Advantage Announces 3rd Quarter Results, Conference Call & Webcast on November 13, 2007
CALGARY, Nov. 12 /CNW/ - Advantage Energy Income Fund (TSX: AVN.UN)
("Advantage" or the "Fund") is pleased to announce its unaudited operating and
financial results for the third quarter ended September 30, 2007.
A conference call will be held on Tuesday, November 13, 2007 at 9:00 a.m.
MST (11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-334-4934. A replay of the call will be available from approximately 2:00
p.m. EST on November 13, 2007 until approximately midnight, November 28, 2007
and can be accessed by dialing toll free 1-866-245-6755. The passcode required
for playback is 271037. A live web cast of the conference call will be
accessible via the Internet on Advantage's website at www.advantageincome.com.Financial and Operating Highlights
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
30, 2007 30, 2006 30, 2007 30, 2006
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Financial ($000)
Revenue before
royalties(1) $ 130,830 $ 124,521 $ 391,407 $ 292,188
per Trust Unit(2) $ 1.09 $ 1.26 $ 3.43 $ 3.97
per boe $ 48.46 $ 45.57 $ 50.32 $ 48.75
Funds from operations $ 62,345 $ 63,110 $ 190,624 $ 152,021
per Trust Unit(3) $ 0.51 $ 0.63 $ 1.64 $ 2.04
per boe $ 23.10 $ 23.10 $ 24.52 $ 25.37
Net income (loss) $ (26,202) $ 1,209 $ (21,330) $ 41,078
per Trust Unit(2) $ (0.22) $ 0.01 $ (0.19) $ 0.56
Distributions declared $ 55,017 $ 60,498 $ 157,319 $ 158,455
per Trust Unit(3) $ 0.45 $ 0.60 $ 1.35 $ 2.10
Expenditures on
property and equipment $ 32,418 $ 49,607 $ 107,792 $ 98,378
Working capital
deficit(4) $ 24,666 $ 33,340 $ 24,666 $ 33,340
Bank indebtedness $ 521,144 $ 372,514 $ 521,144 $ 372,514
Convertible debentures
(face value) $ 281,273 $ 180,730 $ 281,273 $ 180,730
Operating
Daily Production
Natural gas (mcf/d) 115,991 122,227 113,104 86,303
Crude oil and NGLs
(bbls/d) 10,014 9,330 9,641 7,571
Total boe/d @
6:1 29,346 29,701 28,492 21,955
Average prices
(including hedging)
Natural gas ($/mcf) $ 6.35 $ 5.90 $ 7.30 $ 6.68
Crude oil and NGLs
($/bbl) $ 68.51 $ 67.77 $ 63.11 $ 65.24
Supplemental (000)
Trust Units outstanding
at end of period 133,847 104,055 133,847 104,055
Trust Units issuable
Convertible
Debentures 12,069 8,334 12,069 8,334
Trust Units Rights
Incentive Plan 150 188 150 188
Trust Units outstanding
and issuable at end of
period 146,066 112,577 146,066 112,577
Basic weighted average
Trust Units 120,080 98,781 114,132 73,544
(1) includes realized hedging 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
MESSAGE TO UNITHOLDERS
Highlights for the third quarter 2007 include:
- On September 5, 2007, the acquisition of Sound Energy Trust
successfully closed. Results of operations from Sound have been
included with Advantage's results from September 5, 2007. This highly
accretive and synergistic transaction provides stable production, a
large suite of under-capitalized assets and more oil opportunities.
Our drilling inventory has increased to well over five years (750
locations) and tax pools increased to $1.6 billion.
- Production volumes were on track with expectations for the third
quarter of 2007. Volumes increased 8% to 29,346 boe/d compared to the
second quarter of 2007 mainly due to the inclusion of 26 days of
Sound Energy Trust volumes in the third quarter. New wells were also
tied-in during the latter part of the quarter that resulted from our
highly successful drilling program which had a 100% success rate in
the third quarter. Negative impacts on production in the third
quarter resulted from significant third party facility maintenance
outages and wet weather during the early part of the quarter which
delayed the tie-in and drilling of new oil and gas wells. In
addition, approximately 400 boe/d of natural gas production was
temporarily curtailed at Glacier due to third party facility
constraints. This production is anticipated to return in the latter
part of the fourth quarter.
- Natural gas production for the third quarter of 2007 increased 6% to
116.0 mmcf/d compared to 109.0 mmcf/d reported in the second quarter
of 2007. Crude oil and natural gas liquids production increased 12%
to 10,014 bbls/d compared to 8,952 bbls/d in the second quarter of
2007.
- Distributions declared as a percent of funds from operations
increased slightly to 88% for the third quarter compared to 83% for
the second quarter of 2007 despite a 25% decrease in natural gas
prices. Reduced natural gas prices from the previous quarter were
partially offset by hedging gains and the inclusion of 26 days of
accretive cash flow from the Sound properties in the third quarter.
Distributions declared as a percent of funds from operations is 83%
for the nine months ended September 30, 2007, which is on-track with
expectations.
- The Fund declared three distributions during the quarter totaling
$0.45 per Trust Unit. Since inception, the Fund has distributed
$821.9 million or $15.84 per Trust Unit.
- Funds from operations for the third quarter of 2007 was $62.3 million
or $0.51 per Trust Unit compared to $62.6 million or $0.54 per Trust
Unit for the second quarter of 2007. The lower funds from operations
per unit is due to the issuance of additional Trust Units related to
the Sound acquisition with only 26 days of realized revenue in the
quarter and weaker natural gas prices.
- Capital spending during Q3 2007 was a net $32.4 million. During the
quarter a total of 18.3 net (31 gross) wells were drilled at a 100%
success rate.
- Per unit operating costs in Q3 2007 have increased by 4% to
$11.40/boe when compared to Q2 2007. Q3 costs were higher due to the
higher operating cost structure of the Sound assets acquired. Total
operating costs have increased by 14% from Q2 2007 and 28% from Q3 of
2006 which reflects higher industry costs as well as higher operating
costs associated with the Sound assets.
Alberta Royalty Program Changes
- On October 25, 2007, the Alberta Provincial Government announced
changes to royalties for conventional oil, natural gas and oil sands
that will become effective January 1, 2009. Preliminary indications
are that the changes will have a negligible impact on Advantage since
we have a significant number of lower rate wells within our long life
properties that are producing in Alberta. As a result of our diverse
asset base, we also have a significant Horseshoe Canyon coal bed
methane drilling inventory that can be pursued which will also have a
favorable royalty treatment due to lower rate per well
characteristics of that play. Our exposure in Northeast British
Columbia and Saskatchewan also affords us further flexibility with
mitigating the royalty impact in our capital program.
Hedging Position
- Advantage has layered in several hedges on both natural gas and oil
which provides floor protection through summer 2007 and winter
2007/2008 for natural gas.
- Given current weakness in natural gas prices, Advantage is well
positioned through to March 2008. For the fourth quarter of 2007, the
Fund currently has approximately 42% of our net natural gas
production hedged at an average floor price of $8.09/mcf and an
average ceiling of $9.42/mcf. For the first quarter of 2008,
Advantage has 22% of our net natural gas production hedged at a floor
price of $8.85/mcf and a ceiling of $10.19/mcf.
- Advantage has been opportunistic with respect to hedging and will
continue to monitor the forward prices to protect cash flow. We
anticipate hedging approximately 50% of our production in 2008.
Looking Forward
- We are reiterating our guidance for a 2007 exit production rate of
approximately 35,000 boe/d for 2007. On an annual basis, we expect to
average approximately 30,000 boe/d for 2007.
- Operating costs are expected to be approximately $12.50 to $13.50 on
a per boe basis for the fourth quarter of 2007 with the inclusion of
the Sound assets. Sound's assets have higher operating costs but have
a greater exposure to oil which provides improved netbacks given the
current crude oil pricing environment. Advantage will continue to
aggressively pursue optimization initiatives to reduce costs.
Industry service and supply costs may subside in the future as
significant reductions in drilling activity could lead to a more
competitive market.
- Royalty rates are expected to remain in the 19% to 20% range for
2007.
- We are directing approximately 80% of our capital spending toward
more oil projects for the remainder of the 2007 year due to continued
higher crude oil pricing. Total exploration and development capital
for 2007 is expected to approximate $150 million. Advantage's highly
attractive and large drilling inventory allows flexibility in our
capital allocation and an ability to high grade our projects.
- Advantage has exceptional tax pool coverage which will help reduce
the amount of tax leakage to Unitholders for several years after
2011. Including the acquisition of Sound, the Fund has approximately
$1.6 billion in tax pools which was one of the highest in the sector
as a multiple of estimated annual cash flow.
- Advantage is well positioned for upside opportunities in this
'buyer's market' with an estimated safe harbour of $2 billion.MANAGEMENT'S DISCUSSION & ANALYSIS
The following Management's Discussion and Analysis ("MD&A"), dated as of
November 12, 2007, provides a detailed explanation of the financial and
operating results of Advantage Energy Income Fund ("Advantage", the "Fund",
"us", "we" or "our") for the three and nine months ended September 30, 2007
and should be read in conjunction with the consolidated financial statements
contained within this interim report and the audited financial statements and
MD&A for the year ended December 31, 2006. 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 Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Cash provided
by operating
activities $ 65,314 $ 78,971 (17)% $165,766 $163,592 1%
Expenditures
on asset
retirement 1,128 1,065 6% 4,835 2,512 92%
Changes in
non-cash
working
capital (4,097) (16,926) (76)% 20,023 (14,083) (242)%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Funds from
operations $ 62,345 $ 63,110 (1)% $190,624 $152,021 25%
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-------------------------------------------------------------------------Forward-Looking Information
The information in this report 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; obtaining required approvals of regulatory
authorities and other risk factors set forth in Advantage's Annual Information
Form which is available at www.advantageincome.com or www.sedar.com.
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.
Acquisition of Sound Energy Trust
On September 5, 2007, the previously announced acquisition of Sound
Energy Trust ("Sound") was completed. The financial and operational
information for the three and nine months ended September 30, 2007 reflects
operations from the Sound properties effective from the closing date,
September 5, 2007.
The acquisition was accomplished through a Plan of Arrangement (the
"Arrangement") by the exchange of each Sound Trust Unit for 0.30 of an
Advantage Trust Unit or, at the election of the holder of Sound Trust Units,
$0.66 in cash and 0.2557 of an Advantage Trust Unit. In addition, all Sound
Exchangeable Shares were exchanged for Advantage Trust Units on the same ratio
based on the conversion ratio in effect at the effective date of the
Arrangement. Advantage issued 16,977,184 Trust Units and paid $21.4 million
cash consideration to acquire Sound. The transaction is accretive to
Advantage's Unitholders on a production, cash flow, reserves and net asset
value basis and will significantly increase Advantage's tax pool position to a
total of approximately $1.6 billion, and Safe Harbour expansion room is
anticipated to be approximately $2.0 billion. Sound's higher oil weighting,
synergy with many of Advantage's core properties and significant undeveloped
land holdings of approximately 400,000 net undeveloped acres will further
enhance the operating platform of Advantage. The combined trust has an
estimated enterprise value of $2.3 billion.Overview
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Cash provided
by operating
activities
($000) $ 65,314 $ 78,971 (17)% $165,766 $163,592 1%
Funds from
operations
($000) $ 62,345 $ 63,110 (1)% $190,624 $152,021 25%
per Trust
Unit(1) $ 0.51 $ 0.63 (19)% $ 1.64 $ 2.04 (20)%
Net income
(loss)
($000) $(26,202) $ 1,209 (2,267)% $(21,330) $ 41,078 (152)%
per Trust
Unit
- Basic $ (0.22) $ 0.01 (2,300)% $ (0.19) $ 0.56 (134)%
- Diluted $ (0.22) $ 0.01 (2,300)% $ (0.19) $ 0.56 (134)%
(1) Based on Trust Units outstanding at each distribution record date.Cash provided by operating activities decreased 17%, funds from
operations decreased 1%, and funds from operations per Trust Unit decreased
19% for the three months ended September 30, 2007, as compared to the same
period of 2006. For the nine months ended September 30, 2007, cash provided by
operating activities increased 1%, funds from operations increased 25%, and
funds from operations per Trust Unit decreased 20%. Cash provided by operating
activities and funds from operations for the quarter has been primarily
negatively impacted by lower natural gas prices and higher operating costs.
However, cash provided by operating activities and funds from operations for
the nine months has significantly benefited from the increased production,
particularly due to the Ketch acquisition in the second quarter of 2006. Funds
from operations per Trust Unit has been impacted during the periods due to
lower funds from operations relative to a higher average number of Trust Units
outstanding. The weighted average number of Trust Units has increased 22% and
55% for the three and nine months ended in 2007 compared to 2006, mainly due
to the Sound acquisition in 2007, the Ketch acquisition, the Fund's Trust Unit
financing in the first quarter of 2007 and the distribution reinvestment plan.
When compared to the second quarter of 2007, funds from operations was
comparable as production increased 8%, mainly due to the acquisition of Sound,
and was offset by decreased realized natural gas prices before hedging of 25%.
Reduced natural gas prices were partially mitigated by increased realized
crude oil and NGL prices before hedging of 12% and an increase in realized
hedging gains of $7.3 million.
Net income decreased to a net loss for both the three and nine months
ended September 30, 2007, compared to 2006. The lower net income has been
primarily due to additional future income tax expense related to the new tax
legislation concerning income trusts, higher operating costs, as well as
amortization of the management contract internalization and higher depletion
and depreciation expense. 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 Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Distributions
declared
($000) $ 55,017 $ 60,498 (9)% $157,319 $158,455 (1)%
per Trust
Unit(1) $ 0.45 $ 0.60 (25)% $ 1.35 $ 2.10 (36)%
(1) Based on Trust Units outstanding at each distribution record date.Total distributions declared decreased 9% for the three months and 1% for
the nine months ended September 30, 2007 when compared to the same periods in
2006. Total distributions declared are slightly lower as a result of the
decrease in the distribution per Trust Unit in January 2007, being offset by
the increased Trust Units outstanding from the continued growth and
development of the Fund. Since natural gas prices had been very weak during
the 2006/2007 winter season, we reduced the distribution level to more
appropriately reflect the commodity price environment. Distributions per Trust
Unit were $0.45 for the three months and $1.35 for the nine months ended
September 30, 2007, representing a decrease of 25% and 36% from same periods
in 2006. The monthly distribution is currently $0.15 per Trust Unit. To
mitigate the persisting risk associated with lower natural gas prices and the
resulting negative impact on distributions, the Fund implemented a hedging
program in 2006 with 56% of natural gas hedged for April to October 2007. See
"Commodity Price Risk" section for a more detailed discussion of our price
risk management.
Distributions 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 will be susceptible to the risks and uncertainties associated with the oil
and natural gas industry generally. If the oil and natural gas reserves
associated with the Canadian resource properties are not supplemented through
additional development or the acquisition of additional oil and natural gas
properties, our distributions will decline over time in a manner consistent
with declining production from typical oil and natural gas reserves.
Therefore, distributions 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. Oil and natural gas
prices can fluctuate widely on a month-to-month basis in response to a variety
of factors that are beyond our control. Declines in oil or natural gas prices
will have an adverse effect upon our operations, financial condition, reserves
and ultimately on our ability to pay distributions to Unitholders. The Fund
attempts to mitigate the volatility in commodity prices through our hedging
program. It is our long-term objective to provide stable and sustainable
distributions to the Unitholders, while continuing to grow the Fund. However,
given that funds from operations can vary significantly from month-to-month
due to these factors, the Fund may utilize various financing alternatives as
an interim measure to maintain stable distributions.Revenue
Three months ended Nine months ended
September 30 September 30
($000) 2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Natural gas
excluding
hedging $ 60,022 $ 66,228 (9)% $213,115 $157,239 36%
Realized
hedging
gains 7,687 118 6,414% 12,171 118 10,214%
-------------------------------------------------------------------------
Natural gas
including
hedging $ 67,709 $ 66,346 2% $225,286 $157,357 43%
-------------------------------------------------------------------------
Crude oil
and NGLs
excluding
hedging $ 63,598 $ 58,175 9% $164,908 $134,831 22%
Realized
hedging
gains
(losses) (477) - - 1,213 - -
-------------------------------------------------------------------------
Crude oil
and NGLs
including
hedging $ 63,121 $ 58,175 9% $166,121 $134,831 23%
-------------------------------------------------------------------------
Total
revenue $130,830 $124,521 5% $391,407 $292,188 34%
-------------------------------------------------------------------------Natural gas revenues, excluding hedging, have decreased 9% for the three
months and increased 36% for the nine months ended September 30, 2007,
compared to 2006. The decrease in natural gas revenues, excluding hedging, for
the three months is mainly due to a 5% decrease in natural gas production and
realized natural gas prices from the same period in 2006. Conversely, the
increase in natural gas revenues, excluding hedging, for the nine month period
ended in 2007 is mainly due to increased production from the inclusion of a
full nine months of production from the Ketch merger and a modest increase in
the realized natural gas price of 3% compared to 2006. Crude oil and NGL
revenues, excluding hedging, have increased by 9% for the three months and 22%
for the nine months ended September 30, 2007, compared to 2006. Crude oil and
NGL revenue increased due to additional production revenues from the Sound
acquisition since September 5, 2007 and the inclusion of a full nine months of
production from the Ketch merger. For the three and nine months ended
September 30, 2007, the Fund recognized natural gas and crude oil net hedging
gains of $7.2 million and $13.4 million primarily due to effective hedging
contracts in place that offset weaker commodity prices experienced during
2007, particularly natural gas prices.Production
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Natural gas
(mcf/d) 115,991 122,227 (5)% 113,104 86,303 31%
Crude oil
(bbls/d) 7,750 6,982 11% 7,308 5,978 22%
NGLs (bbls/d) 2,264 2,348 (4)% 2,333 1,593 46%
-------------------------------------------------------------------------
Total (boe/d) 29,346 29,701 (1)% 28,492 21,955 30%
-------------------------------------------------------------------------
Natural gas (%) 66% 69% 66% 66%
Crude oil (%) 26% 24% 26% 27%
NGLs (%) 8% 7% 8% 7%The Fund's total daily production averaged 29,346 boe/d for the three
months and 28,492 boe/d for the nine months ended September 30, 2007, a
decrease of 1% and an increase of 30%, respectively, compared with the same
periods of 2006. Natural gas production decreased 5%, crude oil production
increased 11%, and NGLs production decreased 4% for the third quarter of 2007.
For the nine months ended September 30, 2007, natural gas production increased
31%, crude oil production increased 22%, and NGLs production increased 46%.
Production for the quarter is similar to the prior year as natural production
declines have been primarily offset by capital development activity and
additional production from the Sound properties for the 26 days since closing
the acquisition. The increase in production year to date for 2007 from 2006
has been primarily attributed to a full nine months of production from the
Ketch acquisition in 2007, which closed June 23, 2006, and the Sound
acquisition which contributed 26 days of production. Production for the third
quarter increased 8% from the second quarter of 2007 due to the acquisition of
Sound. This was offset by a significant amount of 3rd party facility outages
that were anticipated and wet weather during July that delayed tie-ins of oil
and gas wells.
Our successful first quarter 2007 drilling program at Martin Creek,
followed by continued success at Sunset, Nevis, Willesden Green, as well as
other areas in Southern Alberta and Saskatchewan, has helped offset natural
declines. In addition, our flattening production platform, resulting from our
continued focus on long life assets, is contributing to a stable operating
foundation. For the remainder of the year, we are directing our drilling
activity toward crude oil projects with an estimated exit rate of production
of approximately 35,000 boe/d.Commodity Prices and Marketing
Natural Gas
Three months ended Nine months ended
September 30 September 30
($/mcf) 2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Realized natural
gas prices
Excluding
hedging $ 5.62 $ 5.89 (5)% $ 6.90 $ 6.67 3%
Including
hedging $ 6.35 $ 5.90 8% $ 7.30 $ 6.68 9%
AECO monthly
index $ 5.62 $ 6.03 (7)% $ 6.81 $ 7.19 (5)%Realized natural gas prices, excluding hedging, decreased 5% for the
three months and increased 3% for the nine months ended September 30, 2007, as
compared to 2006. The price of natural gas is primarily based on supply and
demand fundamentals in the North American marketplace, however market
speculation activity has increased price volatility. Natural gas prices have
declined due to high storage injections, mild summer weather and lack of storm
activity in the Gulf of Mexico. Inventory levels remain higher than the five
year average, causing continued downward pressure on commodity prices which
decreased significantly through the summer and have been continuing to
decrease since the end of 2006. Although it appears that we can expect
prolonged weak natural gas prices in the short-term, we continue to believe
that the long-term pricing fundamentals for natural gas remain strong. These
fundamentals include (i) the continued strength of crude oil prices, which has
eliminated the economic advantage of fuel switching away from natural gas
evidenced by the increase in proposed gas fired electrical generation
facilities, (ii) significantly less natural gas drilling in Canada projected
for 2007 and 2008, which will reduce productivity to offset declines, (iii)
the increasing focus on resource style natural gas wells, which have high
initial declines and require a higher threshold economic price than
conventional gas drilling and (iv) the demand for natural gas for the Canadian
oil sands projects.Crude Oil and NGLs
Three months ended Nine months ended
September 30 September 30
($/bbl) 2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Realized crude
oil prices
Excluding
hedging $ 70.22 $ 69.77 1% $ 64.60 $ 66.97 (4)%
Including
hedging $ 69.55 $ 69.77 - $ 65.21 $ 66.97 (3)%
Realized NGLs
prices
Excluding
hedging $ 64.95 $ 61.84 5% $ 56.55 $ 58.73 (4)%
Realized crude
oil and NGLs
prices
Excluding
hedging $ 69.03 $ 67.77 2% $ 62.65 $ 65.24 (4)%
Including
hedging $ 68.51 $ 67.77 1% $ 63.11 $ 65.24 (3)%
WTI ($US/bbl) $ 75.33 $ 70.55 7% $ 66.22 $ 68.42 (3)%
$US/$Canadian
exchange rate $ 0.96 $ 0.89 8% $ 0.91 $ 0.88 3%Realized crude oil and NGLs prices, excluding hedging, increased 2% for
the three months and decreased 4% for the nine months ended September 30,
2007, as compared to the same periods of 2006. Advantage's 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.
For the three and nine months ended September 30, 2007, WTI increased 7% and
decreased 3%, respectively, with significant increases experienced in the
third quarter of 2007. Advantage's realized crude oil price has not changed to
the same extent as WTI due to the change in foreign exchange rates 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 has reached historic high levels. Many developments have resulted in the
current price levels, including significant continuing geopolitical issues and
general market speculation. In fact, the impact of market fundamentals has
diminished as geopolitical events and speculation has prevailed. As a result,
prices have remained strong throughout 2007 and continue to increase. With the
current high price levels, it is notable that demand has remained resilient.
Regardless whether the current price level is sustainable or just a short-term
anomaly, we believe that the 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) ongoing civil
unrest in Venezuela, Nigeria, and the Middle East, (iii) strong world wide
demand, particularly in China, India and the United States and (iv) North
American refinery capacity constraints.
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 therefore on the distributions to holders of Advantage Trust
Units. 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. These commodity price risk management
activities could expose Advantage to losses or gains. 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.Currently, the Fund has the following derivatives in place:
Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas
- AECO
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.16/mcf
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.55/mcf
Fixed price November 2007 to
March 2008 7,109 mcf/d Cdn$9.54/mcf
Collar March 2007 to
December 2007 9,478 mcf/d Floor Cdn$7.91/mcf
Ceiling Cdn$9.50/mcf
Collar May 2007 to
December 2007 4,739 mcf/d Floor Cdn$7.91/mcf
Ceiling Cdn$9.50/mcf
Collar November 2007 to
March 2008 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$10.29/mcf
Collar November 2007 to
March 2008 7,109 mcf/d Floor Cdn$8.70/mcf
Ceiling Cdn$10.71/mcf
Crude oil - WTI
Collar January 2007 to
December 2007 500 bbls/d Floor US$70.00/bbl
Ceiling US$74.30/bbl
Collar March 2007 to
December 2007 1,000 bbls/d Floor US$57.00/bbl
Ceiling US$70.00/bbl
Collar April 2007 to
December 2007 500 bbls/d Floor US$60.00/bbl
Ceiling US$71.50/bblAs at September 30, 2007 the fair value of the derivatives outstanding
was a net asset of approximately $11.3 million. For the nine months ended
September 30, 2007, $2.0 million was recognized in income as an unrealized
derivative loss due to a decrease in the fair value from December 31, 2006 and
$13.4 million was recognized in income as a realized derivative gain, which
partially alleviated lower revenue from reduced commodity prices, particularly
natural gas. As a result of the Sound acquisition, the Fund assumed several of
these derivatives which had an estimated net fair value on closing of
$2.8 million. The change in fair value of these derivatives since acquisition
to the end of the period has been recognized in income as an unrealized
derivative gain or loss. The valuation of the derivatives is the estimated
fair value to settle the contracts as at September 30, 2007 and is based on
pricing models, estimates, assumptions and market data available at that time.
The actual gain or loss realized on cash settlement can vary materially due to
subsequent fluctuations in commodity prices as compared to the valuation
assumptions. 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 income and comprehensive income as an unrealized derivative gain
or loss with a corresponding derivative asset or liability recorded on the
balance sheet.
In addition, the Fund has the following physical natural gas contracts in
place that are not recognized on the balance sheet at fair value, but instead
have gains and losses recognized in earnings as the contracts settle:Description
of Physical
Contract Term Volume Average Price
-------------------------------------------------------------------------
Natural gas
- AECO
Collar April 2007 to October 2007 4,739 mcf/d Floor Cdn$7.12/mcf
Ceiling Cdn$8.67/mcf
Collar April 2007 to October 2007 4,739 mcf/d Floor Cdn$6.86/mcf
Ceiling Cdn$9.13/mcf
Collar April 2007 to October 2007 9,478 mcf/d Floor Cdn$7.39/mcf
Ceiling Cdn$9.63/mcf
Collar April 2007 to October 2007 9,478 mcf/d Floor Cdn$6.33/mcf
Ceiling Cdn$7.20/mcfAlthough the Fund has several fixed price contracts expiring soon, we
will be closely monitoring commodity markets and will pursue new opportunities
to enter contracts that will mitigate commodity price changes for 2008.
Currently, the Fund has fixed the commodity price on anticipated
production as follows:Approximate
Production
Hedged, Net of
Commodity Royalties Minimum Price Maximum Price
-------------------------------------------------------------------------
Natural gas - AECO
April 2007 to October 2007 56% Cdn$7.14/mcf Cdn$8.18/mcf
November 2007 to March 2008 27% Cdn$8.71/mcf Cdn$10.08/mcf
Crude Oil - WTI
April 2007 to October 2007 17% US$64.05/bbl US$85.58/bbl
November 2007 to December 2007 19% US$61.00/bbl US$71.45/bbl
Royalties
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Royalties, net
of Alberta
Royalty
Credit
($000) $ 22,601 $ 22,945 (1)% $ 71,515 $ 53,107 35%
per boe $ 8.37 $ 8.40 - $ 9.19 $ 8.86 4%
As a percentage
of revenue,
excluding
hedging 18.3% 18.4% (0.1)% 18.9% 18.2% 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 2006 are shown net
of the Alberta Royalty Credit, which was a royalty rebate provided by the
Alberta government to certain producers and was eliminated effective January
1, 2007. Royalties are comparable for the quarter and have increased for the
nine months ended September 30, 2007 due to the increase in revenue from
higher production. Royalties as a percentage of revenue, excluding hedging,
have increased slightly from the 2006 period due to the inclusion of slightly
higher royalty rate properties from the Ketch acquisition. We expect the
royalty rate to remain comparable for the remainder of 2007.
On October 25, 2007, the Alberta Provincial Government announced changes
to royalties for conventional oil, natural gas and oil sands that will become
effective January 1, 2009. Given the methodology used in the new royalty
regime, the effect on cash flow will be affected by depths and productivity of
wells and makes them price sensitive with higher royalty levels applying when
commodity prices are higher. A review of the initial information released by
the Alberta Provincial Government indicates that lower rate natural gas wells
will see a benefit of lower royalties while conventional oil will be subject
to an increase in royalties but 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, early indications are that the impact may not be significant based
on our current production and the current commodity price environment.
Advantage continues to analyze the impact of the decision and 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.Operating Costs
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Operating
costs ($000) $ 30,790 $ 24,369 26% $ 87,979 $ 55,108 60%
per boe $ 11.40 $ 8.92 28% $ 11.31 $ 9.19 23%Total operating costs increased 26% for the three months and 60% for the
nine months ended September 30, 2007 as compared to 2006, mainly due to
increased production from the Ketch acquisition which was completed June 23,
2006. Total operating costs also increased slightly for the Sound acquisition
with 26 days of costs included in the three and nine months ended
September 30, 2007. Operating costs per boe increased 28% for the three months
and 23% for the nine months ended September 30, 2007, mainly due to lower
production levels related to second quarter third party turnaround activity
that extended into the third quarter, an extended spring break-up, and
increased service and supply costs as the industry experienced overall cost
increases. However, third quarter 2007 per unit operating costs increased by
only 4% when compared to the three months ended June 30, 2007 with the
inclusion of Sound and higher maintenance costs which are typical for the
period. We will continue to be opportunistic and proactive in pursuing
optimization initiatives that will improve our operating cost structure. The
Fund has been active in preserving the price of power costs by hedging 3.5 MW
at $56.68/MWh for 2007 and 3.0 MW at $54.00/MWh for 2008, which represents a
significant portion of our power usage. We anticipate additional savings in
the newly acquired higher operating cost Sound properties combined with
existing Advantage properties. We expect that operating costs per boe will be
in the range of $12.50 to $13.50 for the fourth quarter of 2007 which will
include the full impact of the Sound acquisition.General and Administrative
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
General and
administrative
expense
($000) $ 4,543 $ 4,766 (5)% $ 13,491 $ 9,152 47%
per boe $ 1.68 $ 1.74 (3)% $ 1.73 $ 1.53 13%General and administrative ("G&A") expense has decreased 5% for the three
months and increased 47% for the nine months ended September 30, 2007, as
compared to 2006. G&A per boe decreased 3% for the three months and increased
13% for the nine months when compared to the same periods of 2006. G&A expense
for the nine months ended September 30, 2007 has increased overall and per boe
primarily due to an increase in staff levels that have resulted from the
June 23, 2006 Ketch acquisition and growth of the Fund. Additionally, the
Ketch acquisition was conditional on Advantage internalizing the external
management contract structure and eliminating all related fees for a more
typical employee compensation arrangement. The new employee compensation plan
has resulted in higher G&A expense that is offset by the elimination of future
management fees and performance incentive. Prior to elimination of the
management contract, the quarterly management fee and annual performance
incentive were not included within G&A.
Unit-Based Compensation
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
purpose of the long-term compensation plans is to retain and attract
employees, to reward and encourage performance, and to focus employees on
operating and financial performance that result 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. 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 based on the "fair value" of the RTUs at the grant date and is
recognized as compensation expense over the service period. This valuation
incorporates the period end Trust Unit price, the estimated number of RTUs to
vest, and certain management estimates. The maximum fair value 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. No RTUs have been
granted under the Plan at this time and accordingly, no compensation expense
relating to the RTUs has been recognized in the interim financial statements.
Once the calendar year is completed and the final Trust Unit return is
calculated for the return period RTUs may be granted and consequently,
compensation expense may be recognized at that time. As the Fund did not meet
the 2006 grant thresholds, there was no RTU grant made for the 2006 year.
For the nine months ended September 30, 2007, the Fund has accrued
unit-based compensation expense of $0.8 million and has capitalized $0.3
million related to Trust Units issuable for the retention of certain employees
of the Fund.Management Fee, Performance Incentive, and Management Internalization
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Management fee
($000) $ - $ - - $ - $ 887 (100)%
per boe $ - $ - - $ - $ 0.15 (100)%
Performance
incentive ($000) $ - $ - - $ - $ 2,380 (100)%
Management
internalization
($000) $ 2,455 $ 7,428 (67)% $ 13,174 $ 7,952 66%Prior to the Ketch merger, the Manager received both a management fee and
a performance incentive fee as compensation pursuant to the Management
Agreement approved by the Board of Directors. As a condition of the merger
with Ketch, the Fund and the Manager reached an agreement to internalize the
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 quarter since one third vested and was paid in June 2007 while two thirds
remains outstanding.Interest
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Interest expense
($000) $ 6,242 $ 5,711 9% $ 16,434 $ 12,844 28%
per boe $ 2.31 $ 2.09 11% $ 2.11 $ 2.14 (1)%
Average effective
interest rate 5.9% 5.2% 0.7% 5.6% 5.0% 0.6%
Bank indebtedness
at September 30
($000) $521,144 $372,514 40%Interest expense has increased 9% for the three months and 28% for the
nine months ended September 30, 2007, as compared to 2006. Interest expense
per boe has increased 11% for the three months and decreased 1% for the nine
months ended September 30, 2007. The increase in total interest expense is
primarily attributable to a higher average debt level associated with the
growth of the Fund, an increase in the average effective interest rates and
increased bank indebtedness assumed on the Sound and Ketch acquisitions. We
monitor the debt level to ensure an optimal mix of financing and cost of
capital that will provide a maximum return to Unitholders. Our current credit
facilities have been a favorable financing alternative with an effective
interest rate of only 5.6% for the nine months ended September 30, 2007. 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 Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Interest on
convertible
debentures
($000) $ 3,910 $ 3,308 18% $ 10,441 $ 7,921 32%
per boe $ 1.45 $ 1.21 20% $ 1.34 $ 1.32 2%
Accretion on
convertible
debentures
($000) $ 644 $ 604 7% $ 1,848 $ 1,502 23%
per boe $ 0.24 $ 0.22 9% $ 0.24 $ 0.25 (4)%
Convertible
debentures
maturity
value at
September 30
($000) $281,273 $180,730 56%Interest on convertible debentures has increased 18% for the three months
and 32% for the nine months ended September 30, 2007, as compared to 2006.
Accretion on convertible debentures has increased 7% for the three months and
23% for the nine months ended September 30, 2007. The increases in total
interest and accretion are due to Advantage assuming Sound's 8.75% and 8.00%
convertible debentures and Ketch's 6.50% convertible debentures in the 2006
merger. The increased interest and accretion from the additional debentures
has been slightly offset due to the exchange of convertible debentures to
Trust Units during 2006 that pay distributions rather than interest. Interest
and accretion per boe for the quarter is higher as our convertible debentures
outstanding has slightly increased relative to our level of production.Cash Netbacks
Three months ended
September 30
2007 2006
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $123,620 $ 45.79 $124,403 $ 45.53
Realized gain on derivatives 7,210 2.67 118 0.04
Royalties, net of Alberta
Royalty Credit (22,601) (8.37) (22,945) (8.40)
Operating costs (30,790) (11.40) (24,369) (8.92)
-------------------------------------------------------------------------
Operating $ 77,439 $ 28.69 $ 77,207 $ 28.25
General and administrative (4,543) (1.68) (4,766) (1.74)
Management fee - - - -
Interest (6,242) (2.31) (5,711) (2.09)
Interest on convertible
debentures (3,910) (1.45) (3,308) (1.21)
Income and capital taxes (399) (0.15) (312) (0.11)
-------------------------------------------------------------------------
Funds from operations $ 62,345 $ 23.10 $ 63,110 $ 23.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine months ended
September 30
2007 2006
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $378,023 $ 48.60 $292,070 $ 48.73
Realized gain on derivatives 13,384 1.72 118 0.02
Royalties, net of Alberta
Royalty Credit (71,515) (9.19) (53,107) (8.86)
Operating costs (87,979) (11.31) (55,108) (9.19)
-------------------------------------------------------------------------
Operating $231,913 $ 29.82 $183,973 $ 30.70
General and administrative (13,491) (1.73) (9,152) (1.53)
Management fee - - (887) (0.15)
Interest (16,434) (2.11) (12,844) (2.14)
Interest on convertible
debentures (10,441) (1.34) (7,921) (1.32)
Income and capital taxes (923) (0.12) (1,148) (0.19)
-------------------------------------------------------------------------
Funds from operations $190,624 $ 24.52 $152,021 $ 25.37
-------------------------------------------------------------------------
-------------------------------------------------------------------------Funds from operations of Advantage for the quarter ended September 30,
2007 decreased to $62.3 million from $63.1 million in the prior year. Funds
from operations for the nine months ended September 30, 2007 increased to
$190.6 million from $152.0 million compared to 2006. The cash netback per boe
for the three months ended September 30, 2007 remained comparable to the same
quarter of 2006, but decreased 3% from $25.37 to $24.52 for the nine months
ended September 30, 2007. The lower cash netback per boe for the nine months
ended September 30, 2007 is primarily due to higher royalties and operating
costs. Operating costs have steadily increased over the past year due to
significantly higher field costs associated with supplies and services that
has resulted from the high level of industry activity and an overall industry
labour cost increase. Although we have experienced significant upward pressure
on operating costs, it is notable that operating costs per boe for the quarter
remained comparable to the second quarter of 2007. When compared to the second
quarter of 2007, funds from operations was similar as production increased 8%,
mainly due to the acquisition of Sound, and was offset by decreased realized
natural gas prices before hedging of 25%. Reduced natural gas prices were
partially mitigated by increased realized crude oil and NGL prices before
hedging of 12% and an increase in realized hedging gains of $7.3 million.Depletion, Depreciation and Accretion
Three months ended Nine months ended
September 30 September 30
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Depletion,
depreciation &
accretion ($000) $ 68,743 $ 67,601 2% $194,026 $130,788 48%
per boe $ 25.46 $ 24.74 3% $ 24.94 $ 21.82 14%Depletion and depreciation of property and equipment is provided on the
"unit-of-production" method based on total proved reserves. The depletion,
depreciation and accretion ("DD&A") provision has increased 2% for the three
months and 48% for the nine months ended September 30, 2007. The nine months
increase is due to the considerable increases of daily production volumes,
mainly from the Ketch acquisition and the increase in the DD&A rate per boe
compared to the prior year. The increased DD&A rate per boe was due to a
higher valuation assigned for reserves from recent acquisitions than
accumulated from prior acquisitions and development activities.
Taxes
Current taxes paid or payable for the quarter ended September 30, 2007
amounted to $0.4 million, which is comparable to the $0.3 million expensed for
the same period of 2006. 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 nine months ended September 30,
2007, the Fund recognized an income tax expense of $0.2 million compared to a
reduction of $17.5 million for 2006. The impact of the Specified Investment
Flow-Through Entity ("SIFT") tax legislation is reflected in 2007 and resulted
in future income tax expense of $13.8 million. The new tax law has altered the
tax treatment of income trusts 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. As at September 30, 2007, we had a future
income tax liability balance of $84.1 million, compared to $61.9 million at
December 31, 2006. 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. As a result
of the Sound acquisition, Advantage recorded a future tax liability of
$22.0 million.
On October 30, 2007, the Federal government announced proposed corporate
income tax rate reductions effective January 1, 2008 to be phased in over the
next five years to 2012. These rate reductions will apply to the new tax on
distributions of income trusts and other specified investment flow-through
entities as of 2011 with a proposed rate reduction of 2% from the current 2011
tax rate and an additional 1.5% rate reduction in 2012. The Fund is currently
assessing the impact of such proposed income tax rate reductions and will
recognize a future income tax reduction once the proposed rate reductions are
substantively enacted.
Contractual Obligations and Commitments
The Fund has contractual obligations in the normal course of operations
including purchases of assets and services, operating agreements,
transportation commitments, sales contracts and convertible debentures. These
obligations are of a recurring and consistent nature and impact cash flow in
an ongoing manner. The following table is a summary of the Fund's remaining
contractual obligations and commitments. Advantage has no guarantees or off-
balance sheet arrangements other than as disclosed.2011 &
Payments due by period there-
($ millions) Total 2007 2008 2009 2010 after
-------------------------------------------------------------------------
Building leases $ 30.1 $ 1.2 $ 6.3 $ 6.7 $ 6.7 $ 9.2
Capital leases 8.7 0.7 1.9 2.0 2.2 1.9
Pipeline/transportation 7.8 1.7 4.8 1.2 0.1 -
Convertible debentures (1) 281.3 1.5 5.4 116.6 70.0 87.8
-------------------------------------------------------------------------
Total contractual
obligations $327.9 $ 5.1 $ 18.4 $126.5 $ 79.0 $ 98.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) As at September 30, 2007, Advantage had $281.3 million convertible
debentures outstanding. Each series of convertible debentures are
convertible to Trust Units based on an established conversion price.
The Fund expects that the obligations related to convertible
debentures will be settled either directly or indirectly through the
issuance of Trust Units.
(2) Bank indebtedness of $521.1 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) September 30, 2007
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 521,144
Working capital deficit (1) 24,666
-------------------------------------------------------------------------
Net debt $ 545,810
-------------------------------------------------------------------------
Trust Units outstanding (000) 133,847
Trust Unit closing market price ($/Trust Unit) $ 12.22
-------------------------------------------------------------------------
Market value $ 1,635,610
-------------------------------------------------------------------------
Capital lease obligation (long-term) $ 5,969
Convertible debentures maturity value (long-term) 274,401
-------------------------------------------------------------------------
Total capitalization $ 2,461,790
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.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 September 30, 2007, the Fund had 133.8 million Trust Units
outstanding. 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). The net proceeds of the offering were used to pay down
bank indebtedness and to subsequently fund capital and general corporate
expenditures. On September 5, 2007, Advantage issued 16,977,184 Trust Units to
finalize the acquisition of Sound. As at November 12, 2007, Advantage had
137.5 million Trust Units issued and outstanding.
On July 24, 2006, Advantage adopted a Premium Distribution™,
Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan").
For 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
nine months ended September 30, 2007, 2,862,545 Trust Units were issued as a
result of the Plan, generating $34.3 million reinvested in the Fund and
representing an approximate 19% participation rate.
As at September 30, 2007, the Fund had $281.3 million convertible
debentures outstanding that were convertible to 12.1 million Trust Units based
on the applicable conversion prices. During the nine months ended
September 30, 2007, $5,000 of convertible debentures were converted resulting
in the issuance of 375 Trust Units. Due to the acquisition of Sound,
$59,513,000 8.75% and $41,035,000 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 as 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 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 8.00% convertible debentures. As at November 12,
2007, the Fund had $224.6 million convertible debentures outstanding due to
the additional conversion of $19,000 convertible debentures to 1,011 Trust
Units and the maturity of $1,470,000 of the 10% convertible debentures
exchanged for 127,458 Trust Units on November 1, 2007.
Bank Indebtedness, Credit Facility and Other Obligations
At September 30, 2007, Advantage had bank indebtedness outstanding of
$521.1 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 secured
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.
At September 30, 2007, Advantage had a working capital deficiency of
$24.7 million. 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 and
convertible debentures. 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. Advantage has
no unusual working capital requirements. 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.
During the quarter ended September 30, 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. On
September 5, 2007, Advantage assumed two capital lease obligations in the
acquisition of Sound resulting in the recognition of a capital lease
obligation 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.Capital Expenditures
Three months ended Nine months ended
September 30 September 30
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Land and seismic $ 221 $ 1,461 $ 4,142 $ 4,739
Drilling, completions and
workovers 22,156 35,819 64,766 70,534
Well equipping and facilities 9,751 11,560 38,325 21,747
Other 290 767 559 1,358
-------------------------------------------------------------------------
$ 32,418 $ 49,607 $107,792 $ 98,378
Acquisition of Sound Energy Trust 22,374 - 22,374 -
Property acquisitions - 198 12,851 198
Property dispositions - (8,727) (427) (8,727)
-------------------------------------------------------------------------
Total capital expenditures $ 54,792 $ 41,078 $142,590 $ 89,849
-------------------------------------------------------------------------
-------------------------------------------------------------------------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 preserve a balance of year round access. We focus on areas
where past activity has yielded long-life reserves with high cash netbacks.
With the integration of the Ketch and Sound assets, 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 September 30, 2007, the Fund spent a net
$32.4 million and drilled a total of 18.3 net (31 gross) wells at a 100%
success rate. During the quarter we drilled 3 net (3 gross) oil wells and 2
net (2 gross) gas wells at Nevis, 2.8 net (4 gross) oil wells at Sunset, 1 net
(1 gross) each oil and gas well at Willesden Green, 3 net (3 gross) gas wells
at Girouxville, as well as several wells at other minor properties. Total
capital spending in the quarter included $8.7 million at Nevis, $5.9 million
at Willesden Green, $3.6 million at Sunset, $2.4 million at Martin Creek and
$1.6 million in Southeast Saskatchewan. Property acquisitions year to date
include a $12.9 million property acquisition in the first quarter for
producing properties and undeveloped land at the Fund's core area, Nevis and
$22.4 million related to the Sound acquisition in the third quarter which
represents the cash portion paid due to the exercise of the cash option
offered to Sound unitholders.
Capital spending, before property acquisitions and dispositions, for the
nine months ended September 30, 2007 was below our internal plans due to
prolonged wet weather resulting in a long spring break-up and restricted
access. The reduced spending has been partially responsible for delays in
bringing on expected production in the second and third quarters of 2007.
However, the Fund still anticipates spending the full capital budget for the
2007 year, in addition to the Sound acquisition.
The following table summarizes the various funding requirements during
the nine months ended September 30, 2007 and the sources of funding to meet
those requirements.Sources and Uses of Funds
Nine months ended
($000) September 30, 2007
-------------------------------------------------------------------------
Sources of funds
Funds from operations $ 190,624
Units issued, net of costs 104,240
Increase in bank indebtedness 2,611
Property dispositions 427
-------------------------------------------------------------------------
$ 297,902
-------------------------------------------------------------------------
Uses of funds
Distributions to Unitholders $ 121,900
Expenditures on property and equipment 107,792
Increase in working capital 25,566
Acquisition of Sound Energy Trust 22,374
Property acquisitions 12,851
Expenditures on asset retirement 4,835
Reduction of capital lease obligations 2,584
-------------------------------------------------------------------------
$ 297,902
-------------------------------------------------------------------------
Quarterly Performance
($000, except as otherwise 2007 2006
indicated) Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 115,991 108,978 114,324 117,134
Crude oil and NGLs (bbls/d) 10,014 8,952 9,958 9,570
Total (boe/d) 29,346 27,115 29,012 29,092
Average prices
Natural gas ($/mcf)
Excluding hedging $ 5.62 $ 7.54 $ 7.61 $ 6.90
Including hedging $ 6.35 $ 7.52 $ 8.06 $ 7.27
AECO monthly index $ 5.62 $ 7.37 $ 7.46 $ 6.36
Crude oil and NGLs ($/bbl)
Excluding hedging $ 69.03 $ 61.84 $ 56.84 $ 54.58
Including hedging $ 68.51 $ 61.93 $ 58.64 $ 55.86
WTI (US$/bbl) $ 75.33 $ 65.02 $ 58.12 $ 60.21
Total revenues (before royalties) $130,830 $125,075 $135,502 $127,539
Net income (loss) $(26,202) $ 4,531 $ 341 $ 8,736
per Trust Unit - basic $ (0.22) $ 0.04 $ 0.00 $ 0.08
- diluted $ (0.22) $ 0.04 $ 0.00 $ 0.08
Funds from operations $ 62,345 $ 62,634 $ 65,645 $ 62,737
Distributions declared $ 55,017 $ 52,096 $ 50,206 $ 58,791
($000, except as otherwise 2006 2005
indicated) Q3 Q2 Q1 Q4
-------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 122,227 70,293 65,768 72,587
Crude oil and NGLs (bbls/d) 9,330 6,593 6,760 7,106
Total (boe/d) 29,701 18,309 17,721 19,204
Average prices
Natural gas ($/mcf)
Excluding hedging $ 5.89 $ 6.18 $ 8.69 $ 11.68
Including hedging $ 5.90 $ 6.18 $ 8.69 $ 10.67
AECO monthly index $ 6.03 $ 6.28 $ 9.31 $ 11.68
Crude oil and NGLs ($/bbl)
Excluding hedging $ 67.77 $ 68.69 $ 58.26 $ 60.14
Including hedging $ 67.77 $ 68.69 $ 58.26 $ 59.53
WTI (US$/bbl) $ 70.55 $ 70.75 $ 63.88 $ 60.04
Total revenues (before royalties) $124,521 $ 80,766 $ 86,901 $110,172
Net income (loss) $ 1,209 $ 23,905 $ 15,964 $ 25,846
per Trust Unit - basic $ 0.01 $ 0.38 $ 0.27 $ 0.45
- diluted $ 0.01 $ 0.38 $ 0.27 $ 0.45
Funds from operations $ 63,110 $ 42,281 $ 46,630 $ 60,906
Distributions declared $ 60,498 $ 53,498 $ 44,459 $ 43,265The table above highlights the Fund's performance for the third quarter
of 2007 and also for the preceding seven quarters. During the first quarter of
2006 we experienced a decrease in daily production due to a one-time
adjustment for several payout wells, restricted production on wells in Chip
Lake and Nevis, and some minor non-core property dispositions that occurred in
2005. Production increased in the second quarter of 2006 as some prior quarter
issues were resolved and the addition of eight days of production from the
Ketch properties. Production further increased in the third quarter of 2006 as
the Ketch acquisition was fully integrated with Advantage. The second quarter
of 2007 encountered a temporary production decrease as expected due to several
facility turnarounds that had been planned for the period. The third quarter
of 2007 includes the financial and operating results from the acquired Sound
properties for 26 days. Advantage's revenues and funds from operations
increased significantly beginning in the third quarter of 2006 primarily due
to the production from the merger with Ketch, offset by lower natural gas
prices. Net income has been lower during the last four quarters due to reduced
natural gas prices realized during the periods, amortization of the management
internalization consideration and increased depletion and depreciation expense
due to the Ketch merger.
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 property and equipment, 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.
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 Vice-President Finance 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. During the third
quarter of 2007, there were no significant changes that would materially
affect, or are reasonably likely to materially affect, the internal controls
over financial reporting.
Because of inherent limitations, internal control over financial
reporting may not prevent or detect misstatements and even those systems
determined to be effective can provide only reasonable assurance with respect
to the financial statement preparation and presentation. Further, 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 that
the degree of compliance with the policies or procedures may deteriorate.
Outlook
The Fund's 2007 Budget, as approved by the Board of Directors, retained a
high degree of activity and focused on drilling in many of our key properties
where a high level of success was realized through 2006. Capital has also been
directed to accommodate facility expansions and further develop enhanced
recovery schemes as necessary. New drill bit additions are expected to be more
effective in replacing production as corporate declines have continued to
subside through the first nine months of 2007. Advantage's production now
contains very little flush production from high impact wells and concentrated
drilling programs (from 2004 and 2005 activities) creating a balanced and
predictable platform.
During the third quarter of 2007, we realized significant impacts to our
production due to third party plant outages. Wet weather through July affected
the tie-in of new well production and reduced capital activity in the second
and third quarters of 2007. Overall, we expect annual production in 2007 to be
approximately 30,000 boe/d with a year-end exit rate of approximately
35,000 boe/d.
Advantage's 2007 capital expenditures is estimated to be approximately
$150 million which includes activity for the Sound assets during the fourth
quarter of 2007. For the remainder of 2007, our capital program will be
directed mainly at oil opportunities due to the continued strong commodity
prices.
Per unit operating costs for 2007 are estimated to be in the $11.60 to
$12.00/boe range and $12.50 to $13.50/boe range for the fourth quarter with
the full impact of the Sound acquisition that had higher operating cost
properties. Higher property taxes, surface rentals and additional trucking
costs due to continued pipeline restrictions in Southeast Saskatchewan have
been realized so far in 2007. Advantage is undertaking several operating cost
reduction initiatives throughout 2007 to help offset these increases and we
have begun to realize some key achievements in this area.
On October 25, 2007, the Alberta Provincial Government announced changes
to royalties for conventional oil, natural gas and oil sands that will become
effective January 1, 2009. Preliminary indications are that the changes will
have a negligible impact on Advantage since we have a significant number of
lower rate wells within our long life properties producing in Alberta.
Advantage also has a significant Horseshoe Canyon coal bed methane drilling
inventory that can be pursued which will also have a favorable royalty
treatment due to lower rate per well characteristics. Our exposure in
Northeast British Columbia and Saskatchewan also affords us further
flexibility with mitigating the royalty impact in our capital program. For
2007, we estimate our royalty rate to be approximately 19-20%.
Advantage's funds from operations in 2007 will continue to be impacted by
the volatility of crude oil and natural gas prices and the $US/$Canadian
exchange rate. Advantage will continue to follow its strategy of acquiring
properties that provide low risk development opportunities and enhance long-
term cash flow. Advantage will also 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 acquisitions.
Looking forward, Advantage's high quality assets combined with a greater
than five year drilling inventory, hedging program and significant tax pools
provides many options for the Fund and we are committed to maximizing value
generation for our Unitholders.
Additional 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.
November 12, 2007Consolidated Financial Statements
Consolidated Balance Sheets
September 30, December 31,
(thousands of dollars) 2007 2006
-------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Accounts receivable $ 89,564 $ 79,537
Prepaid expenses and deposits 19,688 16,878
Derivative asset (note 11) 12,692 9,840
-------------------------------------------------------------------------
121,944 106,255
Deposit on property acquisition - 1,410
Derivative asset (note 11) 189 593
Fixed assets (note 3) 2,194,515 1,753,058
Goodwill 120,271 120,271
-------------------------------------------------------------------------
$2,436,919 $1,981,587
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 105,234 $ 116,109
Distributions payable to Unitholders 20,077 18,970
Current portion of capital lease
obligations (note 4) 1,821 2,527
Current portion of convertible debentures
(note 5) 6,786 1,464
Derivative liability (note 11) 1,607 -
-------------------------------------------------------------------------
135,525 139,070
Capital lease obligations (note 4) 5,969 305
Bank indebtedness (note 6) 521,144 410,574
Convertible debentures (note 5) 230,924 170,819
Asset retirement obligations (note 7) 53,737 34,324
Future income taxes (note 8) 84,113 61,939
-------------------------------------------------------------------------
1,031,412 817,031
-------------------------------------------------------------------------
Unitholders' Equity
Unitholders' capital (note 9) 1,973,513 1,592,758
Convertible debentures equity component (note 5) 46,010 8,041
Contributed surplus (note 9) 1,739 863
Accumulated deficit (note 10) (615,755) (437,106)
-------------------------------------------------------------------------
1,405,507 1,164,556
-------------------------------------------------------------------------
$2,436,919 $1,981,587
-------------------------------------------------------------------------
Commitments (note 12)
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Income,
Comprehensive Income and Accumulated Deficit
Three Three Nine Nine
months months months months
(thousands of dollars, ended ended ended ended
except for per Trust Sept. 30, Sept. 30, Sept. 30, Sept. 30,
Unit amounts) (unaudited) 2007 2006 2007 2006
-------------------------------------------------------------------------
Revenue
Petroleum and natural
gas $ 123,620 $ 124,403 $ 378,023 $ 292,070
Realized gain on
derivatives (note 11) 7,210 118 13,384 118
Unrealized gain (loss)
on derivatives (note 11) (53) 13,725 (1,956) 14,257
Royalties, net of
Alberta Royalty Credit (22,601) (22,945) (71,515) (53,107)
-------------------------------------------------------------------------
108,176 115,301 317,936 253,338
-------------------------------------------------------------------------
Expenses
Operating 30,790 24,369 87,979 55,108
General and administrative 4,543 4,766 13,491 9,152
Unit-based compensation
(note 9) 156 - 785 -
Management fee - - - 887
Performance incentive - - - 2,380
Management
internalization (note 9) 2,455 7,428 13,174 7,952
Interest 6,242 5,711 16,434 12,844
Interest and accretion
on convertible
debentures 4,554 3,912 12,289 9,423
Depletion, depreciation
and accretion 68,743 67,601 194,026 130,788
-------------------------------------------------------------------------
117,483 113,787 338,178 228,534
-------------------------------------------------------------------------
Income (loss) before taxes
and non-controlling
interest (9,307) 1,514 (20,242) 24,804
Future income tax expense
(reduction) 16,496 (7) 165 (17,451)
Income and capital taxes 399 312 923 1,148
-------------------------------------------------------------------------
16,895 305 1,088 (16,303)
-------------------------------------------------------------------------
Net income (loss) before
non-controlling interest (26,202) 1,209 (21,330) 41,107
Non-controlling interest - - - 29
-------------------------------------------------------------------------
Net income (loss) and
comprehensive income (loss) (26,202) 1,209 (21,330) 41,078
Accumulated deficit,
beginning of period (534,536) (327,762) (437,106) (269,674)
Distributions declared (55,017) (60,498) (157,319) (158,455)
-------------------------------------------------------------------------
Accumulated deficit, end
of period $ (615,755) $ (387,051) $ (615,755) $ (387,051)
-------------------------------------------------------------------------
Net income (loss) per
Trust Unit (note 9)
Basic $ (0.22) $ 0.01 $ (0.19) $ 0.56
Diluted $ (0.22) $ 0.01 $ (0.19) $ 0.56
-------------------------------------------------------------------------
-------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
Three Three Nine Nine
months months months months
ended ended ended ended
(thousands of dollars) Sept. 30, Sept. 30, Sept. 30, Sept. 30,
(unaudited) 2007 2006 2007 2006
-------------------------------------------------------------------------
Operating Activities
Net income (loss) $ (26,202) $ 1,209 $ (21,330) $ 41,078
Add (deduct) items not
requiring cash:
Unrealized loss (gain)
on derivatives 53 (13,725) 1,956 (14,257)
Unit-based compensation 156 - 785 -
Performance incentive - - - 2,380
Management
internalization 2,455 7,428 13,174 7,952
Accretion on convertible
debentures 644 604 1,848 1,502
Depletion, depreciation
and accretion 68,743 67,601 194,026 130,788
Future income tax 16,496 (7) 165 (17,451)
Non-controlling interest - - - 29
Expenditures on asset
retirement (1,128) (1,065) (4,835) (2,512)
Changes in non-cash
working capital 4,097 16,926 (20,023) 14,083
-------------------------------------------------------------------------
Cash provided by
operating activities 65,314 78,971 165,766 163,592
-------------------------------------------------------------------------
Financing Activities
Units issued, net of costs
(note 9) (246) 152,200 104,240 152,673
Increase (decrease) in
bank indebtedness 35,373 (128,323) 2,611 (68,827)
Reduction of capital
lease obligations (514) (371) (2,584) (642)
Distributions to
Unitholders (42,595) (63,359) (121,900) (152,106)
-------------------------------------------------------------------------
Cash used in financing
activities (7,982) (39,853) (17,633) (68,902)
-------------------------------------------------------------------------
Investing Activities
Expenditures on property
and equipment (32,418) (49,607) (107,792) (98,378)
Property acquisitions - (198) (12,851) (198)
Property dispositions - 8,727 427 8,727
Acquisition of Ketch
Resources Trust - - - (10,236)
Acquisition of Sound
Energy Trust (note 2) (22,374) - (22,374) -
Changes in non-cash
working capital (2,540) 1,960 (5,543) 5,395
-------------------------------------------------------------------------
Cash used in investing
activities (57,332) (39,118) (148,133) (94,690)
-------------------------------------------------------------------------
Net change in cash - - - -
Cash, beginning of period - - - -
-------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow
Information
Interest paid $ 6,977 $ 9,602 $ 24,153 $ 25,294
Taxes paid $ 244 $ 176 $ 1,074 $ 1,446
see accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2007 (unaudited)
All tabular amounts in thousands except for Trust Units and per Trust
Unit amounts
The interim consolidated financial statements of Advantage Energy Income
Fund ("Advantage" or the "Fund") have been prepared by management in
accordance with Canadian generally accepted accounting principles using
the same accounting policies as those set out in note 2 to the
consolidated financial statements for the year ended December 31, 2006,
except as described below. The interim consolidated financial statements
should be read in conjunction with the audited consolidated financial
statements of Advantage for the year ended December 31, 2006 as set out
in Advantage's Annual Report.
1. Changes in Accounting Policies
(a) Financial Instruments
Effective January 1, 2007, the Fund adopted CICA Handbook sections
3855 "Financial Instruments - Recognition and Measurement", 3862
"Financial Instruments - Disclosures", 3863 "Financial Instruments -
Presentation", and 3865 "Hedges".
Section 3855 "Financial Instruments - Recognition and Measurement"
establishes criteria for recognizing and measuring financial
instruments including financial assets, financial liabilities and
non-financial derivatives. Under this standard, all financial
instruments must initially be 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. Upon
adoption and 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 by the standard have been
classified as such by the Fund. As the Fund frequently utilizes 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. Section 3865 "Hedges" provides
an alternative to recognizing gains and losses on derivatives in
earnings if the instrument is designated as part of a hedging
relationship and meets the necessary criteria. Under the alternative
hedge accounting treatment, gains and losses on derivatives
classified as effective 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 income,
comprehensive income 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 the statement of cash flows as
a result of their recognition.
In some instances, derivative financial instruments can be embedded
within other contracts. Embedded derivatives within a host contract
must be recorded separately from the host contract when their
economic characteristics and risks 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 selected January 1, 2003, as its
accounting transition date for any potential embedded derivatives and
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. Section 3855 requires that
such transaction costs incurred on held for trading financial
instruments be 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.
The Fund has adopted the new standards prospectively as required
which allows amendments to the carrying values of financial
instruments, effective as of the adoption date, to be recognized as
an adjustment to the beginning balance of accumulated deficit. As the
new standards have not resulted in any significant changes to the
recognition and measurement of the Fund's financial instruments, no
adjustment to accumulated deficit was required. The new standards
also require several additional disclosures in the notes to the
financial statements. Among the disclosures required, the Fund must
disclose the exposure to various risks associated with financial
instruments and the policies that exist to manage these risks.
(b) Comprehensive Income
Effective January 1, 2007, the Fund adopted CICA Handbook section
1530 "Comprehensive Income". The Fund has adopted this section
retroactively and there were no changes to prior periods.
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 a new equity category
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.
(c) Accounting Changes
Effective January 1, 2007, the Fund adopted the revised
recommendations of CICA section 1506 "Accounting Changes". The new
recommendations permit voluntary changes in accounting policy only if
they result in financial statements which provide more reliable and
relevant information. Accounting policy changes are applied
retrospectively unless it is impractical to determine the period or
cumulative impact of the change. Corrections of prior period errors
are applied retrospectively and changes in accounting estimates are
applied prospectively by including the changes in earnings. The
guidance was effective for all changes in accounting polices, changes
in accounting estimates and corrections of prior period errors
initiated in periods beginning on or after January 1, 2007.
(d) Recent Accounting Pronouncements Issued But Not Implemented
The CICA has issued section 1535 "Capital Disclosures", which will be
effective January 1, 2008 for the Fund. Section 1535 will require the
Fund to provide additional disclosures relating to capital and how it
is managed. It is not anticipated that the adoption of section 1535
will impact the amounts reported in the Fund's financial statements
as they primarily relate to disclosure.
(e) Comparative Figures
Certain comparative figures have been reclassified to conform to the
current year's presentation.
2. Acquisition of Sound Energy Trust
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 $1.0 million of acquisition costs. Sound Unitholders
and Exchangeable Shareholders could elect to receive 0.30 Advantage
Trust Units for each Sound Trust Unit or receive $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 is
being 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 $ 501,476 16,977,184 Trust
Accounts receivable 27,237 Units issued $ 228,852
Prepaid expenses and Cash 21,404
deposits 3,930 Acquisition costs
Derivative asset, net 2,797 incurred 970
Bank indebtedness (107,959) -----------
Convertible debentures (101,553) $ 251,226
Accounts payable and -----------
accrued liabilities (34,431)
Future income taxes (22,009)
Asset retirement
obligations (16,695)
Capital lease
obligations (1,567)
-----------
$ 251,226
-----------
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 is subject to refinement as certain cost estimates are
realized and the tax balances are finalized.
3. Fixed Assets
Accumulated
Depletion and Net Book
September 30, 2007 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 2,957,081 $ 768,005 $ 2,189,076
Furniture and equipment 9,671 4,232 5,439
---------------------------------------------------------------------
$ 2,966,752 $ 772,237 $ 2,194,515
---------------------------------------------------------------------
Accumulated
Depletion and Net Book
December 31, 2006 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 2,324,948 $ 576,707 $ 1,748,241
Furniture and equipment 8,175 3,358 4,817
---------------------------------------------------------------------
$ 2,333,123 $ 580,065 $ 1,753,058
---------------------------------------------------------------------
During the nine months ended September 30, 2007, Advantage
capitalized general and administrative expenditures and unit-based
compensation directly related to exploration and development
activities of $6.0 million (September 30, 2006 - $4.0 million).
4. Capital Lease Obligations
The Fund has capital leases on a variety of fixed assets. Future
minimum lease payments at September 30, 2007 consist of the
following:
2007 $ 708
2008 1,906
2009 2,040
2010 2,200
2011 1,925
----------------------------------
8,779
Less amounts
representing interest (989)
----------------------------------
7,790
Current portion (1,821)
----------------------------------
$ 5,969
----------------------------------
During the second quarter 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 2) 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.
The amortization of fixed assets subject to capital leases is
recorded in depletion and depreciation expense.
5. 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 Nov. 1, Aug. 1, Feb. 1, June 30,
2007 2008 2009 2009
Conversion price $ 13.30 $ 17.00 $ 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%
--------------------------------------------------------
Trading symbol AVN.DBC AVN.DBE AVN.DBD
Issue date Sep. 15, May 18, Sep. 15,
2004 2005 2004
Maturity date Oct. 1, June 30, Dec. 1,
2009 2010 2011
Conversion price $ 20.25 $ 24.96 $ 21.00
Liability
component $ 71,631 $ 66,981 $ 47,444
Equity component 3,369 2,971 2,556
--------------------------------------------------------
Gross proceeds 75,000 69,952 50,000
Issuance costs (3,190) - (2,190)
--------------------------------------------------------
Net proceeds $ 71,810 $ 69,952 $ 47,810
--------------------------------------------------------
8.00% Total
-------------------------------------------
Trading symbol AVN.DBG
Issue date Nov. 13,
2006
Maturity date Dec. 31,
2011
Conversion price $ 20.33
Liability
component $ 14,884 $ 387,826
Equity component 26,561 53,679
-------------------------------------------
Gross proceeds 41,445 441,505
Issuance costs - (11,907)
-------------------------------------------
Net proceeds $ 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
---------------------------------------------------------------------
10.00% After November 1, 2006
and before November 1, 2007 $1,025
---------------------------------------------------------------------
9.00% After August 1, 2007
and before August 1, 2008 $1,025
---------------------------------------------------------------------
8.25% After February 1, 2007
and on or before February 1, 2008 $1,050
After February 1, 2008 and
before February 1, 2009 $1,025
---------------------------------------------------------------------
8.75% After June 30, 2007 and
on or before June 30, 2008 $1,050
After June 30, 2008 and
before June 30, 2009 $1,025
---------------------------------------------------------------------
7.50% After October 1, 2007 and
on or before October 1, 2008 $1,050
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, 2007 and
on or before December 1, 2008 $1,050
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 September 30, 2007 and
changes in the liability and equity components during the nine months
ended September 30, 2007 are as follows:
10.00% 9.00% 8.25% 8.75%
---------------------------------------------------------------------
Debentures
outstanding $ 1,480 $ 5,392 $ 4,867 $ 59,513
---------------------------------------------------------------------
Liability
component:
Balance at
Dec. 31, 2006 $ 1,464 $ 5,235 $ 4,676 $ -
Assumed on Sound
acquisition - - - 48,700
Accretion of
discount 19 73 68 21
Converted to
Trust Units (5) - - -
---------------------------------------------------------------------
Balance at
Sep. 30, 2007 $ 1,478 $ 5,308 $ 4,744 $ 48,721
---------------------------------------------------------------------
Equity
component:
Balance at
Dec. 31, 2006 $ 59 $ 229 $ 248 $ -
Assumed on Sound
acquisition - - - 11,408
Converted to
Trust Units - - - -
---------------------------------------------------------------------
Balance at
Sep. 30, 2007 $ 59 $ 229 $ 248 $ 11,408
---------------------------------------------------------------------
7.50% 6.50% 7.75%
--------------------------------------------------------
Debentures
outstanding $ 52,268 $ 69,952 $ 46,766
--------------------------------------------------------
Liability
component:
Balance at
Dec. 31, 2006 $ 49,782 $ 67,361 $ 43,765
Assumed on
Sound
acquisition - - -
Accretion of
discount 665 546 446
Converted to
Trust Units - - -
--------------------------------------------------------
Balance at
Sep. 30, 2007 $ 50,447 $ 67,907 $ 44,211
--------------------------------------------------------
Equity
component:
Balance at
Dec. 31, 2006 $ 2,248 $ 2,971 $ 2,286
Assumed on
Sound
acquisition - - -
Converted to
Trust Units - - -
--------------------------------------------------------
Balance at
Sep. 30, 2007 $ 2,248 $ 2,971 $ 2,286
--------------------------------------------------------
8.00% Total
-------------------------------------------
Debentures
outstanding $ 41,035 $ 281,273
-------------------------------------------
Liability
component:
Balance at
Dec. 31, 2006 $ - $ 172,283
Assumed on
Sound
acquisition 14,884 63,584
Accretion of
discount 10 1,848
Converted to
Trust Units - (5)
-------------------------------------------
Balance at
Sep. 30, 2007 $ 14,894 $ 237,710
-------------------------------------------
Equity
component:
Balance at
Dec. 31, 2006 $ - $ 8,041
Assumed on
Sound
acquisition 26,561 37,969
Converted to
Trust Units - -
-------------------------------------------
Balance at
Sep. 30, 2007 $ 26,561 $ 46,010
-------------------------------------------
Due to the acquisition of Sound (note 2), 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 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 nine months ended September 30, 2007, $5,000 debentures
(September 30, 2006 - $24,333,000) were converted resulting in the
issuance of 375 Trust Units (September 30, 2006 - 1,286,901 Trust
Units).
6. 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
1.25% depending on the Fund's debt to cash flow ratio. The credit
facilities are secured 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 2008. 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 first payment due one year and one day after commencement of
the term. The credit facilities contain standard commercial covenants
for facilities of this nature. The only financial covenant is a
requirement for Advantage Oil & Gas Ltd. ("AOG") to maintain a
minimum cash flow to interest expense ratio of 3.5:1, determined on a
rolling four quarter basis. 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 nine months ended September 30, 2007, the
effective interest rate on the outstanding amounts under the facility
was approximately 5.6% (September 30, 2006 - 5.0%).
7. 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 $217.5
million which will be incurred between 2007 to 2057. An inflation
rate of 2% and a credit-adjusted risk-free rate of 7% were used to
calculate the fair value of the asset retirement obligations.
A reconciliation of the asset retirement obligations is provided
below:
September 30, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 34,324 $ 21,263
Accretion expense 1,854 1,684
Assumed in Ketch acquisition - 7,930
Assumed in Sound acquisition (note 2) 16,695 -
Liabilities incurred 5,699 9,421
Liabilities settled (4,835) (5,974)
---------------------------------------------------------------------
Balance, end of period $ 53,737 $ 34,324
---------------------------------------------------------------------
8. Income Taxes
On June 12, 2007 the Federal government's bill regarding the taxation
of distributions from trusts beginning January 1, 2011 received a
third reading and on June 22, 2007 received Royal Assent, thus
becoming fully enacted. As a result, a net expense of $13.8 million
was recognized in the future income tax provision for the nine months
ended September 30, 2007.
9. 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 375 5
Issued on exercise of Trust Unit rights 37,500 562
Distribution reinvestment plan 2,862,545 34,313
Issued for cash, net of costs 8,600,000 104,094
Issued for Sound acquisition,
net of costs (note 2) 16,977,184 228,608
Management internalization forfeitures (21,459) (434)
---------------------------------------------------------------------
133,846,615 $ 1,985,173
---------------------------------------------------------------------
Management internalization escrowed
Trust Units (11,660)
---------------------------------------------------------------------
Balance at September 30, 2007 $ 1,973,513
---------------------------------------------------------------------
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).
During the nine months ended September 30, 2007, 2,862,545 Trust
Units were issued under the Premium Distribution(™), Distribution
Reinvestment, and Optional Trust Unit Purchase Plan, generating
$34.3 million reinvested in the Fund.
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. 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 nine
months ended September 30, 2007, a total of 21,459 Trust Units issued
for the management internalization were forfeited and $13.2 million
has been recognized as management internalization expense. As at
September 30, 2007, 1,197,077 Trust Units remain held in escrow.
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 2). Trust Unit issuance costs of $0.2 million were
incurred for the Sound acquisition.
(b) Trust Units Rights Incentive Plan
Series B
Number Price
--------------------------------------------------------
Balance at December 31, 2006 187,500 $ 10.97
Exercised (37,500) -
Reduction of exercise price - (1.35)
--------------------------------------------------------
Balance at September 30, 2007 150,000 $ 9.62
--------------------------------------------------------
Expiration date June 17, 2008
--------------------------------------------------------
(c) Unit-Based Compensation
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 purpose of the long-term compensation plans is to
retain and attract employees, to reward and encourage performance,
and to focus employees on operating and financial performance that
result 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. 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 based on the "fair value" of the RTUs at the grant
date and is recognized as compensation expense over the service
period. This valuation incorporates the period end Trust Unit price,
the estimated number of RTUs to vest, and certain management
estimates. The maximum fair value 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. No RTUs have been granted
under the Plan at this time and accordingly, no compensation expense
relating to the RTUs has been recognized in the interim financial
statements. Once the calendar year is completed and the final Trust
Unit return is calculated for the return period, RTUs may be granted
and consequently, compensation expense may be recognized at that
time. As the Fund did not meet the 2006 grant thresholds, there was
no RTU grant made for the 2006 year.
For the nine months ended September 30, 2007, the Fund has accrued
unit-based compensation expense of $0.8 million and has capitalized
$0.3 million related to Trust Units issuable for the retention of
certain employees of the Fund.
(d) Net Income (Loss) per Trust Unit
The calculation of basic and diluted net income (loss) per Trust Unit
are derived from both income available to Unitholders and weighted
average Trust Units outstanding calculated as follows:
Three Three Nine Nine
months months months months
ended ended ended ended
Sep. 30, Sep. 30, Sep. 30, Sep. 30,
2007 2006 2007 2006
---------------------------------------------------------------------
Income (loss)
available to
Unitholders
Basic $ (26,202) $ 1,209 $ (21,330) $ 41,078
---------------------------------------------------------------------
Diluted $ (26,202) $ 1,209 $ (21,330) $ 41,078
---------------------------------------------------------------------
Weighted average
Trust Units
outstanding
Basic 120,079,919 98,780,595 114,131,771 73,544,345
Trust Units
Rights
Incentive
Plan
- Series A - - - 58,223
Trust Units
Rights
Incentive
Plan
- Series B - 63,111 - 86,621
Management
internalization - 55,069 - 28,944
---------------------------------------------------------------------
Diluted 120,079,919 98,898,775 114,131,771 73,718,133
---------------------------------------------------------------------
The calculation of diluted net income (loss) per Trust Unit excludes
all series of convertible debentures for the three and nine months
ended September 30, 2007 and 2006 as well as all of the Series B
Trust Unit Rights and Management Internalization escrowed Trust Units
for the three and nine months ended September 30, 2007 as the impact
would be anti-dilutive. All of the remaining Series A Trust Unit
Rights were exercised July 7, 2006. Total weighted average Trust
Units issuable in exchange for the convertible debentures and
excluded from the diluted net income (loss) per Trust Unit
calculation for the three and nine months ended September 30, 2007
were 9,389,620 and 8,690,007, respectively (September 30, 2006 -
8,337,771 and 6,793,997, respectively). As at September 30, 2007, the
total convertible debentures outstanding were immediately convertible
to 12,069,078 Trust Units (September 30, 2006 - 8,334,453).
10. Accumulated Deficit
Accumulated deficit consists of accumulated income and accumulated
distributions for the Fund since inception as follows:
September 30, December 31,
2007 2006
---------------------------------------------------------------------
Accumulated Income $ 206,193 $ 227,523
Accumulated Distributions (821,948) (664,629)
---------------------------------------------------------------------
Accumulated Deficit $ (615,755) $ (437,106)
---------------------------------------------------------------------
For the nine months ended September 30, 2007, the Fund declared
$157.3 million in distributions, representing $1.35 per distributable
Trust Unit (nine months ended September 30, 2006 - $158.5 million
representing $2.10 per distributable Trust Unit).
11. 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 September 30, 2007, 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 5) resulting in fair values that
will vary over time as market conditions change. As at September 30,
2007, the estimated fair value of the total outstanding convertible
debenture obligation was $281.2 million (December 31, 2006 - $180.0
million). The fair value of the liability component of convertible
debentures was determined based on a discounted cash flow model
assuming no future conversions and continuation of current interest
and principal payments. The Fund applied discount rates of between 7
and 8% considering current available market information, assumed
credit adjustments, and various terms to maturity.
Advantage has an established hedging strategy and manages 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 value of the
derivatives are determined through valuation models completed 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.
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. 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 generally enters into
derivative contracts with investment grade institutions that are
members of Advantage's credit facility syndicate to further mitigate
associated credit risk.
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
all 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 funds from operations and the existing credit facility.
The Fund's bank indebtedness is subject to a $710 million credit
facility agreement which 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 first
payment due one year and one day after commencement of the 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 2007 to 2011 (note 5). Interest payments are made
semi-annually with excess funds from 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 option 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.
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% interest rate fluctuation for the nine months ended
September 30, 2007 could potentially have impacted net income by
approximately $1.9 million for that period.
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 September 30, 2007 could impact net income by
approximately $2.2 million for the nine months ended September 30,
2007. As well, a change of 10% in the forward crude oil prices used
to calculate the fair value of the crude oil derivatives at September
30, 2007 could impact net income by $0.9 million for the nine months
ended September 30, 2007. A change of 10% in the forward power prices
used to calculate the fair value of the power derivatives at
September 30, 2007 could impact net income by $0.2 million for the
nine months ended September 30, 2007. A similar change in the
currency rate assumption underlying the derivatives fair value does
not have a material impact on net income.
As at September 30, 2007 the Fund had the following derivatives in
place:
Description of
Derivative Term Volume Average Price
---------------------------------------------------------------------
Natural gas - AECO
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.16/mcf
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.55/mcf
Fixed price November 2007
to March 2008 7,109 mcf/d Cdn$9.54/mcf
Collar March 2007 to
December 2007 9,478 mcf/d Floor Cdn$7.91/mcf
Ceiling Cdn$9.50/mcf
Collar May 2007 to
December 2007 4,739 mcf/d Floor Cdn$7.91/mcf
Ceiling Cdn$9.50/mcf
Collar November 2007
to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$10.29/mcf
Collar November 2007 to
March 2008 7,109 mcf/d Floor Cdn$8.70/mcf
Ceiling Cdn$10.71/mcf
Crude oil - WTI
Collar January 2007 to
December 2007 500 bbls/d Floor US$70.00/bbl
Ceiling US$74.30/bbl
Collar March 2007 to
December 2007 1,000 bbls/d Floor US$57.00/bbl
Ceiling US$70.00/bbl
Collar April 2007 to
December 2007 500 bbls/d Floor US$60.00/bbl
Ceiling US$71.50/bbl
Electricity - Alberta Pool Price
Fixed price April 2006 to
December 2007 0.5 MW Cdn$60.79/MWh
Fixed price January 2007 to
December 2007 3.0 MW Cdn$56.00/MWh
Fixed price January 2008 to
December 2008 3.0 MW Cdn$54.00/MWh
As at September 30, 2007 the fair value of the derivatives
outstanding resulted in an asset of approximately $12,881,000
(December 31, 2006 - $10,433,000) and a liability of approximately
$1,607,000 (December 31, 2006 - nil). For the nine months ended
September 30, 2007, $1,956,000 was recognized in income as an
unrealized derivative loss (September 30, 2006 - $14,257,000
unrealized derivative gain) and $13,384,000 was recognized in income
as a realized derivative gain (September 30, 2006 - $118,000 realized
derivative gain).
As a result of the Sound acquisition (note 2), the Fund assumed
several derivatives, which had an estimated net fair market value of
$2,797,000 on closing.
In addition, the Fund has the following physical natural gas
contracts in place that are not recognized on the balance sheet at
fair value, but instead have gains and losses recognized in earnings
as the contracts settle:
Description of
Physical Contract Term Volume Average Price
---------------------------------------------------------------------
Natural gas - AECO
Collar April 2007 to
October 2007 4,739 mcf/d Floor Cdn$7.12/mcf
Ceiling Cdn$8.67/mcf
Collar April 2007 to
October 2007 4,739 mcf/d Floor Cdn$6.86/mcf
Ceiling Cdn$9.13/mcf
Collar April 2007 to
October 2007 9,478 mcf/d Floor Cdn$7.39/mcf
Ceiling Cdn$9.63/mcf
Collar April 2007 to
October 2007 9,478 mcf/d Floor Cdn$6.33/mcf
Ceiling Cdn$7.20/mcf
12. Commitments
Advantage has several lease commitments relating to office buildings.
As a result of the Sound acquisition (note 2), Advantage assumed one
office lease and has renegotiated additional leases to accommodate
the growth of the Fund. The estimated annual minimum operating lease
rental payments for the buildings are as follows:
2007 $ 1,187
2008 6,283
2009 6,710
2010 6,725
2011 4,280
2012 & thereafter 4,868
-------------------------------------------------
$ 30,053
-------------------------------------------------
Directors Legal Counsel
Steven E. Balog(2) Burnet, Duckworth and Palmer LLP
Gary F. Bourgeois
Kelly I. Drader Abbreviations
Robert B. Hodgins(1)
John A. Howard(2) bbls - barrels
Andy J. Mah bbls/d - barrels per day
Ronald A. McIntosh(1)(2) boe - barrels of oil equivalent
Sheila H. O'Brien(3) (6 mcf = 1 bbl)
Carol D. Pennycook(1)(3) boe/d - barrels of oil equivalent
Steven B. Sharpe(3) per day
Rodger A. Tourigny(1)(3) mcf - thousand cubic feet
(1) Member of Audit Committee mcf/d - thousand cubic feet per day
(2) Member of Reserve Evaluation mmcf - million cubic feet
Committee mmcf/d - million cubic feet per day
(3) Member of Human Resources, gj - gigajoules
Compensation & Corporate NGLs - natural gas liquids
Governance Committee WTI - West Texas Intermediate
TM - denotes trademark of Canaccord
Officers Capital Corporation
Kelly I. Drader, CEO
Andy J. Mah, President and COO Corporate Offices
Patrick J. Cairns, Senior Vice
President Petro-Canada Centre
Gary F. Bourgeois, Vice President, Suite 3100,
Corporate Development 150 - 6 Avenue SW
Peter A. Hanrahan, Vice President, Calgary, Alberta T2P 3Y7
Finance & CFO (403) 261-8810
David Cronkhite, Vice President,
Operations 800, 2 St. Clair Avenue East
Weldon M. Kary, Vice President, Toronto, Ontario M4T 2T5
Geosciences and Land (416) 945-6636
Neil Bokenfohr, Vice President,
Exploitation Transfer Agent
Corporate Secretary Computershare Trust Company of
Canada
Jay P. Reid, Partner
Burnet, Duckworth and Palmer LLP Contact Us
Operating Company Toll free: 1-866-393-0393
Visit our website at
Advantage Oil & Gas Ltd. www.advantageincome.com
Auditors Toronto Stock Exchange Trading
Symbols
PricewaterhouseCoopers LLP
Trust Units: AVN.UN
Bankers 10% Convertible Debentures: AVN.DB
9% Convertible Debentures: AVN.DBA
The Bank of Nova Scotia 8.25% Convertible Debentures:
National Bank of Canada AVN.DBB
Bank of Montreal 7.5% Convertible Debentures: AVN.DBC
Royal Bank of Canada 7.75% Convertible Debentures:
Canadian Imperial Bank of Commerce AVN.DBD
Union Bank of California, 6.50% Convertible Debentures:
Canada Branch AVN.DBE
Société Générale, Canada Branch 8.75% Convertible Debentures:
Alberta Treasury Branches AVN.DBF
8% Convertible Debentures: AVN.DBG
Independent Reserve Evaluators
New York Stock Exchange Trading
Sproule Associates Limited Symbol
Trust Units: AAV%SEDAR: 00016522E %CIK: 0001259995
For further information:
For further information: Toll free: 1-866-393-0393; Visit our website at www.advantageincome.com