Advantage Announces Release of Fourth Quarter and Year Ended December 31, 2006 Financial Results and Reserves
(TSX: AVN.UN, NYSE: AAV)
CALGARY, March 22 /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, 2006.
A conference call will be held on Friday, March 23, 2007 at 9:00 a.m. MST
(11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-585-6398. A replay of the call will be available from approximately 2:00
p.m. EST on March 24, until approximately midnight, March 31, 2007 and can be
accessed by dialing toll free 1-866-245-6755. The passcode required for
playback is 587317. A live web cast of the conference call will be accessible
via the Internet on Advantage's website at www.advantageincome.com.
Merger of Advantage Energy Income Fund and Ketch Resources Trust- Advantage completed the largest transaction in its history by merging
with Ketch Resources Trust on June 23, 2006 adding production and
proven plus probable reserves of approximately 13,000 boe/d and
37.0 million boes respectively.
- Strong operational synergies were achieved by combining Advantage's
longer-life reserve base with Ketch's large undeveloped land base and
significant prospect inventory which has lead to increased
diversification, growth opportunities and complimentary winter/summer
drilling programs.
- In addition, the merger strengthened Advantage's executive, technical
and administrative groups through the addition of many of the key
personnel from Ketch.
Drilling Program and Reserves
- The integration of the Ketch assets was seamless as evidenced by the
strong operational execution throughout the year which resulted in
the drilling of 147 gross (90.2 net) wells in 2006 at a 95% success
rate. During the fourth quarter of 2006 a total of 44 gross
(25.1 net) wells were drilled at a 94% success rate.
- The Fund replaced 104% of its production through the drill bit with
favorable Finding & Development costs of $17.26 per proven plus
probable boe (excluding changes in future development capital).
- Our technical and operations group completed a review of the combined
asset base and have identified over 500 high quality drilling
locations (light oil and liquids rich natural gas focus) which
represents a four year drilling inventory.
- Overall, the Fund replaced 529% of annual production at an all-in
Finding, Development & Acquisition cost of $23.88 per proven plus
probable boe (excluding changes in future development capital).
- The Fund's proven plus probable reserve life index remains among the
highest in the natural gas weighted sector at 11.4 years.
Commodity Prices and Hedging
- Crude oil prices strengthened in 2006 due to continued global demand
growth while natural gas prices fell considerably due to the mild
2005 - 2006 winter experienced in North America.
- The decline in natural gas prices was one of the key factors leading
to lower cash distribution levels in 2006 due to our 67% natural gas
production weighting.
- The outlook for gas prices has since improved as a sustained cold
period through February 2007 has significantly reduced natural gas
inventories closer to historical levels. In addition, natural gas
supply in both the U.S. and Canada has struggled to increase despite
record levels of well completions in the last 3 years.
- The Fund has an active hedging program which has secured 48% of our
net natural gas production at an average floor price of $7.55/mcf and
14% of our oil production at an average floor price of US$65.00/bbl
for 2007.
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 which represented a major turnaround in policy, caught
the income trust investment community completely by surprise and
resulted in severe reductions in Unit prices.
- The final outcome of this policy change remains unknown at this time,
but Advantage remains in a strong position given our considerable tax
pool base of $1.2 billion which is available to shield future taxes.
- Based on the Fund's market capitalization at October 31, 2006
Advantage's safe harbour provides for the issuance of $1.6 billion of
new equity by 2011.
- We will continue to monitor the situation and will take the required
course of action to ensure that taxes are minimized for our
Unitholders.
Advantage is Well-positioned for 2007
- The October federal government announcement has caused a great deal
of upheaval in the trust sector which has resulted in a significant
contraction in Unit prices and the amount of capital available to the
sector.
- Advantage has responded by raising $110 million of new equity in
February, 2007 and reducing our payout ratio in order to strengthen
our balance sheet and enhance the sustainability of cash
distributions.
- We believe that the sector is entering a new environment that will be
characterized by the emergence of a "buyers market" for oil and gas
properties as well as a consolidation phase for royalty trusts and
junior E&Ps.
- Advantage is well positioned to capitalize on these opportunities as
we enter this new environment due to our:
- Long-life asset base and stable production platform,
- High quality, multi-year drilling inventory,
- Strong balance sheet,
- Considerable tax pool base,
- Moderate payout ratio supported by an active hedging program and
- Superior technical and administrative team that is highly
motivated to create Unitholder value.
2007 First Quarter Drilling Highlights
- Execution of the 2007 winter drilling program is on schedule and
costs are on-track.
- The largest component of the winter program is at Martin Creek in
Northeast British Columbia where results have exceeded expectations
with well deliverability in excess of expanded facilities capacity.
Drilling has also extended pool boundaries beyond last year's
interpretations setting up a strong drilling program for 2008.
- At Nevis, Alberta horizontal drilling for light oil in the new
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.
- At Chigwell, Alberta the Fund's first major Horseshoe Canyon coalbed
methane project involving 28 gross wells was successfully completed
and brought on-stream in early January at production rates which were
higher than forecast. Advantage has not aggressively pursued coalbed
methane development on its land base which has over 250 locations in
the heart of the Horseshoe Canyon fairway.
- To date 30 gross (18.2 net) wells have been drilled in 2007 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.
Financial and Operating Highlights
Year ended
December 31, 2006 2005 2004 2003 2002
-------------------------------------------------------------------------
Financial ($000)
Revenue before
royalties 419,727 376,572 241,481 166,075 97,837
per Unit(1) 5.18 6.65 5.89 5.44 3.64
per boe 47.80 51.27 38.92 36.81 24.85
Funds from
operations 214,758 211,541 126,478 94,735 52,537
per Unit(1) 2.63 3.72 3.05 3.09 1.94
per boe 24.77 28.80 20.39 21.01 13.34
Net income 49,814 75,072 24,038 38,503 10,910
per Unit(1) 0.62 1.33 0.59 1.26 0.41
Cash distributions 217,246 177,366 117,655 83,382 46,883
per Unit(2) 2.66 3.12 2.82 2.71 1.73
Payout ratio(3) 101% 84% 93% 88% 89%
Working capital
deficit 42,655 31,612 56,408 47,143 21,515
Bank indebtedness 410,574 252,476 267,054 102,968 114,222
Convertible
debentures 180,730 135,111 148,450 99,984 55,000
Operating
Daily Production
Natural gas
(mcf/d) 94,074 78,561 77,188 57,631 47,753
Crude oil and
NGLs (bbls/d) 8,075 7,029 4,084 2,756 2,828
Total boe/d
at 6:1 23,754 20,123 16,949 12,361 10,787
Average pricing
(including hedging)
Natural gas
($/mcf) 6.86 7.98 6.08 6.07 3.71
Crude oil &
NGLs ($/bbl) 62.44 57.58 46.58 38.14 32.07
Proved plus probable
reserves(4)
Natural gas (bcf) 442.7 286.9 296.9 237.4 223.1
Crude oil &
NGLs (mbbls) 47,524 36,267 34,316 13,697 13,995
Total mboe 121,317 84,082 83,799 53,271 51,180
Reserve life
index(5) 11.4 12.0 9.9 9.1 10.9
Supplemental (000)
Trust Units
outstanding at
end of year 105,390 57,846 49,675 36,717 27,099
Trust Units
issuable
Convertible
Debentures 8,334 6,819 7,602 6,155 4,135
Exchangeable
Shares - 122 1,450 - -
Trust Unit Rights
Incentive Plan 188 310 310 140 175
Trust Units
outstanding and
issuable at end
of year 113,912 65,097 59,037 43,012 31,409
Basic weighted
average Trust
Units 80,958 56,593 41,008 30,536 26,900
(1) based on basic weighted average Trust Units outstanding
(2) based on number of Trust Units outstanding at each cash distribution
record date
(3) payout ratio represents the cash distributions declared for the
period as a percentage of funds from operations
(4) 2006, 2005 and 2004 represents company interest reserves with prior
years being gross working interest reserves. 2002 reserves represent
proved plus 50% of probable reserves
(5) based on fourth quarter 2006 average production rates
RESERVESAdvantage's year end reserve evaluation is based on an independent
engineering study conducted by Sproule Associates Limited ("Sproule")
effective December 31, 2006 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 available at
www.advantageincome.com or www.sedar.com.
Highlights - Company Interest Reserves (Working Interests plus Royalty
Interests Receivable)- The Fund's net asset value at December 31, 2006 is $17.92 per Unit,
(using a 5% discount factor).
- Proved plus probable ("P+P") reserve life index remains among the
highest in the gas weighted sector at 11.4 years.
- Replaced 104% of annual production through the drill bit at an all-in
Finding and Development ("F&D") cost of $17.26 per P+P boe before
consideration of future development capital. Including future
development capital, the F&D cost was $20.93 per P+P boe.
- Replaced 529% of annual production at an all-in Finding, Development
& Acquisition ("FD&A") cost of $23.88 per P+P boe before
consideration of future development capital. Including future
development capital, the FD&A cost was $24.62 per P+P boe. This
includes the acquisition of Ketch Resources Trust, which was
effective June 23, 2006.
December 31, December 31,
2006 2005
-------------------------------------------------------------------------
Proved plus probable reserves (mboe) 121,317 84,082
Present Value of reserves discounted at 5%,
proved plus probable ($000) $2,445,236 $1,814,159
Fund Net Asset Value per Unit discounted at 5% $17.92 $24.46
Reserve Life Index (proved plus probable
- years)(1) 11.4 12.0
Reserves per Unit (proved plus probable)(2) 1.15 1.42
Bank debt per boe of reserves(3) $3.38 $3.00
Convertible debentures per boe of reserves(3) $1.49 $1.61
(1) Based on Q4 average production.
(2) Based on 58.75 million Units and Trust Unit Rights outstanding at
December 31, 2005, and 105.58 million Units and Trust Unit Rights
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, 2006
Light & Natural
Medium Heavy Gas Natural Oil
Oil Oil Liquids Gas Equivalent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed Producing 16,021 1,926 6,289 255,344 66,794
Developed Non-
producing 474 0 242 11,643 2,656
Undeveloped 3,513 0 881 27,970 9,056
Total Proved 20,008 1,926 7,412 294,957 78,506
-------------------------------------------------------------------------
Probable 13,631 693 3,854 147,802 42,811
Total Proved +
Probable 33,639 2,619 11,266 442,759 121,317
-------------------------------------------------------------------------
Gross Working Interest Reserves - Summary as at December 31, 2006
Light & Natural
Medium Heavy Gas Natural Oil
Oil Oil Liquids Gas Equivalent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed Producing 15,949 1,908 6,252 253,286 66,324
Developed Non-
producing 473 0 241 11,523 2,635
Undeveloped 3,513 0 882 27,970 9,056
Total Proved 19,935 1,908 7,375 292,779 78,015
-------------------------------------------------------------------------
Probable 13,586 688 3,833 146,566 42,534
Total Proved +
Probable 33,521 2,596 11,208 439,345 120,549
-------------------------------------------------------------------------
Present Value of Future Net Revenue using Sproule price and cost
forecasts(1)
($000)
Before Income Taxes Discounted at
0% 5% 10%
-------------------------------------------------------------------------
Proved
Developed Producing $2,110,371 $1,495,671 $1,200,133
Developed Non-producing 70,588 57,401 48,211
Undeveloped 184,664 146,958 111,997
Total Proved 2,365,623 1,700,030 1,360,341
-------------------------------------------------------------------------
Probable 1,395,504 745,206 489,732
Total Proved + Probable $3,761,127 $2,445,236 $1,850,073
-------------------------------------------------------------------------
(1) Advantage's crude oil, natural gas and natural gas liquid reserves
were evaluated using Sproule's product price forecast effective
December 31, 2006 prior to the provision for income taxes, interests,
debt services charges and general and administrative expenses. It
should not be assumed that the discounted future revenue estimated by
Sproule represents the fair market value of the reserves.
Sproule Price Forecasts
The present value of future net revenue at December 31, 2006 was based
upon crude oil and natural gas pricing assumptions prepared by Sproule
effective December 31, 2006. These forecasts are adjusted for reserve quality,
transportation charges and the provision of any applicable sales contracts.
The price assumptions used over the next seven years are summarized in the
table below:
Alberta Henry
WTI Edmonton Plantgate Hub
Crude Light Natural Natural Exchange
Oil Crude Oil Gas Gas Rate
($US/ ($Cdn/ ($Cdn ($US/ ($US/
Year bbl) bbl) /mmbtu) mmbtu) $Cdn)
------------------------------------------------------------------------
2007 65.73 74.10 7.47 7.85 0.87
2008 68.82 77.62 8.36 8.39 0.87
2009 62.42 70.25 7.53 7.65 0.87
2010 58.37 65.56 7.35 7.48 0.87
2011 55.20 61.90 7.52 7.63 0.87
2012 56.31 63.15 7.65 7.75 0.87
2013 57.43 64.42 7.80 7.86 0.87
Net 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(1)
- December 31, 2005 $ 38.29 $ 24.46 $ 17.79
-------------------------------------------------------------------------
Present value proved and probable
reserves $3,761,127 $2,445,236 $1,850,073
Undeveloped acreage and seismic(2) 50,520 50,520 50,520
Working capital (deficit) and other (12,093) (12,093) (12,093)
Convertible debentures (180,730) (180,730) (180,730)
Bank debt (410,574) (410,574) (410,574)
Net asset value - December 31, 2006 $3,208,250 $1,892,359 $1,297,196
-------------------------------------------------------------------------
Net asset value per Unit (1) -
December 31, 2006 $ 30.39 $ 17.92 $ 12.29
-------------------------------------------------------------------------
(1) Based on 58.75 million Units and Trust Unit Rights outstanding at
December 31, 2005, and 105.58 million Units and Trust Unit Rights
outstanding at December 31, 2006.
(2) Internal estimate
Gross Working Interest Reserves Reconciliation
Light & Natural
Medium Heavy Gas Natural Oil
Oil Oil Liquids Gas Equivalent
Proved (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2005 15,558 1,720 3,747 195,534 53,613
Extensions 40 0 174 6,420 1,284
Improved recovery 2,327 167 275 4,536 3,525
Discoveries 53 0 0 5 54
Economic factors (249) (27) (60) (3,129) (859)
Technical revisions 1,747 342 156 4,930 3,068
Acquisitions 2,455 0 3,741 119,212 26,065
Dispositions 0 0 0 (392) (65)
Production (1,996) (294) (658) (34,337) (8,670)
-------------------------------------------------------------------------
Closing balance at
Dec. 31, 2006 19,935 1,908 7,375 292,779 78,015
-------------------------------------------------------------------------
Light & Natural
Medium Heavy Gas Natural Oil
Oil Oil Liquids Gas Equivalent
Proved + Probable (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2005 27,470 2,677 5,953 283,547 83,358
Extensions 118 0 258 10,760 2,169
Improved recovery 4,289 240 504 8,044 6,374
Discoveries 94 0 0 14 96
Economic factors (440) (43) (95) (4,537) (1,334)
Technical revisions 1,121 16 54 2,939 1,680
Acquisitions 2,865 0 5,192 173,456 36,966
Dispositions 0 0 0 (541) (90)
Production (1,996) (294) (658) (34,337) (8,670)
-------------------------------------------------------------------------
Closing balance at
Dec. 31, 2006 33,521 2,596 11,208 439,345 120,549
-------------------------------------------------------------------------
Finding, Development & Acquisitions Costs ("FD&A")(1)
FD&A Costs - Gross Working Interest Reserves excluding Future
Development Capital
Proved +
Proved Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 155,091 $ 155,091
Acquisitions net of dispositions ($000) 940,155 940,155
-------------------------------------------------------------------------
Total capital ($000) $1,095,246 $1,095,246
-------------------------------------------------------------------------
Total mboe, end of period 78,015 120,549
Total mboe, beginning of period 53,613 83,358
Production, mboe 8,670 8,670
-------------------------------------------------------------------------
Reserve additions, mboe 33,072 45,861
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 33.12 $ 23.88
Three year average FD&A Costs ($/boe) $ 27.01 $ 18.56
F&D costs ($/boe) $ 21.93 $ 17.26
Three year average F&D costs ($/boe) $ 25.46 $ 17.24
NI 51-101
FD&A Costs - Gross Working Interest Reserves including Future
Development Capital
Proved +
Proved Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 155,091 $ 155,091
Acquisitions net of dispositions ($000) 940,155 940,155
Net change in Future Development Capital 324 34,045
-------------------------------------------------------------------------
Total capital ($000) $1,095,570 $1,129,291
-------------------------------------------------------------------------
Reserve additions, mboe 33,072 45,861
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 33.13 $ 24.62
Three year average FD&A Costs ($/boe) $ 27.74 $ 19.74
F&D costs ($/boe) $ 21.97 $ 20.93
Three year average F&D costs ($/boe) $ 28.12 $ 21.54
(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, 2006
Developed Acres Undeveloped Acres
Gross Net Gross Net
-------------------------------------------------------------------------
Alberta 907,997 438,611 541,547 260,910
British Columbia 169,584 72,330 122,835 68,854
Saskatchewan 32,978 23,969 94,194 78,413
-------------------------------------------------------------------------
Total Acreage 1,110,559 534,910 758,576 408,177
-------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION & ANALYSISThe following Management's Discussion and Analysis ("MD&A"), dated as of
March 21, 2007, provides a detailed explanation of the financial and operating
results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we"
or "our") for the quarter and year ended December 31, 2006 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 and per Trust Unit, cash netbacks, and payout
ratio. Management believes that these financial measures are useful
supplemental information to analyze operating performance, leverage and
provide an indication of the results generated by the Fund's principal
business activities prior to the consideration of how those activities are
financed or how the results are taxed. Investors should be cautioned that
these measures should not be construed as an alternative to net income, cash
provided by operating activities or other measures of financial performance as
determined in accordance with GAAP. Advantage's method of calculating these
measures may differ from other companies, and accordingly, they may not be
comparable to similar measures used by other companies.
Funds from operations, as presented, is based on cash provided by
operating activities before expenditures on asset retirement and changes in
non-cash working capital. Funds from operations per Trust Unit is based on the
number of Trust Units outstanding at each cash distribution record date. Both
cash netbacks and payout ratio are dependent on the determination of funds
from operations. Cash netbacks include the primary cash revenues and expenses
on a per boe basis that comprise funds from operations. Payout ratio
represents the cash distributions declared for the period as a percentage of
funds from operations. Funds from operations reconciled to cash provided by
operating activities is as follows:Three months ended Year ended
December 31 December 31
($000) 2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Cash provided
by operating
activities $ 65,495 $ 70,117 (7)% $229,087 $186,606 23%
Expenditures
on asset
retirement 3,462 445 678% 5,974 2,025 195%
Changes in
non-cash
working
capital (6,220) (9,656) (36)% (20,303) 22,910 (189)%
-------------------------------------------------------------------------
Funds from
operations $ 62,737 $ 60,906 3% $214,758 $211,541 2%
-------------------------------------------------------------------------Forward-Looking Information
The information in this report contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often, but not
always, identified by the use of words such as "seek", "anticipate", "plan",
"continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe",
"would" and similar expressions. These statements involve substantial known
and unknown risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are interpreted and
enforced; fluctuations in commodity prices and foreign exchange and interest
rates; stock market volatility and market valuations; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions; changes in income tax laws or changes in tax laws
and incentive programs relating to the oil and gas industry and income trusts;
geological, technical, drilling and processing problems and other difficulties
in producing petroleum reserves; obtaining required approvals of regulatory
authorities and other risk factors set forth in Advantage's Annual Information
Form which will be 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.
Merger with Ketch Resources Trust
On June 22, 2006, the previously announced merger of Advantage and Ketch
Resources Trust ("Ketch") was approved by 96.6% of the votes cast at the
Advantage Unitholder meeting and 88.4% of the votes cast at the Ketch
Unitholder meeting. Court approval was received on June 22, 2006 with closing
of the Arrangement and the successful merger of the two trusts occurring the
following day. The financial and operational information for the year ended
December 31, 2006 reflect operations from the Ketch properties effective the
closing date, June 23, 2006. The combined trust is managed by an experienced
senior management team which includes key management, technical personnel and
administrative employees from both Advantage and Ketch. The merger was
accomplished through the exchange of each Ketch Unit for 0.565 of an Advantage
Unit and upon completion, Advantage Unitholders owned approximately 65% of the
combined trust and Ketch Unitholders owned approximately 35%.
The merger was conditional on Advantage internalizing the external
management contract structure and eliminating 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 initially valued at $39.1 million using the
weighted average trading value for June 22, 2006 of $20.23 per Advantage Trust
Unit. The Trust Unit consideration was placed in escrow for a 3-year period
ensuring Advantage Unitholders will receive continued benefit and commitment
of the existing management team and employees. The Fund paid final management
fees and performance fees for the period January 1 to March 31, 2006 in the
amount of $3.3 million. The consideration to settle the fees consisted of
$0.9 million in cash and 117,662 Trust Units. AIM agreed to forego fees for
the period April 1, 2006 to the closing of the Arrangement.Overview
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Funds from
operations
($000) $ 62,737 $ 60,906 3% $214,758 $211,541 2%
per Trust
Unit(1) $ 0.59 $ 1.06 (44)% $ 2.63 $ 3.72 (29)%
Net income
($000) $ 8,736 $ 25,846 (66)% $ 49,814 $ 75,072 (34)%
per Trust
Unit
- Basic $ 0.08 $ 0.45 (82)% $ 0.62 $ 1.33 (53)%
- Diluted $ 0.08 $ 0.45 (82)% $ 0.61 $ 1.32 (54)%
(1) Based on Trust Units outstanding at each cash distribution record
date.Funds from operations increased 3% for the three months and 2% for the
year ended December 31, 2006, as compared to the same periods of 2005. Funds
from operations per Trust Unit decreased 44% and 29% respectively. The slight
increase in funds from operations has been primarily due to the Ketch merger.
However, both funds from operations and funds from operations per Trust Unit
have been negatively impacted by significantly lower natural gas prices
throughout 2006. Weak natural gas prices have been partially offset by a
successful hedging program that was implemented in November 2006. Net income
decreased 66% for the three months ended December 31, 2006, as compared to
2005 and 34% for the year ended December 31, 2006. Net income per basic Trust
Unit decreased 82% for the three months and 53% for the year ended
December 31, 2006. The lower net income has been primarily due to the lower
natural gas prices realized during the periods, amortization of the management
internalization consideration, and increased depletion and depreciation
expense. The primary factor that causes significant variability of Advantage's
funds from operations, cash flows 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.Cash Distributions
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Cash
distributions
declared
($000) $ 58,791 $ 43,265 36% $217,246 $177,366 22%
per Trust
Unit(1) $ 0.56 $ 0.75 (25)% $ 2.66 $ 3.12 (15)%
Payout
ratio (%) 94% 71% 23% 101% 84% 17%
(1) Based on Trust Units outstanding at each cash distribution record
date.Total distributions increased 36% for the three months and 22% for the
year ended December 31, 2006. The higher total distributions reflect the
increased Trust Units outstanding from the continued growth and development of
the Fund, especially due to the Ketch acquisition. Natural gas prices were
very weak during the fourth quarter and year resulting in reduced funds from
operations and a higher payout ratio of 94% and 101%, respectively. As a
result, we reduced the distribution level during the last half of 2006 to more
appropriately reflect the current commodity price environment. Cash
distributions per Trust Unit were $0.56 for the three months and $2.66 for the
year ended December 31, 2006 representing decreases of 25% and 15%
respectively, as compared to the same periods of 2005. In January 2007, the
monthly distribution was further decreased to $0.15 as natural gas prices
continued to show prolonged weakness throughout the winter. To mitigate the
persisting risk associated with lower natural gas prices and the resulting
negative impact on distributions, the Fund implemented a hedging program in
2006 with 58% of natural gas hedged for January to March 2007 and 54% hedged
for April to October 2007. See "Commodity Price Risk" section for a more
detailed discussion of our price risk management. It is also important to note
that the timing of the Ketch merger negatively impacted the payout ratio for
the year ended December 31, 2006 as the arrangement closed prior to the June
record date resulting in the payment of a full month distribution to Ketch
Unitholders; however funds from operations for June only included eight days
of cash flows from the Ketch properties. We believe the Fund has taken the
necessary action and is now well-positioned with the objective of providing
long-term distribution sustainability to Unitholders.
Cash distributions are determined by Management and the Board of
Directors. We closely monitor our distribution policy considering forecasted
cash flows, optimal debt levels, capital spending activity, taxability to
Unitholders, working capital requirements, and other potential cash
expenditures. Cash distributions are announced monthly and are based on the
cash available after retaining a portion to meet such spending requirements.
The level of cash 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 cash distributions will decline over time
in a manner consistent with declining production from typical oil and natural
gas reserves. Therefore, cash distributions are highly dependent upon our
success in exploiting the current reserve base and acquiring additional
reserves. Furthermore, monthly cash distributions we pay to Unitholders are
highly dependent upon the prices received for 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 cash 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 holders of Advantage Trust Units, the distributions paid for
2006 were 50% non-taxable return of capital and 50% taxable. For U.S.
unitholders, distributions paid during 2006 were 47% non-taxable return of
capital and 53% 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) 2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Natural gas
excluding
hedging $ 74,309 $ 78,001 (5)% $231,548 $238,902 (3)%
Realized
hedging
gains (losses) 4,046 (6,749) (160)% 4,164 (10,063) (141)%
-------------------------------------------------------------------------
Natural gas
including
hedging $ 78,355 $ 71,252 10% $235,712 $228,839 3%
-------------------------------------------------------------------------
Crude oil
and NGLs
excluding
hedging $ 48,051 $ 39,318 22% $182,882 $151,639 21%
Realized
hedging
gains (losses) 1,133 (398) (385)% 1,133 (3,906) (129)%
-------------------------------------------------------------------------
Crude oil
and NGLs
including
hedging $ 49,184 $ 38,920 26% $184,015 $147,733 25%
-------------------------------------------------------------------------
Total revenue $127,539 $110,172 16% $419,727 $376,572 11%
-------------------------------------------------------------------------Natural gas revenues, excluding hedging, have decreased 5% for the three
months and 3% for the year ended December 31, 2006, compared to 2005. Natural
gas revenues have increased due to additional production from the Ketch merger
but have been more than offset by weak natural gas prices. However, due to the
Fund's hedge positions that were in place for the latter part of 2006, natural
gas revenues, including hedging, have increased 10% for the three months and
3% for the year ended December 31, 2006. Crude oil and NGL revenues, excluding
hedging, have increased by 22% for the three months and 21% for the year ended
December 31, 2006 compared to 2005 due to a combination of continued strong
oil prices and increased production levels from Ketch. The Fund had several
oil hedges that came into effect in October 2006, further increasing crude oil
and NGL revenues 26% for the three months and 25% for the year ended
December 31, 2006, as compared to 2005.Production
Three months ended Year ended
December 31 December 31
($000) 2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Natural gas
(mcf/d) 117,134 72,587 61% 94,074 78,561 20%
Crude oil
(bbls/d) 7,148 5,900 21% 6,273 5,854 7%
NGLs (bbls/d) 2,422 1,206 101% 1,802 1,175 53%
-------------------------------------------------------------------------
Total (boe/d) 29,092 19,204 51% 23,754 20,123 18%
-------------------------------------------------------------------------
Natural gas (%) 67% 63% 66% 65%
Crude oil (%) 25% 31% 26% 29%
NGLs (%) 8% 6% 8% 6%The Fund's total daily production averaged 29,092 boe/d for the fourth
quarter of 2006, an increase of 51% compared with the same period of 2005.
Natural gas production increased 61%, crude oil production increased 21%, and
NGLs production increased 101%. Average daily production for the year ended
December 31, 2006 was 23,754 boe/d, an increase of 18% compared with
December 31, 2005. During this same period natural gas production increased
20%, crude oil production increased 7% and NGLs production increased 53%.
The increase in production during the quarter and year has been primarily
attributed to the Ketch acquisition, which closed June 23, 2006. Other key
production additions included light oil production from our Nevis and Sunset
properties located in Central Alberta of 500 boe/d and gas additions of
3.5 mmcf/d realized from our Sweetgrass and Chigwell properties. An additional
5.0 mmcf/d was placed onstream in July from the Westerose-Battle Lake area.
The additions have been offset somewhat by further capacity constraints at
third party facilities, a one-time adjustment recognizing the impact of
several wells that had paid out whereby partners had elected to convert to
working interest positions and pipeline curtailments. The curtailment on the
main northern leg of the Trans Canada Pipeline system impacted most of our
Northern Alberta areas and resulted in a loss of 150 boe/d for the year. In
addition, significant adverse production impacts occurred in November and
December due to the extreme cold weather conditions at Fontas and Martin
Creek, a compressor failure at Worsley, battery outages at Nevis and Westerose
and high declines at our Hamelin Creek property. Production has also been
impacted by maximum rate limitations ("MRL") initiated on our Chip Lake and
Nevis properties beginning January 1, 2006. At the close of 2006 our Chigwell
North coal bed methane joint venture and our new gas pool at Sweetgrass were
placed onstream. The Chigwell North and Sweetgrass wells were delayed
primarily due to regulatory delays in each respective area, but the
regulations have since been satisfied and production began in late December.Commodity Prices and Marketing
Natural Gas
Three months ended Year ended
December 31 December 31
($/mcf) 2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Realized
natural gas
prices
Excluding
hedging $ 6.90 $ 11.68 (41)% $ 6.74 $ 8.33 (19)%
Including
hedging $ 7.27 $ 10.67 (32)% $ 6.86 $ 7.98 (14)%
AECO monthly
index $ 6.36 $ 11.68 (46)% $ 6.98 $ 8.49 (18)%Realized natural gas prices, excluding hedging, decreased 41% for the
three months and 19% for the year ended December 31, 2006, as compared to the
same periods of 2005. The price of natural gas is primarily based on supply
and demand fundamentals in the North American marketplace. Natural gas prices
began to weaken near the end of 2005 as North America recorded one of the
mildest winters on record, thereby reducing demand. This weakness has
continued through 2006 with relatively uneventful weather resulting in natural
gas inventories that swelled to historic levels. The 2006/2007 winter has also
been mild, with inventory levels remaining high, causing significant downward
pressure on commodity prices. However, February 2007 brought sustained colder
weather and inventory levels decreased below 2006 levels but are still ample
compared to demand. The withdrawals from inventories resulted in a modest
rebound in natural gas prices but overall the prices still remain low due to
weather uncertainty. We continue to believe that the long-term pricing
fundamentals for natural gas remain strong. These fundamentals include (i) the
continued strength of crude oil prices, which has eliminated the economic
advantage of fuel switching away from natural gas, (ii) long-term tightness in
supply that has resulted from persistent demand and the decline in North
American natural gas production levels and (iii) ongoing weather related
factors such as hot summers, cold winters and annual hurricane season in the
Gulf of Mexico, all of which have an impact on the delicate supply/demand
balance that exists.Crude Oil and NGLs
Three months ended Year ended
December 31 December 31
($/bbl) 2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Realized crude
oil prices
Excluding
hedging $ 56.10 $ 61.11 (8)% $ 63.85 $ 61.02 5%
Including
hedging $ 57.82 $ 60.37 (4)% $ 64.34 $ 59.20 9%
Realized
NGLs prices
Excluding
hedging $ 50.09 $ 55.42 (10)% $ 55.81 $ 49.54 13%
Realized crude
oil and NGLs
prices
Excluding
hedging $ 54.58 $ 60.14 (9)% $ 62.05 $ 59.10 5%
Including
hedging $ 55.86 $ 59.53 (6)% $ 62.44 $ 57.58 8%
WTI ($US/bbl) $ 60.21 $ 60.04 0% $ 66.35 $ 56.61 17%
$US/$Canadian
exchange
rate $ 0.88 $ 0.85 4% $ 0.88 $ 0.83 6%Realized crude oil and NGLs prices, excluding hedging, decreased 9% for
the three months and increased 5% for the year ended December 31, 2006, as
compared to the same periods of 2005. Advantage's crude oil prices are based
on the benchmark pricing of West Texas Intermediate Crude ("WTI") adjusted for
quality, transportation costs and $US/$Canadian exchange rates. Advantage's
realized crude oil price has not changed to the same extent as WTI due to
strengthening of the Canadian dollar and the widening of Canadian crude oil
differentials relative to WTI. The price of WTI fluctuates based on worldwide
supply and demand fundamentals. There has been significant price volatility
experienced over the last several years whereby WTI has reached historic high
levels. For the three months ended December 31, 2006 WTI has remained
relatively stable and increased 17% for the year ended December 31, 2006,
compared to 2005. Many developments have resulted in the current price levels,
including significant geopolitical and weather related issues. Early in 2006,
prices remained strong due to concerns regarding the lack of North American
refining capacity, and the continued strength of global demand. However, the
mild 2005/2006 winter and the surge in crude imports to North America have
resulted in significantly higher inventories, which prompted the relative
price decrease towards the end of 2006. These key issues persist and will
continue to impact overall commodity prices. With the current softening of
crude price levels, it is notable that production restrictions are frequently
being considered by the OPEC cartel and that inventory levels can quickly
decline. 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 cash 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 financial derivatives. These commodity risk
management activities could expose Advantage to losses or gains. To the extent
that Advantage engages in risk management activities related to commodity
prices, it will be subject to credit risk associated with counterparties with
which it contracts. Credit risk is mitigated by entering into contracts with
only stable, creditworthy parties and through frequent reviews of exposures to
individual entities.Currently, the Fund has the following financial derivatives in place:
Description
of Financial
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Fixed price November 2006
to March 2007 5,687 mcf/d Cdn$8.70/mcf
Fixed price November 2006
to March 2007 3,791 mcf/d Cdn$10.02/mcf
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.16/mcf
Fixed price April 2007 to
October 2007 9,478 mcf/d Cdn$7.55/mcf
Collar November 2006
to March 2007 9,478 mcf/d Floor Cdn$8.18/mcf
Ceiling Cdn$11.24/mcf
Collar November 2006
to March 2007 4,739 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$12.40/mcf
Collar November 2006
to March 2007 4,739 mcf/d Floor Cdn$8.18/mcf
Ceiling Cdn$11.66/mcf
Collar November 2006
to March 2007 4,739 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$12.29/mcf
Collar November 2006
to March 2007 5,687 mcf/d Floor Cdn$7.91/mcf
Ceiling Cdn$9.81/mcf
Collar November 2006
to March 2007 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$13.82/mcf
Collar November 2007
to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$10.29/mcf
Crude oil - WTI
Collar October 2006
to March 2007 1,250 bbls/d Floor US$65.00/bbl
Ceiling US$87.40/bbl
Collar October 2006 to
September 2007 1,000 bbls/d Floor US$65.00/bbl
Ceiling US$90.00/bbl
In addition, the Fund has the following physical natural gas contracts in
place:
Description
of Physical
Contract Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Collar November 2006
to March 2007 4,739 mcf/d Floor Cdn$8.07/mcf
Ceiling Cdn$11.61/mcf
Collar April 2007 to
October 2007 4,739 mcf/d Floor Cdn$7.12/mcf
Ceiling Cdn$8.67/mcf
Collar April 2007 to
October 2007 4,739 mcf/d Floor Cdn$6.86/mcf
Ceiling Cdn$9.13/mcf
Collar April 2007 to
October 2007 9,478 mcf/d Floor Cdn$7.39/mcf
Ceiling Cdn$9.63/mcf
Collar April 2007 to
October 2007 9,478 mcf/d Floor Cdn$6.33/mcf
Ceiling Cdn$7.20/mcfAs at December 31, 2006 the settlement amount of the financial
derivatives outstanding was an asset of approximately $10,433,000. For the
year ended December 31, 2006, $10,242,000 was recognized in income as an
unrealized derivative gain. As a result of the Ketch merger, we assumed
several of these contracts which had an estimated fair value of $191,000 on
closing. Recorded in revenue are realized hedging gains of $5.2 million for
the three months and $5.3 million for the year ended December 31, 2006, which
partially alleviated lower revenue from reduced commodity prices. The Fund
does not apply hedge accounting and current accounting standards require
changes in the fair value to be included in the income statement as an
unrealized derivative gain or loss with a corresponding derivative asset or
liability recorded on the balance sheet. The valuation is the estimated fair
value to settle the financial contracts as at December 31, 2006 and is based
on pricing models, estimates, assumptions and market data available at that
time. The actual gain or loss realized on cash settlement can vary materially
due to subsequent fluctuations in commodity prices as compared to the
valuation assumptions.
The Fund has fixed the commodity price on anticipated production as
follows:Approximate
Production Hedged,
Commodity Net of Royalties Minimum Price Maximum Price
-------------------------------------------------------------------------
Natural gas - AECO
Winter 2006/2007 58% Cdn$8.42/mcf Cdn$11.46/mcf
Summer 2007 54% Cdn$7.08/mcf Cdn$8.09/mcf
Winter 2007/2008 11% Cdn$8.44/mcf Cdn$10.29/mcf
Crude Oil - WTI
Winter 2006/2007 30% US$65.00/bbl US$88.56/bbl
Summer 2007 14% US$65.00/bbl US$90.00/bbl
Royalties
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Royalties,
net of
Alberta
Royalty
Credit
($000) $ 23,349 $ 23,281 0% $ 76,456 $ 74,290 3%
per boe $ 8.72 $ 13.18 (34)% $ 8.82 $ 10.11 (13)%
As a percentage
of revenue,
excluding
hedging 19.1% 19.8% (0.7)% 18.4% 19.0% (0.6)%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 are shown net of
Alberta Royalty Credit which is a royalty rebate provided by the Alberta
government to certain producers and was eliminated effective January 1, 2007.
Royalties have increased in total due to the increase in revenue from higher
production but have decreased on a per boe basis due to the significantly
reduced natural gas prices. Royalties as a percentage of revenue, excluding
hedging, have remained relatively consistent with comparable periods and we
expect the royalty rate to continue as such.
On February 13, 2007, the Alberta provincial government announced it will
begin an oil and gas royalty and tax system review expected to conclude by
August 31, 2007. The review will concentrate on the oil sands royalty
structure initially, followed by an analysis of the conventional oil and gas
and coal bed methane levies. The panel in charge will perform a comparison to
other oil and gas-producing jurisdictions, ensure the system is sufficiently
sensitive to market conditions, examine the tax treatment compared to other
sectors, assess the impacts of potential changes to the structure and
determine the treatment of existing resource development if changes are made
to the system. The review may result in imposed modifications that affect the
Fund's royalties in the future.Operating Costs
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Operating
costs ($000) $ 27,803 $ 17,381 60% $ 82,911 $ 57,941 43%
per boe $ 10.39 $ 9.84 6% $ 9.56 $ 7.89 21%Total operating costs increased 60% for the three months ended and 43%
for the year ended December 31, 2006 as compared to 2005 mainly due to the
Ketch acquisition and service costs that have escalated in 2006. Operating
costs per boe increased 6% for the three months and 21% for the year ended
December 31, 2006. In the fourth quarter of 2006, crude oil pipeline
restrictions in Southeast Saskatchewan resulted in additional trucking,
increasing operating costs per boe for the quarter. In addition, operating
costs per boe for the quarter and year ended December 31, 2006 have increased
due to significantly higher costs associated with the shortage of supplies and
services in the field. However, there has been recent evidence of reduced
demand on the current available support and service resources as drilling rig
utilization rates have decreased. The impact on operating costs is uncertain
but we will be opportunistic and proactive in pursuing alternatives that will
improve our operating cost structure. A significant operating cost that
Advantage has been successful in stabilizing is electricity costs associated
with field operations. The Fund has been active in preserving the price of
power by hedging 3.5 MW at $56.68/MWh for 2007 and 3.0 MW at $54.00/MWh for
2008. Management of operating costs will be a persistent challenge in the
current environment and we expect operating costs per boe to average between
$9.50 to $10.50 for 2007.General and Administrative
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
General and
administrative
expense
($000) $ 4,586 $ 1,521 202% $ 13,738 $ 5,452 152%
per boe $ 1.71 $ 0.86 99% $ 1.58 $ 0.74 114%
Employees at
December 31 135 80 69%General and administrative ("G&A") expense has increased 202% for the
three months and 152% for the year ended December 31, 2006, as compared to
2005. G&A per boe increased 99% for the three months and 114% for the year
when compared to the same periods of 2005. G&A expense has increased overall
and per boe primarily due to an increase in staff levels that have resulted
from the Ketch acquisition and growth of the Fund. Additionally, the Ketch
acquisition was conditional on Advantage internalizing the external management
contract structure and eliminating all related fees for a more typical
employee compensation arrangement. The new employee compensation plan has
resulted in higher G&A expense that is offset by the elimination of future
management fees and performance incentive. Prior to elimination of the
management contract, the quarterly management fee and annual performance
incentive were not included within G&A.
Current employee compensation includes salary, benefits, a short-term
incentive plan and a long-term incentive plan. The long-term incentive plan
consists of Restricted Trust Unit ("RTU") grants based on the Fund's
individual Trust Unit performance from June 23 to December 31, 2006, adjusted
for each monthly distribution, and compared to a peer group approved by the
Board of Directors. The RTU grants vest over two years and are not available
to previous AIM management for a period of three years following the Ketch
acquisition. As the Fund did not meet the 2006 grant thresholds, there was no
RTU grant made for the 2006 year.Management Fee, Performance Incentive, and Management Internalization
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Management
fee ($000) $ - $ 1,043 (100)% $ 887 $ 3,665 (76)%
per boe $ - $ 0.59 (100)% $ 0.10 $ 0.50 (80)%
Performance
incentive
($000) $ - $ 10,544 (100)% $ 2,380 $ 10,544 (77)%
Management
internal-
ization
($000) $ 5,497 $ - - $ 13,449 $ - -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. Management fees were calculated
based on 1.5% of operating cash flow defined as revenues less royalties and
operating costs.
The Manager was 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 did not
receive any form of compensation in respect of acquisition or divestiture
activities nor were there any form of stock option or bonus plan for the
Manager or the employees of Advantage outside of the management and
performance fees. The management fees and performance fees were shared amongst
all management and employees.
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 for total original
consideration of 1,933,208 Advantage Trust Units initially valued at
$39.1 million using the weighted average trading value for June 22, 2006 of
$20.23 per Advantage Trust Unit. The Trust Unit consideration 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 Fund paid final management fees and
performance fees for the period January 1 to March 31, 2006 in the amount of
$3.3 million, representing $0.9 million in management fees and $2.4 million in
performance fees. The performance fees were settled through the issuance of
117,662 Trust Units of the Fund. The Manager agreed to forego fees for the
period April 1, 2006 to the closing of the Arrangement.Interest
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Interest
expense
($000) $ 5,414 $ 2,865 89% $ 18,258 $ 10,275 78%
per boe $ 2.02 $ 1.62 25% $ 2.11 $ 1.40 51%
Average
effective
interest rate 5.5% 4.4% 1.1% 5.1% 4.3% 0.8%
Bank
indebtedness
at December 31
($000) $410,574 $252,476 63%Interest expense has increased 89% for the three months and 78% for the
year ended December 31, 2006, as compared to 2005. The increase in interest
expense is primarily attributable to a higher average debt level associated
with the growth of the Fund, an increase in the average effective interest
rates, and the merger with Ketch which included the assumption of Ketch's
additional bank indebtedness. The increased debt has been used in financing
continued development activities and pursuit of expansion opportunities. We
monitor the debt level to ensure an optimal mix of financing and cost of
capital that will provide a maximum return to Unitholders. Our current credit
facilities have been a favorable financing alternative with an effective
interest rate of approximately 5.5% for the three months and 5.1% for the year
ended December 31, 2006. 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
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Interest on
convertible
debentures
($000) $ 3,289 $ 2,727 21% $ 11,210 $ 11,210 0%
per boe $ 1.23 $ 1.54 (20)% $ 1.29 $ 1.53 (16)%
Accretion on
convertible
debentures
($000) $ 604 $ 532 14% $ 2,106 $ 2,182 (3)%
per boe $ 0.23 $ 0.30 (23)% $ 0.24 $ 0.30 (20)%
Convertible
debentures
maturity
value at
December 31
($000) $180,730 $135,111 34%Interest on convertible debentures has increased 21% for the three months
and was unchanged for the year ended December 31, 2006 compared to the same
periods of 2005. Accretion on convertible debentures has increased 14% for the
three months and decreased 3% for the year ended December 31, 2006 as compared
to 2005. The increases in total interest and accretion for the quarter as well
as the increased convertible debentures maturity value are due to Advantage
assuming Ketch's 6.50% convertible debentures in the merger. The increased
interest and accretion from the additional debentures has been offset for the
year due to the continual exchange of convertible debentures to Trust Units
that will pay distributions rather than interest. During the year ended
December 31, 2006, $24.3 million of convertible debentures were converted
resulting in the issuance of 1,286,901 Trust Units.Cash Netbacks
Three months ended
December 31
2006 2005
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $122,360 $ 45.72 $117,319 $ 66.40
Realized hedging gains (losses) 5,179 1.93 (7,147) (4.05)
Royalties (23,349) (8.72) (23,281) (13.18)
Operating costs (27,803) (10.39) (17,381) (9.84)
-------------------------------------------------------------------------
Operating $ 76,387 $ 28.54 $ 69,510 $ 39.33
General and administrative (4,586) (1.71) (1,521) (0.86)
Management fee - - (1,043) (0.59)
Interest (5,414) (2.02) (2,865) (1.62)
Interest on convertible
debentures (3,289) (1.23) (2,727) (1.54)
Taxes (361) (0.13) (448) (0.25)
-------------------------------------------------------------------------
Funds from operations $ 62,737 $ 23.45 $ 60,906 $ 34.47
-------------------------------------------------------------------------
Year ended
December 31
2006 2005
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $414,430 $ 47.80 $390,541 $ 53.17
Realized hedging gains (losses) 5,297 0.61 (13,969) (1.90)
Royalties (76,456) (8.82) (74,290) (10.11)
Operating costs (82,911) (9.56) (57,941) (7.89)
-------------------------------------------------------------------------
Operating $260,360 $ 30.03 $244,341 $ 33.27
General and administrative (13,738) (1.58) (5,452) (0.74)
Management fee (887) (0.10) (3,665) (0.50)
Interest (18,258) (2.11) (10,275) (1.40)
Interest on convertible
debentures (11,210) (1.29) (11,210) (1.53)
Taxes (1,509) (0.17) (2,198) (0.30)
-------------------------------------------------------------------------
Funds from operations $214,758 $ 24.78 $211,541 $ 28.80
-------------------------------------------------------------------------Funds from operations per boe have decreased from $28.80 per boe in the
prior year to $24.78 per for the year ended December 31, 2006. The lower cash
netback per boe is primarily due to lower revenues resulting from soft natural
gas prices as well as higher operating costs, general and administrative
expenses and interest. Operating costs per boe for the year ended December 31,
2006 were $9.56, an increase of 21% from the $7.89 experienced in 2005.
Operating costs have steadily increased over the past year due to
significantly higher field costs associated with the shortage of supplies and
services that has resulted from the high level of industry activity. General
and administrative expenses per boe for the 2006 year have increased 114% over
the prior year period due to the additional employees from the growth of the
Fund and the Ketch merger, which also resulted in internalization of the
management arrangement and a new employee compensation plan. Interest expense
per boe on bank indebtedness for the year ended December 31, 2006 has
increased 51% over the prior year due to the assumption of debt in the Ketch
merger, higher average effective interest rates and the general growth of the
Fund.Depletion, Depreciation and Accretion
Three months ended Year ended
December 31 December 31
2006 2005 % change 2006 2005 % change
-------------------------------------------------------------------------
Depletion,
depreciation
& accretion
($000) $ 63,521 $ 32,581 95% $194,309 $135,096 44%
per boe $ 23.73 $ 18.44 29% $ 22.41 $ 18.39 22%Depletion and depreciation of property and equipment is provided on the
"unit-of-production" method based on total proved reserves. The depletion,
depreciation and accretion ("DD&A") provision has increased by 95% for the
three months and 44% for the year ended December 31, 2006. The DD&A per boe
has increased by 29% for the three months and 22% for the year ended
December 31, 2006 compared to prior years. The higher DD&A is primarily due to
increased production from the Ketch acquisition while the DD&A per boe
increase was caused by a higher valuation for the Ketch reserves than
accumulated from prior acquisitions and development activities.
Taxes
Current taxes paid or payable for the quarter ended December 31, 2006
amounted to $0.4 million, compared to $0.4 million expensed for the same
period of 2005. For the year ended December 31, 2006, current taxes paid or
payable were $1.5 million, compared to $2.2 million for the comparative
period. Current taxes primarily represent Federal large corporations tax and
Saskatchewan resource surcharge. Federal large corporations tax was based on
debt and equity levels of the Fund and has been eliminated effective
January 1, 2006 due to government legislation. Saskatchewan resource surcharge
is based on the petroleum and natural gas revenues within the province of
Saskatchewan.
Future income taxes arise from differences between the accounting and tax
bases of the operating company's assets and liabilities. For the year ended
December 31, 2006, the Fund recognized an income tax reduction of
$37.1 million compared to a reduction of $11.4 million for 2005.
Under the Fund's current structure, payments are made between the
operating company and the Fund transferring income tax obligations to the
Unitholders. Therefore, based on the current structure and existing
legislation, no cash income taxes are to be paid by the operating company or
the Fund, and as such, the future income tax liability recorded on the balance
sheet will be recovered through earnings over time. As at December 31, 2006,
the operating company had a future income tax liability balance of
$61.9 million. Canadian generally accepted accounting principles require that
a future income tax liability be recorded when the book value of assets
exceeds the balance of tax pools.
On October 31, 2006, the Federal Government proposed changes to Canada's
tax system that include altering the tax treatment of income trusts. The
government proposed a two-tier tax structure, similar to that of corporations,
whereby distributions paid by trusts that represent a return on capital will
be subject to tax at the trust level in addition to personal tax as if they
were dividends from a taxable Canadian corporation. The changes are proposed
to take effect in 2011 for existing publicly-traded trusts. If enacted, the
proposal could affect the Fund in several ways, and Advantage is currently
assessing several options for the future. The Fund may allocate a portion of
cash flows to additional tax on distributions, resulting in less cash flow
available for distribution or the Fund may determine strategic alternatives
such as increasing cash flow allocated to capital spending, conversion to a
corporation, or paying a higher percentage of distributions on a return of
capital basis, all of which could result in a decrease or elimination of
distributions. The following is a table provided by the Federal Government
showing a simplified comparison of the effects of the proposed changes to
investor tax rates in 2011:Current System Enacted System (2011)
Income Income
Portion of Large Portion of Large
Trust Corporation Trust Corporation
Distributions (Dividend) Distributions (Dividend)
-------------------------------------------------------------------------
Taxable
Canadian
individuals(1) 46% 46% 45.5% 45.5%
Canadian
tax-exempt
investors 0% 32% 31.5% 31.5%
Taxable U.S.
investors(2) 15% 42% 41.5% 41.5%
-------------------------------------------------------------------------
(1) All rates in the table are as of 2011, and include both entity- and
investor-level tax (as applicable). Rates for "Taxable Canadian
individuals" assume that top personal income tax rates apply and that
provincial governments increase their dividend tax credit for
dividends of large corporations.
(2) Canadian taxes only. U.S. tax will also apply in most cases, net of
any foreign tax credits.
The Fund has approximately $1.2 billion in tax pools and deductions at
December 31, 2006, which can be used to declare a higher percentage of
distributions as a return of capital and thus reduce the amount of taxes paid
by Unitholders. The Fund and AOG had the following estimated tax pools in
place at December 31, 2006:
December 31,
2006
Estimated
Tax Pools
($ millions)
------------
Undepreciated Capital Cost $ 453
Canadian Oil and Gas Property Expenses 333
Canadian Development Expenses 303
Canadian Exploration Expenses 44
Non-capital losses 29
Other 22
------------
$ 1,184
------------Non-Controlling Interest
Non-controlling interest expense for the year ended December 31, 2006 was
$29,000, a decrease of 88% from the $232,000 recognized during the same period
of 2005. Non-controlling interest expense represents the net income
attributable to Exchangeable Share ownership interests. The non-controlling
interest was created when Advantage Oil & Gas Ltd. ("AOG"), a subsidiary of
the Fund, issued Exchangeable Shares as partial consideration for the
acquisition of Defiant Energy Corporation ("Defiant") that occurred at the end
of 2004. The decrease in non-controlling interest expense is directly
attributable to the continued conversion of Exchangeable Shares to Trust Units
since the original issuance. On March 8, 2006, AOG elected to exercise its
redemption right to redeem all of the Exchangeable Shares outstanding. The
redemption price per Exchangeable Share was satisfied by delivering that
number of Advantage Trust Units equal to the Exchange Ratio of 1.22138 in
effect on May 9, 2006. As such, there is no non-controlling interest expense
recorded in the quarter and no exchangeable shares remain outstanding.
Contractual Obligations and Commitments
The Fund has contractual obligations in the normal course of operations
including purchases of assets and services, operating agreements,
transportation commitments, sales contracts and convertible debentures. These
obligations are of a recurring and consistent nature and impact cash flow in
an ongoing manner. The following table is a summary of the Fund's remaining
contractual obligations and commitments. Advantage has no guarantees or off-
balance sheet arrangements other than as disclosed.Payments due by period
($ millions) Total 2007 2008 2009 2010 2011
-------------------------------------------------------------------------
Building leases $ 5.4 $ 2.2 $ 1.4 $ 0.8 $ 0.8 $ 0.2
Capital leases 2.9 2.6 0.3 - - -
Pipeline/
transportation 5.9 4.2 1.4 0.3 - -
Convertible
debentures(1) 180.7 1.4 5.4 57.1 70.0 46.8
-------------------------------------------------------------------------
Total contractual
obligations $ 194.9 $ 10.4 $ 8.5 $ 58.2 $ 70.8 $ 47.0
-------------------------------------------------------------------------
(1) As at December 31, 2006, Advantage had $180.7 million convertible
debentures outstanding. Each series of convertible debentures are
convertible to Trust Units based on an established conversion price.
The Fund expects that the obligations related to convertible
debentures will be settled through the issuance of Trust Units.
(2) Bank indebtedness of $410.6 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, 2006
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 410,574
Working capital deficit(1) 42,655
-------------------------------------------------------------------------
Net debt $ 453,229
-------------------------------------------------------------------------
Trust Units outstanding (000) 105,390
Trust Unit closing market price ($/Trust Unit) $ 12.43
-------------------------------------------------------------------------
Market value $1,309,998
-------------------------------------------------------------------------
Capital lease obligation (long-term) $ 305
Convertible debentures maturity value (long-term) 179,245
-------------------------------------------------------------------------
Total capitalization $1,942,777
-------------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities, cash
distributions payable, and the current portion of capital lease
obligations and convertible debentures.Unitholders' Equity, Exchangeable Shares and Convertible Debentures
Advantage has utilized a combination of Trust Units, Exchangeable Shares,
convertible debentures and bank debt to finance acquisitions and development
activities.
As at December 31, 2006, the Fund had 105.4 million Trust Units
outstanding. On January 20, 2006, Advantage issued 475,263 Trust Units to
satisfy $10.5 million of the performance incentive fee obligation related to
the 2005 year. On June 23, 2006, Advantage issued 32,870,465 Trust Units as
consideration for the acquisition of Ketch, 1,933,208 Trust Units as
consideration for all of the outstanding shares of AIM to internalize the
external management contract, and 117,662 Trust Units to satisfy the final
obligation related to the 2006 first quarter performance fee. The Trust Units
issued as consideration for the external management contract are subject to
escrow provisions and 19,366 Trust Units were forfeited during the year ended
December 31, 2006. 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. As at March 21, 2007, Advantage had 115.0 million
Trust Units issued and outstanding.
Exchangeable Shares issued and outstanding were exchangeable for
Advantage Trust Units at any time on the basis of the applicable exchange
ratio in effect at that time. On March 8, 2006, AOG elected to exercise its
redemption right to redeem all of the Exchangeable Shares outstanding. The
redemption price per Exchangeable Share was satisfied by delivering that
number of Advantage Trust Units equal to the Exchange Ratio of 1.22138 in
effect on May 9, 2006. During 2006, the Fund issued 127,014 Trust Units for
the remaining Exchangeable Shares.
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, all of the remaining 85,000 Series A Trust Units Rights
were exercised in the third quarter and 37,500 Series B Trust Unit Rights were
exercised in the second quarter of 2006. As at March 21, 2007, 187,500 Series
B Trust Unit Rights remain outstanding.
As at December 31, 2006, the Fund had $180.7 million convertible
debentures outstanding that were convertible to 8.3 million Trust Units based
on the applicable conversion prices. During the year ended December 31, 2006,
$24.3 million convertible debentures were exchanged for the issuance of
1.3 million Trust Units. As at March 21, 2007, the convertible debentures
outstanding have not changed from December 31, 2006.
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
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, 2006, 2,005,499 Trust Units were issued as a result of
the Plan, generating $27.7 million reinvested in the Fund and representing an
approximate 26% participation rate.
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 $104.2 million (net of Underwriters' fees and other issue
costs of $5.9 million). The net proceeds of the offering will be used to pay
down bank indebtedness and to subsequently fund capital and general corporate
expenditures.
In the October 31, 2006 proposal to tax distributions at the income trust
level as well as the existing Unitholder level, the Federal Government warned
against income trusts incurring "undue expansion" during the period between
the proposal announcement and 2011 when the tax rules will effectively change.
On December 15, 2006 the Federal Government clarified "undue expansion" by
providing a set of guidelines for "normal growth". 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 over the next four
years, which we believe is adequate for any growth we expect to incur.
Bank Indebtedness, Credit Facility and Other Obligations
At December 31, 2006, Advantage had bank indebtedness outstanding of
$410.6 million. Advantage assumed net bank indebtedness of approximately
$188 million in the Ketch merger. The Fund has a $600 million credit facility
agreement consisting of a $580 million extendible revolving loan facility and
a $20 million operating loan facility. The current credit facilities are
secured by a $1 billion floating charge demand debenture, a general security
agreement and a subordination agreement from the Fund covering all assets and
cash flows.
At December 31, 2006, Advantage had a working capital deficiency of
$42.7 million that has remained relatively consistent with the previous year
end. Our working capital includes items expected for normal operations such as
trade receivables, prepaids, deposits, trade payables and accruals. Working
capital varies primarily due to the timing of such items, the current level of
business activity including our capital program, commodity price volatility,
and seasonal fluctuations. Advantage has no unusual working capital
requirements. We do not anticipate any problems in meeting future obligations
as they become due given the strength of our funds from operations. It is also
important to note that working capital is effectively integrated with
Advantage's operating credit facility, which assists with the timing of cash
flows as required.
Advantage generally does not make use of capital leases to finance
development expenditures. However, Advantage currently has two capital leases
outstanding at December 31, 2006 for $2.8 million that were both assumed from
corporate acquisitions.Capital Expenditures
Three months ended Year ended
December 31 December 31
($000) 2006 2005 2006 2005
-------------------------------------------------------------------------
Land and seismic $ 522 $ 609 $ 5,261 $ 3,860
Drilling, completions
and workovers 42,612 24,293 113,146 77,794
Well equipping and
facilities 17,690 2,758 39,437 20,322
Other 285 300 1,643 1,253
-------------------------------------------------------------------------
$ 61,109 $ 27,960 $ 159,487 $ 103,229
Purchase adjustment of
Defiant acquisition - 98 - 98
Property acquisitions 46 (3) 244 210
Property dispositions - 76 (8,727) (3,379)
-------------------------------------------------------------------------
Total capital
expenditures $ 61,155 $ 28,131 $ 151,004 $ 100,158
-------------------------------------------------------------------------Advantage's growth strategy has been to acquire properties in or near
areas where we have large land positions, shallow to medium depth drilling
opportunities, and preserve a balance of year round access. We focus on areas
where past activity has yielded long-life reserves with high cash netbacks.
With the integration of the Ketch assets, Advantage is very well positioned to
selectively exploit the highest value-generating drilling opportunities given
the size, strength and diversity of our asset base. As a result, the Fund has
shifted its remaining capital program to further oil development due to
superior project economics. 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, 2006, the Fund spent a net
$61.2 million on capital expenditures. Approximately $42.6 million was
expended on drilling and completion operations where the Fund drilled a total
of 25.1 net (44 gross) wells. During the quarter we drilled 4.4 net (13 gross)
gas wells at Chigwell, two 100% working interest gas wells at Black, five 70%
working interest oil wells at Sunset, three oil wells and one gas well with
100% working interests at Nevis and several wells at other minor properties.
Total capital spending in the quarter included $13.8 million at Nevis,
$7.5 million at Sunset, $5.4 million at Chigwell, $2.7 million at Hardy,
$2.6 million at Worsley, $2.6 million at Westerose, $2.5 million at Martin
Creek, $2.4 million at Conroy Creek, and $2.4 million at Willesden Green.
For the year ended December 31, 2006, the Fund spent a net $151.0 million
on capital expenditures. The Fund drilled a total of 90.2 net (147 gross)
wells as a result of spending approximately $113.1 million on drilling and
completion operations. During the year, Advantage drilled 10.4 net (25 gross)
gas wells at Chigwell, 15 gas wells with 100% working interest at Medicine
Hat, 2.3 net (4 gross) gas wells at Worsley, 9.8 net (14 gross) oil wells at
Sunset, 4.2 net (6 gross) gas wells and 11 oil wells with 100% working
interest at Nevis, and 3 100% working interest gas wells at Shouldice, along
with numerous wells at other minor properties. The Fund experienced a 95%
success rate on wells drilled in 2006. Total capital spending for the year
included $36.5 million at Nevis, $17.4 million at Sunset, $8.0 million at
Chigwell, $7.8 million at Willesden Green, and $6.5 million at Worsley. The
majority of capital spending was used for drilling and facilities throughout
the year as well as some residual development activity remaining from the end
of 2005. Activity occurring late in the year included three new oil wells at
the Westerose Banff "C" unit adding a net 200 boe/d, two new oil wells at
Little Bow in Southern Alberta adding a net 150 boe/d, the Chigwell North coal
bed methane joint venture and new gas pool at Sweetgrass.
The following table summarizes the various funding requirements during
the year ended December 31, 2006 and the sources of funding to meet those
requirements.Sources and Uses of Funds
Year ended
($000) December 31, 2006
-------------------------------------------------------------------------
Sources of funds
Funds from operations $ 214,758
Units issued, net of costs 169,631
Property dispositions 8,727
Decrease in working capital 27,222
-------------------------------------------------------------------------
$ 420,338
-------------------------------------------------------------------------
Uses of funds
Cash distributions to Unitholders $ 212,738
Expenditures on property and equipment 159,487
Decrease in bank indebtedness 30,767
Acquisition costs of Ketch Resources Trust 10,109
Expenditures on asset retirement 5,974
Reduction of capital lease obligations 1,019
Property acquisitions 244
-------------------------------------------------------------------------
$ 420,338
-------------------------------------------------------------------------
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,
2006 2005 2004
-------------------------------------------------------------------------
Total revenue (before royalties)
($000) $ 419,727 $ 376,572 $ 241,481
Net income ($000) $ 49,814 $ 75,072 $ 24,038
per Trust Unit - Basic $ 0.62 $ 1.33 $ 0.59
- Diluted $ 0.61 $ 1.32 $ 0.58
Total assets ($000) $1,981,587 $1,012,847 $1,033,251
Long term financial liabilities
($000)(1) $ 581,698 $ 379,903 $ 144,039
Cash distributions declared
per Trust Unit $ 2.66 $ 3.12 $ 2.82
(1) Given amendments made in 2005 to the credit facility repayment terms,
the bank indebtedness is classified as a long-term liability while in
2004 bank indebtedness was shown as a current liability. Long term
financial liabilities also exclude asset retirement obligations and
future income taxes.
Quarterly Performance
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 $ 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
Cash distributions
declared $ 58,791 $ 60,498 $ 53,498 $ 44,459
Payout ratio (%) 94% 96% 127% 95%
Quarterly Performance
2005
($000, except as
otherwise indicated) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 72,587 75,994 79,492 86,350
Crude oil and NGLs
(bbls/d) 7,106 7,340 6,772 6,892
Total (boe/d) 19,204 20,006 20,021 21,284
Average prices
Natural gas ($/mcf)
Excluding hedging $ 11.68 $ 8.25 $ 7.27 $ 6.52
Including hedging $ 10.67 $ 7.79 $ 7.30 $ 6.47
AECO monthly index $ 11.68 $ 8.15 $ 7.38 $ 6.70
Crude oil and NGLs
($/bbl)
Excluding hedging $ 60.14 $ 66.00 $ 56.57 $ 53.02
Including hedging $ 59.53 $ 61.10 $ 56.24 $ 53.02
WTI (US$/bbl) $ 60.04 $ 63.17 $ 53.13 $ 49.90
Total revenues
(before royalties) $ 110,172 $ 95,715 $ 87,476 $ 83,209
Net income $ 25,846 $ 18,674 $ 26,537 $ 4,015
per Trust Unit
- basic $ 0.45 $ 0.33 $ 0.46 $ 0.07
- diluted $ 0.45 $ 0.32 $ 0.46 $ 0.07
Funds from operations $ 60,906 $ 55,575 $ 49,705 $ 45,355
Cash distributions
declared $ 43,265 $ 43,069 $ 44,693 $ 46,339
Payout ratio (%) 71% 77% 90% 102%The table above highlights the Fund's performance for the fourth quarter
of 2006 and also for the preceding seven quarters. During 2005, production
continued to experience normal declines until a more significant decrease
occurred in the first quarter of 2006 due to a one-time adjustment for several
payout wells, restricted production on wells in Chip Lake and Nevis, and some
minor non-core property dispositions that occurred in 2005. Production
increased in the second quarter of 2006 with the addition of eight days of
production from the Ketch properties and further increased in the third
quarter of 2006 as the acquisition was fully integrated with Advantage.
Production in the fourth quarter of 2006 was significantly impacted by
freezing problems at several properties due to extreme cold in Alberta during
the latter part of November. Advantage's revenues and funds from operations
for the third and fourth quarters of 2006 are higher primarily due to the
production from the merger with Ketch, offset by significantly lower natural
gas prices. Net income has been lower during the last two quarters due to
reduced natural gas prices realized during the periods, amortization of the
management internalization consideration, and increased depletion and
depreciation expense due to the Ketch merger. During 2006, the payout ratio
has been higher relative to prior quarters as a result of considerably weak
natural gas prices. Additionally, the timing of the Ketch merger has also
increased the payout ratio for the second quarter of 2006 as the arrangement
closed prior to the June record date resulting in the payment of a full month
distribution to Ketch Unitholders whereas funds from operations for June only
included eight days of cash flows from the Ketch properties.
Critical Accounting Estimates
The preparation of financial statements in accordance with GAAP requires
Management to make certain judgments and estimates. Changes in these judgments
and estimates could have a material impact on the Fund's financial results and
financial condition. Management relies on the estimate of reserves as prepared
by the Fund's independent qualified reserves evaluator. The process of
estimating reserves is critical to several accounting estimates. The process
of estimating reserves is complex and requires significant judgments and
decisions based on available geological, geophysical, engineering and economic
data. These estimates may change substantially as additional data from ongoing
development and production activities becomes available and as economic
conditions impact crude oil and natural gas prices, operating costs, royalty
burden changes, and future development costs. Reserve estimates impact net
income through depletion and depreciation of property and equipment, the
provision for asset retirement costs and related accretion expense, and
impairment calculations for property and equipment and goodwill. The reserve
estimates are also used to assess the borrowing base for the Fund's credit
facilities. Revision or changes in the reserve estimates can have either a
positive or a negative impact on net income and the borrowing base of the
Fund.
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 is
expected to develop and release a detailed implementation plan and the Fund
will consider the effect that this implementation plan might have on the
consolidated financial statements during the transition period.
Financial Instruments Recognition and Measurement
In April 2005, a series of new accounting standards were released which
established guidance for the recognition and measurement of financial
instruments. These new standards include Section 1530 "Comprehensive Income",
Section 3855 "Financial Instruments - Recognition and Measurement", and
Section 3865 "Hedges". The new standards also resulted in a number of
significant consequential amendments to other accounting standards to
accommodate the new sections. The standards require all applicable financial
instruments to be classified into one of several categories including:
financial assets and financial liabilities held for trading, held-to-maturity
investments, loans and receivables, available-for-sale financial assets, or
other financial liabilities. The financial instruments are then included on a
company's balance sheet and measured at fair value, cost or amortized value,
depending on the classification. Subsequent measurement and recognition of
changes in value of the financial instruments also depends on the initial
classification. These standards are effective for interim and annual financial
statements for fiscal years beginning on or after October 1, 2006 and must be
implemented simultaneously. Advantage has adopted the new standards as of
January 1, 2007 and there are no significant changes in the recognition and
measurement of the Fund's financial instruments.
In December 2006, new accounting standards were released which provided
further guidance on the presentation and disclosure of financial instruments
and were intended to better align the Canadian standards with international
accounting standards. The new standards are effective for interim and annual
financial statements related to fiscal years beginning on or after October 1,
2007. Advantage has chosen to early adopt the new standards Section 3862
"Financial Instruments - Presentation" and Section 3863 "Financial Instruments
- Disclosure" as issued by the CICA effective January 1, 2007. As a result,
there will be several additional disclosures relating to financial instruments
in 2007, but no significant changes to presentation.
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 operation, 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 2006, 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.
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, 2006. 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 has three members, all of whom are
independent. The Human Resources, Compensation and Corporate Governance
Committee and Audit Committee each have 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 three 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;
and (iii) 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 has established a 2007 Budget, as approved by the Board of
Directors, that retains a high degree of activity and will focus on drilling
in many of our key properties where a high level of success was realized
through 2006. Capital will also be directed to accommodate facility expansions
and further develop enhanced recovery schemes as necessary. New drill bit
additions are expected to be more effective in replacing production as
corporate declines have continued to subside through 2006. Advantage's
production now contains very little flush production from high impact wells
and concentrated drilling programs (from 2004 and 2005 activities) creating a
balanced and predictable platform. During the second and third quarters of
2007, we expect two major third party plant turnarounds to occur which will
significantly affect our Lookout Butte and Westerose properties. These two
turnarounds combined with well payouts are expected to result in an impact of
approximately 400 boe/d to the 2007 annual average production. Overall, we
expect production in 2007 to average between 27,500 to 29,500 boe/d.
Advantage's 2007 capital expenditures budget of $120 to $145 million
includes the drilling, completion and tie-in of 107 gross wells (64 net)
weighted approximately 50% toward light oil and 50% to natural gas. In
Northeast B.C., a 17 well (14 net) natural gas drilling program is being
substantially completed in the first quarter of 2007 at Martin Creek. This
program exploits the northern portions of the Field where a successful
drilling program was conducted in 2006 which extended pool boundaries. At this
time, the 17 well drilling program has been completed and final facilities
work and tie-ins are in progress. Results to date indicate a very successful
program with tested well deliverability in excess of facilities capacity and
budget assumptions. Combined with Advantage's already commanding position of
facilities infrastructure and operatorship, we estimate three years of
drilling inventory in this property. At Sunset, in Northern Alberta, four
wells are planned to follow-up the successful 2006 development drilling
program and capital will also be required to expand water flood facilities in
this light oil pool. In Central Alberta, a 12 well (12 net) program is planned
at Nevis for 40 degree light oil where horizontal drilling in 2006 showed
excellent results. A net 15 sections of land were added through deals with
industry third parties in 2006 bringing the total land under control to
37.5 net sections in this property. A second development drilling program in
the western portion of the Nevis property is underway and facilities will be
constructed to accommodate production additions. Additional gas opportunities
will be pursued in the Central Alberta areas targeting down spacing and
follow- up to successes. In Southern Alberta and S.E. Saskatchewan, 13 wells
(10 net) will be drilled for oil targets in 2007.
Operating costs are forecasted to be closer to the $9.50 to $10.50/boe
range as higher gas prices indicated by the current strip price through the
summer of 2007 suggest higher power costs than what was realized in 2006. In
addition, higher property taxes, surface rentals and additional trucking costs
due to continued pipeline restrictions in Southeast Saskatchewan are expected
to occur in 2007. Advantage is undertaking several operating cost reduction
initiatives through 2007 to help offset these increases.
Advantage's funds from operations in 2007 will continue to be impacted by
the volatility of crude oil and natural gas prices and the $US/$Canadian
exchange rate. Advantage will continue to follow its strategy of acquiring
properties that provide low risk development opportunities and enhance long
term cash flow. Advantage will also continue to focus on low cost production
and reserve additions through low to medium risk development drilling
opportunities that have arisen as a result of the acquisitions completed in
prior years and from the significant inventory of drilling opportunities that
has resulted from the Ketch merger. The synergy of larger size and the
complementary winter/summer drilling programs with the Ketch merger is
providing benefits in terms of securing services, flexibility and quality of
our capital program.
Looking forward, Advantage's high quality assets, three year drilling
inventory, hedging program and excellent tax pools provides many options for
the Fund and we are committed to maximizing value generation for our
Unitholders.
The following table indicates our funds from operations sensitivity to
changes in prices and production of natural gas, crude oil and NGLs, exchange
rates and interest rates for 2007 based on production of 28,000 boe/d
comprised of 110.4 mmcf/d of natural gas and 9,600 bbls/d of crude oil and
NGLs. Advantage is considerably more sensitive to changes in natural gas
prices as compared to oil due to the Fund's higher natural gas weighting.Sensitivities Annual
Annual Funds from
Funds from Operations per
Operations Trust Unit
($000) ($/Trust Unit)
-------------------------------------------------------------------------
Natural gas
AECO monthly price change
of $0.25/mcf $ 5,500 $ 0.05
Production change of 1,000 mcf/d $ 1,800 $ 0.02
Crude oil and NGLs
WTI price change of US$1.00/bbl $ 2,900 $ 0.03
Production change of 200 bbls/d $ 2,800 $ 0.03
$US/$Canadian exchange rate change
of $0.01 $ 5,800 $ 0.04
Interest rate change of 1% $ 3,800 $ 0.03Additional 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 Balance Sheets
December 31, December 31,
(thousands of dollars) 2006 2005
-------------------------------------------------------------------------
Assets
Current assets
Accounts receivable $ 79,537 $ 51,788
Prepaid expenses and deposits 16,878 7,791
Derivative asset (note 13) 9,840 -
-------------------------------------------------------------------------
106,255 59,579
Deposit on property acquisition 1,410 -
Derivative asset (note 13) 593 -
Fixed assets (note 4) 1,753,058 907,795
Goodwill (note 3) 120,271 45,473
-------------------------------------------------------------------------
$ 1,981,587 $ 1,012,847
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 116,109 $ 76,371
Distributions payable to Unitholders 18,970 14,462
Current portion of capital lease obligations
(note 5) 2,527 358
Current portion of convertible debentures
(note 7) 1,464 -
-------------------------------------------------------------------------
139,070 91,191
Capital lease obligations (note 5) 305 1,346
Bank indebtedness (note 6) 410,574 252,476
Convertible debentures (note 7) 170,819 126,081
Asset retirement obligations (note 8) 34,324 21,263
Future income taxes (note 11) 61,939 99,026
-------------------------------------------------------------------------
817,031 591,383
-------------------------------------------------------------------------
Non-controlling Interest
Exchangeable shares (note 9) - 2,369
-------------------------------------------------------------------------
Unitholders' Equity
Unitholders' capital (note 10) 1,592,758 681,574
Convertible debentures equity component
(note 7) 8,041 6,159
Contributed surplus (note 10) 863 1,036
Accumulated deficit (note 12) (437,106) (269,674)
-------------------------------------------------------------------------
1,164,556 419,095
-------------------------------------------------------------------------
$ 1,981,587 $ 1,012,847
-------------------------------------------------------------------------
Commitments (note 15)
Subsequent Event (note 16)
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Income and Accumulated Deficit
Year ended Year ended
(thousands of dollars, except for per December 31, December 31,
Trust Unit amounts) 2006 2005
-------------------------------------------------------------------------
Revenue
Petroleum and natural gas $ 419,727 $ 376,572
Unrealized gain on derivatives (note 13) 10,242 214
Royalties, net of Alberta Royalty Credit (76,456) (74,290)
-------------------------------------------------------------------------
353,513 302,496
-------------------------------------------------------------------------
Expenses
Operating 82,911 57,941
General and administrative 13,738 5,452
Management fee (note 14) 887 3,665
Performance incentive (note 14) 2,380 10,544
Management internalization (note 14) 13,449 -
Interest 18,258 10,275
Interest and accretion on convertible
debentures 13,316 13,392
Depletion, depreciation and accretion 194,309 135,096
-------------------------------------------------------------------------
339,248 236,365
-------------------------------------------------------------------------
Income before taxes and non-controlling interest 14,265 66,131
Future income tax reduction (note 11) (37,087) (11,371)
Income and capital taxes (note 11) 1,509 2,198
-------------------------------------------------------------------------
(35,578) (9,173)
-------------------------------------------------------------------------
Net income before non-controlling interest 49,843 75,304
Non-controlling interest (note 9) 29 232
-------------------------------------------------------------------------
Net income 49,814 75,072
Accumulated deficit, beginning of year (269,674) (167,380)
Distributions declared (217,246) (177,366)
-------------------------------------------------------------------------
Accumulated deficit, end of year $ (437,106) $ (269,674)
-------------------------------------------------------------------------
Net income per Trust Unit (note 10)
Basic $ 0.62 $ 1.33
Diluted $ 0.61 $ 1.32
-------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
Year ended Year ended
December 31, December 31,
(thousands of dollars) 2006 2005
-------------------------------------------------------------------------
Operating Activities
Net income $ 49,814 $ 75,072
Add (deduct) items not requiring cash:
Unrealized gain on derivatives (10,242) (214)
Performance incentive 2,380 10,544
Management internalization 13,449 -
Accretion on convertible debentures 2,106 2,182
Depletion, depreciation and accretion 194,309 135,096
Future income taxes (37,087) (11,371)
Non-controlling interest 29 232
Expenditures on asset retirement (5,974) (2,025)
Changes in non-cash working capital 20,303 (22,910)
-------------------------------------------------------------------------
Cash provided by operating activities 229,087 186,606
-------------------------------------------------------------------------
Financing Activities
Units issued, net of costs (note 10) 169,631 107,616
Decrease in bank indebtedness (30,767) (14,578)
Reduction of capital lease obligations (1,019) (7,687)
Cash distributions to Unitholders (212,738) (175,323)
-------------------------------------------------------------------------
Cash used in financing activities (74,893) (89,972)
-------------------------------------------------------------------------
Investing Activities
Expenditures on property and equipment (159,487) (103,229)
Property acquisitions (244) (210)
Property dispositions 8,727 3,379
Acquisition costs of Ketch Resources Trust
(note 3) (10,109) -
Purchase adjustment of Defiant acquisition - (98)
Changes in non-cash working capital 6,919 3,524
-------------------------------------------------------------------------
Cash used in investing activities (154,194) (96,634)
-------------------------------------------------------------------------
Net change in cash - -
Cash, beginning of year - -
-------------------------------------------------------------------------
Cash, end of year $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow Information
Interest paid $ 34,680 $ 23,358
Taxes paid $ 1,783 $ 2,605
see accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006
All tabular amounts in thousands except for Units and per Unit amounts
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. Cash distributions are determined by Management and the
Board of Directors. We closely monitor our distribution policy
considering forecasted cash flows, optimal debt levels, capital
spending activity, taxability to Unitholders, working capital
requirements, and other potential cash expenditures. Cash
distributions are announced monthly and are based on the cash
available after retaining a portion to meet such spending
requirements. The level of cash 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 cash
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 cash
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 effect 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) Property and equipment
(i) Petroleum and natural gas properties and related equipment
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.
(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.
(d) Cash distributions
Cash distributions are calculated on an accrual basis and are paid to
Unitholders monthly.
(e) Financial instruments
The Fund occasionally uses various types of derivative financial
instruments to manage risk associated with commodity price
fluctuations. These instruments are not used for trading or
speculative purposes. Proceeds and costs realized from holding the
related contracts are recognized in the appropriate revenue and
expense categories of the income statement at the time that each
transaction under a contract is settled. For the unrealized portion
of such contracts, Advantage has chosen not to apply "hedge
accounting" and alternatively utilizes the "fair value" method of
accounting. The fair value is based on an estimate of the amounts
that would have been paid to or received from counterparties to
settle these instruments given future market prices and other
relevant factors. The Fund records changes in the fair value in the
income statement as an unrealized derivative gain or loss with a
corresponding derivative asset or liability recorded on the balance
sheet.
(f) 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.
(g) 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 property and
equipment. 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 and related equipment. 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.
(h) 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 substantively 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.
(i) Exchangeable shares
The Fund's Exchangeable Shares are classified as non-controlling
interest, outside of Unitholders' equity, as they are transferable,
although not publicly traded. The Exchangeable Shares and Trust Units
are considered economically equivalent since the exchange ratio is
increased on each date that a distribution is paid on the Trust Units
and all shares must be exchanged for either Trust Units or cash,
based on the current market price of the Trust Units. Since the
Exchangeable Shares are required to be exchanged, there is no
permanent non-controlling interest. Non-controlling interest expense
is recorded that reflects the earnings attributable to the non-
controlling interest. When Exchangeable Shares are converted to Trust
Units, the carrying value of non-controlling interest on the balance
sheet is reclassified to Unitholders' capital.
(j) Unit-based compensation
The Fund has a unit-based compensation plan for external directors of
the Fund (note 10) as well as Trust Units held in escrow relating to
the management internalization (note 14). Advantage elected to
prospectively adopt amendments to CICA Handbook Section 3870 "Stock-
based Compensation and Other Stock-based Payments" pursuant to the
transitional provisions contained therein. Under this amended
standard, the Fund must account for compensation expense based on the
"fair value" of rights granted under its unit-based compensation
plans.
Since awards under the external directors' unit-based compensation
plan are vested immediately, associated compensation expense is
recognized in the current period earnings and estimated forfeiture
rates for such rights are not incorporated within 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.
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 associated compensation expense is recognized equally over the
appropriate service period and incorporates estimated forfeitures.
(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, and impairment calculations for property
and equipment and goodwill 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, relevant 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) Comparative figures
Certain comparative figures have been reclassified to conform to the
current year's presentation.
3. Acquisition of 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:
Property and 32,870,465 Trust
equipment $ 877,463 Units issued $ 688,636
Goodwill 74,798 Acquisition costs
Net working incurred 10,109
capital(*) 5,368 -----------
Bank $ 698,745
indebtedness (180,000) -----------
Convertible
debentures (66,981)
Convertible
debentures
equity component (2,971)
Asset retirement
obligations (7,930)
Capital lease
obligation (1,002)
-----------
$ 698,745
-----------
(*) Includes cash of $2,713, accounts receivable of $55,806,
prepaid expenses of $6,406, accounts payable of $46,834,
current bank indebtedness of $11,578 and current portion of
capital lease obligation $1,145.
The value of $20.95 per Trust Unit 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, 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
---------------------------------------------------------------------
Accumulated
Depletion and Net Book
December 31, 2005 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 1,290,588 $ 385,140 $ 905,448
Furniture and equipment 4,647 2,300 2,347
---------------------------------------------------------------------
$ 1,295,235 $ 387,440 $ 907,795
---------------------------------------------------------------------
During the year ended December 31, 2006, Advantage capitalized
general and administrative expenditures directly related to
exploration and development activities of $6,444,000 (2005 -
$3,293,000).
Costs of $43,467,000 (2005 - $17,805,000) for unproved properties
have been excluded from the calculation of depletion expense, and
future development costs of $123,464,000 (2005 - $87,843,000) have
been included in costs subject to depletion.
The Fund performed a ceiling test calculation at December 31, 2006 to
assess the recoverable value of property and equipment. Based on the
calculation, the carrying amounts are recoverable as compared to the
sum of the undiscounted net cash flows expected from the production
of proved reserves based on the following benchmark prices:
WTI Crude Oil Exchange Rate AECO Gas
Year ($US/bbl) ($US/$Cdn) ($Cdn/mmbtu)
---------------------------------------------------------------------
2007 $ 65.73 $ 0.87 $ 7.72
2008 $ 68.82 $ 0.87 $ 8.59
2009 $ 62.42 $ 0.87 $ 7.74
2010 $ 58.37 $ 0.87 $ 7.55
2011 $ 55.20 $ 0.87 $ 7.72
---------------------------------------------------------------------
Percentage increase each
year after 2011 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 property and equipment.
Future minimum lease payments at December 31, 2006 consist of the
following:
2007 $ 2,577
2008 308
---------------------------------------------------------------------
2,885
Less amounts representing interest (53)
---------------------------------------------------------------------
2,832
Current portion (2,527)
---------------------------------------------------------------------
$ 305
---------------------------------------------------------------------
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%.
6. Bank Indebtedness
Advantage has a credit facility agreement with a syndicate of
financial institutions which provides for a $580 million extendible
revolving loan facility and a $20 million operating loan facility.
The loan's interest rate is based on either prime, US base rate,
LIBOR or bankers' acceptance rates, at the Fund's option, subject to
certain basis point or stamping fee adjustments ranging from 0.00% to
1.25% depending on the Fund's debt to cash flow ratio. The credit
facilities are secured by a $1 billion floating charge demand
debenture, a general security agreement and a subordination agreement
from the Fund covering all assets and cash flows. The credit
facilities are subject to review on an annual basis. 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 1/2:1, 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, 2006, the
effective interest rate on the outstanding amounts under the facility
was approximately 5.1%.
7. Convertible Debentures
The convertible unsecured subordinated debentures pay interest semi-
annually and are convertible at the option of the holder into Trust
Units of Advantage at the applicable conversion price per Trust Unit
plus accrued and unpaid interest. The details of the convertible
debentures including fair market values initially assigned and
issuance costs are as follows:
10.00% 9.00% 8.25% 7.75%
---------------------------------------------------------------------
Issue date Oct. 18, July 8, Dec. 2, Sep. 15,
2002 2003 2003 2004
Maturity date Nov. 1, Aug. 1, Feb. 1, Dec. 1,
2007 2008 2009 2011
Conversion price $ 13.30 $ 17.00 $ 16.50 $ 21.00
Liability component $ 52,722 $ 28,662 $ 56,802 $ 47,444
Equity component 2,278 1,338 3,198 2,556
---------------------------------------------------------------------
Gross proceeds 55,000 30,000 60,000 50,000
Issuance costs (2,495) (1,444) (2,588) (2,190)
---------------------------------------------------------------------
Net proceeds $ 52,505 $ 28,556 $ 57,412 $ 47,810
---------------------------------------------------------------------
7.50% 6.50% Total
----------------------------------------------------------
Issue date Sep. 15, May 18,
2004 2005
Maturity date Oct. 1, June 30,
2009 2010
Conversion price $ 20.25 $ 24.96
Liability component $ 71,631 $ 66,981 $324,242
Equity component 3,369 2,971 15,710
----------------------------------------------------------
Gross proceeds 75,000 69,952 339,952
Issuance costs (3,190) - (11,907)
----------------------------------------------------------
Net proceeds $ 71,810 $ 69,952 $328,045
----------------------------------------------------------
The convertible debentures are redeemable prior to their maturity
dates, at the option of the Fund, upon providing 30 to 60 days
advance notification. The redemption prices for the various
debentures, plus accrued and unpaid interest, is dependent on the
redemption periods and are as follows:
Convertible Redemption
Debenture Redemption Periods Price
---------------------------------------------------------------------
10.00% After November 1, 2005 and on or before
November 1, 2006 $1,050
After November 1, 2006 and before
November 1, 2007 $1,025
---------------------------------------------------------------------
9.00% After August 1, 2006 and on or before
August 1, 2007 $1,050
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
---------------------------------------------------------------------
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
---------------------------------------------------------------------
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
---------------------------------------------------------------------
The balance of debentures outstanding at December 31, 2006 and
changes in the liability and equity components during the years ended
December 31, 2006 and 2005 are as follows:
10.00% 9.00% 8.25% 7.75%
---------------------------------------------------------------------
Debentures outstanding $ 1,485 $ 5,392 $ 4,867 $ 46,766
---------------------------------------------------------------------
Liability component:
Balance at Dec. 31, 2004 $ 3,923 $ 10,388 $ 12,237 $ 45,548
Accretion of discount 55 168 198 616
Converted to Trust Units (1,525) (3,297) (4,285) (266)
---------------------------------------------------------------------
Balance at Dec. 31, 2005 2,453 7,259 8,150 45,898
Assumed on Ketch
acquisition - - - -
Accretion of discount 30 107 103 589
Converted to Trust Units (1,019) (2,131) (3,577) (2,722)
---------------------------------------------------------------------
Balance at Dec. 31, 2006 $ 1,464 $ 5,235 $ 4,676 $ 43,765
---------------------------------------------------------------------
Equity component:
Balance at Dec. 31, 2004 $ 163 $ 472 $ 675 $ 2,444
Converted to Trust Units (63) (149) (234) (14)
---------------------------------------------------------------------
Balance at Dec. 31, 2005 100 323 441 2,430
Assumed on Ketch
acquisition - - - -
Converted to Trust Units (41) (94) (193) (144)
---------------------------------------------------------------------
Balance at Dec. 31, 2006 $ 59 $ 229 $ 248 $ 2,286
---------------------------------------------------------------------
7.50% 6.50% Total
----------------------------------------------------------
Debentures outstanding $ 52,268 $ 69,952 $180,730
----------------------------------------------------------
Liability component:
Balance at Dec. 31, 2004 $ 64,337 $ - $136,433
Accretion of discount 1,145 - 2,182
Converted to Trust Units (3,161) - (12,534)
----------------------------------------------------------
Balance at Dec. 31, 2005 62,321 - 126,081
Assumed on Ketch
acquisition - 66,981 66,981
Accretion of discount 897 380 2,106
Converted to Trust Units (13,436) - (22,885)
----------------------------------------------------------
Balance at Dec. 31, 2006 $ 49,782 $ 67,361 $172,283
----------------------------------------------------------
Equity component:
Balance at Dec. 31, 2004 $ 3,010 $ - $ 6,764
Converted to Trust Units (145) - (605)
----------------------------------------------------------
Balance at Dec. 31, 2005 2,865 - 6,159
Assumed on Ketch
acquisition - 2,971 2,971
Converted to Trust Units (617) - (1,089)
----------------------------------------------------------
Balance at Dec. 31, 2006 $ 2,248 $ 2,971 $ 8,041
----------------------------------------------------------
As part of the acquisition of Ketch, the 6.50% convertible
debentures, originally issued May 18, 2005, were assumed by Advantage
on June 23, 2006.
During the year ended December 31, 2006, $24,333,000 (2005 -
$13,339,000) debentures were converted resulting in the issuance of
1,286,901 Trust Units (2005 - 783,870 Trust Units).
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
$157.2 million which will be incurred between 2007 to 2057. A credit-
adjusted risk-free rate of 7% was 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,
2006 2005
---------------------------------------------------------------------
Balance, beginning of year $ 21,263 $ 17,503
Accretion expense 1,684 1,162
Assumed in Ketch acquisition (note 3) 7,930 -
Liabilities incurred 9,421 4,623
Liabilities settled (5,974) (2,025)
---------------------------------------------------------------------
Balance, end of year $ 34,324 $ 21,263
---------------------------------------------------------------------
9. Exchangeable Shares
Number
of Shares Amount
---------------------------------------------------------------------
Balance at December 31, 2004 1,450,030 $ 30,842
Converted to Trust Units (1,345,358) (28,705)
Non-controlling interest in net income - 232
---------------------------------------------------------------------
Balance at December 31, 2005 104,672 2,369
Converted to Trust Units (104,672) (2,398)
Non-controlling interest in net income - 29
---------------------------------------------------------------------
Balance at December 31, 2006 - $ -
---------------------------------------------------------------------
Trust Units issuable - -
---------------------------------------------------------------------
AOG is authorized to issue an unlimited number of non-voting
Exchangeable Shares. As partial consideration for the acquisition of
Defiant which closed on December 21, 2004, AOG issued 1,450,030
Exchangeable Shares. The value of the Exchangeable Shares issued 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. Each Exchangeable Share
previously issued by AOG was exchangeable for Advantage Trust Units
at any time (subject to the provisions of the Voting and Exchange
Trust Agreement), on the basis of the applicable exchange ratio in
effect at that time. Dividends were not declared or paid on the
Exchangeable Shares and the Exchangeable Shares were not publicly
traded.
On March 8, 2006 AOG elected to exercise its redemption right to
redeem all of the Exchangeable Shares outstanding. The redemption
price per Exchangeable Share was satisfied by delivering that number
of Advantage Trust Units equal to the Exchange Ratio of 1.22138 in
effect on May 9, 2006.
10. Unitholders' Equity
(a) Unitholders' capital
(i) Authorized
Unlimited number of voting Trust Units
(ii) Issued
Number of Units Amount
---------------------------------------------------------------------
Balance at December 31, 2004 49,674,783 $ 515,544
2004 non-cash performance incentive 763,371 16,570
Issued for cash, net of costs 5,250,000 107,616
Issued on conversion of debentures 783,870 13,139
Issued on conversion of exchangeable shares 1,374,300 28,705
-------------------------------------------------------------------
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
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
---------------------------------------------------------------------
105,390,470 $1,618,025
---------------------------------------------------------------------
Management internalization escrowed
Trust Units (25,267)
---------------------------------------------------------------------
Balance at December 31, 2006 $1,592,758
---------------------------------------------------------------------
On January 19, 2005, Advantage issued 763,371 Trust Units to
partially satisfy the obligation related to the 2004 year end
performance incentive fee.
On February 9, 2005, Advantage issued 5,250,000 Trust Units at $21.65
per Trust Unit for net proceeds of $107.6 million (net of
Underwriters' fees and other issue costs of $6.1 million). The net
proceeds of the offering were used to pay down debt incurred in the
acquisition of Defiant, for 2005 capital expenditures and for general
corporate purposes.
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 (note 14). A total of
19,366 Trust Units related to the internalization have been forfeited
since issuance. The Fund also issued 177,662 Trust Units, 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, 2006, 2,005,499 Trust
Units were issued under the Plan, generating $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.
(b) 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 A Series B
Number Price Number Price
---------------------------------------------------------------------
Balance at
December 31, 2004 85,000 $ 5.05 225,000 $ 16.75
Reduction of exercise
price - (3.12) - (3.12)
---------------------------------------------------------------------
Balance at
December 31, 2005 85,000 1.93 225,000 13.63
Exercised (85,000) - (37,500) -
Reduction of exercise
price - (1.93) - (2.66)
---------------------------------------------------------------------
Balance at
December 31, 2006 - $ - 187,500 $ 10.97
---------------------------------------------------------------------
Expiration date August 16, 2006 June 17, 2008
---------------------------------------------------------------------
The Series A Trust Unit rights were issued in 2002 and the Fund was
unable to determine the fair value for the rights granted under the
Plan at that time. Several essential factors required to value such
rights include expected future exercise price, distributions,
exercise timeframe, volatility and risk-free interest rates. In
determining these assumptions, both historical data and future
expectations are considered. However, when the Series A Trust Unit
rights were originally granted, Advantage had only been established
during the prior year and there was little historical information
available that may suggest future expectations concerning such
assumptions. Therefore, it was concluded that a fair value
determination at that time was not possible. The Fund has disclosed
pro forma results as if the Fund followed the intrinsic value
methodology in accounting for such rights. The intrinsic value
methodology would result in recording compensation expense for the
rights based on the underlying Trust Unit price at the date of
exercise or at the date of the financial statements for unexercised
rights as compared to the exercise price. All of the remaining
85,000 Series A Trust Units Rights were exercised July 7, 2006 in
exchange for an equivalent number of Trust Units.
Year ended Year ended
December 31, December 31,
Pro Forma Results 2006 2005
---------------------------------------------------------------------
Net income, as reported $ 49,814 $ 75,072
Less compensation expense
for rights issued in 2002 (234) 300
---------------------------------------------------------------------
Pro forma net income $ 50,048 $ 74,772
---------------------------------------------------------------------
Net income per Trust Unit, as reported
Basic $ 0.62 $ 1.33
Diluted $ 0.61 $ 1.32
---------------------------------------------------------------------
Net income per Trust Unit, pro forma
Basic $ 0.62 $ 1.32
Diluted $ 0.62 $ 1.31
---------------------------------------------------------------------
(c) Net Income per Trust Unit
The calculation of basic and diluted net income per Trust Unit are
derived from both income available to Unitholders and weighted
average Trust Units outstanding calculated as follows:
Year ended Year ended
December 31, December 31,
2006 2005
---------------------------------------------------------------------
Income available to Unitholders
Basic $ 49,814 $ 75,072
Exchangeable shares - 232
---------------------------------------------------------------------
Diluted $ 49,814 $ 75,304
---------------------------------------------------------------------
Weighted average Trust Units outstanding
Basic 80,958,455 56,593,303
Trust Units Rights Incentive Plan
- Series A 43,548 76,698
Trust Units Rights Incentive Plan
- Series B 78,287 69,800
Exchangeable Shares - 298,341
Management Internalization 113,556 -
---------------------------------------------------------------------
Diluted 81,193,846 57,038,142
---------------------------------------------------------------------
The calculation of diluted net income per Trust Unit excludes all
series of convertible debentures as the impact would be anti-
dilutive. Exchangeable Shares have been excluded for the year ended
December 31, 2006 as the impact would have been 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, 2006 were 7,182,276
(2005 - 7,288,894). As at December 31, 2006, the total convertible
debentures outstanding were immediately convertible to 8,334,453
Trust Units (2005 - 6,818,833).
11. 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 October 31, 2006, the Federal
Government proposed changes to Canada's tax system that include
altering the tax treatment of income trusts. The government proposed
a two-tier tax structure, similar to that of corporations, whereby
distributions paid by trusts will be subject to tax at the trust
level in addition to personal tax as if they were dividends from a
taxable Canadian corporation. The changes are proposed to take
effect in 2011 for existing publicly-traded trusts. As the proposal
was not considered substantially enacted at December 31, 2006, these
changes are not reflected in the current financial statements. As at
December 31, 2006, the Fund had unrecognized non-deductible temporary
differences of $601 million.
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,
2006 2005
---------------------------------------------------------------------
Income before taxes $ 14,265 $ 66,131
---------------------------------------------------------------------
Canadian combined federal and provincial
income tax rates 34.78% 37.98%
Expected income tax expense at statutory
rates 4,961 25,080
Increase (decrease) in income taxes
resulting from:
Non-deductible Crown charges 6,925 12,406
Resource allowance (8,108) (15,390)
Management internalization 4,678 -
Change in enacted tax rates (5,692) (3,230)
Amounts included in trust income and other (39,851) (30,237)
---------------------------------------------------------------------
Future income tax reduction (37,087) (11,371)
Income and capital taxes 1,509 2,198
---------------------------------------------------------------------
$ (35,578) $ (9,173)
---------------------------------------------------------------------
The components of the future income tax liability are as follows:
December 31, December 31,
2006 2005
---------------------------------------------------------------------
Property and equipment in excess of tax
basis $ 85,648 $ 119,065
Asset retirement obligations (10,141) (7,230)
Non-capital tax loss carry forward (8,851) (11,228)
Other (4,717) (1,581)
---------------------------------------------------------------------
Future income tax liability $ 61,939 $ 99,026
---------------------------------------------------------------------
AOG has a non-capital tax loss carry forward of approximately
$29.3 million of which $1.2 million expires in 2010, $27.4 million in
2011, and $0.7 million in 2021.
12. Accumulated Deficit
Accumulated deficit consists of accumulated income and accumulated
distributions for the Fund since inception as follows:
December 31, December 31,
2006 2005
---------------------------------------------------------------------
Accumulated Income $ 227,523 $ 177,709
Accumulated Distributions (664,629) (447,383)
---------------------------------------------------------------------
Accumulated Deficit $ (437,106) $ (269,674)
---------------------------------------------------------------------
For the year ended December 31, 2006 the Fund declared $217.2 million
in distributions, representing $2.66 per distributable Trust Unit
(2005 - $177.4 million representing $3.12 per distributable Trust
Unit).
13. Financial Instruments
Financial instruments of the Fund include accounts receivable,
deposits, accounts payable and accrued liabilities, distributions
payable, and bank indebtedness. As at December 31, 2006, 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. Substantially all of the
Fund's accounts receivable are due from customers and joint venture
partners in the oil and gas industry and are subject to normal
industry credit risks. Credit risk is mitigated by entering into
sales contracts with only stable, creditworthy parties and through
frequent reviews of exposures to individual entities. The carrying
value of accounts receivable reflects Management's assessment of the
associated credit risks. The Fund is further exposed to interest rate
risk to the extent that bank indebtedness is at a floating rate of
interest.
In addition, the Fund has outstanding convertible debenture
obligations that are financial liabilities. The convertible
debentures have different fixed terms and interest rates (note 7)
resulting in fair values that will vary over time as market
conditions change. As at December 31, 2006, the estimated fair value
of the total outstanding convertible debenture obligation was
$180.0 million (2005 - $137.5 million).
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 financial derivatives. 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 exposure to individual entities. As the
fair value of the contracts varies with commodity prices, they give
rise to financial assets or liabilities. As at December 31, 2006 the
Fund had the following financial derivatives in place:
Description of
Financial
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Fixed November 2006
price to March 2007 5,687 mcf/d Cdn$8.70/mcf
Fixed November 2006
price to March 2007 3,791 mcf/d Cdn$10.02/mcf
November 2006 Floor Cdn$8.18/mcf
Collar to March 2007 9,478 mcf/d Ceiling Cdn$11.24/mcf
November 2006 Floor Cdn$8.44/mcf
Collar to March 2007 4,739 mcf/d Ceiling Cdn$12.40/mcf
November 2006 Floor Cdn$8.18/mcf
Collar to March 2007 4,739 mcf/d Ceiling Cdn$11.66/mcf
November 2006 Floor Cdn$8.44/mcf
Collar to March 2007 4,739 mcf/d Ceiling Cdn$12.29/mcf
November 2006 Floor Cdn$7.91/mcf
Collar to March 2007 5,687 mcf/d Ceiling Cdn$9.81/mcf
November 2006 Floor Cdn$8.44/mcf
Collar to March 2007 9,478 mcf/d Ceiling Cdn$13.82/mcf
Crude oil - WTI
October 2006 Floor US$65.00/bbl
Collar to March 2007 1,250 bbls/d Ceiling US$87.40/bbl
October 2006 Floor US$65.00/bbl
Collar to September 2007 1,000 bbls/d Ceiling US$90.00/bbl
Electricity - Alberta Pool Price
Fixed April 2006
price to December 2007 0.5 MW Cdn$60.79/MWh
Fixed January 2007
price to December 2007 3.0 MW Cdn$56.00/MWh
Fixed January 2008
price to December 2008 3.0 MW Cdn$54.00/MWh
As at December 31, 2006 the settlement amount of the financial
derivatives outstanding was an asset of approximately $10,433,000.
For the year ended December 31, 2006, $10,242,000 was recognized in
income as an unrealized derivative gain. As a result of the Ketch
merger, the Fund assumed several contracts which had an estimated
fair market value of $191,000 on closing.
14. 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. A total of
$13.4 million has been included as management internalization expense
for the year ended December 31, 2006 with 19,366 Trust Units
forfeited since issuance. 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. Management fees were
paid quarterly and $1.0 million was payable and included in accrued
liabilities at December 31, 2005.
The Manager was 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. The 2005 opening
and closing Unit prices were $21.71 and $22.19, respectively. Cash
distributions for the 2005 year amounted to $3.12 per Trust Unit. 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 performance incentive fee payable and included in accrued
liabilities at December 31, 2005 was $10.5 million. 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.
15. Commitments
Advantage has lease commitments relating to office buildings. The
estimated annual minimum operating lease rental payments for the
buildings, after deducting sublease income, are as follows:
2007 $ 2,256
2008 1,385
2009 779
2010 779
2011 195
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$ 5,394
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16. Subsequent Event
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 $104.2 million (net of Underwriters' fees
and other issue costs of $5.9 million).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, 3100, 150 - 6th Avenue SW, Calgary, Alberta, T2P 3Y7, Phone: (403) 261-8810, Fax: (403) 262-0723, Web Site: www.advantageincome.com, E-mail: advantage@advantageincome.com