
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Depletion & depreciation (1) 7,802 7,753 6,602 6,666 28,823 16,633
ARO accretion (2) 111 120 118 116 465 353
Total 7,913 7,873 6,720 6,782 29,288 16,986
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Per unit ($/boe) 27.46 28.51 30.02 29.18 28.70 26.59
----------------------------------------------------------------------------
(1): Includes depletion of the capitalized portion of the asset retirement
obligation which was capitalized to the PP&E balance and is being
depleted over the life of the Company's proved reserves.
(2): Represents the accretion expense on the asset retirement obligation
during the year.
Ceiling Test
Orleans calculates a ceiling test whereby the carrying value of property, plant
and equipment ("PP&E") is compared to estimated future cash flow from production
of proved reserves. The ceiling test is performed under a two-step process in
accordance with the requirements of the Canadian Institute of Chartered
Accountants ("CICA") AcG-16 "Oil and Gas Accounting - Full Cost". The Company
performed a ceiling test calculation as at December 31, 2007, resulting in
undiscounted cash flows from proved reserves and the unproved properties not
exceeding the carrying value of its PP&E. Consequently, Orleans performed step
two of the ceiling test assessing whether discounted future cash flows from the
production of proved plus probable reserves plus the carrying cost of unproved
properties, net of any impairment allowance, exceeds the carrying value of its
PP&E. Based on the step two ceiling test calculation results, no write-down of
the Company's carrying value of PP&E was required as at December 31, 2007.
Asset Retirement Obligations
As at December 31, 2007, Orleans recorded an ARO of $5.45 million for estimated
future costs to plug and abandon the Company's oil and gas wells and to
dismantle and remove associated production facilities, as compared to $5.02
million at December 31, 2006. For the year ended December 31, 2007, the ARO
liability increased by a total of $431 thousand as a result of accretion expense
of $465 thousand, $185 thousand in liabilities incurred on development drilling
activities, offset by $186 thousand of liabilities released on property
dispositions and $33 thousand on an ARO liability settlement.
Income Taxes
Orleans follows the liability method of accounting for income taxes whereby
future income taxes are calculated based on temporary differences arising from
the variance between the tax basis of an asset or liability and its PP&E
carrying value. For the year ended December 31, 2007, the Company recorded a
future income tax reduction of $2.88 million, as compared to an $895 thousand
income tax expense recognized in year ended December 31, 2006. During the year
ended December 31, 2007, the Company's effective future income tax rate was
reduced primarily due to income tax rate reductions enacted or substantively
enacted in Canada during both the second and fourth quarters of 2007, and
adjustments to future tax expense related to the final phase-in of 100%
deductibility of Crown royalties and the elimination of the Federal resource
allowance in 2007.
During the year ended December 31, 2007, Orleans was not subject to any
corporate income tax due to the Company's significant tax pool balances, which
aggregate to approximately $175 million. As a result of Orleans' sizeable tax
pool position, the Company does not expect to be subject to corporate cash
income tax in the foreseeable future. The following table outlines Orleans' tax
pools as at December 31, 2007:
----------------------------------------------------------------------------
Access Rate Balance
($ millions)
----------------------------------------------------------------------------
Canadian exploration expense (CEE) 100% $ 30.5
Canadian development expense (CDE) 30% 53.1
Canadian oil and gas property expense (COGPE) 10% 35.7
Undepreciated capital cost (UCC) 25% 41.6
Non-capital losses (NCL) 100% 8.3
Share issue costs and other 20% 5.9
----------------------------------------------------------------------------
Total $ 175.1
----------------------------------------------------------------------------
Reconciliation of Non-GAAP Measures
----------------------------------------------------------------------------
($000s except share data) Year 2007 Year 2006
----------------------------------------------------------------------------
Net loss (6,210) (17,838)
Non-cash items:
Depletion & depreciation 28,823 16,633
ARO accretion 465 353
Stock-based compensation 729 555
Unrealized loss on commodity contracts 432 -
Future income taxes (reduction) (2,880) 895
Goodwill impairment - 16,620
Asset retirement expenditures (33) -
----------------------------------------------------------------------------
Cash flow from operations 21,326 17,219
----------------------------------------------------------------------------
Per share - basic 0.60 0.71
----------------------------------------------------------------------------
Operating Cash Flow and Net Earnings
Orleans' profitability and cash flow generation is primarily a function of
commodity prices, the cost to add reserves through drilling and acquisitions and
the cost to produce the Company's reserves. In the year ended December 31, 2007,
Orleans recorded $21.33 million in cash flow from operations and posted a net
loss of $6.21 million. As compared to the prior 2006 year of generated cash flow
of $17.22 million and a recorded net loss of $17.84 million, which included the
non-cash, goodwill impairment charge of $16.62 million.
----------------------------------------------------------------------------
($000s except 2007 Quarterly Comparison
share data) Q407 Q307 Q207 Q107 Year 2007 Year 2006
----------------------------------------------------------------------------
Cash flow from
operations (1) 5,625 4,492 5,143 6,066 21,326 17,219
Per share -
basic 0.15 0.12 0.16 0.18 0.60 0.71
Per share -
diluted 0.15 0.12 0.15 0.18 0.60 0.69
Net loss (2,095) (3,074) (128) (913) (6,210) (17,838)
Per share -
basic (0.06) (0.08) - (0.03) (0.18) (0.73)
Per share -
diluted (0.06) (0.08) - (0.03) (0.18) (0.73)
----------------------------------------------------------------------------
(1) Cash flow from operations does not have any standardized meaning
prescribed by Canadian GAAP and accordingly represents cash flow from
operating activities before any asset retirement obligation cash
expenditures. As an indicator of the Company's performance, the term
cash flow from operations or operating cash flow contained within
should not be considered as an alternative to, or more meaningful than,
cash flow from operating activities as determined in accordance with
Canadian GAAP.
Capital Expenditures
The Company's capital investments involve exploration, development and
acquisition activities, which generally include the following:
- Drilling and completing new natural gas and oil wells;
- Constructing and installing new field production infrastructure;
- Acquiring and maintaining the Company's lease acreage position and its seismic
resources;
- Enhancing existing natural gas and oil wells through well-bore re-completions;
- Acquiring additional natural gas and oil reserves and producing properties; and,
- General and administrative costs directly associated with exploration and
development activities, including payroll and other overhead expenses
attributable solely to the Company's technical employees.
In the year ended December 31, 2007, the Company's total capital investment
expenditures amounted to $46.26 million. Collectively in 2007, the Company
drilled 18 wells (15.8 net), of which only three (1.25 net) were non-operated.
Orleans drilled wells across the majority of its focus areas, including: 10 gas
wells (9.5 net) in Kaybob, three horizontal oil wells (3.0 net) in Leo, two gas
wells (0.75 net) in Pine Creek, two oil wells (1.5 net) in Gordondale and one
gas well (1.0 net) at Gilby. Additionally, in June 2007, the Company
significantly expanded its land holdings at Kaybob in West Central Alberta
through successful participation at a strategic Alberta Crown land sale. Orleans
acquired 11.5 sections (100% working interest) of land for $5.64 million,
essentially doubling its ownership presence at Kaybob.
Orleans continued to be active with the drill bit in the fourth quarter of 2007,
incurring approximately $6.4 million of drilling and completion expenditures
through the drilling five wells (4.5 net), including two gas wells brought
on-stream in December 2007 and January 2008 and three gas wells awaiting tie-in.
Orleans' 2007 capital investment program enabled the Company to expand its total
proved plus probable oil and gas reserves to 13.7 million boe at December 31,
2007 from 11.4 million boe at December 31, 2006, resulting in a 2007 finding and
development cost of $19.20 per proved plus probable boe (includes change in
undiscounted future development costs).
Orleans' management closely monitors the exploration and development capital
program in relation to estimated cash flow from operations and expects to incur
capital expenditures initially of approximately $30 million, excluding
acquisitions, during 2008. Please refer to the section 2008 Business Outlook
contained within hereafter. Actual spending may vary due to a variety of
factors, including drilling results, natural gas and oil prices, economic
conditions, equipment availability, permitting and any future acquisitions. The
timing of most of the Company's capital expenditures is discretionary because
Orleans does not have any material capital expenditure commitments.
Consequently, the Company has a significant degree of flexibility to adjust the
level of it capital investments as circumstances warrant. Additionally, to
enhance flexibility of the Company's capital program, Orleans typically does not
enter into material long-term obligations with any of its drilling contractors
or service providers with respect to its operated natural gas and oil
properties.
The breakdown of Orleans' capital programs are outlined below:
----------------------------------------------------------------------------
2007 Quarterly Comparison
-------------------------------
Year Year
($000s) Q407 Q307 Q207 Q107 2007 2006
------- ------- ------- ------- ------- -------
Land 60 430 5,691 37 6,218 6,608
Seismic 70 - (33) 260 297 558
Drilling & completions 6,369 11,215 3,780 6,728 28,092 29,788
Facilities & well
equipment 2,473 3,038 1,398 3,965 10,874 9,302
------- ------- ------- ------- ------- -------
Exploration & development 8,972 14,683 10,836 10,990 45,481 46,256
------- ------- ------- ------- ------- -------
Other (1) 661 463 512 428 2,064 1,469
Property purchases
(dispositions) (150) - (1,139) - (1,289) 1,180
Corporate acquisitions (2) - - - - - 110,817
------- ------- ------- ------- ------- -------
Total capital expenditures 9,483 15,146 10,209 11,418 46,256 159,722
----------------------------------------------------------------------------
(1): Year 2007 includes capitalized G&A of $1.01 million (2006: $623
thousand) and non-cash capitalized stock-based compensation of $905
thousand (2006: $720 thousand).
(2): Includes total consideration paid (cash, shares issued and transactions
costs) for acquisitions and working capital and assumption of debt.
Goodwill
In the year ended December 31, 2006, the Company recorded goodwill of
approximately $16.62 million in connection with the acquisition of Morpheus
Energy Corporation (December 31, 2007: nil). The Company conducted the
prescribed impairment test at December 31, 2006, resulting in a non-cash
accounting impairment of the full $16.62 million goodwill amount since the fair
value of Orleans' goodwill did not exceed the goodwill carrying amount.
Liquidity and Capital Resources
At December 31, 2007, the Company was capitalized with a working capital deficit
of $48.19 million (December 31, 2006: $43.23 million), including bank debt of
$44.14 million (December 31, 2006: $38.78 million) and 37.57 million common
shares outstanding with a book capitalization of $137.73 million and a market
capitalization of approximately $83 million.
----------------------------------------------------------------------------
2007 Quarter End Comparison
($000) Dec. 31 Sep. 30 Jun. 30 Mar. 31
----------------------------------------------------------------------------
Bank debt 44,137 34,794 53,281 47,333
Working capital
deficit / (surplus) (1) 4,052 9,743 (99) 1,070
----------------------------------------------------------------------------
Net Debt 48,189 44,537 53,182 48,403
----------------------------------------------------------------------------
Book capitalization (2) 137,732 137,736 118,329 118,231
Market capitalization (3) 83,033 102,877 132,239 122,650
----------------------------------------------------------------------------
(1): Reflects current assets (excluding non-cash commodity risk management
asset) less current liabilities (excluding non-cash commodity risk
management liability and outstanding bank debt).
(2): Reflects the book value of share capital, as reported on the
Company's respective balance sheets.
(3): Based on the market closing price of Orleans stock and the outstanding
number of common shares at period-end.
On April 10, 2007, the Company entered into a new credit agreement with a major
Canadian chartered bank. The new credit agreement increased the borrowing base
of the revolving demand facility to $60 million. The borrowing base, which is
re-determined semi-annually, represents the amount that can be borrowed from a
credit standpoint based on, among other things, the Company's current reserve
report, results of operations, current and forecasted commodity prices and the
current economic environment, as confirmed by the bank.
At December 31, 2007, the Company had borrowings of $44.14 million (December 31,
2006: $38.78 million) under its bank facility with a Canadian chartered bank and
was in compliance with all covenant terms of the credit agreement. The increase
in the bank debt position of the Company at year-end 2007, as compared to
year-end 2006, is attributable to capital investments incurred in 2007 exceeding
the cash generated through operating activities within that period.
On July 12, 2007, the Company closed a "bought-deal" equity financing (the "2007
Financing"). Pursuant to the 2007 Financing, Orleans issued 1.5 million
flow-through common shares at a price of $5.45 per share and 2.8 million common
shares at a price of $4.30 per share, for total gross proceeds of $20,215,000.
Proceeds from the flow-through share component of the 2007 Financing, in the
amount of $8,175,000, will be used to incur Canadian exploration expenditures
prior to December 31, 2008, with such expenditures to be renounced to the
subscribers of the flow-through common shares in the fiscal year ended December
31, 2007.
On March 13, 2008, the Company closed a "bought-deal" equity financing (the
"2008 Financing"). Pursuant to the terms of the 2008 Financing, the Company
issued 7.0 million common shares at a price of $3.60 per share for total gross
proceeds of $25.2 million.
With respect to the asset-backed commercial paper ("ABCP") market liquidity
issues, which occurred during the third quarter of 2007 in the global credit
markets as a result of the deterioration of the U.S. sub-prime mortgage market
and resulted in numerous companies, including those within the oil and gas
sector, not being able to access their funds when the ABCP became ordinarily
due, the Company has never held funds in ABCP and is not directly impacted by
the current market liquidity crunch.
In 2008, as in 2007, the Company expects its cash flow from operations to be its
primary source of liquidity to meet operating, general and administrative and
interest expenses, and fund planned spending on exploration and development
capital projects and undeveloped acreage. The aforementioned $60 million
revolving bank credit facility will provide another source of liquidity. The
Company anticipates that public capital markets will serve as the principal
source of funds to finance any future substantial corporate acquisitions and/or
significant property purchases. Orleans has sold equity securities in the past,
and the Company expects that this source of capital will be available in the
future for acquisition purposes.
Common Share Information
----------------------------------------------------------------------------
2007 Quarterly Comparison Year Year
Q407 Q307 Q207 Q107 2007 2006
----------------------------------------------------------------------------
Share
Price: High $ 3.10 $ 4.00 $ 4.55 $ 4.05 $ 4.55 $ 6.99
Low $ 2.05 $ 2.54 $ 3.53 $ 2.75 $ 2.05 $ 3.37
Close $ 2.21 $ 2.74 $ 3.98 $ 3.70 $ 2.21 $ 3.45
Avg. daily
trading
volume(1) 90,524 49,887 89,663 64,247 73,732 43,145
Shares
outstanding
- period
end(2) 37,571,372 37,546,372 33,225,889 33,148,659 37,571,372 33,148,659
Weighted
average
basic 37,571,100 37,014,430 33,209,828 33,148,659 35,252,993 24,362,187
Weighted
average
diluted 38,019,052 37,526,046 33,833,429 33,743,616 35,772,226 25,136,494
----------------------------------------------------------------------------
(1): The common shares of Orleans commenced trading on the TSX Venture
Exchange on January 31, 2005. In 2008, the Company intends to
undertake the process of graduating the listing of its common shares
to the Toronto Stock Exchange ("TSX"). It is anticipated the listing
of Orleans' common shares on the TSX will provide the Company with
access to Canada's largest stock exchange while enhancing Orleans'
trading liquidity and visibility within the North American capital
markets. This graduation process to the TSX is expected to be
finalized in the second quarter of 2008.
(2): As of the date of this MD&A, total common shares issued and
outstanding are 44,571,372.
Orleans has never paid cash dividends on its common stock. The Company presently
intends to retain any earnings for the operation and expansion of its business
and does not anticipate paying cash dividends in the foreseeable future. Any
future determination as to the payment of dividends will depend upon the results
of the Company's operations, capital investment requirements, Orleans' financial
condition and such other factors the Company's board of directors may deem
relevant. In addition, the Company is restricted under its bank credit facility
from paying or declaring cash dividends.
Commitments Obligations and Commitments
In the normal course of business, the Company has entered into various
commitments that will have an impact on Orleans' future operations. These
commitments primarily relate to debt repayments, operating leases relating to
head office space and natural gas field equipment and drilling rig contractual
obligations. The following table summarizes the Company's various contractual
obligations and commitments as at December 31, 2007:
----------------------------------------------------------------------------
($000s) Less than 1 - 3 Years 4 - 5 Years Beyond 5
1 Year Years Total
----------------------------------------------------------------------------
Bank debt (1) 44,137 - - - 44,137
Head office lease
obligations (2) 649 1,979 1,360 227 4,215
Field equipment
operating leases (3) 254 20 - - 274
Drilling contract (4) 371 - - - 371
----------------------------------------------------------------------------
Total obligations 45,411 1,999 1,360 227 48,997
----------------------------------------------------------------------------
(1): Demand revolving operating credit facility with a Canadian chartered
bank. Refer to Note 8 to the financial statements for the year ended
December 31, 2007. This facility has no specific terms of repayment
aside from the bank's right of demand and periodic review.
(2): Pertains to lease payments associated with the Company's Calgary,
Alberta head office lease entered into on February 16, 2007, including
an estimate of the Company's share of operating, utilities, property
taxes and parking for the duration of the office lease.
(3): Pertains to various monthly and short-term operating leases for nine
field natural gas compressors and one separator.
(4): The Company has committed to a short-term drilling program with a
major drilling contractor. As at December 31, 2007, the Company is
obligated to utilize the contractor's rig for a period of
approximately 44 days, prior to April 30, 2008.
In 1996, a lawsuit was filed against the Company's predecessor, Orleans
Resources Inc. and the "procureur general du Quebec". Since the Company is of
the opinion that this lawsuit against Orleans Resources Inc. is unwarranted and
will have no material adverse effect on the Company's financial position or on
the results of operations, no provision has been recorded in this respect. If
the Company has to pay any amount in this affair, this amount will be paid by
issuing reserved common shares, at a price of $6.00 per share. The maximum
number of common shares that would have to be issued would be 666,118 shares,
representing the full lawsuit value amount of $3.996 million.
Additionally, refer to Note 10 c) to the financial statements for the year ended
December 31, 2007, which outlines the Company's requirements to incur by
December 31, 2008 flow-through share eligible Canadian Exploration Expenditures,
as defined in the Income tax Act (Canada).
Off-Balance Sheet Arrangements
The Company has no off-balance sheet arrangements, special purpose entities,
financing partnerships or guarantees, other than as disclosed in this section.
Orleans has certain lease agreements, as disclosed in the aforementioned
Contractual Obligations and Commitments table, which were entered into in the
normal course of business operations. All leases have been treated as operating
leases or rental arrangements whereby the lease payments are included in
operating expenses or G&A expenses depending on the nature of the lease. No
asset or liability value has been assigned to these leases on the balance sheet
as at December 31, 2007.
Related Party Transactions
A director and the corporate secretary of the Company are partners at a law firm
that provides legal services to the Company. The services were conducted in the
normal course of business operations and are measured at the exchange amount,
which is established and agreed to by the related parties based on standard
rates, time spent and costs incurred. During the year ended December 31, 2007,
Orleans paid and accrued a total of $133 thousand to this firm for legal fees
and disbursements (December 31, 2006: $326 thousand).
Disclosure Controls and Procedures
Orleans' disclosure controls and procedures, as defined in Multilateral
Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim
Filings", were reviewed by the Company's Chief Executive Officer ("CEO") and
Chief Financial Officer ("CFO"). Based on this review and given the size and
nature of the Company's operations, the Company's CEO and CFO believe the
Company's disclosure controls and procedures to be effective as of December 31,
2007. All control systems by their nature have inherent limitations and
therefore Orleans' disclosure controls and procedures are believed to provide
reasonable, but not absolute assurance, that: i) the Company's communications
with the public are timely, factual and accurate and broadly disseminated in
accordance with all applicable legal and regulatory requirements, ii)
non-publicly disclosed information remains confidential, and iii) trading of the
Company's common shares by Orleans' directors, officers and employees remain in
compliance with applicable securities laws.
Internal Controls Over Financial Reporting
The Company's CEO and CFO are responsible for designing the internal controls
over financial reporting ("ICOFR") or causing them to be designed under their
supervision in order to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external
purposes in accordance with Canadian GAAP. As at December 31, 2007, the CEO and
CFO evaluated the design and implementation of the Company's ICOFR. In part,
this evaluation was based on a third party specialist who was engaged by the
Company, under the CFO's supervision, to formally document Orleans' ICOFR. Based
on this evaluation, the CEO and the CFO have concluded that the design of
internal control over financial reporting is sufficiently effective to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
Canadian GAAP.
It should be recognized, however, that control systems over financial reporting,
no matter how well conceived or operated, can provide only reasonable, not
absolute assurance that the objectives of the control systems are met. The
Company, due to its relatively small size and organizational structure, does
have potential weaknesses in its internal control over financial reporting.
These include:
- Comprehensive segregation of duties may not be sufficiently adequate.
Specifically, certain duties within the accounting function were not ideally
segregated due to the small number of individuals employed in this area. This
deficiency was not believed to be a material weakness since, at the present
time, the CEO and the CFO oversee all material transactions and related
accounting records and there is daily oversight by the senior personnel of the
Company. In addition, Orleans' Audit Committee reviews on a quarterly basis the
financial statements and key risks of the Company and queries management about
significant transactions. It should be noted though, as the Company continues to
grow, it plans to expand the number of individuals involved in the accounting
function to facilitate comprehensive segregation of duties.
- The Company does not presently retain staff with specialized, complex and
non-routine accounting expertise, which may present a risk of misstatements. The
Company reports current and future income tax expenses and liabilities and other
complex accounting calculations based on management's estimates, however there
is no guarantee that a material misstatement would be prevented. The Company
will attempt to remediate this potential internal control weakness by utilizing
outside consultants with the appropriate expertise when the need arises or by
developing in-house expertise or recruiting the necessary personnel with the
expertise.
Change in Accounting Policies
The following standards regarding financial instruments were effective for
January 1, 2007; section 3855 "Financial Instruments - Recognition and
Measurement", section 3861 "Financial Instruments - Disclosure and
Presentation", section 1530 "Comprehensive Income", and section 3865 "Hedges".
The standards require all financial instruments other than held-to-maturity
investments, loans and receivables to be included on a company's balance sheet
at their fair value. Held-to-maturity investments, loans and receivables would
be measured at their amortized cost. The standards create a new statement for
comprehensive income that will include changes in the fair value of certain
financial instruments. As a result of these new standards, the Company records
the fair value of its crude oil and natural gas derivative contracts under its
risk management program on the Company's balance sheet. No restatement of prior
periods occurred as a result of these new standards.
New Accounting Pronouncements
Two new accounting standards were issued by the CICA, section 3862 "Financial
Instruments - Disclosures", and section 3863 "Financial Instruments -
Presentation". These sections will replace section 3861 "Financial Instruments -
Disclosure and Presentation" once adopted. The objective of section 3862 is to
provide users with information to evaluate the significance of the financial
instruments on the entity's financial position and performance, the nature and
extent of risks arising from financial instruments, and how the entity manages
those risks. The provisions of section 3863 deal with the classification of
financial instruments, related interest, dividends, losses and gains, and the
circumstances in which financial assets and financial liabilities are offset.
These new sections are effective for the Company beginning January 1, 2008.
In December 2006, the Canadian Accounting Standards Board ("AcSB") issued
section 1535, "Capital Disclosures", requiring disclosure of information about
an entity's capital and the objectives, policies, and processes for managing
capital. The standard is effective for annual periods beginning on or after
October 1, 2007 and will require additional disclosure at that time.
In February 2008, the AcSB issued section 3064, "Goodwill and Intangible
Assets", and amended section 1000, "Financial Statement Concepts" clarifying the
criteria for the recognition of assets, intangible assets and internally
developed intangible assets. Items that no longer meet the definition of an
asset are no longer recognized with assets. The standard is effective for annual
years beginning on or after October 1, 2008 and early adoption is permitted. The
Company is presently evaluating the impact these sections will have on its
results of operations and/or financial position.
In January 2006, the AcSB adopted a strategic plan for the direction of
accounting standards in Canada. Accounting standards for public companies in
Canada will converge with the International Financial Reporting Standards
("IFRS") in 2011. IFRS will replace Canadian GAAP with the official
'change-over' to IFRS to occur for interim and annual financial statements
relating to fiscal years beginning on or after January 1, 2011. The Company
continues to monitor and assess the impact of these convergence efforts.
2008 Business Outlook
In December 2007, Orleans' Board of Directors approved an initial 2008
exploration and development capital expenditure program (net risked) of
approximately $30 million (the "2008 Capital Budget"). In light of the uncertain
outlook for natural gas prices, Orleans decided to initially execute a
conservative capital budget whereby its total budgeted capital investments are
anticipated not to significantly exceed budgeted cash flow from operations.
Notwithstanding this initial, cautious capital expenditures level, anticipated
to facilitate continued financial flexibility, the 2008 Capital Budget is
programmed to deliver approximately 30% growth in average daily production
year-over-year and advance the continued development of Orleans' West Kaybob
asset base in concert with the continued exploration and delineation of its East
Kaybob acreage position.
The 2008 Capital Budget encompasses the drilling of 11 operated wells, with an
approximate 86% working interest, including eight (6.7 net) horizontal wells at
Kaybob targeting the prolific Triassic Montney gas formation. The drilling and
completion expenditure component of Orleans' 2008 Capital Budget is projected to
approximate $22 million, with the remaining budgeted funds allocated towards
investments in field facilities of approximately $7 million and undeveloped land
expansion and seismic programs of approximately $1.5 million. In terms of
geographic area allocation of the budgeted drilling, completion and field
facilities capital expenditures, approximately $21 million is expected to be
deployed at Kaybob, with the residual capital allocated across the Company's
other core areas.
Based on the budgeted capital expenditures anticipated within the initial 2008
Capital Budget, average daily production for fiscal 2008 is projected at
approximately 3,600 to 3,700 boe per day, weighted 80% natural gas and 20% light
crude oil and natural gas liquids. This forecasted production range represents a
30% increase over Orleans' 2007 average daily production of approximately 2,800
boe per day and a 109% increase over the Company's 2006 average daily production
level of 1,750 boe per day. Orleans' year-end 2008 exit production rate is
anticipated to range 3,900 to 4,000 boe per day. The Kaybob drilling program
will be the primary driver of the robust economic production growth that the
Company expects to realize in 2008.
Business Risks and Uncertainties
The Company's exploration and development activities are focused in the Western
Canada Sedimentary Basin within the province of Alberta, which is characterized
as being highly competitive with competitors varying in size from small junior
producers to significantly larger, fully-integrated energy companies and oil and
gas royalty trusts possessing greater financial and personnel resources. The
Company recognizes certain risks inherent in the oil and gas industry, such as
access to oil and gas services, weather-related delays with drilling and
operational plans, finding and developing oil and gas reserves at economic
costs, drilling risks, producing oil and gas in commercial quantities,
environmental and safety risks, and commodity price and political risks and
uncertainties. Orleans has engaged professional management and technical
personnel with many years of experience in the oil and gas business to address,
prudently manage and mitigate these risks.
New Greenhouse Gas and Air Emissions Legislation
The Alberta Government has introduced legislation that will enable the Province
of Alberta to regulate emissions of "greenhouse gases". The regulations require
facilities that emit over 100,000 tonnes of greenhouse gases a year to reduce
their emissions intensity by 12% starting July 1, 2007 or pay a fee based on
emissions in excess of the targeted reductions. The Federal Government has also
released its regulatory framework to reduce emissions of both greenhouse gases
and four smog-forming pollutants with targets coming into force in 2010 and
2015, respectively. Clarification surrounding the regulations is expected in the
next year with the regulations to be finalized by 2010. There are multiple
compliance mechanisms under both the Alberta and Federal plans including making
contributions to technology funds, emissions trading and offset credits. The
Company is in the process of fully evaluating the impact of these regulations,
but Orleans believes that the cost and impact on its operations will be minor.
New Alberta Royalty Regime
On October 25, 2007, the Alberta government released The New Royalty Framework
report ("NRF"), which summarizes the government's decisions on Alberta's new
royalty regime. The NRF was the Alberta government's response to a report issued
September 18, 2007 by the Alberta Royalty Review Panel ("ARRP"), which was
commissioned by the Government of Alberta to perform a review of the province's
royalty system. The NRF, in its entirety, is available at www.energy.gov.ab.ca.
As a result of the Alberta government's changes to their royalty structure on
all Crown mineral rights owned by the Province of Alberta and leased by oil and
gas producers such as Orleans, scheduled to take effect on January 1, 2009 upon
legislation enactment, the Company would like to make the following
observations:
- The Company's geographic, geologic and individual well production diversity of
its asset base within Alberta, in conjunction with the production revenue
derived from its freehold leases which are not impacted by the proposed new
Crown royalties, is anticipated to temper the overall impact to Orleans of the
announced changes to Crown royalties;
- Royalties determined under the NRF will be determined based on commodity
prices, well productivity and depth of wells. A significant portion of the
Company's wells are lower productivity wells that on a relative basis are less
significantly impacted by the NRF than higher productivity wells; and,
- The Company is currently awaiting finalization of the royalty implementation
regulations. The Alberta government is currently reviewing certain possible
"unintended consequences" of NRF and the Company expects further clarification
from the government in the near future. Notwithstanding, Orleans expects that
its 2009 and thereafter Alberta Crown royalty payments will increase as a result
of the proposed royalty changes.
It should be noted that the actual effect of the Alberta Crown royalty rate
changes on Orleans will be determined subsequent to January 1, 2009, based on,
among other things, the actual legislation to be enacted, well production rates
and drilling depths, prevailing commodity prices, foreign exchange rates, and
the Company's commodity composition of its production profile.
Application of Critical Accounting Policies and Estimates
The preparation of the Company's financial statements in accordance with
Canadian GAAP requires Orleans' management to make estimates, assumptions and
judgments that affect the reported amounts of assets, liabilities, revenue and
expenses. The basis for these estimates is historical experience and various
other assumptions that the Company believes to be reasonable. Actual results
could differ from these estimates under different assumptions and conditions.
The following assessment of significant accounting polices is not meant to be
exhaustive or all-inclusive. The Company might realize different results from
the application of new accounting standards put forth, from time to time, by
various rule-making bodies.
Full-Cost Accounting
The Company follows the full cost method of accounting for its crude oil and
natural gas operations, whereby all costs related to the exploration for and
development of oil and gas reserves are capitalized and depleted and depreciated
using the unit-of-production method based upon the gross proved petroleum and
natural gas reserves as determined by an independent qualified reserve
engineering firm. In determining costs subject to depletion, the Company
includes estimated future costs to be incurred in developing proved reserves and
excludes salvage values and the costs of unproved properties. The costs of
acquiring and evaluating unproved properties are excluded from costs subject to
depletion until it is determined whether or not proved reserves are attributable
to the properties or until impairment occurs.
In applying the full cost accounting method, a ceiling test is performed to
ensure that the capitalized costs are recoverable in the future. Oil and gas
assets are evaluated in each reporting period to determine that the carrying
amount in a cost centre is recoverable and does not exceed the fair value of the
properties in the cost centre. The carrying amounts are assessed to be
recoverable when the sum of the undiscounted cash flows expected from the
production of proved reserves, the lower of cost and market of unproved
properties and the cost of major development projects exceeds the carrying
amount of the cost centre. When the carrying amount is not assessed to be
recoverable, an impairment loss is recognized to the extent that the carrying
amount of the cost centre exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves, the lower of cost and
market of unproved properties and the cost of major development projects of the
cost centre. The cash flows are estimated using expected future product prices
and costs and are discounted using a risk-free interest rate. The calculation of
undiscounted cash flows in the ceiling test can be significantly impacted by
fluctuations in any of these estimates.
Asset Retirement Obligation
The asset retirement obligation is estimated based on existing laws, contracts
or other policies. The fair value of the asset retirement requires an estimate
of the future costs to abandon and reclaim wells, pipelines and facilities
discounted to its present value using the Company's credit adjusted risk-free
interest rate. The liability is adjusted each reporting period to reflect the
passage of time, with the accretion charged to earnings. Revisions to the
estimated timing of cash flows or to the original undiscounted cost could also
result in an increase or decrease to the obligation. By their nature, these
estimates are subject to measurement uncertainty and the impact on the financial
statements could be material.
Income Tax Accounting
The determination of the Company's income and other tax liabilities requires
interpretation of complex laws and regulations often involving multiple
jurisdictions. All tax filings are subject to audit and potential reassessment
after the lapse of considerable time. Accordingly, any income tax liability or
asset, as well as any income tax recoveries or reductions, may differ from that
estimated and recorded by the Company's management.
Purchase Price Allocation
Business acquisitions are accounted for by the purchase method of accounting.
Under this method, the purchase price is allocated to the assets acquired and
the liabilities assumed based on the fair value at the time of acquisition. The
excess purchase price over the fair value of identifiable assets and liabilities
acquired is goodwill. The determination of fair value often requires management
to make assumptions and estimates about future events. The assumptions and
estimates with respect to determining the fair value of property, plant and
equipment acquired generally require the most judgment and include estimates of
reserves acquired, future commodity prices and discount rates. Future net
earnings can be affected as a result of changes in future depletion and
depreciation, asset impairment or goodwill impairment.
Accounting for Stock Options
The Company recognizes compensation expense on options granted pursuant to its
stock option plan. Compensation expense is based on the theoretical fair value
of each option at its grant date, the estimation f which requires management to
make assumptions about the future volatility of the Company's stock price,
future interest rates and the timing of optionee's decisions to exercise the
options. The effects of a change in one or more of these variables could result
in a materially different fair value.
For further details on the Company's accounting policies, refer to Note 2 of the
Notes to the financial statements for the year ended December 31, 2007
The Company's financial statements for the year ended December 31, 2007 are
enclosed at the end of this news release.
Orleans Energy Ltd. is a Calgary, Alberta-based emerging crude oil and natural
gas company, with common shares trading on the TSX Venture Exchange under the
symbol "OEX". Orleans is a team of dedicated, experienced professionals focused
on the creation of shareholder value via acquisition and development of crude
oil and natural gas assets in Alberta.
Certain information regarding the Company contained herein may constitute
forward-looking statements within the meaning of applicable securities laws.
Forward-looking statements may include estimates, plans, anticipations,
expectations, intentions, opinions, forecasts, projections, guidance or other
similar statements that are not statements of fact. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to be
correct. These statements are subject to certain risks and uncertainties and may
be based on assumptions that could cause actual results to differ materially
from those anticipated or implied in the forward-looking statements. The
Company's forward-looking statements are expressly qualified in their entirety
by this cautionary statement.
In this news release, reserves and production data are commonly stated in
barrels of oil equivalent ("boe") using a six to one conversion ratio when
converting thousands of cubic feet of natural gas ("mcf") to barrels of oil
("bbl") and a one to one conversion ratio for natural gas liquids ("NGLs" or
"ngls"). Such conversion may be misleading, particularly if used in isolation. A
boe conversion ratio of 6 mcf: 1 bbl is based on energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Balance Sheets
----------------------------------------------------------------------------
December 31, December 31,
2007 2006
-------------- --------------
ASSETS
Current Assets
Cash and cash equivalents $ 65,564 $ 273,165
Accounts receivable 9,038,271 11,072,319
Prepaid expenses and deposits 984,200 749,873
-------------- --------------
10,088,035 12,095,357
Property, plant and equipment (Note 6) 193,662,669 176,229,557
-------------- --------------
$ 203,750,704 $ 188,324,914
-------------- --------------
-------------- --------------
LIABILITIES
Current Liabilities
Accounts payable and accrued liabilities $ 14,139,553 $ 16,539,909
Commodity risk management (Note 15b) 432,470 -
Bank loan (Note 8) 44,136,979 38,781,291
-------------- --------------
58,709,002 55,321,200
Asset retirement obligations (Note 9) 5,454,294 5,023,743
Future income tax liability (Note 13) 3,708,329 2,197,469
-------------- --------------
67,871,625 62,542,412
-------------- --------------
SHAREHOLDERS' EQUITY
Share capital (Note 10) 137,732,354 122,736,373
Contributed surplus (Note 11c) 2,813,682 1,502,963
Retained earnings (deficit) (4,666,957) 1,543,166
-------------- --------------
135,879,079 125,782,502
-------------- --------------
$ 203,750,704 $ 188,324,914
-------------- --------------
-------------- --------------
Description of Business and Significant Accounting Policies (Notes 1 & 2)
Commitments and Contingencies (Note 16)
Subsequent Events (Notes 15b and 19)
On behalf of the Board of Directors:
Barry Olson, Director
Doug Baker, Director
The accompanying notes to the financial statements are an integral part of
these statements.
----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Statements of Operations and Comprehensive Loss
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------
Revenue
Petroleum and natural gas sales $ 47,850,855 $ 32,102,989
Royalties (9,261,378) (5,724,333)
-------------- --------------
38,589,477 26,378,656
Realized gain on commodity contracts
(Note 15b) 1,290,098 344,232
Unrealized loss on commodity contracts
(Note 3, 15b) (432,470) -
-------------- --------------
39,447,105 26,722,888
-------------- --------------
Expenses
Operating 12,576,372 6,315,676
Transportation 1,097,650 567,579
General and administrative (Note 11) 2,920,843 1,945,261
Interest 2,654,962 1,230,922
Depletion, depreciation and accretion 29,287,615 16,985,754
Goodwill impairment (Note 7) - 16,619,991
-------------- --------------
48,537,442 43,665,183
-------------- --------------
Loss before taxes (9,090,337) (16,942,295)
Future income taxes (reduction) (Note 13) (2,880,214) 895,271
-------------- --------------
Net loss (6,210,123) (17,837,566)
Changes in cash flow hedges, net of tax
(Note 3) (425,405) -
-------------- --------------
Comprehensive loss $ (6,635,528) $ (17,837,566)
-------------- --------------
-------------- --------------
Net loss per share (Note 12)
Basic $ (0.18) $ (0.73)
-------------- --------------
-------------- --------------
Diluted $ (0.18) $ (0.73)
-------------- --------------
-------------- --------------
The accompanying notes to the financial statements are an integral part of
these statements.
----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Statements of Retained Earnings (Deficit)
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------
Retained earnings, beginning of year $ 1,543,166 $ 19,380,732
Net loss (6,210,123) (17,837,566)
-------------- --------------
Retained earnings (deficit), end of year $ (4,666,957) $ 1,543,166
-------------- --------------
-------------- --------------
----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Statements of Accumulated Other Comprehensive Income ("AOCI")
----------------------------------------------------------------------------
(audited)
Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------
AOCI, beginning of year $ - $ -
Impact of new cash flow accounting standards
on January 1, 2007 (net of tax of $180,498)
(Note 3) 425,405 -
Reclassification to earnings of net gains on
commodity contracts (net of tax of $180,498) (425,405) -
-------------- --------------
AOCI, end of year $ - $ -
-------------- --------------
-------------- --------------
The accompanying notes to the financial statements are an integral part of
these statements.
----------------------------------------------------------------------------
ORLEANS ENERGY LTD.
Statements of Cash Flows
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2007 2006
-------------- --------------
Cash provided from (used in):
Operating activities
Net loss $ (6,210,123) $ (17,837,566)
Items not affecting cash:
Depletion, depreciation and accretion 29,287,615 16,985,754
Stock-based compensation (Note 11) 729,399 555,486
Unrealized loss on commodity contracts
(Note 15b) 432,470 -
Future income taxes (reduction) (2,880,214) 895,271
Goodwill impairment (Note 7) - 16,619,991
Asset retirement obligations expenditures (33,368) -
-------------- --------------
Funds generated from operations 21,325,779 17,218,936
Change in non-cash working capital (Note 14) 913,241 2,926,942
-------------- --------------
22,239,020 20,145,878
-------------- --------------
Financing activities
Increase in bank loan 5,355,688 14,416,735
Exercise of stock options 98,170 202,432
Proceeds from share issues, net issue costs 18,965,601 50,013,510
-------------- --------------
24,419,459 64,632,677
-------------- --------------
Investing activities
Corporate acquisitions (Note 5) - (39,517,224)
Property, plant and equipment additions (46,642,127) (48,185,416)
Property dispositions 1,289,924 -
Change in non-cash working capital (Note 14) (1,513,877) 3,197,250
-------------- --------------
(46,866,080) (84,505,390)
-------------- --------------
Increase (decrease) in cash and cash
equivalents (207,601) 273,165
Cash and cash equivalents, beginning of year 273,165 -
-------------- --------------
Cash and cash equivalents, end of year $ 65,564 $ 273,165
-------------- --------------
-------------- --------------
Supplemental Cash Flow Information (Note 14)
The accompanying notes to the financial statements are an integral part of
these statements.
ORLEANS ENERGY LTD.
Notes to the Annual Financial Statements
Years ended December 31, 2007 and 2006
1. Description of Business
Orleans Energy Ltd. (the "Company" or "Orleans") is actively engaged in the
exploration for, and development and production of, natural gas, natural gas
liquids and crude oil in the Western Canadian Sedimentary Basin. Orleans is
incorporated under the laws of Alberta and its common shares are traded on the
TSX Venture Exchange under the trading symbol "OEX".
2. Significant Accounting Policies
a) Principles of consolidation and basis of presentation
The financial statements have been prepared by the Company's Management in
accordance with Canadian generally accepted accounting principles ("GAAP"). The
financial statements include the accounts of the Company and any wholly-owned
subsidiaries. A portion of the Company's exploration, development and production
activities are conducted jointly with others and accordingly the financial
statements reflect only the Company's proportionate working interest share in
such activities.
On April 1, 2007, the Company completed an amalgamation with its wholly-owned
subsidiaries, Morpheus Energy Corporation, Orleans Oil and Gas Ltd. and Orleans
Petroleum Ltd. Effective April 1, 2007, these subsidiary entities ceased to
exist as separate legal entities and the Company as the amalgamated entity,
assumed all operational and contractual obligations of the subsidiary companies
from April 1, 2007 onwards.
b) Measurement uncertainty
Amounts recorded for depletion, depreciation and accretion, the provision for
asset retirement obligations and the ceiling test calculation are based upon
estimates of proved petroleum and natural gas reserves, production rates,
commodity prices, future costs and other relevant assumptions. By their nature,
these estimates are subject to measurement uncertainty, and the impact of
changes in such estimates on the financial statements of future periods could be
material. The Company's reserve estimates are evaluated annually by an
independent qualified reserve engineering firm pursuant to the parameters and
guidelines stipulated under National Instrument 51-101 - Standards of Disclosure
for Oil and Gas Activities.
c) Petroleum and natural gas operations
i) Capitalized costs
The Company follows the full cost method of accounting for its petroleum and
natural gas operations. Under this method all costs related to the exploration
for and development of petroleum and natural gas reserves are capitalized. Such
capitalized costs may include lease acquisition costs, geological and
geophysical expenses, costs of drilling both productive and non-productive
wells, gathering and production facilities, lease rentals on non-producing
properties, interest on debt directly related to certain acquisitions, and
certain other overhead expenditures directly related to exploration and
development activities. Proceeds from the sale of properties are applied against
capitalized costs, without any gain or loss being realized, unless such sale
would significantly alter the rate of depletion and depreciation by 20 percent
or more.
ii) Depletion and depreciation
Capitalized costs under the full cost accounting method are depleted and
depreciated using the unit-of-production method based upon the gross proved
petroleum and natural gas reserves (before royalties) as determined by the
Company's independent qualified reserves engineering firm. In determining costs
subject to depletion, the Company includes estimated future costs to be incurred
in developing proved reserves and excludes salvage values and the costs of
unproved properties. The costs of acquiring and evaluating unproved properties
are excluded from costs subject to depletion until it is determined whether or
not proved reserves are attributable to the properties or until impairment
occurs. For depletion and depreciation purposes, relative volumes of petroleum
and natural gas production and reserves are converted at the energy equivalent
conversion rate of six (6) thousand cubic feet of natural gas to one (1) barrel
of crude oil. Depreciation on office furniture and other equipment is provided
for over its useful lives using the declining balance method at a rate of 20
percent.
iii) Ceiling test
Oil and gas assets are evaluated in each reporting period in order to determine
that the carrying amount in a cost centre is recoverable and does not exceed the
fair value of the properties in the cost centre. The carrying amounts are
assessed to be recoverable when the sum of the undiscounted cash flows expected
from the production of proved reserves, the lower of cost and market of unproved
properties and the cost of major development projects exceeds the carrying
amount of the cost centre. When the carrying amount is not assessed to be
recoverable, an impairment loss is recognized to the extent that the carrying
amount of the cost centre exceeds the sum of the discounted cash flows expected
from the production of both proved and probable reserves, the lower of cost and
market of unproved properties and the cost of major development projects of the
cost centre. The cash flows are estimated using expected future commodity prices
and costs with such cash flows discounted using a risk-free interest rate.
d) Asset retirement obligations ("ARO")
The Company recognizes the fair value of its asset retirement obligations
associated with the retirement of tangible long-lived assets as a long-term
liability in the period in which it is incurred, with a corresponding increase
to the carrying amount of the related asset. The costs capitalized to the
related assets are amortized to earnings in a manner consistent with the
depreciation, depletion and amortization of the underlying asset. The
obligations to be recognized are statutory, contractual or legal in nature. The
liability amount is increased each reporting period due to the passage of time
and the amount of accretion is charged to earnings in the respective period.
Revisions to the original estimated undiscounted cost or obligation would also
result in an increase or decrease to the asset retirement obligation.
e) Flow-through shares
The Company may finance a portion of its exploration and development activities
through the issuance of flow-through common shares. Under the terms of the
flow-through share agreements, the resource expenditure deductions for income
tax purposes are renounced to subscribers in accordance with the appropriate
income tax legislation. A future tax liability is recorded and share capital is
reduced by the estimated tax benefits transferred to the flow-through common
share subscribers at the time when the qualifying expenditures are renounced to
such subscribers.
f) Per share amounts
Basic per share amounts are computed using the weighted average number of common
shares outstanding during the reporting period. Diluted per share amounts are
calculated using the treasury stock method, which assumes that any proceeds from
the exercise of stock options in addition to the unrecognized amount of
stock-based compensation expense are used to purchase common shares of the
Company at the average market price during the reporting period.
g) Income taxes
The Company follows the liability method of accounting for income taxes. Future
income taxes are calculated based on temporary differences arising from the
difference between the tax basis of an asset or liability and its carrying value
on the balance sheet using tax rates anticipated to apply in the periods when
the temporary differences are expected to reverse. The effect on future taxes
for a change in tax rates is recognized in income in the period that includes
the enactment date. Future income tax assets are recognized to the extent that
realization of such assets is more likely than not.
h) Revenue recognition
Revenue associated with the sale of petroleum and natural gas production owned
by the Company is recognized when ownership title passes from the Company to its
customers and delivery has taken place.
i) Stock-based compensation plan
The Company has a stock-based compensation plan as described in Note 11. The
fair value of stock options is charged to earnings over the vesting period with
a corresponding increase in contributed surplus. The fair value of options
granted is estimated at the date of the grant using the Black-Scholes evaluation
model. Upon the exercise of the stock option, consideration paid by the option
holder together with the amount previously recognized in contributed surplus, is
credited to share capital.
j) Derivative financial instruments
The Company may use derivative financial or hedging instruments to manage its
exposure to market risks relating to commodity prices, foreign currency exchange
rates, interest rates and power costs. The Company does not utilize derivative
financial instruments for speculative purposes. The Company's commodity price
risk management contracts are derivatives and accounted for as held-for-trading
financial instruments and are recorded at fair value.
k) Cash and cash equivalents
Cash and cash equivalents may consist of cash-on-hand with chartered or
commercial banks and investments in bankers' acceptances or guaranteed notes
with an original maturity of less than three months.
l) Goodwill
The Company records goodwill when the purchase price of an acquired business
exceeds the fair value of the net identifiable assets and liabilities acquired.
Goodwill is not amortized and is tested for impairment annually or more
frequently if events or changes in circumstances indicate that the asset might
be impaired. The impairment test is carried out in two steps. In the first step,
the carrying amount of the segment is compared to its fair value. When the fair
value of the segment exceeds its carrying amount, goodwill is considered not to
be impaired and the second step of the impairment test is unnecessary. The
second step is carried out when the carrying amount of the Company's goodwill
exceeds its fair value, in which case the implied fair value of the Company's
goodwill is compared with its carrying amount to measure the amount of the
impairment loss, if any. The implied fair value of goodwill is determined in the
same manner as the value of the goodwill is determined in a business combination
using the fair value of the Company as if it were the purchase price. When the
carrying amount of the Company's goodwill exceeds the implied fair value of the
goodwill, an impairment loss is recognized in an amount equal to the excess.
3. Changes in Accounting Policies
Effective January 1, 2007, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") handbook section 1530 "Comprehensive Income",
section 3251 "Equity", section 3855 "Financial Instruments - Recognition and
Measurement", section 3861 "Financial Instruments - Disclosure and
Presentation", and section 3865 "Hedges". These standards result in changes in
the accounting for financial instruments and hedges as well as introduce
comprehensive income as a separate component of shareholders' equity. The
Company has adopted these standards prospectively and the comparative financial
statements have not been restated. Except for the adjustments described below,
the adoption of these standards had no material impact on the Company's net
earnings or cash flows. At January 1, 2007, the following adjustments were made
to the balance sheet to adopt the aforementioned new standards:
----------------------------------------------------------------------------
January 1, 2007
-----------------
Commodity risk management asset $ 605,903
Future income taxes (180,498)
Accumulated other comprehensive income (425,405)
----------------------------------------------------------------------------
The $425 thousand of net derivative gains in accumulated other comprehensive
income at January 1, 2007 was reclassified to earnings in 2007 over the
remaining life of the related commodity contracts. From that date forward, the
changes in fair value of such derivatives will be recognized in net earnings
when incurred.
Comprehensive Income (section 1530)
Comprehensive income is comprised of net earnings or loss and other
comprehensive income ("OCI"). OCI represents the change in equity for a period
that arises from unrealized gains and losses on available-for-sale investment
securities and changes in the fair market value of derivative instruments
designated as cash flow hedges. The standard requires a new statement of
comprehensive income, which is comprised of net earnings and other comprehensive
income. The Company has combined this new statement with the statement of
operations.
Equity (section 3251)
This section establishes the standards for presentation of equity and changes in
equity during the period. It requires separate presentation of changes in equity
for the period arising from net income, OCI, contributed surplus, retained
earnings, share capital and reserves. Accumulated OCI would be included in the
balance sheet as a separate component of shareholders' equity.
Financial Instruments - Recognition and Measurement (section 3855)
Section 3855 establishes standards for the recognition and measurement of
financial instruments, which is comprised of financial assets, financial
liabilities, derivatives and non-financial derivatives. All financial
instruments must be classified into one of these five categories: (i)
held-for-trading; (ii) held-to-maturity instruments; (iii) loans and
receivables; (iv) available-for-sale financial assets; and, (v) other financial
liabilities. The new standard requires all financial instruments within its
scope, including all derivatives, to be recognized on the balance sheet
initially at fair market value. Subsequent measurement of all financial assets
and liabilities except those held-for-trading and available-for-sale are
measured at amortized cost determined using the effective interest rate method.
Held-for-trading financial assets are measured at fair value with changes in
fair value recognized in earnings. Available-for-sale financial assets are
measured at fair value with changes in fair value recognized in comprehensive
income until the investment is derecognized or impaired at which time the
amounts would be recorded in earnings.
The Company's cash and cash equivalents are designated as "held-for-trading" and
are measured at carrying value, which approximates fair value due to the
short-term nature of these instruments. The Company's accounts receivable are
designated as "loans and receivables", and are measured at carrying value, which
approximates fair value due to the short-term nature of these instruments. The
Company's accounts payable and accrued liabilities and bank debt are designated
as "other financial liabilities". The Company's commodity risk management
contracts are accounted for as "held-for-trading" and are recorded at fair
value.
Derivatives (section 3855)
A derivative is a financial instrument whose value changes in response to a
specified variable, requires little or no net investment and it is settled at a
future date. A non-financial derivative is a contract that can be settled net in
cash or through another financial instrument. Currently, the Company's commodity
price risk management contracts are derivatives and accounted for as
held-for-trading financial instruments and are recorded at fair value.
An embedded derivative is a derivative that is part of a non-derivative contract
and not directly related to that contract. Under Section 3855, embedded
derivatives must be accounted for as a separate financial instrument. On
adoption, the Company elected to recognize, as separate assets and liabilities,
only for those embedded derivatives in hybrid instruments issued, acquired or
substantively modified after January 1, 2003. The Company did not identify any
material embedded derivatives, which required separate recognition and
measurement.
Hedge Accounting (section 3865)
Section 3865 establishes standards for when and how hedge accounting may be
applied. Hedge accounting continues to be optional and the Company may not
designate the hedging instrument as a hedge for accounting purposes. To qualify
for hedge accounting, the hedging relationship between the hedged item and
hedging instrument must be designated and formally documented at the inception
of the contract. The documentation includes the risk management policy, the risk
management objectives, the hedging relationships between the hedged items and
the hedging items and the methods for testing the effectiveness of the hedge
(i.e. whether or not the hedging relationship is effective in offsetting the
changes associated with the hedged risk). Effectiveness must be tested on an
ongoing basis throughout the life of the hedging relationship. For cash flow
hedges that have been terminated or cease to be effective, prospective gains or
losses on the derivative are recognized in earnings. Any gain or loss that has
been included in accumulated other comprehensive income at the time the hedge is
discontinued continues to be deferred in accumulated other comprehensive income
until the original hedged transaction is recognized in earnings. If the
likelihood of the original hedged transaction occurring is no longer probable,
the entire gain or loss in accumulated other comprehensive income related to
this transaction is immediately reclassified to earnings.
In conjunction with the adoption of these new standards, the Company elected not
to use hedge accounting for its crude oil and natural gas derivative contracts
under its risk management program. Prior to January 1, 2007, the Company applied
hedge accounting to its commodity price risk management contracts. On January 1,
2007 the Company discontinued hedge accounting for all existing hedge
instruments. The Company has chosen not to designate any of its current
commodity contracts as hedges for the purposes of this section and has
classified them as held-for-trading and recorded the fair value of these
instruments on the balance sheet. The fair value of the commodity contracts is
recognized at each reporting period with the change in fair value being
classified as an unrealized gain or loss on the statement of operations. The
impact in fair value is disclosed in Note 15b.
4. New Accounting Pronouncements
Two new accounting standards were issued by the CICA, section 3862 "Financial
Instruments - Disclosures", and section 3863 "Financial Instruments -
Presentation". These sections will replace section 3861 "Financial Instruments -
Disclosure and Presentation" once adopted. The objective of section 3862 is to
provide users with information to evaluate the significance of the financial
instruments on the entity's financial position and performance, the nature and
extent of risks arising from financial instruments, and how the entity manages
those risks. The provisions of section 3863 deal with the classification of
financial instruments, related interest, dividends, losses and gains, and the
circumstances in which financial assets and financial liabilities are offset.
These new sections are effective for the Company beginning January 1, 2008.
In December 2006, the Canadian Accounting Standards Board ("AcSB") issued
section 1535, "Capital Disclosures", requiring disclosure of information about
an entity's capital and the objectives, policies, and processes for managing
capital. The standard is effective for annual periods beginning on or after
October 1, 2007 and will require additional disclosure at that time.
In February 2008, the AcSB issued section 3064, "Goodwill and Intangible
Assets", and amended section 1000, "Financial Statement Concepts" clarifying the
criteria for the recognition of assets, intangible assets and internally
developed intangible assets. Items that no longer meet the definition of an
asset are no longer recognized with assets. The standard is effective for annual
years beginning on or after October 1, 2008 and early adoption is permitted. The
Company is presently evaluating the impact these sections will have on its
results of operations and/or financial position.
In January 2006, the AcSB adopted a strategic plan for the direction of
accounting standards in Canada. Accounting standards for public companies in
Canada are expected to converge with the International Financial Reporting
Standards (IFRS) by 2011. IFRS will replace Canadian GAAP with the official
'change-over' to IFRS to occur for interim and annual financial statements
relating to fiscal years beginning on or after January 1, 2011. The Company
continues to monitor and assess the impact of these convergence efforts.
5. Corporate Acquisitions
Mercury Energy Corporation
On June 2, 2006 the Company acquired all the issued and outstanding shares of
Mercury Energy Corporation ("Mercury"), a private company involved in the
exploration and production of crude oil and natural gas in Central Alberta for
total consideration of approximately $19.5 million. This business combination
has been accounted for using the purchase method and the results of operations
have been included in the financial statements from the date of acquisition. The
allocation of the purchase price and consideration paid is as follows:
----------------------------------------------------------------------------
Consideration:
Issue of 1,623,719 common shares of Orleans (valued at
$5.90/share) $ 9,579,942
Cash 9,835,115
Transaction costs 111,285
----------------------------------------------------------------------------
Total consideration $ 19,526,342
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Assets Acquired (allocated at estimated fair values):
Property, plant and equipment $ 23,690,297
Current assets 1,289,872
Current liabilities (3,792,356)
Asset retirement obligations (525,631)
Future income tax liability (1,135,840)
----------------------------------------------------------------------------
Total net assets acquired $ 19,526,342
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Morpheus Energy Corporation
On June 6, 2006 the Company acquired 99.32% of the issued and outstanding shares
of Morpheus Energy Corporation ("Morpheus"), a private company involved in the
exploration and production of natural gas and natural gas liquids in West
Central Alberta. Orleans acquired the remaining 0.67% on July 4, 2006 pursuant
to the compulsory business acquisition provisions of the Business Corporations
Act (Alberta). The total consideration paid by Orleans to acquire all of the
issued and outstanding shares of Morpheus was approximately $72.9 million. This
business combination has been accounted for using the purchase method and the
results of operations have been included in the financial statements from the
date of acquisition. The allocation of the purchase price and consideration paid
is as follows:
----------------------------------------------------------------------------
Consideration:
Issue of 7,351,727 common shares of Orleans (valued at
$5.90/share) $ 43,375,189
Cash 29,202,548
Transaction costs 368,276
----------------------------------------------------------------------------
Total consideration $ 72,946,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Assets Acquired (allocated at estimated fair values):
Property, plant and equipment $ 86,535,276
Current assets 6,422,172
Current liabilities (22,264,644)
Goodwill 16,619,991
Asset retirement obligations (1,275,664)
Future income tax liability (13,091,118)
----------------------------------------------------------------------------
Total net assets acquired $ 72,946,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Property, Plant and Equipment
----------------------------------------------------------------------------
December 31, 2007 December 31, 2006
-------------------------------------
Petroleum and natural gas properties $ 245,355,653 $ 199,171,180
Accumulated depletion (51,851,778) (23,060,662)
-------------------------------------
193,503,875 176,110,518
-------------------------------------
Office equipment and other 230,327 158,769
Accumulated depreciation (71,533) (39,730)
-------------------------------------
158,794 119,039
----------------------------------------------------------------------------
Property, plant and equipment $ 193,662,669 $ 176,229,557
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the year ended December 31, 2007, certain general and administrative
overhead expenses of $1.86 million (December 31, 2006: $1.34 million) directly
related to exploration and development activities were capitalized. Included in
this amount is capitalized stock-based compensation of $905 thousand (December
31, 2006: $720 thousand), with such amount including the future income tax
liability associated with the capitalized stock-based compensation of $266
thousand (December 31, 2006: $219 thousand).
At December 31, 2007, property, plant and equipment included $10.29 million
(December 31, 2006: $13.23 million) relating to unproved properties, which have
been excluded from the depletion calculation. Future development costs related
to proved non-producing reserves of $20.08 million (December 31, 2006: $22.28
million) have been included in the depletion calculation.
The Company performed a ceiling test calculation as at December 31, 2007 to
assess the recoverable value of property, plant and equipment. The oil and gas
future prices are based on the December 31, 2007 price forecast of the Company's
independent qualified reserve engineering evaluators with certain information
outlined in the following table. Based on the ceiling test calculation results,
no write-down of the Company's carrying value of property, plant and equipment
was required as at December 31, 2007.
----------------------------------------------------------------------------
Company's AECO-C Company's
WTI Edmonton Price Price Price Exchange
Price - Oil Price - Oil - Oil - Gas - Gas Rate
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ($US/$Cdn)
----------------------------------------------------------------------------
2008 89.61 88.17 83.60 6.51 6.75 1.000
2009 86.01 84.54 80.13 7.22 7.51 1.000
2010 84.65 83.16 79.00 7.69 8.03 1.000
2011 82.77 81.26 76.98 7.70 8.03 1.000
2012 82.26 80.73 75.92 7.61 7.96 1.000
2013 82.81 81.25 76.10 7.78 8.15 1.000
2014 84.46 82.88 77.58 7.96 8.35 1.000
2015 86.15 84.55 79.24 8.14 8.55 1.000
2016 87.87 86.25 81.08 8.32 8.75 1.000
2017 89.63 87.98 82.87 8.51 8.96 1.000
Escalated rate of 1.00
2.0% thereafter (1) thereafter(1)
----------------------------------------------------------------------------
(1) Percentage change represents the change in each year after 2017 to the
end of the reserve life.
7. Goodwill
The Company reviewed the valuation of goodwill as of December 31, 2006. Based
upon this review, an impairment charge of goodwill of $16.62 million was
recorded as a non-cash charge to income as of December 31, 2006. This goodwill
resulted from the acquisition of Morpheus.
8. Bank Facility
As at December 31, 2007, the Company had a demand revolving credit facility of
$60 million with a Canadian chartered bank (the "Credit Facility"). The Credit
Facility provides that advances may be made by way of direct advances, banker's
acceptances, or standby letters of credit/guarantees. Direct advances bear
interest at the bank's prime lending rate plus an applicable margin for Canadian
dollar advances and at the bank's U.S. base rate plus an applicable margin for
U.S. dollar advances. The applicable margin charged by the bank is dependent on
the Company's debt-to-trailing cash flow ratio. The banker's acceptances bear
interest at the applicable banker's acceptance rate plus a stamping fee, based
on the Company's debt-to-trailing cash flow ratio. The Credit Facility is
secured by a fixed and floating charge debenture on the assets of the Company.
The borrowing base is subject to semi-annual review by the bank. At December 31,
2007, the Company had $44.14 million of bank debt outstanding (December 31,
2006: $38.78 million).
9. Asset Retirement Obligations
Orleans' asset retirement obligations are based on the Company's net ownership
in wells and facilities and Management's estimate of the timing and expected
future costs associated with site reclamation, facilities dismantlement and the
plugging and abandonment of wells.
At December 31, 2007, the estimated present value of the total amount required
to settle the Company's asset retirement obligations was $5.45 million (December
31, 2006: $5.02 million), based on a total undiscounted future liability amount
of $13.09 million (inflation adjusted) (December 31, 2006: $12.48 million).
These obligations are to be settled based on the economic lives of the
underlying assets, which is currently projected to be up to 48 years. The
Company used a credit-adjusted risk free rate of 10 percent and an inflation
rate of 1.5 percent to calculate the present value of the asset retirement
obligations (December 31, 2006: credit-adjusted risk free rate of 10 percent and
an inflation rate of 1.5 percent).
----------------------------------------------------------------------------
December 31, 2007 December 31, 2006
--------------------------------------
Asset retirement obligations -
beginning $ 5,023,743 $ 2,484,234
Liabilities incurred on development
activities 185,255 385,186
Liabilities acquired through corporate
acquisitions - 1,801,295
Liabilities released on property
dispositions (186,031) -
Liabilities settled (33,368) -
Accretion expense 464,695 353,028
----------------------------------------------------------------------------
Asset retirement obligations - ending $ 5,454,294 $ 5,023,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the year ended December 31, 2007, the Company recognized depletion
expense related to its asset retirement cost of $495 thousand (December 31,
2006: $410 thousand).
10. Share Capital
a) Authorized - Unlimited number of voting common shares.
The Company has neither declared nor paid any dividends on its common shares.
The Company intends to retain its earnings to finance growth and expand its
operations and does not anticipate paying any dividends on its common shares in
the foreseeable future.
b) Issued and outstanding
----------------------------------------------------------------------------
Total Number
of Common Shares Amount
----------------------------------------------------------------------------
Balance, December 31, 2005 15,099,047 $ 19,937,717
Issued on flow-though private
placements 3,300,000 20,147,500
Issued on equity private placement 5,600,000 33,040,000
Combined issue costs, net tax effect of
$1,036,737 - (2,137,253)
Issue on acquisition of Mercury
(Note 5) 1,623,719 9,579,942
Issued on acquisition of Morpheus
(Note 5) 7,351,727 43,375,189
Exercise of stock options 174,166 321,381
Flow through shares tax adjustment - (1,528,103)
----------------------------------------------------------------------------
Balance, December 31, 2006 33,148,659 $ 122,736,373
Issued on flow-through financing 1,500,000 8,175,000
Issued on equity financing 2,800,000 12,040,000
Combined issue costs, net tax effect of
$379,373 - (870,026)
Exercise of stock options 122,713 156,000
Flow through shares tax adjustment - (4,504,993)
----------------------------------------------------------------------------
Balance, December 31, 2007 37,571,372 $ 137,732,354
----------------------------------------------------------------------------
----------------------------------------------------------------------------
c) Flow-through shares
On April 27, 2006, the Company issued 670,000 flow-through common shares on a
private placement basis at a price of $7.50 per share for gross proceeds of
$5.025 million. Under the terms of the flow-through share agreement, the Company
was committed to spend 100 percent of the gross proceeds on qualifying
exploration expenditures prior to December 31, 2007. As at December 31, 2006,
the Company had fully incurred and discharged these expenditures commitments
associated with this private placement. The future income tax effect and
reduction to share capital was recorded in the year ended December 31, 2006, the
period in which the Company filed the renouncement documents with the tax
authorities.
On November 14, 2006, the Company issued 2,630,000 flow-through common shares on
a private placement basis at a price of $5.75 per share for gross proceeds of
$15.123 million. Under the terms of the flow-through share agreement, the
Company was committed to spend 100 percent of the gross proceeds on qualifying
exploration expenditures prior to December 31, 2007. As at December 31, 2007,
the Company had fully incurred and discharged these expenditures commitments
associated with this private placement. The future income tax effect and
reduction to share capital was recorded in the first quarter of 2007, the period
in which the Company filed the renouncement documents with the tax authorities.
On July 12, 2007, the Company issued 1,500,000 flow-through common shares on a
"bought-deal" basis at a price of $5.45 per share for gross proceeds of $8.175
million. Under the terms of the flow-through share agreement, the Company is
committed to spend 100 percent of the gross proceeds on qualifying exploration
expenditures prior to December 31, 2008. As at December 31, 2007, the Company
had incurred approximately $2.37 million of qualifying expenditures associated
with this equity issue with the balance of $5.805 million to be incurred by
December 31, 2008.
11. Stock-Based Compensation
a) Outstanding stock options
The Company has a stock option plan for the benefit of its directors, officers,
employees and certain consultants. The Company has granted options to purchase
common shares, whereby each option permits the holder to purchase one share of
the Company at the stated exercise price. The options vest over a two-to-three
year term and are exercisable on a cumulative basis over five years. At December
31, 2007, 3,118,026 options with a weighted average exercise price of $3.30 were
outstanding and exercisable at various dates through to December 3, 2012.
Subsequent to December 31, 2007, the Company granted stock options to its
officers, directors and employees in an aggregate quantity of 639,000 options
with an exercise price of $2.21 per stock option. The stock options were granted
pursuant to the Company's stock option plan and will vest over a three-year
period with a five-year expiry.
The following table summarizes outstanding stock options as at December 31,
2007:
----------------------------------------------------------------------------
Weighted Avg.
Number Exercise Price
------------------------------
Outstanding - December 31, 2005 1,509,905 $ 1.77
Granted 1,533,000 4.95
Exercised (174,166) 1.16
Forfeited (170,000) 5.30
----------------------------------------------------------------------------
Outstanding - December 31, 2006 2,698,739 $ 3.40
Granted 917,500 3.33
Exercised (122,713) 0.80
Forfeited (375,500) 4.91
----------------------------------------------------------------------------
Outstanding -- December 31, 2007 3,118,026 $ 3.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options exercisable -- December 31, 2007 1,146,100 $ 2.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Exercise price range for options outstanding as at December 31, 2007:
----------------------------------------------------------------------------
Outstanding Options Exercisable Options
----------------------------------------------------------------------------
Weighted Weighted Avg. Weighted
Price Range Number Avg. Price Remaining Life Number Avg. Price
----------------------------------------------------------------------------
$ 0.80 - 1.00 655,271 $ 0.80 2.07 years 449,708 $ 0.80
$ 2.30 - 3.74 1,570,255 $ 3.24 3.56 years 402,392 $ 3.16
$ 3.90 - 5.87 892,500 $ 5.23 3.49 years 294,000 $ 5.33
-------------- --------- - -------- ------------------ --------- - --------
Total 3,118,026 $ 3.30 3.23 years 1,146,100 $ 2.79
-------------- --------- - -------- ------------------ --------- - --------
-------------- --------- - -------- ------------------ --------- - --------
The Company recorded stock-based compensation expense of $729,399 for the year
ended December 31, 2007 (December 31, 2006: $555,486), which was charged to
general and administration expense and presented as such on the Company's
statement of operations.
The Company determined the fair value of stock options granted during the fiscal
period ended December 31, 2007 using the modified Black-Scholes evaluation stock
option pricing model under the following assumptions:
----------------------------------------------------------------------------
December 31, 2007 December 31, 2006
------------------------------------
Weighted-average fair value ($/option) 1.62 2.40
Risk-free interest rate (%) 4.13 4.06
Estimated hold period prior to exercise
(years) 5 5
Volatility in the price of Orleans
shares (%) 49.7 50.4
Dividend yield (%) Nil Nil
----------------------------------------------------------------------------
c) Contributed surplus
----------------------------------------------------------------------------
Contributed surplus - December 31, 2005 $ 565,359
Stock-based compensation, before capitalization 1,056,553
Exercise of stock options (118,949)
----------------------------------------------------------------------------
Contributed surplus - December 31, 2006 1,502,963
Stock-based compensation, before capitalization 1,368,549
Exercise of stock options (57,830)
----------------------------------------------------------------------------
Contributed surplus - December 31, 2007 $ 2,813,682
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. Per Share Amounts
In the calculation of diluted per share amounts, options under the Company's
stock option plan are assumed to have been converted or exercised on the later
of the beginning of the year and the date granted. The treasury stock method is
used to determine the dilutive effect of stock options. The treasury stock
method assumes that proceeds received from the exercise of in-the-money stock
options in addition to the unrecognised stock-based compensation expense are
used to repurchase common shares at the average market price.
For the year ended December 31, 2007, 2.04 million stock options (December 31,
2006: 1.41 million) were excluded in calculating the weighted average number of
diluted common shares outstanding, as they were determined to be anti-dilutive.
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, 2007 December 31, 2006
---------------------------------------
Weighted average shares outstanding:
Basic 35,252,993 24,362,187
Diluted 35,772,226 25,136,494
----------------------------------------------------------------------------
13. Income Taxes
a) Reconciliation of effective tax rate to the Canadian federal tax rate
The provision for income taxes reflects an effective tax rate that differs from
the results which would be obtained by applying the expected statutory income
tax rate to earnings before taxes. The difference results from the following:
December 31, 2007 December 31, 2006
----------------------------------------
Loss before income taxes $ (9,090,337) $ (16,942,295)
Combined federal and provincial
statutory tax rate 32.12% 34.50%
Calculated expected income taxes
(reduction) (2,919,816) (5,845,092)
Increase (decrease) resulting from
the tax effect of:
Non-deductible crown charges (net
ARTC) - 203,734
Federal resource allowance - (240,532)
Non-deductible stock-based
compensation 234,283 191,643
Goodwill Impairment - 5,733,897
Other 95,179 17,306
Statutory rate change (1) (289,860) 834,315
----------------------------------------------------------------------------
Income taxes (reduction) $ (2,880,214) $ 895,271
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Reflects Canadian Federal income tax rate reductions and other
legislative changes enacted or substantively enacted in the second and
fourth quarters of 2007.
b) Future income tax:
The components of the Company's future income tax is as follows:
December 31, 2007 December 31, 2006
----------------------------------------
Future income tax:
Capital assets $ (8,987,391) $ (11,058,776)
Non-capital losses 2,453,652 8,433,831
Share issue costs and other 1,374,568 1,374,553
Asset retirement obligations 1,450,842 1,507,123
Partnership deferral - (2,454,200)
----------------------------------------------------------------------------
Net future income tax liability $ (3,708,329) $ (2,197,469)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's non-capital losses of $8.32 million expire at various times
from 2008 to 2026.
14. Supplemental Cash Flow Information
a) Increase (decrease) in non-cash working capital items
December 31, 2007 December 31, 2006
----------------------------------------
Change in non-cash working
capital:
Accounts receivable and other
current assets $ 1,799,720 $ (411,218)
Accounts payable and accrued
liabilities (2,400,356) 6,535,410
----------------------------------------------------------------------------
$ (600,636) $ 6,124,192
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Changes in non-cash working
capital related to:
Operating activities $ 913,241 $ 2,926,942
Investing activities (1,513,877) 3,197,250
----------------------------------------------------------------------------
$ (600,636) $ 6,124,192
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Other cash flow information
December 31, 2007 December 31, 2006
----------------------------------------
Interest paid (net of interest
income) $ 2,456,920 $ 1,159,363
15. Financial Instruments and Risk Management
a) Balance sheet financial instruments:
The Company's exposure under its financial instruments is limited to financial
assets and liabilities, all of which are included in the financial statements.
The Company's financial instruments recognized in the balance sheet consist of
cash and cash equivalents, accounts receivable, derivative contracts and current
liabilities. Unless otherwise noted, carrying values reflect the current fair
value of the Company's financial instruments. The estimated fair values of
recognized financial instruments have been determined based on the Company's
assessment of available market information and appropriate methodologies, or
through comparisons to similar instruments.
b) Commodity price risk management contracts
The prices the Company receives for its crude oil and natural gas production may
have a significant impact on its revenues and cash provided from operating
activities. Any significant price decline in commodity prices would adversely
affect the amount of funds available for capital reinvestment purposes. As such,
the Company utilizes a risk management program to partially mitigate that risk
and to ensure adequate funds are available for planned capital activities and
other commitments. From time-to-time, the Company may employ financial
instruments to manage fluctuations in oil and gas market prices. The Company
does not utilize derivative financial instruments for speculative purposes. The
Company has elected to not designate its commodity price risk management
contracts as accounting hedges under Canadian GAAP.
As described in Note 3, the Company recognizes the fair value of its commodity
contracts on the balance sheet each reporting period with the change in fair
value being recognized as an unrealized gain or loss on the statement of
operations. On January 1, 2007 the fair value of the commodity contracts was an
asset of $605,903 and resulted in an increase to accumulated other comprehensive
income and the future tax liability of $425,405 and $180,498, respectively. The
entire amount recognized in accumulated other comprehensive income has been
fully amortized over the term of the contracts through other comprehensive
income with a corresponding unrealized gain on financial instruments on the
statement of operations. As a result, $425,405 net of tax, was charged during
the year to other comprehensive income with a corresponding unrealized gain on
financial instruments of $605,903 and a charge to future income tax liability of
$180,498. As at December 31, 2007, the fair value of the financial commodity
contracts was a liability of approximately $433 thousand, resulting in an
unrealized loss for the year of $432,470 net of the amortization of the
accumulated other comprehensive income.
The following table reconciles the Company's unrealized gain (loss) on
commodity contracts:
Year Ended Year Ended
December 31, 2007 December 31, 2006
----------------------------------------
Change in fair value of commodity
contracts $ (1,038,373) $ -
Amortization of accumulated other
comprehensive income 605,903 -
----------------------------------------------------------------------------
Unrealized loss on commodity
contracts $ (432,470) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table outlines the commodity agreements that were outstanding
as at December 31, 2007, in addition to commodity contracts entered into
subsequent to December 31, 2007.
Daily
notional
Commodity Contract Date Type Term Volume Index Price
----------------------------------------------------------------------------
Jan '08 -
Crude Oil Oct. 15, 2007 Swap Jun '08 200 bbls W.T.I. US$ 81.56/bbl
Jul '08 - US$ 90.00 -
Crude Oil (1) Mar. 3, 2008 Collar Dec '08 100 bbls W.T.I. 116.25/bbl
Nov '07 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.545 /GJ
Jan '08 -
NatGas Oct. 18, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.71 /GJ
Jan '08 -
NatGas Oct. 31, 2007 Swap Mar '08 1,000 GJs AECO-C C$ 6.67 /GJ
Apr '08 -
NatGas Dec. 18, 2007 Swap Dec '08 2,000 GJs AECO-C C$ 6.55 /GJ
Apr '08 -
NatGas (1) Jan. 2, 2008 Swap Dec '08 2,000 GJs AECO-C C$ 6.81 /GJ
Apr '08 -
NatGas (1) Jan. 4, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.61 /GJ
Apr '08 -
NatGas (1) Jan. 7, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 6.72 /GJ
Apr '08 -
NatGas (1) Jan. 10, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.01 /GJ
Nov '08 - C$ 7.00 -
NatGas (1) Feb. 13, 2008 Collar Mar '09 2,000 GJs AECO-C 9.70 /GJ
Apr '08 -
NatGas (1) Feb 14, 2008 Swap Oct '08 1,000 GJs AECO-C C$ 7.52 /GJ
----------------------------------------------------------------------------
(1) These contracts were entered into subsequent to December 31, 2007.
c) Credit risk
A substantial portion of the Company's accounts receivable are with customers in
the petroleum and natural gas industry and are subject to normal industry credit
risks which may expose the Company to certain losses in the event that
counterparties or customers default on payment or contract settlement. The
carrying value of accounts receivable reflects Management's assessment of the
credit risk associated with these customers.
d) Interest rate risk
Financial instruments, which subject the Company to interest rate risk, are
limited to the bank loan. The Company's current Credit Facility agreement with
its banker calculates interest based on the bank's prime lending rate plus an
applicable margin (see Note 8).
16. Commitments and Contingencies
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments, operating leases relating to
head office space and natural gas field equipment, and drilling rig contractual
obligations. The following table summarizes the Company's commitments as at
December 31, 2007:
2008 2009 2010 2011 2012 Thereafter
----------- -------- -------- -------- -------- ----------
Bank debt $44,136,979 $ - $ - $ - $ - $ -
Head office
operating lease 649,458 649,458 649,458 680,013 680,013 906,683
Field equipment
operating leases 254,225 20,203 - - - -
Drilling rig
commitment 370,685 - - - - -
Total $45,411,347 $669,661 $649,458 $680,013 $680,013 $ 906,683
----------------------------------------------------------
----------------------------------------------------------
In 1996, a lawsuit was filed against the Company's predecessor, Orleans
Resources Inc. and the "procureur general du Quebec". Since the Company is of
the opinion that this lawsuit against Orleans Resources Inc. is unwarranted and
will have no material adverse effect on the Company's financial position or on
the results of operations, no provision has been recorded in this respect. If
the Company has to pay any amount in this affair, this amount will be paid by
issuing reserved common shares, at a price of $6.00 per share. The maximum
number of common shares that would have to be issued would be 666,118 shares,
representing the full amount of the lawsuit or $3,996,713 in value.
Additionally, refer to Note 10 c), which outlines the Company's requirements to
incur flow-through share eligible Canadian Exploration Expenditures, as defined
in the Income tax Act (Canada).
17. Related Party Transactions
During the year ended December 31, 2007, the Company paid a total of $133
thousand (December 31, 2006: $326 thousand) for legal services provided by a
firm in which a current director and the Company's corporate secretary are
partners of. These payments were made in the normal course of business
operations and are measured at the exchange amount which is established and
agreed to by the related parties based on standard rates, time spent and costs
incurred.
18. Comparative Balances
Certain of the comparative balances have been reclassified to conform to the
current period's presentation.
19. Subsequent Event
On March 13, 2008, the Company closed a bought-deal equity financing (the
"Financing"). Pursuant to the terms of the Financing, the Company issued, on an
underwritten basis, 7.0 million common shares at a price of $3.60 per share for
total gross proceeds of $25.2 million. The Company granted the underwriters an
over allotment option to purchase up to an additional 1,050,000 common shares at
a price of $3.60 per common share for a period of 30 days from the closing date
for additional gross proceeds of $3.78 million.
1 Year Orleans Energy Ltd Com Npv Chart |
1 Month Orleans Energy Ltd Com Npv Chart |
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions
