CALGARY, March 6 /PRNewswire-FirstCall/ - Advantage Energy Income Fund
("Advantage" or the "Fund") is pleased to announce the financial and operating
results and reserves for the year ended December 31, 2007.
A conference call will be held on Friday, March 7, 2008 at 9:00 a.m. MST
(11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-334-4934 and a slide presentation is available on our website. A replay
of the call will be available from approximately 2:00 p.m. EST on March 7,
2008 until approximately midnight, April 5, 2008 and can be accessed by
dialing toll free 1-866-245-6755. The passcode required for playback is
645732. A live web cast of the conference call will be accessible via the
Internet on Advantage's website at www.advantageincome.com.
Acquisition of Sound Energy Trust
- Advantage completed a highly synergistic and accretive acquisition of
Sound Energy Trust which closed on September 5, 2007.
- The acquisition added proven plus probable reserves of 31.4 million
boe at a cost of $14.77 per boe.
- In addition, the acquisition significantly increased Advantage's
undeveloped land base, tax pools, and exposure to light oil. The
acquisition provides a significant number of low risk drilling
locations, facilities consolidation opportunities and 83 sections of
land at Glacier in Northwest Alberta with potential for natural gas
resource play development in the Montney formation.
Successful 2007 Drilling Program and Efficient Reserves Additions
- Overall, the Fund replaced 379% of annual production at a Finding,
Development & Acquisition cost of $15.19 per proven plus probable
boe, excluding changes in future development capital, and $15.90 per
proven plus probable boe, including changes in future development
capital.
- Drill bit reserve additions resulted in strong Finding & Development
("F&D") costs of $16.96 per proven plus probable boe, excluding
changes in future development capital. The three year F&D average is
$15.91 per proven plus probable boe, excluding changes in future
development capital. The Fund replaced 80% of its production through
the drill bit.
- Strong operational execution throughout the year resulted in the
drilling of 112 gross (64.8 net) wells in 2007 at a 99% success rate.
During the fourth quarter of 2007 a total of 32 gross (16.6 net)
wells were drilled at a 100% success rate.
- With the inclusion of Sound's assets and opportunities, Advantage's
drilling inventory grew to over 750 locations representing over
5 years of drilling within our land base.
- The Fund's proven plus probable reserve life index remains among the
highest in the natural gas weighted sector at 12.1 years.
- The Fund's Net Asset Value, before tax increased to $12.96 per unit
at a 10% discount factor.
Commodity Prices
- Crude oil prices strengthened in 2007 due to continued global demand
growth which was partly offset by the rising Canadian dollar.
- Declining natural gas prices, the rising Canadian dollar and
increased service costs were key factors leading to lower revenue and
cash flow levels in the latter part of 2007 due to our natural gas
production weighting. This was partly offset by our natural gas
hedging program which generated gains of $16.5 million in the second
half of 2007.
- The outlook for gas prices has since improved with colder weather in
early 2008. Key factors that are contributing to a more optimistic
view on prices for the remainder of 2008 include a 7 year low in
natural gas drilling activity in Canada, projections for lower LNG
deliveries into the U.S. in 2008 and higher demand for natural gas
fired electrical generation.
Hedging
- For 2008, we have secured approximately 51% of our net natural gas
production at an average Canadian floor price of $7.43 per mcf
(currently equivalent to NYMEX US$8.43 per mcf) and 38% of our oil
production at an average floor price of Canadian $94.07 per bbl
(currently equivalent to NYMEX WTI US$95.95 per bbl).
- The primary purpose of our hedging program is to i) reduce cash flow
volatility and ii) ensure that our capital program is substantially
funded out of cash flow.
Federal Government Tax Fairness Proposal
- On October 31, 2006 the Canadian Federal Government announced its
intention to impose a tax on income trusts beginning in 2011. This
announcement has continued to create uncertainty among the Trust
sector resulting in consolidation and a drive to consider alternate
structures.
- Advantage remains in a very strong position given our considerable
tax pool base of $1.7 billion which is available to shield future
taxes for many years after 2011 and also provides the Fund with more
options as alternatives to the Royalty Trust structure are
considered.
- It is the Fund's intention to continue to be a cash distributing
entity after 2010. We will continue to closely monitor industry
dynamics and are considering a number of alternative structures in
order to maximize after-tax value for Unitholders.
Alberta's Royalty Program Changes
- On October 25, 2007, the Alberta Government issued a proposal to
increase provincial royalties in 2009 on oil sands and conventional
oil and natural gas production. Advantage's analysis indicates a
minimal impact on the Fund due to the number of lower rate wells
within our long life assets which will receive favorable treatment.
Advantage is Well positioned for 2008
- The market was filled with uncertainty in 2007 including reduced
access to capital resulting from the Federal Government's October
2006 announcement and soft natural gas prices. Advantage responded in
2007 by completing a highly accretive acquisition, protecting our
cash flow through commodity price hedging and adjusting our
distributions to reduce the payout ratio to position the Fund for
growth opportunities in 2008 and beyond.
- With our cash flow stream protected through commodity price hedging
in 2008 and the current distribution level, we expect to
substantially fund our capital program out of cash flow and preserve
flexibility for additional opportunities throughout the year.
- Our 2008 capital program includes a strong suite of attractive
development drilling locations at Martin Creek, Nevis, Willesden
Green, Chip Lake, Sunset, Southern Alberta and Southeast
Saskatchewan. In addition, further delineation drilling is planned
for our Montney formation natural gas resource property at Glacier in
Northwest Alberta (located directly adjacent to the very successful
Swan Lake Pool development).
- Our underlying strengths continue to place Advantage in an enviable
position:
- Long-life asset base and stable production platform,
- High quality drilling inventory that exceeds 5 years,
- Superior technical and administrative team that is highly
motivated to create Unitholder value,
- Considerable tax pool base, and
- Reduced payout ratio.
First Quarter 2008 Drilling Highlights
- Execution of the 2008 winter drilling program is on schedule and
costs are on-track.
- At Martin Creek in Northeast British Columbia a 10 well drilling
program is nearing completion and results are anticipated to meet
expectations.
- At Glacier in Northwest Alberta, 4 vertical delineation wells have
been drilled into the Montney formation where completions and testing
are underway with an additional well currently drilling. Advantage's
83 section land block contains several existing Montney well
penetrations and extensive 3-dimensional seismic coverage. Our plans
for the balance of 2008 include additional vertical wells which will
be required to assess the potential for future horizontal well
development and production. This approach is similar to the
development plan conducted at the adjacent Swan Lake and Tupper pool
projects, where significant Montney development is occurring.
- At Nevis, Alberta horizontal drilling for light oil in the newer
western development area has been 100% successful with initial
production rates at or above expectations. A multi-year drilling
inventory and enhanced oil recovery potential exists on this
property.
- To date 53 gross (31.2 net) wells have been drilled in 2008 at a 97%
success rate.
- The Fund has significant behind pipe volumes as a result of these
activities which will be brought on-stream in the second quarter and
throughout 2008.
As a final remark, we wish to acknowledge the dedication and hard work
from all of our directors, employees and personnel who continued to strive for
success despite a year of commodity price and political uncertainty.
We look forward to 2008 with much optimism and confidence in our Fund.
Financial and Operating Highlights
Year ended
December 31, 2007 2006 2005 2004 2003
Financial ($000 except
per unit and per boe
amounts)
Revenue before
royalties(1) 557,358 419,727 376,572 241,481 166,075
per Trust Unit(2) 4.66 5.18 6.65 5.89 5.44
per boe 50.97 48.41 51.27 38.92 36.81
Funds from operations 271,143 214,758 211,541 126,478 94,735
per Trust Unit(3) 2.22 2.65 3.72 3.05 3.09
per boe 24.79 24.78 28.80 20.39 21.01
Net income (loss) (7,535) 49,814 75,072 24,038 38,503
per Trust Unit(2) (0.06) 0.62 1.33 0.59 1.26
Distributions declared 215,194 217,246 177,366 117,655 83,382
per Trust Unit(3) 1.77 2.66 3.12 2.82 2.71
Expenditures on property
and equipment 148,725 159,487 103,229 107,893 76,212
Working capital
deficit(4) 28,087 42,655 31,612 56,408 47,143
Bank indebtedness 547,426 410,574 252,476 267,054 102,968
Convertible debentures
(face value) 224,612 180,730 135,111 148,450 99,984
Trust Units outstanding
at end of year 138,269 105,390 57,846 49,675 36,717
Basic weighted average
Trust Units 119,604 80,958 56,593 41,008 30,536
Operating
Daily Production
Natural gas (mcf/d) 116,998 94,074 78,561 77,188 57,631
Crude oil and NGLs
(bbls/d) 10,462 8,075 7,029 4,084 2,756
Total boe/d @ 6:1 29,962 23,754 20,123 16,949 12,361
Average pricing
(including hedging)
Natural gas ($/mcf) 7.21 6.86 7.98 6.08 6.07
Crude oil & NGLs
($/bbl) 65.38 62.44 57.58 46.58 38.14
Proved plus probable
reserves(5)
Natural gas (bcf) 546.4 442.7 286.9 296.9 237.4
Crude oil & NGLs
(mbbls) 61,131 47,524 36,267 34,316 13,697
Total mboe 152,203 121,317 84,082 83,799 53,271
Reserve life index
(years)(6) 12.1 11.4 12.0 9.9 9.1
(1) includes realized derivative gains and losses
(2) based on basic weighted average Trust Units outstanding
(3) based on Trust Units outstanding at each distribution record date
(4) working capital deficit excludes derivative assets and liabilities
(5) 2007, 2006, 2005 and 2004 represents company interest reserves with
2003 being gross working interest reserves
(6) based on Q4 production rates
RESERVES
Advantage's year end reserve evaluation is based on an independent
engineering study conducted by Sproule Associates Limited ("Sproule")
effective December 31, 2007 and prepared in accordance with National
Instrument 51-101 ("NI 51-101").
Reserves included herein are stated on a Company Interest basis (before
royalty burdens and including royalty interests receivable) unless noted
otherwise. This report contains several cautionary statements that are
specifically required by NI 51-101. In addition to the detailed information
disclosed in this press release more detailed information on a net interest
basis (after royalty burdens and including royalty interests) and on a gross
interest basis (before royalty burdens and excluding royalty interests) will
be included in Advantage's Annual Information Form ("AIF") and will be
available at www.advantageincome.com and www.sedar.com.
Highlights - Company Interest Reserves (Working Interests plus Royalty
Interests Receivable)
- The Fund's net asset value at December 31, 2007 is $12.96 per Unit,
(using a 10% discount factor).
- Proved plus probable ("P+P") reserve life index remains among the
highest in the gas weighted sector at 12.1 years.
- Replaced 379% of annual production at an all-in Finding, Development
& Acquisition ("FD&A") cost of $15.19 per P+P boe before
consideration of future development capital. Including future
development capital, the FD&A cost was $15.90 per P+P boe. This
includes the acquisition of Sound Energy Trust, which was effective
September 5, 2007.
December 31, December 31,
2007 2006
-------------------------------------------------------------------------
Proved plus probable reserves (mboe) 152,203 121,317
Present Value of reserves discounted at 10%,
proved plus probable ($000) $2,462,610 $1,850,073
Net Asset Value per Unit discounted at 10% $12.96 $12.29
Reserve Life Index (proved plus probable -
years)(1) 12.1 11.4
Reserves per Unit (proved plus probable)(2) 1.10 1.15
Bank debt per boe of reserves(3) $3.60 $3.38
Convertible debentures per boe of reserves(3) $1.48 $1.49
(1) Based on Q4 average production.
(2) Based on 138.3 million Units outstanding at December 31, 2007, and
105.6 million Units outstanding as December 31, 2006.
(3) BOE's may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio for natural gas of
6 Mcf: 1 bbl has been used which is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
Company Interest Reserves - Summary as at December 31, 2007
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed Producing 22,222 1,840 6,714 288,398 78,842
Developed Non-producing 473 129 268 13,098 3,054
Undeveloped 3,622 297 941 52,927 13,680
Total Proved 26,317 2,266 7,923 354,423 95,576
-------------------------------------------------------------------------
Probable 17,540 3,282 3,803 192,013 56,627
Total Proved + Probable 43,857 5,548 11,726 546,436 152,203
-------------------------------------------------------------------------
Present Value of Future Net Revenue using Sproule price and cost
forecasts before taxes(1) ($000)
Before Income Taxes Discounted at
0% 5% 10%
-------------------------------------------------------------------------
Proved
Developed Producing $ 2,680,441 $ 1,904,687 $ 1,526,798
Developed Non-producing 83,654 67,773 56,479
Undeveloped 298,697 217,260 155,502
Total Proved 3,062,792 2,189,720 1,738,779
-------------------------------------------------------------------------
Probable 2,038,534 1,100,986 723,831
Total Proved + Probable $ 5,101,326 $ 3,290,706 $ 2,462,610
-------------------------------------------------------------------------
Present Value of Future Net Revenue using Sproule price and cost
forecasts after taxes(1) ($000)
After Income Taxes Discounted at
0% 5% 10%
-------------------------------------------------------------------------
Proved
Developed Producing $ 2,680,441 $ 1,904,687 $ 1,526,798
Developed Non-producing 83,654 67,773 56,479
Undeveloped 298,697 217,260 155,502
Total Proved 3,062,792 2,189,720 1,738,779
-------------------------------------------------------------------------
Probable 1,725,276 1,009,487 691,310
Total Proved + Probable $ 4,788,068 $ 3,199,208 $ 2,430,090
-------------------------------------------------------------------------
(1) Advantage's crude oil, natural gas and natural gas liquid reserves
were evaluated using Sproule's product price forecast effective
December 31, 2007 prior to, interests, debt services charges and
general and administrative expenses. It should not be assumed that
the discounted future revenue estimated by Sproule represents the
fair market value of the reserves.
Sproule Price Forecasts
The present value of future net revenue at December 31, 2007 was based
upon crude oil and natural gas pricing assumptions prepared by Sproule
effective December 31, 2007. These forecasts are adjusted for reserve quality,
transportation charges and the provision of any applicable sales contracts.
The price assumptions used over the next seven years are summarized in the
table below:
Alberta
AECO-C Henry Hub
WTI Edmonton Natural Natural
Crude Light Gas Gas Exchange
Oil Crude Oil ($Cdn/ ($US/ Rate
Year ($US/bbl) ($Cdn/bbl) mmbtu) mmbtu) ($US/$Cdn)
-------------------------------------------------------------------------
2008 89.61 88.17 6.51 7.56 1.00
2009 86.01 84.54 7.22 8.27 1.00
2010 84.65 83.16 7.69 8.74 1.00
2011 82.77 81.26 7.70 8.75 1.00
2012 82.26 80.73 7.61 8.66 1.00
2013 82.81 81.25 7.78 8.83 1.00
2014 84.46 82.88 7.96 9.01 1.00
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 before
taxes(1) - December 31, 2006 $ 30.39 $ 17.92 $ 12.29
-------------------------------------------------------------------------
Present value proved and probable
reserves $ 5,101,326 $ 3,290,706 $ 2,462,610
Undeveloped acreage and
seismic(2) 111,559 111,559 111,559
Working capital (deficit) (9,634) (9,634) (9,634)
Convertible debentures (224,612) (224,612) (224,612)
Bank debt (547,426) (547,426) (547,426)
Net asset value - December 31,
2007 $ 4,431,213 $ 2,620,593 $ 1,792,497
-------------------------------------------------------------------------
Net asset value per Unit after
taxes(1) - December 31, 2007 $ 32.05 $ 18.95 $ 12.96
-------------------------------------------------------------------------
(1) Based on 138.3 million Units outstanding at December 31, 2007, and
105.6 million Units outstanding at December 31, 2006.
(2) Internal estimate
Gross Working Interest Reserves - Summary as at December 31, 2007
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
(mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Proved
Developed Producing 22,060 1,814 6,646 285,551 78,111
Developed Non-producing 473 126 266 12,814 3,001
Undeveloped 3,621 297 928 52,568 13,608
Total Proved 26,154 2,237 7,840 350,933 94,720
-------------------------------------------------------------------------
Probable 17,477 3,271 3,773 190,613 56,289
Total Proved + Probable 43,630 5,508 11,613 541,546 151,009
-------------------------------------------------------------------------
Gross Working Interest Reserves Reconciliation
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
Proved (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2006 19,935 1,908 7,375 292,779 78,015
Extensions 327 55 232 14,694 3,062
Improved recovery 678 0 197 14,716 3,328
Discoveries 24 0 9 636 139
Economic factors 370 1 (105) (572) 170
Technical revisions 177 (562) (95) (2,710) (930)
Acquisitions 7,348 1,083 1,093 74,094 21,872
Dispositions 0 0 0 0 0
Production (2,705) (248) (866) (42,704) (10,936)
-------------------------------------------------------------------------
Closing balance at
Dec. 31, 2007 26,154 2,237 7,840 350,933 94,720
-------------------------------------------------------------------------
Light & Natural Oil
Medium Heavy Gas Natural Equiv-
Oil Oil Liquids Gas alent
Proved + Probable (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
-------------------------------------------------------------------------
Opening balance
Dec. 31, 2006 33,521 2,596 11,208 439,345 120,549
Extensions 1,667 68 519 30,191 7,285
Improved recovery 1,322 0 546 44,193 9,234
Discoveries 41 0 11 795 184
Economic factors 493 2 (133) 1,048 537
Technical revisions (1,271) (674) (1,110) (32,510) (8,472)
Acquisitions 10,562 3,764 1,438 101,188 32,628
Dispositions 0 0 0 0 0
Production (2,705) (248) (866) (42,704) (10,936)
-------------------------------------------------------------------------
Closing balance at
Dec. 31, 2007 43,630 5,508 11,613 541,546 151,009
-------------------------------------------------------------------------
Finding, Development & Acquisitions Costs ("FD&A")(1)
FD&A Costs - Gross Working Interest Reserves excluding Future Development
Capital
Proved Proved + Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 148,725 $ 148,725
Acquisitions net of dispositions ($000) 479,955 479,955
-------------------------------------------------------------------------
Total capital ($000) $ 628,680 $ 628,680
-------------------------------------------------------------------------
Total mboe, end of period
94,720 151,009
Total mboe, beginning of period 78,015 120,549
Production, mboe 10,936 10,936
-------------------------------------------------------------------------
Reserve additions, mboe 27,641 41,396
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 22.74 $ 15.19
Three year average FD&A Costs ($/boe) $ 27.51 $ 19.20
F&D costs ($/boe) $ 25.78 $ 16.96
Three year average F&D costs ($/boe) $ 22.02 $ 15.91
NI 51-101
FD&A Costs - Gross Working Interest Reserves including Future Development
Capital
Proved Proved + Probable
-------------------------------------------------------------------------
Capital expenditures ($000) $ 148,725 $ 148,725
Acquisitions net of dispositions ($000) 479,955 479,955
Net change in Future Development Capital 6,517 29,517
-------------------------------------------------------------------------
Total capital ($000) $ 635,197 $ 658,197
-------------------------------------------------------------------------
Reserve additions, mboe 27,641 41,396
-------------------------------------------------------------------------
FD&A costs ($/boe) $ 22.98 $ 15.90
Three year average FD&A Costs ($/boe) $ 27.94 $ 20.21
F&D costs ($/boe) $ 26.91 $ 20.33
Three year average F&D costs ($/boe) $ 23.21 $ 19.68
(1) Under NI 51-101, the methodology to be used to calculate FD&A costs
includes incorporating changes in future development capital ("FDC")
required to bring the proved undeveloped and probable reserves to
production. For continuity, Advantage has presented herein FD&A costs
calculated both excluding and including FDC.
The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated future
development costs generally will not reflect total finding and development
costs related to reserves additions for that year. Changes in forecast FDC
occur annually as a result of development activities, acquisition and
disposition activities and capital cost estimates that reflect Sproule's best
estimate of what it will cost to bring the proved undeveloped and probable
reserves on production.
In all cases, the FD&A number is calculated by dividing the identified
capital expenditures by the applicable reserve additions. Boes may be
misleading, particularly if used in isolation. A boe conversion ratio of 6
MCF:1 BBL is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.
Land Inventory at December 31, 2007
Developed Acres Undeveloped Acres
Gross Net Gross Net
-------------------------------------------------------------------------
Alberta 1,238,745 647,934 789,914 429,360
British Columbia 159,486 73,877 109,807 64,153
Saskatchewan 50,660 38,312 226,301 192,071
-------------------------------------------------------------------------
Total Acreage 1,448,891 760,123 1,126,022 685,584
-------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION & ANALYSIS
The following Management's Discussion and Analysis ("MD&A"), dated as of
March 5, 2008, provides a detailed explanation of the financial and operating
results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we"
or "our") for the quarter and year ended December 31, 2007 and should be read
in conjunction with the audited consolidated financial statements. The
consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP") and all references
are to Canadian dollars unless otherwise indicated. All per barrel of oil
equivalent ("boe") amounts are stated at a conversion rate of six thousand
cubic feet of natural gas being equal to one barrel of oil or liquids.
Non-GAAP Measures
The Fund discloses several financial measures in the MD&A that do not have
any standardized meaning prescribed under GAAP. These financial measures
include funds from operations, funds from operations per Trust Unit and cash
netbacks. Management believes that these financial measures are useful
supplemental information to analyze operating performance, leverage and
provide an indication of the results generated by the Fund's principal
business activities prior to the consideration of how those activities are
financed or how the results are taxed. Investors should be cautioned that
these measures should not be construed as an alternative to net income, cash
provided by operating activities or other measures of financial performance as
determined in accordance with GAAP. Advantage's method of calculating these
measures may differ from other companies, and accordingly, they may not be
comparable to similar measures used by other companies.
Funds from operations, as presented, is based on cash provided by
operating activities before expenditures on asset retirement and changes in
non-cash working capital. Funds from operations per Trust Unit is based on the
number of Trust Units outstanding at each distribution record date. Cash
netbacks are dependent on the determination of funds from operations and
include the primary cash revenues and expenses on a per boe basis that
comprise funds from operations. Funds from operations reconciled to cash
provided by operating activities is as follows:
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Cash provided
by operating
activities $ 83,366 $ 65,495 27% $ 249,132 $ 229,087 9%
Expenditures on
asset retirement 2,116 3,462 (39)% 6,951 5,974 16%
Changes in non-
cash working
capital (4,963) (6,220) (20)% 15,060 (20,303)(174)%
-------------------------------------------------------------------------
Funds from
operations $ 80,519 $ 62,737 28% $ 271,143 $ 214,758 26%
-------------------------------------------------------------------------
Forward-Looking Information
The information in this report contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often, but not
always, identified by the use of words such as "seek", "anticipate", "plan",
"continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe",
"would" and similar expressions. These statements involve substantial known
and unknown risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are interpreted and
enforced; fluctuations in commodity prices and foreign exchange and interest
rates; stock market volatility and market valuations; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions; changes in income tax laws or changes in tax laws,
royalty regimes and incentive programs relating to the oil and gas industry
and income trusts; geological, technical, drilling and processing problems and
other difficulties in producing petroleum reserves; obtaining required
approvals of regulatory authorities and other risk factors set forth in
Advantage's Annual Information Form which is available at
www.advantageincome.com or www.sedar.com. Advantage's actual results,
performance or achievement could differ materially from those expressed in, or
implied by, such forward-looking statements and, accordingly, no assurances
can be given that any of the events anticipated by the forward-looking
statements will transpire or occur or, if any of them do, what benefits that
Advantage will derive from them. Except as required by law, Advantage
undertakes no obligation to publicly update or revise any forward-looking
statements.
Acquisition of Sound Energy Trust
On September 5, 2007, the previously announced acquisition of Sound Energy
Trust ("Sound") was completed. The financial and operational information for
the quarter and year ended December 31, 2007 reflects operations from the
Sound properties effective from the closing date, September 5, 2007.
The acquisition was accomplished through a Plan of Arrangement (the
"Arrangement") by the exchange of each Sound Trust Unit for 0.30 of an
Advantage Trust Unit or, at the election of the holder of Sound Trust Units,
$0.66 in cash and 0.2557 of an Advantage Trust Unit. In addition, all Sound
Exchangeable Shares were exchanged for Advantage Trust Units on the same ratio
based on the conversion ratio in effect at the effective date of the
Arrangement. Advantage issued 16,977,184 Trust Units and paid $21.4 million
cash as consideration to acquire Sound. The transaction is accretive to
Advantage's Unitholders on a production, cash flow, reserves and net asset
value basis and has significantly increased Advantage's tax pool position to a
total of approximately $1.7 billion, and Safe Harbour expansion room to
approximately $2.0 billion. Sound's higher oil weighting, synergy with many of
Advantage's core properties and significant undeveloped land holdings of
approximately 400,000 net undeveloped acres will further enhance the operating
platform of Advantage.
Overview
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Cash provided
by operating
activities
($000) $ 83,366 $ 65,495 27% $ 249,132 $ 229,087 9%
Funds from
operations
($000) $ 80,519 $ 62,737 28% $ 271,143 $ 214,758 26%
per Trust
Unit(1) $ 0.58 $ 0.59 (2)% $ 2.22 $ 2.63 (16)%
Net income
(loss) ($000) $ 13,795 $ 8,736 58% $ (7,535)$ 49,814 (115)%
per Trust Unit
- Basic $ 0.10 $ 0.08 25% $ (0.06)$ 0.62 (110)%
- Diluted $ 0.10 $ 0.08 25% $ (0.06)$ 0.61 (110)%
(1) Based on Trust Units outstanding at each distribution record date.
Cash provided by operating activities increased 27%, funds from operations
increased 28%, and funds from operations per Trust Unit modestly decreased 2%
for the three months ended December 31, 2007, as compared to the same period
of 2006. For the year ended December 31, 2007, cash provided by operating
activities increased 9%, funds from operations increased 26%, and funds from
operations per Trust Unit decreased 16%. Cash provided by operating activities
and funds from operations for the quarter and year were positively impacted by
increased revenues due to additional production from the Sound acquisition and
the year was further impacted by a full year of production from the Ketch
acquisition that closed in 2006. Funds from operations per Trust Unit
decreased during the periods due to a higher average number of Trust Units
outstanding. The weighted average number of Trust Units has increased 32% for
the three months and 48% for the year ended in 2007 compared to 2006, mainly
due to the Sound acquisition, the Trust Unit financing in the first quarter of
2007 and the distribution reinvestment plan. When compared to the third
quarter of 2007, funds from operations increased 29% due to production
increases of 17% from the acquisition of Sound and stronger commodity prices.
Natural gas prices, excluding hedging, increased 11% and crude oil and NGL
prices, excluding hedging, increased 6% for the fourth quarter of 2007 as
compared to the prior quarter. The Fund also realized net derivative gains of
$5.2 million in the three months and $18.6 million for the year ended December
31, 2007 which also helped to strengthen cash provided by operating activities
and funds from operations.
Net income for the quarter increased 58% over prior year due to higher
crude oil prices and higher production from the Sound acquisition, offset
somewhat by higher costs from the acquisition and general growth of the Fund.
Net income for the year decreased to a net loss for the twelve months ended
December 31, 2007 primarily due to higher operating costs, as well as non-cash
expenses such as amortization of the management contract internalization and
higher depletion and depreciation expense. The primary factor that causes
significant variability of Advantage's cash provided by operating activities,
funds from operations, and net income is commodity prices. Refer to the
section "Commodity Prices and Marketing" for a more detailed discussion of
commodity prices and our price risk management.
Distributions
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Distributions
declared ($000) $ 57,875 $ 58,791 (2)% $ 215,194 $ 217,246 (1)%
per Trust
Unit (1) $ 0.42 $ 0.56 (25)% $ 1.77 $ 2.66 (33)%
(1) Based on Trust Units outstanding at each distribution record date.
Total distributions declared decreased 2% for the three months and 1% for
the year ended December 31, 2007 when compared to the same periods in 2006.
Total distributions declared are slightly lower as a result of the decreases
in the distribution per Trust Unit in January and December 2007. The decreases
in per Trust Unit distributions are offset by additional distributions due to
the increased Trust Units outstanding from the continued growth and
development of the Fund. Since natural gas prices were very weak during the
2006/2007 winter season, we reduced the distribution level in January 2007 and
as natural gas prices continued to show prolonged weakness throughout 2007, we
decreased the distribution level further in December 2007 to more
appropriately reflect the current commodity price environment. Distributions
per Trust Unit were $0.42 for the three months and $1.77 for the year ended
December 31, 2007, representing a decrease of 25% and 33% from same periods in
2006. The monthly distribution is currently $0.12 per Trust Unit. To mitigate
the persisting risk associated with lower commodity prices and the resulting
negative impact on cash flows, the Fund implemented a hedging program with 51%
of natural gas production and 38% of crude oil production, net of royalties,
hedged for 2008. See "Commodity Price Risk" section for a more detailed
discussion of our price risk management.
Distributions from the Fund to Unitholders are entirely discretionary and
are determined by Management and the Board of Directors. We closely monitor
our distribution policy considering forecasted cash flows, optimal debt
levels, capital spending activity, taxability to Unitholders, working capital
requirements, and other potential cash expenditures. Distributions are
announced monthly and are based on the cash available after retaining a
portion to meet such spending requirements. The level of distributions are
primarily determined by cash flows received from the production of oil and
natural gas from existing Canadian resource properties and will be susceptible
to the risks and uncertainties associated with the oil and natural gas
industry generally. If the oil and natural gas reserves associated with the
Canadian resource properties are not supplemented through additional
development or the acquisition of additional oil and natural gas properties,
our distributions will decline over time in a manner consistent with declining
production from typical oil and natural gas reserves. Therefore, distributions
are highly dependent upon our success in exploiting the current reserve base
and acquiring additional reserves. Furthermore, monthly distributions we pay
to Unitholders are highly dependent upon the prices received for such oil and
natural gas production. Oil and natural gas prices can fluctuate widely on a
month-to-month basis in response to a variety of factors that are beyond our
control. Declines in oil or natural gas prices will have an adverse effect
upon our operations, financial condition, reserves and ultimately on our
ability to pay distributions to Unitholders. The Fund attempts to mitigate the
volatility in commodity prices through our hedging program. It is our
long-term objective to provide stable and sustainable distributions to the
Unitholders, while continuing to grow the Fund. However, given that funds from
operations can vary significantly from month-to-month due to these factors,
the Fund may utilize various financing alternatives as an interim measure to
maintain stable distributions.
For Canadian and U.S. holders of Advantage Trust Units, the distributions
paid for 2007 were 100% taxable. All Unitholders of the Fund are encouraged to
consult their tax advisors as to the proper treatment of Advantage
distributions for income tax purposes.
Revenue
Three months ended Year ended
December 31 December 31
($000) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Natural gas
excluding
hedging $ 73,662 $ 74,309 (1)% $ 286,777 $ 231,548 24%
Realized hedging
gains 8,762 4,046 117% 20,933 4,164 403%
-------------------------------------------------------------------------
Natural gas
including
hedging $ 82,424 $ 78,355 5% $ 307,710 $ 235,712 31%
-------------------------------------------------------------------------
Crude oil and
NGLs excluding
hedging $ 87,079 $ 48,051 81% $ 251,987 $ 182,882 38%
Realized
hedging gains
(losses) (3,552) 1,133 (414)% (2,339) 1,133 (306)%
-------------------------------------------------------------------------
Crude oil and
NGLs including
hedging $ 83,527 $ 49,184 70% $ 249,648 $ 184,015 36%
-------------------------------------------------------------------------
Total revenue $165,951 $127,539 30% $ 557,358 $ 419,727 33%
-------------------------------------------------------------------------
Natural gas revenues, excluding hedging, have decreased 1% for the three
months and increased 24% for the year ended December 31, 2007, compared to
2006. The decrease in natural gas revenues for the three months is mainly due
to a 10% decrease in natural gas prices, excluding hedging, offset by an
equivalent 10% increase in production, primarily from the Sound acquisition.
Conversely, the increase in natural gas revenues for the 2007 year is mainly
due to the inclusion of a full year of production from the Ketch merger that
closed in 2006 and production from the Sound acquisition since September 5,
2007, while natural gas prices remained fairly constant. Crude oil and NGL
revenues, excluding hedging, have increased by 81% for the three months and
38% for the year ended December 31, 2007, compared to 2006. Crude oil and NGL
revenue increased due to additional production from the Sound acquisition and
the inclusion of a full year of production from the Ketch merger combined with
an increase in crude oil and NGL prices of 34% for the three months and 6% for
the year ended December 31, 2007. For the three months and year ended December
31, 2007, the Fund recognized natural gas and crude oil net hedging gains of
$5.2 million and $18.6 million primarily due to derivative contracts in place
that offset commodity prices fluctuations which can jeopardize revenues and
corresponding distributions.
Production
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Natural gas
(mcf/d) 128,556 117,134 10% 116,998 94,074 24%
Crude oil
(bbls/d) 10,410 7,148 46% 8,090 6,273 29%
NGLs (bbls/d) 2,485 2,422 3% 2,372 1,802 32%
-------------------------------------------------------------------------
Total (boe/d) 34,321 29,092 18% 29,962 23,754 26%
-------------------------------------------------------------------------
Natural gas (%) 63% 67% 65% 66%
Crude oil (%) 30% 25% 27% 26%
NGLs (%) 7% 8% 8% 8%
The Fund's total daily production averaged 34,321 boe/d for the three
months and 29,962 boe/d for the year ended December 31, 2007, an increase of
18% and 26%, respectively, compared with the same periods of 2006. Natural gas
production increased 10%, crude oil production increased 46%, and NGLs
production increased 3% for the fourth quarter of 2007. For the year ended
December 31, 2007, natural gas production increased 24%, crude oil production
increased 29%, and NGLs production increased 32%. Production for the quarter
increased due to the additional properties from the Sound acquisition. The
increase in production for the year ended December 31, 2007 has been primarily
attributed to a full year of production from the Ketch acquisition which
closed June 23, 2006 and production from the Sound acquisition which closed
September 5, 2007. Production for the fourth quarter increased 17% from the
third quarter of 2007 also due to a full quarter of production from the
acquisition of Sound.
Our successful first quarter 2007 drilling program at Martin Creek,
followed by continued success at Sunset, Nevis, Willesden Green, as well as
other areas in Southern Alberta and Saskatchewan throughout the year has
helped offset natural declines. In addition, our flattening production
platform, resulting from our continued focus on long life assets, is
contributing to a stable operating foundation. For 2008 we expect production
to average approximately 32,000 to 34,000 boe/d, weighted 62% to natural gas.
Approximately 55% of our capital spending will be directed to natural gas and
45% toward light oil projects which will enable us to increase our crude oil
production and capitalize on the stronger crude oil pricing environment.
Commodity Prices and Marketing
Natural Gas
Three months ended Year ended
December 31 December 31
($/mcf) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Realized natural
gas prices
Excluding
hedging $ 6.23 $ 6.90 (10)% $ 6.72 $ 6.74 -
Including
hedging $ 6.97 $ 7.27 (4)% $ 7.21 $ 6.86 5%
AECO monthly
index $ 6.00 $ 6.36 (6)% $ 6.61 $ 6.98 (5)%
Realized natural gas prices, excluding hedging, decreased 10% for the
three months and remained constant for the year ended December 31, 2007, as
compared to 2006. The price of natural gas is primarily based on supply and
demand fundamentals in the North American marketplace; however market
speculation activity has increased price volatility. Natural gas prices
declined for the current quarter and continued to remain weak for the entire
2007 year, as in 2006, due to exceedingly high storage levels, mild summer and
winter weather and a lack of storm activity in the Gulf of Mexico. Fourth
quarter natural gas inventory levels remained well above average, causing
continued downward pressure on commodity prices. However, early 2008 has
brought colder weather and significant inventory withdrawals have been
experienced, resulting in a rebound of natural gas prices. Natural gas storage
levels are now closer to expectation and only slightly above the five-year
average. In addition, there has been a tighter supply of natural gas, putting
further upward pressure on prices. These developments have been encouraging
and we continue to believe that the long-term pricing fundamentals for natural
gas remain strong. These fundamentals include (i) the continued strength of
crude oil prices, which has eliminated the economic advantage of fuel
switching away from natural gas evidenced by the increase in proposed gas
fired electrical generation facilities, (ii) significantly less natural gas
drilling in Canada projected for 2008, which will reduce productivity to
offset declines, (iii) the increasing focus on resource style natural gas
wells, which have high initial declines and require a higher threshold
economic price than conventional gas drilling and (iv) the demand for natural
gas for the Canadian oil sands projects.
Crude Oil and NGLs
Three months ended Year ended
December 31 December 31
($/bbl) 2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Realized crude
oil prices
Excluding
hedging $ 74.19 $ 56.10 32% $ 67.71 $ 63.85 6%
Including
hedging $ 70.48 $ 57.82 22% $ 66.92 $ 64.34 4%
Realized NGLs
prices
Excluding
hedging $ 70.09 $ 50.09 40% $ 60.12 $ 55.81 8%
Realized crude
oil and NGLs
prices
Excluding
hedging $ 73.40 $ 54.58 34% $ 65.99 $ 62.05 6%
Including
hedging $ 70.40 $ 55.86 26% $ 65.38 $ 62.44 5%
WTI ($US/bbl) $ 90.63 $ 60.21 51% $ 72.37 $ 66.35 9%
$US/$Canadian
exchange rate $ 1.02 $ 0.88 16% $ 0.94 $ 0.88 7%
Realized crude oil and NGLs prices, excluding hedging, increased 34% for
the three months and 6% for the year ended December 31, 2007, as compared to
the same periods of 2006. Advantage's crude oil prices are based on the
benchmark pricing of West Texas Intermediate Crude ("WTI") adjusted for
quality, transportation costs and $US/$Canadian exchange rates. For the three
months and year ended December 31, 2007, WTI increased 51% and 9%,
respectively, with momentous increases experienced in the fourth quarter of
2007. Advantage's realized crude oil price has not changed to the same extent
as WTI due to the strengthening of the Canadian dollar relative to the US
dollar and widened Canadian crude oil differentials relative to WTI. The price
of WTI fluctuates based on worldwide supply and demand fundamentals. There has
been significant price volatility experienced over the last several years
whereby WTI has reached historic high levels. Many developments have resulted
in the current price levels, including significant continuing geopolitical
issues and general market speculation. In fact, the impact of market
fundamentals has diminished as geopolitical events and speculation has
prevailed. As a result, prices have remained strong throughout 2007 and into
early 2008. With the current high price levels, it is notable that demand has
remained resilient even as the United States, the world's largest crude oil
consumer, experiences an economic slowdown. Regardless whether the current
price level is sustainable or just a short-term anomaly, we believe that the
pricing fundamentals for crude oil remain strong with many factors affecting
the continued strength including (i) supply management and supply restrictions
by the OPEC cartel, (ii) ongoing civil unrest in Venezuela, Nigeria, and the
Middle East, (iii) strong world wide demand, particularly in China, India and
the United States and (iv) North American refinery capacity constraints.
Commodity Price Risk
The Fund's operational results and financial condition will be dependent
on the prices received for oil and natural gas production. Oil and natural gas
prices have fluctuated widely during recent years and are determined by
economic and, in the case of oil prices, political factors. Supply and demand
factors, including weather and general economic conditions as well as
conditions in other oil and natural gas regions, impact prices. Any movement
in oil and natural gas prices could have an effect on the Fund's financial
condition and therefore on the distributions to holders of Advantage Trust
Units. As current and future practice, Advantage has established a financial
hedging strategy and may manage the risk associated with changes in commodity
prices by entering into derivatives. These commodity price risk management
activities could expose Advantage to losses or gains. To the extent that
Advantage engages in risk management activities related to commodity prices,
it will be subject to credit risk associated with counterparties with which it
contracts. Credit risk is mitigated by entering into contracts with only
stable, creditworthy parties and through frequent reviews of exposures to
individual entities.
We have been active in entering new financial contracts to protect future
cash flows and currently the Fund has the following derivatives in place:
Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas -
AECO
Fixed price November 2007
to March 2008 7,109 mcf/d Cdn$9.54/mcf
Fixed price April 2008 to
October 2008 14,217 mcf/d Cdn$6.85/mcf
Fixed price April 2008 to
October 2008 9,478 mcf/d Cdn$7.25/mcf
Fixed price April 2008 to
October 2008 14,217 mcf/d Cdn$7.83/mcf
Fixed price April 2008 to
March 2009 14,217 mcf/d Cdn$7.10/mcf
Fixed price April 2008 to
March 2009 14,217 mcf/d Cdn$7.06/mcf
Fixed price November 2008
to March 2009 14,217 mcf/d Cdn$7.77/mcf
Fixed price November 2008
to March 2009 4,739 mcf/d Cdn$8.10/mcf
Collar November 2007
to March 2008 9,478 mcf/d Floor Cdn$8.44/mcf
Ceiling Cdn$10.29/mcf
Collar November 2007
to March 2008 7,109 mcf/d Floor Cdn$8.70/mcf
Ceiling Cdn$10.71/mcf
Crude oil - WTI
Fixed price February 2008
to January 2009 2,000 bbls/d Cdn$90.93/bbl
Fixed price April 2008 to
March 2009 2,500 bbls/d Cdn$97.15/bbl
Collar February 2008
to January 2009 2,000 bbls/d Sold put Cdn$70.00/bbl
Purchased
call Cdn$105.00/bbl
Cost Cdn$1.52/bbl
As at December 31, 2007 the fair value of the derivatives outstanding was
a net asset of approximately $2.2 million. For the year ended December 31,
2007, $11.0 million was recognized in income as an unrealized derivative loss
due to changes in the fair value and settlement of such contracts since
December 31, 2006. For the same period we recognized in income a realized
derivative gain of $18.6 million upon the settlement of these financial
contracts, which partially alleviated lower revenue from continued weak
natural gas prices. As a result of the Sound acquisition, the Fund assumed
several derivatives which had an estimated net fair value on closing of $2.8
million. The change in fair value of these derivatives since acquisition to
the end of the period has been recognized in income as an unrealized
derivative gain or loss. The valuation of the derivatives is the estimated
fair value to settle the contracts as at December 31, 2007 and is based on
pricing models, estimates, assumptions and market data available at that time.
The actual gain or loss realized on eventual cash settlement can vary
materially due to subsequent fluctuations in commodity prices as compared to
the valuation assumptions. The Fund does not apply hedge accounting and
current accounting standards require changes in the fair value to be included
in the consolidated statement of income and comprehensive income as an
unrealized derivative gain or loss with a corresponding derivative asset and
liability recorded on the balance sheet.
The Fund has fixed the commodity price on anticipated production as
follows:
Approximate
Production Hedged, Average Average
Commodity Net of Royalties Floor Price Ceiling Price
-------------------------------------------------------------------------
Natural gas - AECO
January to March 2008 22% Cdn$8.85/mcf Cdn$10.19/mcf
April to June 2008 66% Cdn$7.22/mcf Cdn$7.22/mcf
July to September 2008 64% Cdn$7.22/mcf Cdn$7.22/mcf
October to December 2008 53% Cdn$7.32/mcf Cdn$7.32/mcf
-----------------------------------------------------------------------
Total 2008 51% Cdn$7.43/mcf Cdn$7.58/mcf
-----------------------------------------------------------------------
January to March 2009 46% Cdn$7.39/mcf Cdn$7.39/mcf
Crude Oil - WTI
January to March 2008 13% Cdn$90.93/bbl Cdn$90.93/bbl
April to June 2008 47% Cdn$94.39/bbl Cdn$94.39/bbl
July to September 2008 46% Cdn$94.39/bbl Cdn$94.39/bbl
October to December 2008 46% Cdn$94.39/bbl Cdn$94.39/bbl
-----------------------------------------------------------------------
Total 2008 38% Cdn$94.07/bbl Cdn$94.07/bbl
-----------------------------------------------------------------------
January to March 2009 32% Cdn$95.84/bbl Cdn$95.84/bbl
Royalties
Three months ended Year ended
December 31 December 31
2007 2006 %change 2007 2006 %change
-------------------------------------------------------------------------
Royalties, net
of Alberta
Royalty Credit
($
bourse
