(TSX: AAV, NYSE: AAV) CALGARY, Aug. 13 /PRNewswire-FirstCall/ --
Advantage Oil Gas Ltd. ("Advantage" or the "Corporation") is
pleased to announce the unaudited operating and financial results
of Advantage Energy Income Fund (the "Fund") for the second quarter
ended June 30, 2009. On July 9, 2009, the Fund, Advantage and
holders of trust units of the Fund completed a plan of arrangement
(the "Arrangement") which resulted in the reorganization of the
Fund into the Corporation. As a result of the Arrangement, the Fund
was dissolved and ceased to be a reporting issuer, and the
Corporation became a reporting issuer. As at June 30, 2009, the
Fund still existed and was a reporting issuer, and accordingly,
prepared financial statements and accompanying management's
discussion and analysis for the period then ended. All future
financial statements and management's discussion and analysis of
the continuing legal entity will be in the name of Advantage Oil
Gas Ltd. Financial and Operating Highlights Three Three Six Six
months months months months ended ended ended ended June 30, June
30, June 30, June 30, 2009 2008 2009 2008
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Financial ($000, except as otherwise indicated) Revenue before
royalties(1) $ 114,659 $ 208,868 $ 237,609 $ 397,373 per Trust
Unit(2) $ 0.79 $ 1.51 $ 1.65 $ 2.88 per boe $ 40.59 $ 71.69 $ 42.59
$ 67.03 Funds from operations $ 51,590 $ 103,754 $ 107,181 $
198,372 per Trust Unit(3) $ 0.35 $ 0.74 $ 0.73 $ 1.42 per boe $
18.26 $ 35.62 $ 19.21 $ 33.46 Distributions declared $ - $ 50,364 $
17,266 $ 100,385 per Trust Unit(3) $ - $ 0.36 $ 0.12 $ 0.72
Expenditures on property and equipment $ 15,719 $ 21,632 $ 68,362 $
88,535 Working capital deficit(4) $ 131,913 $ 42,201 $ 131,913 $
42,201 Bank indebtedness $ 644,100 $ 547,946 $ 644,100 $ 547,946
Convertible debentures (face value) $ 184,489 $ 224,587 $ 184,489 $
224,587 Trust Units outstanding at end of period (000) 145,198
140,271 145,198 140,271 Basic weighted average Trust Units (000)
144,681 138,612 144,189 138,105 Operating Daily Production Natural
gas (mcf/d) 124,990 123,104 121,498 124,109 Crude oil and NGLs
(bbls/d) 10,212 11,498 10,575 11,890 Total boe/d at 6:1 31,044
32,015 30,825 32,575 Average prices (including hedging) Natural gas
($/mcf) $ 5.63 $ 9.18 $ 6.06 $ 8.70 Crude oil and NGLs ($/bbl) $
54.51 $ 101.34 $ 54.53 $ 92.81 (1) includes realized derivative
gains and losses (2) based on basic weighted average Trust Units
outstanding (3) based on Trust Units outstanding at each
distribution record date (4) working capital deficit 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 MESSAGE TO SHAREHOLDERS Hedging Gains, Operating Cost
Reductions and Lower Royalty Rates Mitigates Lower Commodity Prices
- For the three months ended June 30 2009, our hedging program
contributed a gain of $22.2 million to funds from operations which
helped to partially mitigate a significant reduction in commodity
prices. - Funds from operations for the second quarter of 2009 was
$51.6 million as compared to $103.7 million for the same period of
2008. Funds from operations on a per unit basis decreased 53% to
$0.35 per Trust Unit compared to $0.74 per Trust Unit for the three
months ended June 30, 2008. - Operating costs for the three months
ended June 30, 2009 was $12.40 per boe which is a decrease of 9%
when compared to the same period in 2008 and a decrease of 5% from
the first quarter of 2009. An aggressive optimization program
initiated in 2008 continues to demonstrate positive benefits and we
will seek opportunities to further improve our operating cost
structure. - Royalties during the second quarter of 2009 decreased
6.2% to a royalty rate of 13.8% as compared to the same period of
2008. The decrease is driven by significantly lower commodity
prices. - Average daily production for the three months ended June
30, 2009 increased 1% to 31,044 boe/d compared to the first quarter
of 2009. The increase was due to production recoveries from cold
weather impacts during the first quarter and production from new
wells tied- in during the latter part of the second quarter.
Production decreased 3% when compared to the same period of 2008
due primarily to the shut-in of 1,100 boe/d (73% natural gas) since
August 2008 at our Lookout Butte property as a result of a third
party facility outage. - Natural gas production for the three
months ended June 30, 2009 increased 2% to 125.0 mmcf/d, compared
to 123.1 mmcf/d for the same period of 2008 and 6% when compared to
the first quarter of 2009. Crude oil and natural gas liquids
production decreased 11% to 10,212 bbls/d in the second quarter
compared to11,498 bbls/d during the same period in 2008 and 7% when
compared to the first quarter of 2009. - The Fund's capital program
during the second quarter of 2009 amounted to $15.7 million. Total
capital spending in the quarter included $7.8 million at Glacier,
$1.3 million at Martin Creek, and $1.0 million at Nevis. Activity
at Glacier in the second quarter included well tie-ins and
installation of a new compressor. Capital expenditures at Martin
Creek represented the final steps to complete the tie-in of wells
drilled during the first quarter of 2009. At Nevis, activity
focused on undertaking preparatory work for new Wabamun light oil
wells which may be drilled during the remainder of 2009. Montney
Development Program at Glacier - Phase I of the Glacier development
plan was completed during the second quarter of 2009 with the
commissioning of new wells, an expanded natural gas gathering
system, new pipelines and additional compression facilities. Gross
raw production from the new wells averaged 20 to 25 mmcf/d during
the latter part of the second quarter with typical start-up issues
encountered such as the intermittent flow-back of frac sand and
frac fluid from the horizontal multi-frac completions. Production
at Glacier will decline during the second half of 2009 as our Phase
II development program, which involves additional well drilling and
facilities expansions designed to increase production capacity to
approximately 50 mmcf/d, will not be completed until the second
quarter of 2010. . - Regulatory applications for a new 50 mmcf/d
gas plant have been submitted and drilling has resumed in July with
the deployment of up to four drilling rigs on operated and joint
interest lands. - New wells brought on-stream after March 31, 2009
qualified for the Alberta royalty incentive program which results
in a 5% royalty rate for one year or 0.5 bcf of gas production.
Production from the new wells will be administered in a sequence
that will allow each well to qualify for the full royalty credit
available. In addition, new wells drilled and placed on production
after March 31, 2009 to March 31, 2011 will qualify for the 5%
royalty rate and an additional drilling credit of $200 per meter of
drilled depth. - Advantage will continue to employ a drilling
strategy that will balance production and reserves growth to
delineate our extensive 89 section gross Montney land block
(average 90% working interest). Advantage will also continue to
closely monitor, evaluate and assess well completion design and
technology that is being developed by our technical staff and our
peers in the Montney fairway and in other resource plays in both
Canada and the U.S. that may lead to further improvements in cost
efficiencies and results. Strong Hedging Program - Advantage's
hedging program includes 79% of our net natural gas production
hedged for the second half of 2009 at an average price of $8.17 per
mcf and 58% hedged for 2010 at an average price of $7.46 per mcf.
Crude oil hedges include 54% of our net crude oil production hedged
at an average floor price of $62.40 Cdn per bbl and 31% hedged for
2010 at an average price of $67.83 Cdn per bbl. Details on our
hedging program are available on our website. - Our strategy will
be to continue to employ a multi-year hedging program to reduce the
volatility in cash flow in support of capital requirements.
Completion of Corporate Conversion, Asset Dispositions, Equity
Financing and A Revised Credit Facility - In July 2009, we
completed our conversion to a growth oriented corporation and
significantly improved our financial flexibility by closing our
asset disposition program and an equity financing which generated
gross proceeds of $354.6 million. - Approximately 8,100 boe/d of
natural gas weighted assets ((greater than)74% natural gas) was
sold resulting in a go forward production base that is forecasted
to average approximately 23,000 boe/d during the second half of
2009. - On August 13, 2009, Advantage's lenders completed their
review of the borrowing base subsequent to the previously announced
closing of the asset dispositions. Gross proceeds of $252.6 million
were received from the asset dispositions and Advantage's credit
facility was revised from $710 million to $525 million. Advantage's
current debt is approximately $300 million resulting in an
unutilized capacity of approximately $225 million on our credit
facility. As a result, Advantage has significantly improved its
financial flexibility in support of future capital program
requirements and general corporate purposes. - Advantage's tax pool
position is estimated to be $1.5 billion net of dispositions and
provides a strong position to shield future cash flows from
corporate tax. Looking Forward - On July 8, 2009, Advantage
announced an updated corporate capital budget for the 12 month
period ending June 2010. The capital budget has been set at $207
million and will focus on our Montney natural gas resource play at
Glacier, Alberta where we will continue to employ a phased
development approach. Phase II of the development plan at Glacier
will be undertaken during the next 12 month period. - Corporate
estimates for the 12 month period ending June 2010 is included
below: Updated Guidance/Estimates H2 H1 Total 2009 2010 12 Months
------ ------ ---------- Production (boe/d) 22,700-23,300
24,200-25,200 23,450-24,300 Royalty Rate (%) 15% to 18% 16% to 19%
15% to 19% Operating Costs ($/boe) $12.75 to $13.30 $12.50 to
$13.20 $12.60 to $13.25 Capital Expenditures ($million) $105 to
$110 $100 to $105 $205 to $215 A full year 2010 capital budget and
guidance will be provided at or about year-end 2009. - Production
is forecasted to increase in the first half of 2010 as new wells
will be brought on-stream after additional gathering systems and
new facilities are completed at Glacier. As a result, production
declines will occur at Glacier during the second half of 2009 due
to the timing of new production additions. We anticipate that
additional production impacts may also occur during the second half
of 2009 due to increased natural gas production curtailments from
joint interest and operated properties due to the low price of
natural gas. The magnitude of potential natural gas production
curtailments is difficult to forecast at this time. - Approximately
79% of the total capital expenditures for the 12 month period will
be allocated to Phase II of the Glacier development plan. - Funds
from operations for the above 12 month period based on the mid-
range of guidance is estimated at $204 million using an average
NYMEX natural gas price of $5.19 US/mmbtu (AECO $4.97 Cdn/mcf), WTI
oil price of $73.87 US/bbl and an $0.86 Cdn/$US exchange rate.
Advantage's current hedging positions have been included in the
funds from operations estimate. - The volatility in funds from
operations for the 12 month period has been significantly reduced
due to our strong hedging position. Advantage is well positioned to
pursue future development plans at Glacier with our strong balance
sheet, strong hedging position and conversion to a growth oriented
corporation. With attractive Glacier well economics at under AECO
$5 Cdn per mcf, management believes a disciplined approach will
create long term growth in shareholder value. MANAGEMENT'S
DISCUSSION ANALYSIS The following Management's Discussion and
Analysis ("MD A"), dated as of August 13, 2009, provides a detailed
explanation of the financial and operating results of Advantage
Energy Income Fund ("Advantage", the "Fund", "us", "we" or "our")
for the three and six months ended June 30, 2009 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, 2008. 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. Forward-Looking Information
This MD A contains certain forward-looking statements, which are
based on our current internal expectations, estimates, projections,
assumptions and beliefs. These statements relate to future events
or our future performance. All statements other than statements of
historical fact may be forward-looking statements. Forward-looking
statements are often, but not always, identified by the use of
words such as "seek", "anticipate", "plan", "continue", "estimate",
"expect", "may", "will", "project", "predict", "potential",
"targeting", "intend", "could", "might", "should", "believe",
"would" and similar or related expressions. These statements are
not guarantees of future performance. In particular,
forward-looking statements included in this MD A include, but are
not limited to, statements with respect to average production and
projected exit rates; areas of operations; spending and capital
budgets; availability of funds for our capital program; the size
of, and future net revenues from, reserves; the focus of capital
expenditures; expectations regarding the ability to raise capital
and to continually add to reserves through acquisitions and
development; projections of market prices and costs; the
performance characteristics of our properties; our future operating
and financial results; capital expenditure programs; supply and
demand for oil and natural gas; average royalty rates; and amount
of general and administrative expenses. In addition, statements
relating to "reserves" or "resources" are deemed to be
forward-looking statements, as they involve the implied assessment,
based on certain estimates and assumptions, that the resources and
reserves described can be profitably produced in the future. These
forward-looking statements involve substantial known and unknown
risks and uncertainties, many of which are beyond our control,
including the effect of acquisitions; changes in general economic,
market and business conditions; changes or fluctuations in
production levels; unexpected drilling results, changes in
commodity prices, currency exchange rates, capital expenditures,
reserves or reserves estimates and debt service requirements;
changes to legislation and regulations and how they are interpreted
and enforced, changes to investment eligibility or investment
criteria; our ability to comply with current and future
environmental or other laws; our success at acquisition,
exploitation and development of reserves; actions by governmental
or regulatory authorities including increasing taxes, changes in
investment or other regulations; the occurrence of unexpected
events involved in the exploration for, and the operation and
development of, oil and gas properties; competition from other
producers; the lack of availability of qualified personnel or
management; changes in tax laws, royalty regimes and incentive
programs relating to the oil and gas industry and income trusts;
hazards such as fire, explosion, blowouts, cratering, and spills,
each of which could result in substantial damage to wells,
production facilities, other property and the environment or in
personal injury; stock market volatility; and ability to access
sufficient capital from internal and external sources. Many of
these risks and uncertainties are described in Advantage's Annual
Information Form which is available at http://www.sedar.com/ and
http://www.advantageog.com/. Readers are also referred to risk
factors described in other documents Advantage files with Canadian
securities authorities. With respect to forward-looking statements
contained in this MD A, Advantage has made assumptions regarding:
current commodity prices and royalty regimes; availability of
skilled labour; timing and amount of capital expenditures; future
exchange rates; the price of oil and natural gas; the impact of
increasing competition; conditions in general economic and
financial markets; availability of drilling and related equipment;
effects of regulation by governmental agencies; royalty rates and
future operating costs. Management has included the above summary
of assumptions and risks related to forward-looking information
provided in this MD A in order to provide Unitholders with a more
complete perspective on Advantage's future operations and such
information may not be appropriate for other purposes. Advantage's
actual results, performance or achievement could differ materially
from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of
the events anticipated by the forward-looking statements will
transpire or occur, or if any of them do so, what benefits that
Advantage will derive there from. Readers are cautioned that the
foregoing lists of factors are not exhaustive. These
forward-looking statements are made as of the date of this MD A and
Advantage disclaims any intent or obligation to update publicly any
forward-looking statements, whether as a result of new information,
future events or results or otherwise, other than as required by
applicable securities laws. Corporate Conversion and Asset
Dispositions On March 18, 2009, we announced that our Board of
Directors had approved conversion to a growth oriented corporation
and a strategic asset disposition program to increase financial
flexibility. On July 9, 2009, Unitholders of the Fund voted 91.64%
in favour of the corporate conversion at the annual general and
special meeting of the Fund, with subsequent approval by the
courts. The conversion will enable Advantage to pursue a business
plan that is focused on the development and growth of the Montney
natural gas resource play at Glacier, Alberta. The Fund retained
Tristone Capital Inc. to assist with the disposition of light oil
and natural gas producing properties located in Northeast British
Columbia, West Central Alberta and Northern Alberta. Proposals were
received and evaluated by Advantage with two purchase and sale
agreements signed for gross proceeds of $252.6 million, subject to
customary adjustments, and representing production of approximately
8,100 boe/d. Both of these sales successfully closed in July 2009
with the net proceeds used to reduce outstanding bank debt.
Advantage may utilize its credit facilities in the future to redeem
certain of the Fund's convertible debentures as they mature and to
help finance its future capital program. Given these business
developments, historical operating and financial performance will
not be indicative of future performance. 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 during each applicable period.
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 Six months ended June 30 June 30
2009 2008 % change 2009 2008 % change
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Cash provided by operating activities $ 38,956 $ 93,882 (59)% $
80,835 $175,475 (54)% Expenditures on asset retirement 1,045 982 6
% 3,622 5,947 (39)% Changes in non-cash working capital 11,589
8,890 30 % 22,724 16,950 34 %
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Funds from operations $ 51,590 $103,754 (50)% $107,181 $198,372
(46)%
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Overview Three months ended Six months ended June 30 June 30 2009
2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Cash provided by operating activities ($000) $ 38,956 $ 93,882
(59)% $ 80,835 $175,475 (54)% Funds from operations ($000) $ 51,590
$103,754 (50)% $107,181 $198,372 (46)% per Trust Unit(1) $ 0.35 $
0.74 (53)% $ 0.73 $ 1.42 (49)% (1) Based on Trust Units outstanding
during each applicable period. Cash provided by operating
activities, funds from operations and funds from operations per
Trust Unit have decreased significantly for the three and six
months ended June 30, 2009 as compared to the same periods of 2008
due to considerably lower revenue. Lower revenue has been primarily
caused by severely depressed commodity prices, partially offset by
substantial gains realized on strong derivative contracts. The
current global recession has resulted in drastic reductions in
commodity prices from lower demand and perceived excess supply.
This challenging environment has continued into the third quarter
of 2009 and we expect to see weak commodity prices for the
near-term. 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 Six months ended June 30 June 30
2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Distributions declared ($000) $ - $ 50,364 (100)% $ 17,266 $100,385
(83)% per Trust Unit(1) $ - $ 0.36 (100)% $ 0.12 $ 0.72 (83)% (1)
Based on Trust Units outstanding during each applicable period.
There were no distributions declared and paid for the three months
ended June 30, 2009. We paid a distribution of $0.08 per Trust Unit
for January 2009 and reduced the monthly distribution to $0.04 per
Trust Unit for the February 2009 distribution paid in March 2009.
On March 18, 2009, we announced the discontinuance of future
distributions, consistent with our strategy to reduce debt,
increase financial flexibility, and convert to a growth oriented
corporation that will focus capital on our Montney natural gas
resource play at Glacier, Alberta. We converted to a corporation
pursuant to a plan of arrangement completed on July 9, 2009. Going
forward, Advantage does not anticipate paying dividends in the
immediate future. Revenue Three months ended Six months ended June
30 June 30 ($000) 2009 2008 % change 2009 2008 % change
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Natural gas excluding hedging $ 40,482 $115,687 (65)% $ 97,342
$205,681 (53)% Realized hedging gains (losses) 23,516 (12,861)
(283)% 35,902 (9,151) (492)%
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Natural gas including hedging $ 63,998 $102,826 (38)% $133,244
$196,530 (32)%
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Crude oil and NGLs excluding hedging $ 51,939 $115,266 (55)% $
94,683 $211,370 (55)% Realized hedging gains (losses) (1,278)
(9,224) (86)% 9,682 (10,527) (192)%
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Crude oil and NGLs including hedging $ 50,661 $106,042 (52)%
$104,365 $200,843 (48)%
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Total revenue $114,659 $208,868 (45)% $237,609 $397,373 (40)%
-------------------------------------------------------------------------
Natural gas, crude oil and NGLs revenues, excluding hedging,
decreased significantly for the three and six months ended June 30,
2009, as compared to 2008. This is primarily the result of lower
commodity prices from the ongoing global recession that has reduced
demand and increased perceived supply. For the three month period
ended June 30, 2009, realized natural gas prices, excluding
hedging, decreased a substantial 66% while realized crude oil and
NGL prices, excluding hedging, decreased 49%. For the six month
period ended June 30, 2009, realized natural gas prices, excluding
hedging, decreased 51% while realized crude oil and NGL prices,
excluding hedging, decreased 49%. As a result of our commodity
price risk management program, we recognized natural gas and crude
oil hedging net gains of $22.2 million and $45.6 million for the
three and six months ended June 30, 2009, respectively. The Fund
enters derivative contracts whereby realized hedging gains and
losses partially offset commodity price fluctuations, which can
positively or negatively impact revenues. Production Three months
ended Six months ended June 30 June 30 2009 2008 % change 2009 2008
% change
-------------------------------------------------------------------------
Natural gas (mcf/d) 124,990 123,104 2 % 121,498 124,109 (2)% Crude
oil (bbls/d) 7,989 9,311 (14)% 8,331 9,581 (13)% NGLs (bbls/d)
2,223 2,187 2 % 2,244 2,309 (3)%
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Total (boe/d) 31,044 32,015 (3)% 30,825 32,575 (5)%
-------------------------------------------------------------------------
Natural gas (%) 67% 64% 66% 63% Crude oil (%) 26% 29% 27% 29% NGLs
(%) 7% 7% 7% 8% Average daily production for the second quarter of
2009 was 1% higher as compared to the first quarter of 2009, mainly
due to recovery from cold weather conditions that caused production
outages and new production from a number of wells drilled during
the first quarter of 2009. Additional new well production in
Alberta was delayed into the second quarter of 2009 such that
benefits from the new royalty incentive program which includes a 5%
royalty rate would be realized. The Fund's total daily production
averaged 31,044 boe/d for the three months and 30,825 boe/d for the
six months ended June 30, 2009, a decrease of 3% and 5%,
respectively compared to the same periods in 2008. Production of
1,100 boe/d at our Lookout Butte property in Southern Alberta
remained shut-in since August 2008 due to an extended third party
outage at the Waterton gas plant where a significant modification
project is underway. The modification project is nearing completion
and we will continue to monitor the development and consider the
appropriate timing for bringing this production on-stream given the
current commodity price environment. On March 18, 2009, we
announced the intention to dispose of light oil and natural gas
producing properties located in Northeast British Columbia, West
Central Alberta and Northern Alberta. Proposals were received and
evaluated by Advantage with two purchase and sale agreements signed
for gross proceeds of $252.6 million, subject to customary
adjustments, and representing production of approximately 8,100
boe/d. Both of these sales closed successfully in July 2009 with
the net proceeds used to reduce outstanding bank debt. Commodity
Prices and Marketing Natural Gas Three months ended Six months
ended June 30 June 30 ($/mcf) 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Realized natural gas prices Excluding hedging $ 3.56 $ 10.33 (66)%
$ 4.43 $ 9.11 (51)% Including hedging $ 5.63 $ 9.18 (39)% $ 6.06 $
8.70 (30)% AECO monthly index $ 3.66 $ 9.35 (61)% $ 4.64 $ 8.24
(44)% Realized natural gas prices, excluding hedging, were
significantly lower for the three and six months ended June 30,
2009 than the same periods of 2008 and decreased 34% from the first
quarter of 2009. The 2007/2008 winter season in North America
caused inventory levels to decline to approximately the five-year
average resulting in stronger prices during early 2008. However,
the second half of 2008 and the first half of 2009 experienced
significant softening of natural gas prices from higher US domestic
natural gas production, mild weather conditions and forecasts, and
the ongoing global recession that has impacted demand. These
factors have resulted in much higher inventory levels that continue
to place considerable downward pressure on natural gas prices.
Unfortunately, these conditions have also continued beyond the
second quarter of 2009 with AECO gas presently trading at
approximately $2.90/GJ. Although we continue to believe in the
longer-term pricing fundamentals for natural gas, we are concerned
about the current pricing and economic environment that has the
potential to extend for a considerable period of time. The global
recession could delay the recovery of natural gas pricing longer
than anticipated. While the current pricing situation is quite
weak, some of the factors that we believe will support stronger
future natural gas prices include: (i) significantly less natural
gas drilling in Canada and the US projected for 2009, which will
reduce productivity to offset declines, (ii) the increasing focus
on resource style natural gas wells, which have high initial
declines, and which are becoming a larger proportion of the total
natural gas supply based in Canada and the US, (iii) the potential
demand for natural gas for the Canadian oil sands projects, and
(iv) fuel switching to natural gas. Crude Oil and NGLs Three months
ended Six months ended June 30 June 30 ($/bbl) 2009 2008 % change
2009 2008 % change
-------------------------------------------------------------------------
Realized crude oil prices Excluding hedging $ 61.13 $ 113.71 (46)%
$ 52.74 $ 100.57 (48)% Including hedging $ 59.37 $ 102.83 (42)% $
59.17 $ 94.53 (37)% Realized NGLs prices Excluding hedging $ 37.06
$ 95.02 (61)% $ 37.30 $ 85.67 (56)% Realized crude oil and NGL
prices Excluding hedging $ 55.89 $ 110.15 (49)% $ 49.47 $ 97.68
(49)% Including hedging $ 54.51 $ 101.34 (46)% $ 54.53 $ 92.81
(41)% WTI ($US/bbl) $ 59.62 $ 124.00 (52)% $ 51.46 $ 110.98 (54)%
$US/$Canadian exchange rate $ 0.86 $ 0.99 (13)% $ 0.83 $ 0.99 (16)%
Realized crude oil and NGLs prices, excluding hedging, decreased
notably for the three and six month ended June 30, 2009, as
compared to the same periods of 2008 but increased 29% from the
first quarter of 2009. Advantage's realized crude oil price may not
change to the same extent as WTI, due to changes in the
$US/$Canadian exchange rate, and changes in Canadian crude oil
differentials relative to WTI. The price of WTI fluctuates based on
worldwide supply and demand fundamentals. There has been
significant price volatility experienced over the last several
years whereby WTI reached historic high levels in the first half of
2008, followed by a record decline in the latter half of the year
and into 2009, the result of demand destruction brought on by the
current global recession. There has been a respectable improvement
during the second quarter of 2009, and WTI is currently trading at
approximately US$70/bbl. We continue to believe that the long-term
pricing fundamentals for crude oil remain strong with many factors
affecting the continued strength including (i) supply management
and supply restrictions by the OPEC cartel, (ii) frequent civil
unrest in various crude oil producing countries and regions, (iii)
strong relative demand in developing countries, particularly in
China and India, and (iv) production declines and reduced drilling.
Commodity Price Risk The Fund's operational results and financial
condition will be dependent on the prices received for oil and
natural gas production. Oil and natural gas prices have fluctuated
widely during recent years and are determined by economic and, in
the case of oil prices, political factors. Supply and demand
factors, including weather and general economic conditions as well
as conditions in other oil and natural gas regions, impact prices.
Any movement in oil and natural gas prices could have an effect on
the Fund's financial condition and performance. As current and
future practice, Advantage has established a financial hedging
strategy and may manage the risk associated with changes in
commodity prices by entering into derivatives. Although these
commodity price risk management activities could expose Advantage
to losses or gains, entering derivative contracts helps us to
stabilize cash flows and ensures that our capital expenditure
program is substantially funded by such cash flows. To the extent
that Advantage engages in risk management activities related to
commodity prices, it will be subject to credit risk associated with
counterparties with which it contracts. Credit risk is mitigated by
entering into contracts with only stable, creditworthy parties and
through frequent reviews of exposures to individual entities. We
have been active in entering new financial contracts to protect
future cash flows and currently the Fund has fixed commodity prices
on anticipated production as follows: Approximate Production
Hedged, Net of Average Average Commodity Royalties(1) Floor Price
Ceiling Price
-------------------------------------------------------------------------
Natural gas - AECO July to September 2009 76% Cdn$8.17/mcf
Cdn$8.17/mcf October to December 2009 81% Cdn$8.17/mcf Cdn$8.17/mcf
-----------------------------------------------------------------------
July to December 2009 79% Cdn$8.17/mcf Cdn$8.17/mcf
-----------------------------------------------------------------------
January to March 2010 81% Cdn$7.64/mcf Cdn$7.64/mcf April to June
2010 59% Cdn$7.53/mcf Cdn$7.53/mcf July to September 2010 45%
Cdn$7.27/mcf Cdn$7.27/mcf October to December 2010 46% Cdn$7.27/mcf
Cdn$7.27/mcf
-----------------------------------------------------------------------
Total 2010 58% Cdn$7.46/mcf Cdn$7.46/mcf
-----------------------------------------------------------------------
January to March 2011 8% Cdn$7.25/mcf Cdn$7.25/mcf
-----------------------------------------------------------------------
Crude Oil - WTI July to September 2009 54% Cdn$62.40/bbl
Cdn$69.40/bbl October to December 2009 53% Cdn$62.40/bbl
Cdn$69.40/bbl
-----------------------------------------------------------------------
July to December 2009 54% Cdn$62.40/bbl Cdn$69.40/bbl
-----------------------------------------------------------------------
January to March 2010 28% Cdn$62.80/bbl Cdn$62.80/bbl April to June
2010 30% Cdn$69.50/bbl Cdn$69.50/bbl July to September 2010 32%
Cdn$69.50/bbl Cdn$69.50/bbl October to December 2010 34%
Cdn$69.50/bbl Cdn$69.50/bbl
-----------------------------------------------------------------------
Total 2010 31% Cdn$67.83/bbl Cdn$67.83/bbl
-----------------------------------------------------------------------
January to March 2011 12% Cdn$69.50/bbl Cdn$69.50/bbl
-----------------------------------------------------------------------
(1) Approximate production hedged is based on our assumed average
production by quarter, net of royalty payments, and takes into
consideration our asset dispositions that closed in July 2009. For
the six month period ended June 30, 2009, we recognized in income a
net realized derivative gain of $45.6 million (June 30, 2008 -
$19.7 million net realized derivative loss) on settled derivative
contracts. As at June 30, 2009, the fair value of the derivatives
outstanding and to be settled was a net asset of approximately
$40.8 million (December 31, 2008 - $41.0 million net asset). For
the six months ended June 30, 2009, $0.2 million was recognized in
income as an unrealized derivative loss (June 30, 2008 - $123.9
million unrealized derivative loss) due to changes in the fair
values of these contracts since December 31, 2008. The valuation of
the derivatives is the estimated fair value to settle the contracts
as at June 30, 2009 and is based on pricing models, estimates,
assumptions and market data available at that time. As such, the
recognized amounts are not cash and the actual gains or losses
realized on eventual cash settlement can vary materially due to
subsequent fluctuations in commodity prices as compared to the
valuation assumptions. The Fund does not apply hedge accounting and
current accounting standards require changes in the fair value to
be included in the consolidated statement of loss and comprehensive
loss as an unrealized derivative gain or loss with a corresponding
derivative asset and liability recorded on the balance sheet. These
derivative contracts will settle from July 2009 to January 2011
corresponding to when Advantage will receive revenues from
production. Royalties Three months ended Six months ended June 30
June 30 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Royalties ($000) $ 12,791 $ 46,173 (72)% $ 28,871 $ 80,054 (64)%
per boe $ 4.53 $ 15.85 (71)% $ 5.17 $ 13.50 (62)% As a percentage
of revenue, excluding hedging 13.8% 20.0% (6.2)% 15.0% 19.2% (4.2)%
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
have decreased in total for the three and six months ended June 30,
2009 compared to the same periods of 2008 due to the decrease in
revenue from significantly lower commodity prices. Royalties as a
percentage of revenue, excluding hedging, have decreased as
compared to 2008. Effective January 1, 2009, the Alberta Provincial
Government implemented a new royalty framework for conventional
oil, natural gas and oil sands and Alberta royalties are now
affected by depths and productivity of wells and commodity prices.
Given our production profile and the current commodity price
environment, our royalty rate has decreased as compared to prior
periods. We expect the royalty rate to be in the range of 13% to
16% for 2009 given the current commodity price environment.
Operating Costs Three months ended Six months ended June 30 June 30
2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Operating costs ($000) $ 35,030 $ 39,917 (12)% $ 71,061 $ 80,189
(11)% per boe $ 12.40 $ 13.70 (9)% $ 12.74 $ 13.53 (6)% Total
operating costs decreased 12% and 11% for the three and six months
ended June 30, 2009 as compared to the 2008 respective periods,
which resulted in a reduction in operating costs per boe by 9% and
6%. When compared to the first quarter of 2009, total operating
costs decreased 3% and operating costs per boe decreased by 5%. An
aggressive optimization program through 2008 and into 2009 is
continuing to demonstrate positive benefits and we will seek
further opportunities to improve our operating cost structure.
General and Administrative Three months ended Six months ended June
30 June 30 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
General and administrative expense ($000) $ 7,848 $ 5,763 36 % $
15,228 $ 12,995 17 % per boe $ 2.78 $ 1.98 40 % $ 2.73 $ 2.19 25 %
Employees at June 30 158 174 (9)% General and administrative ("G
A") expense for the three and six months ended June 30, 2009 has
increased compared to the same periods of 2008 due to costs of
approximately $1.8 million incurred for the conversion of the Fund
to a corporation that was completed in July 2009. We expect to see
additional residual costs related to the corporate conversion in
the third quarter of 2009. As well, total G A for 2009 includes the
recognition of $1.7 million of unit-based compensation expense
related to Restricted Trust Units ("RTUs") granted to employees by
the Board of Directors in January 2009. A total of 171,093 Trust
Units were issued to employees for the first one-third of the grant
that vested. The remaining two-thirds of the RTUs granted will vest
over the subsequent two yearly anniversary dates with corresponding
compensation expense recognized over the service period. Management
Internalization Three months ended Six months ended June 30 June 30
2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Management internalization ($000) $ 760 $ 2,439 (69)% $ 1,724 $
4,930 (65)% per boe $ 0.27 $ 0.84 (68)% $ 0.31 $ 0.83 (63)% In
2006, the Fund and Advantage Investment Management Ltd. (the
"Manager") reached an agreement to internalize the pre-existing
management contract arrangement. As part of the agreement,
Advantage agreed to purchase all of the outstanding shares of the
Manager pursuant to the terms of the arrangement, thereby
eliminating the management fee and performance incentive effective
April 1, 2006. The Trust Unit consideration issued in exchange for
the outstanding shares of the Manager was placed in escrow for a
3-year period and was deferred and amortized into income as
management internalization expense over the specific vesting
periods during which employee services were provided. Management
internalization is lower for the three and six months ended June
30, 2009 compared to the same periods of 2008 as the Trust Units
held in escrow continue to vest during the service period. As of
June 23, 2009, the final Trust Units held in escrow vested and
there will be no subsequent management internalization expense
recognized. Interest on Bank Indebtedness Three months ended Six
months ended June 30 June 30 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Interest expense ($000) $ 3,439 $ 7,118 (52)% $ 8,355 $ 14,884
(44)% per boe $ 1.22 $ 2.44 (50)% $ 1.50 $ 2.51 (40)% Average
effective interest rate 2.2% 5.1% (2.9)% 2.8% 5.4% (2.6)% Bank
indebtedness at June 30 ($000) $644,100 $547,946 18 % Total
interest expense decreased 52% and 44% for the three and six months
ended June 30, 2009 as compared to 2008, respectively. The interest
expense decrease is the result of lower interest rates as bank
lending rates have declined significantly in response to rate
reductions enacted by central banks to stimulate the economy. We
monitor the debt level to ensure an optimal mix of financing and
cost of capital that will provide a maximum return to our
Unitholders. Our current credit facilities have been a favorable
financing alternative with an effective interest rate of only 2.2%
for the three months ended June 30, 2009. The Fund's interest rates
are primarily based on short term Bankers Acceptance rates plus a
stamping fee. In June 2009 our credit facility was renewed and is
subject to higher basis point and stamping fee adjustments ranging
from 1.5% to 5.5%, depending on the Fund's debt to cash flow ratio.
Therefore, we expect that our average effective interest rate will
increase from current levels during the following quarters;
however, this will be somewhat offset by lower interest expense on
the reduced debt level that has resulted from the July 2009 asset
dispositions and equity financing. Interest and Accretion on
Convertible Debentures Three months ended Six months ended June 30
June 30 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Interest on convertible debentures ($000) $ 4,009 $ 4,204 (5)% $
7,978 $ 8,391 (5)% per boe $ 1.42 $ 1.44 (1)% $ 1.43 $ 1.42 1 %
Accretion on convertible debentures ($000) $ 681 $ 720 (5)% $ 1,363
$ 1,440 (5)% per boe $ 0.24 $ 0.25 (4)% $ 0.24 $ 0.24 - %
Convertible debentures maturity value at June 30 ($000) $184,489
$224,587 (18)% Interest and accretion on convertible debentures for
the three and six months ended June 30, 2009 has decreased compared
to 2008 due to the maturity of the 9.00% debentures on August 1,
2008 and the 8.25% debentures on February 1, 2009. On June 30,
2009, our 8.75% debentures matured and will result in lower
interest and accretion in subsequent periods. Depletion,
Depreciation and Accretion Three months ended Six months ended June
30 June 30 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Depletion, depreciation and accretion ($000) $ 72,177 $ 74,704 (3)%
$142,099 $151,584 (6)% per boe $ 25.55 $ 25.64 - % $ 25.47 $ 25.57
- % Depletion and depreciation of fixed assets is provided on the
"unit-of-production" method based on total proved reserves.
Accretion represents the increase in the asset retirement
obligation liability each reporting period due to the passage of
time. The depletion, depreciation and accretion ("DD A") provision
has decreased modestly for the three and six months ended June 30,
2009 compared to 2008 due to the slightly lower production. On a
per boe basis, DD A has remained constant. Taxes Current taxes paid
or payable for the six months ended June 30, 2009 amounted to $0.6
million, compared to $1.6 million expensed for the same period of
2008. Current taxes primarily represent Saskatchewan resource
surcharge, which is based on the petroleum and natural gas revenues
within the province of Saskatchewan. The reduction from 2008 is
primarily due to the corresponding decrease in commodity prices
during 2009. Under the Fund's current structure, payments are made
between the operating company and the Fund transferring income tax
obligations to Unitholders and as a result no cash income taxes
would be paid by the operating company or the Fund prior to 2011.
However, the Specified Investment Flow-Through Entity ("SIFT") tax
legislation was enacted on June 22, 2007 altering the tax treatment
by subjecting income trusts to a two-tier tax structure, similar to
that of corporations, whereby the taxable portion of distributions
paid by trusts will be subject to tax at the trust level and at the
Unitholder level. The rules are effective for tax years beginning
in 2011 for existing publicly-traded trusts. 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. On March 12, 2009, the Government of Canada
enacted legislation reducing the provincial component of the SIFT
tax from 13% to 10%, resulting in a future income tax reduction of
approximately $8.9 million during the first quarter of 2009. Under
Canadian GAAP, the future income tax impact of the planned
corporate conversion, which was completed on July 9, 2009, is to be
recorded in the fiscal period that the conversion occurs. For the
six months ended June 30, 2009, the Fund recognized a total future
income tax reduction of $20.9 million compared to $44.0 million for
the same period of 2008. As at June 30, 2009, the Fund had a future
income tax liability balance of $35.0 million, compared to $55.9
million at December 31, 2008. Net Loss Three months ended Six
months ended June 30 June 30 2009 2008 % change 2009 2008 % change
-------------------------------------------------------------------------
Net loss ($000) $(37,810) $(14,369) 163 % $(18,920) $(38,491) (51)%
per Trust Unit - Basic and Diluted $ (0.26) $ (0.10) 160 % $ (0.13)
$ (0.28) (54)% Net loss for the three months ended June 30, 2009
was $37.8 million, as compared to a net loss of $14.4 million for
the same period of 2008. For the six months ended June 30, 2009, we
experienced a net loss of $18.9 million, as opposed to the $38.5
million net loss for the first six months of 2008. The first half
of 2009 has presented major challenges relating to the commodity
price environment that has adversely impacted revenues, partially
offset from a corresponding reduction in royalties and lower
Alberta royalty rates. The lower revenues have resulted in a larger
net loss for the three months ended June 30, 2009 as compared to
the same period of 2008. Regardless of these industry challenges,
we were able to deliver significant results that contributed to
reduce our net loss for the first six months of 2009. Advantage
implemented a very successful commodity price risk management
program that resulted in $45.6 million of realized derivative
gains. Through our ongoing optimization efforts, we were also able
to reduce operating costs and plan to continue these positive
efforts in 2009. We also recognized significant benefits from
reduced interest rates on bank indebtedness, and a future income
tax reduction from a lower provincial component of the SIFT tax.
Cash Netbacks Three months ended June 30 2009 2008 $000 per boe
$000 per boe
-------------------------------------------------------------------------
Revenue $ 92,421 $ 32.72 $ 230,953 $ 79.27 Realized gain (loss) on
derivatives 22,238 7.87 (22,085) (7.58) Royalties (12,791) (4.53)
(46,173) (15.85) Operating costs (35,030) (12.40) (39,917) (13.70)
-------------------------------------------------------------------------
Operating $ 66,838 $ 23.66 $ 122,778 $ 42.14 General and
administrative(1) (7,456) (2.64) (6,831) (2.34) Interest (3,439)
(1.22) (7,118) (2.44) Interest on convertible debentures(1) (4,009)
(1.42) (4,204) (1.44) Income and capital taxes (344) (0.12) (871)
(0.30)
-------------------------------------------------------------------------
Funds from operations $ 51,590 $ 18.26 $ 103,754 $ 35.62
-------------------------------------------------------------------------
Six months ended June 30 2009 2008 $000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 192,025 $ 34.42 $ 417,051 $ 70.35 Realized gain (loss) on
derivatives 45,584 8.17 (19,678) (3.32) Royalties (28,871) (5.17)
(80,054) (13.50) Operating costs (71,061) (12.74) (80,189) (13.53)
-------------------------------------------------------------------------
Operating $ 137,677 $ 24.68 $ 237,130 $ 40.00 General and
administrative(1) (13,539) (2.43) (13,924) (2.35) Interest (8,355)
(1.50) (14,884) (2.51) Interest on convertible debentures(1)
(7,978) (1.43) (8,391) (1.42) Income and capital taxes (624) (0.11)
(1,559) (0.26)
-------------------------------------------------------------------------
Funds from operations $ 107,181 $ 19.21 $ 198,372 $ 33.46
-------------------------------------------------------------------------
(1) General and administrative expense excludes non-cash unit-based
compensation expense. Interest on convertible debentures excludes
non-cash accretion expense. Funds from operations and cash netbacks
decreased in total and per boe for the three and six months ended
June 30, 2009 compared to the same periods of 2008. As compared to
the first quarter of 2009, cash netbacks decreased 10% from $20.19
per boe for that period. The lower cash netback in total and per
boe is primarily due to much weaker commodity prices, particularly
natural gas, which adversely impacted revenue. However, as a result
of our successful commodity price risk management program, we were
able to recognize significant gains on derivatives. Royalties also
decreased during the periods as would be expected since they are
significantly influenced by commodity prices. Operating costs,
which had increased steadily over the 2008 year, have started to
decrease as we begin to realize benefits from our ongoing
optimization efforts. We have also realized modest benefits from
lower interest expense. Contractual Obligations and Commitments The
Fund has contractual obligations in the normal course of operations
including purchases of assets and services, operating agreements,
transportation commitments, sales contracts and convertible
debentures. These obligations are of a recurring and consistent
nature and impact cash flow in an ongoing manner. The following
table is a summary of the Fund's remaining contractual obligations
and commitments. Advantage has no guarantees or off-balance sheet
arrangements other than as disclosed. Payments due by period ($
millions) Total 2009 2010 2011 2012
-------------------------------------------------------------------------
Building leases $ 8.4 $ 1.9 $ 3.9 $ 1.5 $ 1.1 Capital leases 5.3
1.2 2.2 1.9 - Pipeline/transportation 3.9 1.4 2.0 0.5 - Convertible
debentures(1) 184.4 52.2 69.9 62.3 -
-------------------------------------------------------------------------
Total contractual obligations $ 202.0 $ 56.7 $ 78.0 $ 66.2 $ 1.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) As at June 30, 2009, Advantage had $184.4 million convertible
debentures outstanding (excluding interest payable during the
various debenture terms). Each series of convertible debentures are
convertible to Trust Units based on an established conversion
price. All remaining obligations related to convertible debentures
can be settled through the payment of cash or issuance of Trust
Units at Advantage's option. (2) Bank indebtedness of $644.1
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 one year term facility
with repayment due one year 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) June 30, 2009
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 644,100 Working capital deficit(1)
131,913
-------------------------------------------------------------------------
Net debt $ 776,013
-------------------------------------------------------------------------
Trust Units outstanding (000) 145,198 Trust Units closing market
price ($/Trust Unit) $ 4.90
-------------------------------------------------------------------------
Market value $ 711,470
-------------------------------------------------------------------------
Convertible debentures maturity value (long-term) $ 62,294 Capital
lease obligation (long term) $ 2,970
-------------------------------------------------------------------------
Total capitalization $ 1,552,747
-------------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities,
and the current portion of capital lease obligations and
convertible debentures. Advantage monitors its capital structure
and makes adjustments according to market conditions in an effort
to meet its objectives given the current outlook of the business
and industry in general. The capital structure of the Fund is
composed of working capital (excluding derivative assets and
liabilities), bank indebtedness, convertible debentures, capital
lease obligations and Unitholders' equity. Advantage may manage its
capital structure by issuing new Trust Units, obtaining additional
financing either through bank indebtedness or convertible debenture
issuances, refinancing current debt, issuing other financial or
equity-based instruments, adjusting or discontinuing the amount of
monthly distributions, suspending or renewing its distribution
reinvestment plan, adjusting capital spending, or disposing of
assets. The capital structure is reviewed by Management and the
Board of Directors on an ongoing basis. Management of the Fund's
capital structure is facilitated through its financial and
operational forecasting processes. The forecast of the Fund's
future cash flows is based on estimates of production, commodity
prices, forecast capital and operating expenditures, and other
investing and financing activities. The forecast is regularly
updated based on new commodity prices and other changes, which the
Fund views as critical in the current environment. Selected
forecast information is frequently provided to the Board of
Directors. This continual financial assessment process further
enables the Fund to mitigate risks. The Fund continues to satisfy
all liabilities and commitments as they come due. We had an
established $710 million credit facility agreement with a syndicate
of financial institutions; the balance of which utilized at June
30, 2009 was $644.1 million. This facility was renewed in June 2009
and was comprised of a $20 million revolving operating loan
facility, a $630 million extendible revolving credit facility and a
$60 million liquidity facility. Subsequent to our asset
dispositions that closed in July 2009, we have renegotiated and
finalized our new credit facility for the corporation, that will be
$525 million, consisting of a $20 million revolving operating loan
facility and a $505 million extendible revolving credit facility.
The Fund additionally has convertible debentures that will mature
in 2009, whereby we have the option to settle such obligations by
cash or though the issuance of Trust Units. The current economic
situation has placed additional pressure on commodity prices. Crude
oil has dropped from a historic high in 2008 to approximately
US$70/bbl. The impact from the decrease in WTI will be somewhat
mitigated for Advantage due to the strengthening US dollar relative
to the Canadian dollar. Natural gas prices that had been improving
early in 2008, have now declined due to the ailing economy as well
as increased inventory levels from strong injections and mild
weather. Natural gas has dropped with AECO gas presently trading at
approximately $2.90/GJ. The outlook for the Fund from prolonged
weak commodity prices would be reductions in operating netbacks and
funds from operations. Management has partially mitigated this risk
through our commodity hedging program but the lower commodity price
environment has still had a significant negative impact. In order
to strengthen our financial position and balance our cash flows,
the monthly distribution was discontinued to repay debt and focus
capital spending on our Montney natural gas resource play. In
summary, we have implemented a strategy to balance funds from
operations and capital program expenditure requirements. A
successful hedging program was also executed to help reduce the
volatility of our funds from operations. As a result, we feel that
Advantage has implemented adequate strategies to protect our
business as much as possible in this environment. However, as with
all companies, we are still exposed to risks as a result of the
current economic situation and the potential duration. We continue
to closely monitor the possible impact on our business and
strategy, and will make adjustments as necessary with prudent
management. Unitholders' Equity and Convertible Debentures
Advantage has utilized a combination of Trust Units, convertible
debentures and bank debt to finance acquisitions and development
activities. As at June 30, 2009, the Fund had 145.2 million Trust
Units outstanding. During the six months ended June 30, 2009,
1,263,158 Trust Units were issued as a result of the Premium
Distribution(TM), Distribution Reinvestment and Optional Trust Unit
Purchase Plan (the "Plan"), generating $5.2 million reinvested in
the Fund (June 30, 2008 - 1,854,776 Trust Units were issued under
the Plan, generating $19.5 million reinvested in the Fund). As at
August 13, 2009, Trust Units outstanding increased to 162.2 million
due to 17 million Trust Units issued on July 7, 2009, through a
bought deal financing that raised gross proceeds of $102 million.
The proceeds were utilized to reduce bank indebtedness. At June 30,
2009, the Fund had $184.4 million convertible debentures
outstanding that were immediately convertible to 8.4 million Trust
Units based on the applicable conversion prices (December 31, 2008
- $219.2 million outstanding and convertible to 9.5 million Trust
Units). During the six months ended June 30, 2009, there were no
conversions of debentures (June 30, 2008 - $25,000 converted
resulting in the issuance of 1,001 Trust Units). The principal
amount of 8.25% convertible debentures matured on February 1, 2009
and was settled by issuing 946,887 Trust Units while the 8.75%
convertible debentures that matured on June 30, 2009 was settled
with $29.8 million in cash. As at August 13, 2009, the convertible
debentures outstanding have not changed from June 30, 2009. We have
$52.2 million of 7.50% debentures that mature on October 1, 2009.
These obligations can be settled through the payment of cash or
issuance of Trust Units at Advantage's option. Bank Indebtedness,
Credit Facility and Other Obligations At June 30, 2009, Advantage
had bank indebtedness outstanding of $644.1 million. Bank
indebtedness increased $56.7 million since December 31, 2008 as a
significant portion of our 2009 capital expenditure program was
incurred during the first half of 2009 and $29.8 million principal
amount of debentures matured and was settled with cash on June 30,
2009. The Fund renewed its credit facility in June 2009 which was a
$710 million credit facility as at June 30, 2009. However, given
our asset dispositions that closed in July 2009, we have
renegotiated and finalized a new credit facility of $525 million,
comprised of a $20 million revolving operating loan facility and a
$505 million extendible revolving credit facility. The net proceeds
from the asset dispositions were used to reduce our outstanding
bank debt to improve Advantage's financial flexibility. 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. As
well, the borrowing base for the Fund's credit facilities is
determined through utilizing our regular reserve estimates. The
banking syndicate thoroughly evaluates the reserve estimates based
upon their own commodity price expectations to determine the amount
of the borrowing base. Revision or changes in the reserve estimates
and commodity prices can have either a positive or a negative
impact on the borrowing base of the Fund. The next annual review is
scheduled to occur in June 2010. There can be no assurances that
the $525 million credit facility will be renewed at the current
borrowing base level at that time. As at August 13, 2009, our bank
indebtedness was approximately $300 million with unutilized room of
$225 million. Advantage had a working capital deficiency of $131.9
million as at June 30, 2009. Our working capital includes items
expected for normal operations such as trade receivables, prepaids,
deposits, trade payables and accruals as well as the current
portion of capital lease obligations. Working capital varies
primarily due to the timing of such items, the current level of
business activity including our capital program, commodity price
volatility, and seasonal fluctuations. We do not anticipate any
problems in meeting future obligations as they become due given our
funds from operations. It is also important to note that working
capital is effectively integrated with Advantage's operating credit
facility, which assists with the timing of cash flows as required.
The increase in our working capital deficiency is due to the
additional inclusion in current liabilities of $121.2 million of
convertible debentures that mature during the next twelve months.
We have $52.2 million of 7.50% debentures that mature on October 1,
2009 and $69.9 million of 6.50% debentures that mature on June 30,
2010. Advantage has capital lease obligations on various pieces of
equipment used in its operations. The total amount of principal
obligation outstanding at June 30, 2009 is $5.0 million, bearing
interest at effective rates ranging from 5.5% to 6.7%, and is
collateralized by the related equipment. The leases expire at dates
ranging from December 2009 to August 2010. Capital Expenditures
Three months ended Six months ended June 30 June 30 ($000) 2009
2008 2009 2008
-------------------------------------------------------------------------
Land and seismic $ 40 $ 11 $ 1,707 $ 4,181 Drilling, completions
and workovers 4,526 9,425 42,138 46,169 Well equipping and
facilities 11,082 11,978 24,379 37,576 Other 71 218 138 609
-------------------------------------------------------------------------
$ 15,719 $ 21,632 $ 68,362 $ 88,535 Property dispositions (860) -
(1,619) (91)
-------------------------------------------------------------------------
Total capital expenditures $ 14,859 $ 21,632 $ 66,743 $ 88,444
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Advantage's exploitation and development program focuses on areas
where past activity has yielded long-life reserves with high cash
netbacks. We are very well positioned to selectively exploit the
highest value-generating drilling opportunities given the size,
strength and diversity of our asset base as evidenced by our
success at Glacier, Nevis and several other key properties. As a
result, the Fund has a high level of flexibility to allocate 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. Advantage's acquisition strategy has
been to acquire long-life properties with strong drilling
opportunities while retaining a balance of year round access and
risk. For the six month period ended June 30, 2009, the Fund spent
a net $68.4 million and drilled a total of 9.6 net (11 gross) wells
at a 100% success rate. Total capital spending included $48.4
million at Glacier, $6.3 million at Martin Creek, and the remaining
balance at other miscellaneous areas. Glacier capital spending
included 3 net (3 gross) horizontal wells and 2 net (2 gross)
vertical wells. Two new Montney horizontal wells were brought
on-stream at combined rates of 8 to 10 mmcf/d at the end of January
2009. Facilities work involving the expansion of compression
facilities and our pipeline gathering system was completed at the
end of the quarter and has taken our overall facility capacity to
25 mmcf/d after commissioning the expansion in the second quarter
of 2009. With the facilities work completed, our Montney wells
drilled in the fourth quarter of 2008 and the first quarter of 2009
were brought on-stream during the latter portion of the second
quarter of 2009 at total well rates of between 20 and 25 mmcf/d.
The new wells brought on-stream will qualify for the Alberta
royalty incentive program which results in a 5% royalty rate for
one year or 0.5 bcf of gas production. Activity is now underway at
Glacier to increase production capacity to 50 mmcf/d by mid 2010.
At Nevis, activity focused on increasing battery capacity and
preparatory work for new Wabamun light oil wells which may be
drilled during the remainder of 2009. On July 8, 2009, the Board of
Directors approved a new capital budget for the twelve month period
beginning July 2009 and ending June 2010. Management will review
the capital program on a regular basis in the context of prevailing
economic conditions and make adjustments as deemed necessary to the
program, subject to review by the Board of Directors. Advantage's
corporate capital budget for the 12 month period ending June 2010
has been set at $207 million, with $105 to $110 million for the
remainder of 2009. The budget will focus on development of our
Montney natural gas resource play at Glacier, Alberta where
Advantage will continue to employ a phased development approach.
Phase I of the development plan was achieved during the second
quarter of 2009 where production capacity was increased to
approximately 25 mmcf/d and included wells, compression facilities
and additional pipelines. Phase II of the development plan will be
undertaken during the next 12 months and will result in production
capacity increasing to approximately 50 mmcf/d by mid 2010. Phase
III of the development plan will result in the attainment of 100
mmcf/d by mid 2011. Approximately 79% of the total capital
expenditures for the 12 month period will be allocated to Glacier.
Sources and Uses of Funds The following table summarizes the
various funding requirements during the six months ended June 30,
2009 and 2008 and the sources of funding to meet those
requirements: Six months ended June 30 ($000) 2009 2008
-------------------------------------------------------------------------
Sources of funds Funds from operations $ 107,181 $ 198,372 Increase
in bank indebtedness 58,393 520 Property dispositions 1,619 91
Units issued, net of costs - 925
-------------------------------------------------------------------------
$ 167,193 $ 199,908
-------------------------------------------------------------------------
Uses of funds Expenditures on property and equipment $ 68,362 $
88,535 Increase in working capital 41,123 23,882 Convertible
debenture repayment 29,839 - Distributions to Unitholders 23,481
80,632 Expenditures on asset retirement 3,622 5,947 Reduction of
capital lease obligations 645 912 Trust Unit issue costs 121 -
-------------------------------------------------------------------------
$ 167,193 $ 199,908
-------------------------------------------------------------------------
The Fund generated lower funds from operations during the six
months ended June 30, 2009 compared to the same period of 2008, due
to a sharp decrease in commodity prices. Consequently, our bank
indebtedness increased as a result to assist with the timing of
cash flow requirements. The major use of funds during this period
was expenditures on property and equipment, which was reduced from
the 2008 levels, given the lower commodity price environment.
Distributions were suspended indefinitely in the first quarter of
2009 in order to maintain our budgeted capital program including
significant investment at our Glacier Montney natural gas property
and to repay bank indebtedness. Additionally, our 8.75% convertible
debentures matured on June 30, 2009 and were settled with $29.8
million of cash. Quarterly Performance 2009 2008 ($000, except as
otherwise indicated) Q2 Q1 Q4 Q3
-------------------------------------------------------------------------
Daily production Natural gas (mcf/d) 124,990 117,968 120,694
122,627 Crude oil and NGLs (bbls/d) 10,212 10,942 11,413 11,980
Total (boe/d) 31,044 30,603 31,529 32,418 Average prices Natural
gas ($/mcf) Excluding hedging $ 3.56 $ 5.36 $ 7.15 $ 8.65 Including
hedging $ 5.63 $ 6.52 $ 7.61 $ 7.55 AECO monthly index $ 3.66 $
5.64 $ 6.79 $ 9.27 Crude oil and NGLs ($/bbl) Excluding hedging $
55.89 $ 43.41 $ 53.65 $ 107.96 Including hedging $ 54.51 $ 54.54 $
61.67 $ 100.02 WTI ($US/bbl) $ 59.62 $ 43.21 $ 58.75 $ 118.13 Total
revenues (before royalties) $ 114,659 $ 122,950 $ 149,205 $ 195,384
Net income (loss) $ (37,810) $ 18,890 $ (95,477) $ 113,391 per
Trust Unit - basic $ (0.26) $ 0.13 $ (0.67) $ 0.81 - diluted $
(0.26) $ 0.13 $ (0.67) $ 0.79 Funds from operations $ 51,590 $
55,591 $ 69,370 $ 93,345 Distributions declared $ - $ 17,266 $
45,514 $ 50,743 2008 2007 ($000, except as otherwise indicated) Q2
Q1 Q4 Q3
-------------------------------------------------------------------------
Daily production Natural gas (mcf/d) 123,104 125,113 128,556
115,991 Crude oil and NGLs (bbls/d) 11,498 12,281 12,895 10,014
Total (boe/d) 32,015 33,133 34,321 29,346 Average prices Natural
gas ($/mcf) Excluding hedging $ 10.33 $ 7.90 $ 6.23 $ 5.62
Including hedging $ 9.18 $ 8.23 $ 6.97 $ 6.35 AECO monthly index $
9.35 $ 7.13 $ 6.00 $ 5.62 Crude oil and NGLs ($/bbl) Excluding
hedging $ 110.15 $ 85.99 $ 73.40 $ 69.03 Including hedging $ 101.34
$ 84.83 $ 70.40 $ 68.51 WTI ($US/bbl) $ 124.00 $ 97.96 $ 90.63 $
75.33 Total revenues (before royalties) $ 208,868 $ 188,505 $
165,951 $ 130,830 Net income (loss) $ (14,369) $ (24,122) $ 13,795
$ (26,202) per Trust Unit - basic $ (0.10) $ (0.18) $ 0.10 $ (0.22)
- diluted $ (0.10) $ (0.18) $ 0.10 $ (0.22) Funds from operations $
103,754 $ 94,618 $ 80,519 $ 62,345 Distributions declared $ 50,364
$ 50,021 $ 57,875 $ 55,017 The table above highlights the Fund's
performance for the second quarter of 2009 and also for the
preceding seven quarters. The Sound acquisition closed on September
5, 2007, and significantly increased production for the third and
fourth quarters of 2007. Production has gradually decreased through
the first half of 2008 due to natural declines, wet and cold
weather delays, and facility turnarounds. Production increased
modestly in the third quarter of 2008 as new wells were brought on
production and most facility turnarounds were completed. During the
fourth quarter of 2008 and the first quarter of 2009, production
again decreased as we experienced freezing conditions from early
cold weather in December and a slow recovery from such cold weather
conditions. An extended third party facility outage began in August
2008 and has continued well into 2009 and it is expected that
production may come on-stream near the end of the third quarter
2009. Production increased in the second quarter of 2009 due to
recovery from cold weather conditions that caused brief production
outages and additional production from a number of wells drilled
during the first quarter of 2009 but delayed until after March 31
such that we could benefit from the new 5% Alberta royalty rate
available on such wells for the next twelve month period. Financial
results, particularly revenues and funds from operations, increased
through to the second quarter of 2008, as both commodity prices and
production steadily increased over that timeframe. However,
revenues and funds from operations slightly declined in the third
quarter of 2008, as commodity prices began to decline in response
to the financial crisis that materialized in the fall of 2008. This
trend worsened in the fourth quarter, as a full global recession
set in, and commodity prices continued on a downward trend through
to the second quarter of 2009. We experienced a net loss in the
third quarter of 2007 due to a significant drop in natural gas
prices realized at that time, amortization of the management
internalization consideration and increased depletion and
depreciation expense. Net income increased in the fourth quarter of
2007 due to the full integration of the Sound acquisition and
moderately improved commodity prices. Net losses were realized in
the first and second quarters of 2008, primarily as a result of
significant unrealized losses on commodity derivative contracts for
future periods. Commodity price declines in the third quarter of
2008 gave rise to significant unrealized gains on these same
derivative contracts, and in turn the Fund reported record high net
income. We recognized a considerable net loss in the fourth quarter
of 2008, a combined result of falling commodity prices and an
impairment of our entire balance of goodwill. In the first quarter
of 2009, the global economy showed no clear sign of recovery and
commodity prices, particularly natural gas, were weak in comparison
to prior quarters. However, Advantage was still able to recognize
net income as we recognized both realized and unrealized gains on
our derivative contracts and moderately lower expenses, including
operating costs. Natural gas prices continued to worsen during the
second quarter of 2009 resulting in the recognition of a net loss.
Critical Accounting Estimates The preparation of financial
statements in accordance with GAAP requires Management to make
certain judgments and estimates. Changes in these judgments and
estimates could have a material impact on the Fund's financial
results and financial condition. Management relies on the estimate
of reserves as prepared by the Fund's independent qualified
reserves evaluator. The process of estimating reserves is critical
to several accounting estimates. The process of estimating reserves
is complex and requires significant judgments and decisions based
on available geological, geophysical, engineering and economic
data. These estimates may change substantially as additional data
from ongoing development and production activities becomes
available and as economic conditions impact crude oil and natural
gas prices, operating costs, royalty burden changes, and future
development costs. Reserve estimates impact net income through
depletion and depreciation of fixed assets, the provision for asset
retirement costs and related accretion expense, and impairment
calculations for fixed assets and goodwill. The reserve estimates
are also used to assess the borrowing base for the Fund's credit
facilities. Revision or changes in the reserve estimates can have
either a positive or a negative impact on net income and the
borrowing base of the Fund. Management's process of determining the
provision for future income taxes, the provision for asset
retirement obligation costs and related accretion expense, and the
fair values assigned to any acquired company's assets and
liabilities in a business combination is based on estimates. These
estimates are significant and can include reserves, future
production rates, future crude oil and natural gas prices, future
costs, future interest rates, future tax rates and other relevant
assumptions. Revisions or changes in any of these estimates can
have either a positive or a negative impact on asset and liability
values and net income. In accordance with GAAP, derivative assets
and liabilities are recorded at their fair values at the reporting
date, with unrealized gains and losses recognized directly into net
income and comprehensive income in the same period. The fair value
of derivatives outstanding is an estimate based on pricing models,
estimates, assumptions and market data available at that time. As
such, the recognized amounts are not cash and the actual gains or
losses realized on eventual cash settlement can vary materially due
to subsequent fluctuations in commodity prices as compared to the
valuation assumptions. International Financial Reporting Standards
("IFRS") In February 2008, the Accounting Standards Board of the
Canadian Institute of Chartered Accountants confirmed that publicly
accountable entities will be required to adopt IFRS effective
January 1, 2011, including preparation of comparative financial
information. Management has engaged its key personnel responsible
for financial reporting and developed an overall plan to address
IFRS implementation. The initial stage of the plan involved staff
training and ongoing education. Key personnel received professional
education on IFRS accounting principles and standards, both in
general and for the oil and gas industry in particular. Review of
changes to IFRS has been incorporated into existing processes of
internal control over financial reporting. A preliminary project
plan for IFRS implementation has been drafted and will be subject
to ongoing revision as there are developments. As well, appropriate
operating personnel have been engaged, as necessary, to determine
how to implement the requirements of IFRS into the Fund's manual
and information systems that collect and process financial data. We
expect to have continual discussion with our external and internal
auditors throughout the process regarding IFRS and implementation.
The most significant change identified will be accounting for
property, plant and equipment. The Fund, like many Canadian oil and
gas reporting issuers, applies the "full cost" concept in
accounting for its oil and gas assets. Under full cost, capital
expenditures are maintained in a single cost centre for each
country, and the cost centre is subject to a single depletion
calculation and impairment test. IFRS will require the Fund to make
a much more detailed assessment of its oil and gas property, plant
and equipment. For depletion and depreciation, the Fund must
identify asset components, and determine an appropriate
depreciation or depletion method for each component. With regard to
impairment test calculations, we must identify "Cash Generating
Units", which are defined as the smallest group of assets that
produce independent cash flows. An impairment test must be
performed individually for all cash generating units. The
recognition of impairments in a prior year can be reversed
subsequently depending on such calculations. It is also important
to note that the International Accounting Standards Board ("IASB")
is currently undertaking an extractive industries project, to
develop accounting standards specifically for businesses like that
of the Fund. However, the project will not be complete prior to
IFRS adoption in Canada. We have also identified a number of other
areas whereby differences between Canadian GAAP and IFRS are likely
to exist for Advantage. However, currently we are concentrating on
the accounting for property, plant and equipment and will evaluate
these other areas in due course and develop more detailed plans to
address the identified issues. Disclosure Controls and Internal
Controls over Financial Reporting Disclosure controls and
procedures have been designed to provide reasonable assurance that
information required to be disclosed by the Fund is recorded,
processed, summarized and reported within the time periods
specified under the Canadian securities law. Advantage's Chief
Executive Officer and Chief Financial Officer have concluded, based
on their evaluation, that the disclosure controls and procedures as
of the end of June 30, 2009, are effective and provide reasonable
assurance that material information related to the Fund is made
known to them by others within Advantage. Advantage's Chief
Executive Officer and Chief Financial Officer are responsible for
establishing and maintaining internal controls over financial
reporting ("ICFR"). They have, as at the quarter ended June 30,
2009, designed ICFR or caused it to be designed under their
supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with Canadian GAAP.
The control framework Advantage's officers used to design the ICFR
is the Internal Control - Integrated Framework issued by the
Committee of Sponsoring Organizations. Advantage's Chief Executive
Officer and Chief Financial Officer are required to disclose any
change in the internal controls over financial reporting that
occurred during our most recent interim period that has materially
affected, or is reasonably likely to affect, the Fund's internal
controls over financial reporting. No material changes in the
internal controls were identified during the period ended June 30,
2009 that have materially affected, or are reasonably likely to
materially affect, our internal controls over financial reporting.
It should be noted that a control system, including Advantage's
disclosure and internal controls and procedures, no matter how well
conceived or operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system will be met and
it should be not be expected that the disclosure and internal
controls and procedures will prevent all errors or fraud. Outlook
On March 18, 2009, we announced the intention to dispose of light
oil and natural gas producing properties located in Northeast
British Columbia, West Central Alberta and Northern Alberta.
Proposals were received and evaluated by Advantage with two
purchase and sale agreements signed for gross proceeds of $252.6
million, subject to customary adjustments, and representing
production of approximately 8,100 boe/d. Both of these sales closed
successfully in July 2009 with the net proceeds used to reduce
outstanding bank debt. We expect production to average
approximately 23,000 boe/d for the period July to December 2009
from a more focused asset base. Additionally, we also announced
that we entered into an agreement with a syndicate of underwriters
for the purchase of 17 million trust units by the underwriters on a
bought deal basis, at a price of $6.00 per Trust Unit for total
gross proceeds of $102 million, which closed on July 7, 2009. The
net proceeds of this offering were also used to repay indebtedness
under Advantage's credit facility. These transactions have enabled
Advantage to repay a significant portion of outstanding bank
indebtedness while increasing the balance of unutilized credit
facility. This improves our financial flexibility as we convert to
a growth oriented corporation to pursue the significant potential
of our Montney natural gas resource play. Our credit facility may
be subsequently redrawn to fund capital expenditures and for
general corporate purposes but it is our long-term intention to
balance funds from operations and our capital expenditure program.
Although our funds from operations will continue to be impacted by
the volatility of crude oil and natural gas prices, we have a
substantial hedging portfolio that improves cash flow stability for
our capital program. Approximately 79% of our natural gas
production, net of royalties, is now hedged for the remainder of
2009 at an average fixed price of $8.17/mcf. We have also hedged
approximately 54% of our remaining 2009 crude oil production, net
of royalties, at an average floor price of $62.40/bbl. For 2010, we
have hedged 58% of our natural gas production, net of royalties, at
an average fixed price of $7.46/mcf and 31% of our crude oil
production, net of royalties, at an average fixed price of
$67.83/bbl. Our strategy will be to continue to employ a multi-year
hedging program to reduce the volatility in cash flow in support of
capital requirements. In conjunction with our corporate conversion,
we announced on July 8, 2009 that the Board of Directors had
approved a new capital budget for the twelve month period beginning
July 2009 and ending June 2010. Management will review the capital
program on a regular basis in the context of prevailing economic
conditions and make adjustments as deemed necessary to the program,
subject to review by the Board of Directors. Advantage's corporate
capital budget for the 12 month period ending June 2010 has been
set at $207 million, with approximately $105 to $110 million for
the remainder of 2009. Guidance for the 12 month period is as
follows: July to December January to June Total 2009 2010 12 Months
---- ---- --------- Production (boe/d) 22,700 to 23,300 24,200 to
25,200 23,450 to 24,300 Royalty rate (%) 15% to 18% 16% to 19% 15%
to 19% Operating costs ($/boe) $12.75 to $13.30 $12.50 to $13.20
$12.60 to $13.25 Capital expenditures ($ millions) $105 to $110
$100 to $105 $205 to $215 Funds from operations ($ millions)
$204(1) (1) Based on NYMEX US$5.19/mmbtu, AECO $4.97/mcf, WTI
US$73.87/bbl, $US/$Canadian exchange rate $0.86 and current hedging
positions. Funds from operations are forecasted to be approximately
within the range of capital expenditures required for the next 12
month period. The volatility in funds from operations is
significantly reduced due to our hedging positions through to the
end of 2010. Production is forecasted to increase during the first
half of 2010 as new wells are brought on stream after additional
gathering systems and new facilities are constructed at Glacier
during the fourth quarter of 2009. Production declines will occur
at Glacier during the second half of 2009 and at our remaining
properties. We also expect natural gas production curtailments to
occur during the second half of 2009 as several joint operators
have announced their intention to shut-in production due to the low
price of natural gas. The budget will focus on development of our
Montney natural gas resource play at Glacier, Alberta where
Advantage will continue to employ a phased development approach.
Phase II of the development plan will be undertaken during the next
12 months and will result in production capacity increasing to 50
mmcf/d by mid 2010. A continued focus on optimizing well
completions at Glacier will involve production logging of several
wells in order to further evaluate the effectiveness of frac
designs and new technology applications. Phase II of the Glacier
development plan includes the drilling and completion of 16 gross
(16.0 net) horizontal operated wells, up to 16 gross (6.1 net)
joint interest horizontal wells, and 1 gross (1.0 net) vertical
well during the next twelve months. Drilling plans will continue to
balance production and reserve growth and delineation of our
extensive 89 section gross (average 90% working interest) Montney
land block. Drilling resumed in early July at Glacier with the
deployment of four drilling rigs on operated and joint interest
lands. Phase II also includes the expansion of the existing gas
gathering system, additional compression and a new Advantage
operated gas plant to complement the existing infrastructure and
provide total processing and production capacity of 50 mmcf/d. The
majority of the wells drilled during the last half of 2009 will be
tied-in during the second quarter of 2010 when the facilities
expansions are expected to be completed. Glacier capital
expenditures are estimated to be approximately $84 million net for
the remainder of 2009 and $81 million net for the first half of
2010. Approximately $116 million will be allocated to drilling and
completions with $29 million for well equipping and tie-ins and $20
million for facilities and plant expansion. Phase III of the
development plan will result in the attainment of 100 mmcf/d by mid
2011. The Alberta Government's recently announced extension of the
energy incentive programs to March 31, 2011 will provide
substantial benefits to all three phases of our Glacier development
plan. The energy incentive programs will allow Advantage to
capitalize on lower drilling costs (through a drilling royalty
credit of up to $200 per meter of drilled depth subject to a
corporate ceiling) and an initial 5% royalty rate on the first 500
mmcf of production for new wells based on our go-forward drilling
plans for each of the three phases of development at Glacier. With
regards to field operating costs, we will continue with our
optimization programs which has already delivered cost reductions.
We expect to see some further easing of operating costs as the
lower commodity price environment is expected to remain for a
sustained period. Looking forward, Advantage's high quality assets
combined with a significant unconventional and conventional
inventory, strong hedging program and improved balance sheet
enables us to create value growth for our Unitholders. Additional
Information Additional information relating to Advantage can be
found on SEDAR at http://www.sedar.com/ and the Fund's website at
http://www.advantageog.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. August 13, 2009
CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets June
December (thousands of dollars) 30, 2009 31, 2008
-------------------------------------------------------------------------
(unaudited) Assets Current assets Accounts receivable $ 56,524 $
84,689 Prepaid expenses and deposits 12,879 11,571 Derivative asset
(note 10) 60,156 41,472
-------------------------------------------------------------------------
129,559 137,732 Derivative asset (note 10) 6,008 1,148 Fixed assets
(note 3) 2,103,233 2,163,866
-------------------------------------------------------------------------
$2,238,800 $2,302,746
-------------------------------------------------------------------------
Liabilities Current liabilities Accounts payable and accrued
liabilities $ 78,066 $ 146,046 Distributions payable to Unitholders
- 11,426 Current portion of capital lease obligations (note 4)
2,038 1,747 Current portion of convertible debentures (note 5)
121,212 86,125 Derivative liability (note 10) 17,376 611 Future
income taxes 12,377 11,939
-------------------------------------------------------------------------
231,069 257,894 Derivative liability (note 10) 7,996 1,039 Capital
lease obligations (note 4) 2,970 3,906 Bank indebtedness (note 6)
643,110 584,717 Convertible debentures (note 5) 60,419 128,849
Asset retirement obligations (note 7) 84,953 73,852 Future income
taxes 22,586 43,976
-------------------------------------------------------------------------
1,053,103 1,094,233
-------------------------------------------------------------------------
Unitholders' Equity Unitholders' capital (note 8) 2,088,497
2,075,877 Convertible debentures equity component (note 5) 8,303
9,403 Contributed surplus (note 8) 2,137 287 Accumulated deficit
(note 9) (913,240) (877,054)
-------------------------------------------------------------------------
1,185,697 1,208,513
-------------------------------------------------------------------------
$2,238,800 $2,302,746
-------------------------------------------------------------------------
Commitments (note 12) Subsequent events (note 13) See accompanying
Notes to Consolidated Financial Statements Consolidated Statements
of Loss, Comprehensive Loss and Accumulated Deficit (thousands of
dollars, Three months ended Six months ended except for per Trust
June 30, June 30, June 30, June 30, Unit amounts) (unaudited) 2009
2008 2009 2008
-------------------------------------------------------------------------
Revenue Petroleum and natural gas $ 92,421 $ 230,953 $ 192,025 $
417,051 Realized gain (loss) on derivatives (note 10) 22,238
(22,085) 45,584 (19,678) Unrealized loss on derivatives (note 10)
(24,575) (62,696) (178) (123,882) Royalties (12,791) (46,173)
(28,871) (80,054)
-------------------------------------------------------------------------
77,293 99,999 208,560 193,437
-------------------------------------------------------------------------
Expenses Operating 35,030 39,917 71,061 80,189 General and
administrative 7,848 5,763 15,228 12,995 Management internalization
(note 8) 760 2,439 1,724 4,930 Interest 3,439 7,118 8,355 14,884
Interest and accretion on convertible debentures 4,690 4,924 9,341
9,831 Depletion, depreciation and accretion 72,177 74,704 142,099
151,584
-------------------------------------------------------------------------
123,944 134,865 247,808 274,413
-------------------------------------------------------------------------
Loss before taxes (46,651) (34,866) (39,248) (80,976) Future income
tax reduction (9,185) (21,368) (20,952) (44,044) Income and capital
taxes 344 871 624 1,559
-------------------------------------------------------------------------
(8,841) (20,497) (20,328) (42,485)
-------------------------------------------------------------------------
Net loss and comprehensive loss (37,810) (14,369) (18,920) (38,491)
Accumulated deficit, beginning of period (875,430) (733,978)
(877,054) (659,835) Distributions declared - (50,364) (17,266)
(100,385)
-------------------------------------------------------------------------
Accumulated deficit, end of period $(913,240) $(798,711) $(913,240)
$(798,711)
-------------------------------------------------------------------------
Net loss per Trust Unit (note 8) Basic and diluted $ (0.26) $
(0.10) $ (0.13) $ (0.28)
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows Three months ended Six months
ended (thousands of dollars) June 30, June 30, June 30, June 30,
(unaudited) 2009 2008 2009 2008
-------------------------------------------------------------------------
Operating Activities Net loss $ (37,810) $ (14,369) $ (18,920) $
(38,491) Add (deduct) items not requiring cash: Unrealized loss on
derivatives 24,575 62,696 178 123,882 Unit-based compensation 392
(1,068) 1,689 (929) Management internalization 760 2,439 1,724
4,930 Accretion on convertible debentures 681 720 1,363 1,440
Depletion, depreciation and accretion 72,177 74,704 142,099 151,584
Future income tax reduction (9,185) (21,368) (20,952) (44,044)
Expenditures on asset retirement (1,045) (982) (3,622) (5,947)
Changes in non-cash working capital (11,589) (8,890) (22,724)
(16,950)
-------------------------------------------------------------------------
Cash provided by operating activities 38,956 93,882 80,835 175,475
-------------------------------------------------------------------------
Financing Activities Units issued, net of costs (121) 967 (121) 925
Increase (decrease) in bank indebtedness 31,102 (15,554) 58,393 520
Convertible debenture repayment (note 5) (29,839) - (29,839) -
Reduction of capital lease obligations (325) (306) (645) (912)
Distributions to Unitholders - (40,330) (23,481) (80,632)
-------------------------------------------------------------------------
Cash provided by (used in) financing activities 817 (55,223) 4,307
(80,099)
-------------------------------------------------------------------------
Investing Activities Expenditures on property and equipment
(15,719) (21,632) (68,362) (88,535) Property dispositions 860 -
1,619 91 Changes in non-cash working capital (24,914) (17,027)
(18,399) (6,932)
-------------------------------------------------------------------------
Cash used in investing activities (39,773) (38,659) (85,142)
(95,376)
-------------------------------------------------------------------------
Net change in cash - - - - Cash, beginning of period - - - -
-------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow Information Interest paid 6,793 10,013
15,040 18,579 Taxes paid 235 638 610 792 See accompanying Notes to
Consolidated Financial Statements NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS June 30, 2009 (unaudited) All tabular amounts in
thousands except as otherwise indicated. 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 ("GAAP") using
the same accounting policies as those set out in note 2 to the
consolidated financial statements for the year ended December 31,
2008, except as described below. These interim financial statement
note disclosures do not include all of those required by Canadian
GAAP applicable for annual financial statements. The interim
consolidated financial statements should be read in conjunction
with the audited consolidated financial statements of Advantage for
the year ended December 31, 2008 as set out in Advantage's Annual
Report. 1. Business and Structure of the Fund Advantage was formed
on May 23, 2001 as a result of a plan of arrangement. For Canadian
tax purposes, Advantage is an open-ended unincorporated mutual fund
trust created under the laws of the Province of Alberta pursuant to
a Trust Indenture originally dated April 17, 2001, and as
occasionally amended, between Advantage Oil & Gas Ltd. ("AOG")
and Computershare Trust Company of Canada, as trustee. The Fund
commenced operations on May 24, 2001. The beneficiaries of the Fund
are the holders of the Trust Units (the "Unitholders"). The
principal undertaking of the Fund is to indirectly acquire and hold
interests in petroleum and natural gas properties and assets
related thereto. The business of the Fund is carried on by its
wholly-owned subsidiary, AOG. The Fund's primary assets are
currently the common shares of AOG, a royalty in the producing
properties of AOG (the "AOG Royalty") and notes of AOG (the "AOG
Notes"). The Fund's strategy, through AOG, is to minimize exposure
to exploration risk while focusing on growth through acquisitions
and development of producing crude oil and natural gas properties.
The original purpose of the Fund was to distribute available cash
flow to Unitholders on a monthly basis in accordance with the terms
of the Trust Indenture. The Fund's available cash flow include
principal repayments and interest income earned from the AOG Notes,
royalty income earned from the AOG Royalty, and any dividends
declared on the common shares of AOG less any expenses of the Fund
including interest on convertible debentures. Cash received on the
AOG Notes, AOG Royalty and common shares of AOG result in the
effective transfer of the economic interest in the properties of
AOG to the Fund. However, while the royalty is a contractual
interest in the properties owned by AOG, it does not confer
ownership in the underlying resource properties. Any distributions
from the Fund to Unitholders were entirely discretionary and
determined by Management and the Board of Directors. Management
closely monitored the distribution policy considering forecasted
cash flows, optimal debt levels, capital spending activity,
taxability to Unitholders, working capital requirements, and other
potential cash expenditures. Distributions were based on the cash
available after retaining a portion to meet such spending
requirements. The level of distributions were primarily determined
by cash flows received from the production of oil and natural gas
from existing Canadian resource properties and were dependent upon
our success in exploiting the current reserve base and acquiring
additional reserves. Furthermore, monthly distributions that were
paid to Unitholders were dependent upon the prices received for
such oil and natural gas production. On March 18, 2009, Advantage
announced the Board of Directors had approved conversion to a
growth oriented corporation and suspension of the monthly
distribution. The corporate conversion was approved by the Fund's
Unitholders at the Annual General and Special Meeting on July 9,
2009, and received customary court and regulatory approvals. The
conversion will enable the new corporation, Advantage Oil & Gas
Ltd., to pursue a business plan that is focused on the development
and growth of the Montney natural gas resource play at Glacier,
Alberta. Going forward, Advantage does not anticipate paying
dividends in the immediate future and will instead direct cash flow
to capital expenditures and debt repayment. 2. Changes in
Accounting Policies (a) Goodwill and intangible assets In February
2008, the Canadian Institute of Chartered Accountants ("CICA")
issued Section 3064, Goodwill and Intangible Assets, replacing
Section 3062, Goodwill and Other Intangible Assets and Section
3450, Research and Development Costs. The new Section became
effective January 1, 2009. Management has implemented the new
Section and there was no impact for the financial statements of the
Fund. (b) Recent accounting pronouncements issued but not
implemented (i) International Financial Reporting Standards
("IFRS") In February 2008, the CICA Accounting Standards Board
confirmed that IFRS will replace Canadian GAAP effective January 1,
2011 for publicly accountable enterprises. Management is currently
evaluating the effects of all current and pending pronouncements of
the International Accounting Standards Board on the financial
statements of the Fund, and has developed a plan for
implementation. (c) Comparative figures Certain comparative figures
have been reclassified to conform to the current period
presentation. 3. Fixed Assets Accumulated Depletion and Net Book
June 30, 2009 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas properties $ 3,378,370 $ 1,279,452 $
2,098,918 Furniture and equipment 11,710 7,395 4,315
---------------------------------------------------------------------
$ 3,390,080 $ 1,286,847 $ 2,103,233
---------------------------------------------------------------------
Accumulated Depletion and Net Book December 31, 2008 Cost
Depreciation Value
---------------------------------------------------------------------
Value Petroleum and natural gas properties $ 3,299,657 $ 1,140,710
$ 2,158,947 Furniture and equipment 11,572 6,653 4,919
---------------------------------------------------------------------
$ 3,311,229 $ 1,147,363 $ 2,163,866
---------------------------------------------------------------------
4. Capital Lease Obligations The Fund has capital leases on a
variety of fixed assets. Future minimum lease payments at June 30,
2009 consist of the following: 2009 1,239 2010 2,200 2011 1,925
--------------------------------------------- 5,364 Less amounts
representing interest (356)
--------------------------------------------- 5,008 Current portion
(2,038) --------------------------------------------- $ 2,970
--------------------------------------------- 5. Convertible
Debentures The balance of debentures outstanding at June 30, 2009
and changes in the liability and equity components during the six
months ended June 30, 2009 are as follows: 8.25% 8.75% 7.50%
--------------------------------------------------------- Trading
symbol AAV.DBB AAV.DBF AAV.DBC Debentures outstanding $ - $ - $
52,268 ---------------------------------------------------------
Liability component: Balance at December 31, 2008 $ 4,859 $ 29,687
$ 51,579 Accretion of discount 8 152 457 Matured (4,867) (29,839) -
--------------------------------------------------------- Balance
at June 30, 2009 $ - $ - $ 52,036
--------------------------------------------------------- Equity
component: Balance at December 31, 2008 $ 248 $ 852 $ 2,248 Expired
(248) (852) -
-------------------------------------------------------------
Balance at June 30, 2009 $ - $ - $ 2,248
------------------------------------------------------------- 6.50%
7.75% 8.00% Total
---------------------------------------------------------------------
Trading symbol AAV.DBE AAV.DBD AAV.DBG Debentures outstanding $
69,927 $ 46,766 $ 15,528 $ 184,489
---------------------------------------------------------------------
Liability component: Balance at December 31, 2008 $ 68,807 $ 44,964
$ 15,078 $ 214,974 Accretion of discount 369 303 74 1,363 Matured -
- - (34,706)
---------------------------------------------------------------------
Balance at June 30, 2009 $ 69,176 $ 45,267 $ 15,152 $ 181,631
---------------------------------------------------------------------
Equity component: Balance at December 31, 2008 $ 2,971 $ 2,286 $
798 $ 9,403 Expired - - - (1,100)
---------------------------------------------------------------------
Balance at June 30, 2009 $ 2,971 $ 2,286 $ 798 $ 8,303
---------------------------------------------------------------------
During the six months ended June 30, 2009, there were no
convertible debenture conversions (June 30, 2008 - $25,000
converted resulting in the issuance of 1,001 Trust Units). The
principal amount of 8.25% convertible debentures matured on
February 1, 2009 and was settled by issuing 946,887 Trust Units,
while the 8.75% convertible debentures that matured on June 30,
2009 were settled with $29.8 million in cash. 6. Bank Indebtedness
June December 30, 2009 31, 2008
---------------------------------------------------------------------
Revolving credit facility $ 644,100 $ 587,404 Discount on Bankers
Acceptances (990) (2,687)
---------------------------------------------------------------------
Balance, end of period $ 643,110 $ 584,717
---------------------------------------------------------------------
Advantage has a credit facility agreement with a syndicate of
financial institutions which provides for a $630 million extendible
revolving loan facility, a $20 million operating loan facility, and
a $60 million liquidity facility. The liquidity facility will,
subject to renewal, expire on October 31, 2010. 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 1.50% to 5.50%
depending on the Fund's debt to cash flow ratio. The credit
facilities are collateralized by a $1 billion floating charge
demand debenture, a general security agreement and a subordination
agreement from the Fund covering all assets and cash flows. The
amounts available to Advantage from time to time under the credit
facilities are based upon the borrowing base determined by the
lenders and which is re- determined on a semi-annual basis by those
lenders. The credit facilities are subject to review on an annual
basis with the next renewal due in June 2010. 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 one year term facility with the
principal payable at the end of such one year term. The credit
facilities contain standard commercial covenants for facilities of
this nature. The only financial covenant is a requirement for AOG
to maintain a minimum cash flow to interest expense ratio of 3.5:1,
determined on a rolling four quarter basis. The credit facilities
also prohibit the Fund from entering into any derivative contract
where the term of such contract exceeds two years and the aggregate
of such contracts hedge greater than 60% of total estimated oil and
gas production, except for the initial period ended December 31,
2009 whereby the Fund shall not hedge greater than 80% of total
estimated oil and gas production. Breach of any covenant will
result in an event of default in which case AOG has 20 days to
remedy such default. If the default is not remedied or waived, and
if required by the 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, days of grace, 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 six months ended June
30, 2009, the average effective interest rate on the outstanding
amounts under the facility was approximately 2.8% (June 30, 2008 -
5.4%). As a result of the asset dispositions completed in July
2009, the borrowing base was subsequently re-determinded and
established at $525 million (note 13). 7. Asset Retirement
Obligations A reconciliation of the asset retirement obligations is
provided below: Six months ended Year ended June 30, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 73,852 $ 60,835 Accretion expense
2,615 4,186 Liabilities incurred 379 1,526 Change in estimates
11,729 16,564 Liabilities settled (3,622) (9,259)
---------------------------------------------------------------------
Balance, end of period $ 84,953 $ 73,852
---------------------------------------------------------------------
8. Unitholders' Equity (a) Unitholders' capital (i) Authorized
Unlimited number of voting Trust Units (ii) Issued Number of Units
Amount
---------------------------------------------------------------------
Balance at December 31, 2008 142,824,854 $ 2,077,760 Distribution
reinvestment plan 1,263,158 5,211 Issued on maturity of debentures
946,887 4,867 Issued pursuant to Restricted Trust Unit Plan 171,093
939 Management internalization forfeitures (7,862) (159) Issuance
costs - (121)
---------------------------------------------------------------------
Balance at June 30, 2009 145,198,130 $ 2,088,497
---------------------------------------------------------------------
On June 23, 2006, Advantage internalized the external management
contract structure and eliminated all related fees for total
original consideration of 1,933,208 Advantage Trust Units initially
valued at $39.1 million and subject to escrow provisions over a
3-year period, vesting one-third each year beginning June 23, 2007.
For the six months ended June 30, 2009, a total of 7,862 Trust
Units issued for the management internalization were forfeited
(June 30, 2008 - 4,193 Trust Units) and $1.7 million has been
recognized as management internalization expense (June 30, 2008 -
$4.9 million). As at June 30, 2009, all Trust Units in respect of
management internalization were issued and none remain held in
escrow (December 31, 2008 - 564,612 Trust Units remained in
escrow). During the six months ended June 30, 2009, 1,263,158 Trust
Units (June 30, 2008 - 1,854,776 Trust Units) were issued under the
Premium Distribution(TM), Distribution Reinvestment and Optional
Trust Unit Purchase Plan, generating $5.2 million (June 30, 2008 -
$19.5 million) reinvested in the Fund. The principal amount of
8.25% convertible debentures matured on February 1, 2009 and was
settled by issuing 946,887 Trust Units. (b) Contributed surplus Six
months ended Year ended June 30, December 31, 2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 287 $ 2,005 Unit-based compensation
750 (1,256) Expiration of convertible debentures equity component
1,100 229 Exercise of Trust Unit Rights - (691)
---------------------------------------------------------------------
Balance, end of period $ 2,137 $ 287
---------------------------------------------------------------------
(c) Unit-based compensation Advantage's current employee
compensation includes a Restricted Trust Unit Plan, as approved by
the Unitholders on June 23, 2006. The purpose of the long-term
compensation plan is to retain and attract employees, to reward and
encourage performance, and to focus employees on operating and
financial performance that results in lasting Unitholder return.
Although Advantage experienced a negative return for the 2008 year,
the approved peer group also experienced likewise negative returns.
As a result, Advantage's 2008 annual return was within the top two-
thirds of the approved peer group and the Board of Directors
granted Restricted Trust Units ("RTUs") at their discretion. The
RTUs were deemed to be granted at January 15, 2009 and was valued
at $3.8 million to be issued in Trust Units at $5.49 per Trust
Unit. Unit- based compensation expense of $1.7 million has been
included in general and administration expense for the six month
period ended June 30, 2009 and 171,093 Trust Units were issued to
employees in January 2009 for the first one-third of the grant that
vested. The remaining two-thirds of the RTUs granted will vest over
the subsequent two yearly anniversary dates with corresponding
compensation expense recognized over the service period. Since
implementing the Plan in 2006, the grant thresholds have not been
previously met, and there have been no RTU grants made during prior
years and no related compensation expense has been recognized. (d)
Net loss per Trust Unit The calculations of basic and diluted net
loss per Trust Unit are derived from both loss available to
Unitholders and weighted average Trust Units outstanding,
calculated as follows: Three months ended Six months ended June 30,
June 30, June 30, June 30, 2009 2008 2009 2008
---------------------------------------------------------------------
Loss available to Unitholders Basic and diluted (37,810) (14,369)
(18,920) (38,491)
---------------------------------------------------------------------
Weighted average Trust Units outstanding Basic and diluted
144,681,321 138,611,924 144,189,031 138,105,497
---------------------------------------------------------------------
The calculation of diluted net loss per Trust Unit excludes all
series of convertible debentures for both the three and six months
ended June 30, 2009 and 2008 as the impact on these periods would
be anti-dilutive. Total weighted average Trust Units issuable in
exchange for the convertible debentures and excluded from the
diluted net loss per Trust Unit calculation for the three and six
months ended June 30, 2009 were 9,224,648 and 9,279,871 Trust
Units, respectively. Total weighted average Trust Units issuable in
exchange for the convertible debentures and excluded from the
diluted net loss per Trust Unit calculation for the three and six
months ended June 30, 2008 were 9,846,252 and 9,846,610 Trust
Units, respectively. As at June 30, 2009, the total convertible
debentures outstanding were immediately convertible to 8,373,448
Trust Units (June 30, 2008 - 9,846,252 Trust Units). Escrowed RTUs
granted in January 2009 have been excluded from the calculation of
diluted net loss per Trust Unit for the three and six months ended
June 30, 2009, as the impact would have been anti- dilutive. Total
weighted average Trust Units issuable in exchange for the RTUs and
excluded from the diluted net loss per Trust Unit calculation for
the three and six months ended June 30, 2009 were 89,475 and
52,645, respectively. Management Internalization escrowed Trust
Units have been excluded from the calculation of diluted net loss
per Trust Unit for the three and six months ended June 30, 2009 and
2008, as the impact would have been anti-dilutive. Total weighted
average Trust Units issuable in exchange for the Management
Internalization escrowed Trust Units and excluded from the diluted
net loss per Trust Unit calculation for the three and six months
ended June 30, 2009 were 401,473 and 312,719, respectively. Total
weighted average Trust Units issuable in exchange for the
Management Internalization escrowed Trust Units and excluded from
the diluted net loss per Trust Unit calculation for the three and
six months ended June 30, 2008 were 528,068 and 484,869,
respectively. 9. Accumulated Deficit Accumulated deficit consists
of accumulated income and accumulated distributions for the Fund
since inception as follows: June 30, December 31, 2009 2008
---------------------------------------------------------------------
Accumulated Income $ 180,491 $ 199,411 Accumulated Distributions
(1,093,731) (1,076,465)
---------------------------------------------------------------------
Accumulated Deficit $ (913,240) $ (877,054)
---------------------------------------------------------------------
For the six months ended June 30, 2009, the Fund declared $17.3
million in distributions, representing $0.12 per distributable
Trust Unit (June 30, 2008 - $100.4 million in distributions
representing $0.72 per Trust Unit). 10. 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 June 30, 2009, 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 June 30, 2009, the estimated fair
value of the total outstanding convertible debenture obligation was
$178.0 million (December 31, 2008 - $191.2 million). The fair value
of convertible debentures was determined based on the public
trading activity of such debentures. Advantage has an established
strategy to manage the risk associated with changes in commodity
prices by entering into derivatives, which are recorded at fair
value as derivative assets and liabilities with gains and losses
recognized through earnings. As the fair value of the contracts
varies with commodity prices, they give rise to financial assets
and liabilities. The fair values of the derivatives are determined
through valuation models completed internally and by third parties.
Various assumptions based on current market information were used
in these valuations, including settled forward commodity prices,
interest rates, foreign exchange rates, volatility and other
relevant factors. The actual gains and losses realized on eventual
cash settlement can vary materially due to subsequent fluctuations
in commodity prices as compared to the valuation assumptions.
Credit Risk Accounts receivable, deposits, and derivative assets
are subject to credit risk exposure and the carrying values reflect
Management's assessment of the associated maximum exposure to such
credit risk. Advantage mitigates such credit risk by closely
monitoring significant counterparties and dealing with a broad
selection of partners that diversify risk within the sector. The
Fund's deposits are primarily due from the Alberta Provincial
government and are viewed by Management as having minimal
associated credit risk. To the extent that Advantage enters
derivatives to manage commodity price risk, it may be subject to
credit risk associated with counterparties with which it contracts.
Credit risk is mitigated by entering into contracts with only
stable, creditworthy parties and through frequent reviews of
exposures to individual entities. In addition, the Fund only enters
into derivative contracts with major national banks and
international energy firms to further mitigate associated credit
risk. Substantially all of the Fund's accounts receivable are due
from customers and joint operation partners concentrated in the
Canadian oil and gas industry. As such, accounts receivable are
subject to normal industry credit risks. As at June 30, 2009, $9.9
million or 18% of accounts receivable are outstanding for 90 days
or more (December 31, 2008 - $14.2 million or 17% of accounts
receivable). The Fund believes that the entire balance is
collectible, and in some instances we have the ability to mitigate
risk through withholding production or offsetting payables with the
same parties. Accordingly, management has not provided for an
allowance for doubtful accounts at June 30, 2009. Liquidity Risk
The Fund is subject to liquidity risk attributed from accounts
payable and accrued liabilities, distributions payable to
Unitholders, bank indebtedness, convertible debentures, and
derivative liabilities. Accounts payable and accrued liabilities,
distributions payable to Unitholders and derivative liabilities are
primarily due within one year of the balance sheet date and
Advantage does not anticipate any problems in satisfying the
obligations from cash provided by operating activities and the
existing credit facility. The Fund's bank indebtedness is subject
to a $710 million credit facility agreement. Although the credit
facility is a source of liquidity risk, the facility also mitigates
liquidity risk by enabling Advantage to manage interim cash flow
fluctuations. The credit facility constitutes a revolving facility
for a 364 day term which is extendible annually for a further 364
day revolving period at the option of the syndicate. If not
extended, the revolving credit facility is converted to a one year
term facility with the principal payable at the end of such one
year term. The terms of the credit facility are such that it
provides Advantage adequate flexibility to evaluate and assess
liquidity issues if and when they arise. Additionally, the Fund
regularly monitors liquidity related to obligations by evaluating
forecasted cash flows, optimal debt levels, capital spending
activity, working capital requirements, and other potential cash
expenditures. This continual financial assessment process further
enables the Fund to mitigate liquidity risk. Advantage has several
series of convertible debentures outstanding that mature from 2009
to 2011 (note 5). Interest payments are made semi-annually with
excess cash provided by operating activities. As the debentures
become due, the Fund can satisfy the obligations in cash or issue
Trust Units at a price determined in the applicable debenture
agreements. This settlement alternative allows the Fund to
adequately manage liquidity, plan available cash resources and
implement an optimal capital structure. To the extent that
Advantage enters derivatives to manage commodity price risk, it may
be subject to liquidity risk as derivative liabilities become due.
While the Fund has elected not to follow hedge accounting,
derivative instruments are not entered for speculative purposes and
Management closely monitors existing commodity risk exposures. As
such, liquidity risk is mitigated since any losses actually
realized are subsidized by increased cash flows realized from the
higher commodity price environment. The timing of cash outflows
relating to financial liabilities are as follows: Less than One to
Four to one year three years five years Thereafter
---------------------------------------------------------------------
Accounts payable and accrued liabilities $ 78,066 $ - $ - $ -
Derivative liabilities 17,376 7,996 - - Bank indebtedness -
principal - 644,100 - - - interest 14,091 14,091 - - Convertible
debentures - principal 122,195 62,294 - - - interest 16,256 7,920 -
-
---------------------------------------------------------------------
$ 247,984 $ 736,401 $ - $ -
---------------------------------------------------------------------
The Fund's bank indebtedness does not have specific maturity dates.
It is governed by a credit facility agreement with a syndicate of
financial institutions (note 6). Under the terms of the agreement,
the facility is reviewed annually, with the next review scheduled
in June 2010. The facility is revolving, and is extendible at each
annual review for a further 364 day period at the option of the
syndicate. If not extended, the credit facility is converted at
that time into a one year term facility, with the principal payable
at the end of such one year term. Management fully expects that the
facility will be extended at each annual review. Interest Rate Risk
The Fund is exposed to interest rate risk to the extent that bank
indebtedness is at a floating rate of interest and the Fund's
maximum exposure to interest rate risk is based on the effective
interest rate and the current carrying value of the bank
indebtedness. The Fund monitors the interest rate markets to ensure
that appropriate steps can be taken if interest rate volatility
compromises the Fund's cash flows. A 1% increase in interest rates
for the six months ended June 30, 2009 could have decreased net
income by approximately $2.3 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 loss. It is estimated that a 10%
increase in the forward natural gas prices used to calculate the
fair value of the natural gas derivatives at June 30, 2009 could
increase net loss by approximately $10.6 million for the six months
ended June 30, 2009. As well, an increase of 10% in the forward
crude oil prices used to calculate the fair value of the crude oil
derivatives at June 30, 2009 could increase net loss by $8.8
million for the six months ended June 30, 2009. An increase of 10%
in the forward power prices used to calculate the fair value of the
power derivatives at June 30, 2009 would not materially increase
net loss for the six months ended June 30, 2009. A similar increase
in the currency rate assumption underlying the derivatives fair
value does not materially increase net loss. As at June 30, 2009
the Fund had the following derivatives in place: Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO Fixed price April 2009 to 9,478 mcf/d Cdn
$8.66/mcf December 2009 Fixed price April 2009 to 9,478 mcf/d Cdn
$8.67/mcf December 2009 Fixed price April 2009 to 9,478 mcf/d Cdn
$8.94/mcf December 2009 Fixed price April 2009 to 14,217 mcf/d Cdn
$7.59/mcf March 2010 Fixed price April 2009 to 14,217 mcf/d Cdn
$7.56/mcf March 2010 Fixed price January 2010 to 14,217 mcf/d Cdn
$8.23/mcf June 2010 Fixed price January 2010 to 18,956 mcf/d Cdn
$7.29/mcf December 2010 Fixed price April 2010 to 18,956 mcf/d Cdn
$7.25/mcf January 2011 Crude oil - WTI Collar April 2009 to 2,000
bbl/d Bought put Cdn $62.00/bbl December 2009 Sold call Cdn
$76.00/bbl Fixed price April 2009 to 2,000 bbls/d Cdn $62.80/bbl
March 2010 Fixed price April 2010 to 2,000 bbls/d Cdn $69.50/bbl
January 2011 Electricity - Alberta Pool Price Fixed price March
2009 to 2.0 MW Cdn$75.43/MWh December 2009 As at June 30, 2009, the
fair value of the derivatives outstanding resulted in an asset of
approximately $66.2 million (December 31, 2008 - $42.6 million) and
a liability of approximately $25.4 million (December 31, 2008 -
$1.7 million). For the six months ended June 30, 2009, $0.2 million
was recognized in income as an unrealized derivative loss (June 30,
2008 - $123.9 million unrealized derivative loss) and $45.6 million
was recognized in income as a realized derivative gain (June 30,
2008 - $19.7 million realized derivative loss). 11. Capital
Management The Fund manages its capital with the following
objectives: - To ensure sufficient financial flexibility to achieve
the ongoing business objectives including replacement of
production, funding of future growth opportunities, and pursuit of
accretive acquisitions; and - To maximize Unitholder return through
enhancing the Trust Unit value. Advantage monitors its capital
structure and makes adjustments according to market conditions in
an effort to meet its objectives given the current outlook of the
business and industry in general. The capital structure of the Fund
is composed of working capital (excluding derivative assets and
liabilities), bank indebtedness, convertible debentures, capital
lease obligations and Unitholders' equity. Advantage may manage its
capital structure by issuing new Trust Units, obtaining additional
financing either through bank indebtedness or convertible debenture
issuances, refinancing current debt, issuing other financial or
equity-based instruments, adjusting or discontinuing the amount of
monthly distributions, suspending or renewing its distribution
reinvestment plan, adjusting capital spending, or disposing of
assets. The capital structure is reviewed by Management and the
Board of Directors on an ongoing basis. Advantage's capital
structure as at June 30, 2009 is as follows: June 30, 2009
---------------------------------------------------------------------
Bank indebtedness (long-term) $ 644,100 Working capital deficit(1)
131,913
---------------------------------------------------------------------
Net debt 776,013 Trust Units outstanding market value 711,470
Convertible debentures maturity value (long-term) 62,294 Capital
lease obligations (long-term) 2,970
---------------------------------------------------------------------
Total capitalization $ 1,552,747
---------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities,
and the current portion of capital lease obligations and
convertible debentures. The Fund's bank indebtedness is governed by
a $710 million credit facility agreement (note 6) that contains
standard commercial covenants for facilities of this nature. The
only financial covenant is a requirement for AOG to maintain a
minimum cash flow to interest expense ratio of 3.5:1, determined on
a rolling four quarter basis. The Fund is in compliance with all
credit facility covenants. As well, the borrowing base for the
Fund's credit facilities is determined through utilizing
Advantage's regular reserve estimates. The banking syndicate
thoroughly evaluates the reserve estimates based upon their own
commodity price expectations to determine the amount of the
borrowing base. Revision or changes in the reserve estimates and
commodity prices can have either a positive or a negative impact on
the borrowing base of the Fund. On March 18, 2009, we announced our
intention to dispose of certain assets with the net proceeds from
these sales utilized to reduce outstanding bank debt and improve
Advantage's financial flexibility. Further to this end, asset sales
were completed in July 2009 and the amount of the borrowing base
was subsequently revised to $525 million for the new corporation
(note 13). Advantage's issuance of convertible debentures is
limited by its Trust Indenture which currently restricts the
issuance of additional convertible debentures to 25% of market
capitalization subsequent to issuance. Advantage's Trust Indenture
also provides for the issuance of an unlimited number of Trust
Units. However, through tax legislation, an income trust is
restricted to doubling its market capitalization as it stands on
October 31, 2006 by growing a maximum of 40% in 2007 and 20% for
the years 2008 to 2010. In addition, an income trust may replace
debt that was outstanding as of October 31, 2006 with new equity or
issue new, non- convertible debt without affecting the normal
growth percentage. As a result of the "normal growth" guidelines as
at June 30, 2009, the Fund is permitted to issue approximately $2.3
billion of new equity to January 1, 2011. If an income trust
exceeds the established limits on the issuance of new trust units
and convertible debt that constitute normal growth, the income
trust will be immediately subject to the Specified Investment
Flow-Through Entity tax legislation whereby the taxable portion of
any distributions paid will be subject to tax at the trust level.
Management of the Fund's capital structure is facilitated through
its financial and operational forecasting processes. The forecast
of the Fund's future cash flows is based on estimates of
production, commodity prices, forecast capital and operating
expenditures, and other investing and financing activities. The
forecast is regularly updated based on new commodity prices and
other changes, which the Fund views as critical in the current
environment. Selected forecast information is frequently provided
to the Board of Directors. The Fund's capital management
objectives, policies and processes have remained unchanged during
the six month period ended June 30, 2009. 12. Commitments Advantage
has several lease commitments relating to office buildings. The
estimated remaining annual minimum operating lease rental payments
for the buildings are as follows: 2009 1,931 2010 3,878 2011 1,471
2012 1,072
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$ 8,352
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13. Subsequent events On July 7, 2009, the Fund successfully closed
a bought deal financing with 17 million Trust Units issued at $6.00
each, for gross proceeds of $102 million. The proceeds were used to
reduce bank indebtedness. On July 9, 2009, the Fund successfully
completed the Plan of Arrangement (the "Arrangement") pursuant to
the Information Circular dated June 5, 2009. Under the Arrangement,
the Fund was dissolved and converted into a corporation, Advantage
Oil and Gas Ltd. (the "Corporation"), with each Trust Unit of the
Fund converted into one Common Share of the Corporation. On July 15
and 27, 2009, the Corporation successfully closed two dispositions
of oil and natural gas properties for gross proceeds of $252.6
million, subject to customary adjustments. The proceeds were used
to reduce bank indebtedness. On August 13, 2009, the borrowing base
of the credit facility was revised from $710 million to $525
million, pursuant to completion of the asset dispositions, with
terms and conditions substantially unchanged. Advisory The
information in this release contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical
fact may be forward-looking statements. Forward-looking statements
are often, but not always, identified by the use of words such as
"seek", "anticipate", "plan", "continue", "estimate", "estimates",
"expect", "designed", "may", "will", "project", "predict",
"potential", "targeting", "target", "targets" "intend", "could",
"might", "should", "believe", "would" and similar expressions.
These statements involve substantial known and unknown risks and
uncertainties, certain of which are beyond Advantage's control,
including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption
of new environmental laws and regulations and changes in how they
are interpreted and enforced; fluctuations in commodity prices and
foreign exchange and interest rates; stock market volatility and
market valuations; volatility in market prices for oil and natural
gas; liabilities inherent in oil and natural gas operations;
uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital,
acquisitions, of reserves, undeveloped lands and skilled personnel;
incorrect assessments of the value of acquisitions; changes in
income tax laws or changes in tax laws and incentive programs
relating to the oil and gas industry and income trusts; geological,
technical, drilling and processing problems and other difficulties
in producing petroleum reserves; and obtaining required approvals
of regulatory authorities. Advantage's actual results, performance
or achievement could differ materially from those expressed in, or
implied by, such forward-looking statements and, accordingly, no
assurances can be given that any of the events anticipated by the
forward-looking statements will transpire or occur or, if any of
them do, what benefits that Advantage will derive from them. Except
as required by law, Advantage undertakes no obligation to publicly
update or revise any forward-looking statements. DATASOURCE:
Advantage Oil & Gas Ltd. CONTACT: Investor Relations, Toll
free: 1-866-393-0393, ADVANTAGE OIL GAS LTD., 700, 400 - 3rd Avenue
SW, Calgary, Alberta, T2P 4H2, Phone: (403) 718-8000, Fax: (403)
718-8300, Web Site: http://www.advantageog.com/, E-mail:
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