Advantage Announces Release of Fourth Quarter and Year Ended December 31, 2008 Financial Results
(TSX: AVN.UN, NYSE: AAV)
CALGARY, March 18 /CNW/ - 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 & AnalysisThe 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 www.sedar.com and
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™, 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 $ 50,206The 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
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 $ 0.04Additional Information
Additional information relating to Advantage can be found on SEDAR at
www.sedar.com and the Fund's website at 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, 2009CONSOLIDATED 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™, 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™ 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® "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 ® 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.
%CIK: 0001259995
For further information:
For further information: 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: www.advantageincome.com, E-mail: advantage@advantageincome.com