(TSX: AVN.UN, NYSE: AAV) CALGARY, March 18 /PRNewswire-FirstCall/
-- Advantage Energy Income Fund ("Advantage" or the "Fund") is
pleased to announce the financial and operating results for the
year ended December 31, 2008. Funds from Operations Increased 33%
and Annual Production Increased 8% - Strong average natural gas and
crude oil prices and excellent drilling results resulted in a 33%
increase in funds from operations to $361.1 million for 2008
compared to $271.1 for 2007. Funds from operations on a per unit
basis increased 16% to $2.57 per Trust Unit compared to $2.22 per
Trust Unit for the year ended December 31, 2007. - Average 2008
daily production increased 8% to 32,273 boe/d compared to 29,962
boe/d for 2007. This was achieved despite 1,100 boe/d (73% natural
gas) being curtailed since August 2008 as a result of a third party
facility outage at the Lookout Butte property. Fourth quarter
production of 31,529 boe/d was impacted by severe cold weather in
December and the continuing outage at Lookout Butte. - Natural gas
production for 2008 increased 5% to 122.9 mmcf/d, compared to 117.0
mmcf/d for 2007. Crude oil and natural gas liquids production
increased 13% to 11,793 bbls/d compared to 10,462 bbls/d in 2007. -
Operating costs for 2008 increased to $13.89 per boe due to higher
cost of service and supplies driven by the increasing commodity
price environment for most of the year. Fourth quarter 2008
operating costs was $14.71 per boe due to lower production, the
impact of higher third party processing costs, increased property
taxes and additional costs due to the severe cold weather that
created unplanned equipment repairs. - The Fund declared
distributions totaling $1.40 per Trust Unit with a 2008 payout
ratio of just 54% as compared to 79% for 2007. Since inception, the
Fund has distributed $1.1 billion or $17.66 per Trust Unit. Highly
Efficient Reserve Additions from a Very Successful 2008 Drilling
Program - Overall, the Fund replaced 290% of annual production with
the vast majority of reserve additions realized through our
successful 2008 drilling program at Glacier, Alberta where the Fund
commenced a significant development drilling program on our Montney
natural gas resource play (refer to Advantage's year-end reserves
press release dated March 5, 2009). - Proven and probable reserves
increased 15% to 174.8 mmboe from 152.2 mmboe at year end 2007.
Proven reserves increased 7% to 102.3 mmboe from 95.6 mmboe at year
end 2007. The Fund's proven plus probable reserve life index
increased 26% to 15.2 years compared to 12.1 years at the end of
2007. Natural gas reserves calculate to a reserve life index of
15.9 years, and crude oil and natural gas liquids calculate to a
reserve life index of 13.9 years, indicative of a very stable
producing platform with significant upside potential. - In 2008,
all-in Finding, Development and Acquisition ("FD&A") costs were
$7.67 per proven plus probable boe before changes in future
development capital ("FDC") and $16.70 per boe including changes in
FDC. Drill bit reserve additions alone resulted in the replacement
of 285% of annual production at a Finding and Development
("F&D") cost of $7.61 per proven and probable boe before
consideration of changes in FDC and $16.95 per boe including the
change in FDC. - The 2008 capital program totaled $263.2 million of
which $255.6 million was invested in development activities and
$7.6 million was expended on a complimentary acquisition at our
Nevis property. Advantage invested $101 million at Glacier, which
dramatically increased proven and probable reserves. Included in
our 2008 capital expenditures were $20 million of strategic
undeveloped land acquisitions, the majority of which was located at
Glacier. A total of 124 gross (86.8 net) wells were drilled in 2008
at a 99% success rate. The $7.6 million Nevis acquisition resulted
in increasing our working interest in 9 gross sections of land and
provided future drilling locations on an additional 4 gross
sections for Horseshoe Canyon coal bed methane. Glacier Montney
Results Confirms Significant Resource Play Potential - Advantage
invested $101 million at Glacier in 2008 and increased proven and
probable reserves by 29 mmboe and confirmed horizontal well rates
of 2.5 to 7.5 mmcfd (417 to 1,250 boe per day). - The 2008 F&D
cost at Glacier was $3.48 per proven and probable boe before
changes in FDC and $13.14 per boe including changes in FDC. -
Montney reserves are assigned to only 32 of our 89 sections. The
reserve assignment is based on an average well density of 2.4 wells
per section of land although we currently have regulatory approval
to drill up to 8 wells per section consisting of 4 wells in the
Upper and 4 wells in the Lower Montney zones. Adjacent operators
are currently evaluating 16 wells per section which may lead to
significant future reserve additions. Further delineation drilling
is required to evaluate the undeveloped land potential in the
remaining 57 sections. Based on results to date, 440 locations have
been confirmed in our extensive Montney land block. The drilling
inventory at Glacier could exceed 800 locations depending on the
density of horizontal wells that will ultimately be drilled per
section of land. - Advantage estimates that fully developing the
Montney resource potential at Glacier will require additional
capital expenditures in excess of $2.5 billion over the life of the
project which, if properly deployed, could result in significant
reserve and production growth. Advantage will utilize a disciplined
financial approach to development in order to yield significant
long term value growth for Unitholders. Hedging Update -
Advantage's hedging program includes 56% of our net natural gas
production hedged for 2009 at an average price of $8.09 Cdn per mcf
and 48% hedged for 2010 at an average price of $7.46 per mcf. Crude
oil hedges include 46% of our net crude oil production hedged at an
average floor price of $69.38 Cdn per bbl and 26% hedged for 2010
at an average price of $67.83 Cdn per bbl. Details on our hedging
program are available on our website. Looking Forward - The Board
of Directors approved a 2009 budget with capital expenditures
between $100 and $135 million with approximately 46% directed to
further developing our Montney natural gas reserves and production
at Glacier. As a result of a much lower commodity price environment
driven by global economic concerns, Advantage will be very
disciplined and proactive to undertake actions as required to
balance our capital and cash flows as we prepare for a challenging
2009. However, our capital expenditure priority will be to ensure
the funding of further development in our Montney resource play at
Glacier where the Fund sees significant reserves and production
growth potential. - On March 18, 2009, Advantage announced that our
Board of Directors had approved conversion to a growth oriented
corporation and a strategic asset disposition program to increase
financial flexibility. - The corporate conversion will be subject
to two-thirds Unitholder approval as well as customary court and
regulatory approvals, anticipated to be completed on or about June
30, 2009. The conversion will enable Advantage to pursue a business
plan that is focused on the development and growth of the Montney
natural gas resource play at Glacier. The conversion will have the
added benefit of removing the uncertainty surrounding the upcoming
changes in Canadian tax law whereby the government will begin
imposing taxes on income trusts on January 1, 2011. - The Fund has
retained Tristone Capital Inc. to assist with the disposition of
properties producing up to 11,300 boe/d of light oil and natural
gas properties located in Northeast British Columbia, West Central
Alberta and Northern Alberta. The net proceeds from these sales or
other oil and natural gas property sales will initially be used to
reduce outstanding bank debt to improve Advantage's financial
flexibility. Advantage may also draw down its credit facilities in
the future to redeem certain of the Fund's convertible debentures.
Proposals are anticipated by mid May 2009 and the selected assets
will be available in four distinct packages varying in size from
approximately 1,600 to 5,400 boe/d of production. - As another step
to increase Advantage's financial flexibility and to focus on
development and growth at Glacier, Advantage will discontinue
payment of cash distributions with the final cash distribution paid
on March 16, 2009 to unitholders of record as of February 27, 2009.
Going forward, Advantage does not anticipate paying distributions
or dividends in the immediate future and will instead, direct cash
flow to capital expenditures and debt repayment. Financial and
Operating Highlights Year ended December 31, 2008 2007 2006 2005
2004 Financial ($000, except per Trust Unit, per boe or as
otherwise indicated) Revenue before royalties(1) 741,962 557,358
419,727 376,572 241,481 per Trust Unit(2) 5.32 4.66 5.18 6.65 5.89
per boe 62.82 50.97 48.41 51.27 38.92 Funds from operations 361,087
271,143 214,758 211,541 126,478 per Trust Unit(3) 2.57 2.22 2.65
3.72 3.05 per boe 30.58 24.79 24.78 28.80 20.39 Net income (loss)
(20,577) (7,535) 49,814 75,072 24,038 per Trust Unit(2) (0.15)
(0.06) 0.62 1.33 0.59 Distributions declared 196,642 215,194
217,246 177,366 117,655 per Trust Unit(3) 1.40 1.77 2.66 3.12 2.82
Expenditures on property and equipment 255,591 148,725 159,487
103,229 107,893 Working capital deficit(4) 146,397 28,087 42,655
31,612 56,408 Bank indebtedness 587,404 547,426 410,574 252,476
267,054 Convertible debentures (face value) 219,195 224,612 180,730
135,111 148,450 Trust Units outstanding at end of year (000)
142,825 138,269 105,390 57,846 49,675 Basic weighted average Trust
Units (000) 139,483 119,604 80,958 56,593 41,008 Operating Daily
Production Natural gas (mcf/d) 122,878 116,998 94,074 78,561 77,188
Crude oil and NGLs (bbls/d) 11,793 10,462 8,075 7,029 4,084 Total
boe/d at 6:1 32,273 29,962 23,754 20,123 16,949 Average pricing
(including hedging) Natural gas ($/mcf) 8.14 7.21 6.86 7.98 6.08
Crude oil and NGLs ($/bbl) 87.08 65.38 62.44 57.58 46.58 Proved
plus probable reserves Natural gas (bcf) 704.3 546.4 442.7 286.9
296.9 Crude oil & NGLs (mbbls) 57,386 61,131 47,524 36,267
34,316 Total mboe 174,767 152,203 121,317 84,082 83,799 Reserve
life index (years)(5) 15.2 12.1 11.4 12.0 9.9 (1) includes realized
derivative gains and losses (2) based on basic weighted average
Trust Units outstanding (3) based on Trust Units outstanding at
each distribution record date (4) working capital deficit excludes
derivative assets and liabilities (5) based on year end exit
production rates Management's Discussion & Analysis The
following Management's Discussion and Analysis ("MD&A"), dated
as of March 18, 2009, provides a detailed explanation of the
financial and operating results of Advantage Energy Income Fund
("Advantage", the "Fund", "us", "we" or "our") for the quarter and
year ended December 31, 2008 and should be read in conjunction with
the audited consolidated financial statements. The consolidated
financial statements have been prepared in accordance with Canadian
generally accepted accounting principles ("GAAP") and all
references are to Canadian dollars unless otherwise indicated. All
per barrel of oil equivalent ("boe") amounts are stated at a
conversion rate of six thousand cubic feet of natural gas being
equal to one barrel of oil or liquids. Non-GAAP Measures The Fund
discloses several financial measures in the MD&A that do not
have any standardized meaning prescribed under GAAP. These
financial measures include funds from operations, funds from
operations per Trust Unit and cash netbacks. Management believes
that these financial measures are useful supplemental information
to analyze operating performance, leverage and provide an
indication of the results generated by the Fund's principal
business activities prior to the consideration of how those
activities are financed or how the results are taxed. Investors
should be cautioned that these measures should not be construed as
an alternative to net income, cash provided by operating activities
or other measures of financial performance as determined in
accordance with GAAP. Advantage's method of calculating these
measures may differ from other companies, and accordingly, they may
not be comparable to similar measures used by other companies.
Funds from operations, as presented, is based on cash provided by
operating activities before expenditures on asset retirement and
changes in non-cash working capital. Funds from operations per
Trust Unit is based on the number of Trust Units outstanding at
each distribution record date. Cash netbacks are dependent on the
determination of funds from operations and include the primary cash
revenues and expenses on a per boe basis that comprise funds from
operations. Funds from operations reconciled to cash provided by
operating activities is as follows: Three months ended Year ended
December 31 December 31 ($000) 2008 2007 %change 2008 2007 %change
-------------------------------------------------------------------------
Cash provided by operating activities $ 83,754 $ 83,366 0% $374,750
$249,132 50% Expenditures on asset retirement 2,968 2,116 40% 9,259
6,951 33% Changes in non-cash working capital (17,352) (4,963) 250%
(22,922) 15,060 (252)%
-------------------------------------------------------------------------
Funds from operations $ 69,370 $ 80,519 (14)% $361,087 $271,143 33%
-------------------------------------------------------------------------
Forward-Looking Information This MD&A contains certain
forward-looking statements, which are based on our current internal
expectations, estimates, projections, assumptions and beliefs.
These statements relate to future events or our future performance.
All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often,
but not always, identified by the use of words such as "seek",
"anticipate", "plan", "continue", "estimate", "expect", "may",
"will", "project", "predict", "potential", "targeting", "intend",
"could", "might", "should", "believe", "would" and similar or
related expressions. These statements are not guarantees of future
performance. In particular, forward-looking statements included in
this MD&A include, but are not limited to, statements with
respect to average production and projected exit rates; areas of
operations; spending and capital budgets; availability of funds for
our capital program; the size of, and future net revenues from,
reserves; the focus of capital expenditures; expectations regarding
the ability to raise capital and to continually add to reserves
through acquisitions and development; projections of market prices
and costs; the performance characteristics of our properties; our
future operating and financial results; capital expenditure
programs; supply and demand for oil and natural gas; average
royalty rates; and amount of general and administrative expenses.
In addition, statements relating to "reserves" or "resources" are
deemed to be forward-looking statements, as they involve the
implied assessment, based on certain estimates and assumptions,
that the resources and reserves described can be profitably
produced in the future. These forward-looking statements involve
substantial known and unknown risks and uncertainties, many of
which are beyond our control, including the effect of acquisitions;
changes in general economic, market and business conditions;
changes or fluctuations in production levels; unexpected drilling
results, changes in commodity prices, currency exchange rates,
capital expenditures, reserves or reserves estimates and debt
service requirements; changes to legislation and regulations and
how they are interpreted and enforced, changes to investment
eligibility or investment criteria; our ability to comply with
current and future environmental or other laws; our success at
acquisition, exploitation and development of reserves; actions by
governmental or regulatory authorities including increasing taxes,
changes in investment or other regulations; the occurrence of
unexpected events involved in the exploration for, and the
operation and development of, oil and gas properties; competition
from other producers; the lack of availability of qualified
personnel or management; changes in tax laws, royalty regimes and
incentive programs relating to the oil and gas industry and income
trusts; hazards such as fire, explosion, blowouts, cratering, and
spills, each of which could result in substantial damage to wells,
production facilities, other property and the environment or in
personal injury; stock market volatility; and ability to access
sufficient capital from internal and external sources. Many of
these risks and uncertainties are described in Advantage's Annual
Information Form which is available at http://www.sedar.com/ and
http://www.advantageincome.com/. Readers are also referred to risk
factors described in other documents Advantage files with Canadian
securities authorities. With respect to forward-looking statements
contained in this MD&A, Advantage has made assumptions
regarding: current commodity prices and royalty regimes;
availability of skilled labour; timing and amount of capital
expenditures; future exchange rates; the price of oil and natural
gas; the impact of increasing competition; conditions in general
economic and financial markets; availability of drilling and
related equipment; effects of regulation by governmental agencies;
royalty rates and future operating costs. Management has included
the above summary of assumptions and risks related to
forward-looking information provided in this MD&A in order to
provide Unitholders with a more complete perspective on Advantage's
future operations and such information may not be appropriate for
other purposes. Advantage's actual results, performance or
achievement could differ materially from those expressed in, or
implied by, these forward-looking statements and, accordingly, no
assurance can be given that any of the events anticipated by the
forward-looking statements will transpire or occur, or if any of
them do so, what benefits that Advantage will derive there from.
Readers are cautioned that the foregoing lists of factors are not
exhaustive. These forward-looking statements are made as of the
date of this MD&A and Advantage disclaims any intent or
obligation to update publicly any forward-looking statements,
whether as a result of new information, future events or results or
otherwise, other than as required by applicable securities laws.
Corporate Conversion and Asset Disposition On March 18, 2009, we
announced that our Board of Directors had approved conversion to a
growth oriented corporation and a strategic asset disposition
program to increase financial flexibility. The corporate conversion
will be subject to approval by at least two-thirds of the Fund's
Unitholders as well as customary court and regulatory approvals,
anticipated to be completed on or about June 30, 2009. The
conversion will enable Advantage to pursue a business plan that is
focused on the development and growth of the Montney natural gas
resource play at Glacier. The conversion will have the added
benefit of removing the uncertainty surrounding the upcoming
changes in Canadian tax law whereby the government will begin
imposing taxes on income trusts on January 1, 2011. The Fund has
retained Tristone Capital Inc. to assist with the disposition of
properties producing up to 11,300 boe/d of light oil and natural
gas properties located in Northeast British Columbia, West Central
Alberta and Northern Alberta. The net proceeds from these sales or
other oil and natural gas property sales will initially be used to
reduce outstanding bank debt to improve Advantage's financial
flexibility. Advantage may also draw down its credit facilities in
the future to redeem certain of the Fund's convertible debentures.
Proposals are anticipated by mid May 2009 and the selected assets
will be available in four distinct packages varying in size from
approximately 1,600 to 5,400 boe/d of production. As another step
to increase Advantage's financial flexibility and to focus on
development and growth at Glacier, Advantage will discontinue
payment of cash distributions with the final cash distribution paid
on March 16, 2009 to unitholders of record as of February 27, 2009.
Going forward, Advantage does not anticipate paying distributions
or dividends in the immediate future and will instead direct cash
flow to capital expenditures and debt repayment. Given these
business developments, historical operating and financial
performance may not be indicative of future performance depending
on the magnitude of the asset disposition process and pending
approval of the corporate conversion. Overview Three months ended
Year ended December 31 December 31 2008 2007 %change 2008 2007
%change
-------------------------------------------------------------------------
Cash provided by operating activities ($000) $ 83,754 $ 83,366 -%
$374,750 $249,132 50% Funds from operations ($000) $ 69,370 $
80,519 (14)% $361,087 $271,143 33% per Trust Unit(1) $ 0.49 $ 0.58
(16)% $ 2.57 $ 2.22 16% (1) Based on Trust Units outstanding at
each distribution record date. Cash provided by operating
activities and funds from operations have increased significantly
for the year ended December 31, 2008 as compared to 2007 due to
considerably higher revenue. Our 2008 annual revenue has benefited
from both higher average commodity prices and production. Improved
production is substantially due to the Sound Energy Trust ("Sound")
acquisition, which closed on September 5, 2007, and incremental
production from our 2008 drilling program. The financial and
operating results from the acquired Sound properties are included
in all 2008 figures but are only included in the year ended
December 31, 2007 effective from the closing date. Funds from
operations per Trust Unit has also increased significantly, but not
in the same proportion due to the higher number of Trust Units
outstanding for 2008. Trust Units outstanding has increased due to
Trust Units issued in exchange for the Sound acquisition and our
distribution reinvestment plan that allows Unitholders to purchase
Trust Units in exchange for their regular monthly cash
distributions. Although cash provided by operating activities for
the three months ended December 31, 2008 is comparable with the
same period of 2007, funds from operations for the current quarter
has decreased 14% and funds from operations per Trust Unit has
decreased 16%. These decreases have been due to a slightly lower
average production and a dramatic reduction in crude oil prices.
The fourth quarter of 2008 has seen significant negative economic
developments as a direct result of the global recession, which has
triggered a sharp decline in crude oil prices from lower demand.
This challenging situation has continued into 2009 placing
continued downward pressure on commodity prices. The primary factor
that causes significant variability of Advantage's cash provided by
operating activities, funds from operations, and net income is
commodity prices. Refer to the section "Commodity Prices and
Marketing" for a more detailed discussion of commodity prices and
our price risk management. Distributions Three months ended Year
ended December 31 December 31 2008 2007 %change 2008 2007 %change
-------------------------------------------------------------------------
Distributions declared ($000) $ 45,514 $ 57,875 (21)% $196,642
$215,194 (9)% per Trust Unit(1) $ 0.32 $ 0.42 (24)% $ 1.40 $ 1.77
(21)% (1) Based on Trust Units outstanding at each distribution
record date. Total distributions declared decreased 21% for the
three months and 9% for the year ended December 31, 2008 when
compared to the same periods in 2007. Total distributions are lower
as a result of decreases in the distribution declared per Trust
Unit during these periods. Lower total distributions were partially
offset by additional distributions due to increased Trust Units
outstanding. As commodity prices have weakened, we have reduced the
distribution level to more appropriately reflect the current price
environment. Distributions per Trust Unit were $0.32 for the three
months and $1.40 for the year ended December 31, 2008, representing
decreases of 24% and 21% from the same periods in 2007. For the
majority of 2008, we paid a monthly distribution of $0.12 per Trust
Unit and reduced the distribution to $0.08 per Trust Unit effective
for the December distribution paid in January. We further reduced
the monthly distribution to $0.04 per Trust Unit for the February
distribution paid in March. On March 18, 2009, we discontinued all
future distributions, consistent with our strategy to reduce debt
and convert to a growth oriented corporation that will focus
capital on the Glacier Montney natural gas resource play.
Distribution Taxability For Canadian and U.S. holders of Advantage
Trust Units, the distributions paid for 2008 were 100% taxable. All
Unitholders of the Fund are encouraged to consult their tax
advisors as to the proper treatment of Advantage distributions for
income tax purposes. Revenue Three months ended Year ended December
31 December 31 ($000) 2008 2007 %change 2008 2007 %change
-------------------------------------------------------------------------
Natural gas excluding hedging $ 79,402 $ 73,662 8% $382,701
$286,777 33% Realized hedging gains (losses) 5,051 8,762 (42)%
(16,580) 20,933 (179)%
-------------------------------------------------------------------------
Natural gas including hedging $ 84,453 $ 82,424 2% $366,121
$307,710 19%
-------------------------------------------------------------------------
Crude oil and NGLs excluding hedging $ 56,330 $ 87,079 (35)%
$386,700 $251,987 53% Realized hedging gains (losses) 8,422 (3,552)
(337)% (10,859) (2,339) 364%
-------------------------------------------------------------------------
Crude oil and NGLs including hedging $ 64,752 $ 83,527 (22)%
$375,841 $249,648 51%
-------------------------------------------------------------------------
Total revenue $149,205 $165,951 (10)% $741,962 $557,358 33%
-------------------------------------------------------------------------
Revenues were significantly higher for the year ended December 31,
2008 due to the full year of additional production from the Sound
acquisition and stronger average commodity prices. During this
period, the higher revenue was partially offset by realized hedging
losses that also resulted from the higher average commodity price
environment. Unfortunately, the fourth quarter of 2008 experienced
a significant decrease in crude oil and NGL prices, due to the
global recession, and our revenues were substantially impacted. As
we had hedged a significant portion of our production, we also
realized hedging gains during the quarter that partially offset the
reduced revenues. The Fund enters derivative contracts whereby
realized hedging gains and losses partially offset commodity price
fluctuations, which can positively or negatively impact revenues.
Production Three months ended Year ended December 31 December 31
2008 2007 %change 2008 2007 %change
-------------------------------------------------------------------------
Natural gas (mcf/d) 120,694 128,556 (6)% 122,878 116,998 5% Crude
oil (bbls/d) 9,443 10,410 (9)% 9,543 8,090 18% NGLs (bbls/d) 1,970
2,485 (21)% 2,250 2,372 (5)%
-------------------------------------------------------------------------
Total (boe/d) 31,529 34,321 (8)% 32,273 29,962 8%
-------------------------------------------------------------------------
Natural gas (%) 64% 63% 63% 65% Crude oil (%) 30% 30% 30% 27% NGLs
(%) 6% 7% 7% 8% The Fund's total daily production averaged 32,273
boe/d for the year ended December 31, 2008, an increase of 8%
realized primarily due to the Sound acquisition, which closed
September 5, 2007, and drilling results from our successful 2008
capital program. Production for the three months ended December 31,
2008 was 31,529 boe/d, a decrease of 3% from the 32,418 boe/d
realized in the third quarter of 2008. Production of 1,100 boe/d at
our Lookout Butte property in Southern Alberta remained shut-in
during the fourth quarter by an extended third party facility
outage that began in August 2008 at the Waterton gas plant where a
significant modification project is underway. Original estimates
provided by the third party indicated a potential outage of
approximately 55 to 75 days. However, subsequent information now
indicates that the gas plant may be down until April 1, 2009.
Additionally, in the fourth quarter of 2008 we also experienced
freezing conditions from cold weather that reduced production in
December. On March 18, 2009, we announced the intention to dispose
of properties producing up to 11,300 boe/d of light oil and natural
gas properties located in Northeast British Columbia, West Central
Alberta and Northern Alberta. The net proceeds from these sales or
other oil and natural gas property sales will initially be used to
reduce outstanding bank debt to improve Advantage's financial
flexibility. Proposals are anticipated by mid May 2009 and the
selected assets will be available in four distinct packages varying
in size from approximately 1,600 to 5,400 boe/d of production.
Assuming asset sales of approximately 10,000 to 11,300 boe/d of
production are completed, we expect production of approximately
20,000 to 22,000 boe/d from a focused asset base (60% natural gas,
40% oil and natural gas liquids). Commodity Prices and Marketing
Natural Gas Three months ended Year ended December 31 December 31
($/mcf) 2008 2007 %change 2008 2007 %change
-------------------------------------------------------------------------
Realized natural gas prices Excluding hedging $ 7.15 $ 6.23 15% $
8.51 $ 6.72 27% Including hedging $ 7.61 $ 6.97 9% $ 8.14 $ 7.21
13% AECO monthly index $ 6.79 $ 6.00 13% $ 8.13 $ 6.61 23% Realized
natural gas prices, excluding hedging, were considerably higher for
the three months and year ended December 31, 2008 compared to 2007
but have decreased approximately 17% from the third quarter of
2008. The 2007/2008 winter season in North America caused inventory
levels, that had been high prior to winter, to decline to
approximately the five-year average. In addition, reduced liquefied
natural gas imports into the US and the slowdown in natural gas
drilling in Western Canada provided upward price support in the
first half of this year. However, during the third and fourth
quarters of 2008, there has been significant softening of natural
gas prices from higher US domestic natural gas production, mild
weather conditions and forecasts, and the ongoing global recession
that has impacted demand. These factors have resulted in much
higher inventory levels that continue to place considerable
downward pressure on natural gas prices. Unfortunately, these
conditions have also continued well into 2009 with AECO gas
presently trading at approximately $3.80/GJ. Although we continue
to believe in the longer-term pricing fundamentals for natural gas,
we are concerned about the current pricing and economic environment
that has the potential to extend for a considerable period of time.
The global recession could delay the recovery of natural gas
pricing longer than anticipated. While the current pricing
situation is quite weak, some of the factors that we believe will
support stronger future natural gas prices include: (i)
significantly less natural gas drilling in Canada projected for
2009, which will reduce productivity to offset declines, (ii) signs
of reduced natural gas drilling in the US, (iii) the increasing
focus on resource style natural gas wells, which have high initial
declines, and which are becoming a larger proportion of the total
natural gas supply based in Canada and the US, and (iv) the demand
for natural gas for the Canadian oil sands projects. Crude Oil and
NGLs Three months ended Year ended December 31 December 31 ($/bbl)
2008 2007 %change 2008 2007 %change
-------------------------------------------------------------------------
Realized crude oil prices Excluding hedging $ 57.46 $ 74.19 (23)% $
92.81 $ 67.71 37% Including hedging $ 67.16 $ 70.48 (5)% $ 89.71 $
66.92 34% Realized NGLs prices Excluding hedging $ 35.38 $ 70.09
(50)% $ 75.93 $ 60.12 26% Realized crude oil and NGL prices
Excluding hedging $ 53.65 $ 73.40 (27)% $ 89.59 $ 65.99 36%
Including hedging $ 61.67 $ 70.40 (12)% $ 87.08 $ 65.38 33% WTI
($US/bbl) $ 58.75 $ 90.63 (35)% $ 99.65 $ 72.37 38% $US/$Canadian
exchange rate $ 0.83 $ 1.02 (19)% $ 0.94 $ 0.94 -% Advantage's
realized crude oil prices are based on the benchmark pricing of
West Texas Intermediate Crude ("WTI") adjusted for quality,
transportation costs and $US/$Canadian exchange rates. Advantage's
realized crude oil price may not change to the same extent as WTI,
due to changes in the $US/$Canadian exchange rate, and changes in
Canadian crude oil differentials relative to WTI. The price of WTI
fluctuates based on worldwide supply and demand fundamentals. There
has been significant price volatility experienced over the last
several years whereby WTI reached historic high levels in 2008,
producing a 36% increase in our average realized crude oil and NGL
price, excluding hedging, for the year. However, as we have seen
remarkable crude oil price increases, we have also seen a similarly
dramatic reduction in the later half of 2008 whereby WTI decreased
35% for the three months ended December 31, 2008 as compared to the
same period of 2007 and decreased 50% from the third quarter of
2008. This decline has had a significant negative impact on our
realized crude oil and NGL price, excluding hedging, that has
dropped 27% for the fourth quarter of 2008 as compared to same
quarter of 2007 and decreased 50% from the third quarter of 2008.
WTI has continued to decline in 2009 to approximately US$47/bbl,
the result of demand destruction brought on by the current global
recession. The impact from this decrease in WTI will be somewhat
mitigated for Advantage due to the strengthening US dollar relative
to the Canadian dollar. As with natural gas, it seems evident that
the global recession will likely prolong depressed crude oil prices
through the coming year. Regardless of this significant decrease,
we believe that the longer-term pricing fundamentals for crude oil
remain strong with many factors affecting the continued strength
including (i) supply management and supply restrictions by the OPEC
cartel, (ii) frequent civil unrest in various crude oil producing
countries and regions, (iii) strong relative worldwide demand in
developing countries, particularly in China and India, and (iv)
production declines and reduced drilling due to the lower price
environment. Commodity Price Risk The Fund's operational results
and financial condition will be dependent on the prices received
for oil and natural gas production. Oil and natural gas prices have
fluctuated widely during recent years and are determined by
economic and, in the case of oil prices, political factors. Supply
and demand factors, including weather and general economic
conditions as well as conditions in other oil and natural gas
regions, impact prices. Any movement in oil and natural gas prices
could have an effect on the Fund's financial condition and
performance. As current and future practice, Advantage has
established a financial hedging strategy and may manage the risk
associated with changes in commodity prices by entering into
derivatives. Although these commodity price risk management
activities could expose Advantage to losses or gains, entering
derivative contracts helps us to stabilize cash flows and ensures
that our capital expenditure program is substantially funded by
such cash flows. To the extent that Advantage engages in risk
management activities related to commodity prices, it will be
subject to credit risk associated with counterparties with which it
contracts. Credit risk is mitigated by entering into contracts with
only stable, creditworthy parties and through frequent reviews of
exposures to individual entities. We have been active in entering
new financial contracts to protect future cash flows and currently
the Fund has the following derivatives in place: Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO Fixed price April 2008 to March 2009 14,217
mcf/d Cdn$7.10/mcf Fixed price April 2008 to March 2009 14,217
mcf/d Cdn$7.06/mcf Fixed price November 2008 to March 2009 14,217
mcf/d Cdn$7.77/mcf Fixed price November 2008 to March 2009 4,739
mcf/d Cdn$8.10/mcf Fixed price November 2008 to March 2009 14,217
mcf/d Cdn$9.45/mcf Fixed price April 2009 to December 2009 9,478
mcf/d Cdn$8.66/mcf Fixed price April 2009 to December 2009 9,478
mcf/d Cdn$8.67/mcf Fixed price April 2009 to December 2009 9,478
mcf/d Cdn$8.94/mcf Fixed price April 2009 to March 2010 14,217
mcf/d Cdn$7.59/mcf Fixed price April 2009 to March 2010 14,217
mcf/d Cdn$7.56/mcf Fixed price January 2010 to June 2010 14,217
mcf/d Cdn$8.23/mcf Fixed price January 2010 to December 2010 18,956
mcf/d Cdn$7.29/mcf(1) Fixed price April 2010 to January 2011 18,956
mcf/d Cdn$7.25/mcf(1) Crude oil - WTI Fixed price February 2008 to
January 2009 2,000 bbls/d Cdn$90.93/bbl Collar February 2008 to
January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl Purchase call
Cdn$105.00/bbl Cost Cdn$1.52/bbl Fixed price April 2008 to March
2009 2,500 bbls/d Cdn$97.15/bbl Collar April 2009 to December 2009
2,000 bbls/d Bought put Cdn$62.00/bbl Sold call Cdn$76.00/bbl Fixed
price April 2009 to March 2010 2,000 bbls/d Cdn$62.80/bbl(1) Fixed
price April 2010 to January 2011 2,000 bbls/d Cdn$69.50/bbl(1) (1)
The Fund entered into these hedges after December 31, 2008. The
Fund has fixed the commodity price on anticipated production as
follows: Approximate Production Hedged, Average Average Commodity
Net of Royalties Floor Price Ceiling Price
-------------------------------------------------------------------------
Natural gas - AECO January to March 2009 62% Cdn$7.87/mcf
Cdn$7.87/mcf April to June 2009 53% Cdn$8.17/mcf Cdn$8.17/mcf July
to September 2009 54% Cdn$8.17/mcf Cdn$8.17/mcf October to December
2009 56% Cdn$8.17/mcf Cdn$8.17/mcf
-----------------------------------------------------------------------
Total 2009 56% Cdn$8.09/mcf Cdn$8.09/mcf
-----------------------------------------------------------------------
January to March 2010 62% Cdn$7.64/mcf Cdn$7.64/mcf April to June
2010 53% Cdn$7.53/mcf Cdn$7.53/mcf July to September 2010 38%
Cdn$7.27/mcf Cdn$7.27/mcf October to December 2010 38% Cdn$7.27/mcf
Cdn$7.27/mcf
-----------------------------------------------------------------------
Total 2010 48% Cdn$7.46/mcf Cdn$7.46/mcf
-----------------------------------------------------------------------
January to March 2011 6% Cdn$7.25/mcf Cdn$7.25/mcf
-----------------------------------------------------------------------
Crude Oil - WTI January to March 2009 38% Cdn$95.84/bbl
Cdn$95.84/bbl April to June 2009 48% Cdn$62.40/bbl Cdn$69.40/bbl
July to September 2009 48% Cdn$62.40/bbl Cdn$69.40/bbl October to
December 2009 50% Cdn$62.40/bbl Cdn$69.40/bbl
-----------------------------------------------------------------------
Total 2009 46% Cdn$69.38/bbl Cdn$74.92/bbl
-----------------------------------------------------------------------
January to March 2010 26% Cdn$62.80/bbl Cdn$62.80/bbl April to June
2010 26% Cdn$69.50/bbl Cdn$69.50/bbl July to September 2010 26%
Cdn$69.50/bbl Cdn$69.50/bbl October to December 2010 26%
Cdn$69.50/bbl Cdn$69.50/bbl
-----------------------------------------------------------------------
Total 2010 26% Cdn$67.83/bbl Cdn$67.83/bbl
-----------------------------------------------------------------------
January to March 2011 9% Cdn$69.50/bbl Cdn$69.50/bbl
-----------------------------------------------------------------------
For the year ended December 31, 2008, we recognized in income a
realized derivative loss of $27.4 million on settled derivative
contracts (2007 - $18.6 million realized derivative gain). As at
December 31, 2008, the fair value of derivative contracts remaining
to be settled was an approximate $41.0 million net asset (December
31, 2007 - $2.2 million net asset) resulting in the recognition of
a $38.8 million unrealized derivative gain for the 2008 year (2007
- $11.0 million unrealized derivative loss) due to changes in fair
value since December 31, 2007. The valuation of the derivatives is
the estimated fair value to settle the contracts as at December 31,
2008 and is based on pricing models, estimates, assumptions and
market data available at that time. As such, the unrealized amounts
are not cash and the actual gains or losses realized on eventual
cash settlement can vary materially due to subsequent fluctuations
in commodity prices as compared to the valuation assumptions. These
fair values are extremely sensitive to assumptions regarding
forward commodity prices as demonstrated from our recognized $34.0
million unrealized derivative gain during the fourth quarter of
2008 as commodity prices continued to decrease and the $7.0 million
net derivative asset recognized at September 30, 2008 is now valued
as a $41.0 million net asset. The Fund does not apply hedge
accounting and current accounting standards require changes in the
fair value to be included in the consolidated statement of loss and
comprehensive loss as an unrealized derivative gain or loss with a
corresponding derivative asset and liability recorded on the
balance sheet. Our outstanding derivative contracts will settle
from January 2009 to March 2011 corresponding to when Advantage
will receive revenues from production. Royalties Three months ended
Year ended December 31 December 31 2008 2007 % change 2008 2007 %
change
-------------------------------------------------------------------------
Royalties ($000) $ 23,338 $ 27,099 (14)% $146,349 $ 98,614 48% per
boe $ 8.05 $ 8.58 (6)% $ 12.39 $ 9.02 37% As a percentage of
revenue, excluding hedging 17.2% 16.9% 0.3% 19.0% 18.3% 0.7%
Advantage pays royalties to the owners of mineral rights from which
we have leases. The Fund currently has mineral leases with
provincial governments, individuals and other companies. Royalties
for the year have increased in total due to the increase in revenue
from higher production and commodity prices. However, total
royalties for the fourth quarter have decreased as both production
and prices are lower as compared to the same quarter of 2007.
Royalties as a percentage of revenue, excluding hedging, have
modestly increased as higher prices generally attract a higher
royalty rate. Royalty rates are dependent on prices and individual
well production levels such that average royalty rates will vary as
the nature of our properties change through ongoing development
activities and acquisitions. Our royalty rate for the fourth
quarter of 2008 was slightly lower than expected due to the
recognition of several royalty credits during the period. We expect
the royalty rate to be in the range of 18% to 20% for 2009 given
current commodity prices and the Fund's production levels. The
Alberta Provincial Government implemented a new royalty framework
for conventional oil, natural gas and oil sands effective January
1, 2009. Given the methodology used in the new royalty regime,
royalties and as a result, cash flows will be affected by depths
and productivity of wells. In addition, royalties are price
sensitive with higher royalty levels applying when commodity prices
are higher. Lower rate natural gas wells will see a benefit of
lower royalties while conventional oil will be subject to an
increase in royalties that is again less punitive at lower rates.
Commodity prices and individual well production rates are both key
factors in the calculation. The majority of Advantage's production
in Alberta comes from lower rate wells due to well-established
large, long life properties. In addition, we have a significant
presence in British Columbia and Saskatchewan. Therefore, the
impact may not be significant based on our current production and
the current commodity price environment. Advantage will take the
new royalty regime into consideration in preparing future
development projects. Project economics are evaluated taking into
consideration all relevant factors including the new royalty regime
given the commodity pricing environment anticipated. Those projects
that maximize return to Advantage Unitholders will continue to be
selected for development. On March 3, 2009, the Alberta Government
released a three-part incentive program aimed to stimulate new
economic activity. The first part of the plan includes a one-year
drilling royalty credit of $200 per metre drilled based on a
sliding scale dependant on 2008 corporate production in the
Province of Alberta. The second part of the plan includes a
one-year new well incentive program which offers a maximum five
percent royalty rate for the first year of production from new oil
or gas wells. Lastly, to encourage the clean-up of inactive oil and
gas wells, the province will invest $30 million in a fund committed
to abandoning and reclaiming oil well sites. We are currently
evaluating the program and our initial assessment is that Advantage
will realize financial benefits from the drilling incentive and
reduced royalty rate. Operating Costs Three months ended Year ended
December 31 December 31 2008 2007 % change 2008 2007 % change
-------------------------------------------------------------------------
Operating costs ($000) $ 42,673 $ 39,330 8% $164,091 $127,309 29%
per boe $ 14.71 $ 12.46 18% $ 13.89 $ 11.64 19% Total operating
costs increased 29% for the year ended December 31, 2008 as
compared to 2007 primarily due to increased production from the
Sound acquisition, which closed September 5, 2007, and cost
escalation driven by the strong oil and natural gas environment
during the first half of 2008. Operating costs for the fourth
quarter of 2008 were up just 4% from $41.2 million incurred in the
third quarter of 2008 and 8% higher from the fourth quarter of
2007. Operating costs reflect a general industry increase which has
continued despite recessionary pressures. Operating costs in the
fourth quarter are 6% higher than the $13.82 realized during the
third quarter of 2008. Fourth quarter operating costs per boe were
higher primarily due to lower average quarterly production due
primarily to freezing conditions experienced in December, increased
third party processing fees, and higher property taxes than
expected. We anticipate that operating costs in the latter half of
2009 will decrease as the slower economy will reduce the cost of
services and supplies. We will continue to be opportunistic and
proactive in pursuing optimization initiatives that will improve
our operating cost structure. In 2009, the Fund entered into fixed
price power hedges commencing March 2009 and continuing to December
2009. Under these arrangements, 2.0 MW have been hedged at an
average fixed price of $69.38/MWh. We expect that operating costs
will be in the range of $13.95 to $14.45 per boe for 2009; however,
this will be impacted by the magnitude of our asset disposition
program. General and Administrative Three months ended Year ended
December 31 December 31 2008 2007 % change 2008 2007 % change
-------------------------------------------------------------------------
General and administrative expense ($000) $ 3,198 $ 7,173 (55)% $
22,493 $ 21,449 5% per boe $ 1.10 $ 2.27 (51)% $ 1.90 $ 1.96 (3)%
Employees at December 31 176 172 2% Total general and
administrative ("G&A") expense has decreased 55% for the three
months ended and increased 5% for the year ended December 31, 2008.
The higher total G&A expense for the year has been primarily
due to an increase in average staff levels that have resulted from
the Sound acquisition, general growth of the Fund, and a one-time
payment to terminate an office lease that occurred in the first
quarter of 2008. G&A was lower in the fourth quarter of 2008 as
compared to the same quarter of 2007 due to several large
nonrecurring expenditures that were recognized in the 2007 period.
Current employee compensation includes salary, benefits, a
short-term incentive plan and a long-term incentive plan. The
long-term incentive plan consists of a Restricted Trust Unit Plan
(the "Plan"), as approved by the Unitholders on June 23, 2006. The
purpose of the long-term compensation plan is to retain and attract
employees, to reward and encourage performance, and to focus
employees on operating and financial performance that results in
lasting Unitholder return. The Plan authorizes the Board of
Directors to grant Restricted Trust Units ("RTUs") to directors,
officers, or employees of the Fund. The number of RTUs granted is
based on the Fund's Trust Unit return for a calendar year and
compared to a peer group approved by the Board of Directors. The
Trust Unit return is calculated at the end of the year and is
primarily based on the year-over-year change in the Trust Unit
price plus distributions. If the Trust Unit return for a year is
positive, an RTU grant will be calculated based on the return and
market capitalization. If the Trust Unit return for a year is
negative, but the return is still within the top two-thirds of the
approved peer group performance, the Board of Directors may choose
a discretionary RTU grant. The RTU grants vest one-third
immediately on grant date, with the remaining two-thirds vesting
evenly on the following two yearly anniversary dates. The holders
of RTUs may elect to receive cash upon vesting in lieu of the
number of Trust Units to be issued, subject to consent of the Fund.
Compensation cost related to the Plan is recognized as compensation
expense over the service period beginning at the grant date and
incorporates the Trust Unit grant price, the estimated number of
RTUs to vest, and certain management estimates. The maximum amount
of RTUs granted in any one calendar year is limited to 175% of the
base salaries of those individuals participating in the Plan for
such period. For 2008, although Advantage experienced a negative
return for the year, the approved peer group also experienced
likewise negative returns. As a result, Advantage's 2008 annual
return was within the top two-thirds of the approved peer group and
the Board of Directors granted an RTU at their discretion. The RTU
was deemed to be granted at January 15, 2009 and was valued at $3.8
million to be issued in Trust Units at $5.49 per Trust Unit. No
compensation expense was included in general and administration
expense for the year ended December 31, 2008 as the RTU was granted
after year-end. A total of 171,093 Trust Units were issued to
employees in early 2009 in satisfaction of the first third of the
grant that vested immediately. The remaining two-thirds of the RTU
grant will vest evenly on the following two yearly anniversary
dates. Since implementing the Plan in 2006, the grant thresholds
have not been previously met, and there have been no RTU grants
made during prior years and no related compensation expense has
been recognized. Management Internalization Three months ended Year
ended December 31 December 31 2008 2007 % change 2008 2007 % change
-------------------------------------------------------------------------
Management internalization ($000) $ 916 $ 2,534 (64)% $ 6,964 $
15,708 (56)% per boe $ 0.32 $ 0.80 (60)% $ 0.59 $ 1.44 (59)% In
2006, the Fund and Advantage Investment Management Ltd. (the
"Manager") reached an agreement to internalize the pre-existing
management contract arrangement. As part of the agreement,
Advantage agreed to purchase all of the outstanding shares of the
Manager pursuant to the terms of the Arrangement, thereby
eliminating the management fee and performance incentive effective
April 1, 2006. The Trust Unit consideration issued in exchange for
the outstanding shares of the Manager was placed in escrow for a
3-year period and is being deferred and amortized into income as
management internalization expense over the specific vesting
periods during which employee services are provided. The management
internalization is lower for the three months and year ended
December 31, 2008 as one third vested and was paid in June 2007
with an additional one third vested and paid in June 2008. Interest
on Bank Indebtedness Three months ended Year ended December 31
December 31 2008 2007 % change 2008 2007 % change
-------------------------------------------------------------------------
Interest expense ($000) $ 6,430 $ 7,917 (19)% $ 27,893 $ 24,351 15%
per boe $ 2.22 $ 2.51 (12)% $ 2.36 $ 2.23 6% Average effective
interest rate 4.5% 6.2% (1.7)% 5.0% 5.7% (0.7)% Bank indebtedness
at December 31 ($000) $587,404 $547,426 7% Interest expense in
total and per boe for the full year 2008 has increased modestly as
compared to 2007 primarily due to the additional debt assumed by
the Fund from the Sound acquisition on September 5, 2007. However,
interest expense in total and per boe for the three months ended
December 31, 2008 have decreased as compared to the same period of
2007 as a result of declining interest rates in the fourth quarter.
Bank lending rates have declined significantly in response to rate
reductions enacted by central banks to stimulate the economy. We
monitor the debt level to ensure an optimal mix of financing and
cost of capital that will provide a maximum return to our
Unitholders. Our current credit facilities have been a favorable
financing alternative with an effective interest rate of only 5.0%
for the year ended December 31, 2008. The Fund's interest rates are
primarily based on short term Bankers Acceptance rates plus a
stamping fee. Interest and Accretion on Convertible Debentures
Three months ended Year ended December 31 December 31 2008 2007 %
change 2008 2007 % change
-------------------------------------------------------------------------
Interest on convertible debentures ($000) $ 4,080 $ 4,426 (8)% $
16,627 $ 14,867 12% per boe $ 1.41 $ 1.40 1% $ 1.41 $ 1.36 4%
Accretion on convertible debentures ($000) $ 703 $ 721 (2)% $ 2,855
$ 2,569 11% per boe $ 0.24 $ 0.23 4% $ 0.24 $ 0.23 4% Convertible
debentures maturity value at December 31 ($000) $219,195 $224,612
(2)% Interest and accretion on convertible debentures has increased
for the year ended December 31, 2008 compared to 2007 due to
Advantage assuming Sound's 8.75% and 8.00% convertible debentures
on the acquisition. The increased interest and accretion from the
additional debentures has been partially offset by the maturation
of both the 10% convertible debentures with a face value of $1.4
million on November 1, 2007 and the 9% convertible debentures with
a face value of $5.4 million on August 1, 2008. These debenture
maturities have resulted in lower total interest and accretion for
the three months ended December 31, 2008 as compared to the same
period of 2007. Depletion, Depreciation and Accretion Three months
ended Year ended December 31 December 31 2008 2007 % change 2008
2007 % change
-------------------------------------------------------------------------
Depletion, depreciation and accretion ($000) $ 72,100 $ 78,149 (8)%
$302,104 $272,175 11% per boe $ 24.86 $ 24.75 0% $ 25.58 $ 24.89 3%
Depletion and depreciation of property and equipment is provided on
the "unit-of-production" method based on total proved reserves.
Accretion represents the increase in the asset retirement
obligation liability each reporting period due to the passage of
time. The depletion, depreciation and accretion ("DD&A")
provision has increased in total for the year ended December 31,
2008 compared to the same period of 2007, due to the increase in
production and fixed assets, mainly attributed to the Sound
acquisition and our ongoing capital development program. The slight
increase in the DD&A rate per boe for this period is due to
high capital expenditures in 2008 and the higher value assigned to
the Sound acquisition than accumulated from prior development
activities. The total DD&A provision for the three months ended
December 31, 2008 is less than the same period of 2007, because of
lower production. The D&D rate per boe in the fourth quarter
was comparable to 2007. Goodwill The Fund frequently assesses
goodwill impairment which is effectively a comparison of the fair
value of the Fund to the values assigned to the identifiable assets
and liabilities. The fair value of the Fund is typically determined
by reference to the market capitalization adjusted for a number of
potential valuation factors. The values of the identifiable assets
and liabilities include the current assessed value of our reserves
and other assets and liabilities. Near the end of 2008, Advantage
and the entire oil and gas industry, experienced a substantial
decline in market capitalization as a result of the worldwide
recession, resulting soft commodity prices, and general negative
market reaction. As a result, the entire $120.3 million balance of
goodwill was determined to be impaired at December 31, 2008, as
there is no market perception of goodwill. Taxes Current taxes paid
or payable for the quarter ended December 31, 2008 amounted to $0.1
million, comparable to the $0.5 million expensed for the same
period of 2007. The higher current taxes for the year are due to
the increased Saskatchewan properties and activity within these
properties from the Ketch and Sound acquisitions. Current taxes
primarily represent Saskatchewan resource surcharge, which is based
on the petroleum and natural gas revenues within the province of
Saskatchewan. Future income taxes arise from differences between
the accounting and tax bases of the assets and liabilities. For the
year ended December 31, 2008, the Fund recognized a future income
tax reduction of $10.8 million compared to $24.6 million for 2007.
Under the Fund's current structure, payments are made between the
operating company and the Fund transferring income tax obligations
to Unitholders and as a result no cash income taxes would be paid
by the operating company or the Fund prior to 2011. However, the
Specified Investment Flow-Through Entity ("SIFT") tax legislation
was enacted on June 22, 2007 altering the tax treatment by
subjecting income trusts to a two-tier tax structure, similar to
that of corporations, whereby the taxable portion of distributions
paid by trusts will be subject to tax at the trust level and at the
Unitholder level. The rules are effective for tax years beginning
in 2011 for existing publicly-traded trusts. The impact of the new
tax law has been reflected in both 2008 and 2007 and resulted in an
additional future income tax expense of $Nil (2007 - $42.9
million). As at December 31, 2008, we had a future income tax
liability balance of $55.9 million, compared to $66.7 million at
December 31, 2007. Canadian generally accepted accounting
principles require that a future income tax liability be recorded
when the book value of assets exceeds the balance of tax pools. It
further requires that a future tax liability be recorded on an
acquisition when a corporation acquires assets with associated tax
pools that are less than the purchase price. During the year ended
December 31, 2007, Advantage recorded a future tax liability of
$29.4 million with the acquisition of Sound. On December 14, 2007,
the Federal government enacted legislation phasing in corporate
income tax rate reductions which will reduce federal tax rates from
22.1% to 15.0% by 2012. Rate reductions will also apply to the new
tax on distributions of income trusts and other specified
investment flow-through entities as of 2011, reducing the tax rate
in 2011 to 29.5% and in 2012 to 28.0%. These rates include a deemed
provincial rate of 13%. The Fund has approximately $1.8 billion in
tax pools and deductions at December 31, 2008, which can be used to
reduce the amount of taxes paid by Advantage. The Fund and
Advantage Oil & Gas Ltd. ("AOG") had the following estimated
tax pools in place at December 31, 2008: December 31, 2008
Estimated Tax Pools ($ millions) ---------- Undepreciated Capital
Cost $ 658 Canadian Oil and Gas Property Expenses 444 Canadian
Development Expenses 555 Canadian Exploration Expenses 67
Non-capital losses 75 Other 16 ---------- $ 1,815 ----------
---------- Net Income (Loss) Three months ended Year ended December
31 December 31 2008 2007 % change 2008 2007 % change
-------------------------------------------------------------------------
Net income (loss) ($000) $(95,477) $ 13,795 (792)% $(20,577) $
(7,535) 173% per Trust Unit - Basic $ (0.67) $ 0.10 (775)% $ (0.15)
$ (0.06) 146% - Diluted $ (0.67) $ 0.10 (775)% $ (0.15) $ (0.06)
146% Advantage experienced a net loss for the three months and year
ended December 31, 2008 primarily due to a $120.3 million
impairment of goodwill. Excluding this one-time non-cash item,
Advantage had net income of $99.7 million for 2008, delivering
significant financial results. For the full year, we experienced
considerably higher revenues from increased production and average
commodity prices. This was partially offset by some higher
expenses, including operating costs, depletion and depreciation.
Although overall Advantage had a successful year, the fourth
quarter began to show strains from the sudden drop in commodity
prices that reduced revenues and negatively impacted net income.
Commodity prices have continued to worsen in 2009, presenting a
significant challenge for the entire oil and gas industry. We
expect this situation to have a wide-ranging impact on the sector
for the coming year. Net loss for the quarter and year also
included unrealized derivative gains of $34.0 million and $38.8
million, respectively, from the low commodity price environment
(see "Commodity Price Risk" section). The unrealized amounts are
not cash and the actual gains or losses realized on eventual cash
settlement can vary materially due to subsequent fluctuations in
commodity prices. The Fund does not apply hedge accounting and
current accounting standards require changes in the fair value to
be included in the consolidated statement of loss and comprehensive
loss as an unrealized derivative gain or loss with a corresponding
derivative asset and liability recorded on the balance sheet. These
derivative contracts currently outstanding will settle from January
2009 to March 2011 corresponding to when Advantage will receive
revenues from production. Cash Netbacks Three months ended December
31 2008 2007 $000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 135,732 $ 46.79 $ 160,741 $ 50.91 Realized gain (loss) on
derivatives 13,473 4.64 5,210 1.65 Royalties (23,338) (8.05)
(27,099) (8.58) Operating costs (42,673) (14.71) (39,330) (12.46)
-------------------------------------------------------------------------
Operating $ 83,194 $ 28.67 $ 99,522 $ 31.52 General and
administrative(1) (3,198) (1.10) (7,029) (2.23) Interest (6,430)
(2.22) (7,917) (2.51) Interest on convertible debentures(2) (4,080)
(1.41) (3,536) (1.12) Income and capital taxes (116) (0.04) (521)
(0.16)
-------------------------------------------------------------------------
Funds from operations $ 69,370 $ 23.90 $ 80,519 $ 25.50
-------------------------------------------------------------------------
Year ended December 31 2008 2007 $000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 769,401 $ 65.14 $ 538,764 $ 49.27 Realized gain (loss) on
derivatives (27,439) (2.32) 18,594 1.70 Royalties (146,349) (12.39)
(98,614) (9.02) Operating costs (164,091) (13.89) (127,309) (11.64)
-------------------------------------------------------------------------
Operating $ 431,522 $ 36.54 $ 331,435 $ 30.31 General and
administrative(1) (23,422) (1.98) (20,520) (1.88) Interest (27,893)
(2.36) (24,351) (2.23) Interest on convertible debentures(2)
(16,627) (1.41) (13,977) (1.28) Income and capital taxes (2,493)
(0.21) (1,444) (0.13)
-------------------------------------------------------------------------
Funds from operations $ 361,087 $ 30.58 $ 271,143 $ 24.79
-------------------------------------------------------------------------
(1) General and administrative expense excludes non-cash unit-based
compensation expense. (2) Interest on convertible debentures
excludes non-cash accretion expense and interest expense. Funds
from operations and cash netbacks increased in total and per boe
for the year ended December 31, 2008, compared to 2007, due
primarily to additional production from the Sound acquisition and
higher average commodity prices through the first three quarters of
2008. Increased cash netbacks per boe for the year ended December
31, 2008 were partially offset by realized losses on derivatives,
and increased operating expenses and royalties. Realized hedging
losses resulted from the higher commodity price environment as the
Fund entered derivative contracts to lessen commodity price
fluctuations, which can positively or negatively impact cash flows.
Operating costs increased during 2008 due to significantly higher
field costs associated with a general industry escalation and
higher relative operating costs from the Sound acquisition.
Royalties also increased as would be expected since they are
generally based on current commodity prices. Funds from operations
and cash netbacks per boe for the three months ended December 31,
2008 decreased from the same period of 2007, a direct result of the
commodity price drops that occurred in the fourth quarter of 2008
as the financial crisis deepened into a global recession. The
decrease in commodity prices was significantly offset by realized
gains on derivatives during the period. Operating costs per boe
were higher for the three months ended December 31, 2008 due to
early cold weather conditions that increased some operating costs
and lowered corresponding production volumes. However, we expect to
see some easing of operating costs in 2009 as the poor economic
environment continues to have an impact on the service sector.
Contractual Obligations and Commitments The Fund has contractual
obligations in the normal course of operations including purchases
of assets and services, operating agreements, transportation
commitments, sales contracts and convertible debentures. These
obligations are of a recurring and consistent nature and impact
cash flow in an ongoing manner. The following table is a summary of
the Fund's remaining contractual obligations and commitments.
Advantage has no guarantees or off-balance sheet arrangements other
than as disclosed. Payments due by period ($ millions) Total 2009
2010 2011 2012
-------------------------------------------------------------------------
Building leases $ 10.3 $ 3.8 $ 3.9 $ 1.5 $ 1.1 Capital leases 6.2
2.1 2.2 1.9 - Pipeline/transportation 4.9 3.2 1.4 0.3 - Convertible
debentures (1) 219.2 87.0 69.9 62.3 -
-------------------------------------------------------------------------
Total contractual obligations $ 240.6 $ 96.1 $ 77.4 $ 66.0 $ 1.1
-------------------------------------------------------------------------
(1) As at December 31, 2008, Advantage had $219.2 million
convertible debentures outstanding (excluding interest payable
during the various debenture terms). Each series of convertible
debentures are convertible to Trust Units based on an established
conversion price. All remaining obligations related to convertible
debentures can be settled through the payment of cash or issuance
of Trust Units at Advantage's option. (2) Bank indebtedness of
$587.4 million has been excluded from the contractual obligations
table as the credit facilities constitute a revolving facility for
a 364 day term which is extendible annually for a further 364 day
revolving period at the option of the syndicate. If not extended,
the revolving credit facility is converted to a two year term
facility with the first payment due one year and one day after
commencement of the term. Liquidity and Capital Resources The
following table is a summary of the Fund's capitalization
structure. ($000, except as otherwise indicated) December 31, 2008
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 587,404 Working capital deficit(1)
146,397
-------------------------------------------------------------------------
Net debt $ 733,801
-------------------------------------------------------------------------
Trust Units outstanding (000) 142,825 Trust Units closing market
price ($/Trust Unit) $ 5.12
-------------------------------------------------------------------------
Market value $ 731,263
-------------------------------------------------------------------------
Convertible debentures maturity value (long-term) $ 132,221 Capital
lease obligation (long term) 3,906
-------------------------------------------------------------------------
Total capitalization $1,601,191
-------------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities,
distributions payable, and the current portion of capital lease
obligations and convertible debentures. Advantage monitors its
capital structure and makes adjustments according to market
conditions in an effort to meet its objectives given the current
outlook of the business and industry in general. The capital
structure of the Fund is composed of working capital (excluding
derivative assets and liabilities), bank indebtedness, convertible
debentures, capital lease obligations and Unitholders' equity.
Advantage may manage its capital structure by issuing new Trust
Units, obtaining additional financing either through bank
indebtedness or convertible debenture issuances, refinancing
current debt, issuing other financial or equity-based instruments,
adjusting or discontinuing the amount of monthly distributions,
suspending or renewing its distribution reinvestment plan,
adjusting capital spending, or disposing of assets. The capital
structure is reviewed by Management and the Board of Directors on
an ongoing basis. In late 2008, a financial crisis materialized
which has now turned into a full global recession. This situation
has significantly impacted the ability to raise capital. Despite
this situation, the Fund continues to generate funds from
operations sufficient to fund our operations and a reduced capital
program. Management of the Fund's capital structure is facilitated
through its financial and operational forecasting processes. The
forecast of the Fund's future cash flows is based on estimates of
production, commodity prices, forecast capital and operating
expenditures, and other investing and financing activities. The
forecast is regularly updated based on new commodity prices and
other changes, which the Fund views as critical in the current
environment. Selected forecast information is frequently provided
to the Board of Directors. This continual financial assessment
process further enables the Fund to mitigate risks. The Fund
continues to satisfy all liabilities and commitments as they come
due. We have an established $710 million credit facility agreement
with a syndicate of financial institutions; the balance of which
utilized at December 31, 2008 was $587 million. This facility will
be subject for renewal again in June 2009. The Fund additionally
has several convertible debentures that will mature in 2009,
whereby we have the option to settle such obligations by cash or
though the issuance of Trust Units. Management has budgeted for a
capital program of $100 to $130 million for fiscal 2009, as it is
important to bring on additional production to offset natural
reserve declines and to grow the Fund. Management has significantly
reduced the capital program from 2008 and will continually monitor
our capital expenditures and make adjustments as needed in order to
remain self-sufficient within our funds from operations through the
foreseeable future. The current economic situation has also placed
additional pressure on commodity prices. Crude oil has dropped from
a historic high to approximately US$47/bbl. The impact from the
decrease in WTI will be somewhat mitigated for Advantage due to the
strengthening US dollar relative to the Canadian dollar. Natural
gas prices that had been improving early in 2008, have now started
to decline due to the ailing economy as well as increased inventory
levels from strong injections and mild weather. Natural gas has
dropped to approximately CAD$3.80/GJ. The net effect for the Fund
from prolonged weak commodity prices would be reductions in
operating netbacks and funds from operations. Management has
partially mitigated this risk through our commodity hedging program
but the lower commodity price environment has still had a
significant negative impact. In order to strengthen our financial
position and balance our cash flows, the monthly distribution has
been discontinued to repay debt and focus capital spending on our
Montney natural gas resource play. To summarize, we have
implemented a strategy to maximize self sufficiency such that funds
from operations will satisfy our capital program, reduce debt, and
meet other expenditure requirements. We do not anticipate any
problems satisfying obligations as they become due. A successful
hedging program was also executed to help protect our funds from
operations. As a result, we feel that Advantage has implemented
adequate strategies to protect our business as much as possible in
this environment. However, as with all companies, we are still
exposed to risks as a result of the current economic situation and
the potential duration. We continue to closely monitor the possible
impact on our business and strategy, and will make adjustments as
necessary with prudent management. Unitholders' Equity and
Convertible Debentures Advantage has utilized a combination of
Trust Units, convertible debentures and bank debt to finance
acquisitions and development activities. As at December 31, 2008,
the Fund had 142.8 million Trust Units outstanding. During the year
ended December 31, 2008, 4,414,830 Trust Units were issued as a
result of the Premium Distribution(TM), Distribution Reinvestment
and Optional Trust Unit Purchase Plan (the "Plan"), generating
$39.9 million reinvested in the Fund and representing an
approximate 20% participation rate (for the year ended December 31,
2007, 4,028,252 Trust Units were issued under the Plan, generating
$46.7 million reinvested in the Fund and representing an
approximate 18% participation rate). As at March 18, 2009,
Advantage had 145.2 million Trust Units issued and outstanding. At
December 31, 2008, the Fund had $219.2 million convertible
debentures outstanding that were immediately convertible to 9.5
million Trust Units based on the applicable conversion prices
(December 31, 2007 - $224.6 million outstanding and convertible to
9.8 million Trust Units). During the year ended December 31, 2008,
$25,000 debentures were converted resulting in the issuance of
1,001 Trust Units and the 9.00% debentures matured on August 1,
2008, resulting in a cash payment of $5,392,000 to the debenture
holders. As at March 18, 2009, the Fund had $214.3 million
convertible debentures outstanding, after the remaining $4.9
million 8.25% debentures matured on February 1, 2009 and were
settled through the issuance of 946,887 Trust Units. We have $29.8
million of 8.75% debentures that will mature on June 30, 2009 and
$52.3 million of 7.50% debentures that mature on October 1, 2009.
These obligations can be settled through the payment of cash or
issuance of Trust Units at Advantage's option. Advantage has a
Trust Units Rights Incentive Plan for external directors as
approved by the Unitholders of the Fund. A total of 500,000 Trust
Units were reserved for issuance under the plan with an aggregate
of 400,000 rights granted since inception. The initial exercise
price of rights granted under the plan may not be less than the
current market price of the Trust Units as of the date of the grant
and the maximum term of each right is not to exceed ten years with
all rights vesting immediately upon grant. At the option of the
rights holder, the exercise price of the rights can be adjusted
downwards over time based upon distributions paid by the Fund to
Unitholders. In 2008, all remaining 150,000 outstanding rights were
exercised at $8.60 per right for total cash proceeds of $1,290,000.
No Trust Unit Rights were outstanding as of December 31, 2008. As a
result of the SIFT tax legislation, an income trust is permitted to
double its market capitalization as it stands on October 31, 2006
by growing a maximum of 40% in 2007 and 20% for the years 2008 to
2010. Any unused expansion from the prior year can be brought
forward into the following year until the new tax rules take
effect. In addition, an income trust may replace debt that was
outstanding as of October 31, 2006 with new equity or issue new,
non-convertible debt without affecting the normal growth
percentage. An income trust may also merge with another income
trust without a change to their normal growth percentage, provided
there is no net addition to equity as a result of the merger. As a
result of the "normal growth" guidelines, the Fund is permitted to
issue approximately $2.3 billion of new equity from January 1, 2009
to January 1, 2011, which we believe is adequate for any growth we
expect to incur. On January 20, 2009, the Fund adopted a Unitholder
Rights Agreement (the "Agreement") for which Unitholder approval
will be sought at the Fund's next annual meeting of Unitholders.
Under the terms of the Agreement, Unitholders will be granted one
right per unit. Each right entitles the holder to purchase a Trust
Unit from treasury at a specified exercise price in the event of an
unsolicited take-over bid for the Fund. The purpose of the
Agreement is to allow Unitholders and the Board adequate time to
consider and evaluate any unsolicited bid made for the Fund, to
provide the Board with adequate time to identify, develop and
negotiate value-enhancing alternatives, if considered appropriate,
to any such unsolicited bid, to encourage the fair treatment of
Unitholders in connection with any take-over bid for the Fund and
to ensure that any proposed transaction is in the best interests of
the Unitholders of the Fund. The Agreement is similar to other
rights plans adopted by many Canadian income trusts and
corporations. The Rights Plan is not triggered if an offer to
acquire Fund Trust Units is made as a "permited bid" and thereby
allows sufficient time for the Board and Unitholders to consider
and react to the offer. Bank Indebtedness, Credit Facility and
Other Obligations At December 31, 2008, Advantage had bank
indebtedness outstanding of $587.4 million. The Fund has a $710
million credit facility agreement consisting of a $690 million
extendible revolving loan facility and a $20 million operating loan
facility. The current credit facilities are collateralized by a $1
billion floating charge demand debenture, a general security
agreement and a subordination agreement from the Fund covering all
assets and cash flows. As well, the borrowing base for the Fund's
credit facilities is determined through utilizing our regular
reserve estimates. The banking syndicate thoroughly evaluates the
reserve estimates based upon their own commodity price expectations
to determine the amount of the borrowing base. Revision or changes
in the reserve estimates and commodity prices can have either a
positive or a negative impact on the borrowing base of the Fund. In
June 2008, the Fund renewed its credit facilities for a further
year with the next annual review scheduled to occur in June 2009.
There can be no assurances that the $710 million credit facility
will be renewed at the current borrowing base level given the
present commodity price environment. On March 18, 2009, we
announced our intention to dispose of certain assets. The net
proceeds from these sales or other oil and natural gas property
sales will initially be used to reduce our outstanding bank debt to
improve Advantage's financial flexibility. Advantage had a working
capital deficiency of $146.4 million as at December 31, 2008. Our
working capital includes items expected for normal operations such
as trade receivables, prepaids, deposits, trade payables and
accruals as well as the current portion of capital lease
obligations. Working capital varies primarily due to the timing of
such items, the current level of business activity including our
capital program, commodity price volatility, and seasonal
fluctuations. We do not anticipate any problems in meeting future
obligations as they become due given the strength of our funds from
operations. It is also important to note that working capital is
effectively integrated with Advantage's operating credit facility,
which assists with the timing of cash flows as required. The
increase in our working capital deficiency at December 31, 2008 is
due to the additional inclusion of $87 million in principal amount
of convertible debentures that mature during 2009 and are
classified as a current liability. The $4.9 million principal
amount 8.25% debentures matured on February 1, 2009 and were
settled through the issuance of 946,887 Trust Units. We have $29.8
million of 8.75% debentures that will mature on June 30, 2009 and
$52.3 million of 7.50% debentures that mature on October 1, 2009.
These obligations can be settled through the payment of cash or
issuance of Trust Units at Advantage's option. Advantage has
capital lease obligations on various pieces of equipment used in
its operations. The total amount of principal obligation
outstanding at December 31, 2008 is $5.7 million, bearing interest
at effective rates ranging from 5.5% to 6.7%, and is collateralized
by the related equipment. The leases expire at dates ranging from
December 2009 to August 2010. Capital Expenditures Three months
ended Year ended December 31 December 31 ($000) 2008 2007 2008 2007
-------------------------------------------------------------------------
Land and seismic $ 13,039 $ 64 $ 22,532 $ 3,270 Drilling,
completions and workovers 49,833 30,020 140,019 94,786 Well
equipping and facilities 36,242 9,971 92,016 48,296 Other 198 878
1,024 2,373
-------------------------------------------------------------------------
$ 99,312 $ 40,933 $ 255,591 $ 148,725 Acquisition of Sound Energy
Trust - (67) - 22,307 Property acquisitions - 3,200 7,621 16,051
Property dispositions (850) (610) (941) (1,037)
-------------------------------------------------------------------------
Total capital expenditures $ 98,462 $ 43,456 $ 262,271 $ 186,046
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Advantage's growth strategy has been to acquire properties in or
near areas where we have large land positions, shallow to medium
depth drilling opportunities, and a balance of year round access.
We focus on areas where past activity has yielded long-life
reserves with high cash netbacks. Advantage is very well positioned
to selectively exploit the highest value-generating drilling
opportunities given the size, strength and diversity of our asset
base. As a result, the Fund has a high level of flexibility to
distribute its capital program and ensure a risk-balanced platform
of projects. Our preference is to operate a high percentage of our
properties such that we can maintain control of capital
expenditures, operations and cash flows. For the three month period
ended December 31, 2008, the Fund spent a net $99.3 million. Total
capital spending in the quarter included $66.4 million at Glacier,
$9.4 million at Nevis, $5.8 million at Willesden Green, and $1.6
million at Chip Lake. For the year ended December 31, 2008, the
Fund spent a net $255.6 million and drilled a total of 86.8 net
(124 gross) wells at a 99% success rate. Total capital spending for
the year included $101.7 million at Glacier, $49.6 million at
Nevis, $17.2 million at Martin Creek, $15.1 million at Willesden,
$9.4 million at Sousa, and $8.1 million at Chip Lake. During 2008,
we commenced a significant development drilling program on our
Montney natural gas resource play in Glacier, Alberta. Our
investment at Glacier considerably increased reserves and confirmed
horizontal well rates of 2.5 to 7.5 mmcf/d (417 to 1,250 boe/d). At
Nevis, continued light oil drilling in the Wabamun formation
extended the field and resulted in numerous wells with initial
production exceeding 200 boe/day. A 35 gross (27 net) well
Horseshoe Canyon coal bed methane drilling program in 2008 also
confirmed several more phases of future drilling. At Nevis, a total
of 47 gross (38.8 net) wells were drilled at a 100% success rate
and added 2,980 boe/day of initial production. At Martin Creek, our
successful 10 well gross (8 net) drilling program in early 2008
added 1,490 boe/day of initial production. At Willesden Green, a
new light oil pool was discovered with the drilling of 2 gross (2
net) wells with initial combined production of 800 boe/day. In
addition, 3 gross (3 net) wells were successfully drilled for
liquids rich natural gas production from the Rock Creek formation.
At Northville, Brazeau and Youngstown, 6 gross (4.3 net) wells were
successfully drilled adding additional reserves and defined
additional drilling locations. Property acquisitions year to date
include a $7.6 million property acquisition closed in the third
quarter which increased our working interest ownership and drilling
inventory in the Horseshoe Canyon coal bed methane lands at Nevis.
On December 18, 2008, the Board approved budgeted capital
expenditures for 2009 in the range of $100 to $130 million. This is
down from 2008 as we feel a conservative approach is appropriate in
the current economic climate, where commodity prices are depressed
and available financing is limited. The capital spending will be
primarily directed towards drilling, infrastructure and strategic
investments in our Montney natural gas resource play at Glacier in
Northwest Alberta. We will continue to evaluate and adjust our 2009
capital program as the year progresses. Sources and Uses of Funds
The following table summarizes the various funding requirements
during the year ended December 31, 2008 and 2007 and the sources of
funding to meet those requirements: Year ended December 31 ($000)
2008 2007
-------------------------------------------------------------------------
Sources of funds Funds from operations $ 361,087 $ 271,143 Increase
in bank indebtedness 39,978 28,893 Decrease in working capital
38,070 - Units issued, net of costs 1,248 104,215 Property
dispositions 941 1,037
-------------------------------------------------------------------------
$ 441,324 $ 405,288
-------------------------------------------------------------------------
Uses of funds Expenditures on property and equipment $ 255,591 $
148,725 Distributions to Unitholders 161,924 170,915 Expenditures
on asset retirement 9,259 6,951 Property acquisitions 7,621 16,051
Convertible debenture repayment 5,392 - Reduction of capital lease
obligations 1,537 3,184 Acquisition of Sound Energy Trust - 22,307
Debentures redeemed - 19,406 Increase in working capital - 17,749
-------------------------------------------------------------------------
$ 441,324 $ 405,288
-------------------------------------------------------------------------
The Fund generated higher funds from operations during 2008
compared to 2007 due to higher production levels and a stronger
average commodity price environment that prevailed through the
first three quarters of the year. As a result, the Fund was able to
adequately finance its capital expenditures and distributions to
Unitholders. However, given the current economy and its effects on
commodity prices, our bank indebtedness increased during the fourth
quarter as a source of funds. We have been proactive in balancing
our cash flows and reduced our distribution in December 2008
followed by a further reduction in January 2009 as commodity prices
continued to erode. On March 18, 2009, we announced that our
monthly distribution will be discontinued and future cash flow
redirect to repay debt and focus capital on our Montney natural gas
resource play. We will be closely monitoring our future sources and
uses of funds. Annual Financial Information The following is a
summary of selected financial information of the Fund for the years
indicated. Year ended Year ended Year ended Dec. 31, Dec. 31, Dec.
31, 2008 2007 2006
-------------------------------------------------------------------------
Total revenue (before royalties) ($000) $ 741,962 $ 557,358 $
419,727 Net income (loss) ($000) $ (20,577) $ (7,535) $ 49,814 per
Trust Unit - Basic $ (0.15) $ (0.06) $ 0.62 - Diluted $ (0.15) $
(0.06) $ 0.61 Total assets ($000) $2,305,433 $2,422,280 $1,981,587
Long term financial liabilities ($000)(1) $ 721,198 $ 768,060 $
581,698 Distributions declared per Trust Unit $ 1.40 $ 1.77 $ 2.66
(1) Long term financial liabilities exclude asset retirement
obligations and future income taxes. Quarterly Performance 2008
($000, except as otherwise indicated) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production Natural gas (mcf/d) 120,694 122,627 123,104
125,113 Crude oil and NGLs (bbls/d) 11,413 11,980 11,498 12,281
Total (boe/d) 31,529 32,418 32,015 33,133 Average prices Natural
gas ($/mcf) Excluding hedging $ 7.15 $ 8.65 $ 10.33 $ 7.90
Including hedging $ 7.61 $ 7.55 $ 9.18 $ 8.23 AECO monthly index $
6.79 $ 9.27 $ 9.35 $ 7.13 Crude oil and NGLs ($/bbl) Excluding
hedging $ 53.65 $ 107.96 $ 110.15 $ 85.99 Including hedging $ 61.67
$ 100.02 $ 101.34 $ 84.83 WTI ($US/bbl) $ 58.75 $ 118.13 $ 124.00 $
97.96 Total revenues (before royalties) $ 149,205 $ 195,384 $
208,868 $ 188,505 Net income (loss) $ (95,477) $ 113,391 $ (14,369)
$ (24,122) per Trust Unit - basic $ (0.67) $ 0.81 $ (0.10) $ (0.18)
- diluted $ (0.67) $ 0.79 $ (0.10) $ (0.18) Funds from operations $
69,370 $ 93,345 $ 103,754 $ 94,618 Distributions declared $ 45,514
$ 50,743 $ 50,364 $ 50,021 2007 ($000, except as otherwise
indicated) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production Natural gas (mcf/d) 128,556 115,991 108,978
114,324 Crude oil and NGLs (bbls/d) 12,895 10,014 8,952 9,958 Total
(boe/d) 34,321 29,346 27,115 29,012 Average prices Natural gas
($/mcf) Excluding hedging $ 6.23 $ 5.62 $ 7.54 $ 7.61 Including
hedging $ 6.97 $ 6.35 $ 7.52 $ 8.06 AECO monthly index $ 6.00 $
5.62 $ 7.37 $ 7.46 Crude oil and NGLs ($/bbl) Excluding hedging $
73.40 $ 69.03 $ 61.84 $ 56.84 Including hedging $ 70.40 $ 68.51 $
61.93 $ 58.64 WTI ($US/bbl) $ 90.63 $ 75.33 $ 65.02 $ 58.12 Total
revenues (before royalties) $ 165,951 $ 130,830 $ 125,075 $ 135,502
Net income (loss) $ 13,795 $ (26,202) $ 4,531 $ 341 per Trust Unit
- basic $ 0.10 $ (0.22) $ 0.04 $ 0.00 - diluted $ 0.10 $ (0.22) $
0.04 $ 0.00 Funds from operations $ 80,519 $ 62,345 $ 62,634 $
65,645 Distributions declared $ 57,875 $ 55,017 $ 52,096 $ 50,206
The table above highlights the Fund's performance for the fourth
quarter of 2008 and also for the preceding seven quarters.
Production during the 2006/2007 winter was steady until we
experienced a decrease in the second quarter of 2007 due to several
facility turnarounds at that time. The Sound acquisition closed on
September 5, 2007, and significantly increased production for the
third and fourth quarters of 2007. Production has gradually
decreased through the first half of 2008 due to natural declines,
wet and cold weather delays, and facility turnarounds. Production
increased modestly in the third quarter of 2008 as new wells were
brought on production and most facility turnarounds were completed.
During the fourth quarter, production again decreased as we
experienced freezing conditions from early cold weather as well as
an extended third party facility outage. Financial results,
particularly revenues and funds from operations, have increased
through to the second quarter of 2008, as both commodity prices and
production steadily increased over that timeframe. However,
revenues and funds from operations slightly declined in the third
quarter of 2008, as commodity prices began to decline in response
to the financial crisis that materialized in the fall of 2008. This
trend worsened in the fourth quarter, as a full global recession
set in, and commodity prices continued on a downward trend. We
experienced a net loss in the third quarter of 2007 due to a
significant drop in natural gas prices realized at that time,
amortization of the management internalization consideration and
increased depletion and depreciation expense. Net income increased
in the fourth quarter of 2007 due to the full integration of the
Sound acquisition and moderately improved commodity prices. Net
losses were realized in the first and second quarters of 2008,
primarily as a result of significant unrealized losses on commodity
derivative contracts for future periods. Commodity price declines
in the third quarter of 2008 gave rise to significant unrealized
gains on these same derivative contracts, and in turn the Fund
reported record high net income. We recognized a considerable net
loss in the fourth quarter of 2008, a combined result of falling
commodity prices and an impairment of our entire goodwill. Critical
Accounting Estimates The preparation of financial statements in
accordance with GAAP requires Management to make certain judgments
and estimates. Changes in these judgments and estimates could have
a material impact on the Fund's financial results and financial
condition. Management relies on the estimate of reserves as
prepared by the Fund's independent qualified reserves evaluator.
The process of estimating reserves is critical to several
accounting estimates. The process of estimating reserves is complex
and requires significant judgments and decisions based on available
geological, geophysical, engineering and economic data. These
estimates may change substantially as additional data from ongoing
development and production activities becomes available and as
economic conditions impact crude oil and natural gas prices,
operating costs, royalty burden changes, and future development
costs. Reserve estimates impact net income through depletion and
depreciation of fixed assets, the provision for asset retirement
costs and related accretion expense, and impairment calculations
for fixed assets and goodwill. The reserve estimates are also used
to assess the borrowing base for the Fund's credit facilities.
Revision or changes in the reserve estimates can have either a
positive or a negative impact on net income and the borrowing base
of the Fund. Management's process of determining the provision for
future income taxes, the provision for asset retirement obligation
costs and related accretion expense, and the fair values assigned
to any acquired company's assets and liabilities in a business
combination is based on estimates. These estimates are significant
and can include reserves, future production rates, future crude oil
and natural gas prices, future costs, future interest rates, future
tax rates and other relevant assumptions. Revisions or changes in
any of these estimates can have either a positive or a negative
impact on asset and liability values and net income. In accordance
with GAAP, derivative assets and liabilities are recorded at their
fair values at the reporting date, with unrealized gains and losses
recognized directly into net income and comprehensive income in the
same period. The fair value of derivatives outstanding is an
estimate based on pricing models, estimates, assumptions and market
data available at that time. As such, the unrealized amounts are
not cash and the actual gains or losses realized on eventual cash
settlement can vary materially due to subsequent fluctuations in
commodity prices as compared to the valuation assumptions.
International Financial Reporting Standards ("IFRS") In February
2008, the Accounting Standards Board of the Canadian Institute of
Chartered Accountants confirmed that publicly accountable entities
will be required to adopt IFRS effective January 1, 2011, including
preparation of comparative financial information. Management has
engaged its key personnel responsible for financial reporting and
developed an overall plan to address IFRS implementation. The
initial stage of the plan involved staff training and ongoing
education. Key personnel received professional education on IFRS
accounting principles and standards, both in general and for the
oil and gas industry in particular. Review of changes to IFRS has
been incorporated into existing processes of internal control over
financial reporting. A preliminary project plan for IFRS
implementation has been drafted and will be subject to ongoing
revision as there are developments. As well, appropriate operating
personnel have been engaged, as necessary, to determine how to
implement the requirements of IFRS into the Fund's manual and
information systems that collect and process financial data. We
expect to have continual discussion with our external auditors
throughout the process regarding IFRS and implementation. The most
significant change identified will be accounting for property,
plant and equipment. The Fund, like many Canadian oil and gas
reporting issuers, applies the "full cost" concept in accounting
for its oil and gas assets. Under full cost, capital expenditures
are maintained in a single cost centre for each country, and the
cost centre is subject to a single depletion calculation and
impairment test. IFRS will require the Fund to make a much more
detailed assessment of its oil and gas property, plant and
equipment. For depletion and depreciation, the Fund must identify
asset components, and determine an appropriate depreciation or
depletion method for each component. With regards to impairment
calculation purposes, we must be identify "Cash Generating Units",
which are defined as the smallest group of assets that produces
independent cash flows. An impairment test must be performed
individually for all cash generating units. The recognition of
impairments in a prior year can be reversed subsequently depending
on such calculations. It is also important to note that the
International Accounting Standards Board ("IASB") is currently
undertaking an extractive industries project, to develop accounting
standards specifically for businesses like that of the Fund.
However, the project will not be complete prior to IFRS adoption in
Canada. We have also identified a number of other areas whereby
differences between Canadian GAAP and IFRS are likely to exist for
Advantage. However, currently we are concentrating on the
accounting for property, plant and equipment and will evaluate
these other areas in due course and develop more detailed plans to
address the identified issues. Controls and Procedures The Fund has
established procedures and internal control systems to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with GAAP. Management of the Fund is
committed to providing timely, accurate and balanced disclosure of
all material information about the Fund. Disclosure controls and
procedures are in place to ensure all ongoing reporting
requirements are met and material information is disclosed on a
timely basis. The Chief Executive Officer and President and Chief
Financial Officer, individually, sign certifications that the
financial statements, together with the other financial information
included in the regular filings, fairly present in all material
respects the financial condition, results of operations, and cash
flows as of the dates and for the periods presented in the filings.
The certifications further acknowledge that the filings do not
contain any untrue statement of a material fact or omit to state a
material fact required to be stated or that is necessary to make a
statement not misleading in light of the circumstances under which
it was made, with respect to the period covered by the filings.
Evaluation of Disclosure Controls and Procedures The Fund has
established a Disclosure Committee consisting of the executive
members with the responsibility of overseeing the Fund's disclosure
practices and designing disclosure controls and procedures ("DCP"),
as such term is defined in National Instrument 52-109 Certification
of Disclosure in Issuers' Annual and Interim Filings, to provide
reasonable assurance that information required to be disclosed by
the Fund in its annual filings, interim filings or other reports
filed or submitted by the Fund under applicable securities
legislation is recorded, processed, summarized and reported within
the time periods specified in applicable securities legislation and
that all material information relating to the Fund is made known to
them by others, particularly during the period in which the Fund's
annual and interim filings are being prepared. All written public
disclosures are reviewed and approved by at least one member of the
Disclosure Committee prior to issuance. Additionally, the
Disclosure Committee assists the Chief Executive Officer and Chief
Financial Officer of the Fund in making certifications with respect
to the disclosure controls of the Fund required under applicable
regulations and ensures that the Board of Directors is promptly and
fully informed regarding potential disclosure issues facing the
Fund. The Fund's Management is responsible for establishing and
maintaining effective internal control over financial reporting
("ICFR"), as such term is defined in National Instrument 52-109
Certification of Disclosure in Issuers' Annual and Interim Filings.
Management of Advantage, including our Chief Executive Officer and
President and Chief Financial Officer, has evaluated the
effectiveness of the design and operation of the disclosure
controls and procedures as of December 31, 2008. Based on that
evaluation, Management has concluded that the disclosure controls
and procedures are effective as of the end of the period, in all
material respects. It should be noted that while the Chief
Executive Officer and President and Chief Financial Officer believe
that the Fund's design of disclosure controls and procedures
provide a reasonable level of assurance that they are effective,
they do not expect that the disclosure controls and procedures or
internal control over financial reporting will prevent all errors
and fraud. A control system does not provide absolute, but rather
is designed to provide reasonable, assurance that the objective of
the control system is met. Management's Report on Internal Controls
over Financial Reporting The Fund is responsible for establishing
and maintaining adequate internal control over financial reporting.
The Fund's internal control over financial reporting is a process
designed, under the supervision and with the participation of
executive and financial officers of the Fund, to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of the Fund's financial statements for external
reporting purposes in accordance with GAAP. The Fund's internal
control over financial reporting includes policies and procedures
that: 1. pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect transactions and dispositions
of assets of the Fund; 2. provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with GAAP; and 3. provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the Fund's assets
that could have a material effect on the financial statements. The
Fund's internal control over financial reporting may not prevent or
detect all misstatements because of inherent limitations.
Additionally, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become
inadequate because of changes in conditions or deterioration in the
degree of compliance with the Fund's policies and procedures. The
Fund's management assessed the design and effectiveness of the
internal control over financial reporting as of December 31, 2008,
based on the framework established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on this assessment, management
concluded that the Fund maintained effective internal control over
financial reporting as of December 31, 2008. During the year ended
December 31, 2008, there has been no change in the Fund's internal
control over financial reporting that has materially affected, or
is reasonably likely to materially affect, the Fund's internal
control over financial reporting. Corporate Governance The Board of
Directors' mandate is to supervise the management of the business
and affairs of the Fund including the business and affairs of the
Fund delegated to AOG. In particular, all decisions relating to:
(i) the acquisition and disposition of properties for a purchase
price or proceeds in excess of $5 million; (ii) the approval of
annual operating and capital expenditure budgets; and (iii) the
establishment of credit facilities and the issuance of additional
Trust Units, will be made by the Board. Computershare Trust Company
of Canada, the Trustee of the Fund, has delegated certain matters
to the Board of Directors. These include all decisions relating to
issuance of additional Trust Units and the determination of the
amount of distributions. Any amendment to any material contract to
which the Fund is a party will require the approval of the Board of
Directors and, in some cases, Unitholder approval. The Board of
Directors meets regularly to review the business and affairs of the
Fund and AOG and to make any required decisions. The Board of
Directors consists of eleven members, eight of whom are unrelated
to the Fund. The Independent Reserve Evaluation Committee has four
members, the Audit Committee has five members, and the Human
Resources, Compensation and Corporate Governance Committee has four
members. All members of the various committees are independent. One
member of the Audit Committee has been designated a "Financial
Expert" as defined in applicable regulatory guidance. In addition,
the Chairman of the Board is not related and is not an executive
officer of the Fund. The Board of Directors approved and Management
implemented a Code of Business Conduct and Ethics. The purpose of
the code is to lay out the expectation for the highest standards of
professional and ethical conduct from our directors, officers and
employees. The code reflects our commitment to a culture of
honesty, integrity and accountability and outlines the basic
principles and policies with which all employees are expected to
comply. Our Code of Business Conduct and Ethics is available on our
website at http://www.advantageincome.com/. As a Canadian issuer
listed on the New York Stock Exchange (the "NYSE"), Advantage is
not required to comply with most of the NYSE rules and listing
standards and instead may comply with domestic requirements. As a
foreign private issuer, Advantage is only required to comply with
four of the NYSE Rules: (i) have an audit committee that satisfies
the requirements of the United States Securities Exchange Act of
1934; (ii) the Chief Executive Officer must promptly notify the
NYSE in writing after an executive officer becomes aware of any
material non-compliance with the applicable NYSE Rules; (iii)
submit an executed annual written affirmation, as well as an
interim affirmation each time a change occurs to the audit
committee; and (iv) provide a brief description of any significant
differences between its corporate governance practices and those
followed by U.S. companies listed under the NYSE. Advantage has
reviewed the NYSE listing standards and confirms that its corporate
governance practices do not differ significantly from such
standards. A further discussion of the Fund's corporate governance
practices can be found in the Management Proxy Circular. Outlook
The Fund's 2009 budget, as approved by the Board of Directors, is
tailored to the current economic climate. Our natural gas resource
play at Montney in Glacier, Northwest Alberta will be the largest
area of focus. We reiterate that these are extremely uncertain
times. Although the 2009 budget incorporates flexibility in its
current form, management and the Board will review the budget
continually, and adapt when necessary. Advantage's 2009 capital
expenditures budget is estimated to be approximately $100 to $130
million. Capital spending is estimated to be allocated 46% to
Montney, and 54% to other core areas. Given the low commodity price
environment and increasing concerns with the economy, Advantage
will target 2009 capital expenditures at the lower end of our
guidance range. On March 18, 2009, we announced the intention to
dispose of properties producing up to 11,300 boe/d of light oil and
natural gas properties located in Northeast British Columbia, West
Central Alberta and Northern Alberta. The net proceeds from these
sales or other oil and natural gas property sales will initially be
used to reduce outstanding bank debt to improve Advantage's
financial flexibility. Proposals are anticipated by mid May 2009
and the selected assets will be available in four distinct packages
varying in size from approximately 1,600 to 5,400 boe/d of
production. Assuming asset sales of approximately 10,000 to 11,300
boe/d of production are completed, we expect production of
approximately 20,000 to 22,000 boe/d from a focused asset base (60%
natural gas, 40% oil and natural gas liquids). Industry supply,
servicing and maintenance costs increased through the first three
quarters of 2008 driven primarily from higher crude oil and natural
gas prices. Also, there were significant increases from electrical
power costs, processing fees, steel and chemicals. We expect to see
some easing of operating costs as the lower commodity price
environment is expected to remain for a sustained period. Per unit
operating costs on an annual basis are expected to range between
the $13.95 to $14.45/boe in 2009; however, this will be impacted by
the magnitude of our asset disposition program. Advantage's funds
from operations in 2009 will continue to be impacted by the
volatility of crude oil and natural gas prices and the
$US/$Canadian exchange rate. Additional hedging has been completed
for 2009 and 2010 to stabilize cash flows and ensure that the
Fund's capital program is fully funded. Approximately 56% of our
natural gas production, net of royalties, is now hedged for the
2009 calendar year at an average fixed price of $8.09/mcf.
Advantage has also hedged 46% of its 2009 crude oil production, net
of royalties, at an average floor price of $69.38/bbl. For 2010, we
have hedged 48% of our natural gas production, net of royalties, at
an average fixed price of $7.46/mcf and 26% of our crude oil
production, net of royalties, at an average fixed price of
$67.83/bbl. Advantage will continue to focus on low cost production
and reserve additions through low to medium risk development
drilling opportunities that have arisen as a result of the
acquisitions completed in prior years and from the significant
inventory of drilling opportunities that has resulted from the
Ketch and Sound mergers. Our total drilling inventory in our
Glacier Montney natural gas resource play has grown to over 440
confirmed drilling locations and we have significant additional
conventional drilling locations. Looking forward, Advantage's high
quality assets combined with a significant unconventional and
conventional inventory, strong hedging program and excellent tax
pools provides many options for the Fund to maximize value
generation for our Unitholders. Sensitivities The following table
displays the current estimated sensitivity on funds from operations
and funds from operations per Trust Unit to changes in production,
commodity prices, exchange rates and interest rates for 2009
excluding any impact from our asset disposition program. Annual
Funds from Annual Operations Funds from per Operations Trust Unit
($000) ($/Trust Unit)
-------------------------------------------------------------------------
Natural gas: AECO monthly price change of $1.00/mcf $ 16,900 $ 0.11
Production change of 6.0 mmcf/d $ 9,800 $ 0.06 Crude oil and NGLs:
WTI price change of US$10.00/bbl $ 22,300 $ 0.14 Production change
of 1,000 bbls/d $ 11,900 $ 0.07 $US/$Canadian exchange rate change
of $0.01 $ 4,800 $ 0.03 Interest rate change of 1% $ 6,400 $ 0.04
Additional Information Additional information relating to Advantage
can be found on SEDAR at http://www.sedar.com/ and the Fund's
website at http://www.advantageincome.com/. Such other information
includes the annual information form, the annual information
circular - proxy statement, press releases, material contracts and
agreements, and other financial reports. The annual information
form will be of particular interest for current and potential
Unitholders as it discusses a variety of subject matter including
the nature of the business, structure of the Fund, description of
our operations, general and recent business developments, risk
factors, reserves data and other oil and gas information. March 18,
2009 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets
December 31, December 31, (thousands of dollars) 2008 2007
-------------------------------------------------------------------------
Assets Current assets Accounts receivable $ 84,689 $ 95,474 Prepaid
expenses and deposits 14,258 21,988 Derivative asset (note 13)
41,472 7,027
-------------------------------------------------------------------------
140,419 124,489 Derivative asset (note 13) 1,148 174 Fixed assets
(note 4) 2,163,866 2,177,346 Goodwill (note 5) - 120,271
-------------------------------------------------------------------------
$ 2,305,433 $ 2,422,280
-------------------------------------------------------------------------
Liabilities Current liabilities Accounts payable and accrued
liabilities $ 146,046 $ 122,087 Distributions payable to
Unitholders 11,426 16,592 Current portion of capital lease
obligations (note 6) 1,747 1,537 Current portion of convertible
debentures (note 7) 86,125 5,333 Derivative liability (note 13) 611
2,242 Future income taxes (note 10) 11,939 1,430
-------------------------------------------------------------------------
257,894 149,221 Derivative liability (note 13) 1,039 2,778 Capital
lease obligations (note 6) 3,906 5,653 Bank indebtedness (note 8)
587,404 547,426 Convertible debentures (note 7) 128,849 212,203
Asset retirement obligations (note 9) 73,852 60,835 Future income
taxes (note 10) 43,976 65,297
-------------------------------------------------------------------------
1,096,920 1,043,413
-------------------------------------------------------------------------
Unitholders' Equity Unitholders' capital (note 11) 2,075,877
2,027,065 Convertible debentures equity component (note 7) 9,403
9,632 Contributed surplus (note 11) 287 2,005 Accumulated deficit
(note 12) (877,054) (659,835)
-------------------------------------------------------------------------
1,208,513 1,378,867
-------------------------------------------------------------------------
$ 2,305,433 $ 2,422,280
-------------------------------------------------------------------------
Commitments (note 16) Subsequent event (note 17) see accompanying
Notes to Consolidated Financial Statements Consolidated Statements
of Loss, Comprehensive Loss and Accumulated Deficit Year ended Year
ended (thousands of dollars, except December 31, December 31, for
per Trust Unit amounts) 2008 2007
-------------------------------------------------------------------------
Revenue Petroleum and natural gas $ 769,401 $ 538,764 Realized gain
(loss) on derivatives (note 13) (27,439) 18,594 Unrealized gain
(loss) on derivatives (note 13) 38,789 (11,049) Royalties (146,349)
(98,614)
-------------------------------------------------------------------------
634,402 447,695
-------------------------------------------------------------------------
Expenses Operating 164,091 127,309 General and administrative
22,493 21,449 Management internalization (note 14) 6,964 15,708
Interest 27,893 24,351 Interest and accretion on convertible
debentures 19,482 17,436 Depletion, depreciation and accretion
302,104 272,175 Impairment of goodwill (note 5) 120,271 -
-------------------------------------------------------------------------
663,298 478,428
-------------------------------------------------------------------------
Loss before taxes (28,896) (30,733) Future income tax reduction
(note 10) (10,812) (24,642) Income and capital taxes (note 10)
2,493 1,444
-------------------------------------------------------------------------
(8,319) (23,198)
-------------------------------------------------------------------------
Net loss and comprehensive loss (20,577) (7,535) Accumulated
deficit, beginning of year (659,835) (437,106) Distributions
declared (196,642) (215,194)
-------------------------------------------------------------------------
Accumulated deficit, end of year $ (877,054) $ (659,835)
-------------------------------------------------------------------------
Net loss per Trust Unit (note 11) Basic $ (0.15) $ (0.06) Diluted $
(0.15) $ (0.06)
-------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows Year ended Year ended
December 31, December 31, (thousands of dollars) 2008 2007
-------------------------------------------------------------------------
Operating Activities Net loss $ (20,577) $ (7,535) Add (deduct)
items not requiring cash: Unrealized loss (gain) on derivatives
(38,789) 11,049 Unit-based compensation (929) 929 Management
internalization 6,964 15,708 Non-cash interest expense - 890
Accretion on convertible debentures 2,855 2,569 Depletion,
depreciation and accretion 302,104 272,175 Impairment of goodwill
120,271 - Future income tax recovery (10,812) (24,642) Expenditures
on asset retirement (9,259) (6,951) Changes in non-cash working
capital 22,922 (15,060)
-------------------------------------------------------------------------
Cash provided by operating activities 374,750 249,132
-------------------------------------------------------------------------
Financing Activities Units issued, net of costs (note 11) 1,248
104,215 Increase in bank indebtedness 39,978 28,893 Convertible
debenture repayment (note 7) (5,392) (19,406) Reduction of capital
lease obligations (1,537) (3,184) Distributions to Unitholders
(161,924) (170,915)
-------------------------------------------------------------------------
Cash used in financing activities (127,627) (60,397)
-------------------------------------------------------------------------
Investing Activities Expenditures on property and equipment
(255,591) (148,725) Property acquisitions (7,621) (16,051) Property
dispositions 941 1,037 Acquisition of Sound Energy Trust (note 3) -
(22,307) Changes in non-cash working capital 15,148 (2,689)
-------------------------------------------------------------------------
Cash used in investing activities (247,123) (188,735)
-------------------------------------------------------------------------
Net change in cash - - Cash, beginning of year - -
-------------------------------------------------------------------------
Cash, end of year $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow Information Interest paid $ 40,215 $ 42,017
Taxes paid $ 1,957 $ 2,062 see accompanying Notes to Consolidated
Financial Statements NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2008 All tabular amounts in thousands except as
otherwise indicated. 1. Business and Structure of the Fund
Advantage Energy Income Fund ("Advantage" or the "Fund") was formed
on May 23, 2001 as a result of a plan of arrangement. For Canadian
tax purposes, Advantage is an open-ended unincorporated mutual fund
trust created under the laws of the Province of Alberta pursuant to
a Trust Indenture originally dated April 17, 2001, and as
occasionally amended, between Advantage Oil & Gas Ltd. ("AOG")
and Computershare Trust Company of Canada, as trustee. The Fund
commenced operations on May 24, 2001. The beneficiaries of the Fund
are the holders of the Trust Units (the "Unitholders"). The
principal undertaking of the Fund is to indirectly acquire and hold
interests in petroleum and natural gas properties and assets
related thereto. The business of the Fund is carried on by its
wholly-owned subsidiary, AOG. The Fund's primary assets are
currently the common shares of AOG, a royalty in the producing
properties of AOG (the "AOG Royalty") and notes of AOG (the "AOG
Notes"). The Fund's strategy, through AOG, is to minimize exposure
to exploration risk while focusing on growth through acquisitions
and development of producing crude oil and natural gas properties.
The purpose of the Fund is to distribute available cash flow to
Unitholders on a monthly basis in accordance with the terms of the
Trust Indenture. The Fund's available cash flow includes principal
repayments and interest income earned from the AOG Notes, royalty
income earned from the AOG Royalty, and any dividends declared on
the common shares of AOG less any expenses of the Fund including
interest on convertible debentures. Cash received on the AOG Notes,
AOG Royalty and common shares of AOG result in the effective
transfer of the economic interest in the properties of AOG to the
Fund. However, while the royalty is a contractual interest in the
properties owned by AOG, it does not confer ownership in the
underlying resource properties. Distributions from the Fund to
Unitholders are entirely discretionary and are determined by
Management and the Board of Directors. We closely monitor our
distribution policy considering forecasted cash flows, optimal debt
levels, capital spending activity, taxability to Unitholders,
working capital requirements, and other potential cash
expenditures. Distributions are announced monthly and are based on
the cash available after retaining a portion to meet such spending
requirements. The level of distributions are primarily determined
by cash flows received from the production of oil and natural gas
from existing Canadian resource properties and are highly dependent
upon our success in exploiting the current reserve base and
acquiring additional reserves. Furthermore, monthly distributions
we pay to Unitholders are highly dependent upon the prices received
for such oil and natural gas production. On March 18, 2009,
Advantage announced its intention to convert to a growth oriented
corporation and has discontinued the payment of distributions to
focus on debt repayment and developing the Montney natural gas
resource play (note 17). 2. Summary of Significant Accounting
Policies The Management of the Fund prepares its consolidated
financial statements in accordance with Canadian generally accepted
accounting principles ("Canadian GAAP") and all amounts are stated
in Canadian dollars. The preparation of consolidated financial
statements requires Management to make estimates and assumptions
that affect the reported amount of assets, liabilities and equity
and disclosures of contingencies at the date of the consolidated
financial statements and the reported amounts of revenues and
expenses during the period. The following significant accounting
policies are presented to assist the reader in evaluating these
consolidated financial statements and, together with the notes,
should be considered an integral part of the consolidated financial
statements. (a) Consolidation and joint operations These
consolidated financial statements include the accounts of the Fund
and all subsidiaries, including AOG. All intercompany balances and
transactions have been eliminated. The Fund conducts exploration
and production activities jointly with other participants. The
accounts of the Fund reflect its proportionate interest in such
joint operations. (b) Fixed assets (i) Petroleum and natural gas
properties The Fund follows the "full cost" method of accounting in
accordance with the guideline issued by the Canadian Institute of
Chartered Accountants ("CICA") whereby all costs associated with
the acquisition of and the exploration for and development of
petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre and charged
to income as set out below. Such costs include lease acquisition,
drilling and completion, production facilities, asset retirement
costs, geological and geophysical costs and overhead expenses
related to exploration and development activities. Gains or losses
are not recognized upon disposition of petroleum and natural gas
properties unless crediting the proceeds against accumulated costs
would result in a change in the rate of depletion and depreciation
of 20% or more. Depletion of petroleum and natural gas properties
and depreciation of lease, well equipment and production facilities
is provided on accumulated costs using the "unit-of-production"
method based on estimated net proved petroleum and natural gas
reserves, before royalties, as determined by independent engineers.
For purposes of the depletion and depreciation calculation, proved
petroleum and natural gas reserves are converted to a common
unit-of-measure on the basis of one barrel of oil or liquids being
equal to six thousand cubic feet of natural gas. The depletion and
depreciation cost base includes total capitalized costs, less costs
of unproved properties, plus a provision for future development
costs of proved undeveloped reserves. Costs of acquiring and
evaluating unproved properties are excluded from depletion
calculations until it is determined whether or not proved reserves
are attributable to the properties or impairment occurs. Petroleum
and natural 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 "ceiling test"). The carrying amounts are assessed to
be recoverable when the sum of the undiscounted net 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 net 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 net cash flows
are estimated using expected future product prices and costs and
are discounted using a risk-free interest rate. Under Canadian
GAAP, there has been no impairment of the Fund's petroleum and
natural gas properties since inception. (ii) Furniture and
equipment The Fund records furniture and equipment at cost and
provides depreciation on the declining balance method at a rate of
20% per annum which is designed to amortize the cost of the assets
over their estimated useful lives. The Fund records leasehold
improvements at cost and provides depreciation on the straight-
line method over the term of the lease. (c) Goodwill Goodwill is
the excess purchase price of a business over the fair value of
identifiable assets and liabilities acquired. Goodwill is stated at
cost less impairment and is not amortized. Goodwill impairment is
assessed at year-end, or as economic events dictate, by comparing
the fair value of the reporting unit (the Fund) to its carrying
value, including goodwill. If the fair value of the Fund is less
than its carrying value, a goodwill impairment loss is recognized
by allocating the fair value of the Fund to the identifiable assets
and liabilities as if the Fund had been acquired in a business
acquisition for a purchase price equal to the fair value. The
excess of the fair value of the Fund over the values assigned to
the identifiable assets and liabilities is the implied fair value
of the goodwill. Any excess of the carrying value of the goodwill
over the implied fair value is the impairment amount and is charged
to income in the period incurred. (d) Distributions Distributions
declared are calculated on an accrual basis. (e) Financial
instruments The Fund's financial instruments consist of financial
assets, financial liabilities, and non-financial derivatives. All
financial instruments are initially recognized at fair value on the
balance sheet. Measurement of financial instruments subsequent to
the initial recognition, as well as resulting gains and losses, are
recorded based on how each financial instrument was initially
classified. The Fund has classified each identified financial
instrument into the following categories: held for trading, loans
and receivables, held to maturity investments, available for sale
financial assets, and other financial liabilities. Held for trading
financial instruments are measured at fair value with gains and
losses recognized in earnings immediately. Available for sale
financial assets are measured at fair value with gains and losses,
other than impairment losses, recognized in other comprehensive
income and transferred to earnings when the asset is derecognized.
Loans and receivables, held to maturity investments and other
financial liabilities are recognized at amortized cost using the
effective interest method and impairment losses are recorded in
earnings when incurred. With all new financial instruments, an
election is available that allows entities to classify any
financial instrument as held for trading. Only those financial
assets and liabilities that must be classified as held for trading
are classified as such by the Fund. As the Fund frequently uses
non-financial derivative instruments to manage market risk
associated with volatile commodity prices, such instruments must be
classified as held for trading and recorded on the balance sheet at
fair value as derivative assets and liabilities. Under the
alternative hedge accounting treatment, gains and losses on
derivatives classified as effective cash flow hedges are included
in other comprehensive income until the time at which the hedged
item is realized. The Fund does not utilize derivative instruments
for speculative purposes but has elected not to apply hedge
accounting. Therefore, gains and losses on these instruments are
recorded as unrealized gains and losses on derivatives in the
consolidated statement of loss, comprehensive loss and accumulated
deficit in the period they occur and as realized gains and losses
on derivatives when the contracts are settled. Since unrealized
gains and losses on derivatives are non-cash items, there is no
impact on cash provided by operating activities as a result of
their recognition. The Fund also evaluates whether any host
contracts contain embedded derivatives, and records them separately
from the host contract when their economic characteristics and risk
are not clearly and closely related to those of the host contract,
the terms of the embedded derivatives are the same as those of a
freestanding derivative, and the combined contract is not
classified as held for trading or designated at fair value. The
Fund has not identified any embedded derivatives that would require
separation from the host contract and fair value accounting.
Transaction costs are frequently attributed to the acquisition or
issue of a financial asset or liability. Such costs incurred on
held for trading financial instruments are expensed immediately.
For other financial instruments, an entity can adopt an accounting
policy of either expensing transaction costs as they occur or
adding such transaction costs to the fair value of the financial
instrument. The Fund has chosen a policy of adding transaction
costs to the fair value initially recognized for financial assets
and liabilities that are not classified as held for trading. (f)
Comprehensive income Comprehensive income consists of net income
and other comprehensive income ("OCI") with amounts included in OCI
shown net of tax. Accumulated other comprehensive income is
comprised of the cumulative amounts of OCI. To date, the Fund does
not have any adjustments in OCI and therefore comprehensive income
is currently equal to net income. (g) Convertible debentures The
Fund's convertible debentures are financial liabilities consisting
of a liability with an embedded conversion feature. As such, the
debentures are segregated between liabilities and equity based on
the relative fair market value of the liability and equity
portions. Therefore, the debenture liabilities are presented at
less than their eventual maturity values. The liability and equity
components are further reduced for issuance costs initially
incurred. The discount of the liability component as compared to
maturity value is accreted by the "effective interest" method over
the debenture term and expensed accordingly. As debentures are
converted to Trust Units, an appropriate portion of the liability
and equity components are transferred to Unitholders' capital. (h)
Asset retirement obligations The Fund follows the "asset retirement
obligation" method of recording the future cost associated with
removal, site restoration and asset retirement costs. The fair
value of the liability for the Fund's asset retirement obligations
is recorded in the period in which it is incurred, discounted to
its present value using the Fund's credit adjusted risk-free
interest rate and the corresponding amount recognized by increasing
the carrying amount of fixed assets. The asset recorded is depleted
on a "unit-of-production" basis over the life of the reserves
consistent with the Fund's depletion and depreciation policy for
petroleum and natural gas properties. The liability amount is
increased each reporting period due to the passage of time and the
amount of accretion is charged to income in the period. Revisions
to the estimated timing of cash flows or to the original estimated
undiscounted cost could also result in an increase or decrease to
the obligation. Actual costs incurred upon settlement of the
retirement obligations are charged against the obligation to the
extent of the liability recorded. (i) Income taxes The Fund is
considered an open-ended unincorporated mutual fund trust under the
Income Tax Act (Canada). Any taxable income is allocated to the
Unitholders and therefore no provision for current income taxes
relating to the Fund is included in these financial statements. The
Fund and its subsidiaries follow the "liability" method of
accounting for future income taxes. Under this method future income
tax assets and liabilities are determined based on differences
between the carrying value of an asset or liability and its tax
basis using substantially enacted tax rates and laws expected to
apply when the differences reverse. The effect a change in income
tax rates has on future tax assets and liabilities is recognized in
net income in the period in which the change is substantively
enacted. (j) Unit-based compensation Advantage accounts for
compensation expense based on the "fair value" of rights granted
under its unit-based compensation plans. The Fund has Trust Units
held in escrow relating to the management internalization (note
14), a unit-based compensation plan for external directors of the
Fund, and a Restricted Trust Unit Plan (note 11). The escrowed
Trust Units relating to the management internalization vest equally
over three years, the period during which employees are required to
provide service to receive the Trust Units. Therefore, the
management internalization consideration is being deferred and
amortized into income as management internalization expense over
the specific vesting periods during which employee services are
provided, including an estimate of future Trust Unit forfeitures.
Awards under the external directors' unit-based compensation plan
vest immediately with associated compensation expense recognized in
the current period earnings and estimated forfeiture rates are not
incorporated in the determination of fair value. The compensation
expense results in the creation of contributed surplus until the
rights are exercised. Consideration paid upon the exercise of the
rights together with the amount previously recognized in
contributed surplus is recorded as an increase in Unitholders'
capital. Advantage's current employee compensation includes a
Restricted Trust Unit Plan (the "Plan"), as approved by the
Unitholders on June 23, 2006, and Trust Units issuable for the
retention of certain employees of the Fund. The Plan authorizes the
Board of Directors to grant Restricted Trust Units ("RTUs") to
directors, officers, or employees of the Fund. The number of RTUs
granted is based on the Fund's Trust Unit return for a calendar
year and compared to a peer group approved by the Board of
Directors. The Trust Unit return is calculated at the end of the
year and is primarily based on the year-over-year change in the
Trust Unit price plus distributions. If the Trust Unit return for a
year is positive, an RTU grant will be calculated based on the
return and market capitalization. If the Trust Unit return for a
year is negative, but the return is still within the top two-thirds
of the approved peer group performance, the Board of Directors may
choose a discretionary RTU grant. The RTU grants vest one third
immediately on grant date, with the remaining two thirds vesting
evenly on the following two yearly anniversary dates. The holders
of RTUs may elect to receive cash upon vesting in lieu of the
number of Trust Units to be issued, subject to consent of the Fund.
Compensation cost related to the Plan is recognized as compensation
expense over the service period and incorporates the Trust Unit
grant price, the estimated number of RTUs to vest, and certain
management estimates. The maximum amount of RTUs granted in any one
calendar year is limited to 175% of the base salaries of those
individuals participating in the Plan for such period. (k) Revenue
recognition Revenue associated with the sale of crude oil, natural
gas and natural gas liquids is recognized when the title and risks
pass to the purchaser, normally at the pipeline delivery point for
natural gas and at the wellhead for crude oil. (l) Per Trust Unit
amounts Net loss per Trust Unit is calculated using the weighted
average number of Trust Units outstanding during the year. Diluted
net loss per Trust Unit is calculated using the "if-converted"
method to determine the dilutive effect of convertible debentures
and the "treasury stock" method for trust unit rights granted to
directors, management internalization escrowed Trust Units and
Restricted Trust Units. (m) Measurement uncertainty The amounts
recorded for depletion and depreciation of fixed assets, the
provision for asset retirement obligation costs and related
accretion expense, impairment calculations for fixed assets and
goodwill, derivative fair value calculations, future income tax
provisions, as well as fair values assigned to any identifiable
assets and liabilities in business combinations are based on
estimates. These estimates are significant and include proved and
probable reserves, future production rates, future crude oil and
natural gas prices, future costs, future interest rates, fair value
assessments, and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the effect on
the consolidated financial statements of changes in such estimates
in future years could be material. (n) Capital disclosures
Effective January 1, 2008, the Fund adopted CICA Handbook Section
1535, Capital Disclosures. This Section establishes standards for
disclosing information about an entity's capital and how it is
managed to enable users of financial statements to evaluate the
entity's objectives, policies and procedures for managing capital.
The adoption of this Section requires that information on capital
management be included in the notes to the consolidated financial
statements (see note 15). This new standard does not have any
effect on the Fund's financial position or results of operations.
(o) Recent accounting pronouncements issued but not implemented (i)
Goodwill and intangible assets In February 2008, the CICA issued
Section 3064, Goodwill and Intangible Assets, replacing Section
3062, Goodwill and Other Intangible Assets and Section 3450,
Research and Development Costs. The new Section will become
effective January 1, 2009. Management has evaluated the new Section
and there will be no impact for the financial statements of the
Fund. (ii) International Financial Reporting Standards ("IFRS") In
February 2008, the CICA Accounting Standards Board confirmed that
IFRS will replace Canadian GAAP effective January 1, 2011 for
publicly accountable enterprises. Management is currently
evaluating the effects of all current and pending pronouncements of
the International Accounting Standards Board on the financial
statements of the Fund, and has developed a plan for
implementation. (p) Comparative figures Certain comparative figures
have been reclassified to conform to the current year's
presentation. 3. Sound Energy Trust Acquisition On September 5,
2007, Advantage acquired all of the issued and outstanding Trust
Units and Exchangeable Shares of Sound Energy Trust ("Sound") for
$21.4 million cash consideration, 16,977,184 Advantage Trust Units
and $0.9 million of acquisition costs. Sound Unitholders and
Exchangeable Shareholders elected to receive either 0.30 Advantage
Trust Units for each Sound Trust Unit or $0.66 in cash and 0.2557
Advantage Trust Units for each Sound Trust Unit. All of the Sound
Exchangeable Shares were exchanged for Advantage Trust Units on the
same ratio as the Sound Trust Units based on the conversion ratio
in effect at the effective date of the acquisition. Sound was an
energy trust engaged in the development, acquisition and production
of natural gas and crude oil in western Canada. The acquisition was
accounted for using the "purchase method" with the results of
operations included in the consolidated financial statements as of
the closing date of the acquisition. The purchase price has been
allocated as follows: Net assets acquired and Consideration:
liabilities assumed: Fixed assets $ 514,060 16,977,184 Trust
Accounts receivable 27,656 Units issued $ 228,852 Prepaid expenses
and Cash 21,403 deposits 3,873 Acquisition costs Derivative asset,
net 2,797 incurred 904 Bank indebtedness (107,959) -----------
Convertible debentures (101,553) $ 251,159 Accounts payable and
----------- accrued liabilities (40,023) Future income taxes
(29,430) Asset retirement obligations (16,695) Capital lease
obligations (1,567) ----------- $ 251,159 ----------- The value of
the Trust Units issued as consideration was determined based on the
weighted average trading value of Advantage Trust Units during the
two-day period before and after the terms of the acquisition were
agreed to and announced. The allocation of the purchase price has
been revised in 2008 due to the realization of estimates. As a
result, fixed assets increased $4.4 million, accounts receivable
increased $0.2 million, and accounts payable and accrued
liabilities increased $4.6 million. 4. Fixed Assets Accumulated
Depletion and Net Book December 31, 2008 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas properties $ 3,299,657 $ 1,140,710 $
2,158,947 Furniture and equipment 11,572 6,653 4,919
---------------------------------------------------------------------
$ 3,311,229 $ 1,147,363 $ 2,163,866
---------------------------------------------------------------------
Accumulated Depletion and Net Book December 31, 2007 Cost
Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas properties $ 3,016,243 $ 844,671 $
2,171,572 Furniture and equipment 10,548 4,774 5,774
---------------------------------------------------------------------
$ 3,026,791 $ 849,445 $ 2,177,346
---------------------------------------------------------------------
During the year ended December 31, 2008, Advantage capitalized
general and administrative expenditures directly related to
exploration and development activities of $11,127,000 (2007 -
$9,653,000). Costs of $68,267,000 (2007 - $60,238,000) for unproved
properties have been excluded from the calculation of depletion
expense, and future development costs of $378,242,000 (2007 -
$190,146,000) have been included in costs subject to depletion. The
Fund performed a ceiling test calculation at December 31, 2008 to
assess the recoverable value of fixed assets. Based on the
calculation, the carrying amounts are recoverable as compared to
the sum of the undiscounted net cash flows expected from the
production of proved reserves based on the following benchmark
prices: WTI Crude Oil Exchange Rate AECO Gas Year ($US/bbl)
($US/$Cdn) ($Cdn/mmbtu)
---------------------------------------------------------------------
2009 $ 53.73 $ 0.80 $ 6.82 2010 $ 63.41 $ 0.85 $ 7.56 2011 $ 69.53
$ 0.85 $ 7.84 2012 $ 79.59 $ 0.90 $ 8.38 2013 $ 92.01 $ 0.95 $ 9.20
2014 $ 93.85 $ 0.95 $ 9.41
---------------------------------------------------------------------
Approximate escalation rate after 2014 2.0% - 2.0%
---------------------------------------------------------------------
Benchmark prices are adjusted for a variety of factors such as
quality differentials to determine the expected price to be
realized by the Fund when performing the ceiling test calculation.
5. Goodwill The Fund frequently assesses goodwill impairment which
is effectively a comparison of the fair value of the Fund to the
values assigned to the identifiable assets and liabilities. The
fair value of the Fund is typically determined by reference to the
market capitalization adjusted for a number of potential valuation
factors. The values of the identifiable assets and liabilities
include the current assessed value of our reserves and other assets
and liabilities. Near the end of 2008, Advantage and the entire oil
and gas industry, experienced a substantial decline in market
capitalization as a result of the worldwide recession, resulting
soft commodity prices, and general negative market reaction. As a
result, the entire balance of goodwill was determined to be
impaired at December 31, 2008, as there is no market perception of
goodwill. Year ended Year ended December 31, December 31, 2008 2007
---------------------------------------------------------------------
Balance, beginning of year $ 120,271 $ 120,271 Impairment (120,271)
-
---------------------------------------------------------------------
Balance, end of year $ - $ 120,271
---------------------------------------------------------------------
6. Capital Lease Obligations The Fund has capital leases on a
variety of fixed assets. Future minimum lease payments at December
31, 2008 consist of the following: 2009 $ 2,040 2010 2,200 2011
1,925 ---------------------------------------------- 6,165 Less
amounts representing interest (512)
---------------------------------------------- 5,653 Current
portion (1,747) ---------------------------------------------- $
3,906 ---------------------------------------------- During the
second quarter of 2007, Advantage entered a new lease arrangement
that resulted in the recognition of a fixed asset addition and
capital lease obligation of $4.1 million. The lease obligation
bears interest at 5.8% and is secured by the related equipment. The
lease term expires June 2011 with a final purchase obligation of
$1.5 million at which time ownership of the equipment will transfer
to Advantage. Effective September 4, 2007, Advantage entered a new
lease arrangement that resulted in the recognition of a fixed asset
addition and capital lease obligation of $1.8 million. The lease
obligation bears interest at 6.7% and is secured by the related
equipment. The lease term expires August 2010 with a final payment
obligation of $0.7 million. Distributions to Unitholders are not
permitted if the Fund is in default of such capital lease. On
September 5, 2007, Advantage assumed two capital lease obligations
in the acquisition of Sound (note 3) resulting in the recognition
of capital lease obligations of $1.6 million. Both of the lease
obligations bear interest at 5.6% and are secured by the related
equipment. The lease terms expire December 2009 and April 2010 with
a total final payment obligation of $0.9 million. Fixed assets
subject to capital leases are depreciated on a "unit-of-
production" basis over the life of the reserves consistent with the
Fund's depletion and depreciation policy for petroleum and natural
gas properties and is included in depletion, depreciation and
accretion expense. 7. Convertible Debentures The convertible
unsecured subordinated debentures pay interest semi- annually and
are convertible at the option of the holder into Trust Units of
Advantage at the applicable conversion price per Trust Unit plus
accrued and unpaid interest. The details of the convertible
debentures including fair market values initially assigned and
issuance costs are as follows: 10.00% 9.00% 8.25% 8.75%
----------------------------------------------------------- Trading
symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF Issue date Oct 18, July 8,
Dec 2, June 10, 2002 2003 2003 2004 Maturity date Matured Matured
Feb. 1, June 30, 2009 2009 Conversion price Matured Matured $ 16.50
$ 34.67 Liability component $ 52,722 $ 28,662 $ 56,802 $ 48,700
Equity component 2,278 1,338 3,198 11,408
----------------------------------------------------------- Gross
proceeds 55,000 30,000 60,000 60,108 Issuance costs (2,495) (1,444)
(2,588) -
----------------------------------------------------------- Net
proceeds $ 52,505 $ 28,556 $ 57,412 $ 60,108
----------------------------------------------------------- 7.50%
6.50% 7.75% 8.00% Total
---------------------------------------------------------------------
Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG Issue date Sep. 15,
May 18, Sept 15, Nov 13, 2004 2005 2004 2006 Maturity date Oct. 1,
June 30, Dec. 1, Dec. 31, 2009 2010 2011 2011 Conversion price $
20.25 $ 24.96 $ 21.00 $ 20.33 Liability component $ 71,631 $ 66,981
$ 47,444 $ 14,884 $387,826 Equity component 3,369 2,971 2,556
26,561 53,679
---------------------------------------------------------------------
Gross proceeds 75,000 69,952 50,000 41,445 441,505 Issuance costs
(3,190) - (2,190) - (11,907)
---------------------------------------------------------------------
Net proceeds $ 71,810 $ 69,952 $ 47,810 $ 41,445 $429,598
---------------------------------------------------------------------
The convertible debentures are redeemable prior to their maturity
dates, at the option of the Fund, upon providing 30 to 60 days
advance notification. The redemption prices for the various
debentures, plus accrued and unpaid interest, is dependent on the
redemption periods and are as follows: Convertible Redemption
Debenture Redemption Periods Price
---------------------------------------------------------------------
8.25% After February 1, 2008 and before February 1, 2009 $1,025
---------------------------------------------------------------------
8.75% After June 30, 2008 and before June 30, 2009 $1,025
---------------------------------------------------------------------
7.50% After October 1, 2008 and before October 1, 2009 $1,025
---------------------------------------------------------------------
6.50% After June 30, 2008 and on or before June 30, 2009 $1,050
After June 30, 2009 and before June 30, 2010 $1,025
---------------------------------------------------------------------
7.75% After December 1, 2008 and on or before December 1, 2009
$1,025 After December 1, 2009 and before December 1, 2011 $1,000
---------------------------------------------------------------------
8.00% After December 31, 2009 and on or before December 31, 2010
$1,050 After December 31, 2010 and before December 31, 2011 $1,025
---------------------------------------------------------------------
The balance of debentures outstanding at December 31, 2008 and
changes in the liability and equity components during the years
ended December 31, 2008 and 2007 are as follows: 10.00% 9.00% 8.25%
8.75% -----------------------------------------------------------
Trading symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF Debentures
outstanding $ - $ - $ 4,867 $ 29,839
-----------------------------------------------------------
Liability component: Balance at December 31, 2006 $ 1,464 $ 5,235 $
4,676 $ - Assumed on Sound acquisition - - - 48,700 Accretion of
discount 22 98 91 96 Converted to Trust Units (1,486) - - (8)
Redeemed for cash - - - (19,406)
----------------------------------------------------------- Balance
at December 31, 2007 $ - $ 5,333 $ 4,767 $ 29,382 Accretion of
discount - 59 92 305 Converted to Trust Units - - - - Matured -
(5,392) - -
----------------------------------------------------------- Balance
at December 31, 2008 $ - $ - $ 4,859 $ 29,687
----------------------------------------------------------- Equity
component: Balance at December 31, 2006 $ 59 $ 229 $ 248 $ -
Assumed on Sound acquisition - - - 11,408 Converted to Trust Units
- - - (10,556) Expired (59) - - -
----------------------------------------------------------- Balance
at December 31, 2007 $ - $ 229 $ 248 $ 852 Converted to Trust Units
- - - - Expired - (229) - -
----------------------------------------------------------- Balance
at December 31, 2008 $ - $ - $ 248 $ 852
----------------------------------------------------------- 7.50%
6.50% 7.75% 8.00% Total
---------------------------------------------------------------------
Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG Debentures
outstanding $ 52,268 $ 69,927 $ 46,766 $ 15,528 $219,195
---------------------------------------------------------------------
Liability component: Balance at December 31, 2006 $ 49,782 $ 67,361
$ 43,765 $ - $172,283 Assumed on Sound acquisition - - - 14,884
63,584 Accretion of discount 889 731 595 47 2,569 Converted to
Trust Units - - - - (1,494) Redeemed for cash - - - - (19,406)
---------------------------------------------------------------------
Balance at December 31, 2007 $ 50,671 $ 68,092 $ 44,360 $ 14,931
$217,536 Accretion of discount 908 740 604 147 2,855 Converted to
Trust Units - (25) - - (25) Matured - - - - (5,392)
---------------------------------------------------------------------
Balance at December 31, 2008 $ 51,579 $ 68,807 $ 44,964 $ 15,078
$214,974
---------------------------------------------------------------------
Equity component: Balance at December 31, 2006 $ 2,248 $ 2,971 $
2,286 $ - $ 8,041 Assumed on Sound acquisition - - - 26,561 37,969
Converted to Trust Units - - - (25,763) (36,319) Expired - - - -
(59)
---------------------------------------------------------------------
Balance at December 31, 2007 $ 2,248 $ 2,971 $ 2,286 $ 798 $ 9,632
Converted to Trust Units - - - - - Expired - - - - (229)
---------------------------------------------------------------------
Balance at December 31, 2008 $ 2,248 $ 2,971 $ 2,286 $ 798 $ 9,403
---------------------------------------------------------------------
Due to the acquisition of Sound (note 3), 8.75% and 8.00%
convertible debentures were assumed by Advantage on September 5,
2007. As a result of the change in control of Sound, the Fund was
required by the debenture indentures to make an offer to purchase
all of the outstanding convertible debentures assumed from Sound at
a price equal to 101% of the principal amount plus accrued and
unpaid interest. On October 17, 2007, the expiry date of the offer,
911,709 Trust Units were issued and $19.9 million in total cash
consideration was paid in exchange for $29,665,000 8.75%
convertible debentures and 2,220,289 Trust Units were issued in
exchange for $25,507,000 8.0% convertible debentures. During the
year ended December 31, 2008, $25,000 debentures (2007 - $24,000)
were converted resulting in the issuance of 1,001 Trust Units (2007
- 1,386 Trust Units). The principal amount of 9.00% convertible
debentures matured on August 1, 2008 and the Fund settled the
obligation by payment of $5.4 million in cash. 8. Bank Indebtedness
Advantage has a credit facility agreement with a syndicate of
financial institutions which provides for a $690 million extendible
revolving loan facility and a $20 million operating loan facility.
The loan's interest rate is based on either prime, US base rate,
LIBOR or bankers' acceptance rates, at the Fund's option, subject
to certain basis point or stamping fee adjustments ranging from
0.00% to 1.50% depending on the Fund's debt to cash flow ratio. The
credit facilities are collateralized by a $1 billion floating
charge demand debenture, a general security agreement and a
subordination agreement from the Fund covering all assets and cash
flows. The credit facilities are subject to review on an annual
basis with the next renewal due in June 2009. Various borrowing
options are available under the credit facilities, including prime
rate-based advances, US base rate advances, US dollar LIBOR
advances and bankers' acceptances loans. The credit facilities
constitute a revolving facility for a 364 day term which is
extendible annually for a further 364 day revolving period at the
option of the syndicate. If not extended, the revolving credit
facility is converted to a two year term facility with the
principal payable at the end of such two year term. The credit
facilities contain standard commercial covenants for facilities of
this nature. The only financial covenant is a requirement for AOG
to maintain a minimum cash flow to interest expense ratio of 3.5:1,
determined on a rolling four quarter basis. The credit facilities
also prohibit the Fund from entering into any derivative contract
where the term of such contract exceeds two years or the aggregate
of such contracts hedge greater than 60% of the Fund's estimated
oil and gas production. Breach of any covenant will result in an
event of default in which case AOG has 20 days to remedy such
default. If the default is not remedied or waived, and if required
by the majority of lenders, the administrative agent of the lenders
has the option to declare all obligations of AOG under the credit
facilities to be immediately due and payable without further
demand, presentation, protest, or notice of any kind. Distributions
by AOG to the Fund (and effectively by the Fund to Unitholders) are
subordinated to the repayment of any amounts owing under the credit
facilities. Distributions to Unitholders are not permitted if the
Fund is in default of such credit facilities or if the amount of
the Fund's outstanding indebtedness under such facilities exceeds
the then existing current borrowing base. Interest payments under
the debentures are also subordinated to indebtedness under the
credit facilities and payments under the debentures are similarly
restricted. For the year ended December 31, 2008, the effective
interest rate on the outstanding amounts under the facility was
approximately 5.0% (2007 - 5.7%). 9. Asset Retirement Obligations
The Fund's asset retirement obligations result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Fund estimates the
total undiscounted and inflated amount of cash flows required to
settle its asset retirement obligations is approximately $249.9
million which will be incurred between 2009 and 2058. A credit-
adjusted risk-free rate of 7% and an inflation factor of 2% were
used to calculate the fair value of the asset retirement
obligations. A reconciliation of the asset retirement obligations
is provided below: Year ended Year ended December 31, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of year $ 60,835 $ 34,324 Accretion expense
4,186 2,795 Assumed in Sound acquisition - 16,695 Liabilities
incurred 1,526 1,640 Change in estimates 16,564 12,332 Liabilities
settled (9,259) (6,951)
---------------------------------------------------------------------
Balance, end of year $ 73,852 $ 60,835
---------------------------------------------------------------------
10. Income Taxes The taxable income of the Fund is comprised of
interest income related to the AOG Notes and royalty income from
the AOG Royalty less deductions for Canadian Oil and Gas Property
Expense, Trust Unit issue costs, and interest on convertible
debentures. Given that taxable income of the Fund is allocated to
the Unitholders, no provision for current income taxes relating to
the Fund is included in these financial statements. On December 14,
2007, the Federal government enacted legislation phasing in
corporate income tax rate reductions which will reduce federal tax
rates from 22.1% to 15.0% by 2012. Rate reductions will also apply
to the new tax on distributions of income trusts and other
specified investment flow-through entities as of 2011, reducing the
tax rate in 2011 to 29.5% and in 2012 to 28.0%. These rates include
a deemed provincial rate of 13%. The provision for income taxes
varies from the amount that would be computed by applying the
combined Canadian federal and provincial income tax rates for the
following reasons: Year ended Year ended December 31, December 31,
2008 2007
---------------------------------------------------------------------
Loss before taxes $ (28,896) $ (30,733)
---------------------------------------------------------------------
Canadian combined federal and provincial income tax rates 29.79%
32.57% Expected income tax recovery at statutory rates (8,608)
(10,011) Increase (decrease) in income taxes resulting from:
Amounts included in trust income (58,587) (70,097) Change in
enacted tax rates - 550 Management internalization 1,798 5,507
Specified Investment Flow-Through - 42,862 Impairment of goodwill
35,833 - Difference between current and expected rates 18,376
11,297 Other 376 (4,750)
---------------------------------------------------------------------
Future income tax reduction (10,812) (24,642) Income and capital
taxes 2,493 1,444
---------------------------------------------------------------------
$ (8,319) $ (23,198)
---------------------------------------------------------------------
The components of the future income tax liability are as follows:
December 31, December 31, 2008 2007
---------------------------------------------------------------------
Fixed assets in excess of tax basis $ 9,463 $ 29,240 Asset
retirement obligations (21,475) (16,330) Non-capital tax loss carry
forward (21,541) (20,369) Trust assets in excess of tax basis
84,017 82,642 Net derivative assets 11,970 651 Other (6,519)
(9,107)
---------------------------------------------------------------------
Future income tax liability $ 55,915 $ 66,727
---------------------------------------------------------------------
Current future income tax liability $ 11,939 $ 1,430 Long-term
future income tax liability 43,976 65,297
---------------------------------------------------------------------
$ 55,915 $ 66,727
---------------------------------------------------------------------
AOG has a non-capital loss carry forward of approximately $75
million of which $18 million expires in 2011, $11 million in 2012
and $46 million after 2020. 11. Unitholders' Equity (a)
Unitholders' capital (i) Authorized Unlimited number of voting
Trust Units (ii) Issued Number of Units Amount
---------------------------------------------------------------------
Balance at December 31, 2006 105,390,470 $ 1,618,025 Issued on
conversion of debentures 128,879 1,494 Issued on exercise of Trust
Unit rights 37,500 562 Issued for cash, net of costs 8,600,000
104,094 Distribution reinvestment plan 4,028,252 46,657 Issued for
Sound acquisition, net of costs (note 3) 16,977,184 228,583 Issued
on offer to purchase Sound debentures (note 7) 3,131,998 37,209
Management internalization forfeitures (24,909) (503)
---------------------------------------------------------------------
Balance at December 31, 2007 138,269,374 2,036,121 Distribution
reinvestment plan 4,414,830 39,884 Issued for cash, net of costs -
(42) Issued on conversion of debentures 1,001 25 Issued on exercise
of Trust Unit rights 150,000 1,981 Management internalization
forfeitures (10,351) (209)
---------------------------------------------------------------------
142,824,854 $ 2,077,760
---------------------------------------------------------------------
Management internalization escrowed Trust Units (1,883)
---------------------------------------------------------------------
Balance at December 31, 2008 $ 2,075,877
---------------------------------------------------------------------
On June 23, 2006, Advantage internalized the external management
contract structure and eliminated all related fees for total
original consideration of 1,933,208 Advantage Trust Units initially
valued at $39.1 million and subject to escrow provisions over a
3-year period, vesting one-third each year beginning June 23, 2007.
For the year ended December 31, 2008, a total of 10,351 Trust Units
issued for the management internalization were forfeited (2007 -
24,909 Trust Units) and $7.0 million has been recognized as
management internalization expense (2007 - $15.7 million). As at
December 31, 2008, 564,612 Trust Units remain held in escrow
(December 31, 2007 - 1,193,622 Trust Units). On July 24, 2006,
Advantage announced that it adopted a Premium Distribution(TM),
Distribution Reinvestment and Optional Trust Unit Purchase Plan
(the "Plan"). For eligible Unitholders that elect to participate in
the Plan, Advantage will settle the monthly distribution obligation
through the issuance of additional Trust Units at 95% of the
Average Market Price (as defined in the Plan). Unitholder
enrollment in the Premium Distribution(TM) component of the Plan
effectively authorizes the subsequent disposal of the issued Trust
Units in exchange for a cash payment equal to 102% of the cash
distributions that the Unitholder would otherwise have received if
they did not participate in the Plan. During the year ended
December 31, 2008, 4,414,830 Trust Units (2007 - 4,028,252 Trust
Units) were issued under the Plan, generating $39.9 million (2007 -
$46.7 million) reinvested in the Fund. On February 14, 2007
Advantage issued 7,800,000 Trust Units, plus an additional 800,000
Trust Units upon exercise of the Underwriters' over-allotment
option on March 7, 2007, at $12.80 per Trust Unit for approximate
net proceeds of $104.1 million (net of Underwriters' fees and other
issue costs of $6.0 million). On September 5, 2007, Advantage
issued 16,977,184 Trust Units, valued at $228.9 million, as partial
consideration for the acquisition of Sound (note 3). Trust Unit
issuance costs of $0.3 million were incurred for the Sound
acquisition. Due to the acquisition of Sound (note 3), 8.75% and
8.00% convertible debentures were assumed by Advantage on September
5, 2007. As a result of the change in control of Sound, the Fund
was required by the debenture indentures to make an offer to
purchase all of the outstanding convertible debentures assumed from
Sound at a price equal to 101% of the principal amount plus accrued
and unpaid interest. On October 17, 2007, the expiry date of the
offer, 911,709 Trust Units were issued and $19.9 million in total
cash consideration was paid in exchange for $29,665,000 8.75%
convertible debentures and 2,220,289 Trust Units were issued in
exchange for $25,507,000 8.0% convertible debentures. (b)
Contributed surplus Year ended Year ended December 31, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of year $ 2,005 $ 863 Unit-based compensation
(1,256) 1,255 Expiration of convertible debentures equity component
229 59 Exercise of Trust Unit Rights (691) (172)
---------------------------------------------------------------------
Balance, end of year $ 287 $ 2,005
---------------------------------------------------------------------
(c) Trust Units Rights Incentive Plan Effective June 25, 2002, a
Trust Units Rights Incentive Plan for external directors of the
Fund was established and approved by the Unitholders of Advantage.
A total of 500,000 Trust Units were reserved for issuance under the
plan with an aggregate of 400,000 rights granted since inception.
At December 31, 2007, 150,000 rights remained outstanding under the
plan, all of which were exercised at $8.60 per right in 2008 for
total cash proceeds of $1,290,000. Contributed surplus of $691,000
in respect of these rights has been transferred to Unitholders'
capital. No Trust Unit Rights are outstanding as of December 31,
2008. Number Price
---------------------------------------------------------------------
Balance at December 31, 2006 187,500 $ 10.97 Exercised (37,500) -
Reduction of exercise price - (1.77)
---------------------------------------------------------------------
Balance at December 31, 2007 150,000 9.20 Exercised (150,000) -
Reduction of exercise price - (0.60)
---------------------------------------------------------------------
Balance at December 31, 2008 - $ 8.60
---------------------------------------------------------------------
(d) Unit-based compensation Advantage's current employee
compensation includes a Restricted Trust Unit Plan, as approved by
the Unitholders on June 23, 2006. The purpose of the long-term
compensation plan is to retain and attract employees, to reward and
encourage performance, and to focus employees on operating and
financial performance that results in lasting Unitholder return.
Although Advantage experienced a negative return for the 2008 year,
the approved peer group also experienced likewise negative returns.
As a result, Advantage's 2008 annual return was within the top two-
thirds of the approved peer group and the Board of Directors
granted Restricted Trust Units at their discretion. The RTU was
deemed to be granted at January 15, 2009 and was valued at $3.8
million to be issued in Trust Units at $5.49 per Trust Unit. No
compensation expense was included in general and administration
expense for the year ended December 31, 2008 as the RTU was granted
after year-end. A total of 171,093 Trust Units were issued to
employees in early 2009 in satisfaction of the first third of the
grant that vested immediately. The remaining two-thirds of the RTU
grant will vest evenly on the following two yearly anniversary
dates. Since implementing the Plan in 2006, the grant thresholds
have not been previously met, and there have been no RTU grants
made during prior years and no related compensation expense has
been recognized. (e) Net loss per Trust Unit The calculations of
basic and diluted net loss per Trust Unit are derived from both
loss available to Unitholders and weighted average Trust Units
outstanding calculated as follows: Year ended Year ended December
31, December 31, 2008 2007
---------------------------------------------------------------------
Loss available to Unitholders Basic and diluted $ (20,577) $
(7,535)
---------------------------------------------------------------------
Weighted average Trust Units outstanding Basic and diluted
139,483,151 119,604,019
---------------------------------------------------------------------
The calculation of diluted net loss per Trust Unit excludes all
series of convertible debentures for the years as the impact would
be anti-dilutive. Total weighted average Trust Units issuable in
exchange for the convertible debentures and excluded from the
diluted net loss per Trust Unit calculation for the year ended
December 31, 2008 were 9,713,840 (2007 - 9,083,663 Trust Units). As
at December 31, 2008, the total convertible debentures outstanding
were immediately convertible to 9,529,075 Trust Units (2007 -
9,847,253 Trust Units). All of the Trust Unit Rights and Management
Internalization escrowed Trust Units have been excluded from the
calculations of diluted net loss per Trust Unit for the years ended
December 31, 2008, and 2007 as the impacts would be anti-dilutive.
Total weighted average Trust Units issuable in exchange for the
Trust Unit Rights and Management Internalization escrowed Trust
Units and excluded from the diluted net loss per Trust Unit
calculation for the year ended December 31, 2008 were 8,795 and
576,827, respectively (year ended December 31, 2007 - 42,918 and
582,861 Trust Units, respectively). 12. Accumulated Deficit
Accumulated deficit consists of accumulated income and accumulated
distributions for the Fund since inception as follows: December 31,
December 31, 2008 2007
---------------------------------------------------------------------
Accumulated Income $ 199,411 $ 219,988 Accumulated Distributions
(1,076,465) (879,823)
---------------------------------------------------------------------
Accumulated Deficit $ (877,054) $ (659,835)
---------------------------------------------------------------------
The Fund has historically paid distributions in excess of
accumulated income as distributions are typically based on cash
flows generated in the period while accumulated income is based on
such cash flows less other non-cash charges such as depletion,
depreciation, and accretion expense recorded on the original
investment in petroleum and natural gas properties, management
internalization expense and other asset impairments. For the year
ended December 31, 2008 the Fund declared $196.6 million in
distributions representing $1.40 per distributable Trust Unit (2007
- $215.2 million in distributions representing $1.77 per
distributable Trust Unit). 13. Financial Instruments Financial
instruments of the Fund include accounts receivable, deposits,
accounts payable and accrued liabilities, distributions payable to
Unitholders, bank indebtedness, convertible debentures and
derivative assets and liabilities. Accounts receivable and deposits
are classified as loans and receivables and measured at amortized
cost. Accounts payable and accrued liabilities, distributions
payable to Unitholders and bank indebtedness are all classified as
other liabilities and similarly measured at amortized cost. As at
December 31, 2008, there were no significant differences between
the carrying amounts reported on the balance sheet and the
estimated fair values of these financial instruments due to the
short terms to maturity and the floating interest rate on the bank
indebtedness. The Fund has convertible debenture obligations
outstanding, of which the liability component has been classified
as other liabilities and measured at amortized cost. The
convertible debentures have different fixed terms and interest
rates (note 7) resulting in fair values that will vary over time as
market conditions change. As at December 31, 2008, the estimated
fair value of the total outstanding convertible debenture
obligation was $191.2 million (December 31, 2007 - $215.4 million).
The fair value of convertible debentures was determined based on
the current public trading activity of such debentures. Advantage
has an established strategy to manage the risk associated with
changes in commodity prices by entering into derivatives, which are
recorded at fair value as derivative assets and liabilities with
gains and losses recognized through earnings. As the fair value of
the contracts varies with commodity prices, they give rise to
financial assets and liabilities. The fair values of the
derivatives are determined through valuation models completed
internally and by third parties. Various assumptions based on
current market information were used in these valuations, including
settled forward commodity prices, interest rates, foreign exchange
rates, volatility and other relevant factors. The actual gains and
losses realized on eventual cash settlement can vary materially due
to subsequent fluctuations in commodity prices as compared to the
valuation assumptions. Credit Risk Accounts receivable, deposits,
and derivative assets are subject to credit risk exposure and the
carrying values reflect Management's assessment of the associated
maximum exposure to such credit risk. Advantage mitigates such
credit risk by closely monitoring significant counterparties and
dealing with a broad selection of partners that diversify risk
within the sector. The Fund's deposits are primarily due from the
Alberta Provincial government and are viewed by Management as
having minimal associated credit risk. To the extent that Advantage
enters derivatives to manage commodity price risk, it may be
subject to credit risk associated with counterparties with which it
contracts. Credit risk is mitigated by entering into contracts with
only stable, creditworthy parties and through frequent reviews of
exposures to individual entities. In addition, the Fund only enters
into derivative contracts with major national banks and
international energy firms to further mitigate associated credit
risk. Substantially all of the Fund's accounts receivable are due
from customers and joint operation partners concentrated in the
Canadian oil and gas industry. As such, accounts receivable are
subject to normal industry credit risks. As at December 31, 2008,
$14.2 million or 17% of accounts receivable are outstanding for 90
days or more. The Fund believes that the entire balance is
collectible, and in some instances we have the ability to mitigate
risk through withholding production or offsetting payables with the
same parties. Accordingly, management has not provided for an
allowance for doubtful accounts at December 31, 2008. Liquidity
Risk The Fund is subject to liquidity risk attributed from accounts
payable and accrued liabilities, distributions payable to
Unitholders, bank indebtedness, convertible debentures, and
derivative liabilities. Accounts payable and accrued liabilities,
distributions payable to Unitholders and derivative liabilities are
primarily due within one year of the balance sheet date and
Advantage does not anticipate any problems in satisfying the
obligations due to the strength of cash provided by operating
activities and the existing credit facility. The Fund's bank
indebtedness is subject to a $710 million credit facility
agreement. Although the credit facility is a source of liquidity
risk, the facility also mitigates liquidity risk by enabling
Advantage to manage interim cash flow fluctuations. The credit
facility constitutes a revolving facility for a 364 day term which
is extendible annually for a further 364 day revolving period at
the option of the syndicate. If not extended, the revolving credit
facility is converted to a two year term facility with the
principal payable at the end of such two year term. The terms of
the credit facility are such that it provides Advantage adequate
flexibility to evaluate and assess liquidity issues if and when
they arise. Additionally, the Fund regularly monitors liquidity
related to obligations by evaluating forecasted cash flows, optimal
debt levels, capital spending activity, working capital
requirements, and other potential cash expenditures. This continual
financial assessment process further enables the Fund to mitigate
liquidity risk. Advantage has several series of convertible
debentures outstanding that mature from 2009 to 2011 (note 7).
Interest payments are made semi-annually with excess cash provided
by operating activities. As the debentures become due, the Fund can
satisfy the obligations in cash or issue Trust Units at a price
determined in the applicable debenture agreements. This settlement
alternative allows the Fund to adequately manage liquidity, plan
available cash resources and implement an optimal capital
structure. To the extent that Advantage enters derivatives to
manage commodity price risk, it may be subject to liquidity risk as
derivative liabilities become due. While the Fund has elected not
to follow hedge accounting, derivative instruments are not entered
for speculative purposes and Management closely monitors existing
commodity risk exposures. As such, liquidity risk is mitigated
since any losses actually realized are subsidized by increased cash
flows realized from the higher commodity price environment. The
timing of cash outflows relating to financial liabilities are as
follows: One to Four Less than three to five one year years years
Thereafter Total
---------------------------------------------------------------------
Accounts payable and accrued liabilities $ 146,046 $ - $ - $ - $
146,046 Distributions payable to Unitholders 11,426 - - - 11,426
Derivative liabilities 611 1,039 - - 1,650 Bank indebtedness -
principal - 587,404 - - 587,404 Bank indebtedness - interest 25,242
37,863 - - 63,105 Convertible debentures - principal 86,974 132,221
- - 219,195 Convertible debentures - interest 14,838 12,005 - -
26,843
---------------------------------------------------------------------
$ 285,137 $ 770,532 $ - $ - $1,055,669
---------------------------------------------------------------------
The Fund's bank indebtedness does not have specific maturity dates.
It is governed by a credit facility agreement with a syndicate of
financial institutions (note 8). Under the terms of the agreement,
the facility is reviewed annually, with the next review scheduled
in June 2009. The facility is revolving, and is extendible at each
annual review for a further 364 day period at the option of the
syndicate. If not extended, the credit facility is converted at
that time into a two year term facility, with the principal payable
at the end of such two year term. Management fully expects that the
facility will be extended at each annual review. Interest Rate Risk
The Fund is exposed to interest rate risk to the extent that bank
indebtedness is at a floating rate of interest and the Fund's
maximum exposure to interest rate risk is based on the effective
interest rate and the current carrying value of the bank
indebtedness. The Fund monitors the interest rate markets to ensure
that appropriate steps can be taken if interest rate volatility
compromises the Fund's cash flows. A 1% increase in interest rate
for the year ended December 31, 2008 could have increased net loss
by approximately $4.2 million for that period (year ended December
31, 2007 - $3.0 million). Price and Currency Risk Advantage's
derivative assets and liabilities are subject to both price and
currency risks as their fair values are based on assumptions
including forward commodity prices and foreign exchange rates. The
Fund enters derivative financial instruments to manage commodity
price risk exposure relative to actual commodity production and
does not utilize derivative instruments for speculative purposes.
Changes in the price assumptions can have a significant effect on
the fair value of the derivative assets and liabilities and thereby
impact net income. It is estimated that a 10% change in the forward
natural gas prices used to calculate the fair value of the natural
gas derivatives at December 31, 2008 could impact net loss by
approximately $12.8 million for the year ended December 31, 2008.
As well, a change of 10% in the forward crude oil prices used to
calculate the fair value of the crude oil derivatives at December
31, 2008 could impact net loss by $2.8 million for the year ended
December 31, 2008. A similar change in the currency rate assumption
underlying the derivatives fair value does not have a material
impact on net income. As at December 31, 2008 the Fund had the
following derivatives in place: Description of Derivative Term
Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO Fixed price April 2008 to 14,217 mcf/d
Cdn$7.10/mcf March 2009 Fixed price April 2008 to 14,217 mcf/d
Cdn$7.06/mcf March 2009 Fixed price November 2008 14,217 mcf/d
Cdn$7.77/mcf to March 2009 Fixed price November 2008 4,739 mcf/d
Cdn$8.10/mcf to March 2009 Fixed price November 2008 14,217 mcf/d
Cdn $9.45/mcf to March 2009 Fixed price April 2009 to 9,478 mcf/d
Cdn $8.66/mcf December 2009 Fixed price April 2009 to 9,478 mcf/d
Cdn $8.67/mcf December 2009 Fixed price April 2009 to 9,478 mcf/d
Cdn $8.94/mcf December 2009 Fixed price April 2009 to 14,217 mcf/d
Cdn $7.59/mcf March 2010 Fixed price April 2009 to 14,217 mcf/d Cdn
$7.56/mcf March 2010 Fixed price January 2010 14,217 mcf/d Cdn
$8.23/mcf to June 2010 Crude oil - WTI Fixed price February 2008
2,000 bbls/d Cdn$90.93/bbl to January 2009 Collar February 2008
2,000 bbls/d Sold put Cdn$70.00/bbl to Purchase call Cdn$105.00/bbl
January 2009 Cost Cdn$1.52/bbl Fixed price April 2008 to 2,500
bbl/d Cdn $97.15/bbl March 2009 Collar April 2009 to 2,000 bbl/d
Bought put Cdn $62.00/bbl December 2009 Sold call Cdn $76.00/bbl As
at December 31, 2008, the fair value of the derivatives outstanding
resulted in an asset of approximately $42,620,000 (December 31,
2007 - $7,201,000) and a liability of approximately $1,650,000
(December 31, 2007 - $5,020,000). For the year ended December 31,
2008, $38,789,000 was recognized in net loss as an unrealized
derivative gain (December 31, 2007 - $11,049,000 unrealized
derivative loss) and $27,439,000 was recognized in net loss as a
realized derivative loss (December 31, 2007 - $18,594,000 realized
derivative gain). 14. Management Internalization Concurrent with
the acquisition of Ketch Resources Trust in 2006, Advantage
internalized the external management contract structure and
eliminated all related fees. The Fund reached an agreement with
Advantage Investment Management Ltd. ("AIM" or the "Manager") to
purchase all of the outstanding shares of AIM pursuant to the terms
of the Plan of Arrangement for total original consideration of
1,933,208 Advantage Trust Units. The Trust Units were initially
valued at $39.1 million using the weighted average trading value
for Advantage Trust Units on the Unitholder approval date of June
22, 2006 and are subject to escrow provisions over a 3-year period,
vesting one-third each year beginning in 2007. The management
internalization consideration is being deferred and amortized into
income as management internalization expense over the specific
vesting periods during which employee services are provided,
including an estimate of future Trust Unit forfeitures. For the
year ended December 31, 2008, a total of 10,351 Trust Units issued
for the management internalization were forfeited (2007 - 24,909
Trust Units) and $7.0 million has been recognized as management
internalization expense (2007 - $15.7 million). As at December 31,
2008, 564,612 Trust Units remain held in escrow (December 31, 2007
- 1,193,622 Trust Units). 15. Capital Management The Fund manages
its capital with the following objectives: - To ensure sufficient
financial flexibility to achieve the ongoing business objectives
including replacement of production, funding of future growth
opportunities, and pursuit of accretive acquisitions; and - To
maximize Unitholder return through enhancing the Trust Unit value.
Advantage monitors its capital structure and makes adjustments
according to market conditions in an effort to meet its objectives
given the current outlook of the business and industry in general.
The capital structure of the Fund is composed of working capital
(excluding derivative assets and liabilities), bank indebtedness,
convertible debentures, capital lease obligations and Unitholders'
equity. Advantage may manage its capital structure by issuing new
Trust Units, obtaining additional financing either through bank
indebtedness or convertible debenture issuances, refinancing
current debt, issuing other financial or equity-based instruments,
adjusting or discontinuing the amount of monthly distributions,
suspending or renewing its distribution reinvestment plan,
adjusting capital spending, or disposing of non-core assets. The
capital structure is reviewed by Management and the Board of
Directors on an ongoing basis. Advantage's capital structure as at
December 31, 2008 is as follows: December 31, 2008
---------------------------------------------------------------------
Bank indebtedness (long-term) $ 587,404 Working capital deficit(1)
146,397
---------------------------------------------------------------------
Net debt 733,801 Trust Units outstanding market value 731,263
Convertible debentures maturity value (long-term) 132,221 Capital
lease obligations (long-term) 3,906
---------------------------------------------------------------------
Total $ 1,601,191
---------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities,
distributions payable, and the current portion of capital lease
obligations and convertible debentures. The Fund's bank
indebtedness is governed by a $710 million credit facility
agreement (note 8) that contains standard commercial covenants for
facilities of this nature. The only financial covenant is a
requirement for AOG to maintain a minimum cash flow to interest
expense ratio of 3.5:1, determined on a rolling four quarter basis.
The Fund is in compliance with all credit facility covenants. As
well, the borrowing base for the Fund's credit facilities is
determined through utilizing Advantage's regular reserve estimates.
The banking syndicate thoroughly evaluates the reserve estimates
based upon their own commodity price expectations to determine the
amount of the borrowing base. Revision or changes in the reserve
estimates and commodity prices can have either a positive or a
negative impact on the borrowing base of the Fund. Advantage's
issuance of convertible debentures is limited by its Trust
Indenture which currently restricts the issuance of additional
convertible debentures to 25% of market capitalization subsequent
to issuance. Advantage's Trust Indenture also provides for the
issuance of an unlimited number of Trust Units. However, through
tax legislation, an income trust is restricted to doubling its
market capitalization as it stands on October 31, 2006 by growing a
maximum of 40% in 2007 and 20% for the years 2008 to 2010. In
addition, an income trust may replace debt that was outstanding as
of October 31, 2006 with new equity or issue new, non-convertible
debt without affecting the normal growth percentage. As a result of
the "normal growth" guidelines, the Fund is permitted to issue
approximately $2.3 billion of new equity from January 1, 2009 to
January 1, 2011, which we believe is adequate for any growth we
expect to incur. If an income trust exceeds the established limits
on the issuance of new trust units and convertible debt that
constitute normal growth, the income trust will be immediately
subject to the Specified Investment Flow-Through Entity tax
legislation whereby the taxable portion of distributions paid will
be subject to tax at the trust level. Management of the Fund's
capital structure is facilitated through its financial and
operational forecasting processes. The forecast of the Fund's
future cash flows is based on estimates of production, commodity
prices, forecast capital and operating expenditures, and other
investing and financing activities. The forecast is regularly
updated based on new commodity prices and other changes, which the
Fund views as critical in the current environment. Selected
forecast information is frequently provided to the Board of
Directors. The Fund's capital management objectives, policies and
processes have remained unchanged during the year ended December
31, 2008. 16. Commitments Advantage has several lease commitments
relating to office buildings. The estimated annual minimum
operating lease rental payments for buildings are as follows: 2009
$ 3,862 2010 3,878 2011 1,471 2012 1,072
---------------------------------------------------------------------
$ 10,283
---------------------------------------------------------------------
17. Subsequent event On March 18, 2009, Advantage announced that
our Board of Directors had approved conversion to a growth oriented
corporation and a strategic asset disposition program to increase
financial flexibility. The corporate conversion will be subject to
approval by at least two-thirds of the Fund's Unitholders as well
as customary court and regulatory approvals, anticipated to be
completed on or about June 30, 2009. The conversion will enable
Advantage to pursue a business plan that is focused on the
development and growth of the Montney natural gas resource play at
Glacier. The Fund has engaged an advisory firm to assist in the
disposal of light oil and natural gas properties located in
Northeast British Columbia, West Central Alberta and Northern
Alberta with proposals anticipated by mid May 2009. As another step
to increase Advantage's financial flexibility and to focus on
development and growth at Glacier, Advantage announced it will
discontinue payment of cash distributions with the final cash
distribution paid on March 16, 2009 to Unitholders of record as of
February 27, 2009. Going forward, Advantage does not anticipate
paying distributions or dividends in the immediate future and will
instead direct cash flow to capital expenditures and debt
repayment. 18. Reconciliation of Financial Statements to United
States Generally Accepted Accounting Principles The consolidated
financial statements of Advantage have been prepared in accordance
with accounting principles generally accepted in Canada. Canadian
GAAP, in most respects, conforms to generally accepted accounting
principles in the United States ("US GAAP"). Any differences in
accounting principles between Canadian GAAP and US GAAP, as they
apply to Advantage, are not material, except as described below.
(a) Unit-based compensation Advantage accounts for compensation
expense based on the fair value of the equity awards on the grant
date and the initial fair value is not subsequently remeasured.
Advantage's unit-based compensation consists of a Restricted Trust
Unit Plan and Trust Units held in escrow subject to service
requirement provisions. The initial fair value is expensed over the
vesting period of the Trust Units or rights granted. Under US GAAP,
the Fund adopted SFAS 123(R) "Share-Based Payment" on January 1,
2006 using the modified prospective approach and applies the fair
value method of accounting for all Unit-based compensation granted
after January 1, 2006. A US GAAP difference exists as unit-based
compensation grants are considered liability awards for US GAAP and
equity awards for Canadian GAAP. Under US GAAP, the fair value of a
liability award is measured at the grant date and is subsequently
remeasured at each reporting period. When the rights are exercised
and the Trust Units vested, the amount recorded as a liability is
recognized as temporary equity. (b) Convertible debentures The Fund
applies CICA 3863 "Financial Instruments - Presentation" in
accounting for convertible debentures which results in their
classification as liabilities. The convertible debentures also have
an embedded conversion feature which must be segregated between
liabilities and equity, based on the relative fair market value of
the liability and equity portions. Therefore, the debenture
liabilities are presented at less than their eventual maturity
values. The liability and equity components are further reduced for
issuance costs initially incurred. The discount of the liability
component, net of issuance costs, as compared to maturity value is
accreted by the effective interest method over the debenture term.
As debentures are converted to Trust Units, an appropriate portion
of the liability and equity components are transferred to
Unitholders' capital. Interest and accretion expense on the
convertible debentures are shown on the Consolidated Statements of
Loss. Under US GAAP, the entire convertible debenture balance would
be shown as a liability. The embedded conversion feature would not
be accounted for separately as a component of equity. Additionally,
under US GAAP, issuance costs are generally shown as a deferred
charge rather than netted from the convertible debenture balance
and are amortized to interest expense over the term of the
debenture. Given that the convertible debentures are carried at
maturity value, it is not necessary to accrete the balance over the
term of the debentures which results in an expense reduction.
Interest and accretion on convertible debentures represents
interest expense on the convertible debentures and amortization of
the associated deferred issuance costs. (c) Depletion and
depreciation For Canadian GAAP, depletion of petroleum and natural
gas properties and depreciation of lease and well equipment is
provided on accumulated costs using the unit-of-production method
based on estimated net proved petroleum and natural gas reserves,
before royalties, based on forecast prices and costs. US GAAP
provides for a similar accounting methodology except that estimated
net proved petroleum and natural gas reserves are net of royalties
and based on constant prices and costs. Therefore, depletion and
depreciation under US GAAP will be different since changes to
royalty rates will impact both proved reserves and production and
differences between constant prices and costs as compared to
forecast prices and costs will impact proved reserve volumes.
Additionally, differences in depletion and depreciation will result
in divergence of net book value for Canadian GAAP and US GAAP from
year-to-year and impact future depletion and depreciation expense
as well as the net book value utilized for future ceiling test
calculations. (d) Ceiling test Under Canadian GAAP, petroleum and
natural gas assets are evaluated each reporting period to determine
that the carrying amount is recoverable and does not exceed the
fair value of the properties in the cost centre (the "ceiling
test"). The carrying amounts are assessed to be recoverable when
the sum of the undiscounted net 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 net 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. For Canadian GAAP
purposes, Advantage has not recognized an impairment loss since
inception. Under US GAAP, the carrying amounts of petroleum and
natural gas assets, net of deferred income taxes, shall not exceed
an amount equal to the sum of the present value of estimated net
future after-tax cash flows of proved reserves (at current prices
and costs as of the balance sheet date) computed using a discount
factor of ten percent plus the lower of cost or estimated fair
value of unproved properties. Any excess is charged to expense as
an impairment loss. Under US GAAP, Advantage recognized impairment
losses of $49.5 million in 2001 ($28.3 million net of tax), $535.4
million in 2006 ($477.8 million net of tax), and $1,047.5 million
in 2008 ($770.8 million net of tax). Impairment losses decrease net
book value of property and equipment which reduces depletion and
depreciation expense subsequently recorded as well as future
ceiling test calculations. (e) Income tax The future income tax
accounting standard under Canadian GAAP is substantially similar to
the deferred income tax approach as required by US GAAP. Pursuant
to Canadian GAAP, substantively enacted tax rates are used to
calculate future income tax, whereas US GAAP applies enacted tax
rates. However, there were no tax rate differences for the years
ended December 31, 2008 and 2007. The differences between Canadian
GAAP and US GAAP relate to future income tax impact on GAAP
differences for fixed assets. Under Canadian GAAP as at December
31, 2008, the Fund's carrying value of its net assets exceeded its
tax bases and resulted in a future income tax liability.
Adjustments under US GAAP result in a large future income tax
recovery and a future income tax asset, as the ceiling test write
down significantly lowered the Fund's fixed assets carrying value
under US GAAP. Under US GAAP, an entity that is subject to income
tax in multiple jurisdictions is required to disclose income tax
expense in each jurisdiction. The total amount of income taxes in
2007 and 2008 is entirely at the provincial level. (f) Goodwill
Under Canadian and US GAAP, the Fund is required to test the
carrying amount of goodwill at each balance sheet reporting date
and the methodologies are substantially the same. However, the
carrying value of the reporting unit (the Fund) under US GAAP is
much lower due to the impairments to property, plant and equipment
required under US GAAP (note 18(d)). As the fair value of the
reporting unit (the Fund) is in excess of its carrying values as
determined under US GAAP, there is no impairment of goodwill for US
GAAP reporting purposes. (g) Unitholders' equity Unitholders'
equity of Advantage consists primarily of Trust Units. The Trust
Units are redeemable at any time on demand by the holders, which is
required for the Fund to retain its Canadian mutual fund trust
status. The holders are entitled to receive a price per Trust Unit
equal to the lesser of: (i) 85% of the simple average of the
closing market prices of the Trust Units, on the principal market
on which the Trust Units are quoted for trading, during the 10
trading-day period commencing immediately after the date on which
the Trust Units are surrendered for redemption; and (ii) the
closing market price on the principal market on which the Trust
Units are quoted for trading on the redemption date. For Canadian
GAAP purposes, the Trust Units are considered permanent equity and
are presented as a component of Unitholders' equity. Under US GAAP,
it is required that equity with a redemption feature be presented
as temporary equity between the liability and equity sections of
the balance sheet. The temporary equity is shown at an amount equal
to the redemption value based on the terms of the Trust Units.
Changes in the redemption value from year-to-year are charged to
deficit. All components of Unitholders' equity related to Trust
Units are eliminated. When calculating net income per Trust Unit,
increases in the redemption value during a period results in a
reduction of net income available to Unitholders while decreases in
the redemption value increases net income available to Unitholders.
For the years ended December 31, 2008 and 2007, net income
available to Unitholders was increased by $476.2 million and $390.3
million corresponding to changes in the Trust Units redemption
value for the respective periods. A continuity schedule of
significant equity accounts for each reporting period is required
disclosure under US GAAP. The following table is a continuity of
unitholders' equity, the Fund's only significant equity account:
Year ended Year ended Unitholders' Equity December 31, December 31,
(thousands of Canadian dollars) 2008 2007
---------------------------------------------------------------------
Balance, beginning of year $ (176,393) $ (402,158) Net income
(loss) and comprehensive income (loss) (555,148) 50,610
Distributions declared (196,642) (215,194) Change in redemption
value of temporary equity 476,237 390,349
---------------------------------------------------------------------
Balance, end of year $ (451,946) $ (176,393)
---------------------------------------------------------------------
(h) Balance Sheet Disclosure US GAAP requires disclosure of certain
line items for balances that would be aggregated in the Canadian
GAAP financials. The following are the additional line items to be
disclosed for accounts receivable and accounts payable: December
31, December 31, (thousands of Canadian dollars) 2008 2007
---------------------------------------------------------------------
Accounts receivable Trade receivables $ 84,592 $ 94,959 Other
receivables 97 515
---------------------------------------------------------------------
Total accounts receivable $ 84,689 $ 95,474
---------------------------------------------------------------------
December 31, December 31, (thousands of Canadian dollars) 2008 2007
---------------------------------------------------------------------
Accounts payable and accrued liabilities Accounts payable $ 80,016
$ 72,691 Accrued liabilities 66,030 48,994 Other payables - 402
---------------------------------------------------------------------
Total accounts payable and accrued liabilities $ 146,046 $ 122,087
---------------------------------------------------------------------
(i) Statements of cash flow The differences between Canadian GAAP
and US GAAP have not resulted in any significant variances
concerning the statements of cash flows as reported. (j) Sound
acquisition On September 5, 2007, Advantage acquired all of the
issued and outstanding Trust Units and Exchangeable Shares of
Sound. The accounting for business combinations is effectively the
same under US and Canadian GAAP. However, the purchase price under
US GAAP is different as a result of AOG realizing a future income
tax asset from previously unrecognized temporary differences. The
purchase price under US GAAP has been allocated as follows: Net
assets acquired and liabilities assumed: Consideration: Fixed
assets $ 484,630 16,977,184 Trust Future income tax Units issued $
228,852 asset 29,430 Cash 21,403 Accounts receivable 27,656
Acquisition costs Prepaid expenses incurred 904 and deposits 3,873
------------ Derivative asset, net 2,797 $ 251,159 Bank
indebtedness (107,959) ------------ Convertible debentures
(101,553) Accounts payable and accrued liabilities (40,023) Future
income tax liability (29,430) Asset retirement obligations (16,695)
Capital lease obligations (1,567) ------------ $ 251,159
------------ (k) US Accounting Pronouncements Implemented SFAS 157
Fair Value Measurements: This Statement defines fair value,
establishes a framework for measuring fair value in GAAP, and
expands disclosures about fair value measurements. This Statement
applies under other accounting pronouncements that require or
permit fair value measurements. Accordingly, this Statement does
not require any new fair value measurements. The implementation
date for this standard was originally as of the beginning of the
first interim or annual reporting period that begins after November
15, 2007. However, the FASB postponed this implementation date by
one year for non-financial assets and liabilities by the issuance
of Staff Position 157-2. Accordingly, the Fund has implemented FAS
157 for all financial assets and liabilities only. The
implementation did not result in any changes to the fair values of
financial assets and liabilities of the Fund. (l) Recent US
Accounting Pronouncements Issued But Not Implemented SFAS 141 (R)
Business Combinations: This Statement requires assets and
liabilities acquired in a business combination, contingent
consideration, and certain acquired contingencies to be measured at
their fair values as of the date of acquisition. In addition,
acquisition-related and restructuring costs are to be recognized
separately from the business combination. This standard applies to
business combinations entered into after January 1, 2009. As the
standard is applied prospectively, the Fund will assess the impact
on any future business combinations. FASB Staff Position 157-2:
This Staff Position delays the implementation of the requirements
of SFAS 157 with respect to non-financial assets and liabilities,
until the first interim or annual reporting period that begins
after November 15, 2008. The Fund has not yet assessed the full
impact, if any, of this standard on the consolidated financial
statements. SFAS 162, Hierarchy of GAAP: This Statement establishes
a hierarchy among the existing types of accounting pronouncements
in the United States. The implementation date for this standard is
as of the beginning of the first interim or annual reporting period
that begins after November 15, 2008. The Fund has assessed the
impact of this Statement and does not anticipate any significant
impact on the consolidated financial statements. FASB Staff
Position APB 14-1, Accounting for Convertible Debt Instruments That
May Be Settled in Cash upon Conversion (Including Partial Cash
Settlement): If an entity issues convertible debt within the scope
of the Staff Position, it is required to separate the instrument
into a liability-classified component and an equity-classified
component. The implementation date for this standard was originally
as of the beginning of the first interim or annual reporting period
that begins after December 15, 2008. The Fund has assessed the
impact of this Staff Position and does not anticipate any
significant impact on the consolidated financial statements. The
application of US GAAP would have the following effect on net loss
as reported: Consolidated Statements of Income (Loss) and
Comprehensive Income (Loss) Year ended Year ended (thousands of
Canadian dollars, except December 31, December 31, for per Trust
Unit amounts) 2008 2007
---------------------------------------------------------------------
Net loss - Canadian GAAP, as reported $ (20,577) $ (7,535) US GAAP
Adjustments: General and administrative - note 18 (a) (904) 606
Management internalization - note 18 (a) 2,946 7,450 Interest and
accretion on convertible debentures - note 18 (b) 2,051 1,741
Depletion, depreciation and accretion - notes 18 (c) and (d)
(983,222) 72,990 Impairment of goodwill - note 18 (f) 120,271 -
Future income tax reduction - note 18 (e) 324,287 (24,642)
---------------------------------------------------------------------
Net income (loss) and comprehensive income (loss) - US GAAP $
(555,148) $ 50,610
---------------------------------------------------------------------
The application of US GAAP would have the following effect on the
balance sheets as reported: Consolidated December 31, 2008 December
31, 2007 Balance Sheets ----------------- -----------------
(thousands of Canadian US Canadian US Canadian dollars) GAAP GAAP
GAAP GAAP
---------------------------------------------------------------------
Assets Deferred charge - note 18 (b) $ - $ 1,181 $ - $ 1,984 Fixed
assets, net - notes 18 (c) and (d) 2,163,866 676,611 2,177,346
1,673,251 Future income taxes - note 18 (e) - 347,038 - - Goodwill
- note 18 (f) - 120,271 120,271 120,271 Liabilities and
Unitholders' Equity Current portion of convertible debentures
86,125 87,272 5,333 5,392 - note 18 (b) Current portion of future
income taxes - note 18 (e) 11,939 11,939 1,430 - Trust Unit
liability - note 18 (a) - 2,414 - 7,515 Convertible debentures -
note 18 (b) 128,849 132,377 212,203 219,674 Future income taxes -
note 18 (e) 43,976 - 65,297 - Temporary equity - note 18 (g) -
678,581 - 1,104,831 Unitholders' equity - notes 18 (a), (b) and (g)
1,208,513 (451,946) 1,378,867 (176,393) Advisory The information in
this release contains certain forward-looking statements. These
statements relate to future events or our future performance. All
statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often,
but not always, identified by the use of words such as "seek",
"anticipate", "plan", "continue", "estimate", "expect", "may",
"will", "project", "predict", "potential", "targeting", "intend",
"could", "might", "should", "believe", "would" and similar
expressions. These statements involve substantial known and unknown
risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions;
industry conditions; changes in laws and regulations including the
adoption of new environmental laws and regulations and changes in
how they are interpreted and enforced; fluctuations in commodity
prices and foreign exchange and interest rates; stock market
volatility and market valuations; volatility in market prices for
oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and
natural gas reserves; competition for, among other things, capital,
acquisitions, of reserves, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions; changes in
income tax laws or changes in tax laws and incentive programs
relating to the oil and gas industry and income trusts; geological,
technical, drilling and processing problems and other difficulties
in producing petroleum reserves; and obtaining required approvals
of regulatory authorities. Advantage's actual results, performance
or achievement could differ materially from those expressed in, or
implied by, such forward-looking statements and, accordingly, no
assurances can be given that any of the events anticipated by the
forward-looking statements will transpire or occur or, if any of
them do, what benefits that Advantage will derive from them. Except
as required by law, Advantage undertakes no obligation to publicly
update or revise any forward-looking statements. DATASOURCE:
Advantage Energy Income Fund CONTACT: Investor Relations, Toll
free: 1-866-393-0393, ADVANTAGE ENERGY INCOME FUND, 700, 400 - 3rd
Avenue SW, Calgary, Alberta, T2P 4H2, Phone: (403) 718-8000, Fax:
(403) 718-8300, Web Site: http://www.advantageincome.com/, E-mail:
Copyright