Advantage Announces 1st Quarter Results, Conference Call & Webcast on May 14, 2007
CALGARY, May 11 /CNW/ - Advantage Energy Income Fund (TSX: AVN.UN)
("Advantage" or the "Fund") is pleased to announce its unaudited operating and
financial results for the first quarter ended March 31, 2007.
A conference call will be held on Monday May 14, 2007 at 9:00 a.m. MST
(11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-585-6398. A replay of the call will be available from approximately 2:00
p.m. EST on May 14, 2007 until approximately midnight, May 21, 2007 and can be
accessed by dialing toll free 1-866-245-6755. The passcode required for
playback is 587317. A live web cast of the conference call will be accessible
via the Internet on Advantage's website at www.advantageincome.com.Three months Three months
ended ended
March 31, 2007 March 31, 2006
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Financial ($000)
Revenue before royalties $ 135,502 $ 86,901
per Trust Unit(1) $ 1.25 $ 1.48
per boe $ 51.90 $ 54.49
Funds from operations $ 65,645 $ 46,630
per Trust Unit(2) $ 0.59 $ 0.79
per boe $ 25.14 $ 29.24
Net income $ 341 $ 15,964
per Trust Unit(1) $ 0.00 $ 0.27
Distributions $ 50,206 $ 44,459
per Trust Unit(2) $ 0.45 $ 0.75
Payout ratio (%) 76% 95%
Expenditures on property and equipment $ 49,696 $ 20,989
Working capital deficit(3) $ 31,896 $ 18,644
Bank indebtedness $ 354,443 $ 278,777
Convertible debentures (face value) $ 180,730 $ 113,531
Operating
Daily Production
Natural gas (mcf/d) 114,324 65,768
Crude oil and NGLs (bbls/d) 9,958 6,760
Total boe/d at 6:1 29,012 17,721
Average prices (including hedging)
Natural gas ($/mcf) $ 8.06 $ 8.69
Crude oil and NGLs ($/bbl) $ 58.64 $ 58.26
Supplemental (000)
Trust Units outstanding at end of period 115,050 59,468
Trust Units issuable
Convertible Debentures 8,334 5,699
Exchangeable Shares - 99
Trust Units Rights Incentive Plan 188 310
Trust Units outstanding and issuable at
end of period 123,572 65,576
Basic weighted average Trust Units 108,332 58,874
(1) based on basic weighted average Trust Units outstanding
(2) based on number of Trust Units outstanding at each cash distribution
record date
(3) working capital deficit excludes derivative assets and liabilities
Message to Unitholders
Highlights of the first quarter include:
- Production volumes in Q1 of 2007 increased 64% to 29,012 boe/d
compared to 17,721 boe/d in Q1 of 2006. Natural gas production for Q1
of 2007 was 114.3 mmcf/d, compared to 65.8 mmcf/d reported in the
same period of 2006. Crude oil and natural gas liquids production
averaged 9,958 bbls/d compared to 6,760 bbls/d in Q1 of 2006.
Production volumes in the first quarter are higher due to continued
success in our drilling program and from the Ketch acquisition, which
closed June 23, 2006. First quarter production volumes were impacted
by cold weather issues that created operational downtime at Fontas
and Martin Creek.
- Q1 2007 payout ratio decreased to 76% compared to 95% for the same
period in 2006, and 94% in Q4 2006. The decreased payout ratio from
Q4 2006 resulted from distribution adjustments and better realized
gas pricing due to our hedging program.
- The Fund declared three distributions during the quarter totaling
$0.45 per Trust Unit ($0.15 per unit per month). Since inception, the
Fund has distributed $714.8 million or $14.94 per Trust Unit.
- Funds from operations for the first quarter of 2007 was $65.6 million
or $0.59 per Trust Unit compared to $46.6 million or $0.79 per Trust
Unit for the same period of 2006.
- Advantage has successfully de-leveraged the balance sheet by reducing
debt from 1.64 times bank debt to cash flow from Q4 of 2006 to
1.35 times bank debt to cash flow in Q1 2007. This has positioned the
Fund for future opportunities.
- A highly successful capital program during the first quarter resulted
in the drilling of 39 gross (24.1 net) wells at a 97% success rate.
Capital expenditures totaled a net $49 million for E&D activity which
was less than expected due to the deferral of some projects as a
result of early spring break-up. Activity was primarily focused on
Martin Creek and Nevis. During the first quarter 13 gas wells (of a
17 well winter program) were drilled at Martin Creek, 6 gas wells
were drilled at Chigwell and 3 oil wells were drilled at Nevis. As
well, 2 oil wells and 1 gas well were drilled at Willesden Green.
Other capital spending related to a variety of wells, with smaller
working interests, and facilities necessary to support our 2007
activity.
- A complimentary asset acquisition of $12.9 million was also completed
at Nevis where the Fund has been very active and successful. The
acquisition included 175 boe/d and 6.75 sections of undeveloped land
with immediate drilling opportunities.
- Operating costs were higher in the first quarter driven by
significant one-time costs associated with the freeze up of
facilities at Fontas, a prior period adjustment and a general
increase in the cost of production services.
Hedging Position
- Advantage has layered in a number of hedges on both natural gas and
oil which will provide floor protection through summer 2007 and
winter 2007/2008 for natural gas. The Fund will continue to be active
in hedging to protect cash flow.
- The Fund currently has approximately 54% of natural gas production,
net of royalties, hedged for summer at an average floor price of
$7.08/mcf and an average ceiling of $8.09/mcf. In addition, 14% of
crude oil production, net of royalties, has been hedged for the same
period at an average floor of US$65.00/bbl and a ceiling of
US$90.00/bbl.
Looking Forward
- The merger of Advantage and Ketch has created a very high quality
long life asset base with over 500 high quality drilling locations
(greater than 4 year inventory) allowing increased flexibility for
capital allocation and upgrading.
- Production during the summer will be impacted by spring break-up and
major 3rd party plant turnarounds which are expected to occur. Per
unit operating costs are expected to remain in the higher end of our
guidance during spring and summer months when planned facilities
outages take place. In addition, we expect the payout ratio to be
higher during that period due to softer gas prices which are partly
offset by our hedging program, and lower production rates due to 3rd
party plant maintenance.
- Advantage reiterates annual guidance of 27,500 to 29,500 boe/d of
production with capital expenditures of $125 to $145 million. Annual
operating costs are expected to remain around the higher end of our
guidance of $9.50 to $10.50/boe driven by continued higher power
costs and cost pressures. We believe some relief in production
services will occur later this year as decreased drilling in western
Canada will reduce the cost of production services and supplies.
- Advantage has exceptional tax pool coverage which will help reduce
the amount of tax leakage to Unitholders for several years after
2011. As at December 31, 2006 the Fund had approximately $1.2 billion
in tax pools and deductions available, one of the highest in the
sector.MANAGEMENT'S DISCUSSION & ANALYSIS
The following Management's Discussion and Analysis ("MD&A"), dated as of
May 11, 2007, provides a detailed explanation of the financial and operating
results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we"
or "our") for the three months ended March 31, 2007 and should be read in
conjunction with the consolidated financial statements contained within this
interim report and the audited financial statements and MD&A for the year
ended December 31, 2006. The consolidated financial statements have been
prepared in accordance with Canadian generally accepted accounting principles
("GAAP") and all references are to Canadian dollars unless otherwise
indicated. All per barrel of oil equivalent ("boe") amounts are stated at a
conversion rate of six thousand cubit feet of natural gas being equal to one
barrel of oil or liquids.
Non-GAAP Measures
The Fund discloses several financial measures in the MD&A that do not
have any standardized meaning prescribed under GAAP. These financial measures
include funds from operations and per Trust Unit, cash netbacks, and payout
ratio. Management believes that these financial measures are useful
supplemental information to analyze operating performance, leverage and
provide an indication of the results generated by the Fund's principal
business activities prior to the consideration of how those activities are
financed or how the results are taxed. Investors should be cautioned that
these measures should not be construed as an alternative to net income, cash
provided by operating activities or other measures of financial performance as
determined in accordance with GAAP. Advantage's method of calculating these
measures may differ from other companies, and accordingly, they may not be
comparable to similar measures used by other companies.
Funds from operations, as presented, is based on cash provided by
operating activities before expenditures on asset retirement and changes in
non-cash working capital. Funds from operations per Trust Unit is based on the
number of Trust Units outstanding at each distribution record date. Both cash
netbacks and payout ratio are dependent on the determination of funds from
operations. Cash netbacks include the primary cash revenues and expenses on a
per boe basis that comprise funds from operations. Payout ratio represents the
distributions declared for the period as a percentage of funds from
operations. Funds from operations reconciled to cash provided by operating
activities is as follows:Three months ended
March 31
($000) 2007 2006 % change
-------------------------------------------------------------------------
Cash provided by operating
activities $ 50,520 $ 39,880 27%
Expenditures on asset retirement 4,009 1,033 288%
Changes in non-cash working
capital 11,116 5,717 94%
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Funds from operations $ 65,645 $ 46,630 41%
-------------------------------------------------------------------------Forward-Looking Information
The information in this report contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often, but not
always, identified by the use of words such as "seek", "anticipate", "plan",
"continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe",
"would" and similar expressions. These statements involve substantial known
and unknown risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are interpreted and
enforced; fluctuations in commodity prices and foreign exchange and interest
rates; stock market volatility and market valuations; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions; changes in income tax laws or changes in tax laws
and incentive programs relating to the oil and gas industry and income trusts;
geological, technical, drilling and processing problems and other difficulties
in producing petroleum reserves; obtaining required approvals of regulatory
authorities and other risk factors set forth in Advantage's Annual Information
Form which is available at www.advantageincome.com or www.sedar.com.
Advantage's actual results, performance or achievement could differ materially
from those expressed in, or implied by, such forward-looking statements and,
accordingly, no assurances can be given that any of the events anticipated by
the forward-looking statements will transpire or occur or, if any of them do,
what benefits that Advantage will derive from them. Except as required by law,
Advantage undertakes no obligation to publicly update or revise any
forward-looking statements.Overview
Three months ended
March 31
2007 2006 % change
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Cash provided by operating
activities ($000) $ 50,520 $ 39,880 27%
Funds from operations ($000) $ 65,645 $ 46,630 41%
per Trust Unit(1) $ 0.59 $ 0.79 (25)%
Net income ($000) $ 341 $ 15,964 (98)%
per Trust Unit - Basic $ 0.00 $ 0.27 (100)%
- Diluted $ 0.00 $ 0.27 (100)%
(1) Based on Trust Units outstanding at each distribution record date.Cash provided by operating activities increased 27%, funds from
operations increased 41%, and funds from operations per Trust Unit decreased
25% for the three months ended March 31, 2007, as compared to the same period
of 2006. The increase in cash provided by operating activities and funds from
operations has been primarily due to the merger with Ketch Resources Trust
("Ketch") that closed on June 23, 2006. The financial and operating results
from the acquired Ketch properties are included in all 2007 figures but are
not included in the three month period ended March 31, 2006, thereby
explaining most variances. However, both funds from operations and funds from
operations per Trust Unit have been negatively impacted by lower natural gas
prices throughout the first three months of 2007. Natural gas prices,
excluding hedging, were $7.61/mcf in the first quarter of 2007, a decrease of
12% compared to $8.69/mcf in the first quarter of 2006. Weaker natural gas
prices have been partially offset by a successful hedging program that was
implemented in November 2006. Net income decreased 98% in 2007, and net income
per basic Trust Unit decreased 100% for the three months ended March 31, 2007,
as compared to 2006. The lower net income has been primarily due to the lower
natural gas prices realized during the period, amortization of the management
internalization consideration, and increased depletion and depreciation
expense. The primary factor that causes significant variability of Advantage's
cash provided by operating activities, funds from operations and net income is
commodity prices. Refer to the section "Commodity Prices and Marketing" for a
more detailed discussion of commodity prices and our price risk management.Distributions
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Distributions declared ($000) $ 50,206 $ 44,459 13%
per Trust Unit(1) $ 0.45 $ 0.75 (40)%
Payout ratio (%) 76% 95% (19)%
(1) Based on Trust Units outstanding at each distribution record date.Total distributions increased 13% in the first quarter of 2007 when
compared to the same period in 2006. The higher total distributions reflect
the increased Trust Units outstanding from the continued growth and
development of the Fund, particularly due to the Ketch acquisition. As a
result of natural gas prices that have been very weak during the 2006/2007
winter season, we reduced the distribution level during this period to more
appropriately reflect the current commodity price environment. Distributions
per Trust Unit were $0.45 for the three months ended March 31, 2007,
representing a decrease of 40% from the $0.75 in 2006. This positively
impacted the payout ratio in the first three months of 2007 which was 76%, a
decrease of 19% when compared to the same period in 2006. The monthly
distribution is currently $0.15 per Trust Unit. To mitigate the persisting
risk associated with lower natural gas prices and the resulting negative
impact on distributions, the Fund implemented a hedging program in 2006 with
54% of natural gas hedged for April to October 2007. See "Commodity Price
Risk" section for a more detailed discussion of our price risk management. We
believe the Fund has taken the necessary action and is now well-positioned
with the objective of providing long-term distribution sustainability to
Unitholders.
Distributions are determined by Management and the Board of Directors. We
closely monitor our distribution policy considering forecasted cash flows,
optimal debt levels, capital spending activity, taxability to Unitholders,
working capital requirements, and other potential cash expenditures.
Distributions are announced monthly and are based on the cash available after
retaining a portion to meet such spending requirements. The level of
distributions are primarily determined by cash flows received from the
production of oil and natural gas from existing Canadian resource properties
and will be susceptible to the risks and uncertainties associated with the oil
and natural gas industry generally. If the oil and natural gas reserves
associated with the Canadian resource properties are not supplemented through
additional development or the acquisition of additional oil and natural gas
properties, our distributions will decline over time in a manner consistent
with declining production from typical oil and natural gas reserves.
Therefore, distributions are highly dependent upon our success in exploiting
the current reserve base and acquiring additional reserves. Furthermore,
monthly distributions we pay to Unitholders are highly dependent upon the
prices received for such oil and natural gas production. Oil and natural gas
prices can fluctuate widely on a month-to-month basis in response to a variety
of factors that are beyond our control. Declines in oil or natural gas prices
will have an adverse effect upon our operations, financial condition, reserves
and ultimately on our ability to pay distributions to Unitholders. The Fund
attempts to mitigate the volatility in commodity prices through our hedging
program. It is our long-term objective to provide stable and sustainable
distributions to the Unitholders, while continuing to grow the Fund. However,
given that funds from operations can vary significantly from month-to-month
due to these factors, the Fund may utilize various financing alternatives as
an interim measure to maintain stable distributions.Revenue
Three months ended
March 31
($000) 2007 2006 % change
-------------------------------------------------------------------------
Natural gas excluding hedging $ 78,333 $ 51,458 52%
Realized hedging gains 4,620 - -
-------------------------------------------------------------------------
Natural gas including hedging $ 82,953 $ 51,458 61%
-------------------------------------------------------------------------
Crude oil and NGLs excluding
hedging $ 50,939 $ 35,443 44%
Realized hedging gains 1,610 - -
-------------------------------------------------------------------------
Crude oil and NGLs including
hedging $ 52,549 $ 35,443 48%
-------------------------------------------------------------------------
Total revenue $ 135,502 $ 86,901 56%
-------------------------------------------------------------------------Natural gas revenues, excluding hedging, have increased 52% for the three
months ended March 31, 2007, compared to 2006. Crude oil and NGL revenues,
excluding hedging, have increased by 44% for the three months ended March 31,
2007. Revenues have increased due to additional production from the Ketch
merger but have been partially offset by lower commodity prices. Due to the
Fund's hedge positions that were in place for the first quarter of 2007,
natural gas revenues, including hedging, have increased 61% and crude oil and
NGL revenues, including hedging, increased 48%.Production
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Natural gas (mcf/d) 114,324 65,768 74%
Crude oil (bbls/d) 7,557 5,615 35%
NGLs (bbls/d) 2,401 1,145 110%
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Total (boe/d) 29,012 17,721 64%
-------------------------------------------------------------------------
Natural gas (%) 66% 62%
Crude oil (%) 26% 32%
NGLs (%) 8% 6%The Fund's total daily production averaged 29,012 boe/d for the first
quarter of 2007, an increase of 64% compared with the same period of 2006.
Natural gas production increased 74%, crude oil production increased 35%, and
NGLs production increased 110%. The increase in production during the quarter
has been primarily attributed to the Ketch acquisition, which closed June 23,
2006.
Our successful fourth quarter 2006 drilling program and further additions
in the first quarter of 2007 from Nevis, Chigwell, and Willesden Green, as
well as other areas in Southern Alberta and Saskatchewan have moderately
offset declines. Additions from Martin Creek were minimal in the first quarter
as most of the new production came on during the latter part of March. In
addition, our flattening production platform, resulting from our continued
focus on long life assets, is contributing to a stable operating foundation.
Production outages were slightly higher than expected especially in our
northern properties of Fontas and Martin Creek where cold weather issues
created operational downtime.
For the remainder of the year, we expect major third party plant
turnarounds during the second and third quarter, which will impact our
production levels.Commodity Prices and Marketing
Natural Gas
Three months ended
March 31
($/mcf) 2007 2006 % change
-------------------------------------------------------------------------
Realized natural gas prices
Excluding hedging $ 7.61 $ 8.69 (12)%
Including hedging $ 8.06 $ 8.69 (7)%
AECO monthly index $ 7.46 $ 9.31 (20)%Realized natural gas prices, excluding hedging, decreased 12% for the
three months ended March 31, 2007, as compared to the same period of 2006. The
price of natural gas is primarily based on supply and demand fundamentals in
the North American marketplace. Natural gas prices experienced sustained
weakness throughout 2006 due to relatively uneventful weather resulting in
natural gas inventories that swelled to historic levels. The 2006/2007 winter
has generally been mild, with inventory levels remaining higher than average,
causing continued downward pressure on commodity prices. However, February
2007 brought sustained colder weather and inventory levels decreased below
2006 levels but are still ample compared to demand. The withdrawals from
inventories resulted in a modest rebound in natural gas prices but overall the
prices still remain low. We continue to believe that the long-term pricing
fundamentals for natural gas remain strong. These fundamentals include (i) the
continued strength of crude oil prices, which has eliminated the economic
advantage of fuel switching away from natural gas, (ii) long-term tightness in
supply that has resulted from persistent demand and the decline in North
American natural gas production levels and (iii) ongoing weather related
factors such as hot summers, cold winters and annual hurricane season in the
Gulf of Mexico, all of which have an impact on the delicate supply/demand
balance that exists.Crude Oil and NGLs
Three months ended
March 31
($/bbl) 2007 2006 % change
-------------------------------------------------------------------------
Realized crude oil prices
Excluding hedging $ 59.03 $ 59.42 (1)%
Including hedging $ 61.40 $ 59.42 3%
Realized NGLs prices
Excluding hedging $ 49.93 $ 52.57 (5)%
Realized crude oil and NGLs
prices
Excluding hedging $ 56.84 $ 58.26 (2)%
Including hedging $ 58.64 $ 58.26 1%
WTI ($US/bbl) $ 58.12 $ 63.88 (9)%
$US/$Canadian exchange rate $ 0.85 $ 0.87 (2)%Realized crude oil and NGLs prices, excluding hedging, decreased 2% for
the three months ended March 31, 2007, as compared to the same period of 2006.
Advantage's crude oil prices are based on the benchmark pricing of West Texas
Intermediate Crude ("WTI") adjusted for quality, transportation costs and
$US/$Canadian exchange rates. Advantage's realized crude oil price has not
changed to the same extent as WTI due to the change in foreign exchange rates
and the narrowing of Canadian crude oil differentials relative to WTI. The
price of WTI fluctuates based on worldwide supply and demand fundamentals.
There has been significant price volatility experienced over the last several
years whereby WTI has reached historic high levels. For the three months ended
March 31, 2007, WTI averaged $US 58.12/bbl, a decrease of 9%, compared to
2006. Many developments have resulted in the current price levels, including
significant geopolitical issues. Early in 2006, prices were strong due to
concerns regarding the lack of North American refining capacity, and the
continued strength of global demand. The mild 2005/2006 winter and the surge
in crude imports to North America resulted in significantly higher inventories
that prompted the relative price decrease during the end of 2006. Prices have
strengthened once again in the first quarter of 2007 due to continued civil
unrest in the Middle East and production restrictions by the OPEC cartel. With
the current strengthening in price levels, it is notable that demand has
remained resilient. We believe that the pricing fundamentals for crude oil
remain strong with many factors affecting the continued strength including (i)
supply management and supply restrictions by the OPEC cartel, (ii) ongoing
civil unrest in Venezuela, Nigeria, and the Middle East, (iii) strong world
wide demand, particularly in China, India and the United States and (iv) North
American refinery capacity constraints.
Commodity Price Risk
The Fund's operational results and financial condition will be dependent
on the prices received for oil and natural gas production. Oil and natural gas
prices have fluctuated widely during recent years and are determined by
economic and, in the case of oil prices, political factors. Supply and demand
factors, including weather and general economic conditions as well as
conditions in other oil and natural gas regions impact prices. Any movement in
oil and natural gas prices could have an effect on the Fund's financial
condition and therefore on the distributions to holders of Advantage Trust
Units. As current and future practice, Advantage has established a financial
hedging strategy and may manage the risk associated with changes in commodity
prices by entering into derivatives. These commodity risk management
activities could expose Advantage to losses or gains. To the extent that
Advantage engages in risk management activities related to commodity prices,
it will be subject to credit risk associated with counterparties with which it
contracts. Credit risk is mitigated by entering into contracts with only
stable, creditworthy parties and through frequent reviews of exposures to
individual entities.
Currently, the Fund has the following derivatives in place:Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Fixed price April 2007 9,478 mcf/d Cdn$7.16/mcf
to October 2007
Fixed price April 2007 9,478 mcf/d Cdn$7.55/mcf
to October 2007
Fixed price November 2007 7,109 mcf/d Cdn$9.54/mcf
to March 2008
Collar November 2007 9,478 mcf/d Floor Cdn$8.44/mcf
to March 2008 Ceiling Cdn$10.29/mcf
Collar November 2007 7,109 mcf/d Floor Cdn$8.70/mcf
to March 2008 Ceiling Cdn$10.71/mcf
Crude oil - WTI
Collar October 2006 to 1,000 bbls/d Floor US$65.00/bbl
September 2007 Ceiling US$90.00/bblAs at March 31, 2007 the fair value of the derivatives outstanding was an
asset of approximately $1,638,000 and a liability of $3,234,000. For the three
months ended March 31, 2007, $12,029,000 was recognized in income as an
unrealized derivative loss due to a decrease in the fair value from
December 31, 2006 and $6,230,000 was recognized in income as a realized
derivative gain, which partially alleviated lower revenue from reduced
commodity prices. The valuation of the derivatives is the estimated fair value
to settle the contracts as at March 31, 2007 and is based on pricing models,
estimates, assumptions and market data available at that time. The actual gain
or loss realized on cash settlement can vary materially due to subsequent
fluctuations in commodity prices as compared to the valuation assumptions. The
Fund does not apply hedge accounting and current accounting standards require
changes in the fair value to be included in the consolidated statement of
income and comprehensive income as an unrealized derivative gain or loss with
a corresponding derivative asset or liability recorded on the balance sheet.
In addition, the Fund has the following physical natural gas contracts in
place with gains and losses recognized in earnings as the contracts settle:Description of
Physical Contract Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Collar April 2007 4,739 mcf/d Floor Cdn$7.12/mcf
to October 2007 Ceiling Cdn$8.67/mcf
Collar April 2007 4,739 mcf/d Floor Cdn$6.86/mcf
to October 2007 Ceiling Cdn$9.13/mcf
Collar April 2007 9,478 mcf/d Floor Cdn$7.39/mcf
to October 2007 Ceiling Cdn$9.63/mcf
Collar April 2007 9,478 mcf/d Floor Cdn$6.33/mcf
to October 2007 Ceiling Cdn$7.20/mcf
Currently, the Fund has fixed the commodity price on anticipated
production as follows:
Approximate
Production Hedged,
Commodity Net of Royalties Minimum Price Maximum Price
-------------------------------------------------------------------------
Natural gas - AECO
Summer 2007 54% Cdn$7.08/mcf Cdn$8.09/mcf
Winter 2007/2008 28% Cdn$8.85/mcf Cdn$10.19/mcf
Crude Oil - WTI
Summer 2007 14% US$65.00/bbl US$90.00/bbl
Royalties
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Royalties, net of Alberta
Royalty Credit ($000) $ 26,165 $ 16,340 60%
per boe $ 10.02 $ 10.25 (2)%
As a percentage of revenue,
excluding hedging 20.2% 18.8% 1.4%Advantage pays royalties to the owners of mineral rights from which we
have leases. The Fund currently has mineral leases with provincial
governments, individuals and other companies. Royalties for 2006 are shown net
of Alberta Royalty Credit, which was a royalty rebate provided by the Alberta
government to certain producers and is proposed to be eliminated effective
January 1, 2007. Royalties have increased in total due to the increase in
revenue from higher production and have decreased on a per boe basis due to
reduced natural gas prices. Royalties as a percentage of revenue, excluding
hedging, have increased slightly from the 2006 period due to the inclusion of
slightly higher royalty rate properties from the Ketch acquisition and the
payment of prior year royalty adjustments. We expect the royalty rate to
remain comparable for 2007.Operating Costs
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Operating costs ($000) $ 30,270 $ 15,066 101%
per boe $ 11.59 $ 9.45 23%Total operating costs increased 101% for the three months ended March 31,
2007 as compared to 2006 mainly due to the Ketch acquisition. Operating costs
per boe increased 23% for the three months ended March 31, 2007, mainly due to
increased service and supply costs as the industry experienced an overall
labour cost increase, a prior period adjustment and several one-time events.
Cold weather in February 2007 caused the freeze-up of facilities in Fontas and
Martin Creek that required additional maintenance and repair work. In
addition, increased power and trucking costs due to crude oil pipeline
restrictions in Southeast Saskatchewan have continued into the first quarter
of 2007. Lastly, upward pressure is normally placed on operating costs during
the winter months due to a peak in winter activity and field work. We will be
opportunistic and proactive in pursuing alternatives that will improve our
operating cost structure. A significant operating cost that Advantage has been
successful in stabilizing is electricity associated with field operations. The
Fund has been active in preserving the price of power by hedging 3.5 MW at
$56.68/MWh for 2007 and 3.0 MW at $54.00/MWh for 2008, which represents a
substantial portion of our power usage. We expect that operating costs per boe
will be in the upper end of our guidance range of $9.50 to $10.50 for the 2007
year.General and Administrative
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
General and administrative
expense ($000) $ 4,716 $ 1,966 140%
per boe $ 1.81 $ 1.23 47%General and administrative ("G&A") expense has increased 140% for the
three months ended March 31, 2007, as compared to 2006. G&A per boe increased
47% for the three months when compared to the same period of 2006. G&A expense
has increased overall and per boe primarily due to an increase in staff levels
that have resulted from the Ketch acquisition and growth of the Fund.
Additionally, the Ketch acquisition was conditional on Advantage internalizing
the external management contract structure and eliminating all related fees
for a more typical employee compensation arrangement. The new employee
compensation plan has resulted in higher G&A expense that is offset by the
elimination of future management fees and performance incentive. Prior to
elimination of the management contract, the quarterly management fee and
annual performance incentive were not included within G&A.Management Fee, Performance Incentive, and Management Internalization
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Management fee ($000) $ - $ 832 (100)%
per boe $ - $ 0.52 (100)%
Performance incentive ($000) $ - $ 2,680 (100)%
Management internalization ($000) $ 5,369 $ - -Prior to the Ketch merger, the Manager received both a management fee and
a performance incentive fee as compensation pursuant to the Management
Agreement approved by the Board of Directors. As a condition of the merger
with Ketch, the Fund and the Manager reached an agreement to internalize the
management contract arrangement. As part of the agreement, Advantage agreed to
purchase all of the outstanding shares of the Manager pursuant to the terms of
the Arrangement, thereby eliminating the management fee and performance
incentive effective April 1, 2006. The Trust Unit consideration issued in
exchange for the outstanding shares of the Manager was placed in escrow for a
3-year period and is being deferred and amortized into income as management
internalization expense over the specific vesting periods during which
employee services are provided.Interest
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Interest expense ($000) $ 5,187 $ 3,193 62%
per boe $ 1.99 $ 2.00 (1)%
Average effective interest rate 5.4% 4.9% 0.5%
Bank indebtedness at March 31
($000) $ 354,443 $ 278,777 27%Interest expense has increased 62% for the three months ended March 31,
2007, as compared to 2006. Interest expense per boe has remained stable for
the three months ended March 31, 2007. The increase in interest expense is
primarily attributable to a higher average debt level associated with the
growth of the Fund, an increase in the average effective interest rates, and
the merger with Ketch, which included the assumption of Ketch's additional
bank indebtedness. The increased debt has been used in financing continued
development activities and pursuit of expansion opportunities. We monitor the
debt level to ensure an optimal mix of financing and cost of capital that will
provide a maximum return to Unitholders. Our current credit facilities have
been a favorable financing alternative with an effective interest rate of only
5.4% for the three months ended March 31, 2007. The Fund's interest rates are
primarily based on short term Bankers Acceptance rates plus a stamping fee.Interest and Accretion on Convertible Debentures
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Interest on convertible
debentures ($000) $ 3,238 $ 2,345 38%
per boe $ 1.24 $ 1.47 (16)%
Accretion on convertible
debentures ($000) $ 599 $ 461 30%
per boe $ 0.23 $ 0.29 (21)%
Convertible debentures maturity
value at March 31 ($000) $ 180,730 $ 113,531 59%Interest on convertible debentures has increased 38% and accretion on
convertible debentures has increased 30% for the three months ended March 31,
2007 as compared to the same period of 2006. The increases in total interest
and accretion for the quarter as well as the increased convertible debentures
maturity value are due to Advantage assuming Ketch's 6.50% convertible
debentures in the merger. The increased interest and accretion from the
additional debentures has been partially offset for the quarter due to the
exchange of convertible debentures to Trust Units during 2006 that pay
distributions rather than interest. During the three months ended March 31,
2007, there were no convertible debenture conversions.Cash Netbacks
Three months ended Three months ended
March 31, 2007 March 31, 2006
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 129,272 $ 49.51 $ 86,901 $ 54.49
Realized gain on
derivatives 6,230 2.39 - -
Royalties (26,165) (10.02) (16,340) (10.25)
Operating costs (30,270) (11.59) (15,066) (9.45)
-------------------------------------------------------------------------
Operating $ 79,067 $ 30.29 $ 55,495 $ 34.79
General and
administrative (4,716) (1.81) (1,966) (1.23)
Management fee - - (832) (0.52)
Interest (5,187) (1.99) (3,193) (2.00)
Interest on
convertible debentures (3,238) (1.24) (2,345) (1.47)
Taxes (281) (0.11) (529) (0.33)
-------------------------------------------------------------------------
Funds from operations $ 65,645 $ 25.14 $ 46,630 $ 29.24
-------------------------------------------------------------------------Funds from operations of Advantage for the quarter ended March 31, 2007
increased to $65.6 million from $46.6 million in the prior year. However, the
cash netback per boe for March 31, 2007 was $25.14, 14% lower than the $29.24
realized during the same period of 2006. The lower cash netback per boe is
primarily due to lower revenues per boe resulting from softer natural gas
prices as well as higher operating costs. Operating costs per boe for the
three months ended March 31, 2007 were $11.59, an increase of 23% from the
$9.45 experienced in 2006. Operating costs have steadily increased over the
past year due to significantly higher field costs associated with supplies and
services that has resulted from the high level of industry activity and an
overall industry labour cost increase.Depletion, Depreciation and Accretion
Three months ended
March 31
2007 2006 % change
-------------------------------------------------------------------------
Depletion, depreciation &
accretion ($000) $ 63,918 $ 30,023 113%
per boe $ 24.48 $ 18.82 30%Depletion and depreciation of property and equipment is provided on the
"unit-of-production" method based on total proved reserves. The depletion,
depreciation and accretion ("DD&A") provision has increased 113% for the three
months ended March 31, 2007 due to the 64% increase of daily production
volumes mainly from the Ketch acquisition. The DD&A per boe has increased by
30% for the three months ended March 31, 2007 compared to the prior year. The
higher DD&A per boe was due to a higher valuation for the Ketch reserves than
accumulated from prior acquisitions and development activities.
Taxes
Current taxes paid or payable for the quarter ended March 31, 2007
amounted to $0.3 million, compared to $0.5 million expensed for the same
period of 2006. Current taxes primarily represent Saskatchewan resource
surcharge, which is based on the petroleum and natural gas revenues within the
province of Saskatchewan.
Future income taxes arise from differences between the accounting and tax
bases of the operating company's assets and liabilities. For the three months
ended March 31, 2007, the Fund recognized an income tax reduction of
$16.6 million compared to a reduction of $2.5 million for 2006.
Under the Fund's current structure, payments are made between the
operating company and the Fund transferring income tax obligations to the
Unitholders. Therefore, based on the current structure and existing
legislation, no cash income taxes are to be paid by the operating company or
the Fund, and as such, the future income tax liability recorded on the balance
sheet will be recovered through earnings over time. As at March 31, 2007, the
operating company had a future income tax liability balance of $45.3 million,
compared to $61.9 million at December 31, 2006. Canadian generally accepted
accounting principles require that a future income tax liability be recorded
when the book value of assets exceeds the balance of tax pools.
On October 31, 2006, the Federal Government proposed changes to Canada's
tax system that include altering the tax treatment of income trusts. The
government proposed a two-tier tax structure, similar to that of corporations,
whereby the taxable portion of distributions paid by trusts will be subject to
tax at the trust level in addition to personal tax as if they were dividends
from a taxable Canadian corporation. The changes are proposed to take effect
in 2011 for existing publicly-traded trusts. If enacted, the proposal could
affect the Fund in several ways, and Advantage is currently assessing several
options for the future. The Fund may allocate a portion of cash flows to
additional tax on distributions, resulting in less cash flow available for
distribution or the Fund may determine strategic alternatives such as
increasing cash flow allocated to capital spending, conversion to a
corporation, or paying a higher percentage of distributions on a return of
capital basis, all of which could result in a decrease or elimination of
distributions.
Contractual Obligations and Commitments
The Fund has contractual obligations in the normal course of operations
including purchases of assets and services, operating agreements,
transportation commitments, sales contracts and convertible debentures. These
obligations are of a recurring and consistent nature and impact cash flow in
an ongoing manner. The following table is a summary of the Fund's remaining
contractual obligations and commitments. Advantage has no guarantees or
off-balance sheet arrangements other than as disclosed.Payments due by period
($ millions) Total 2007 2008 2009 2010 2011
-------------------------------------------------------------------------
Building leases $ 4.8 $ 1.6 $ 1.4 $ 0.8 $ 0.8 $ 0.2
Capital leases 2.5 2.2 0.3 - - -
Pipeline/transportation 5.5 2.9 2.0 0.5 0.1 -
Convertible debentures(1) 180.7 1.4 5.4 57.1 70.0 46.8
-------------------------------------------------------------------------
Total contractual
obligations $193.5 $ 8.1 $ 9.1 $ 58.4 $ 70.9 $ 47.0
-------------------------------------------------------------------------
(1) As at March 31, 2007, Advantage had $180.7 million convertible
debentures outstanding. Each series of convertible debentures are
convertible to Trust Units based on an established conversion price.
The Fund expects that the obligations related to convertible
debentures will be settled either directly or indirectly through the
issuance of Trust Units.
(2) Bank indebtedness of $354.4 million has been excluded from the
contractual obligations table as the credit facilities constitute a
revolving facility for a 364 day term which is extendible annually
for a further 364 day revolving period at the option of the
syndicate. If not extended, the revolving credit facility is
converted to a two year term facility with the first payment due one
year and one day after commencement of the term.
Liquidity and Capital Resources
The following table is a summary of the Fund's capitalization structure:
($000, except as otherwise indicated) March 31, 2007
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 354,443
Working capital deficit(1) 31,896
-------------------------------------------------------------------------
Net debt $ 386,339
-------------------------------------------------------------------------
Trust Units outstanding (000) 115,050
Trust Unit closing market price ($/Trust Unit) $ 11.84
-------------------------------------------------------------------------
Market value $ 1,362,192
-------------------------------------------------------------------------
Convertible debentures maturity value (long-term) $ 179,245
-------------------------------------------------------------------------
Total capitalization $ 1,927,776
-------------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities,
distributions payable, and the current portion of capital lease
obligations and convertible debentures.Unitholders' Equity and Convertible Debentures
Advantage has utilized a combination of Trust Units, convertible
debentures and bank debt to finance acquisitions and development activities.
As at March 31, 2007, the Fund had 115.0 million Trust Units outstanding.
On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an
additional 800,000 Trust Units upon exercise of the Underwriters'
over-allotment option on March 7, 2007, at $12.80 per Trust Unit for
approximate net proceeds of $104.1 million (net of Underwriters' fees and
other issue costs of $6.0 million). The net proceeds of the offering were used
to pay down bank indebtedness and to subsequently fund capital and general
corporate expenditures. As at May 11, 2007, Advantage had 115.4 million Trust
Units issued and outstanding.
On July 24, 2006, Advantage adopted a Premium Distribution™,
Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan").
For Unitholders that elect to participate in the Plan, Advantage will settle
the monthly distribution obligation through the issuance of additional Trust
Units at 95% of the Average Market Price (as defined in the Plan). Unitholder
enrollment in the Premium Distribution™ component of the Plan effectively
authorizes the subsequent disposal of the issued Trust Units in exchange for a
cash payment equal to 102% of the cash distributions that the Unitholder would
otherwise have received if they did not participate in the Plan. During the
three months ended March 31, 2007, 1,069,989 Trust Units were issued as a
result of the Plan, generating $12.4 million reinvested in the Fund and
representing an approximate 23% participation rate.
As at March 31, 2007, the Fund had $180.7 million convertible debentures
outstanding that were convertible to 8.3 million Trust Units based on the
applicable conversion prices. During the three months ended March 31, 2007, no
convertible debentures were exchanged and as at May 11, 2007, the convertible
debentures outstanding have not changed from December 31, 2006.
Bank Indebtedness, Credit Facility and Other Obligations
At March 31, 2007, Advantage had bank indebtedness outstanding of
$354.4 million, after executing the highest quarter of capital spending
expected in 2007. The Fund has a $600 million credit facility agreement
consisting of a $580 million extendible revolving loan facility and a $20
million operating loan facility. The current credit facilities are secured by
a $1 billion floating charge demand debenture, a general security agreement
and a subordination agreement from the Fund covering all assets and cash
flows.
At March 31, 2007, Advantage had a working capital deficiency of
$31.9 million. Our working capital includes items expected for normal
operations such as trade receivables, prepaids, deposits, trade payables and
accruals as well as the current portion of capital lease obligations and
convertible debentures. Working capital varies primarily due to the timing of
such items, the current level of business activity including our capital
program, commodity price volatility, and seasonal fluctuations. Advantage has
no unusual working capital requirements. We do not anticipate any problems in
meeting future obligations as they become due given the strength of our funds
from operations. It is also important to note that working capital is
effectively integrated with Advantage's operating credit facility, which
assists with the timing of cash flows as required.
Advantage generally does not make use of capital leases to finance
development expenditures. However, Advantage currently has two capital leases
outstanding at March 31, 2007 for $2.5 million that were both assumed from
corporate acquisitions.Capital Expenditures
Three months ended
March 31
($000) 2007 2006
-------------------------------------------------------------------------
Land and seismic $ 2,340 $ 2,228
Drilling, completions and workovers 27,135 14,007
Well equipping and facilities 20,110 4,288
Other 111 466
-------------------------------------------------------------------------
$ 49,696 $ 20,989
Property acquisitions 12,851 -
Property dispositions (427) -
-------------------------------------------------------------------------
Total capital expenditures $ 62,120 $ 20,989
-------------------------------------------------------------------------Advantage's growth strategy has been to acquire properties in or near
areas where we have large land positions, shallow to medium depth drilling
opportunities, and preserve a balance of year round access. We focus on areas
where past activity has yielded long-life reserves with high cash netbacks.
With the integration of the Ketch assets, Advantage is very well positioned to
selectively exploit the highest value-generating drilling opportunities given
the size, strength and diversity of our asset base. As a result, the Fund has
a high level of flexibility to distribute its capital program and ensure a
risk-balanced platform of projects. Our preference is to operate a high
percentage of our properties such that we can maintain control of capital
expenditures, operations and cash flows.
For the three month period ended March 31, 2007, the Fund had a very
active capital program and spent a net $62.1 million. Approximately
$27.1 million was expended on drilling and completion operations where the
Fund drilled a total of 24.1 net (39 gross) wells at a 97% success rate.
During the quarter we drilled 9.9 net (13 gross) gas wells at Martin Creek,
2.3 net (6 gross) gas wells at Chigwell, one 100% working interest gas well at
both Boundary Lake and Westerose, three 100% working interest oil wells at
Nevis, two 100% working interest oil wells and 0.2 net (1 gross) gas well at
Willesden Green, and one 100% working interest oil well at Pinto as well as
several wells at other minor properties. Total capital spending in the quarter
included $21.7 million at Martin Creek, $7.3 million at Nevis, $4.9 million at
Willesden Green, $3.1 million at Brazeau, and $2.4 million in SE Saskatchewan.
The $12.9 million property acquisition was for producing properties and
undeveloped land at the Fund's core area, Nevis.
The following table summarizes the various funding requirements during
the three months ended March 31, 2007 and the sources of funding to meet those
requirements.Sources and Uses of Funds
Three months
ended March 31,
($000) 2007
-------------------------------------------------------------------------
Sources of funds
Units issued, net of costs $ 116,481
Funds from operations 65,645
Property dispositions 427
-------------------------------------------------------------------------
$ 182,553
-------------------------------------------------------------------------
Uses of funds
Decrease in bank indebtedness $ 56,131
Distributions to Unitholders 51,919
Expenditures on property and equipment 49,696
Property acquisitions 12,851
Increase in working capital 7,596
Expenditures on asset retirement 4,009
Reduction of capital lease obligations 351
-------------------------------------------------------------------------
$ 182,553
-------------------------------------------------------------------------
Quarterly Performance
2007 2006
($000, except as
otherwise indicated) Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 114,324 117,134 122,227 70,293 65,768
Crude oil and NGLs
(bbls/d) 9,958 9,570 9,330 6,593 6,760
Total (boe/d) 29,012 29,092 29,701 18,309 17,721
Average prices
Natural gas ($/mcf)
Excluding hedging $ 7.61 $ 6.90 $ 5.89 $ 6.18 $ 8.69
Including hedging $ 8.06 $ 7.27 $ 5.90 $ 6.18 $ 8.69
AECO monthly $ 7.46 $ 6.36 $ 6.03 $ 6.28 $ 9.31
Crude oil and NGLs
($/bbl)
Excluding hedging $ 56.84 $ 54.58 $ 67.77 $ 68.69 $ 58.26
Including hedging $ 58.64 $ 55.86 $ 67.77 $ 68.69 $ 58.26
WTI (US$/bbl) $ 58.12 $ 60.21 $ 70.55 $ 70.75 $ 63.88
Total revenues
(before royalties) $135,502 $127,539 $124,521 $ 80,766 $ 86,901
Net income $ 341 $ 8,736 $ 1,209 $ 23,905 $ 15,964
per Trust Unit
- basic $ 0.00 $ 0.08 $ 0.01 $ 0.38 $ 0.27
- diluted $ 0.00 $ 0.08 $ 0.01 $ 0.38 $ 0.27
Funds from operations $ 65,645 $ 62,737 $ 63,110 $ 42,281 $ 46,630
Distributions declared $ 50,206 $ 58,791 $ 60,498 $ 53,498 $ 44,459
Payout ratio (%) 76% 94% 96% 127% 95%
2005
($000, except as
otherwise indicated) Q4 Q3 Q2
-----------------------------------------------------
Daily production
Natural gas (mcf/d) 72,587 75,994 79,492
Crude oil and NGLs
(bbls/d) 7,106 7,340 6,772
Total (boe/d) 19,204 20,006 20,021
Average prices
Natural gas ($/mcf)
Excluding hedging $ 11.68 $ 8.25 $ 7.27
Including hedging $ 10.67 $ 7.79 $ 7.30
AECO monthly $ 11.68 $ 8.15 $ 7.38
Crude oil and NGLs
($/bbl)
Excluding hedging $ 60.14 $ 66.00 $ 56.57
Including hedging $ 59.53 $ 61.10 $ 56.24
WTI (US$/bbl) $ 60.04 $ 63.17 $ 53.13
Total revenues
(before royalties) $110,172 $ 95,715 $ 87,476
Net income $ 25,846 $ 18,674 $ 26,537
per Trust Unit
- basic $ 0.45 $ 0.33 $ 0.46
- diluted $ 0.45 $ 0.32 $ 0.46
Funds from operations $ 60,906 $ 55,575 $ 49,705
Distributions declared $ 43,265 $ 43,069 $ 44,693
Payout ratio (%) 71% 77% 90%The table above highlights the Fund's performance for the first quarter
of 2007 and also for the preceding seven quarters. During 2005, production
continued to experience normal declines until a more significant decrease
occurred in the first quarter of 2006 due to a one-time adjustment for several
payout wells, restricted production on wells in Chip Lake and Nevis, and some
minor non-core property dispositions that occurred in 2005. Production
increased in the second quarter of 2006 with the addition of eight days of
production from the Ketch properties and further increased in the third
quarter of 2006 as the acquisition was fully integrated with Advantage.
Advantage's revenues and funds from operations increased beginning in the
third quarter of 2006 primarily due to the production from the merger with
Ketch, offset by lower natural gas prices. Net income has been lower during
the last three quarters due to reduced natural gas prices realized during the
periods, amortization of the management internalization consideration, and
increased depletion and depreciation expense due to the Ketch merger. During
2006, the payout ratio was higher relative to prior quarters as a result of
considerably weak natural gas prices relative to the distribution level.
Additionally, the timing of the Ketch merger significantly increased the
payout ratio for the second quarter of 2006 as the arrangement closed prior to
the June record date resulting in the payment of a full month distribution to
Ketch Unitholders whereas funds from operations for June only included eight
days of cash flows from the Ketch properties. The payout ratio in the first
quarter of 2007 decreased as we reduced the distribution level to reflect
current commodity prices.
Critical Accounting Estimates
The preparation of financial statements in accordance with GAAP requires
Management to make certain judgments and estimates. Changes in these judgments
and estimates could have a material impact on the Fund's financial results and
financial condition. Management relies on the estimate of reserves as prepared
by the Fund's independent qualified reserves evaluator. The process of
estimating reserves is critical to several accounting estimates. The process
of estimating reserves is complex and requires significant judgments and
decisions based on available geological, geophysical, engineering and economic
data. These estimates may change substantially as additional data from ongoing
development and production activities becomes available and as economic
conditions impact crude oil and natural gas prices, operating costs, royalty
burden changes, and future development costs. Reserve estimates impact net
income through depletion and depreciation of property and equipment, the
provision for asset retirement costs and related accretion expense, and
impairment calculations for property and equipment and goodwill. The reserve
estimates are also used to assess the borrowing base for the Fund's credit
facilities. Revision or changes in the reserve estimates can have either a
positive or a negative impact on net income and the borrowing base of the
Fund.
Controls and Procedures
The Fund has established procedures and internal control systems to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in
accordance with GAAP. Management of the Fund is committed to providing timely,
accurate and balanced disclosure of all material information about the Fund.
Disclosure controls and procedures are in place to ensure all ongoing
reporting requirements are met and material information is disclosed on a
timely basis. The Chief Executive Officer and Vice-President Finance and Chief
Financial Officer, individually, sign certifications that the financial
statements, together with the other financial information included in the
regular filings, fairly present in all material respects the financial
condition, results of operations, and cash flows as of the dates and for the
periods presented in the filings. The certifications further acknowledge that
the filings do not contain any untrue statement of a material fact or omit to
state a material fact required to be stated or that is necessary to make a
statement not misleading in light of the circumstances under which it was
made, with respect to the period covered by the filings. During the first
quarter of 2007, there were no significant changes that would materially
affect, or are reasonably likely to materially affect, the internal controls
over financial reporting.
Because of inherent limitations, internal control over financial
reporting may not prevent or detect misstatements and even those systems
determined to be effective can provide only reasonable assurance with respect
to the financial statement preparation and presentation. Further, projections
of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
Outlook
The Fund has established a 2007 Budget, as approved by the Board of
Directors, that retains a high degree of activity and will focus on drilling
in many of our key properties where a high level of success was realized
through 2006. Capital will also be directed to accommodate facility expansions
and further develop enhanced recovery schemes as necessary. New drill bit
additions are expected to be more effective in replacing production as
corporate declines have continued to subside through the first quarter of
2007. Advantage's production now contains very little flush production from
high impact wells and concentrated drilling programs (from 2004 and 2005
activities) creating a balanced and predictable platform. During the second
and third quarters of 2007, we expect two major third party plant turnarounds
to occur which will significantly affect our Lookout Butte and Westerose
properties. These two turnarounds combined with well payouts are expected to
result in an impact of approximately 400 boe/d to the 2007 annual average
production. Overall, we expect production in 2007 to average between 27,500 to
29,500 boe/d.
Advantage's 2007 capital expenditures budget of $120 to $145 million
includes the drilling, completion and tie-in of 107 gross wells (64 net)
weighted approximately 50% toward light oil and 50% to natural gas. In
Northeast B.C., a 17 well (14 net) natural gas drilling program was
substantially completed in the first quarter of 2007 at Martin Creek. This
program exploited the northern portions of the Field where a successful
drilling program was conducted in 2006 which extended pool boundaries. Results
confirm a very successful program with tested well deliverability in excess of
facilities capacity and budget assumptions. Combined with Advantage's already
commanding position of facilities infrastructure and operatorship, we estimate
three to four years of drilling inventory in this property. At Sunset, in
Northern Alberta, four wells are planned to follow-up the successful 2006
development drilling program and capital will also be required to expand water
flood facilities in this light oil pool. In Central Alberta, a 12 well
(12 net) program is planned at Nevis for 40 degree light oil where horizontal
drilling in 2006 showed excellent results. A net 15 sections of land were
added through deals with industry third parties in 2006 bringing the total
land under control to 37.5 net sections in this property. A second development
drilling program in the western portion of the Nevis property is underway and
facilities will be constructed to accommodate production additions. Additional
gas opportunities will be pursued in the Central Alberta areas targeting down
spacing and follow-up to successes. Initial drilling results on the west side
of Nevis are comparable to wells previously drilled to date. In Southern
Alberta and S.E. Saskatchewan, 13 wells (10 net) will be drilled for oil
targets in 2007.
Operating costs are forecasted to be closer to the upper end of our
guidance range of $9.50 to $10.50/boe range as higher gas prices indicated by
the current strip price through the summer of 2007 suggest higher power costs
than what was realized in 2006. In addition, higher property taxes, surface
rentals and additional trucking costs due to continued pipeline restrictions
in Southeast Saskatchewan are expected to occur in 2007. Advantage is
undertaking several operating cost reduction initiatives through 2007 to help
offset these increases.
Advantage's funds from operations in 2007 will continue to be impacted by
the volatility of crude oil and natural gas prices and the $US/$Canadian
exchange rate. Advantage will continue to follow its strategy of acquiring
properties that provide low risk development opportunities and enhance long
term cash flow. Advantage will also continue to focus on low cost production
and reserve additions through low to medium risk development drilling
opportunities that have arisen as a result of the acquisitions completed in
prior years and from the significant inventory of drilling opportunities that
has resulted from the Ketch merger. The synergy of larger size and the
complementary winter/summer drilling programs with the Ketch merger is
providing benefits in terms of securing services, flexibility and quality of
our capital program.
Looking forward, Advantage's high quality assets, three year drilling
inventory, hedging program and excellent tax pools provides many options for
the Fund and we are committed to maximizing value generation for our
Unitholders.
Additional Information
Additional information relating to Advantage can be found on SEDAR at
www.sedar.com and the Fund's website at www.advantageincome.com. Such other
information includes the annual information form, the annual information
circular - proxy statement, press releases, material contracts and agreements,
and other financial reports. The annual information form will be of particular
interest for current and potential Unitholders as it discusses a variety of
subject matter including the nature of the business, structure of the Fund,
description of our operations, general and recent business developments, risk
factors, reserves data and other oil and gas information.
May 11, 2007CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
March 31, December 31,
(thousands of dollars) 2007 2006
-------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Accounts receivable $ 81,580 $ 79,537
Prepaid expenses and deposits 16,555 16,878
Derivative asset (note 8) 1,093 9,840
-------------------------------------------------------------------------
99,228 106,255
Deposit on property acquisition - 1,410
Derivative asset (note 8) 545 593
Fixed assets (note 2) 1,756,251 1,753,058
Goodwill 120,271 120,271
-------------------------------------------------------------------------
$ 1,976,295 $ 1,981,587
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 108,823 $ 116,109
Distributions payable to Unitholders 17,257 18,970
Current portion of capital lease
obligations (note 3) 2,481 2,527
Current portion of convertible debentures
(note 5) 1,470 1,464
Derivative liability (note 8) 3,234 -
-------------------------------------------------------------------------
133,265 139,070
Capital lease obligations (note 3) - 305
Bank indebtedness (note 4) 354,443 410,574
Convertible debentures (note 5) 171,412 170,819
Asset retirement obligations 35,306 34,324
Future income taxes 45,328 61,939
-------------------------------------------------------------------------
739,754 817,031
-------------------------------------------------------------------------
Unitholders' Equity
Unitholders' capital (note 6) 1,714,608 1,592,758
Convertible debentures equity component
(note 5) 8,041 8,041
Contributed surplus (note 6) 863 863
Accumulated deficit (note 7) (486,971) (437,106)
-------------------------------------------------------------------------
1,236,541 1,164,556
-------------------------------------------------------------------------
$ 1,976,295 $ 1,981,587
-------------------------------------------------------------------------
Commitments (note 9)
See accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Income,
Comprehensive Income and Accumulated Deficit
Three months Three months
ended ended
(thousands of dollars, except for per March 31, March 31,
Trust Unit amounts) (unaudited) 2007 2006
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas $ 129,272 $ 86,901
Realized gain on derivatives (note 8) 6,230 -
Unrealized loss on derivatives (note 8) (12,029) -
Royalties, net of Alberta Royalty Credit (26,165) (16,340)
-------------------------------------------------------------------------
97,308 70,561
-------------------------------------------------------------------------
Expenses
Operating 30,270 15,066
General and administrative 4,716 1,966
Management fee - 832
Performance incentive - 2,680
Management internalization (note 6) 5,369 -
Interest 5,187 3,193
Interest and accretion on convertible
debentures 3,837 2,806
Depletion, depreciation and accretion 63,918 30,023
-------------------------------------------------------------------------
113,297 56,566
-------------------------------------------------------------------------
Income (loss) before taxes and non-controlling
interest (15,989) 13,995
Future income tax reduction (16,611) (2,527)
Income and capital taxes 281 529
-------------------------------------------------------------------------
(16,330) (1,998)
-------------------------------------------------------------------------
Net income before non-controlling interest 341 15,993
Non-controlling interest - 29
-------------------------------------------------------------------------
Net income and comprehensive income 341 15,964
Accumulated deficit, beginning of period (437,106) (269,674)
Distributions declared (50,206) (44,459)
-------------------------------------------------------------------------
Accumulated deficit, end of period $ (486,971) $ (298,169)
-------------------------------------------------------------------------
Net income per Trust Unit (note 6)
Basic $ 0.00 $ 0.27
Diluted $ 0.00 $ 0.27
-------------------------------------------------------------------------
See accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
Three months Three months
ended ended
March 31, March 31,
(thousands of dollars) (unaudited) 2007 2006
-------------------------------------------------------------------------
Operating Activities
Net income $ 341 $ 15,964
Add (deduct) items not requiring cash:
Unrealized loss on derivatives 12,029 -
Performance incentive - 2,680
Management internalization 5,369 -
Accretion on convertible debentures 599 461
Depletion, depreciation and accretion 63,918 30,023
Future income taxes (16,611) (2,527)
Non-controlling interest - 29
Expenditures on asset retirement (4,009) (1,033)
Changes in non-cash working capital (11,116) (5,717)
-------------------------------------------------------------------------
Cash provided by operating activities 50,520 39,880
-------------------------------------------------------------------------
Financing Activities
Units issued, net of costs (note 6) 116,481 -
Increase (decrease) in bank indebtedness (56,131) 26,301
Reduction of capital lease obligations (351) (88)
Distributions to Unitholders (51,919) (44,054)
-------------------------------------------------------------------------
Cash provided by (used in) financing activities 8,080 (17,841)
-------------------------------------------------------------------------
Investing Activities
Expenditures on property and equipment (49,696) (20,989)
Property acquisitions (12,851) -
Property dispositions 427 -
Changes in non-cash working capital 3,520 (1,050)
-------------------------------------------------------------------------
Cash used in investing activities (58,600) (22,039)
-------------------------------------------------------------------------
Net change in cash - -
Cash, beginning of period - -
-------------------------------------------------------------------------
Cash, end of period $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Interest paid $ 7,005 $ 6,643
Taxes paid $ 361 $ 529
See accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007 (unaudited)
All tabular amounts in thousands except for Trust Units and per Trust
Unit amounts
The interim consolidated financial statements of Advantage Energy Income
Fund ("Advantage" or the "Fund") have been prepared by management in
accordance with Canadian generally accepted accounting principles using
the same accounting policies as those set out in note 2 to the
consolidated financial statements for the year ended December 31, 2006,
except as described below. The interim consolidated financial statements
should be read in conjunction with the audited consolidated financial
statements of Advantage for the year ended December 31, 2006 as set out
in Advantage's Annual Report.
1. Changes in Accounting Policies
(a) Financial Instruments
Effective January 1, 2007, the Fund adopted CICA Handbook sections
3855 "Financial Instruments - Recognition and Measurement", 3862
"Financial Instruments - Disclosures", 3863 "Financial Instruments -
Presentation", and 3865 "Hedges".
Section 3855 "Financial Instruments - Recognition and Measurement"
establishes criteria for recognizing and measuring financial
instruments including financial assets, financial liabilities and
non-financial derivatives. Under this standard, all financial
instruments must initially be recognized at fair value on the balance
sheet. Measurement of financial instruments subsequent to the initial
recognition, as well as resulting gains and losses, are recorded
based on how each financial instrument was initially classified. The
Fund has classified each identified financial instrument into the
following categories: held for trading, loans and receivables, held
to maturity investments, available for sale financial assets, and
other financial liabilities. Held for trading financial instruments
are measured at fair value with gains and losses recognized in
earnings immediately. Available for sale financial assets are
measured at fair value with gains and losses, other than impairment
losses, recognized in other comprehensive income and transferred to
earnings when the asset is derecognized. Loans and receivables, held
to maturity investments and other financial liabilities are
recognized at amortized cost using the effective interest method and
impairment losses are recorded in earnings when incurred. Upon
adoption and with all new financial instruments, an election is
available that allows entities to classify any financial instrument
as held for trading. Only those financial assets and liabilities that
must be classified as held for trading by the standard have been
classified as such by the Fund. As the Fund frequently utilizes non-
financial derivative instruments to manage market risk associated
with volatile commodity prices, such instruments must be classified
as held for trading and recorded on the balance sheet at fair value
as derivative assets and liabilities. Section 3865 "Hedges" provides
an alternative to recognizing gains and losses on derivatives in
earnings if the instrument is designated as part of a hedging
relationship and meets the necessary criteria. Under the alternative
hedge accounting treatment, gains and losses on derivatives
classified as effective hedges are included in other comprehensive
income until the time at which the hedged item is realized. The Fund
does not utilize derivative instruments for speculative purposes but
has elected not to apply hedge accounting. Therefore, gains and
losses on these instruments are recorded as unrealized gains and
losses on derivatives in the consolidated statement of income,
comprehensive income and accumulated deficit in the period they occur
and as realized gains and losses on derivatives when the contracts
are settled. Since unrealized gains and losses on derivatives are
non-cash items, there is no impact on the statement of cash flows as
a result of their recognition.
In some instances, derivative financial instruments can be embedded
within other contracts. Embedded derivatives within a host contract
must be recorded separately from the host contract when their
economic characteristics and risks are not clearly and closely
related to those of the host contract, the terms of the embedded
derivatives are the same as those of a freestanding derivative, and
the combined contract is not classified as held for trading or
designated at fair value. The Fund selected January 1, 2003, as its
accounting transition date for any potential embedded derivatives and
has not identified any embedded derivatives that would require
separation from the host contract and fair value accounting.
Transaction costs are frequently attributed to the acquisition or
issue of a financial asset or liability. Section 3855 requires that
such transaction costs incurred on held for trading financial
instruments be expensed immediately. For other financial instruments,
an entity can adopt an accounting policy of either expensing
transaction costs as they occur or adding such transaction costs to
the fair value of the financial instrument. The Fund has chosen a
policy of adding transaction costs to the fair value initially
recognized for financial assets and liabilities that are not
classified as held for trading.
The Fund has adopted the new standards prospectively as required
which allows amendments to the carrying values of financial
instruments, effective as of the adoption date, to be recognized as
an adjustment to the beginning balance of accumulated deficit. As the
new standards have not resulted in any significant changes to the
recognition and measurement of the Fund's financial instruments, no
adjustment to accumulated deficit was required. The new standards
also require several additional disclosures in the notes to the
financial statements. Among the disclosures required, the Fund must
disclose the exposure to various risks associated with financial
instruments and the policies that exist to manage these risks.
(b) Comprehensive Income
Effective January 1, 2007, the Fund adopted CICA Handbook section
1530 "Comprehensive Income". The Fund has adopted this section
retroactively and there were no changes to prior periods.
Comprehensive income consists of net income and other comprehensive
income ("OCI") with amounts included in OCI shown net of tax.
Accumulated other comprehensive income is a new equity category
comprised of the cumulative amounts of OCI. To date, the Fund does
not have any adjustments in OCI and therefore comprehensive income is
currently equal to net income.
(c) Accounting Changes
Effective January 1, 2007, the Fund adopted the revised
recommendations of CICA section 1506 "Accounting Changes". The new
recommendations permit voluntary changes in accounting policy only if
they result in financial statements which provide more reliable and
relevant information. Accounting policy changes are applied
retrospectively unless it is impractical to determine the period or
cumulative impact of the change. Corrections of prior period errors
are applied retrospectively and changes in accounting estimates are
applied prospectively by including the changes in earnings. The
guidance was effective for all changes in accounting polices, changes
in accounting estimates and corrections of prior period errors
initiated in periods beginning on or after January 1, 2007.
(d) Recent Accounting Pronouncements Issued But Not Implemented
The CICA has issued section 1535 "Capital Disclosures", which will be
effective January 1, 2008 for the Fund. Section 1535 will require the
Fund to provide additional disclosures relating to capital and how it
is managed. It is not anticipated that the adoption of section 1535
will impact the amounts reported in the Fund's financial statements
as they primarily relate to disclosure.
2. Fixed Assets
Accumulated
Depletion and Net Book
March 31, 2007 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 2,391,363 $ 639,774 $ 1,751,589
Furniture and equipment 8,286 3,624 4,662
---------------------------------------------------------------------
$ 2,399,649 $ 643,398 $ 1,756,251
---------------------------------------------------------------------
Accumulated
Depletion and Net Book
December 31, 2006 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 2,324,948 $ 576,707 $ 1,748,241
Furniture and equipment 8,175 3,358 4,817
---------------------------------------------------------------------
$ 2,333,123 $ 580,065 $ 1,753,058
---------------------------------------------------------------------
During the three months ended March 31, 2007, Advantage capitalized
general and administrative expenditures directly related to
exploration and development activities of $1,969,000 (March 31,
2006 - $838,000).
3. Capital Lease Obligations
The Fund has capital leases on a variety of property and equipment.
Future minimum lease payments at March 31, 2007 consist of the
following:
2007 $ 2,207
2008 308
-------------------------------------------------
2,515
Less amounts representing interest (34)
-------------------------------------------------
Current portion $ 2,481
-------------------------------------------------
4. Bank Indebtedness
Advantage has a credit facility agreement with a syndicate of
financial institutions which provides for a $580 million extendible
revolving loan facility and a $20 million operating loan facility.
The loan's interest rate is based on either prime, US base rate,
LIBOR or bankers' acceptance rates, at the Fund's option, subject to
certain basis point or stamping fee adjustments ranging from 0.00% to
1.25% depending on the Fund's debt to cash flow ratio. The credit
facilities are secured by a $1 billion floating charge demand
debenture, a general security agreement and a subordination agreement
from the Fund covering all assets and cash flows. The credit
facilities are subject to review on an annual basis with the next
review to occur in June 2007. Various borrowing options are available
under the credit facilities, including prime rate-based advances, US
base rate advances, US dollar LIBOR advances and bankers' acceptances
loans. The credit facilities constitute a revolving facility for a
364 day term which is extendible annually for a further 364 day
revolving period at the option of the syndicate. If not extended, the
revolving credit facility is converted to a two year term facility
with the first payment due one year and one day after commencement of
the term. The credit facilities contain standard commercial covenants
for facilities of this nature. The only financial covenant is a
requirement for AOG to maintain a minimum cash flow to interest
expense ratio of 3.5:1, determined on a rolling four quarter basis.
Breach of any covenant will result in an event of default in which
case AOG has 20 days to remedy such default. If the default is not
remedied or waived, and if required by the majority of lenders, the
administrative agent of the lenders has the option to declare all
obligations of AOG under the credit facilities to be immediately due
and payable without further demand, presentation, protest, or notice
of any kind. Distributions by AOG to the Fund (and effectively by the
Fund to Unitholders) are subordinated to the repayment of any amounts
owing under the credit facilities. Distributions to Unitholders are
not permitted if the Fund is in default of such credit facilities or
if the amount of the Fund's outstanding indebtedness under such
facilities exceeds the then existing current borrowing base. Interest
payments under the debentures are also subordinated to indebtedness
under the credit facilities and payments under the debentures are
similarly restricted. For the three months ended March 31, 2007, the
effective interest rate on the outstanding amounts under the facility
was approximately 5.4% (March 31, 2006 - 4.9%).
5. Convertible Debentures
The convertible unsecured subordinated debentures pay interest semi-
annually and are convertible at the option of the holder into Trust
Units of Advantage at the applicable conversion price per Trust Unit
plus accrued and unpaid interest. The details of the convertible
debentures including fair market values initially assigned and
issuance costs are as follows:
10.00% 9.00% 8.25% 7.75%
---------------------------------------------------------------------
Issue date Oct. 18, July 8, Dec. 2, Sep. 15,
2002 2003 2003 2004
Maturity date Nov. 1, Aug. 1, Feb. 1, Dec. 1,
2007 2008 2009 2011
Conversion price $ 13.30 $ 17.00 $ 16.50 $ 21.00
Liability
component $ 52,722 $ 28,662 $ 56,802 $ 47,444
Equity component 2,278 1,338 3,198 2,556
---------------------------------------------------------------------
Gross proceeds 55,000 30,000 60,000 50,000
Issuance costs (2,495) (1,444) (2,588) (2,190)
---------------------------------------------------------------------
Net proceeds $ 52,505 $ 28,556 $ 57,412 $ 47,810
---------------------------------------------------------------------
7.50% 6.50% Total
--------------------------------------------------------
Issue date Sep. 15, May 18,
2004 2005
Maturity date Oct. 1, June 30,
2009 2010
Conversion price $ 20.25 $ 24.96
Liability
component $ 71,631 $ 66,981 $ 324,242
Equity component 3,369 2,971 15,710
--------------------------------------------------------
Gross proceeds 75,000 69,952 339,952
Issuance costs (3,190) - (11,907)
--------------------------------------------------------
Net proceeds $ 71,810 $ 69,952 $ 328,045
--------------------------------------------------------
The convertible debentures are redeemable prior to their maturity
dates, at the option of the Fund, upon providing 30 to 60 days
advance notification. The redemption prices for the various
debentures, plus accrued and unpaid interest, is dependent on the
redemption periods and are as follows:
Convertible Redemption
Debenture Redemption Periods Price
---------------------------------------------------------------------
10.00% After November 1, 2006 and $1,025
before November 1, 2007
---------------------------------------------------------------------
9.00% After August 1, 2006 and $1,050
on or before August 1, 2007
After August 1, 2007 and $1,025
before August 1, 2008
---------------------------------------------------------------------
8.25% After February 1, 2007 and $1,050
on or before February 1, 2008
After February 1, 2008 and $1,025
before February 1, 2009
---------------------------------------------------------------------
7.75% After December 1, 2007 and $1,050
on or before December 1, 2008
After December 1, 2008 and $1,025
on or before December 1, 2009
After December 1, 2009 and $1,000
before December 1, 2011
---------------------------------------------------------------------
7.50% After October 1, 2007 and on $1,050
or before October 1, 2008
After October 1, 2008 and $1,025
before October 1, 2009
---------------------------------------------------------------------
6.50% After June 30, 2008 and $1,050
on or before June 30, 2009
After June 30, 2009 and $1,025
before June 30, 2010
---------------------------------------------------------------------
The balance of debentures outstanding at March 31, 2007 and changes
in the liability and equity components during the three months ended
March 31, 2007 are as follows:
10.00% 9.00% 8.25% 7.75%
---------------------------------------------------------------------
Debentures
outstanding $ 1,485 $ 5,392 $ 4,867 $ 46,766
---------------------------------------------------------------------
Liability
component:
Balance at
Dec. 31, 2006 $ 1,464 $ 5,235 $ 4,676 $ 43,765
Accretion of
discount 6 24 23 147
Converted to
Trust Units - - - -
---------------------------------------------------------------------
Balance at
Mar. 31, 2007 $ 1,470 $ 5,259 $ 4,699 $ 43,912
---------------------------------------------------------------------
Equity component:
Balance at
Dec. 31, 2006 $ 59 $ 229 $ 248 $ 2,286
Converted to
Trust Units - - - -
---------------------------------------------------------------------
Balance at
Mar. 31, 2007 $ 59 $ 229 $ 248 $ 2,286
---------------------------------------------------------------------
7.50% 6.50% Total
--------------------------------------------------------
Debentures
outstanding $ 52,268 $ 69,952 $ 180,730
--------------------------------------------------------
Liability
component:
Balance at
Dec. 31, 2006 $ 49,782 $ 67,361 $ 172,283
Accretion of
discount 219 180 599
Converted to
Trust Units - - -
--------------------------------------------------------
Balance at
Mar. 31, 2007 $ 50,001 $ 67,541 $ 172,882
--------------------------------------------------------
Equity component:
Balance at
Dec. 31, 2006 $ 2,248 $ 2,971 $ 8,041
Converted to
Trust Units - - -
--------------------------------------------------------
Balance at
Mar. 31, 2007 $ 2,248 $ 2,971 $ 8,041
--------------------------------------------------------
During the three months ended March 31, 2007, there were no
convertible debenture conversions (March 31, 2006 - $21,580,000).
6. Unitholders' Equity
(a) Unitholders' Capital
(i) Authorized
Unlimited number of voting Trust Units
(ii) Issued
Number of
Units Amount
---------------------------------------------------------------------
Balance at December 31, 2006 105,390,470 $ 1,618,025
Distribution reinvestment plan 1,069,989 12,381
Issued for cash, net of costs 8,600,000 104,100
Management internalization forfeitures (10,784) (218)
---------------------------------------------------------------------
115,049,675 $ 1,734,288
---------------------------------------------------------------------
Management internalization escrowed
Trust Units (19,680)
---------------------------------------------------------------------
Balance at March 31, 2007 $ 1,714,608
---------------------------------------------------------------------
On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an
additional 800,000 Trust Units upon exercise of the Underwriters'
over-allotment option on March 7, 2007, at $12.80 per Trust Unit for
approximate net proceeds of $104.1 million (net of Underwriters' fees
and other issue costs of $6.0 million).
During the quarter, 1,069,989 Trust Units were issued under the
Premium Distribution(™), Distribution Reinvestment, and Optional
Trust Unit Purchase Plan, generating $12.4 million reinvested in the
Fund.
On June 23, 2006, Advantage internalized the external management
contract structure and eliminated all related fees for total original
consideration of 1,933,208 Advantage Trust Units initially valued at
$39.1 million and subject to escrow provisions over a 3-year period,
vesting one-third each year beginning June 23, 2007. The management
internalization consideration is being deferred and amortized into
income as management internalization expense over the specific
vesting periods during which employee services are provided,
including an estimate of future Trust Unit forfeitures. For the three
months ended March 31, 2007, a total of 10,784 Trust Units issued for
the management internalization were forfeited and $5.4 million has
been recognized as management internalization expense. As at
March 31, 2007, 1,809,935 Trust Units remain held in escrow.
(b) Trust Units Rights Incentive Plan
Series B
Number Price
--------------------------------------------------------
Balance at December 31, 2006 187,500 $ 10.97
Reduction of exercise price - (0.45)
--------------------------------------------------------
Balance at March 31, 2007 187,500 $ 10.52
--------------------------------------------------------
Expiration date June 17, 2008
--------------------------------------------------------
(c) Net Income per Trust Unit
The calculation of basic and diluted net income per Trust Unit are
derived from both income available to Unitholders and weighted
average Trust Units outstanding calculated as follows:
Three months Three months
ended ended
March 31, March 31,
2007 2006
---------------------------------------------------------------------
Income available to Unitholders
Basic $ 341 $ 15,964
---------------------------------------------------------------------
Diluted $ 341 $ 15,964
---------------------------------------------------------------------
Weighted average Trust Units outstanding
Basic 108,331,960 58,873,831
Trust Units Rights Incentive Plan -
Series A - 80,568
Trust Units Rights Incentive Plan -
Series B 28,042 96,940
Management Internalization 221,180 -
---------------------------------------------------------------------
Diluted 108,581,182 59,051,339
---------------------------------------------------------------------
The calculation of diluted net income per Trust Unit excludes
Exchangeable Shares for the first quarter of 2006 and all series of
convertible debentures for both quarters as the impact would be anti-
dilutive. There were no Exchangeable Shares remaining in 2007. Total
weighted average Trust Units issuable in exchange for the
Exchangeable Shares and excluded from the diluted net income per
Trust Unit calculation for the quarter ended March 31, 2006 were
105,661. Total weighted average Trust Units issuable in exchange for
the convertible debentures and excluded from the diluted net income
per Trust Unit calculation for the quarter ended March 31, 2007 were
8,334,453 (March 31, 2006 - 6,163,733). As at March 31, 2007, the
total convertible debentures outstanding were immediately convertible
to 8,334,453 Trust Units (March 31, 2006 - 5,698,802).
7. Accumulated Deficit
Accumulated deficit consists of accumulated income and accumulated
distributions for the Fund since inception as follows:
March 31, December 31,
2007 2006
---------------------------------------------------------------------
Accumulated Income $ 227,864 $ 227,523
Accumulated Distributions (714,835) (664,629)
---------------------------------------------------------------------
Accumulated Deficit $ (486,971) $ (437,106)
---------------------------------------------------------------------
For the three months ended March 31, 2007, the Fund declared
$50.2 million in distributions, representing $0.45 per distributable
Trust Unit (three months ended March 31, 2006 - $44.5 million
representing $0.75 per distributable Trust Unit).
8. 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 March 31, 2007, there were no
significant differences between the carrying amounts reported on the
balance sheet and the estimated fair values of these financial
instruments due to the short terms to maturity and the floating
interest rate on the bank indebtedness.
The Fund has convertible debenture obligations outstanding, of which
the liability component has been classified as other liabilities and
measured at amortized cost. The convertible debentures have different
fixed terms and interest rates (note 5) resulting in fair values that
will vary over time as market conditions change. As at March 31,
2007, the estimated fair value of the total outstanding convertible
debenture obligation was $180.9 million (December 31, 2006 -
$180.0 million). The fair value of the liability component of
convertible debentures was determined based on a discounted cash flow
model assuming no future conversions and continuation of current
interest and principal payments. The Fund applied discount rates of
between 7 1/2 and 8% considering current available market
information, assumed credit adjustments, and various terms to
maturity.
Advantage has an established hedging strategy and manages the risk
associated with changes in commodity prices by entering into
derivatives, which are recorded at fair value as derivative assets
and liabilities with gains and losses recognized through earnings. As
the fair value of the contracts varies with commodity prices, they
give rise to financial assets and liabilities. The fair value of the
derivatives are determined through valuation models completed by
third parties. Various assumptions based on current market
information were used in these valuations, including settled forward
commodity prices, interest rates, foreign exchange rates, volatility
and other relevant factors. The actual gains and losses realized on
eventual cash settlement can vary materially due to subsequent
fluctuations in commodity prices as compared to the valuation
assumptions.
Credit Risk
Accounts receivable, deposits, and derivative assets are subject to
credit risk exposure and the carrying values reflect Management's
assessment of the associated maximum exposure to such credit risk.
Substantially all of the Fund's accounts receivable are due from
customers and joint operation partners concentrated in the Canadian
oil and gas industry. As such, accounts receivable are subject to
normal industry credit risks. Advantage mitigates such credit risk by
closely monitoring significant counterparties and dealing with a
broad selection of partners that diversify risk within the sector.
The Fund's deposits are primarily due from the provincial government
and are viewed by Management as having minimal associated credit
risk. To the extent that Advantage enters derivatives to manage
commodity price risk, it may be subject to credit risk associated
with counterparties with which it contracts. Credit risk is mitigated
by entering into contracts with only stable, creditworthy parties and
through frequent reviews of exposures to individual entities. In
addition, the Fund generally enters into derivative contracts with
investment grade institutions that are members of Advantage's credit
facility syndicate to further mitigate associated credit risk.
Liquidity Risk
The Fund is subject to liquidity risk attributed from accounts
payable and accrued liabilities, distributions payable to
Unitholders, bank indebtedness, convertible debentures, and
derivative liabilities. Accounts payable and accrued liabilities,
distributions payable to Unitholders and derivative liabilities are
all due within one year of the balance sheet date and Advantage does
not anticipate any problems in satisfying the obligations due to the
strength of funds from operations and the existing credit facility.
The Fund's bank indebtedness is subject to a $600 million credit
facility agreement which mitigates liquidity risk by enabling
Advantage to manage interim cash flow fluctuations. The credit
facility constitutes a revolving facility for a 364 day term which is
extendible annually for a further 364 day revolving period at the
option of the syndicate. If not extended, the revolving credit
facility is converted to a two year term facility with the first
payment due one year and one day after commencement of the term. The
terms of the credit facility are such that it provides Advantage
adequate flexibility to evaluate and assess liquidity issues if and
when they arise. Additionally, the Fund regularly monitors liquidity
related to obligations by evaluating forecasted cash flows, optimal
debt levels, capital spending activity, working capital requirements,
and other potential cash expenditures. This continual financial
assessment process further enables the Fund to mitigate liquidity
risk.
Advantage has several series of convertible debentures outstanding
that mature from 2007 to 2011 (note 5). Interest payments are made
semi-annually with excess funds from operating activities. As the
debentures become due, the Fund can satisfy the obligations in cash
or issue Trust Units at a price determined in the applicable
debenture agreements. This settlement option allows the Fund to
adequately manage liquidity, plan available cash resources and
implement an optimal capital structure.
To the extent that Advantage enters derivatives to manage commodity
price risk, it may be subject to liquidity risk as derivative
liabilities become due. While the Fund has elected not to follow
hedge accounting, derivative instruments are not entered for
speculative purposes and Management closely monitors existing
commodity risk exposures. As such, liquidity risk is mitigated since
any losses actually realized are subsidized by increased cash flows
realized from the higher commodity price environment.
Interest Rate Risk
The Fund is exposed to interest rate risk to the extent that bank
indebtedness is at a floating rate of interest and the Fund's maximum
exposure to interest rate risk is based on the effective interest
rate and the current carrying value of the bank indebtedness. The
Fund monitors the interest rate markets to ensure that appropriate
steps can be taken if interest rate volatility compromises the Fund's
cash flows. A 1% interest rate fluctuation for the three months ended
March 31, 2007 could potentially have impacted interest expense by
approximately $1.0 million for that period.
Price and Currency Risk
Advantage's derivative assets and liabilities are subject to both
price and currency risks as their fair values are based on
assumptions including forward commodity prices and foreign exchange
rates. The Fund enters derivative financial instruments to manage
commodity price risk exposure relative to actual commodity production
and does not utilize derivative instruments for speculative purposes.
Changes in the price assumptions can have a significant effect on the
fair value of the derivative assets and liabilities and thereby
impact net income. It is estimated that a 10% change in the forward
natural gas prices used to calculate the fair value of the natural
gas derivatives at March 31, 2007 could impact net income by
approximately $4.0 million for the three months ended March 31, 2007.
As well, a change of 10% in the forward crude oil prices used to
calculate the fair value of the crude oil derivatives at March 31,
2007 could impact net income by $0.5 million for the three months
ended March 31, 2007. A change of 10% in the forward power prices
used to calculate the fair value of the power derivatives at
March 31, 2007 could impact net income by $0.3 million for the
three months ended March 31, 2007. A similar change in the currency
rate assumption underlying the derivatives fair value does not have a
material impact on net income.
As at March 31, 2007 the Fund had the following derivatives in place:
Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.16/mcf
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.55/mcf
Fixed price November 2007
to March 2008 7,109 mcf/d Cdn$9.54/mcf
Collar November 2007
to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$10.29/mcf
Collar November 2007
to March 2008 7,109 mcf/d Floor Cdn$8.70/mcf
Ceiling Cdn$10.71/mcf
Crude oil - WTI
Collar October 2006 to
September 2007 1,000 bbls/d Floor US$65.00/bbl
Ceiling US$90.00/bbl
Electricity -
Alberta Pool
Price
Fixed price April 2006 to
December 2007 0.5 MW Cdn$60.79/MWh
Fixed price January 2007 to
December 2007 3.0 MW Cdn$56.00/MWh
Fixed price January 2008 to
December 2008 3.0 MW Cdn$54.00/MWh
As at March 31, 2007 the fair value of the derivatives outstanding
was an asset of approximately $1,638,000 and a liability of
$3,234,000 (December 31, 2006 - derivative asset of $10,433,000). For
the three months ended March 31, 2007 $12,029,000 was recognized in
income as an unrealized derivative loss and $6,230,000 was recognized
in income as a realized derivative gain. There were no derivatives in
place at March 31, 2006.
In addition, the Fund has the following physical natural gas
contracts in place with gains and losses recognized in earnings as
the contracts settle:
Description of
Physical Contract Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Collar April 2007 to
October 2007 4,739 mcf/d Floor Cdn$7.12/mcf
Ceiling Cdn$8.67/mcf
Collar April 2007 to
October 2007 4,739 mcf/d Floor Cdn$6.86/mcf
Ceiling Cdn$9.13/mcf
Collar April 2007 to
October 2007 9,478 mcf/d Floor Cdn$7.39/mcf
Ceiling Cdn$9.63/mcf
Collar April 2007 to
October 2007 9,478 mcf/d Floor Cdn$6.33/mcf
Ceiling Cdn$7.20/mcf
9. Commitments
Advantage has lease commitments relating to office buildings. The
estimated annual minimum operating lease rental payments for the
buildings, after deducting sublease income, are as follows:
2007 $ 1,684
2008 1,385
2009 779
2010 779
2011 195
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$ 4,822
---------------------------------------------------------------------%SEDAR: 00016522E %CIK: 0001259995
For further information:
For further information: Investor Relations, Toll free: 1-866-393-0393; Advantage Energy Income Fund, 3100, 150 - 6th Avenue SW, Calgary, Alberta, T2P 3Y7, Phone: (403) 261-8810, Fax: (403) 262-0723, Web Site: www.advantageincome.com, E-mail: advantage@advantageincome.com