Advantage Announces Release of Fourth Quarter and Year Ended December 31, 2007 Financial Results and Reserves
(TSX: AVN.UN, NYSE: AAV)
CALGARY, March 6 /CNW/ - Advantage Energy Income Fund ("Advantage" or the
"Fund") is pleased to announce the financial and operating results and
reserves for the year ended December 31, 2007.
A conference call will be held on Friday, March 7, 2008 at 9:00 a.m. MST
(11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-334-4934 and a slide presentation is available on our website. A replay
of the call will be available from approximately 2:00 p.m. EST on March 7,
2008 until approximately midnight, April 5, 2008 and can be accessed by
dialing toll free 1-866-245-6755. The passcode required for playback is
645732. A live web cast of the conference call will be accessible via the
Internet on Advantage's website at www.advantageincome.com.Acquisition of Sound Energy Trust
- Advantage completed a highly synergistic and accretive acquisition of
Sound Energy Trust which closed on September 5, 2007.
- The acquisition added proven plus probable reserves of 31.4 million
boe at a cost of $14.77 per boe.
- In addition, the acquisition significantly increased Advantage's
undeveloped land base, tax pools, and exposure to light oil. The
acquisition provides a significant number of low risk drilling
locations, facilities consolidation opportunities and 83 sections of
land at Glacier in Northwest Alberta with potential for natural gas
resource play development in the Montney formation.
Successful 2007 Drilling Program and Efficient Reserves Additions
- Overall, the Fund replaced 379% of annual production at a Finding,
Development & Acquisition cost of $15.19 per proven plus probable
boe, excluding changes in future development capital, and $15.90 per
proven plus probable boe, including changes in future development
capital.
- Drill bit reserve additions resulted in strong Finding & Development
("F&D") costs of $16.96 per proven plus probable boe, excluding
changes in future development capital. The three year F&D average is
$15.91 per proven plus probable boe, excluding changes in future
development capital. The Fund replaced 80% of its production through
the drill bit.
- Strong operational execution throughout the year resulted in the
drilling of 112 gross (64.8 net) wells in 2007 at a 99% success rate.
During the fourth quarter of 2007 a total of 32 gross (16.6 net)
wells were drilled at a 100% success rate.
- With the inclusion of Sound's assets and opportunities, Advantage's
drilling inventory grew to over 750 locations representing over
5 years of drilling within our land base.
- The Fund's proven plus probable reserve life index remains among the
highest in the natural gas weighted sector at 12.1 years.
- The Fund's Net Asset Value, before tax increased to $12.96 per unit
at a 10% discount factor.
Commodity Prices
- Crude oil prices strengthened in 2007 due to continued global demand
growth which was partly offset by the rising Canadian dollar.
- Declining natural gas prices, the rising Canadian dollar and
increased service costs were key factors leading to lower revenue and
cash flow levels in the latter part of 2007 due to our natural gas
production weighting. This was partly offset by our natural gas
hedging program which generated gains of $16.5 million in the second
half of 2007.
- The outlook for gas prices has since improved with colder weather in
early 2008. Key factors that are contributing to a more optimistic
view on prices for the remainder of 2008 include a 7 year low in
natural gas drilling activity in Canada, projections for lower LNG
deliveries into the U.S. in 2008 and higher demand for natural gas
fired electrical generation.
Hedging
- For 2008, we have secured approximately 51% of our net natural gas
production at an average Canadian floor price of $7.43 per mcf
(currently equivalent to NYMEX US$8.43 per mcf) and 38% of our oil
production at an average floor price of Canadian $94.07 per bbl
(currently equivalent to NYMEX WTI US$95.95 per bbl).
- The primary purpose of our hedging program is to i) reduce cash flow
volatility and ii) ensure that our capital program is substantially
funded out of cash flow.
Federal Government Tax Fairness Proposal
- On October 31, 2006 the Canadian Federal Government announced its
intention to impose a tax on income trusts beginning in 2011. This
announcement has continued to create uncertainty among the Trust
sector resulting in consolidation and a drive to consider alternate
structures.
- Advantage remains in a very strong position given our considerable
tax pool base of $1.7 billion which is available to shield future
taxes for many years after 2011 and also provides the Fund with more
options as alternatives to the Royalty Trust structure are
considered.
- It is the Fund's intention to continue to be a cash distributing
entity after 2010. We will continue to closely monitor industry
dynamics and are considering a number of alternative structures in
order to maximize after-tax value for Unitholders.
Alberta's Royalty Program Changes
- On October 25, 2007, the Alberta Government issued a proposal to
increase provincial royalties in 2009 on oil sands and conventional
oil and natural gas production. Advantage's analysis indicates a
minimal impact on the Fund due to the number of lower rate wells
within our long life assets which will receive favorable treatment.
Advantage is Well positioned for 2008
- The market was filled with uncertainty in 2007 including reduced
access to capital resulting from the Federal Government's October
2006 announcement and soft natural gas prices. Advantage responded in
2007 by completing a highly accretive acquisition, protecting our
cash flow through commodity price hedging and adjusting our
distributions to reduce the payout ratio to position the Fund for
growth opportunities in 2008 and beyond.
- With our cash flow stream protected through commodity price hedging
in 2008 and the current distribution level, we expect to
substantially fund our capital program out of cash flow and preserve
flexibility for additional opportunities throughout the year.
- Our 2008 capital program includes a strong suite of attractive
development drilling locations at Martin Creek, Nevis, Willesden
Green, Chip Lake, Sunset, Southern Alberta and Southeast
Saskatchewan. In addition, further delineation drilling is planned
for our Montney formation natural gas resource property at Glacier in
Northwest Alberta (located directly adjacent to the very successful
Swan Lake Pool development).
- Our underlying strengths continue to place Advantage in an enviable
position:
- Long-life asset base and stable production platform,
- High quality drilling inventory that exceeds 5 years,
- Superior technical and administrative team that is highly
motivated to create Unitholder value,
- Considerable tax pool base, and
- Reduced payout ratio.
First Quarter 2008 Drilling Highlights
- Execution of the 2008 winter drilling program is on schedule and
costs are on-track.
- At Martin Creek in Northeast British Columbia a 10 well drilling
program is nearing completion and results are anticipated to meet
expectations.
- At Glacier in Northwest Alberta, 4 vertical delineation wells have
been drilled into the Montney formation where completions and testing
are underway with an additional well currently drilling. Advantage's
83 section land block contains several existing Montney well
penetrations and extensive 3-dimensional seismic coverage. Our plans
for the balance of 2008 include additional vertical wells which will
be required to assess the potential for future horizontal well
development and production. This approach is similar to the
development plan conducted at the adjacent Swan Lake and Tupper pool
projects, where significant Montney development is occurring.
- At Nevis, Alberta horizontal drilling for light oil in the newer
western development area has been 100% successful with initial
production rates at or above expectations. A multi-year drilling
inventory and enhanced oil recovery potential exists on this
property.
- To date 53 gross (31.2 net) wells have been drilled in 2008 at a 97%
success rate.
- The Fund has significant behind pipe volumes as a result of these
activities which will be brought on-stream in the second quarter and
throughout 2008.As a final remark, we wish to acknowledge the dedication and hard work
from all of our directors, employees and personnel who continued to strive for
success despite a year of commodity price and political uncertainty.
We look forward to 2008 with much optimism and confidence in our Fund.Financial and Operating Highlights
Year ended
December 31, 2007 2006 2005 2004 2003
Financial ($000 except
per unit and per boe
amounts)
Revenue before
royalties(1) 557,358 419,727 376,572 241,481 166,075
per Trust Unit(2) 4.66 5.18 6.65 5.89 5.44
per boe 50.97 48.41 51.27 38.92 36.81
Funds from operations 271,143 214,758 211,541 126,478 94,735
per Trust Unit(3) 2.22 2.65 3.72 3.05 3.09
per boe 24.79 24.78 28.80 20.39 21.01
Net income (loss) (7,535) 49,814 75,072 24,038 38,503
per Trust Unit(2) (0.06) 0.62 1.33 0.59 1.26
Distributions declared 215,194 217,246 177,366 117,655 83,382
per Trust Unit(3) 1.77 2.66 3.12 2.82 2.71
Expenditures on property
and equipment 148,725 159,487 103,229 107,893 76,212
Working capital
deficit(4) 28,087 42,655 31,612 56,408 47,143
Bank indebtedness 547,426 410,574 252,476 267,054 102,968
Convertible debentures
(face value) 224,612 180,730 135,111 148,450 99,984
Trust Units outstanding
at end of year 138,269 105,390 57,846 49,675 36,717
Basic weighted average
Trust Units 119,604 80,958 56,593 41,008 30,536
Operating
Daily Production
Natural gas (mcf/d) 116,998 94,074 78,561 77,188 57,631
Crude oil and NGLs
(bbls/d) 10,462 8,075 7,029 4,084 2,756
Total boe/d @ 6:1 29,962 23,754 20,123 16,949 12,361
Average pricing
(including hedging)
Natural gas ($/mcf) 7.21 6.86 7.98 6.08 6.07
Crude oil & NGLs
($/bbl) 65.38 62.44 57.58 46.58 38.14
Proved plus probable
reserves(5)
Natural gas (bcf) 546.4 442.7 286.9 296.9 237.4
Crude oil & NGLs
(mbbls) 61,131 47,524 36,267 34,316 13,697
Total mboe 152,203 121,317 84,082 83,799 53,271
Reserve life index
(years)(6) 12.1 11.4 12.0 9.9 9.1
(1) includes realized derivative gains and losses
(2) based on basic weighted average Trust Units outstanding
(3) based on Trust Units outstanding at each distribution record date
(4) working capital deficit excludes derivative assets and liabilities
(5) 2007, 2006, 2005 and 2004 represents company interest reserves with
2003 being gross working interest reserves
(6) based on Q4 production rates
RESERVESAdvantage's year end reserve evaluation is based on an independent
engineering study conducted by Sproule Associates Limited ("Sproule")
effective December 31, 2007 and prepared in accordance with National
Instrument 51-101 ("NI 51-101").
Reserves included herein are stated on a Company Interest basis (before
royalty burdens and including royalty interests receivable) unless noted
otherwise. This report contains several cautionary statements that are
specifically required by NI 51-101. In addition to the detailed information
disclosed in this press release more detailed information on a net interest
basis (after royalty burdens and including royalty interests) and on a gross
interest basis (before royalty burdens and excluding royalty interests) will
be included in Advantage's Annual Information Form ("AIF") and will be
available at www.advantageincome.com and www.sedar.com.Highlights - Company Interest Reserves (Working Interests plus Royalty
Interests Receivable)
- The Fund's net asset value at December 31, 2007 is $12.96 per Unit,
(using a 10% discount factor).
- Proved plus probable ("P+P") reserve life index remains among the
highest in the gas weighted sector at 12.1 years.
- Replaced 379% of annual production at an all-in Finding, Development
& Acquisition ("FD&A") cost of $15.19 per P+P boe before
consideration of future development capital. Including future
development capital, the FD&A cost was $15.90 per P+P boe. This
includes the acquisition of Sound Energy Trust, which was effective
September 5, 2007.
December 31, December 31,
2007 2006
-------------------------------------------------------------------------
Proved plus probable reserves (mboe) 152,203 121,317
Present Value of reserves discounted at 10%,
proved plus probable ($000) $2,462,610 $1,850,073
Net Asset Value per Unit discounted at 10% $12.96 $12.29
Reserve Life Index (proved plus probable -
years)(1) 12.1 11.4
Reserves per Unit (proved plus probable)(2) 1.10 1.15
Bank debt per boe of reserves(3) $3.60 $3.38
Convertible debentures per boe of reserves(3) $1.48 $1.49
(1) Based on Q4 average production.
(2) Based on 138.3 million Units outstanding at December 31, 2007, and
105.6 million Units outstanding as December 31, 2006.
(3) BOE's may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio for natural gas of
6 Mcf: 1 bbl has been used which is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Company Interest Reserves - Summary as at December 31, 2007
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed Producing 22,222 1,840 6,714 288,398 78,842
Developed Non-producing 473 129 268 13,098 3,054
Undeveloped 3,622 297 941 52,927 13,680
Total Proved 26,317 2,266 7,923 354,423 95,576
-------------------------------------------------------------------------
Probable 17,540 3,282 3,803 192,013 56,627
Total Proved + Probable 43,857 5,548 11,726 546,436 152,203
-------------------------------------------------------------------------
Present Value of Future Net Revenue using Sproule price and cost
forecasts before taxes(1) ($000)
Before Income Taxes Discounted at
0% 5% 10%
-------------------------------------------------------------------------
Proved
Developed Producing $ 2,680,441 $ 1,904,687 $ 1,526,798
Developed Non-producing 83,654 67,773 56,479
Undeveloped 298,697 217,260 155,502
Total Proved 3,062,792 2,189,720 1,738,779
-------------------------------------------------------------------------
Probable 2,038,534 1,100,986 723,831
Total Proved + Probable $ 5,101,326 $ 3,290,706 $ 2,462,610
-------------------------------------------------------------------------
Present Value of Future Net Revenue using Sproule price and cost
forecasts after taxes(1) ($000)
After Income Taxes Discounted at
0% 5% 10%
-------------------------------------------------------------------------
Proved
Developed Producing $ 2,680,441 $ 1,904,687 $ 1,526,798
Developed Non-producing 83,654 67,773 56,479
Undeveloped 298,697 217,260 155,502
Total Proved 3,062,792 2,189,720 1,738,779
-------------------------------------------------------------------------
Probable 1,725,276 1,009,487 691,310
Total Proved + Probable $ 4,788,068 $ 3,199,208 $ 2,430,090
-------------------------------------------------------------------------
(1) Advantage's crude oil, natural gas and natural gas liquid reserves
were evaluated using Sproule's product price forecast effective
December 31, 2007 prior to, interests, debt services charges and
general and administrative expenses. It should not be assumed that
the discounted future revenue estimated by Sproule represents the
fair market value of the reserves.Sproule Price Forecasts
The present value of future net revenue at December 31, 2007 was based
upon crude oil and natural gas pricing assumptions prepared by Sproule
effective December 31, 2007. These forecasts are adjusted for reserve quality,
transportation charges and the provision of any applicable sales contracts.
The price assumptions used over the next seven years are summarized in the
table below:Alberta
AECO-C Henry Hub
WTI Edmonton Natural Natural
Crude Light Gas Gas Exchange
Oil Crude Oil ($Cdn/ ($US/ Rate
Year ($US/bbl) ($Cdn/bbl) mmbtu) mmbtu) ($US/$Cdn)
-------------------------------------------------------------------------
2008 89.61 88.17 6.51 7.56 1.00
2009 86.01 84.54 7.22 8.27 1.00
2010 84.65 83.16 7.69 8.74 1.00
2011 82.77 81.26 7.70 8.75 1.00
2012 82.26 80.73 7.61 8.66 1.00
2013 82.81 81.25 7.78 8.83 1.00
2014 84.46 82.88 7.96 9.01 1.00Net Asset Value using Sproule price and cost forecasts
The following net asset value ("NAV") table shows what is normally
referred to as a "produce-out" NAV calculation under which the current value
of the Fund's reserves would be produced at forecast future prices and costs.
The value is a snapshot in time and is based on various assumptions including
commodity prices and foreign exchange rates that vary over time.($000, except per Unit amounts) 0% 5% 10%
-------------------------------------------------------------------------
Net asset value per Unit before
taxes(1) - December 31, 2006 $ 30.39 $ 17.92 $ 12.29
-------------------------------------------------------------------------
Present value proved and probable
reserves $ 5,101,326 $ 3,290,706 $ 2,462,610
Undeveloped acreage and
seismic(2) 111,559 111,559 111,559
Working capital (deficit) (9,634) (9,634) (9,634)
Convertible debentures (224,612) (224,612) (224,612)
Bank debt (547,426) (547,426) (547,426)
Net asset value - December 31,
2007 $ 4,431,213 $ 2,620,593 $ 1,792,497
-------------------------------------------------------------------------
Net asset value per Unit after
taxes(1) - December 31, 2007 $ 32.05 $ 18.95 $ 12.96
-------------------------------------------------------------------------
(1) Based on 138.3 million Units outstanding at December 31, 2007, and
105.6 million Units outstanding at December 31, 2006.
(2) Internal estimate
Gross Working Interest Reserves - Summary as at December 31, 2007
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed Producing 22,060 1,814 6,646 285,551 78,111
Developed Non-producing 473 126 266 12,814 3,001
Undeveloped 3,621 297 928 52,568 13,608
Total Proved 26,154 2,237 7,840 350,933 94,720
-------------------------------------------------------------------------
Probable 17,477 3,271 3,773 190,613 56,289
Total Proved + Probable 43,630 5,508 11,613 541,546 151,009
-------------------------------------------------------------------------
Gross Working Interest Reserves Reconciliation
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
Proved (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2006 19,935 1,908 7,375 292,779 78,015
Extensions 327 55 232 14,694 3,062
Improved recovery 678 0 197 14,716 3,328
Discoveries 24 0 9 636 139
Economic factors 370 1 (105) (572) 170
Technical revisions 177 (562) (95) (2,710) (930)
Acquisitions 7,348 1,083 1,093 74,094 21,872
Dispositions 0 0 0 0 0
Production (2,705) (248) (866) (42,704) (10,936)
-------------------------------------------------------------------------
Closing balance at
Dec. 31, 2007 26,154 2,237 7,840 350,933 94,720
-------------------------------------------------------------------------
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
Proved + Probable (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2006 33,521 2,596 11,208 439,345 120,549
Extensions 1,667 68 519 30,191 7,285
Improved recovery 1,322 0 546 44,193 9,234
Discoveries 41 0 11 795 184
Economic factors 493 2 (133) 1,048 537
Technical revisions (1,271) (674) (1,110) (32,510) (8,472)
Acquisitions 10,562 3,764 1,438 101,188 32,628
Dispositions 0 0 0 0 0
Production (2,705) (248) (866) (42,704) (10,936)
-------------------------------------------------------------------------
Closing balance at
Dec. 31, 2007 43,630 5,508 11,613 541,546 151,009
-------------------------------------------------------------------------
Finding, Development & Acquisitions Costs ("FD&A")(1)
FD&A Costs - Gross Working Interest Reserves excluding Future Development
Capital
Proved Proved + Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 148,725 $ 148,725
Acquisitions net of dispositions ($000) 479,955 479,955
-------------------------------------------------------------------------
Total capital ($000) $ 628,680 $ 628,680
-------------------------------------------------------------------------
Total mboe, end of period
94,720 151,009
Total mboe, beginning of period 78,015 120,549
Production, mboe 10,936 10,936
-------------------------------------------------------------------------
Reserve additions, mboe 27,641 41,396
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 22.74 $ 15.19
Three year average FD&A Costs ($/boe) $ 27.51 $ 19.20
F&D costs ($/boe) $ 25.78 $ 16.96
Three year average F&D costs ($/boe) $ 22.02 $ 15.91
NI 51-101
FD&A Costs - Gross Working Interest Reserves including Future Development
Capital
Proved Proved + Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 148,725 $ 148,725
Acquisitions net of dispositions ($000) 479,955 479,955
Net change in Future Development Capital 6,517 29,517
-------------------------------------------------------------------------
Total capital ($000) $ 635,197 $ 658,197
-------------------------------------------------------------------------
Reserve additions, mboe 27,641 41,396
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 22.98 $ 15.90
Three year average FD&A Costs ($/boe) $ 27.94 $ 20.21
F&D costs ($/boe) $ 26.91 $ 20.33
Three year average F&D costs ($/boe) $ 23.21 $ 19.68
(1) Under NI 51-101, the methodology to be used to calculate FD&A costs
includes incorporating changes in future development capital ("FDC")
required to bring the proved undeveloped and probable reserves to
production. For continuity, Advantage has presented herein FD&A costs
calculated both excluding and including FDC.The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated future
development costs generally will not reflect total finding and development
costs related to reserves additions for that year. Changes in forecast FDC
occur annually as a result of development activities, acquisition and
disposition activities and capital cost estimates that reflect Sproule's best
estimate of what it will cost to bring the proved undeveloped and probable
reserves on production.
In all cases, the FD&A number is calculated by dividing the identified
capital expenditures by the applicable reserve additions. Boes may be
misleading, particularly if used in isolation. A boe conversion ratio of 6
MCF:1 BBL is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.Land Inventory at December 31, 2007
Developed Acres Undeveloped Acres
Gross Net Gross Net
-------------------------------------------------------------------------
Alberta 1,238,745 647,934 789,914 429,360
British Columbia 159,486 73,877 109,807 64,153
Saskatchewan 50,660 38,312 226,301 192,071
-------------------------------------------------------------------------
Total Acreage 1,448,891 760,123 1,126,022 685,584
-------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION & ANALYSISThe following Management's Discussion and Analysis ("MD&A"), dated as of
March 5, 2008, provides a detailed explanation of the financial and operating
results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we"
or "our") for the quarter and year ended December 31, 2007 and should be read
in conjunction with the audited consolidated financial statements. The
consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP") and all references
are to Canadian dollars unless otherwise indicated. All per barrel of oil
equivalent ("boe") amounts are stated at a conversion rate of six thousand
cubic feet of natural gas being equal to one barrel of oil or liquids.
Non-GAAP Measures
The Fund discloses several financial measures in the MD&A that do not
have any standardized meaning prescribed under GAAP. These financial measures
include funds from operations, funds from operations per Trust Unit and cash
netbacks. Management believes that these financial measures are useful
supplemental information to analyze operating performance, leverage and
provide an indication of the results generated by the Fund's principal
business activities prior to the consideration of how those activities are
financed or how the results are taxed. Investors should be cautioned that
these measures should not be construed as an alternative to net income, cash
provided by operating activities or other measures of financial performance as
determined in accordance with GAAP. Advantage's method of calculating these
measures may differ from other companies, and accordingly, they may not be
comparable to similar measures used by other companies.
Funds from operations, as presented, is based on cash provided by
operating activities before expenditures on asset retirement and changes in
non-cash working capital. Funds from operations per Trust Unit is based on the
number of Trust Units outstanding at each distribution record date. Cash
netbacks are dependent on the determination of funds from operations and
include the primary cash revenues and expenses on a per boe basis that
comprise funds from operations. Funds from operations reconciled to cash
provided by operating activities is as follows:Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Cash provided
by operating
activities $ 83,366 $ 65,495 27% $ 249,132 $ 229,087 9%
Expenditures on
asset retirement 2,116 3,462 (39)% 6,951 5,974 16%
Changes in non-
cash working
capital (4,963) (6,220) (20)% 15,060 (20,303)(174)%
-------------------------------------------------------------------------
Funds from
operations $ 80,519 $ 62,737 28% $ 271,143 $ 214,758 26%
-------------------------------------------------------------------------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,
royalty regimes and incentive programs relating to the oil and gas industry
and income trusts; geological, technical, drilling and processing problems and
other difficulties in producing petroleum reserves; obtaining required
approvals of regulatory authorities and other risk factors set forth in
Advantage's Annual Information Form which is available at
www.advantageincome.com or www.sedar.com. Advantage's actual results,
performance or achievement could differ materially from those expressed in, or
implied by, such forward-looking statements and, accordingly, no assurances
can be given that any of the events anticipated by the forward-looking
statements will transpire or occur or, if any of them do, what benefits that
Advantage will derive from them. Except as required by law, Advantage
undertakes no obligation to publicly update or revise any forward-looking
statements.
Acquisition of Sound Energy Trust
On September 5, 2007, the previously announced acquisition of Sound
Energy Trust ("Sound") was completed. The financial and operational
information for the quarter and year ended December 31, 2007 reflects
operations from the Sound properties effective from the closing date,
September 5, 2007.
The acquisition was accomplished through a Plan of Arrangement (the
"Arrangement") by the exchange of each Sound Trust Unit for 0.30 of an
Advantage Trust Unit or, at the election of the holder of Sound Trust Units,
$0.66 in cash and 0.2557 of an Advantage Trust Unit. In addition, all Sound
Exchangeable Shares were exchanged for Advantage Trust Units on the same ratio
based on the conversion ratio in effect at the effective date of the
Arrangement. Advantage issued 16,977,184 Trust Units and paid $21.4 million
cash as consideration to acquire Sound. The transaction is accretive to
Advantage's Unitholders on a production, cash flow, reserves and net asset
value basis and has significantly increased Advantage's tax pool position to a
total of approximately $1.7 billion, and Safe Harbour expansion room to
approximately $2.0 billion. Sound's higher oil weighting, synergy with many of
Advantage's core properties and significant undeveloped land holdings of
approximately 400,000 net undeveloped acres will further enhance the operating
platform of Advantage.Overview
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Cash provided
by operating
activities
($000) $ 83,366 $ 65,495 27% $ 249,132 $ 229,087 9%
Funds from
operations
($000) $ 80,519 $ 62,737 28% $ 271,143 $ 214,758 26%
per Trust
Unit(1) $ 0.58 $ 0.59 (2)% $ 2.22 $ 2.63 (16)%
Net income
(loss) ($000) $ 13,795 $ 8,736 58% $ (7,535)$ 49,814 (115)%
per Trust Unit
- Basic $ 0.10 $ 0.08 25% $ (0.06)$ 0.62 (110)%
- Diluted $ 0.10 $ 0.08 25% $ (0.06)$ 0.61 (110)%
(1) Based on Trust Units outstanding at each distribution record date.Cash provided by operating activities increased 27%, funds from
operations increased 28%, and funds from operations per Trust Unit modestly
decreased 2% for the three months ended December 31, 2007, as compared to the
same period of 2006. For the year ended December 31, 2007, cash provided by
operating activities increased 9%, funds from operations increased 26%, and
funds from operations per Trust Unit decreased 16%. Cash provided by operating
activities and funds from operations for the quarter and year were positively
impacted by increased revenues due to additional production from the Sound
acquisition and the year was further impacted by a full year of production
from the Ketch acquisition that closed in 2006. Funds from operations per
Trust Unit decreased during the periods due to a higher average number of
Trust Units outstanding. The weighted average number of Trust Units has
increased 32% for the three months and 48% for the year ended in 2007 compared
to 2006, mainly due to the Sound acquisition, the Trust Unit financing in the
first quarter of 2007 and the distribution reinvestment plan. When compared to
the third quarter of 2007, funds from operations increased 29% due to
production increases of 17% from the acquisition of Sound and stronger
commodity prices. Natural gas prices, excluding hedging, increased 11% and
crude oil and NGL prices, excluding hedging, increased 6% for the fourth
quarter of 2007 as compared to the prior quarter. The Fund also realized net
derivative gains of $5.2 million in the three months and $18.6 million for the
year ended December 31, 2007 which also helped to strengthen cash provided by
operating activities and funds from operations.
Net income for the quarter increased 58% over prior year due to higher
crude oil prices and higher production from the Sound acquisition, offset
somewhat by higher costs from the acquisition and general growth of the Fund.
Net income for the year decreased to a net loss for the twelve months ended
December 31, 2007 primarily due to higher operating costs, as well as non-cash
expenses such as amortization of the management contract internalization and
higher depletion and depreciation expense. The primary factor that causes
significant variability of Advantage's cash provided by operating activities,
funds from operations, and net income is commodity prices. Refer to the
section "Commodity Prices and Marketing" for a more detailed discussion of
commodity prices and our price risk management.Distributions
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Distributions
declared ($000) $ 57,875 $ 58,791 (2)% $ 215,194 $ 217,246 (1)%
per Trust
Unit (1) $ 0.42 $ 0.56 (25)% $ 1.77 $ 2.66 (33)%
(1) Based on Trust Units outstanding at each distribution record date.Total distributions declared decreased 2% for the three months and 1% for
the year ended December 31, 2007 when compared to the same periods in 2006.
Total distributions declared are slightly lower as a result of the decreases
in the distribution per Trust Unit in January and December 2007. The decreases
in per Trust Unit distributions are offset by additional distributions due to
the increased Trust Units outstanding from the continued growth and
development of the Fund. Since natural gas prices were very weak during the
2006/2007 winter season, we reduced the distribution level in January 2007 and
as natural gas prices continued to show prolonged weakness throughout 2007, we
decreased the distribution level further in December 2007 to more
appropriately reflect the current commodity price environment. Distributions
per Trust Unit were $0.42 for the three months and $1.77 for the year ended
December 31, 2007, representing a decrease of 25% and 33% from same periods in
2006. The monthly distribution is currently $0.12 per Trust Unit. To mitigate
the persisting risk associated with lower commodity prices and the resulting
negative impact on cash flows, the Fund implemented a hedging program with 51%
of natural gas production and 38% of crude oil production, net of royalties,
hedged for 2008. See "Commodity Price Risk" section for a more detailed
discussion of our price risk management.
Distributions from the Fund to Unitholders are entirely discretionary and
are determined by Management and the Board of Directors. We closely monitor
our distribution policy considering forecasted cash flows, optimal debt
levels, capital spending activity, taxability to Unitholders, working capital
requirements, and other potential cash expenditures. Distributions are
announced monthly and are based on the cash available after retaining a
portion to meet such spending requirements. The level of distributions are
primarily determined by cash flows received from the production of oil and
natural gas from existing Canadian resource properties and 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.
For Canadian and U.S. holders of Advantage Trust Units, the distributions
paid for 2007 were 100% taxable. All Unitholders of the Fund are encouraged to
consult their tax advisors as to the proper treatment of Advantage
distributions for income tax purposes.Revenue
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Natural gas
excluding
hedging $ 73,662 $ 74,309 (1)% $ 286,777 $ 231,548 24%
Realized hedging
gains 8,762 4,046 117% 20,933 4,164 403%
-------------------------------------------------------------------------
Natural gas
including
hedging $ 82,424 $ 78,355 5% $ 307,710 $ 235,712 31%
-------------------------------------------------------------------------
Crude oil and
NGLs excluding
hedging $ 87,079 $ 48,051 81% $ 251,987 $ 182,882 38%
Realized
hedging gains
(losses) (3,552) 1,133 (414)% (2,339) 1,133 (306)%
-------------------------------------------------------------------------
Crude oil and
NGLs including
hedging $ 83,527 $ 49,184 70% $ 249,648 $ 184,015 36%
-------------------------------------------------------------------------
Total revenue $165,951 $127,539 30% $ 557,358 $ 419,727 33%
-------------------------------------------------------------------------Natural gas revenues, excluding hedging, have decreased 1% for the three
months and increased 24% for the year ended December 31, 2007, compared to
2006. The decrease in natural gas revenues for the three months is mainly due
to a 10% decrease in natural gas prices, excluding hedging, offset by an
equivalent 10% increase in production, primarily from the Sound acquisition.
Conversely, the increase in natural gas revenues for the 2007 year is mainly
due to the inclusion of a full year of production from the Ketch merger that
closed in 2006 and production from the Sound acquisition since September 5,
2007, while natural gas prices remained fairly constant. Crude oil and NGL
revenues, excluding hedging, have increased by 81% for the three months and
38% for the year ended December 31, 2007, compared to 2006. Crude oil and NGL
revenue increased due to additional production from the Sound acquisition and
the inclusion of a full year of production from the Ketch merger combined with
an increase in crude oil and NGL prices of 34% for the three months and 6% for
the year ended December 31, 2007. For the three months and year ended
December 31, 2007, the Fund recognized natural gas and crude oil net hedging
gains of $5.2 million and $18.6 million primarily due to derivative contracts
in place that offset commodity prices fluctuations which can jeopardize
revenues and corresponding distributions.Production
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Natural gas
(mcf/d) 128,556 117,134 10% 116,998 94,074 24%
Crude oil
(bbls/d) 10,410 7,148 46% 8,090 6,273 29%
NGLs (bbls/d) 2,485 2,422 3% 2,372 1,802 32%
-------------------------------------------------------------------------
Total (boe/d) 34,321 29,092 18% 29,962 23,754 26%
-------------------------------------------------------------------------
Natural gas (%) 63% 67% 65% 66%
Crude oil (%) 30% 25% 27% 26%
NGLs (%) 7% 8% 8% 8%The Fund's total daily production averaged 34,321 boe/d for the three
months and 29,962 boe/d for the year ended December 31, 2007, an increase of
18% and 26%, respectively, compared with the same periods of 2006. Natural gas
production increased 10%, crude oil production increased 46%, and NGLs
production increased 3% for the fourth quarter of 2007. For the year ended
December 31, 2007, natural gas production increased 24%, crude oil production
increased 29%, and NGLs production increased 32%. Production for the quarter
increased due to the additional properties from the Sound acquisition. The
increase in production for the year ended December 31, 2007 has been primarily
attributed to a full year of production from the Ketch acquisition which
closed June 23, 2006 and production from the Sound acquisition which closed
September 5, 2007. Production for the fourth quarter increased 17% from the
third quarter of 2007 also due to a full quarter of production from the
acquisition of Sound.
Our successful first quarter 2007 drilling program at Martin Creek,
followed by continued success at Sunset, Nevis, Willesden Green, as well as
other areas in Southern Alberta and Saskatchewan throughout the year has
helped offset natural declines. In addition, our flattening production
platform, resulting from our continued focus on long life assets, is
contributing to a stable operating foundation. For 2008 we expect production
to average approximately 32,000 to 34,000 boe/d, weighted 62% to natural gas.
Approximately 55% of our capital spending will be directed to natural gas and
45% toward light oil projects which will enable us to increase our crude oil
production and capitalize on the stronger crude oil pricing environment.Commodity Prices and Marketing
Natural Gas
Three months ended Year ended
December 31 December 31
($/mcf) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Realized natural
gas prices
Excluding
hedging $ 6.23 $ 6.90 (10)% $ 6.72 $ 6.74 -
Including
hedging $ 6.97 $ 7.27 (4)% $ 7.21 $ 6.86 5%
AECO monthly
index $ 6.00 $ 6.36 (6)% $ 6.61 $ 6.98 (5)%Realized natural gas prices, excluding hedging, decreased 10% for the
three months and remained constant for the year ended December 31, 2007, as
compared to 2006. The price of natural gas is primarily based on supply and
demand fundamentals in the North American marketplace; however market
speculation activity has increased price volatility. Natural gas prices
declined for the current quarter and continued to remain weak for the entire
2007 year, as in 2006, due to exceedingly high storage levels, mild summer and
winter weather and a lack of storm activity in the Gulf of Mexico. Fourth
quarter natural gas inventory levels remained well above average, causing
continued downward pressure on commodity prices. However, early 2008 has
brought colder weather and significant inventory withdrawals have been
experienced, resulting in a rebound of natural gas prices. Natural gas storage
levels are now closer to expectation and only slightly above the five-year
average. In addition, there has been a tighter supply of natural gas, putting
further upward pressure on prices. These developments have been encouraging
and we continue to believe that the long-term pricing fundamentals for natural
gas remain strong. These fundamentals include (i) the continued strength of
crude oil prices, which has eliminated the economic advantage of fuel
switching away from natural gas evidenced by the increase in proposed gas
fired electrical generation facilities, (ii) significantly less natural gas
drilling in Canada projected for 2008, which will reduce productivity to
offset declines, (iii) the increasing focus on resource style natural gas
wells, which have high initial declines and require a higher threshold
economic price than conventional gas drilling and (iv) the demand for natural
gas for the Canadian oil sands projects.Crude Oil and NGLs
Three months ended Year ended
December 31 December 31
($/bbl) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Realized crude
oil prices
Excluding
hedging $ 74.19 $ 56.10 32% $ 67.71 $ 63.85 6%
Including
hedging $ 70.48 $ 57.82 22% $ 66.92 $ 64.34 4%
Realized NGLs
prices
Excluding
hedging $ 70.09 $ 50.09 40% $ 60.12 $ 55.81 8%
Realized crude
oil and NGLs
prices
Excluding
hedging $ 73.40 $ 54.58 34% $ 65.99 $ 62.05 6%
Including
hedging $ 70.40 $ 55.86 26% $ 65.38 $ 62.44 5%
WTI ($US/bbl) $ 90.63 $ 60.21 51% $ 72.37 $ 66.35 9%
$US/$Canadian
exchange rate $ 1.02 $ 0.88 16% $ 0.94 $ 0.88 7%Realized crude oil and NGLs prices, excluding hedging, increased 34% for
the three months and 6% for the year ended December 31, 2007, as compared to
the same periods of 2006. Advantage's crude oil prices are based on the
benchmark pricing of West Texas Intermediate Crude ("WTI") adjusted for
quality, transportation costs and $US/$Canadian exchange rates. For the three
months and year ended December 31, 2007, WTI increased 51% and 9%,
respectively, with momentous increases experienced in the fourth quarter of
2007. Advantage's realized crude oil price has not changed to the same extent
as WTI due to the strengthening of the Canadian dollar relative to the US
dollar and widened Canadian crude oil differentials relative to WTI. The price
of WTI fluctuates based on worldwide supply and demand fundamentals. There has
been significant price volatility experienced over the last several years
whereby WTI has reached historic high levels. Many developments have resulted
in the current price levels, including significant continuing geopolitical
issues and general market speculation. In fact, the impact of market
fundamentals has diminished as geopolitical events and speculation has
prevailed. As a result, prices have remained strong throughout 2007 and into
early 2008. With the current high price levels, it is notable that demand has
remained resilient even as the United States, the world's largest crude oil
consumer, experiences an economic slowdown. Regardless whether the current
price level is sustainable or just a short-term anomaly, we believe that the
pricing fundamentals for crude oil remain strong with many factors affecting
the continued strength including (i) supply management and supply restrictions
by the OPEC cartel, (ii) ongoing civil unrest in Venezuela, Nigeria, and the
Middle East, (iii) strong world wide demand, particularly in China, India and
the United States and (iv) North American refinery capacity constraints.
Commodity Price Risk
The Fund's operational results and financial condition will be dependent
on the prices received for oil and natural gas production. Oil and natural gas
prices have fluctuated widely during recent years and are determined by
economic and, in the case of oil prices, political factors. Supply and demand
factors, including weather and general economic conditions as well as
conditions in other oil and natural gas regions, impact prices. Any movement
in oil and natural gas prices could have an effect on the Fund's financial
condition and therefore on the distributions to holders of Advantage Trust
Units. As current and future practice, Advantage has established a financial
hedging strategy and may manage the risk associated with changes in commodity
prices by entering into derivatives. These commodity price risk management
activities could expose Advantage to losses or gains. To the extent that
Advantage engages in risk management activities related to commodity prices,
it will be subject to credit risk associated with counterparties with which it
contracts. Credit risk is mitigated by entering into contracts with only
stable, creditworthy parties and through frequent reviews of exposures to
individual entities.
We have been active in entering new financial contracts to protect future
cash flows and currently the Fund has the following derivatives in place:Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas -
AECO
Fixed price November 2007
to March 2008 7,109 mcf/d Cdn$9.54/mcf
Fixed price April 2008 to
October 2008 14,217 mcf/d Cdn$6.85/mcf
Fixed price April 2008 to
October 2008 9,478 mcf/d Cdn$7.25/mcf
Fixed price April 2008 to
October 2008 14,217 mcf/d Cdn$7.83/mcf
Fixed price April 2008 to
March 2009 14,217 mcf/d Cdn$7.10/mcf
Fixed price April 2008 to
March 2009 14,217 mcf/d Cdn$7.06/mcf
Fixed price November 2008
to March 2009 14,217 mcf/d Cdn$7.77/mcf
Fixed price November 2008
to March 2009 4,739 mcf/d Cdn$8.10/mcf
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
Fixed price February 2008
to January 2009 2,000 bbls/d Cdn$90.93/bbl
Fixed price April 2008 to
March 2009 2,500 bbls/d Cdn$97.15/bbl
Collar February 2008
to January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl
Purchased
call Cdn$105.00/bbl
Cost Cdn$1.52/bblAs at December 31, 2007 the fair value of the derivatives outstanding was
a net asset of approximately $2.2 million. For the year ended December 31,
2007, $11.0 million was recognized in income as an unrealized derivative loss
due to changes in the fair value and settlement of such contracts since
December 31, 2006. For the same period we recognized in income a realized
derivative gain of $18.6 million upon the settlement of these financial
contracts, which partially alleviated lower revenue from continued weak
natural gas prices. As a result of the Sound acquisition, the Fund assumed
several derivatives which had an estimated net fair value on closing of
$2.8 million. The change in fair value of these derivatives since acquisition
to the end of the period has been recognized in income as an unrealized
derivative gain or loss. The valuation of the derivatives is the estimated
fair value to settle the contracts as at December 31, 2007 and is based on
pricing models, estimates, assumptions and market data available at that time.
The actual gain or loss realized on eventual cash settlement can vary
materially due to subsequent fluctuations in commodity prices as compared to
the valuation assumptions. The Fund does not apply hedge accounting and
current accounting standards require changes in the fair value to be included
in the consolidated statement of income and comprehensive income as an
unrealized derivative gain or loss with a corresponding derivative asset and
liability recorded on the balance sheet.
The Fund has fixed the commodity price on anticipated production as
follows:Approximate
Production Hedged, Average Average
Commodity Net of Royalties Floor Price Ceiling Price
-------------------------------------------------------------------------
Natural gas - AECO
January to March 2008 22% Cdn$8.85/mcf Cdn$10.19/mcf
April to June 2008 66% Cdn$7.22/mcf Cdn$7.22/mcf
July to September 2008 64% Cdn$7.22/mcf Cdn$7.22/mcf
October to December 2008 53% Cdn$7.32/mcf Cdn$7.32/mcf
-----------------------------------------------------------------------
Total 2008 51% Cdn$7.43/mcf Cdn$7.58/mcf
-----------------------------------------------------------------------
January to March 2009 46% Cdn$7.39/mcf Cdn$7.39/mcf
Crude Oil - WTI
January to March 2008 13% Cdn$90.93/bbl Cdn$90.93/bbl
April to June 2008 47% Cdn$94.39/bbl Cdn$94.39/bbl
July to September 2008 46% Cdn$94.39/bbl Cdn$94.39/bbl
October to December 2008 46% Cdn$94.39/bbl Cdn$94.39/bbl
-----------------------------------------------------------------------
Total 2008 38% Cdn$94.07/bbl Cdn$94.07/bbl
-----------------------------------------------------------------------
January to March 2009 32% Cdn$95.84/bbl Cdn$95.84/bbl
Royalties
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Royalties, net
of Alberta
Royalty Credit
($000) $ 27,099 $ 23,349 16% $ 98,614 $ 76,456 29%
per boe $ 8.58 $ 8.72 (2)% $ 9.02 $ 8.82 2%
As a percentage
of revenue,
excluding
hedging 16.9% 19.1% (2.2)% 18.3% 18.4% (0.1)%Advantage pays royalties to the owners of mineral rights from which we
have leases. The Fund currently has mineral leases with provincial
governments, individuals and other companies. Royalties for 2006 are shown net
of the Alberta Royalty Credit, which was a royalty rebate provided by the
Alberta government to certain producers and was eliminated effective
January 1, 2007. Royalties have increased in total for the 2007 periods due to
the increase in revenue from higher production related to acquisitions but
remains comparable on a per boe basis. Royalties as a percentage of revenue,
excluding hedging, remained consistent for the year as compared to 2006 but
decreased in the fourth quarter of 2007 due to the lower natural gas prices
experienced by Advantage during the last six months of the year. We expect the
royalty rate to be in the range of 17% to 19% for 2008 given the current
environment.
On October 25, 2007, the Alberta Provincial Government announced changes
to royalties for conventional oil, natural gas and oil sands that will become
effective January 1, 2009. Given the methodology used in the new royalty
regime, royalties and as a result, cash flows will be affected by depths and
productivity of wells. In addition, royalties are price sensitive with higher
royalty levels applying when commodity prices are higher. A review of the
initial information released by the Alberta Provincial Government indicates
that lower rate natural gas wells will see a benefit of lower royalties while
conventional oil will be subject to an increase in royalties but is again less
punitive at lower rates. Commodity prices and individual well production rates
are both key factors in the calculation. The majority of Advantage's
production in Alberta comes from lower rate wells due to well-established
large, long life properties. In addition, we have a significant presence in
British Columbia and Saskatchewan. Therefore, early indications are that the
impact may not be significant based on our current production and the current
commodity price environment. Advantage continues to analyze the impact of the
decision and will take the new royalty regime into consideration in preparing
future development projects. Project economics are evaluated taking into
consideration all relevant factors including the new royalty regime given the
commodity pricing environment anticipated. Those projects that maximize return
to Advantage Unitholders will continue to be selected for development.Operating Costs
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Operating costs
($000) $ 39,330 $ 27,803 41% $ 127,309 $ 82,911 54%
per boe $ 12.46 $ 10.39 20% $ 11.64 $ 9.56 22%Total operating costs increased 41% for the three months and 54% for the
year ended December 31, 2007 as compared to 2006, mainly due to increased
production from the Ketch acquisition which was completed June 23, 2006 and
the Sound acquisition, which closed on September 5, 2007. Operating costs per
boe increased 20% for the three months and 22% for the year ended December 31,
2007, mainly due to lower production levels related to third party turnaround
activity, an extended spring break-up, increased service and supply costs as
the industry experienced overall cost increases, and higher relative operating
costs from recent acquisitions. However, fourth quarter 2007 per boe operating
costs came in modestly lower than our expectation of $12.50 to $13.50, due to
optimization initiatives put in place by the Fund in 2007. We will continue to
be opportunistic and proactive in pursuing programs that will improve our
operating cost structure. Consistent with this strategy, the Fund entered
hedges for power costs, one of our more significant operating costs, of 3.0 MW
at $54.00/MWh for 2008. We expect that operating costs per boe will be in the
range of $12.50 to $13.30 for the 2008 year.General and Administrative
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
General and
administrative
expense ($000) $ 7,173 $ 4,586 56% $ 21,449 $ 13,738 56%
per boe $ 2.27 $ 1.71 33% $ 1.96 $ 1.58 24%
Employees at
December 31 172 135 27%General and administrative ("G&A") expense has increased 56% for the
three months and year ended December 31, 2007, as compared to 2006. G&A per
boe increased 33% for the three months and 24% for the year when compared to
the same periods of 2006. G&A expense for the year ended December 31, 2007 has
increased overall and per boe primarily due to an increase in staff levels
that have resulted from the Ketch and Sound acquisitions and general 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, including unit-
based compensation, which 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.
Current employee compensation includes salary, benefits, a short-term
incentive plan and a long-term incentive plan. The long-term incentive plan
consists of a Restricted Trust Unit Plan (the "Plan"), as approved by the
Unitholders on June 23, 2006, and Trust Units issuable for the retention of
certain employees of the Fund. The purpose of the long-term compensation plans
is to retain and attract employees, to reward and encourage performance, and
to focus employees on operating and financial performance that results in
lasting Unitholder return.
The Plan authorizes the Board of Directors to grant Restricted Trust
Units ("RTUs") to directors, officers, or employees of the Fund. The number of
RTUs granted is based on the Fund's Trust Unit return for a calendar year and
compared to a peer group approved by the Board of Directors. The Trust Unit
return is calculated at the end of the year and is primarily based on the
year- over-year change in the Trust Unit price plus distributions. The RTU
grants vest one third immediately on grant date, with the remaining two thirds
vesting evenly on the following two yearly anniversary dates. The holders of
RTUs may elect to receive cash upon vesting in lieu of the number of Trust
Units to be issued, subject to consent of the Fund. Compensation cost related
to the Plan is based on the "fair value" of the RTUs at the grant date and is
recognized as compensation expense over the service period. This valuation
incorporates the period end Trust Unit price, the estimated number of RTUs to
vest, and certain management estimates. The maximum fair value of RTUs granted
in any one calendar year is limited to 175% of the base salaries of those
individuals participating in the Plan for such period. As the Fund did not
meet the 2007 or 2006 grant thresholds, there were no RTU grants made during
these years and no related compensation expense has been recognized.
For the year ended December 31, 2007, the Fund has accrued unit-based
compensation expense of $0.9 million in general and administrative expense and
has capitalized $0.3 million related to Trust Units issuable for the retention
of certain employees of the Fund.Management Fee, Performance Incentive, and Management Internalization
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Management
fee ($000) $ - $ - - $ - $ 887 (100)%
per boe $ - $ - - $ - $ 0.10 (100)%
Performance
incentive
($000) $ - $ - - $ - $ 2,380 (100)%
Management
internalization
($000) $ 2,534 $ 5,497 (54)% $ 15,708 $ 13,449 17%Prior to the Ketch merger, the Manager received both a management fee and
a performance incentive fee as compensation pursuant to the Management
Agreement approved by the Board of Directors. As a condition of the merger
with Ketch, the Fund and the Manager reached an agreement to internalize the
management contract arrangement. As part of the agreement, Advantage agreed to
purchase all of the outstanding shares of the Manager pursuant to the terms of
the Arrangement, thereby eliminating the management fee and performance
incentive effective April 1, 2006. The Trust Unit consideration issued in
exchange for the outstanding shares of the Manager was placed in escrow for a
3-year period and is being deferred and amortized into income as management
internalization expense over the specific vesting periods during which
employee services are provided. The management internalization is lower for
the quarter since one third vested and was paid in June 2007 while two thirds
remains outstanding.Interest
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Interest expense
($000) $ 7,917 $ 5,414 46% $ 24,351 $ 18,258 33%
per boe $ 2.51 $ 2.02 24% $ 2.23 $ 2.11 6%
Average effective
interest rate 6.2% 5.5% 0.7% 5.7% 5.1% 0.6%
Bank indebtedness
at December 31
($000) $ 547,426 $ 410,574 33%
Interest expense has increased 46% for the three months and 33% for the
year ended December 31, 2007, as compared to 2006. Interest expense per boe
has increased 24% for the three months and 6% for the year ended December 31,
2007. The increase in total interest expense is primarily attributable to a
higher average debt level associated with the growth of the Fund, an increase
in the average effective interest rates and increased bank indebtedness
assumed on the Ketch and Sound acquisitions. We monitor the debt level to
ensure an optimal mix of financing and cost of capital that will provide a
maximum return to Unitholders. Our current credit facilities have been a
favorable financing alternative with an effective interest rate of only 5.7%
for the year ended December 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 Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Interest on
convertible
debentures
($000) $ 4,426 $ 3,289 35% $ 14,867 $ 11,210 33%
per boe $ 1.40 $ 1.23 14% $ 1.36 $ 1.29 5%
Accretion on
convertible
debentures
($000) $ 721 $ 604 19% $ 2,569 $ 2,106 22%
per boe $ 0.23 $ 0.23 - $ 0.23 $ 0.24 (4)%
Convertible
debentures
maturity
value at
December 31
($000) $ 224,612 $ 180,730 24%
Interest on convertible debentures has increased 35% for the three months
and 33% for the year ended December 31, 2007, as compared to 2006. Accretion
on convertible debentures has increased 19% for the three months and 22% for
the year ended December 31, 2007. The increases in total interest and
accretion are due to Advantage assuming Sound's 8.75% and 8.00% convertible
debentures and Ketch's 6.50% convertible debentures in the 2006 merger. The
increased interest and accretion from the additional debentures has been
slightly offset due to the exchange of convertible debentures to Trust Units
during 2006 that pay distributions rather than interest. Interest per boe for
the quarter is higher as our convertible debentures outstanding have slightly
increased relative to our level of production.
Cash Netbacks
Three months ended
December 31
2007 2006
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 160,741 $ 50.91 $ 122,360 $ 45.72
Realized gain on
derivatives 5,210 1.65 5,179 1.93
Royalties, net of
Alberta Royalty
Credit (27,099) (8.58) (23,349) (8.72)
Operating costs (39,330) (12.46) (27,803) (10.39)
-------------------------------------------------------------------------
Operating $ 99,522 $ 31.52 $ 76,387 $ 28.54
General and
administrative(1) (7,029) (2.23) (4,586) (1.71)
Management fee - - - -
Interest (7,917) (2.51) (5,414) (2.02)
Interest on
convertible
debentures(1) (3,536) (1.12) (3,289) (1.23)
Income and capital
taxes (521) (0.16) (361) (0.13)
-------------------------------------------------------------------------
Funds from operations $ 80,519 $ 25.50 $ 62,737 $ 23.45
-------------------------------------------------------------------------
Cash Netbacks
Year ended
December 31
2007 2006
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 538,764 $ 49.27 $ 414,430 $ 47.80
Realized gain on
derivatives 18,594 1.70 5,297 0.61
Royalties, net of
Alberta Royalty
Credit (98,614) (9.02) (76,456) (8.82)
Operating costs (127,309) (11.64) (82,911) (9.56)
-------------------------------------------------------------------------
Operating $ 331,435 $ 30.31 $ 260,360 $ 30.03
General and
administrative(1) (20,520) (1.88) (13,738) (1.58)
Management fee - - (887) (0.10)
Interest (24,351) (2.23) (18,258) (2.11)
Interest on
convertible
debentures(1) (13,977) (1.28) (11,210) (1.29)
Income and capital
taxes (1,444) (0.13) (1,509) (0.17)
-------------------------------------------------------------------------
Funds from operations $ 271,143 $ 24.79 $ 214,758 $ 24.78
-------------------------------------------------------------------------
(1) General and administrative expense and interest on convertible
debentures exclude unit-based compensation and non-cash interest
expense.Funds from operations of Advantage for the quarter ended December 31,
2007 increased to $80.5 million from $62.7 million in the prior year. Funds
from operations for the year ended December 31, 2007 increased to
$271.1 million from $214.8 million compared to 2006. The cash netback per boe
for the three months ended December 31, 2007 increased 9% from $23.45 to
$25.50 for the quarter, but remained comparable for the year ended December
31, 2007. The higher cash netback per boe for the three months ended December
31, 2007 is primarily due to higher revenues, resulting from additional
production from the accretive Sound acquisition and strong oil prices offset
somewhat by lower natural gas prices as well as higher operating and general
and administrative costs. Operating costs have steadily increased over the
past year due to significantly higher field costs associated with supplies and
services that have resulted from the high level of industry activity, an
overall industry labour cost increase, and higher relative operating costs
from recent acquisitions. However, it is noteworthy that due to several of our
initiatives this year, operating costs for the quarter were less than
anticipated. The increased general and administrative costs are due to higher
staff levels and general growth of the Fund. When compared to the third
quarter of 2007, funds from operations per boe increased 10%, again mainly due
to the acquisition of Sound.Depletion, Depreciation and Accretion
Three months ended Year ended
December 31 December 31
2007 2006 % change 2007 2006 % change
-------------------------------------------------------------------------
Depletion,
depreciation
& accretion
($000) $ 78,149 $ 63,521 23% $272,175 $194,309 40%
per boe $ 24.75 $ 23.73 4% $ 24.89 $ 22.41 11%Depletion and depreciation of fixed assets is provided on the
"unit-of-production" method based on total proved reserves. Accretion
represents the increase in the asset retirement obligation liability each
reporting period due to the passage of time. The depletion, depreciation and
accretion ("DD&A") provision has increased 23% for the three months and 40%
for the year ended December 31, 2007. The higher DD&A is due to considerable
increases in daily production volumes, mainly from the Ketch and Sound
acquisitions and the increase in the DD&A rate per boe compared to the prior
year. The increased DD&A rate per boe was due to a higher valuation assigned
for reserves from recent acquisitions than accumulated from prior acquisitions
and development activities. We evaluate the recoverability of our petroleum
and natural gas assets each reporting period to ensure the carrying amount
does not exceed the fair value. When the carrying amount is not assessed to be
recoverable, an impairment loss is recognized. There has been no impairment of
the Fund's petroleum and natural gas properties under Canadian GAAP since
inception.
Taxes
Current taxes paid or payable for the quarter ended December 31, 2007
amounted to $0.5 million, comparable to the $0.4 million expensed for the same
period of 2006. The higher current taxes are due to the increased Saskatchewan
properties and activity within these properties from the Ketch and Sound
acquisitions. Current taxes primarily represent Saskatchewan resource
surcharge, which is based on the petroleum and natural gas revenues within the
province of Saskatchewan.
Future income taxes arise from differences between the accounting and tax
bases of the assets and liabilities. For the year ended December 31, 2007, the
Fund recognized a future income tax reduction of $24.6 million compared to
$37.1 million for 2006. Under the Fund's current structure, payments are made
between the operating company and the Fund transferring income tax obligations
to Unitholders and as a result no cash income taxes would be paid by the
operating company or the Fund prior to 2011. However, the Specified Investment
Flow-Through Entity ("SIFT") tax legislation was enacted on June 22, 2007
altering the tax treatment by subjecting income trusts to a two-tier tax
structure, similar to that of corporations, whereby the taxable portion of
distributions paid by trusts will be subject to tax at the trust level and at
the Unitholder level. The rules are effective for tax years beginning in 2011
for existing publicly-traded trusts. The impact of the new tax law is
reflected in 2007 and resulted in an additional future income tax expense of
$42.9 million. As at December 31, 2007, we had a future income tax liability
balance of $66.7 million, compared to $61.9 million at December 31, 2006.
Canadian generally accepted accounting principles require that a future income
tax liability be recorded when the book value of assets exceeds the balance of
tax pools. It further requires that a future tax liability be recorded on an
acquisition when a corporation acquires assets with associated tax pools that
are less than the purchase price. As a result of the Sound acquisition,
Advantage recorded a future tax liability of $29.4 million.
On December 14, 2007, the Federal government enacted legislation phasing
in corporate income tax rate reductions which will reduce federal tax rates
from 22.1% to 15.0% by 2012. Rate reductions will also apply to the new tax on
distributions of income trusts and other specified investment flow-through
entities as of 2011, reducing the tax rate in 2011 to 29.5% and in 2012 to
28.0%. These rates include a deemed provincial rate of 13%.
The Fund has approximately $1.7 billion in tax pools and deductions at
December 31, 2007, which can be used to reduce the amount of taxes paid by
Advantage. The Fund and Advantage Oil & Gas Ltd. ("AOG") had the following
estimated tax pools in place at December 31, 2007:December 31, 2007
Estimated Tax Pools
($ millions)
------------
Undepreciated Capital Cost $ 641
Canadian Oil and Gas Property Expenses 462
Canadian Development Expenses 435
Canadian Exploration Expenses 65
Non-capital losses 76
Other 25
------------
$ 1,704
------------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 2008 2009 2010 2011 2012
-------------------------------------------------------------------------
Building leases $ 16.6 $ 5.3 $ 4.1 $ 4.1 $ 1.8 $ 1.3
Capital leases 8.1 1.9 2.1 2.2 1.9 -
Pipeline/transportation 6.0 4.4 1.3 0.3 - -
Convertible debentures(1) 224.6 5.4 87.0 69.9 62.3 -
-------------------------------------------------------------------------
Total contractual
obligations $255.3 $ 17.0 $ 94.5 $ 76.5 $ 66.0 $ 1.3
-------------------------------------------------------------------------
(1) As at December 31, 2007, Advantage had $224.6 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 $547.4 million has been excluded from the
contractual obligations table as the credit facilities constitute a
revolving facility for a 364 day term which is extendible annually
for a further 364 day revolving period at the option of the
syndicate. If not extended, the revolving credit facility is
converted to a two year term facility with the first payment due one
year and one day after commencement of the term.
Liquidity and Capital Resources
The following table is a summary of the Fund's capitalization structure.
($000, except as otherwise indicated) December 31, 2007
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 547,426
Working capital deficit(1) 28,087
-------------------------------------------------------------------------
Net debt $ 575,513
-------------------------------------------------------------------------
Trust Units outstanding (000) 138,269
Trust Unit closing market price ($/Trust Unit) $ 8.73
-------------------------------------------------------------------------
Market value $ 1,207,088
-------------------------------------------------------------------------
Capital lease obligations (long-term) $ 5,653
Convertible debentures maturity value (long-term) 219,220
-------------------------------------------------------------------------
Total capitalization $ 2,007,474
-------------------------------------------------------------------------
(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 December 31, 2007, the Fund had 138.3 million Trust Units
outstanding. On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus
an additional 800,000 Trust Units upon exercise of the Underwriters'
over-allotment option on March 7, 2007, at $12.80 per Trust Unit for
approximate net proceeds of $104.1 million (net of Underwriters' fees and
other issue costs of $6.0 million). The net proceeds of the offering were used
to pay down bank indebtedness and to subsequently fund capital and general
corporate expenditures. On September 5, 2007, Advantage issued 16,977,184
Trust Units as partial consideration for the acquisition of Sound. As at March
5, 2008, Advantage had 139.0 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
year ended December 31, 2007, 4,028,252 Trust Units were issued as a result of
the Plan, generating $46.7 million reinvested in the Fund and representing an
approximate 18% participation rate.
As at December 31, 2007, the Fund had $224.6 million convertible
debentures outstanding that were convertible to 9.8 million Trust Units based
on the applicable conversion prices. During the year ended December 31, 2007,
$24,000 debentures were converted resulting in the issuance of 1,386 Trust
Units and all of the remaining $1,470,000 10% convertible debentures matured
on November 1, 2007 and were settled with the issuance of 127,493 Trust Units.
Due to the acquisition of Sound, $59,513,000 8.75% and $41,035,000 8.00%
convertible debentures were assumed by Advantage on September 5, 2007. As a
result of the change in control of Sound, the Fund was required by the
debenture indentures to make an offer to purchase all of the outstanding
convertible debentures assumed from Sound as at a price equal to 101% of the
principal amount plus accrued and unpaid interest. On October 17, 2007, the
expiry date of the offer, 911,709 Trust Units were issued and $19.9 million in
total cash consideration was paid in exchange for $29,665,000 8.75%
convertible debentures and 2,220,289 Trust Units were issued in exchange for
$25,507,000 8.00% convertible debentures. As at March 5, 2008, the convertible
debentures have not changed from December 31, 2007.
Effective June 25, 2002, a Trust Units Rights Incentive Plan for external
directors of the Fund was established and approved by the Unitholders of
Advantage. A total of 500,000 Trust Units have been reserved for issuance
under the plan with an aggregate of 400,000 rights granted since inception.
The initial exercise price of rights granted under the plan may not be less
than the current market price of the Trust Units as of the date of the grant
and the maximum term of each right is not to exceed ten years with all rights
vesting immediately upon grant. At the option of the rights holder, the
exercise price of the rights can be adjusted downwards over time based upon
distributions paid by the Fund to Unitholders. In exchange for an equivalent
number of Trust Units, 37,500 Series B Trust Unit Rights were exercised in the
second quarter of 2007. As at March 5, 2008, 150,000 Series B Trust Unit
Rights remain outstanding.
As a result of the new SIFT tax legislation, an income trust is permitted
to double its market capitalization as it stands on October 31, 2006 by
growing a maximum of 40% in 2007 and 20% for the years 2008 to 2010. Any
unused expansion from the prior year can be brought forward into the following
year until the new tax rules take effect. In addition, an income trust may
replace debt that was outstanding as of October 31, 2006 with new equity or
issue new, non-convertible debt without affecting the normal growth
percentage. An income trust may also merge with another income trust without a
change to their normal growth percentage, provided there is no net addition to
equity as a result of the merger. As of October 31, 2006, the Fund had an
approximate market capitalization of $1.6 billion and bank indebtedness of
$0.4 billion. Therefore, as a result of the "normal growth" guidelines, the
Fund is permitted to issue $2.0 billion of new equity from October 31, 2006 to
January 1, 2011, which we believe is adequate for any growth we expect to
incur.
Bank Indebtedness, Credit Facility and Other Obligations
At December 31, 2007, Advantage had bank indebtedness outstanding of
$547.4 million. The Fund has a $710 million credit facility agreement
consisting of a $690 million extendible revolving loan facility and a
$20 million operating loan facility. The current credit facilities are 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 December 31, 2007, Advantage had a working capital deficiency of
$28.1 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.
In the second quarter of 2007, Advantage entered a new lease arrangement
that resulted in the recognition of a fixed asset addition and capital lease
obligation of $4.1 million. The lease obligation bears interest at 5.8% and is
secured by the related equipment. The lease term expires June 2011 with a
final purchase obligation of $1.5 million at which time ownership of the
equipment will transfer to Advantage. We entered a second lease arrangement
during the third quarter of 2007 that resulted in the recognition of a fixed
asset addition and capital lease obligation of $1.8 million. This lease
obligation bears interest at 6.7% and is also secured by the related
equipment. The lease term expires August 2010 with a final payment obligation
of $0.7 million. Distributions to Unitholders are not permitted if the Fund is
in default of this capital lease.
On September 5, 2007, Advantage assumed two capital lease obligations in
the acquisition of Sound resulting in the recognition of capital lease
obligations of $1.6 million. Both of the assumed lease obligations bear
interest at 5.6% and are secured by the related equipment. The lease terms
expire December 2009 and April 2010 with a total final payment obligation of
$0.9 million.Capital Expenditures
Three months ended Year ended
December 31 December 31
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
Land and seismic $ 64 $ 522 $ 3,270 $ 5,261
Drilling, completions
and workovers 30,020 42,612 94,786 113,146
Well equipping and
facilities 9,971 17,690 48,296 39,437
Other 878 285 2,373 1,643
-------------------------------------------------------------------------
$ 40,933 $ 61,109 $ 148,725 $ 159,487
Acquisition of Sound
Energy Trust (67) - 22,307 -
Property acquisitions 3,200 46 16,051 244
Property dispositions (610) - (1,037) (8,727)
-------------------------------------------------------------------------
Total capital
expenditures $ 43,456 $ 61,155 $ 186,046 $ 151,004
-------------------------------------------------------------------------Advantage's growth strategy has been to acquire properties in or near
areas where we have large land positions, shallow to medium depth drilling
opportunities, and a balance of year round access. We focus on areas where
past activity has yielded long-life reserves with high cash netbacks. With the
integration of the Ketch and Sound assets, Advantage is very well positioned
to selectively exploit the highest value-generating drilling opportunities
given the size, strength and diversity of our asset base. As a result, the
Fund has a high level of flexibility to distribute its capital program and
ensure a risk-balanced platform of projects. Our preference is to operate a
high percentage of our properties such that we can maintain control of capital
expenditures, operations and cash flows.
For the three month period ended December 31, 2007, the Fund spent a net
$40.9 million and drilled a total of 16.6 net (32 gross) wells at a 100%
success rate. Total capital spending in the quarter included $7.1 million at
Nevis, $5.7 million at Chip Lake, $5.3 million at Martin Creek, $3.9 million
at Southeast Saskatchewan and $3.4 million at Willesden Green. For the year
ended December 31, 2007, the Fund spent a net $148.7 million and drilled a
total of 64.8 net (112 gross) wells at a 99% success rate. Total capital
spending for the year included $33.6 million at Martin Creek, $26.2 million at
Nevis, $17.5 million at Willesden Green, $10.5 million in Southeast
Saskatchewan, $8.5 million at Chip Lake, and $7.2 million at Sunset.
Property acquisitions year to date include a $12.9 million property
acquisition in the first quarter for producing properties and undeveloped land
at the Fund's core area, Nevis, and a $3.2 million property acquisition in the
Boundary Lake area during the fourth quarter. Costs of $22.3 million were
incurred related to the Sound acquisition representing the cash portion paid
due to the exercise of the cash option offered to Sound Unitholders and other
costs.
The following table summarizes the various funding requirements during
the years ended December 31, 2007 and 2006 and the sources of funding to meet
those requirements.Sources and Uses of Funds
Year ended
December 31
($000) 2007 2006
-------------------------------------------------------------------------
Sources of funds
Funds from operations $ 271,143 $ 214,758
Units issued, net of costs 104,215 141,908
Increase in bank indebtedness 28,893 -
Property dispositions 1,037 8,727
Decrease in working capital - 27,222
-------------------------------------------------------------------------
$ 405,288 $ 392,615
-------------------------------------------------------------------------
Uses of funds
Distributions to Unitholders $ 170,915 $ 185,015
Expenditures on property and equipment 148,725 159,487
Acquisition of Sound Energy Trust 22,307 -
Debentures redeemed 19,406 -
Increase in working capital 17,749 -
Property acquisitions 16,051 244
Expenditures on asset retirement 6,951 5,974
Reduction of capital lease obligations 3,184 1,019
Decrease in bank indebtedness - 30,767
Acquisition of Ketch Resources Trust - 10,109
-------------------------------------------------------------------------
$ 405,288 $ 392,615
-------------------------------------------------------------------------
Annual Financial Information
The following is a summary of selected financial information of the Fund
for the periods indicated.
Year ended Year ended Year ended
Dec. 31, Dec. 31, Dec. 31,
2007 2006 2005
-------------------------------------------------------------------------
Total revenue (before royalties)
($000) $ 557,358 $ 419,727 $ 376,572
Net income (loss) ($000) $ (7,535) $ 49,814 $ 75,072
per Trust Unit - Basic $ (0.06) $ 0.62 $ 1.33
- Diluted $ (0.06) $ 0.61 $ 1.32
Total assets ($000) $ 2,422,280 $ 1,981,587 $ 1,012,847
Long term financial liabilities
($000)(1) $ 768,060 $ 581,698 $ 379,903
Distributions declared per Trust
Unit $ 1.77 $ 2.66 $ 3.12
(1) Long term financial liabilities exclude asset retirement obligations
and future income taxes.
Quarterly Performance
2007
($000, except as
otherwise indicated) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 128,556 115,991 108,978 114,324
Crude oil and NGLs
(bbls/d) 12,895 10,014 8,952 9,958
Total (boe/d) 34,321 29,346 27,115 29,012
Average prices
Natural gas ($/mcf)
Excluding hedging $ 6.23 $ 5.62 $ 7.54 $ 7.61
Including hedging $ 6.97 $ 6.35 $ 7.52 $ 8.06
AECO monthly index $ 6.00 $ 5.62 $ 7.37 $ 7.46
Crude oil and NGLs
($/bbl)
Excluding hedging $ 73.40 $ 69.03 $ 61.84 $ 56.84
Including hedging $ 70.40 $ 68.51 $ 61.93 $ 58.64
WTI (US$/bbl) $ 90.63 $ 75.33 $ 65.02 $ 58.12
Total revenues (before
royalties) $ 165,951 $ 130,830 $ 125,075 $ 135,502
Net income (loss) $ 13,795 $ (26,202) $ 4,531 $ 341
per Trust Unit
- basic $ 0.10 $ (0.22) $ 0.04 $ 0.00
- diluted $ 0.10 $ (0.22) $ 0.04 $ 0.00
Funds from operations $ 80,519 $ 62,345 $ 62,634 $ 65,645
Distributions
declared $ 57,875 $ 55,017 $ 52,096 $ 50,206
2006
($000, except as
otherwise indicated) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 117,134 122,227 70,293 65,768
Crude oil and NGLs
(bbls/d) 9,570 9,330 6,593 6,760
Total (boe/d) 29,092 29,701 18,309 17,721
Average prices
Natural gas ($/mcf)
Excluding hedging $ 6.90 $ 5.89 $ 6.18 $ 8.69
Including hedging $ 7.27 $ 5.90 $ 6.18 $ 8.69
AECO monthly index $ 6.36 $ 6.03 $ 6.28 $ 9.31
Crude oil and NGLs
($/bbl)
Excluding hedging $ 54.58 $ 67.77 $ 68.69 $ 58.26
Including hedging $ 55.86 $ 67.77 $ 68.69 $ 58.26
WTI (US$/bbl) $ 60.21 $ 70.55 $ 70.75 $ 63.88
Total revenues (before
royalties) $ 127,539 $ 124,521 $ 80,766 $ 86,901
Net income (loss) $ 8,736 $ 1,209 $ 23,905 $ 15,964
per Trust Unit
- basic $ 0.08 $ 0.01 $ 0.38 $ 0.27
- diluted $ 0.08 $ 0.01 $ 0.38 $ 0.27
Funds from operations $ 62,737 $ 63,110 $ 42,281 $ 46,630
Distributions
declared $ 58,791 $ 60,498 $ 53,498 $ 44,459The table above highlights the Fund's performance for the fourth quarter
of 2007 and also for the preceding seven quarters. Production significantly
increased in the third quarter of 2006 as the Ketch acquisition that closed on
June 23, 2006 was fully integrated with Advantage. The second quarter of 2007
encountered a temporary production decrease as expected due to several
facility turnarounds that had been planned for that period. The third quarter
of 2007 includes the financial and operating results from the acquired Sound
properties for 26 days, and fourth quarter of 2007 includes the full
integration of the Sound properties. Advantage's revenues and funds from
operations increased significantly beginning in the third quarter of 2006
primarily due to the production from the merger with Ketch and surged again in
the fourth quarter of 2007 due to the Sound acquisition, partially offset by
lower natural gas prices. Net income was lower in the first three quarters of
2007 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 and Sound mergers. Net
income increased in the fourth quarter of 2007 due to the full integration of
the Sound acquisition and stronger crude oil 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 fixed assets, the provision for asset retirement
costs and related accretion expense, and impairment calculations for fixed
assets and goodwill. The reserve estimates are also used to assess the
borrowing base for the Fund's credit facilities. Revision or changes in the
reserve estimates can have either a positive or a negative impact on net
income and the borrowing base of the Fund.
Management's process of determining the provision for future income
taxes, the provision for asset retirement obligation costs and related
accretion expense, and the fair values assigned to any acquired company's
assets and liabilities in a business combination is based on estimates. These
estimates are significant and can include reserves, future production rates,
future crude oil and natural gas prices, future costs, future interest rates,
future tax rates and other relevant assumptions. Revisions or changes in any
of these estimates can have either a positive or a negative impact on asset
and liability values and net income.
Financial Reporting Update
Convergence of Canadian GAAP with International Financial Reporting
Standards
In 2006, Canada's Accounting Standards Board ("AcSB") issued a strategic
plan that will result in Canadian GAAP, as it applies to publicly accountable
entities, being converged with International Financial Reporting Standards
over a transitional period, initially indicated to be five years. The AcSB
released a detailed implementation plan in May 2007 and the Fund will consider
the effects that this implementation plan might have on the consolidated
financial statements during the transition period.
Capital Disclosures
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.
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 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.
Evaluation of Disclosure Controls and Procedures
The Fund has established a Disclosure Committee consisting of seven
executive members with the responsibility of overseeing the Fund's disclosure
practices and designing disclosure controls and procedures to ensure that all
material information is communicated to the Disclosure Committee. All written
public disclosures are reviewed and approved by at least one member of the
Disclosure Committee prior to issuance. Additionally, the Disclosure Committee
assists the Chief Executive Officer and Chief Financial Officer of the Fund in
making certifications with respect to the disclosure controls of the Fund
required under applicable regulations and ensures that the Board of Directors
is promptly and fully informed regarding potential disclosure issues facing
the Fund.
The Fund's Management is responsible for establishing and maintaining
effective internal control over financial reporting. Management of Advantage,
including our Chief Executive Officer and Vice-President, Finance and Chief
Financial Officer, has evaluated the effectiveness of the design and operation
of the disclosure controls and procedures as of December 31, 2007. Based on
that evaluation, Management has concluded that the disclosure controls and
procedures are effective as of the end of the period, in all material
respects. It should be noted that while the Chief Executive Officer and Chief
Financial Officer believe that the Fund's design of disclosure controls and
procedures provide a reasonable level of assurance that they are effective,
they do not expect that the disclosure controls and procedures or internal
control over financial reporting will prevent all errors and fraud. A control
system does not provide absolute, but rather is designed to provide
reasonable, assurance that the objective of the control system is met.
Corporate Governance
The Board of Directors' mandate is to supervise the management of the
business and affairs of the Fund including the business and affairs of the
Fund delegated to AOG. In particular, all decisions relating to: (i) the
acquisition and disposition of properties for a purchase price or proceeds in
excess of $5 million; (ii) the approval of annual operating and capital
expenditure budgets; and (iii) the establishment of credit facilities and the
issuance of additional Trust Units, will be made by the Board.
Computershare Trust Company of Canada, the Trustee of the Fund, has
delegated certain matters to the Board of Directors. These include all
decisions relating to issuance of additional Trust Units and the determination
of the amount of distributions. Any amendment to any material contract to
which the Fund is a party will require the approval of the Board of Directors
and, in some cases, Unitholder approval.
The Board of Directors meets regularly to review the business and affairs
of the Fund and AOG and to make any required decisions. The Board of Directors
consists of ten members, seven of whom are unrelated to the Fund. The
Independent Reserve Evaluation Committee and Audit Committee each have three
members, all of whom are independent. The Human Resources, Compensation and
Corporate Governance Committee has four members, all of whom are independent.
One member of the Audit Committee has been designated a "Financial Expert" as
defined in applicable regulatory guidance. In addition, the Chairman of the
Board is not related and is not an executive officer of the Fund.
The Board of Directors approved and Management implemented a Code of
Business Conduct and Ethics. The purpose of the code is to lay out the
expectation for the highest standards of professional and ethical conduct from
our directors, officers and employees. The code reflects our commitment to a
culture of honesty, integrity and accountability and outlines the basic
principles and policies with which all employees are expected to comply. Our
Code of Business Conduct and Ethics is available on our website at
www.advantageincome.com.
As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"),
Advantage is not required to comply with most of the NYSE rules and listing
standards and instead may comply with domestic requirements. As a foreign
private issuer, Advantage is only required to comply with four of the NYSE
Rules: (i) have an audit committee that satisfies the requirements of the
United States Securities Exchange Act of 1934; (ii) the Chief Executive
Officer must promptly notify the NYSE in writing after an executive officer
becomes aware of any material non-compliance with the applicable NYSE Rules;
(iii) submit an executed annual written affirmation, as well as an interim
affirmation each time a change occurs to the audit committee; and (iv) provide
a brief description of any significant differences between its corporate
governance practices and those followed by U.S. companies listed under the
NYSE. Advantage has reviewed the NYSE listing standards and confirms that its
corporate governance practices do not differ significantly from such
standards.
A further discussion of the Fund's corporate governance practices can be
found in the Management Proxy Circular.
Outlook
The Fund's 2008 Budget, as approved by the Board of Directors, retains a
high degree of activity and focus on drilling in many of our key properties
where a high level of success was realized through 2007. Capital has also been
directed to delineate a natural gas resource play at Glacier in Northwest
Alberta and to accommodate facility expansions and 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
throughout 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 fourth quarter of 2007, production was on-track and operating
costs were lower than expected. We realized some impact to our production due
to third party related facilities outages in December, however, continued
efforts in operating cost optimization is providing efficiency gains. For
2008, we are forecasting production to be in the range of 32,000 to
34,000 boe/d. Advantage's 2008 capital expenditures budget is estimated to be
approximately $125 to $145 million with approximately 143 gross (88 net)
wells. An active winter program at Martin Creek, Glacier, Nevis and Willesden
Green will be followed by a relatively even paced program in Q3 and Q4 of
2008. Capital spending is estimated to be split evenly between oil and gas
activities.
Per unit operating costs on an annual basis are expected to range between
the $12.50 to $13.30/boe range. Advantage is continuing with several operating
cost reduction initiatives throughout 2008 to help offset these increases and
we have begun to realize some key achievements in this area. We expect
industry servicing and maintenance costs to generally remain stable in 2008
with some potential for natural gas related costs to increase during the
latter part of 2008 if natural gas prices strengthen at that time.
On October 25, 2007, the Alberta Provincial Government announced changes
to royalties for conventional oil, natural gas and oil sands that will become
effective January 1, 2009. Preliminary indications are that the changes will
have a negligible impact on Advantage since we have a significant number of
lower rate wells within our long life properties producing in Alberta.
Advantage also has a significant Horseshoe Canyon coal bed methane drilling
inventory that can be pursued which will also have a favorable royalty
treatment due to lower rate per well characteristics. Our exposure in
Northeast British Columbia and Saskatchewan also affords us further
flexibility with mitigating the royalty impact in our capital program. We
expect our royalty rates to range from 17% to 19% in 2008.
Advantage's funds from operations in 2008 will continue to be impacted by
the volatility of crude oil and natural gas prices and the $US/$Canadian
exchange rate. Additional hedging has been completed for 2008 to i) stabilize
cash flows and ii) ensure that the Fund's capital program is substantially
funded out of cash flow. Approximately 51% of our natural gas production, net
of royalties, is now hedged for the 2008 calendar year at a floor of
$7.43/mcf. Advantage has also hedged 38% of its 2008 crude oil production, net
of royalties, at an average price of $94.07/bbl.
Advantage will continue to follow its strategy of acquiring properties
that provide low risk development opportunities and enhance long-term cash
flow. Advantage will also continue to focus on low cost production and reserve
additions through low to medium risk development drilling opportunities that
have arisen as a result of the acquisitions completed in prior years and from
the significant inventory of drilling opportunities that has resulted from the
Ketch and Sound mergers.
Looking forward, Advantage's high quality assets combined with a greater
than five 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.
Sensitivities
The following table displays the current estimated sensitivity on funds
from operations and funds from operations per Trust Unit to changes in
production, commodity prices, exchange rates and interest rates for 2008.Annual
Funds from
Annual Operations
Funds from per
Operations Trust Unit
($000) ($/Trust Unit)
-------------------------------------------------------------------------
Natural gas
AECO monthly price change of $1.00/mcf $ 17,800 $ 0.12
Production change of 6.0 mmcf/d $ 7,200 $ 0.05
Crude oil and NGLs
WTI price change of US$10.00/bbl $ 27,900 $ 0.20
Production change of 1,000 bbls/d $ 22,200 $ 0.16
$US/$Canadian exchange rate change of $0.01 $ 5,900 $ 0.04
Interest rate change of 1% $ 5,600 $ 0.04Additional Information
Additional information relating to Advantage can be found on SEDAR at
www.sedar.com and the Fund's website at www.advantageincome.com. Such other
information includes the annual information form, the annual information
circular - proxy statement, press releases, material contracts and agreements,
and other financial reports. The annual information form will be of particular
interest for current and potential Unitholders as it discusses a variety of
subject matter including the nature of the business, structure of the Fund,
description of our operations, general and recent business developments, risk
factors, reserves data and other oil and gas information.CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
December 31, December 31,
(thousands of dollars) 2007 2006
-------------------------------------------------------------------------
Assets
Current assets
Accounts receivable $ 95,474 $ 79,537
Prepaid expenses and deposits 21,988 16,878
Derivative asset (note 12) 7,027 9,840
-------------------------------------------------------------------------
124,489 106,255
Deposit on property acquisition - 1,410
Derivative asset (note 12) 174 593
Fixed assets (note 4) 2,177,346 1,753,058
Goodwill (note 3) 120,271 120,271
-------------------------------------------------------------------------
$ 2,422,280 $ 1,981,587
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 122,087 $ 116,109
Distributions payable to Unitholders 16,592 18,970
Current portion of capital lease obligations
(note 5) 1,537 2,527
Current portion of convertible debentures
(note 6) 5,333 1,464
Derivative liability (note 12) 2,242 -
-------------------------------------------------------------------------
147,791 139,070
Derivative liability (note 12) 2,778 -
Capital lease obligations (note 5) 5,653 305
Bank indebtedness (note 7) 547,426 410,574
Convertible debentures (note 6) 212,203 170,819
Asset retirement obligations (note 8) 60,835 34,324
Future income taxes (note 9) 66,727 61,939
-------------------------------------------------------------------------
1,043,413 817,031
-------------------------------------------------------------------------
Unitholders' Equity
Unitholders' capital (note 10) 2,027,065 1,592,758
Convertible debentures equity component (note 6) 9,632 8,041
Contributed surplus (note 10) 2,005 863
Accumulated deficit (note 11) (659,835) (437,106)
-------------------------------------------------------------------------
1,378,867 1,164,556
-------------------------------------------------------------------------
$ 2,422,280 $ 1,981,587
-------------------------------------------------------------------------
Commitments (note 14)
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Income (Loss),
Comprehensive Income and Accumulated Deficit
Year ended Year ended
(thousands of dollars, except December 31, December 31,
for per Trust Unit amounts) 2007 2006
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas $ 538,764 $ 414,430
Realized gain on derivatives (note 12) 18,594 5,297
Unrealized gain (loss) on derivatives (note 12) (11,049) 10,242
Royalties, net of Alberta Royalty Credit (98,614) (76,456)
-------------------------------------------------------------------------
447,695 353,513
-------------------------------------------------------------------------
Expenses
Operating 127,309 82,911
General and administrative 21,449 13,738
Management fee (note 13) - 887
Performance incentive (note 13) - 2,380
Management internalization (note 13) 15,708 13,449
Interest 24,351 18,258
Interest and accretion on convertible
debentures 17,436 13,316
Depletion, depreciation and accretion 272,175 194,309
-------------------------------------------------------------------------
478,428 339,248
-------------------------------------------------------------------------
Income (loss) before taxes and non-controlling
interest (30,733) 14,265
Future income tax reduction (note 9) (24,642) (37,087)
Income and capital taxes (note 9) 1,444 1,509
-------------------------------------------------------------------------
(23,198) (35,578)
-------------------------------------------------------------------------
Net income (loss) before non-controlling interest (7,535) 49,843
Non-controlling interest - 29
-------------------------------------------------------------------------
Net income (loss) and comprehensive income (loss) (7,535) 49,814
Accumulated deficit, beginning of year (437,106) (269,674)
Distributions declared (215,194) (217,246)
-------------------------------------------------------------------------
Accumulated deficit, end of year $ (659,835) $ (437,106)
-------------------------------------------------------------------------
Net income (loss) per Trust Unit (note 10)
Basic $ (0.06) $ 0.62
Diluted $ (0.06) $ 0.61
-------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
Year ended Year ended
December 31, December 31,
(thousands of dollars) 2007 2006
-------------------------------------------------------------------------
Operating Activities
Net income (loss) $ (7,535) $ 49,814
Add (deduct) items not requiring cash:
Unrealized loss (gain) on derivatives 11,049 (10,242)
Unit-based compensation 929 -
Performance incentive - 2,380
Management internalization 15,708 13,449
Non-cash interest expense 890 -
Accretion on convertible debentures 2,569 2,106
Depletion, depreciation and accretion 272,175 194,309
Future income tax (24,642) (37,087)
Non-controlling interest - 29
Expenditures on asset retirement (6,951) (5,974)
Changes in non-cash working capital (15,060) 20,303
-------------------------------------------------------------------------
Cash provided by operating activities 249,132 229,087
-------------------------------------------------------------------------
Financing Activities
Units issued, net of costs (note 10) 104,215 141,908
Debentures redeemed (note 6) (19,406) -
Increase (decrease) in bank indebtedness 28,893 (30,767)
Reduction of capital lease obligations (3,184) (1,019)
Distributions to Unitholders (170,915) (185,015)
-------------------------------------------------------------------------
Cash used in financing activities (60,397) (74,893)
-------------------------------------------------------------------------
Investing Activities
Expenditures on property and equipment (148,725) (159,487)
Property acquisitions (16,051) (244)
Property dispositions 1,037 8,727
Acquisition of Sound Energy Trust (note 3) (22,307) -
Acquisition of Ketch Resources Trust (note 3) - (10,109)
Changes in non-cash working capital (2,689) 6,919
-------------------------------------------------------------------------
Cash used in investing activities (188,735) (154,194)
-------------------------------------------------------------------------
Net change in cash - -
Cash, beginning of year - -
-------------------------------------------------------------------------
Cash, end of year $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Interest paid $ 42,017 $ 34,680
Taxes paid $ 2,062 $ 1,783
see accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007
All tabular amounts in thousands except as otherwise indicated
1. Business and Structure of the Fund
Advantage Energy Income Fund ("Advantage" or the "Fund") was formed
on May 23, 2001 as a result of a plan of arrangement. For Canadian
tax purposes, Advantage is an open-ended unincorporated mutual fund
trust created under the laws of the Province of Alberta pursuant to a
Trust Indenture originally dated April 17, 2001, and as occasionally
amended, between Advantage Oil & Gas Ltd. ("AOG") and Computershare
Trust Company of Canada, as trustee. The Fund commenced operations on
May 24, 2001. The beneficiaries of the Fund are the holders of the
Trust Units (the "Unitholders").
The principal undertaking of the Fund is to indirectly acquire and
hold interests in petroleum and natural gas properties and assets
related thereto. The business of the Fund is carried on by its
wholly-owned subsidiary, AOG. The Fund's primary assets are currently
the common shares of AOG, a royalty in the producing properties of
AOG (the "AOG Royalty") and notes of AOG (the "AOG Notes"). The
Fund's strategy, through AOG, is to minimize exposure to exploration
risk while focusing on growth through acquisition and development of
producing crude oil and natural gas properties.
The purpose of the Fund is to distribute available cash flow to
Unitholders on a monthly basis in accordance with the terms of the
Trust Indenture. The Fund's available cash flow includes principal
repayments and interest income earned from the AOG Notes, royalty
income earned from the AOG Royalty, and any dividends declared on the
common shares of AOG less any expenses of the Fund including interest
on convertible debentures. Cash received on the AOG Notes, AOG
Royalty and common shares of AOG result in the effective transfer of
the economic interest in the properties of AOG to the Fund. However,
while the royalty is a contractual interest in the properties owned
by AOG, it does not confer ownership in the underlying resource
properties. Distributions from the Fund to Unitholders are entirely
discretionary and are determined by Management and the Board of
Directors. We closely monitor our distribution policy considering
forecasted cash flows, optimal debt levels, capital spending
activity, taxability to Unitholders, working capital requirements,
and other potential cash expenditures. Distributions are announced
monthly and are based on the cash available after retaining a portion
to meet such spending requirements. The level of distributions are
primarily determined by cash flows received from the production of
oil and natural gas from existing Canadian resource properties and
are highly dependent upon our success in exploiting the current
reserve base and acquiring additional reserves. Furthermore, monthly
distributions we pay to Unitholders are highly dependent upon the
prices received for such oil and natural gas production. It is our
long-term objective to provide stable and sustainable distributions
to the Unitholders, while continuing to grow the Fund.
2. Summary of Significant Accounting Policies
The Management of the Fund prepares its consolidated financial
statements in accordance with Canadian generally accepted accounting
principles ("Canadian GAAP") and all amounts are stated in Canadian
dollars. The preparation of consolidated financial statements
requires Management to make estimates and assumptions that affect the
reported amount of assets, liabilities and equity and disclosures of
contingencies at the date of the consolidated financial statements
and the reported amounts of revenues and expenses during the period.
The following significant accounting policies are presented to assist
the reader in evaluating these consolidated financial statements and,
together with the notes, should be considered an integral part of the
consolidated financial statements.
(a) Consolidation and joint operations
These consolidated financial statements include the accounts of the
Fund and all subsidiaries, including AOG. All intercompany balances
and transactions have been eliminated.
The Fund conducts exploration and production activities jointly with
other participants. The accounts of the Fund reflect its
proportionate interest in such joint operations.
(b) Fixed assets
(i) Petroleum and natural gas properties
The Fund follows the "full cost" method of accounting in
accordance with the guideline issued by the Canadian Institute of
Chartered Accountants ("CICA") whereby all costs associated with
the acquisition of and the exploration for and development of
petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in a Canadian cost centre and
charged to income as set out below. Such costs include lease
acquisition, drilling and completion, production facilities, asset
retirement costs, geological and geophysical costs and overhead
expenses related to exploration and development activities.
Gains or losses are not recognized upon disposition of petroleum
and natural gas properties unless crediting the proceeds against
accumulated costs would result in a change in the rate of
depletion and depreciation of 20% or more.
Depletion of petroleum and natural gas properties and depreciation
of lease, well equipment and production facilities is provided on
accumulated costs using the "unit-of-production" method based on
estimated net proved petroleum and natural gas reserves, before
royalties, as determined by independent engineers. For purposes of
the depletion and depreciation calculation, proved petroleum and
natural gas reserves are converted to a common unit-of-measure on
the basis of one barrel of oil or liquids being equal to six
thousand cubic feet of natural gas.
The depletion and depreciation cost base includes total
capitalized costs, less costs of unproved properties, plus a
provision for future development costs of proved undeveloped
reserves. Costs of acquiring and evaluating unproved properties
are excluded from depletion calculations until it is determined
whether or not proved reserves are attributable to the properties
or impairment occurs.
Petroleum and natural gas assets are evaluated in each reporting
period to determine that the carrying amount in a cost centre is
recoverable and does not exceed the fair value of the properties
in the cost centre (the "ceiling test"). The carrying amounts are
assessed to be recoverable when the sum of the undiscounted net
cash flows expected from the production of proved reserves, the
lower of cost and market of unproved properties and the cost of
major development projects exceeds the carrying amount of the cost
centre. When the carrying amount is not assessed to be
recoverable, an impairment loss is recognized to the extent that
the carrying amount of the cost centre exceeds the sum of the
discounted net cash flows expected from the production of proved
and probable reserves, the lower of cost and market of unproved
properties and the cost of major development projects of the cost
centre. The net cash flows are estimated using expected future
product prices and costs and are discounted using a risk-free
interest rate. There has been no impairment of the Fund's
petroleum and natural gas properties since inception.
(ii) Furniture and equipment
The Fund records furniture and equipment at cost and provides
depreciation on the declining balance method at a rate of 20% per
annum which is designed to amortize the cost of the assets over
their estimated useful lives.
(c) Goodwill
Goodwill is the excess purchase price of a business over the fair
value of identifiable assets and liabilities acquired. Goodwill is
stated at cost less impairment and is not amortized. Goodwill
impairment is assessed at year-end, or as economic events dictate, by
comparing the fair value of the reporting unit (the Fund) to its
carrying value, including goodwill. If the fair value of the Fund is
less than its carrying value, a goodwill impairment loss is
recognized by allocating the fair value of the Fund to the
identifiable assets and liabilities as if the Fund had been acquired
in a business acquisition for a purchase price equal to the fair
value. The excess of the fair value of the Fund over the values
assigned to the identifiable assets and liabilities is the implied
fair value of the goodwill. Any excess of the carrying value of the
goodwill over the implied fair value is the impairment amount and is
charged to income in the period incurred. There has been no
impairment of the Fund's goodwill since inception.
(d) Distributions
Distributions are calculated on an accrual basis and are paid to
Unitholders monthly.
(e) 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 cash flow hedges are included in other
comprehensive income until the time at which the hedged item is
realized. The Fund does not utilize derivative instruments for
speculative purposes but has elected not to apply hedge accounting.
Therefore, gains and losses on these instruments are recorded as
unrealized gains and losses on derivatives in the consolidated
statement of 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.
(f) Comprehensive income
Effective January 1, 2007, the Fund adopted CICA Handbook section
1530 "Comprehensive Income". Comprehensive income consists of net
income and other comprehensive income ("OCI") with amounts included
in OCI shown net of tax. Accumulated other comprehensive income is 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.
(g) Convertible debentures
The Fund's convertible debentures are financial liabilities
consisting of a liability with an embedded conversion feature. As
such, the debentures are segregated between liabilities and equity
based on the relative fair market value of the liability and equity
portions. Therefore, the debenture liabilities are presented at less
than their eventual maturity values. The liability and equity
components are further reduced for issuance costs initially incurred.
The discount of the liability component as compared to maturity value
is accreted by the "effective interest" method over the debenture
term and expensed accordingly. As debentures are converted to Trust
Units, an appropriate portion of the liability and equity components
are transferred to Unitholders' capital.
(h) Asset retirement obligations
The Fund follows the "asset retirement obligation" method of
recording the future cost associated with removal, site restoration
and asset retirement costs. The fair value of the liability for the
Fund's asset retirement obligations is recorded in the period in
which it is incurred, discounted to its present value using the
Fund's credit adjusted risk-free interest rate and the corresponding
amount recognized by increasing the carrying amount of fixed assets.
The asset recorded is depleted on a "unit-of-production" basis over
the life of the reserves consistent with the Fund's depletion and
depreciation policy for petroleum and natural gas properties. The
liability amount is increased each reporting period due to the
passage of time and the amount of accretion is charged to income in
the period. Revisions to the estimated timing of cash flows or to the
original estimated undiscounted cost could also result in an increase
or decrease to the obligation. Actual costs incurred upon settlement
of the retirement obligations are charged against the obligation to
the extent of the liability recorded.
(i) Income taxes
The Fund is considered an open-ended unincorporated mutual fund trust
under the Income Tax Act (Canada). Any taxable income is allocated to
the Unitholders and therefore no provision for current income taxes
relating to the Fund is included in these financial statements.
The Fund and its subsidiaries follow the "liability" method of
accounting for income taxes. Under this method future tax assets and
liabilities are determined based on differences between financial
reporting and income tax bases of assets and liabilities, and are
measured using substantially enacted tax rates and laws expected to
apply when the differences reverse. The effect on future tax assets
and liabilities of a change in tax rates is recognized in net income
in the period in which the change is substantially enacted.
(j) Unit-based compensation
Advantage accounts for compensation expense based on the "fair value"
of rights granted under its unit-based compensation plans. The Fund
has Trust Units held in escrow relating to the management
internalization (note 13) as well as a unit-based compensation plan
for external directors of the Fund, a Restricted Trust Unit Plan and
Trust Units issuable for the retention of certain employees of the
Fund (note 10).
The escrowed Trust Units relating to the management internalization
vest equally over three years, the period during which employees are
required to provide service to receive the Trust Units. Therefore,
the management internalization consideration is being deferred and
amortized into income as management internalization expense over the
specific vesting periods during which employee services are provided,
including an estimate of future Trust Unit forfeitures.
Awards under the external directors' unit-based compensation plan
vest immediately with associated compensation expense recognized in
the current period earnings and estimated forfeiture rates are not
incorporated in the determination of fair value. The compensation
expense results in the creation of contributed surplus until the
rights are exercised. Consideration paid upon the exercise of the
rights together with the amount previously recognized in contributed
surplus is recorded as an increase in Unitholders' capital.
Advantage's current employee compensation includes a Restricted Trust
Unit Plan (the "Plan"), as approved by the Unitholders on June 23,
2006, and Trust Units issuable for the retention of certain employees
of the Fund. The Plan authorizes the Board of Directors to grant
Restricted Trust Units ("RTUs") to directors, officers, or employees
of the Fund. The number of RTUs granted is based on the Fund's Trust
Unit return for a calendar year and compared to a peer group approved
by the Board of Directors. The Trust Unit return is calculated at the
end of the year and is primarily based on the year-over-year change
in the Trust Unit price plus distributions. The RTU grants vest one
third immediately on grant date, with the remaining two thirds
vesting evenly on the following two yearly anniversary dates. The
holders of RTUs may elect to receive cash upon vesting in lieu of the
number of Trust Units to be issued, subject to consent of the Fund.
Compensation cost related to the Plan is recognized as compensation
expense over the service period and incorporates the period end Trust
Unit price, the estimated number of RTUs to vest, and certain
management estimates. The maximum amount of RTUs granted in any one
calendar year is limited to 175% of the base salaries of those
individuals participating in the Plan for such period.
(k) Revenue recognition
Revenue associated with the sale of crude oil, natural gas and
natural gas liquids is recognized when the title and risks pass to
the purchaser, normally at the pipeline delivery point for natural
gas and at the wellhead for crude oil.
(l) Per Trust Unit amounts
Net income per Trust Unit is calculated using the weighted average
number of Trust Units outstanding during the year. Diluted net income
per Trust Unit is calculated using the "if-converted" method to
determine the dilutive effect of convertible debentures and
exchangeable shares and the "treasury stock" method for trust unit
rights granted to directors and the management internalization
escrowed Trust Units.
(m) Measurement uncertainty
The amounts recorded for depletion and depreciation of property and
equipment, the provision for asset retirement obligation costs and
related accretion expense, impairment calculations for fixed assets
and goodwill, derivative fair value calculations, future income tax
provisions, as well as fair values assigned to any identifiable
assets and liabilities in business combinations are based on
estimates. These estimates are significant and include proved and
probable reserves, future production rates, future crude oil and
natural gas prices, future costs, future interest rates, fair value
assessments, and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the effect on
the consolidated financial statements of changes in such estimates in
future years could be material.
(n) 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.
(o) 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.
(p) Comparative figures
Certain comparative figures have been reclassified to conform to the
current year's presentation.
3. Acquisitions
(a) Sound Energy Trust
On September 5, 2007, Advantage acquired all of the issued and
outstanding Trust Units and Exchangeable Shares of Sound Energy Trust
("Sound") for $21.4 million cash consideration, 16,977,184 Advantage
Trust Units and $0.9 million of acquisition costs. Sound Unitholders
and Exchangeable Shareholders could elect to receive 0.30 Advantage
Trust Units for each Sound Trust Unit or receive $0.66 in cash and
0.2557 Advantage Trust Units for each Sound Trust Unit. All of the
Sound Exchangeable Shares were exchanged for Advantage Trust Units on
the same ratio as the Sound Trust Units based on the conversion ratio
in effect at the effective date of the acquisition. Sound was an
energy trust engaged in the development, acquisition and production
of, natural gas and crude oil in western Canada. The acquisition is
being accounted for using the "purchase method" with the results of
operations included in the consolidated financial statements as of
the closing date of the acquisition.
The purchase price has been allocated as follows:
Net assets acquired and
liabilities assumed: Consideration:
Fixed assets $ 509,656 16,977,184 Trust Units $ 228,852
issued
Accounts
receivable 27,433 Cash 21,403
Prepaid expenses
and deposits 3,873 Acquisition costs incurred 904
Derivative asset, -----------
net 2,797 $ 251,159
Bank indebtedness (107,959) -----------
Convertible
debentures (101,553)
Accounts payable
and accrued
liabilities (35,396)
Future income taxes (29,430)
Asset retirement
obligations (16,695)
Capital lease
obligations (1,567)
-----------
$ 251,159
-----------
The value of the Trust Units issued as consideration was determined
based on the weighted average trading value of Advantage Trust Units
during the two-day period before and after the terms of the
acquisition were agreed to and announced. The allocation of the
purchase price has been revised due to the realization of estimates
and is subject to further refinement as additional cost estimates and
tax balances are finalized.
(b) Ketch Resources Trust
On June 23, 2006, Advantage acquired all of the issued and
outstanding Trust Units of Ketch Resources Trust ("Ketch") in return
for 32,870,465 Advantage Trust Units, utilizing an exchange ratio of
0.565 Advantage Trust Units for each Ketch Trust Unit outstanding.
Ketch was an energy trust engaged in the development, acquisition and
production of, natural gas and crude oil in western Canada. The
acquisition is being accounted for using the "purchase method" with
the results of operations included in the consolidated financial
statements as of the closing date of the acquisition. The purchase
price has been allocated as follows:
Net assets acquired and
liabilities assumed: Consideration:
Fixed assets $ 877,463 32,870,465 Trust Units $ 688,636
issued
Goodwill 74,798 Acquisition costs incurred 10,109
-----------
Accounts receivable 55,806 $ 698,745
Prepaid expenses -----------
and deposits 6,406
Cash 2,713
Bank indebtedness (191,578)
Convertible
debentures (69,952)
Accounts payable (46,834)
Asset retirement
obligations (7,930)
Capital lease
obligation (2,147)
-----------
$ 698,745
-----------
The value of the Trust Units issued as consideration was determined
based on the weighted average trading value of Advantage Trust Units
during the two-day period before and after the terms of the
acquisition were agreed to and announced.
4. Fixed Assets
Accumulated
Depletion and Net Book
December 31, 2007 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 3,016,243 $ 844,671 $ 2,171,572
Furniture and equipment 10,548 4,774 5,774
---------------------------------------------------------------------
$ 3,026,791 $ 849,445 $ 2,177,346
---------------------------------------------------------------------
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 year ended December 31, 2007, Advantage capitalized
general and administrative expenditures directly related to
exploration and development activities of $9,653,000 (2006 -
$6,444,000).
Costs of $60,238,000 (2006 - $43,467,000) for unproved properties
have been excluded from the calculation of depletion expense, and
future development costs of $190,146,000 (2006 - $123,464,000) have
been included in costs subject to depletion.
The Fund performed a ceiling test calculation at December 31, 2007 to
assess the recoverable value of fixed assets. Based on the
calculation, the carrying amounts are recoverable as compared to the
sum of the undiscounted net cash flows expected from the production
of proved reserves based on the following benchmark prices:
WTI Exchange
Crude Oil Rate AECO Gas
Year ($US/bbl) ($US/$Cdn) ($Cdn/mmbtu)
---------------------------------------------------------------------
2008 $ 89.61 $ 1.00 $ 6.51
2009 $ 86.01 $ 1.00 $ 7.22
2010 $ 84.65 $ 1.00 $ 7.69
2011 $ 82.77 $ 1.00 $ 7.70
2012 $ 82.26 $ 1.00 $ 7.61
2013 $ 82.81 $ 1.00 $ 7.78
---------------------------------------------------------------------
Approximate escalation rate after
2013 2.0% - 2.0%
---------------------------------------------------------------------
Benchmark prices are adjusted for a variety of factors such as
quality differentials to determine the expected price to be realized
by the Fund when performing the ceiling test calculation.
5. Capital Lease Obligations
The Fund has capital leases on a variety of fixed assets. Future
minimum lease payments at December 31, 2007 consist of the following:
2008 $ 1,906
2009 2,040
2010 2,200
2011 1,925
---------------------------------------------------------------------
8,071
Less amounts representing interest (881)
---------------------------------------------------------------------
7,190
Current portion (1,537)
---------------------------------------------------------------------
$ 5,653
---------------------------------------------------------------------
On June 23, 2006, Advantage assumed a total capital lease obligation
of $2.1 million in the acquisition of Ketch (note 3). The lease ends
in March 2008 and interest expense is recognized at 5.3%.
During the second quarter of 2007, Advantage entered a new lease
arrangement that resulted in the recognition of a fixed asset
addition and capital lease obligation of $4.1 million. The lease
obligation bears interest at 5.8% and is secured by the related
equipment. The lease term expires June 2011 with a final purchase
obligation of $1.5 million at which time ownership of the equipment
will transfer to Advantage.
Effective September 4, 2007, Advantage entered a new lease
arrangement that resulted in the recognition of a fixed asset
addition and capital lease obligation of $1.8 million. The lease
obligation bears interest at 6.7% and is secured by the related
equipment. The lease term expires August 2010 with a final payment
obligation of $0.7 million. Distributions to Unitholders are not
permitted if the Fund is in default of such capital lease.
On September 5, 2007, Advantage assumed two capital lease obligations
in the acquisition of Sound (note 3) resulting in the recognition of
capital lease obligations of $1.6 million. Both of the lease
obligations bear interest at 5.6% and are secured by the related
equipment. The lease terms expire December 2009 and April 2010 with a
total final payment obligation of $0.9 million.
Fixed assets subject to capital leases are depreciated on a "unit-of-
production" basis over the life of the reserves consistent with the
Fund's depletion and depreciation policy for petroleum and natural
gas properties and is included in depletion and depreciation expense.
6. Convertible Debentures
The convertible unsecured subordinated debentures pay interest semi-
annually and are convertible at the option of the holder into Trust
Units of Advantage at the applicable conversion price per Trust Unit
plus accrued and unpaid interest. The details of the convertible
debentures including fair market values initially assigned and
issuance costs are as follows:
10.00% 9.00% 8.25% 8.75%
---------------------------------------------------------------------
Trading symbol AVN.DB AVN.DBA AVN.DBB AVN.DBF
Issue date Oct. 18, July 8, Dec. 2, June 10,
2002 2003 2003 2004
Maturity date Matured Aug. 1, Feb. 1, June 30,
2008 2009 2009
Conversion price Matured $ 17.00 $ 16.50 $ 34.67
Liability component $ 52,722 $ 28,662 $ 56,802 $ 48,700
Equity component 2,278 1,338 3,198 11,408
---------------------------------------------------------------------
Gross proceeds 55,000 30,000 60,000 60,108
Issuance costs (2,495) (1,444) (2,588) -
---------------------------------------------------------------------
Net proceeds $ 52,505 $ 28,556 $ 57,412 $ 60,108
---------------------------------------------------------------------
7.50% 6.50% 7.75% 8.00% Total
---------------------------------------------------------------------
Trading symbol AVN.DBC AVN.DBE AVN.DBD AVN.DBG
Issue date Sep. 15, May 18, Sep. 15, Nov. 13,
2004 2005 2004 2006
Maturity date Oct. 1, June 30, Dec. 1, Dec. 31,
2009 2010 2011 2011
Conversion price $ 20.25 $ 24.96 $ 21.00 $ 20.33
Liability component $ 71,631 $ 66,981 $ 47,444 $ 14,884 $387,826
Equity component 3,369 2,971 2,556 26,561 53,679
---------------------------------------------------------------------
Gross proceeds 75,000 69,952 50,000 41,445 441,505
Issuance costs (3,190) - (2,190) - (11,907)
---------------------------------------------------------------------
Net proceeds $ 71,810 $ 69,952 $ 47,810 $ 41,445 $429,598
---------------------------------------------------------------------
The convertible debentures are redeemable prior to their maturity
dates, at the option of the Fund, upon providing 30 to 60 days
advance notification. The redemption prices for the various
debentures, plus accrued and unpaid interest, is dependent on the
redemption periods and are as follows:
Convertible Redemption
Debenture Redemption Periods Price
---------------------------------------------------------------------
9.00% After August 1, 2007 and before
August 1, 2008 $1,025
---------------------------------------------------------------------
8.25% After February 1, 2007 and on or before
February 1, 2008 $1,050
After February 1, 2008 and before
February 1, 2009 $1,025
---------------------------------------------------------------------
8.75% After June 30, 2007 and on or before
June 30, 2008 $1,050
After June 30, 2008 and before June 30, 2009 $1,025
---------------------------------------------------------------------
7.50% After October 1, 2007 and on or before
October 1, 2008 $1,050
After October 1, 2008 and before October 1, 2009 $1,025
---------------------------------------------------------------------
6.50% After June 30, 2008 and on or before
June 30, 2009 $1,050
After June 30, 2009 and before June 30, 2010 $1,025
---------------------------------------------------------------------
7.75% After December 1, 2007 and on or before
December 1, 2008 $1,050
After December 1, 2008 and on or before
December 1, 2009 $1,025
After December 1, 2009 and before
December 1, 2011 $1,000
---------------------------------------------------------------------
8.00% After December 31, 2009 and on or before
December 31, 2010 $1,050
After December 31, 2010 and before
December 31, 2011 $1,025
---------------------------------------------------------------------
The balance of debentures outstanding at December 31, 2007 and
changes in the liability and equity components during the years ended
December 31, 2007 and 2006 are as follows:
10.00% 9.00% 8.25% 8.75%
---------------------------------------------------------------------
Debentures outstanding $ - $ 5,392 $ 4,867 $ 29,839
---------------------------------------------------------------------
Liability component:
Balance at Dec. 31, 2005 $ 2,453 $ 7,259 $ 8,150 $ -
Assumed on Ketch acquisition - - - -
Accretion of discount 30 107 103 -
Converted to Trust Units (1,019) (2,131) (3,577) -
---------------------------------------------------------------------
Balance at Dec. 31, 2006 1,464 5,235 4,676 -
Assumed on Sound acquisition - - - 48,700
Accretion of discount 22 98 91 96
Converted to Trust Units (1,486) - - (8)
Redeemed for cash - - - (19,406)
---------------------------------------------------------------------
Balance at Dec. 31, 2007 $ - $ 5,333 $ 4,767 $ 29,382
---------------------------------------------------------------------
Equity component:
Balance at Dec. 31, 2005 $ 100 $ 323 $ 441 $ -
Assumed on Ketch acquisition - - - -
Converted to Trust Units (41) (94) (193) -
---------------------------------------------------------------------
Balance at Dec. 31, 2006 59 229 248 -
Assumed on Sound acquisition - - - 11,408
Converted to Trust Units - - - (10,556)
Expired (59) - - -
---------------------------------------------------------------------
Balance at Dec. 31, 2007 $ - $ 229 $ 248 $ 852
---------------------------------------------------------------------
7.50% 6.50% 7.75% 8.00% Total
---------------------------------------------------------------------
Debentures
outstanding $ 52,268 $ 69,952 $ 46,766 $ 15,528 $224,612
---------------------------------------------------------------------
Liability component:
Balance at Dec. 31,
2005 $ 62,321 $ - $ 45,898 $ - $126,081
Assumed on Ketch
acquisition - 66,981 - - 66,981
Accretion of
discount 897 380 589 - 2,106
Converted to
Trust Units (13,436) - (2,722) - (22,885)
---------------------------------------------------------------------
Balance at Dec. 31,
2006 49,782 67,361 43,765 - 172,283
Assumed on Sound
acquisition - - - 14,884 63,584
Accretion of
discount 889 731 595 47 2,569
Converted to Trust
Units - - - - (1,494)
Redeemed for cash - - - - (19,406)
---------------------------------------------------------------------
Balance at Dec. 31,
2007 $ 50,671 $ 68,092 $ 44,360 $ 14,931 $217,536
---------------------------------------------------------------------
Equity component:
Balance at Dec. 31,
2005 $ 2,865 $ - $ 2,430 $ - $ 6,159
Assumed on Ketch
acquisition - 2,971 - - 2,971
Converted to Trust
Units (617) - (144) - (1,089)
---------------------------------------------------------------------
Balance at Dec. 31,
2006 2,248 2,971 2,286 - 8,041
Assumed on Sound
acquisition - - - 26,561 37,969
Converted to Trust
Units - - - (25,763) (36,319)
Expired - - - - (59)
---------------------------------------------------------------------
Balance at Dec. 31,
2007 $ 2,248 $ 2,971 $ 2,286 $ 798 $ 9,632
---------------------------------------------------------------------
As part of the acquisition of Ketch (note 3), the 6.50% convertible
debentures, originally issued May 18, 2005, were assumed by Advantage
on June 23, 2006.
Due to the acquisition of Sound (note 3), 8.75% and 8.00% convertible
debentures were assumed by Advantage on September 5, 2007. As a
result of the change in control of Sound, the Fund was required by
the debenture indentures to make an offer to purchase all of the
outstanding convertible debentures assumed from Sound at a price
equal to 101% of the principal amount plus accrued and unpaid
interest. On October 17, 2007, the expiry date of the offer, 911,709
Trust Units were issued and $19.9 million in total cash consideration
was paid in exchange for $29,665,000 8.75% convertible debentures and
2,220,289 Trust Units were issued in exchange for $25,507,000 8.0%
convertible debentures.
During the year ended December 31, 2007, $24,000 debentures (2006 -
$24,333,000) were converted resulting in the issuance of 1,386 Trust
Units (2006 - 1,286,901 Trust Units) and all of the remaining
$1,470,000 10% convertible debentures matured on November 1, 2007 and
were settled with the issuance of 127,493 Trust Units.
7. Bank Indebtedness
Advantage has a credit facility agreement with a syndicate of
financial institutions which provides for a $690 million extendible
revolving loan facility and a $20 million operating loan facility.
The loan's interest rate is based on either prime, US base rate,
LIBOR or bankers' acceptance rates, at the Fund's option, subject to
certain basis point or stamping fee adjustments ranging from 0.00% to
1.25% depending on the Fund's debt to cash flow ratio. The credit
facilities are secured by a $1 billion floating charge demand
debenture, a general security agreement and a subordination agreement
from the Fund covering all assets and cash flows. The credit
facilities are subject to review on an annual basis with the next
renewal due in June 2008. Various borrowing options are available
under the credit facilities, including prime rate-based advances, US
base rate advances, US dollar LIBOR advances and bankers' acceptances
loans. The credit facilities constitute a revolving facility for a
364 day term which is extendible annually for a further 364 day
revolving period at the option of the syndicate. If not extended, the
revolving credit facility is converted to a two year term facility
with the first payment due one year and one day after commencement of
the term. The credit facilities contain standard commercial covenants
for facilities of this nature. The only financial covenant is a
requirement for 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 year ended December 31, 2007, the
effective interest rate on the outstanding amounts under the facility
was approximately 5.7% (2006 - 5.1%).
8. Asset Retirement Obligations
The Fund's asset retirement obligations result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Fund estimates the
total undiscounted and inflated amount of cash flows required to
settle its asset retirement obligations is approximately
$243.9 million which will be incurred between 2008 to 2057. A credit-
adjusted risk-free rate of 7% and an inflation factor of 2% were used
to calculate the fair value of the asset retirement obligations.
A reconciliation of the asset retirement obligations is provided
below:
Year ended Year ended
December 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of year $ 34,324 $ 21,263
Accretion expense 2,795 1,684
Assumed in Sound acquisition (note 3) 16,695 -
Assumed in Ketch acquisition (note 3) - 7,930
Liabilities incurred 13,972 9,421
Liabilities settled (6,951) (5,974)
---------------------------------------------------------------------
Balance, end of year $ 60,835 $ 34,324
---------------------------------------------------------------------
9. Income Taxes
The taxable income of the Fund is comprised of interest income
related to the AOG Notes and royalty income from the AOG Royalty less
deductions for Canadian Oil and Gas Property Expense, Trust Unit
issue costs, and interest on convertible debentures. Given that
taxable income of the Fund is allocated to the Unitholders, no
provision for current income taxes relating to the Fund is included
in these financial statements. On December 14, 2007, the Federal
government enacted legislation phasing in corporate income tax rate
reductions which will reduce federal tax rates from 22.1% to 15.0% by
2012. Rate reductions will also apply to the new tax on distributions
of income trusts and other specified investment flow-through entities
as of 2011, reducing the tax rate in 2011 to 29.5% and in 2012 to
28.0%. These rates include a deemed provincial rate of 13%.
The provision for income taxes varies from the amount that would be
computed by applying the combined Canadian federal and provincial
income tax rates for the following reasons:
Year ended Year ended
December 31, December 31,
2007 2006
---------------------------------------------------------------------
Income (loss) before taxes $ (30,733) $ 14,265
---------------------------------------------------------------------
Canadian combined federal and provincial
income tax rates 32.57% 34.78%
Expected income tax expense (recovery) at
statutory rates (10,011) 4,961
Increase (decrease) in income taxes
resulting from:
Amounts included in trust income (57,766) (39,940)
Change in enacted tax rates 550 (5,692)
Management internalization 4,554 4,678
Specified Investment Flow-Through 42,862 -
Non-deductible Crown charges - 6,925
Resource allowance - (8,108)
Other (4,831) 89
---------------------------------------------------------------------
Future income tax reduction (24,642) (37,087)
Income and capital taxes 1,444 1,509
---------------------------------------------------------------------
$ (23,198) $ (35,578)
---------------------------------------------------------------------
The components of the future income tax liability are as follows:
December 31, December 31,
2007 2006
---------------------------------------------------------------------
Fixed assets in excess of tax basis $ 29,240 $ 85,648
Asset retirement obligations (16,330) (10,141)
Non-capital tax loss carry forward (20,369) (8,851)
Trust assets in excess of tax basis 82,642 -
Other (8,456) (4,717)
---------------------------------------------------------------------
Future income tax liability $ 66,727 $ 61,939
---------------------------------------------------------------------
AOG has a non-capital tax loss carry forward of approximately
$76 million of which $1 million expires in 2008, $18 million in 2011,
$11 million in 2012 and $46 million after 2020.
10. Unitholders' Equity
(a) Unitholders' capital
(i) Authorized
Unlimited number of voting Trust Units
(ii) Issued
Number of Units Amount
---------------------------------------------------------------------
Balance at December 31, 2005 57,846,324 $ 681,574
2005 non-cash performance incentive 475,263 10,544
Issued on conversion of debentures 1,286,901 23,974
Issued on conversion of exchangeable shares 127,014 2,398
Issued on exercise of Trust Unit rights 122,500 682
Issued for Ketch acquisition (note 3) 32,870,465 688,636
Management internalization 1,913,842 38,716
2006 non-cash performance incentive 117,662 2,380
Distribution reinvestment plan 2,005,499 27,722
Issued for cash, net of costs 8,625,000 141,399
---------------------------------------------------------------------
Balance at December 31, 2006 105,390,470 1,618,025
Issued on conversion of debentures 128,879 1,494
Issued on exercise of Trust Unit rights 37,500 562
Issued for cash, net of costs 8,600,000 104,094
Distribution reinvestment plan 4,028,252 46,657
Issued for Sound acquisition, net of costs
(note 3) 16,977,184 228,583
Issued on offer to purchase Sound debentures
(note 6) 3,131,998 37,209
Management internalization forfeitures (24,909) (503)
---------------------------------------------------------------------
138,269,374 $ 2,036,121
---------------------------------------------------------------------
Management internalization escrowed Trust
Units (9,056)
---------------------------------------------------------------------
Balance at December 31, 2007 $ 2,027,065
---------------------------------------------------------------------
On January 20, 2006, Advantage issued 475,263 Trust Units to satisfy
the obligation related to the 2005 year end performance incentive
fee.
On June 23, 2006, Advantage issued 32,870,465 Trust Units as
consideration for the acquisition of Ketch (note 3). Concurrent with
the Ketch acquisition, 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 (note 13). For
the year ended December 31, 2007, a total of 24,909 Trust Units
issued for the management internalization were forfeited (2006 -
19,366 Trust Units) and $15.7 million has been recognized as
management internalization expense (2006 - $13.4 million). As at
December 31, 2007, 1,193,622 Trust Units remain held in escrow
(December 31, 2006 - 1,822,098 Trust Units). The Fund also issued
117,662 Trust Units on June 23, 2006, valued at $2.4 million, to
satisfy the final obligation related to the 2006 first quarter
performance fee.
On July 24, 2006, Advantage announced that it adopted a Premium
Distribution™, Distribution Reinvestment and Optional Trust Unit
Purchase Plan (the "Plan"). The Plan commenced with the monthly cash
distribution payable on August 15, 2006 to Unitholders of record on
July 31, 2006. For eligible Unitholders that elect to participate in
the Plan, Advantage will settle the monthly distribution obligation
through the issuance of additional Trust Units at 95% of the Average
Market Price (as defined in the Plan). Unitholder enrollment in the
Premium Distribution™ component of the Plan effectively authorizes
the subsequent disposal of the issued Trust Units in exchange for a
cash payment equal to 102% of the cash distributions that the
Unitholder would otherwise have received if they did not participate
in the Plan. During the year ended December 31, 2007, 4,028,252 Trust
Units (2006 - 2,005,499 Trust Units) were issued under the Plan,
generating $46.7 million (2006 - $27.7 million) reinvested in the
Fund.
On August 1, 2006, Advantage issued 7,500,000 Trust Units, plus an
additional 1,125,000 Trust Units upon full exercise of the
Underwriters' over-allotment option on August 4, 2006, at $17.30 per
Trust Unit for net proceeds of $141.4 million (net of Underwriters'
fees and other issue costs of $7.8 million). The net proceeds of the
offering were used to pay down bank indebtedness and to subsequently
fund capital and general corporate expenditures.
On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an
additional 800,000 Trust Units upon exercise of the Underwriters'
over-allotment option on March 7, 2007, at $12.80 per Trust Unit for
approximate net proceeds of $104.1 million (net of Underwriters' fees
and other issue costs of $6.0 million).
On September 5, 2007, Advantage issued 16,977,184 Trust Units, valued
at $228.9 million, as partial consideration for the acquisition of
Sound (note 3). Trust Unit issuance costs of $0.3 million were
incurred for the Sound acquisition.
Due to the acquisition of Sound (note 3), 8.75% and 8.00% convertible
debentures were assumed by Advantage on September 5, 2007. As a
result of the change in control of Sound, the Fund was required by
the debenture indentures to make an offer to purchase all of the
outstanding convertible debentures assumed from Sound at a price
equal to 101% of the principal amount plus accrued and unpaid
interest. On October 17, 2007, the expiry date of the offer, 911,709
Trust Units were issued and $19.9 million in total cash consideration
was paid in exchange for $29,665,000 8.75% convertible debentures and
2,220,289 Trust Units were issued in exchange for $25,507,000 8.0%
convertible debentures.
(b) Contributed surplus
Year ended Year ended
December 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of year $ 863 $ 1,036
Unit-based compensation 1,255 -
Expiration of convertible debentures equity
component 59 -
Exercise of Trust Unit Rights (172) (173)
---------------------------------------------------------------------
Balance, end of year $ 2,005 $ 863
---------------------------------------------------------------------
(c) Trust Units Rights Incentive Plan
Effective June 25, 2002, a Trust Units Rights Incentive Plan for
external directors of the Fund was established and approved by the
Unitholders of Advantage. A total of 500,000 Trust Units have been
reserved for issuance under the plan with an aggregate of 400,000
rights granted since inception. The initial exercise price of rights
granted under the plan may not be less than the current market price
of the Trust Units as of the date of the grant and the maximum term
of each right is not to exceed ten years with all rights vesting
immediately upon grant. At the option of the rights holder, the
exercise price of the rights can be adjusted downwards over time
based upon distributions paid by the Fund to Unitholders.
Series B
Number Price
---------------------------------------------------------------------
Balance at December 31, 2005 225,000 $ 13.63
Exercised (37,500) -
Reduction of exercise price - (2.66)
---------------------------------------------------------------------
Balance at December 31, 2006 187,500 10.97
Exercised (37,500) -
Reduction of exercise price - (1.77)
---------------------------------------------------------------------
Balance at December 31, 2007 150,000 $ 9.20
---------------------------------------------------------------------
Expiration date June 17, 2008
---------------------------------------------------------------------
(d) Unit-based compensation
Advantage's current employee compensation includes a Restricted Trust
Unit Plan (the "Plan"), as approved by the Unitholders on June 23,
2006, and Trust Units issuable for the retention of certain employees
of the Fund. The purpose of the long-term compensation plans is to
retain and attract employees, to reward and encourage performance,
and to focus employees on operating and financial performance that
results in lasting Unitholder return.
The Plan authorizes the Board of Directors to grant Restricted Trust
Units ("RTUs") to directors, officers, or employees of the Fund. The
number of RTUs granted is based on the Fund's Trust Unit return for a
calendar year and compared to a peer group approved by the Board of
Directors. The Trust Unit return is calculated at the end of the year
and is primarily based on the year-over-year change in the Trust Unit
price plus distributions. The RTU grants vest one third immediately
on grant date, with the remaining two thirds vesting evenly on the
following two yearly anniversary dates. The holders of RTUs may elect
to receive cash upon vesting in lieu of the number of Trust Units to
be issued, subject to consent of the Fund. As the Fund did not meet
the 2007 or 2006 grant thresholds, there were no RTU grants made
during these years.
For the year ended December 31, 2007, the Fund has accrued unit-based
compensation expense of $0.9 million recorded in general and
administrative expense (December 31, 2006 - nil) and has capitalized
$0.3 million (December 31, 2006 - nil) related to Trust Units
issuable for the retention of certain employees of the Fund.
(e) Net income (loss) per Trust Unit
The calculation of basic and diluted net income (loss) per Trust Unit
are derived from both income (loss) available to Unitholders and
weighted average Trust Units outstanding calculated as follows:
Year ended Year ended
December 31, December 31,
2007 2006
---------------------------------------------------------------------
Income (loss) available to Unitholders
Basic and Diluted $ (7,535) $ 49,814
---------------------------------------------------------------------
Weighted average Trust Units outstanding
Basic 119,604,019 80,958,455
Trust Units Rights Incentive Plan -
Series A - 43,548
Trust Units Rights Incentive Plan -
Series B - 78,287
Management Internalization - 113,556
---------------------------------------------------------------------
Diluted 119,604,019 81,193,846
---------------------------------------------------------------------
The calculation of diluted net income per Trust Unit excludes all
series of convertible debentures for the years as the impact would be
anti-dilutive. Total weighted average Trust Units issuable in
exchange for the convertible debentures and excluded from the diluted
net income per Trust Unit calculation for the year ended December 31,
2007 were 9,083,663 (2006 - 7,182,276). As at December 31, 2007, the
total convertible debentures outstanding were immediately convertible
to 9,847,253 Trust Units (2006 - 8,334,453).
All of the Series B Trust Unit Rights and Management Internalization
escrowed Trust Units have been excluded from the calculation of
diluted net income per Trust Unit for the year ended December 31,
2007, as the impact would be anti-dilutive. Total weighted average
Trust Units issuable in exchange for the Series B Trust Unit Rights
and Management Internalization escrowed Trust Units and excluded from
the diluted net income per Trust Unit calculation for the year ended
December 31, 2007 were 42,918 and 582,861, respectively. All of the
remaining Series A Trust Unit Rights were exercised July 7, 2006.
Exchangeable Shares have been excluded from the calculation of
diluted net income per Trust Unit for the year ended December 31,
2006 as the impact would have been anti-dilutive. All of the
remaining Exchangeable Shares were redeemed May 9, 2006. 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 year ended December 31, 2006 were
36,448.
11. Accumulated Deficit
Accumulated deficit consists of accumulated income and accumulated
distributions for the Fund since inception as follows:
December 31, December 31,
2007 2006
---------------------------------------------------------------------
Accumulated Income $ 219,988 $ 227,523
Accumulated Distributions (879,823) (664,629)
---------------------------------------------------------------------
Accumulated Deficit $ (659,835) $ (437,106)
---------------------------------------------------------------------
The Fund has historically paid distributions in excess of accumulated
income as distributions are typically based on cash flows generated
in the period while accumulated income is based on such cash flows
less other non-cash charges such as depletion, depreciation, and
accretion expense recorded on the original investment in petroleum
and natural gas properties and management internalization expense.
For the year ended December 31, 2007 the Fund declared $215.2 million
in distributions representing $1.77 per distributable Trust Unit
(2006 - $217.2 million in distributions representing $2.66 per
distributable Trust Unit).
12. Financial Instruments
Financial instruments of the Fund include accounts receivable,
deposits, accounts payable and accrued liabilities, distributions
payable to Unitholders, bank indebtedness, convertible debentures and
derivative assets and liabilities.
Accounts receivable and deposits are classified as loans and
receivables and measured at amortized cost. Accounts payable and
accrued liabilities, distributions payable to Unitholders and bank
indebtedness are all classified as other liabilities and similarly
measured at amortized cost. As at December 31, 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 6) resulting in fair values that
will vary over time as market conditions change. As at December 31,
2007, the estimated fair value of the total outstanding convertible
debenture obligation was $215.4 million (December 31, 2006 -
$180.0 million). The fair value of the liability component of
convertible debentures was determined primarily based on a discounted
cash flow model assuming no future conversions and continuation of
current interest and principal payments as well as taking into
consideration the current public trading activity of such debentures.
The Fund applied discount rates of between 7 and 8% considering
current available market information, assumed credit adjustments, and
various terms to maturity.
Advantage has an established strategy to manage the risk associated
with changes in commodity prices by entering into derivatives, which
are recorded at fair value as derivative assets and liabilities with
gains and losses recognized through earnings. As the fair value of
the contracts varies with commodity prices, they give rise to
financial assets and liabilities. The fair values of the derivatives
are determined through valuation models completed by third parties.
Various assumptions based on current market information were used in
these valuations, including settled forward commodity prices,
interest rates, foreign exchange rates, volatility and other relevant
factors. The actual gains and losses realized on eventual cash
settlement can vary materially due to subsequent fluctuations in
commodity prices as compared to the valuation assumptions.
Credit Risk
Accounts receivable, deposits, and derivative assets are subject to
credit risk exposure and the carrying values reflect Management's
assessment of the associated maximum exposure to such credit risk.
Substantially all of the Fund's accounts receivable are due from
customers and joint operation partners concentrated in the Canadian
oil and gas industry. As such, accounts receivable are subject to
normal industry credit risks. Advantage mitigates such credit risk by
closely monitoring significant counterparties and dealing with a
broad selection of partners that diversify risk within the sector.
The Fund's deposits are primarily due from the Alberta Provincial
government and are viewed by Management as having minimal associated
credit risk. To the extent that Advantage enters derivatives to
manage commodity price risk, it may be subject to credit risk
associated with counterparties with which it contracts. Credit risk
is mitigated by entering into contracts with only stable,
creditworthy parties and through frequent reviews of exposures to
individual entities. In addition, the Fund generally enters into
derivative contracts with investment grade institutions that are
members of Advantage's credit facility syndicate to further mitigate
associated credit risk.
Liquidity Risk
The Fund is subject to liquidity risk attributed from accounts
payable and accrued liabilities, distributions payable to
Unitholders, bank indebtedness, convertible debentures, and
derivative liabilities. Accounts payable and accrued liabilities,
distributions payable to Unitholders and derivative liabilities are
primarily due within one year of the balance sheet date and Advantage
does not anticipate any problems in satisfying the obligations due to
the strength of cash provided by operating activities and the
existing credit facility. The Fund's bank indebtedness is subject to
a $710 million credit facility agreement 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 2008 to 2011 (note 6). Interest payments are made
semi-annually with excess cash provided by operating activities. As
the debentures become due, the Fund can satisfy the obligations in
cash or issue Trust Units at a price determined in the applicable
debenture agreements. This settlement alternative allows the Fund to
adequately manage liquidity, plan available cash resources and
implement an optimal capital structure.
To the extent that Advantage enters derivatives to manage commodity
price risk, it may be subject to liquidity risk as derivative
liabilities become due. While the Fund has elected not to follow
hedge accounting, derivative instruments are not entered for
speculative purposes and Management closely monitors existing
commodity risk exposures. As such, liquidity risk is mitigated since
any losses actually realized are subsidized by increased cash flows
realized from the higher commodity price environment.
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 year ended
December 31, 2007 could potentially have impacted net income by
approximately $3.0 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 December 31, 2007 could impact net income by
approximately $8.7 million for the year ended December 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 December 31,
2007 could impact net income by $3.7 million for the year ended
December 31, 2007. A change of 10% in the forward power prices used
to calculate the fair value of the power derivatives at December 31,
2007 could impact net income by $0.1 million for the year ended
December 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 December 31, 2007 the Fund had the following derivatives in
place:
Description of
Derivative Term Volume Average Price
---------------------------------------------------------------------
Natural gas - AECO
Fixed price November 2007 7,109 mcf/d Cdn$9.54/mcf
to March 2008
Fixed price April 2008 14,217 mcf/d Cdn$6.85/mcf
to October 2008
Fixed price April 2008 14,217 mcf/d Cdn$7.10/mcf
to March 2009
Fixed price April 2008 14,217 mcf/d Cdn$7.06/mcf
to March 2009
Fixed price November 2008 14,217 mcf/d Cdn$7.77/mcf
to March 2009
Collar November 2007 9,478 mcf/d Floor Cdn$8.44/mcf
to March 2008 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
Fixed price February 2008 2,000 bbls/d Cdn$90.93/bbl
to January 2009
Collar February 2008 2,000 bbls/d Sold put Cdn$70.00/bbl
to January 2009 Purchase call Cdn$105.00/bbl
Cost Cdn$1.52/bbl
Electricity - Alberta Pool Price
Fixed price January 2008 3.0 MW Cdn$54.00/MWh
to December 2008
As at December 31, 2007, the fair value of the derivatives
outstanding resulted in an asset of approximately $7,201,000
(December 31, 2006 - $10,433,000) and a liability of approximately
$5,020,000 (December 31, 2006 - nil). For the year ended December 31,
2007, $11,049,000 was recognized in income as an unrealized
derivative loss (December 31, 2006 - $10,242,000 unrealized
derivative gain) and $18,594,000 was recognized in income as a
realized derivative gain (December 31, 2006 - $5,297,000).
As a result of the Sound acquisition (note 3), the Fund assumed
several derivatives, which had an estimated net fair market value of
$2,797,000 on closing.
13. Management Fee, Performance Incentive, and Management Internalization
Concurrent with the Ketch acquisition (note 3), Advantage
internalized the external management contract structure and
eliminated all related fees. The Fund reached an agreement with
Advantage Investment Management Ltd. ("AIM" or the "Manager") to
purchase all of the outstanding shares of AIM pursuant to the terms
of the Plan of Arrangement for total original consideration of
1,933,208 Advantage Trust Units. The Trust Units were initially
valued at $39.1 million using the weighted average trading value for
Advantage Trust Units on the Unitholder approval date of June 22,
2006 and are subject to escrow provisions over a 3-year period,
vesting one-third each year beginning in 2007. The management
internalization consideration is being deferred and amortized into
income as management internalization expense over the specific
vesting periods during which employee services are provided,
including an estimate of future Trust Unit forfeitures. For the year
ended December 31, 2007, a total of 24,909 Trust Units issued for the
management internalization were forfeited (2006 - 19,366 Trust Units)
and $15.7 million has been recognized as management internalization
expense (2006 - $13.4 million). As at December 31, 2007, 1,193,622
Trust Units remain held in escrow (2006 - 1,822,098 Trust Units). The
Fund also issued 117,662 Trust Units to satisfy the final obligation
related to the 2006 first quarter performance fee along with
$0.9 million in cash to settle the first quarter management fee. AIM
agreed to forego fees from the period April 1, 2006 to the closing of
the Arrangement.
Prior to the internalization, 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. Management
fees were calculated based on 1.5% of operating cash flow defined as
revenues less royalties and operating costs and were paid quarterly.
The Manager of the Fund was also entitled to earn an annual
performance incentive fee when the Fund's total annual return
exceeded 8%. The total annual return was calculated at the end of the
year by dividing the year-over-year change in Unit price plus cash
distributions by the opening Unit price, as defined in the Management
Agreement. Ten percent of the amount of the total annual return in
excess of 8% was multiplied by the market capitalization (defined as
the opening Unit price multiplied by the weighted average number of
Trust Units outstanding during the year) to determine the performance
incentive fee. The Management Agreement provided an option to the
Manager to receive the performance incentive fee in equivalent Trust
Units. The Manager exercised the option and on January 20, 2006, the
Fund issued 475,263 Advantage Trust Units at the closing Unit price
of $22.19 to satisfy the 2005 performance fee obligation. The Manager
did not receive any form of compensation in respect of acquisition or
divestiture activities nor was there any form of stock option or
bonus plan for the Manager or the employees of Advantage outside of
the management and performance fees prior to the internalization. The
management fees and performance fees were shared amongst all
management and employees.
14. Commitments
Advantage has several lease commitments relating to office buildings.
The Fund has assumed office lease commitments from prior corporate
acquisitions and has renegotiated leases to accommodate the growth of
the Fund. The estimated annual minimum operating lease rental
payments for buildings are as follows:
2008 $ 5,319
2009 4,111
2010 4,127
2011 1,731
2012 1,314
---------------------------------------------------------------------
$ 16,602
---------------------------------------------------------------------
15. Reconciliation of Financial Statements to United States Generally
Accepted Accounting Principles
The consolidated financial statements of Advantage have been prepared
in accordance with accounting principles generally accepted in
Canada. Canadian GAAP, in most respects, conforms to generally
accepted accounting principles in the United States. Any differences
in accounting principles between Canadian GAAP and US GAAP, as they
apply to Advantage, are not material, except as described below.
(a) Unit-based compensation
Advantage accounts for compensation expense based on the fair value
of the equity awards on the grant date and the initial fair value is
not subsequently remeasured. Advantage's unit-based compensation
consists of a Trust Units Rights Incentive Plan, Trust Units held in
escrow subject to service requirement provisions, and Trust Units
issuable for the retention of certain employees of the Fund. The
initial fair value is expensed over the vesting period of the Trust
Units or rights granted.
Under US GAAP, the Fund adopted SFAS 123® "Share-Based Payment" on
January 1, 2006 using the modified prospective approach and applies
the fair value method of accounting for all Unit-based compensation
granted after January 1, 2006. A US GAAP difference exists as unit-
based compensation grants are considered liability awards for US GAAP
and equity awards for Canadian GAAP. Under US GAAP, the fair value of
a liability award is measured at the grant date and is subsequently
remeasured at each reporting period. When the rights are exercised
and the Trust Units vested, the amount recorded as a liability is
recognized as temporary equity and the fair value at adoption of the
new standard has been charged to income as the cumulative effect of a
change in accounting policy.
(b) Convertible debentures
The Fund applies CICA 3863 "Financial Instruments - Presentation" in
accounting for convertible debentures which results in their
classification as liabilities. The convertible debentures also have
an embedded conversion feature which must be segregated between
liabilities and equity, based on the relative fair market value of
the liability and equity portions. Therefore, the debenture
liabilities are presented at less than their eventual maturity
values. The liability and equity components are further reduced for
issuance costs initially incurred. The discount of the liability
component, net of issuance costs, as compared to maturity value is
accreted by the effective interest method over the debenture term. As
debentures are converted to Trust Units, an appropriate portion of
the liability and equity components are transferred to Unitholders'
capital. Interest and accretion expense on the convertible debentures
are shown on the Consolidated Statements of Income.
Under US GAAP, the entire convertible debenture balance would be
shown as a liability. The embedded conversion feature would not be
accounted for separately as a component of equity. Additionally,
under US GAAP, issuance costs are generally shown as a deferred
charge rather than netted from the convertible debenture balance. As
a result of these US GAAP differences, the convertible debenture
balance in liabilities represents the actual maturity value of the
outstanding debentures. Issuance costs are shown separately as a
deferred charge and are amortized to interest expense over the term
of the debenture. Given that the convertible debentures are carried
at maturity value, it is not necessary to accrete the balance over
the term of the debentures which results in an expense reduction.
Interest and accretion on convertible debentures represents interest
expense on the convertible debentures and amortization of the
associated deferred issuance costs.
(c) Depletion and depreciation
For Canadian GAAP, depletion of petroleum and natural gas properties
and depreciation of lease and well equipment is provided on
accumulated costs using the unit-of-production method based on
estimated net proved petroleum and natural gas reserves, before
royalties, based on forecast prices and costs.
US GAAP provides for a similar accounting methodology except that
estimated net proved petroleum and natural gas reserves are net of
royalties and based on constant prices and costs. Therefore,
depletion and depreciation under US GAAP will be different since
changes to royalty rates will impact both proved reserves and
production and differences between constant prices and costs as
compared to forecast prices and costs will impact proved reserve
volumes. Additionally, differences in depletion and depreciation will
result in divergence of net book value for Canadian GAAP and US GAAP
from year-to-year and impact future depletion and depreciation
expense as well as the net book value utilized for future ceiling
test calculations.
(d) Ceiling test
Under Canadian GAAP, petroleum and natural gas assets are evaluated
each reporting period to determine that the carrying amount is
recoverable and does not exceed the fair value of the properties in
the cost centre (the "ceiling test"). The carrying amounts are
assessed to be recoverable when the sum of the undiscounted net cash
flows expected from the production of proved reserves, the lower of
cost and market of unproved properties and the cost of major
development projects exceeds the carrying amount of the cost centre.
When the carrying amount is not assessed to be recoverable, an
impairment loss is recognized to the extent that the carrying amount
of the cost centre exceeds the sum of the discounted net cash flows
expected from the production of proved and probable reserves, the
lower of cost and market of unproved properties and the cost of major
development projects of the cost centre. The cash flows are estimated
using expected future product prices and costs and are discounted
using a risk-free interest rate. For Canadian GAAP purposes,
Advantage has not recognized an impairment loss since inception.
Under US GAAP, the carrying amounts of petroleum and natural gas
assets, net of deferred income taxes, shall not exceed an amount
equal to the sum of the present value of estimated net future after-
tax cash flows of proved reserves (at current prices and costs as of
the balance sheet date) computed using a discount factor of ten
percent plus the lower of cost or estimated fair value of unproved
properties. Any excess is charged to expense as an impairment loss.
Under US GAAP, Advantage recognized an impairment loss of
$49.5 million in 2001, $28.3 million net of tax, and an impairment
loss of $535.4 million in 2006, $477.8 million net of tax. The
impairment loss decreases net book value of property and equipment
which reduces depletion and depreciation expense subsequently
recorded as well as future ceiling test calculations.
(e) Income tax
The future income tax accounting standard under Canadian GAAP is
substantially similar to the deferred income tax approach as required
by US GAAP. Pursuant to Canadian GAAP, substantively enacted tax
rates are used to calculate future income tax, whereas US GAAP
applies enacted tax rates. However, there were no tax rate
differences for the years ended December 31, 2007 and 2006. The
differences between Canadian GAAP and US GAAP relate to future income
tax impact on GAAP differences for fixed assets.
Under US GAAP, an entity that is subject to income tax in multiple
jurisdictions is required to disclose income tax expense in each
jurisdiction. The total amount of income taxes in 2006 and 2007 is
entirely at the provincial level.
(f) Unitholders' equity
Unitholders' equity of Advantage consists primarily of Trust Units.
The Trust Units are redeemable at any time on demand by the holders,
which is required for the Fund to retain its Canadian mutual fund
trust status. The holders are entitled to receive a price per Trust
Unit equal to the lesser of: (i) 85% of the simple average of the
closing market prices of the Trust Units, on the principal market on
which the Trust Units are quoted for trading, during the 10 trading-
day period commencing immediately after the date on which the Trust
Units are surrendered for redemption; and (ii) the closing market
price on the principal market on which the Trust Units are quoted for
trading on the redemption date. For Canadian GAAP purposes, the Trust
Units are considered permanent equity and are presented as a
component of Unitholders' equity.
Under US GAAP, it is required that equity with a redemption feature
be presented as temporary equity between the liability and equity
sections of the balance sheet. The temporary equity is shown at an
amount equal to the redemption value based on the terms of the Trust
Units. Changes in the redemption value from year-to-year are charged
to deficit. All components of Unitholders' equity related to Trust
Units are eliminated. When calculating net income per Trust Unit,
increases in the redemption value during a period results in a
reduction of net income available to Unitholders while decreases in
the redemption value increases net income available to Unitholders.
For the years ended December 31, 2007 and 2006, net income available
to Unitholders was increased by $390.3 million and $898.0 million
corresponding to changes in the Trust Units redemption value for the
respective periods.
A continuity schedule of significant equity accounts for each
reporting period is required disclosure under US GAAP. The following
table is a continuity of deficit, the Fund's only significant equity
account:
Year ended Year ended
Deficit December 31, December 31,
(thousands of Canadian dollars) 2007 2006
---------------------------------------------------------------------
Balance, beginning of year $ (402,158) $ (665,627)
Net income (loss) and comprehensive income
(loss) 50,610 (417,274)
Distributions declared (215,194) (217,246)
Change in redemption value of temporary
equity 390,349 897,989
---------------------------------------------------------------------
Balance, end of year $ (176,393) $ (402,158)
---------------------------------------------------------------------
(g) Balance Sheet Disclosure
US GAAP requires disclosure of certain line items for balances that
would be aggregated in the Canadian GAAP financials. The following
are the additional line items to be disclosed for accounts receivable
and accounts payable:
December 31, December 31,
(thousands of Canadian dollars) 2007 2006
---------------------------------------------------------------------
Accounts receivable
Trade receivables $ 94,959 $ 78,698
Other receivables 515 839
---------------------------------------------------------------------
Total accounts receivable $ 95,474 $ 79,537
---------------------------------------------------------------------
December 31, December 31,
(thousands of Canadian dollars) 2007 2006
---------------------------------------------------------------------
Accounts payable and accrued liabilities
Accounts payable $ 72,691 $ 75,500
Accrued liabilities 48,994 39,999
Other payables 402 610
---------------------------------------------------------------------
Total accounts payable and accrued
liabilities $ 122,087 $ 116,109
---------------------------------------------------------------------
(h) Statements of cash flow
The differences between Canadian GAAP and US GAAP have not resulted
in any significant variances concerning the statements of cash flows
as reported.
(i) Ketch acquisition
On June 23, 2006, Advantage acquired all of the issued and
outstanding Trust Units of Ketch to benefit from an increase in
property diversification, the ability to pursue a greater range of
high impact growth opportunities available to a larger entity and
complimentary summer/winter drilling programs. The merger provides
increased liquidity and presence in the Canadian markets as well as
greater exposure to the United States capital markets for previous
Ketch Unitholders through Advantage's NYSE listing.
The purchase price for the acquisition and resulting goodwill is due
to both US and Canadian GAAP requiring the purchase price to be
determined using Trust Unit prices at the announcement date, while
the fair value of the assets and liabilities is determined at the
closing date of the acquisition. As commodity prices decreased
significantly between the announcement and closing dates, the fair
value of the assets acquired also decreased and as a result, goodwill
was recorded.
(j) Sound acquisition
On September 5, 2007, Advantage acquired all of the issued and
outstanding Trust Units and Exchangeable Shares of Sound. The
accounting for business combinations is effectively the same under US
and Canadian GAAP. However, the purchase price under US GAAP is
different as a result of AOG realizing a future income tax asset from
previously unrecognized temporary differences. The purchase price
under US GAAP has been allocated as follows:
Net assets acquired and liabilities
assumed: Consideration:
Fixed assets $ 480,226 16,977,184 Trust
Units issued $ 228,852
Future income tax asset 29,430 Cash 21,403
Accounts receivable 27,433 Acquisition costs
incurred 904
Prepaid expenses and ----------
deposits 3,873 $ 251,159
Derivative asset, net 2,797 ----------
Bank indebtedness (107,959)
Convertible debentures (101,553)
Accounts payable and
accrued liabilities (35,396)
Future income tax
liability (29,430)
Asset retirement
obligations (16,695)
Capital lease obligations (1,567)
----------
$ 251,159
----------
(k) Recent US Accounting Pronouncements Issued But Not Implemented
SFAS 157 Fair Value Measurements: This Statement defines fair value,
establishes a framework for measuring fair value in GAAP, and expands
disclosures about fair value measurements. This Statement applies
under other accounting pronouncements that require or permit fair
value measurements. Accordingly, this Statement does not require any
new fair value measurements. The implementation effective date for
this standard is as of the beginning of the first interim or annual
reporting period that begins after November 15, 2007. The Fund has
assessed the impact of this interpretation and does not anticipate
any significant impact on the consolidated financial statements.
SFAS 141 ® Business Combinations: This Statement requires assets
and liabilities acquired in a business combination, contingent
consideration, and certain acquired contingencies to be measured at
their fair values as of the date of acquisition. In addition,
acquisition-related and restructuring costs are to be recognized
separately from the business combination. This standard applies to
business combinations entered into after January 1, 2009. The Fund
has not yet assessed the full impact, if any, of this standard on the
consolidated financial statements.
The application of US GAAP would have the following effect on net
income as reported:
Consolidated Statements of Income and
Comprehensive Income Year ended Year ended
(thousands of Canadian dollars, December 31, December 31,
except for per Trust Unit amounts) 2007 2006
---------------------------------------------------------------------
Net income (loss) - Canadian GAAP, as
reported $ (7,535) $ 49,814
US GAAP Adjustments:
General and administrative - note 15(a) 606 1,453
Management internalization - note 15(a) 7,450 4,684
Interest and accretion on convertible
debentures - note 15(b) 1,741 1,254
Depletion, depreciation and accretion -
notes 15(c) and (d) 72,990 (528,734)
Future income tax reduction - note 15(e) (24,642) 55,526
---------------------------------------------------------------------
Net income (loss) before cumulative effect
of a change in accounting principle 50,610 (416,003)
Cumulative effect of a change in accounting
principle - note 15(a) - (1,271)
---------------------------------------------------------------------
Net income (loss) and comprehensive income
(loss) - US GAAP $ 50,610 $ (417,274)
---------------------------------------------------------------------
Net income (loss) per Trust Unit before
cumulative effect of a change in accounting
principle - US GAAP:
Basic $ 0.42 $ (5.14)
Diluted $ 0.42 $ (5.14)
Net income (loss) per Trust Unit before
change in redemption value of Trust Units -
US GAAP:
Basic $ 0.42 $ (5.15)
Diluted $ 0.42 $ (5.15)
Net income per Trust Unit - US GAAP:
Basic $ 3.69 $ 5.94
Diluted $ 3.54 $ 5.59
---------------------------------------------------------------------
The application of US GAAP would have the following effect on the
balance sheets as reported:
Consolidated Balance December 31, 2007 December 31, 2006
Sheets ----------------- -----------------
(thousands of Canadian US Canadian US
Canadian dollars) GAAP GAAP GAAP GAAP
---------------------------------------------------------------------
Assets
Deferred charge
- note 15(b) $ - $ 1,984 $ - $ 2,810
Fixed assets, net
- notes 15(c)
and (d) 2,177,346 1,673,251 1,753,058 1,205,465
Liabilities and
Unitholders'
Equity
Current portion of
convertible
debentures
- note 15(b) 5,333 5,392 1,464 1,485
Trust Unit
liability
- note 15(a) - 7,515 - 7,633
Convertible
debentures
- note 15(b) 212,203 219,674 170,819 179,245
Future income
taxes
- note 15(e) 66,727 - 61,939 -
Temporary equity
- note 15(f) - 1,104,831 - 1,067,790
Unitholders'
capital
- note 15(f) 2,027,065 - 1,592,758 -
Convertible
debentures
equity
component
- note 15(b) 9,632 - 8,041 -
Contributed
surplus
- note 15(a) 2,005 - 863 -
Accumulated
deficit
- note 15(f) (659,835) (176,393) (437,106) (402,158)
Advisory
The information in this release contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often, but not
always, identified by the use of words such as "seek", "anticipate", "plan",
"continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe",
"would" and similar expressions. These statements involve substantial known
and unknown risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are interpreted and
enforced; fluctuations in commodity prices and foreign exchange and interest
rates; stock market volatility and market valuations; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions, of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions; changes in income tax laws or changes in tax laws
and incentive programs relating to the oil and gas industry and income trusts;
geological, technical, drilling and processing problems and other difficulties
in producing petroleum reserves; and obtaining required approvals of
regulatory authorities. Advantage's actual results, performance or achievement
could differ materially from those expressed in, or implied by, such
forward-looking statements and, accordingly, no assurances can be given that
any of the events anticipated by the forward-looking statements will transpire
or occur or, if any of them do, what benefits that Advantage will derive from
them. Except as required by law, Advantage undertakes no obligation to
publicly update or revise any forward-looking statements.%SEDAR: 00016522E %CIK: 0001259995
For further information:
For further information: Investor Relations, Toll free: 1-866-393-0393, Advantage Energy Income Fund, 700, 400 -3rd Avenue SW, Calgary, Alberta, T2P 5E9, Phone: (403) 718-8100, Fax: (403) 718-8300, Web Site: www.advantageincome.com, E-mail: advantage@advantageincome.com