Strong Production and Operating Performance in Q3 2010, Glacier On-Track to Double Production to 100 MMCF/D by Q2 2011
TSX: AAV, NYSE: AAV
CALGARY, Nov. 11 /CNW/ - Advantage Oil & Gas Ltd. ("Advantage" or the "Corporation") is pleased to announce its unaudited operating and financial results for the third quarter ended September 30, 2010.
Three months ended Nine months ended
Financial and Operating September 30 September 30
Highlights 2010 2009 2010 2009
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Financial ($000, except
as otherwise indicated)
Revenue before
royalties(1) $ 83,335 $ 93,101 $278,489 $330,710
per share(2) $ 0.51 $ 0.58 $ 1.71 $ 2.21
per boe $ 37.29 $ 42.82 $ 42.38 $ 42.66
Funds from operations $ 38,450 $ 42,213 $134,395 $149,394
per share(2) $ 0.23 $ 0.26 $ 0.82 $ 1.00
per boe $ 17.19 $ 19.42 $ 20.44 $ 19.27
Net loss $(16,915) $(53,293) $(26,039) $(72,213)
per share(2) $ (0.10) $ (0.33) $ (0.16) $ (0.48)
Expenditures on fixed
assets $ 65,491 $ 42,658 $154,390 $111,020
Working capital
deficit(3) $ 62,011 $109,581 $ 62,011 $109,581
Bank indebtedness $263,306 $330,800 $263,306 $330,800
Convertible debentures
(maturity value) $148,544 $132,221 $148,544 $132,221
Shares outstanding at end
of period (000) 163,720 162,476 163,720 162,476
Basic weighted average
shares (000) 163,537 161,182 163,276 149,916
Operating
Daily Production
Natural gas (mcf/d) 104,714 91,200 100,024 111,288
Crude oil and NGLs
(bbls/d) 6,835 8,431 7,398 9,853
Total boe/d @ 6:1 24,287 23,631 24,069 28,401
Average prices (including
hedging)
Natural gas ($/mcf) $ 4.80 $ 6.10 $ 5.68 $ 6.07
Crude oil and NGLs
($/bbl) $ 59.01 $ 54.02 $ 61.15 $ 54.38
(1) includes realized derivative gains and losses
(2) based on basic weighted average shares outstanding
(3) working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities, and
the current portion of capital lease obligations and convertible
debentures
MESSAGE TO SHAREHOLDERS
Financial Results Supported by Strong Production Performance, Reduced
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Cost Structure & Hedging Gains
------------------------------
- Average daily production of 24,287 boe/d for the third quarter of
2010 was supported by strong well and gas plant performance at
Glacier where Advantage's natural gas sales averaged 50.4 mmcf/d and
exited the third quarter of 2010 at 52.3 mmcf/d. Advantage's third
quarter 2010 corporate production represents a 23% increase through
the drill bit when compared to Q3 2009 after adjusting for non-core
asset sales. Corporate production is forecast to grow an additional
25% in 2011 to approximately 30,000 boe/d as illustrated in the graph
available at the following link:
http://files.newswire.ca/909/Graph.pdf
- Funds from operations for the third quarter of 2010 were $38.5
million or $0.23 per share. Funds from operations were supported by
strong production performance, lower operating, royalty and interest
costs and hedging gains.
- Total operating costs for the third quarter of 2010 decreased 9% to
$22.8 million and decreased 12% on a per boe basis to $10.21/boe as
compared to $25.1 million or $11.55/boe during the third quarter of
2009. Per boe operating costs decreased 4% as compared to the second
quarter of 2010. Total operating costs and on a per unit basis have
decreased as a result of the increasing contribution of low cost
production from Glacier, the disposition of higher cost non-core
assets, and the continued optimization of our other properties.
- The royalty rate as a percentage of revenue was 14.1% as compared to
15.1% in the second quarter of 2010. Total royalties paid during the
third quarter of 2010 decreased by 16% to $10.3 million as compared
to $12.2 million in the second quarter of 2010.
- Total interest expense on bank indebtedness for the third quarter of
2010 decreased 47% as compared to the third quarter of the prior year
due to a 20% decrease in bank indebtedness during the last twelve
months.
- As at September 30, 2010, Advantage's bank debt was $263.3 million on
a credit facility of $525 million with an unutilized capacity of
approximately $252.1 million. A total of $148.5 million of
convertible debentures remain outstanding of which $62.3 million will
mature in December 2011 and the balance of $86.2 million will mature
in January 2015.
- For the three and nine months ended September 30, 2010, our hedging
program contributed a net gain of $10.6 million and $35.3 million to
funds from operations, respectively. Advantage's hedging program has
helped to stabilize and enhance our cash flow for capital
reinvestment requirements.
- Capital expenditures during the third quarter of 2010 amounted to
$65.5 million for a total of $154.4 million for the first nine months
ended September 30, 2010. Approximately 84% of our 2010 capital
program has been invested at Glacier where we successfully completed
Phase II of our development program in the second quarter of 2010
which increased production to approximately 50 mmcf/d. Our third
quarter 2010 capital spending focused on initiation of our Phase III
development program at Glacier which is targeted to increase
production to 100 mmcf/d by the second quarter of 2011.
- Additional capital activities included 2 net (2 gross) light oil
wells at Nevis, 1.8 net (5 gross) wells in Central Alberta and 0.5
net (1 gross) well in Saskatchewan.
Glacier On Track to Double Production to 100 MMCF/D
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- Capital development activity at Glacier is progressing favorably on
all fronts in an effort to double production to our target of 100
mmcf/d by Q2 2011. In conjunction with this expansion, total
corporate production is expected to grow by approximately 25%.
- Since July 2010, 21 net (21 gross) new Montney horizontal wells have
been drilled out of our planned Phase III total program of 28 net (28
gross) wells. Improved drilling efficiencies has resulted in our
drilling program progressing ahead of schedule.
- Of the Phase III wells drilled to date, seven of the 21 new wells
have been completed and tested. Results continue to exceed
expectations with test rates ranging from 5.5 to 12.3 mmcf/d and
flowing pressures of 591 psig to 1,427 psig. Improvements in
completion techniques have resulted in increasing our average well
test rate by 259% to 9.6 mmcf/d on our Phase III wells as compared to
our initial Phase I wells drilled in 2008.
- A total of 75 mmcf/d of new behind pipe productivity is currently
available to support our 100 mmcf/d target. An additional 14 net (14
gross) wells are awaiting completion at this time.
- Production rates have been impressive with the most recent 8 wells
demonstrating an average 30 day initial production ("IP") rate of 5.3
mmcf/d with the highest well demonstrating a 30 day IP rate of 8.9
mmcf/d. The average production type curve and 30 day initial
production distribution is trending very similar to the results in
the Montney fairway between Groundbirch and Glacier. In addition,
cumulative production from several Montney wells in this fairway are
approaching 4 bcf which further substantiates the high quality
resource potential in this area.
- Fabrication of a new processing train to facilitate expansion of our
Glacier gas plant to 100 mmcf/d is nearing completion and we are
anticipating equipment delivery to our plant site by year-end with
on-site construction to begin in the first quarter of 2011. Expansion
of our Glacier plant from the current 50 mmcf/d to 100 mmcf/d is
targeted for the second quarter of 2011.
- The TCPL pipeline lateral expansion is also progressing ahead of
schedule and is expected to be completed by year end 2010.
Low Operating Costs and Royalties at Glacier Generates Impressive
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Netbacks and Economics
----------------------
- Operating costs at Glacier are forecast to decrease from the current
$3.00/boe ($0.50/mcf) to $1.75/boe ($0.29/mcf) when the property
reaches 100 mmcf/d due to efficiencies created by increasing the
production rate through Advantage's 100% owned Glacier gas plant and
the utilization of multi-well production well pads on our contiguous
land block which simplifies field operations.
- On May 27, 2010, the Alberta Government announced royalty changes
which included incentives that have a positive long-term impact on
the netbacks and drilling economics for our Montney development at
Glacier. We view the Montney as being one of North America's most
economic natural gas resource plays with very strong investment
returns at Glacier supported by low operating costs and a favorable
royalty structure.
- All Montney horizontal wells drilled at Glacier after May 1, 2010
qualify for a royalty incentive of $2.7 to $3.4 million based on a
typical Glacier Montney horizontal well (total length of 4,200 to
4,500 metres). As a result, the effective royalty rate for a new
Glacier Montney well is estimated to be less than 7% for the
producing life of the well.
- The attractive royalty rates and low operating costs significantly
enhances the netback and drilling economics of all of our Glacier
Montney drilling locations as indicated below:
$/mcf $/mcf
---------------------------------------------------------- Operating
Revenue (realized price) $4.00 $5.00 netbacks
Royalties (7% royalty rate) (0.28) (0.35) exceed 85% of
Operating costs (0.29) (0.29) revenue
Netback* $3.43 $4.36
Well Drilling
Economics pre-tax
rate of return * greater than 39% greater than 66%
* Note: assumes 4.5 mmcf/d IP, 5 Bcf reserves & $5.5 million per well
with total Glacier production of 100 mmcf/d
- Based on netbacks of $3.43/mcf and $4.36/mcf, annualized cash flows
are projected to be $125 million and $159 million respectively, which
is in excess of estimated capital requirements to maintain a 100
mmcf/d production rate at Glacier.
- In summary, Glacier is a unique asset which provides the opportunity
for Advantage to develop a large, scalable natural gas resource play
which contains decades of drilling inventory and with one of the
lowest cost structures in the Western Canadian Sedimentary Basin.
Commodity Hedging Program
-------------------------
- Advantage's hedging program includes 59% of our forecast natural gas
production for 2010 hedged at an average price of Cdn$7.46 AECO per
mcf. For 2011, Advantage has hedged approximately 28% of our forecast
production at an average price of Cdn$6.30 AECO per mcf.
- For 2010 we have hedged 34% of our forecast crude oil production at
Cdn$67.83 per bbl and for 2011 we have hedged 33% of forecast net
crude oil production at Cdn$88.90 per bbl.
- Additional details on our hedging program are available at our
website at www.advantageog.com.
H2 2010 Production Guidance Increased due to Strong Well and Plant
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Performance at Glacier
----------------------
- Our Corporate guidance for the twelve months ending June 2011 has
been increased to reflect stronger than expected well and plant
performance at Glacier as follows:
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Total
H2 2010 H1 2011 12 Months
(estimate) (estimate) (estimate)
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Production Average
(boe/d) 23,500 - 24,300 26,600 - 27,200 25,050 - 25,750
Exit Rate (boe/d) ~24,000 ~30,000
Royalty Rate (%) 13% - 15% 13% - 15% 13% - 15%
Operating Costs
($/boe) $9.75 - $10.25 $8.50 - $9.00 $9.10 - $9.65
Capital
Expenditures*
($ million) $120 - $130 $70 - $80 $190 - $210*
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* - Capital expenditures are net of total drilling credits of $19
million over the 12 month period.
- Our current corporate strategy is to focus on the development of our
Montney natural gas resource play at Glacier, maintain financial
flexibility and optimize our cost structure and operating
efficiencies to deliver economic growth, particularly during the
lower commodity price period we are currently experiencing. The
enhanced financial flexibility resulting from the previously
completed non-core asset dispositions has provided further support to
our corporate strategy.
- Advantage is well positioned to deliver growth in shareholder value.
With a current inventory in excess of 500 Montney drilling locations
at Glacier and a growing inventory of opportunities in our light oil
and other natural gas assets, Advantage is in an enviable position to
provide economic growth.
MANAGEMENT'S DISCUSSION & ANALYSIS
The following Management's Discussion and Analysis ("MD&A"), dated as of November 11, 2010, provides a detailed explanation of the financial and operating results of Advantage Oil & Gas Ltd. ("Advantage", the "Corporation", "us", "we" or "our") for the three and nine months ended September 30, 2010 and should be read in conjunction with the unaudited consolidated financial statements for the nine months ended September 30, 2010 and the audited consolidated financial statements and MD&A for the year ended December 31, 2009. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and all references are to Canadian dollars unless otherwise indicated. All per barrel of oil equivalent ("boe") amounts are stated at a conversion rate of six thousand cubic feet of natural gas being equal to one barrel of oil or liquids.
Forward-Looking Information
This MD&A contains certain forward-looking statements, which are based on our current internal expectations, estimates, projections, assumptions and beliefs. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar or related expressions. These statements are not guarantees of future performance.
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to spending and capital budgets; capital expenditure programs; the focus of capital expenditures; availability of funds for our capital program; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; the size of, and future net revenues from, reserves; our future operating and financial results; supply and demand for oil and natural gas; projections of market prices and costs; areas of operations; the performance characteristics of our properties; average production and projected exit rates; average royalty rates; and the amount of general and administrative expenses. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.
These forward-looking statements involve substantial known and unknown risks and uncertainties, many of which are beyond our control, including changes in general economic, market and business conditions; stock market volatility; changes to legislation and regulations and how they are interpreted and enforced, changes to investment eligibility or investment criteria; our ability to comply with current and future environmental or other laws; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; our success at acquisition, exploitation and development of reserves; unexpected drilling results, changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; competition from other producers; the lack of availability of qualified personnel or management; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties are described in the Corporation's Annual Information Form which is available at www.sedar.com and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.
With respect to forward-looking statements contained in this MD&A, Advantage has made assumptions regarding: conditions in general economic and financial markets; effects of regulation by governmental agencies; current commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; availability of skilled labour; availability of drilling and related equipment; timing and amount of capital expenditures; and the impact of increasing competition.
Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Non-GAAP Measures
The Corporation 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 cash netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation'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. 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 Nine months ended
September 30 September 30
($000) 2010 2009 % change 2010 2009 % change
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Cash provided by
operating
activities $ 48,536 $ 50,671 (4)% $147,226 $131,506 12%
Expenditures on
asset retirement 2,603 868 200% 4,464 4,490 (1)%
Changes in
non-cash working
capital (12,689) (9,326) 36% (17,295) 13,398 (229)%
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Funds from
operations $ 38,450 $ 42,213 (9)% $134,395 $149,394 (10)%
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Overview
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
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Cash provided by
operating
activities
($000) $ 48,536 $ 50,671 (4)% $147,226 $131,506 12%
Funds from
operations
($000) $ 38,450 $ 42,213 (9)% $134,395 $149,394 (10)%
per share(1) $ 0.23 $ 0.26 (12)% $ 0.82 $ 1.00 (18)%
per boe $ 17.19 $ 19.42 (11)% $ 20.44 $ 19.27 6%
(1) Based on basic weighted average shares outstanding.
In July 2009 we closed two major asset dispositions for net proceeds of $242.1 million representing production of approximately 8,100 boe/d. On May 31 and June 3, 2010, we closed two additional asset dispositions of non-core natural gas weighted properties for net proceeds of $66.1 million, subject to further adjustments, and representing production of approximately 1,700 boe/d. The net proceeds from the various dispositions were utilized to reduce outstanding debt. As a result of the dispositions, total funds from operations decreased for the three and nine months ended September 30, 2010 compared to the same periods of 2009 with all revenues and expenses generally impacted. As the two most recent dispositions closed near the end of the second quarter of 2010, they modestly impacted the prior quarter and are completely excluded from our financial and operating results for the third quarter of 2010.
Funds from operations per boe decreased when compared to 2009 primarily due to lower realized derivative gains as we have a lower percentage of natural gas production hedged at lower average prices for 2010. However, for the nine months ended September 30, 2010 we continued to realize significant gains on derivatives which amounted to $35.3 million that has helped to offset the continued weak natural gas prices and positively impact funds from operations. Funds from operations has also benefited during this year from higher commodity prices and continued cost reductions, such as operating costs and interest expense. Although natural gas prices have improved as compared to 2009, it is important to note that they still remain weak and pose a continuing challenge to the entire natural gas industry. In fact, when comparing the current quarter to the second quarter of 2010, our funds from operations per boe decreased 13% to $17.19/boe from $19.76/boe as commodity prices decreased. Funds from operations per share decreased from 2009 due to the decrease in total funds from operations and the increase in shares outstanding attributable to 17 million shares issued in July 2009. Cash provided by operating activities has decreased for the third quarter of 2010 as compared to the same quarter of last year corresponding to the change in funds from operations but increased for the nine months ended September 30, 2010 as compared to the same period of 2009 due to the decrease in funds from operations being more than offset by changes in working capital.
As a result of asset dispositions completed in 2009 and 2010 and changes in commodity prices, historical financial and operating performance may not be indicative of future performance.
The primary factor that causes significant variability of the Corporation'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.
Revenue
Three months ended Nine months ended
September 30 September 30
($000) 2010 2009 % change 2010 2009 % change
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Natural gas
excluding
hedging $ 33,832 $ 24,266 39% $112,491 $121,608 (7)%
Realized hedging
gains 12,388 26,935 (54)% 42,489 62,837 (32)%
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Natural gas
including
hedging $ 46,220 $ 51,201 (10)% $154,980 $184,445 (16)%
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Crude oil and NGLs
excluding
hedging $ 38,890 $ 44,204 (12)% $130,656 $138,887 (6)%
Realized hedging
gains (losses) (1,775) (2,304) (23)% (7,147) 7,378 (197)%
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Crude oil and NGLs
including
hedging $ 37,115 $ 41,900 (11)% $123,509 $146,265 (16)%
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Total revenue(1) $ 83,335 $ 93,101 (10)% $278,489 $330,710 (16)%
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(1) Total revenue excludes unrealized derivative gains and losses.
Revenue, excluding hedging, was negatively impacted for the three and nine months ended September 30, 2010, as compared to 2009 primarily due to lower production attributable to our asset dispositions that closed in the third quarter of 2009 and the second quarter of 2010. However, natural gas revenue for 2010 has benefited from significantly increased production from our Montney natural gas resource play at Glacier, Alberta and higher natural gas prices whereby natural gas revenue, excluding hedging, actually exceeded the third quarter of 2009 by 39%. Although natural gas prices have increased as compared to the prior year, they have decreased from the second quarter of 2010 and have been relatively weak during the last two years due to many factors including the recession in the North American economy that has generally reduced energy demand and higher North American natural gas production, both of which have increased natural gas inventory. Crude oil and NGL prices, excluding hedging, have been higher for 2010 as compared to 2009 which has also positively impacted revenues and partially offset reduced production from asset dispositions. Given the relatively lower natural gas price environment, our commodity price risk management program has delivered realized natural gas hedging gains of $12.4 million and $42.5 million for the three and nine months ended September 30, 2010, respectively. As crude oil prices have strengthened, we have realized crude oil hedging losses of $1.8 million and $7.1 million for the three and nine months ended September 30, 2010, respectively. The Corporation enters derivative contracts whereby realized hedging gains and losses partially offset commodity price fluctuations, which can positively or negatively impact revenue. The realized natural gas hedging gains have been significant and helped us stabilize cash flows and ensure that our capital expenditure program is substantially funded by such cash flows.
Production
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
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Natural gas
(mcf/d) 104,714 91,200 15% 100,024 111,288 (10)%
Crude oil
(bbls/d) 4,686 6,289 (25)% 5,140 7,643 (33)%
NGLs (bbls/d) 2,149 2,142 -% 2,258 2,210 2%
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Total (boe/d) 24,287 23,631 3% 24,069 28,401 (15)%
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Natural gas (%) 72% 64% 69% 65%
Crude oil (%) 19% 27% 21% 27%
NGLs (%) 9% 9% 10% 8%
Production was lower for the nine months ended September 30, 2010 as compared to the same period of 2009 primarily due to asset dispositions completed during these years. We closed property dispositions representing 8,100 boe/d in the third quarter of 2009 and 1,700 boe/d during the second quarter of 2010. As the most recent dispositions closed near the end of the second quarter of 2010, they have been completely excluded from our financial and operating results for the third quarter of 2010 resulting in the decrease from 25,365 boe/d reported in the immediately prior quarter. Corporate average daily production for the third quarter of 2010 increased 3% and natural gas production increased 15% above the same period of 2009. However, production from the third quarter of 2009 included approximately 3,850 boe/d related to assets disposed in 2009 and 2010. After adjusting for these asset dispositions, Advantage's corporate production actually increased by approximately 23% through drill bit growth as compared to the third quarter of 2009. The reduced average daily production from dispositions has been considerably offset by production increases at Glacier, where in the second quarter of 2010 our new 100% working interest gas plant ("Glacier gas plant") was brought on-stream ahead of schedule with production rates exceeding 50 mmcf/d (8,300 boe/d). This milestone represented another key step in the development of our significant Montney reserves and resource potential at Glacier by increasing production capability 100%.
Phase III of our Glacier development project is progressing on schedule and is targeted to increase production to 100 mmcf/d (16,667 boe/d) by the second quarter of 2011 with an active drilling program during the remainder of 2010 and into early 2011. New production at Glacier will be brought on-stream to replace declines during the balance of 2010 and significant increases will be realized once facilities and infrastructure expansion work is completed in the second quarter of 2011. Therefore, we expect corporate production to average approximately 23,500 to 24,300 boe/d for the second half of 2010.
Commodity Prices and Marketing
Natural Gas
Three months ended Nine months ended
September 30 September 30
($/mcf) 2010 2009 % change 2010 2009 % change
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Realized natural
gas prices
Excluding
hedging $ 3.51 $ 2.89 21% $ 4.12 $ 4.00 3%
Including
hedging $ 4.80 $ 6.10 (21)% $ 5.68 $ 6.07 (6)%
AECO monthly
index $ 3.72 $ 3.03 23% $ 4.30 $ 4.10 5%
Realized natural gas prices, excluding hedging, were 21% higher for the three months ended and 3% higher for the nine months ended September 30, 2010 as compared to the same periods of 2009. However, our realized natural gas prices, excluding hedging, for this quarter decreased 8% from the second quarter of 2010. Although natural gas prices have continued to remain weak, our commodity hedging strategy has resulted in realized natural gas prices, including hedging, that well exceed current market prices. Our realized natural gas prices, including hedging, have decreased during 2010 as compared to 2009 as we have less natural gas production hedged for this year at lower average prices. Nevertheless, our hedging program has significantly mitigated the negative impact from lower natural gas prices and has reduced the volatility of our cash flows.
During 2009 and 2010, natural gas prices have remained low from continued high US domestic natural gas production that has increased supply and the ongoing weak global economy that has negatively impacted demand. These factors have resulted in higher inventory placing considerable downward pressure on natural gas prices. Heading into the 2009/2010 winter season, we saw strong inventory withdraws which helped to modestly strengthen prices relative to the prior lows experienced during the majority of 2009. However, as we exited the winter, natural gas prices significantly decreased and have remained weak with AECO gas presently trading at approximately $3.65/mcf. Although we continue to believe in the longer-term pricing fundamentals for natural gas, we are concerned about the strength and timing of the North American economic recovery which is linked to industrial demand for natural gas. We continue to monitor these market developments closely and will be proactive in implementing an appropriate hedging strategy to mitigate the volatility in our cash flow as a result of fluctuations in natural gas prices.
Crude Oil and NGL
Three months ended Nine months ended
September 30 September 30
($/bbl) 2010 2009 % change 2010 2009 % change
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Realized crude
oil prices
Excluding
hedging $ 70.75 $ 65.34 8% $ 72.17 $ 56.24 28%
Including
hedging $ 66.63 $ 61.36 9% $ 67.07 $ 59.77 12%
Realized NGLs
prices
Excluding
hedging $ 42.41 $ 32.46 31% $ 47.68 $ 35.72 33%
Realized crude oil
and NGL prices
Excluding
hedging $ 61.84 $ 56.99 9% $ 64.69 $ 51.64 25%
Including
hedging $ 59.01 $ 54.02 9% $ 61.15 $ 54.38 12%
WTI ($US/bbl) $ 76.21 $ 68.29 12% $ 77.65 $ 57.13 36%
$US/$Canadian
exchange rate $ 0.96 $ 0.91 5% $ 0.97 $ 0.86 13%
Realized crude oil and NGL prices, excluding hedging, increased 9% and 25% for the three and nine months ended September 30, 2010, as compared to the same periods of 2009. As compared to the second quarter of 2010, realized crude oil and NGL prices, excluding hedging, have decreased 4% for the third quarter of 2010. Advantage's realized crude oil price may not change to the same extent as West Texas Intermediate ("WTI"), due to changes in the $US/$Canadian exchange rate and changes in Canadian crude oil differentials relative to WTI.
The price of WTI fluctuates based on worldwide supply and demand fundamentals. There has been significant price volatility experienced over the last several years whereby WTI reached historic high levels in the first half of 2008, followed by a record decline in the latter half of the year and into early 2009, the result of demand destruction brought on by the global recession. There was improvement during the last half of 2009 which has continued into 2010, and WTI is currently trading at approximately US$87/bbl. However, we have also seen a constant strengthening of the $US/$Canadian exchange rate during 2009 and 2010 such that our increase in realized price has been less than the improvement in WTI. We continue to believe that the long-term pricing fundamentals for crude oil will remain strong with supply management by the OPEC cartel and strong relative demand from many developing countries, such as China and India.
Commodity Price Risk
The Corporation's financial results and condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely and are determined by economic and 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 Corporation's financial condition and performance. Advantage has an established financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivative contracts. Although these commodity price risk management activities could expose Advantage to losses or gains, entering derivative contracts helps us to stabilize cash flows and ensures that our capital expenditure program is substantially funded by such cash flows. To the extent that Advantage engages in risk management activities related to commodity prices, it will be subject to credit risk associated with counterparties with which it contracts. Credit risk is mitigated by entering into contracts with only stable, creditworthy parties and through frequent reviews of exposures to individual entities. In addition, the Corporation only enters into derivative contracts with major banks that are members of our credit facility syndicate and international energy firms to further mitigate associated credit risk. Our credit facilities also prohibit the Corporation from entering into any derivative contract where the term of such contract exceeds three years. Further, the aggregate of such contracts cannot hedge greater than 60% of total estimated petroleum and natural gas production over two years and 50% over the third year.
We have been active in entering financial contracts to protect future cash flows and currently the Corporation has the following derivatives in place:
Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas -
AECO
Fixed price January 2010 to December 2010 18,956 mcf/d Cdn$7.29/mcf
Fixed price April 2010 to January 2011 18,956 mcf/d Cdn$7.25/mcf
Fixed price January 2011 to December 2011 9,478 mcf/d Cdn$6.24/mcf
Fixed price January 2011 to December 2011 9,478 mcf/d Cdn$6.24/mcf
Fixed price January 2011 to December 2011 9,478 mcf/d Cdn$6.26/mcf
Crude oil -
WTI
Fixed price April 2010 to January 2011 2,000 bbls/d Cdn$69.50/bbl
Fixed price January 2011 to December 2011 1,500 bbls/d Cdn$91.05/bbl
The derivative contracts have allowed us to fix the commodity price on anticipated production, net of royalties, as follows:
Approximate Production Average
Commodity Hedged, Net of Royalties(1) Price
-------------------------------------------------------------------------
Natural gas - AECO
October to December 2010 48% Cdn$7.27/mcf
-----------------------------------------------------------------------
Total 2010 59% Cdn$7.46/mcf
-----------------------------------------------------------------------
January to March 2011 40% Cdn$6.43/mcf
April to June 2011 25% Cdn$6.24/mcf
July to September 2011 24% Cdn$6.24/mcf
October to December 2011 24% Cdn$6.24/mcf
-----------------------------------------------------------------------
Total 2011 28% Cdn$6.30/mcf
-----------------------------------------------------------------------
Crude Oil - WTI
October to December 2010 37% Cdn$69.50/bbl
-----------------------------------------------------------------------
Total 2010 34% Cdn$67.83/bbl
-----------------------------------------------------------------------
January to March 2011 41% Cdn$84.42/bbl
April to June 2011 30% Cdn$91.05/bbl
July to September 2011 31% Cdn$91.05/bbl
October to December 2011 31% Cdn$91.05/bbl
-----------------------------------------------------------------------
Total 2011 33% Cdn$88.90/bbl
-----------------------------------------------------------------------
(1) Approximate production hedged is based on our estimated average
production by quarter, net of estimated royalty payments.
For the nine months ended September 30, 2010, we recognized in income a net realized derivative gain of $35.3 million (September 30, 2009 - $70.2 million net realized derivative gain) on settled derivative contracts as a result of average market prices decreasing below our established average hedge prices. Our realized derivative gain has decreased during 2010 as compared to 2009 as we have less natural gas production hedged for this year at lower average prices. However, our successful commodity price risk management program has still enabled us to realize significant gains on derivatives for the nine months ended September 30, 2010 that has helped to offset the continued weak natural gas prices and positively impact funds from operations. As at September 30, 2010, the fair value of the derivative contracts outstanding and to be settled was a net asset of approximately $36.7 million, an increase of $19.5 million from the $17.2 million net asset recognized as at December 31, 2009. For the nine months ended September 30, 2010, this $19.5 million increase was recognized in income as an unrealized derivative gain (September 30, 2009 - $9.3 million unrealized derivative loss). The valuation of the derivatives is the estimated fair value to settle the contracts as at September 30, 2010 and is based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are not cash and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices and foreign exchange rates as compared to the valuation assumptions. The Corporation does not apply hedge accounting and current accounting standards require changes in the fair value to be included in the consolidated statements of income and comprehensive income as an unrealized derivative gain or loss with a corresponding derivative asset and liability recorded on the balance sheet. These derivative contracts will settle in 2010 and 2011 corresponding to when the Corporation will receive revenues from production.
Royalties
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Royalties ($000) $ 10,272 $ 8,749 17% $ 35,327 $ 37,620 (6)%
per boe $ 4.60 $ 4.02 14% $ 5.38 $ 4.85 11%
As a percentage
of revenue, 14.1% 12.8% 1.3% 14.5% 14.4% 0.1%
excluding hedging
Advantage pays royalties to the owners of mineral rights from which we have leases. The Corporation currently has mineral leases with provincial governments, individuals and other companies. Royalty expense includes the impact of gas cost allowance ("GCA"), which is a reduction of royalties payable to the Alberta Provincial Government to recognize capital and operating expenditures incurred in the gathering and processing of their share of natural gas production and does not generally fluctuate with natural gas prices. Total royalties paid and royalties as a percentage of revenue increased for the three months ended September 30, 2010 compared to the same period of 2009 due to higher commodity prices. For the nine months ended September 30, 2010, total royalties paid decreased due to lower revenue from reduced production attributable to our asset dispositions while royalties as a percentage of revenue was comparable.
Our average corporate royalty rates are significantly impacted by the Alberta Provincial Government's royalty framework that was revised effective January 1, 2009 for conventional oil, natural gas and oil sands whereby Alberta royalties are affected by depths, productivity of wells, and commodity prices. Additionally, the Alberta Provincial Government implemented a number of drilling incentive programs with reduced royalty rates over a period of time for qualifying wells. The majority of our wells brought on production since April 1, 2009 qualify under these incentive programs and benefit from a reduced 5% royalty rate on the first 500 mmcf produced or one-year, whichever comes first, and a drilling credit of $200 per metre drilled that reduces capital spending and is limited to 40% of corporate crown royalties paid during the program term. The drilling credit incentives are effective for qualifying wells drilled and brought on production from April 1, 2009 to March 31, 2011 while the reduced 5% royalty rate program is a permanent incentive. The Alberta Provincial Government also made changes in the Natural Gas Deep Drilling Program ("NGDDP") which reduces the vertical depth requirement to 2,000 metres (from 2,500 metres) and makes the program permanent. As a result, all of our Montney horizontal wells at Glacier drilled after May 1, 2010 will qualify for the NGDDP which is estimated to provide an additional royalty incentive of $2.7 to $3.4 million for a typical horizontal well (a typical Advantage horizontal well at Glacier is 4,200 to 4,500 metres in total length). This royalty incentive is recognized through a reduced 5% royalty rate until the total incentive is realized. This significantly lowers the natural gas price threshold required to drill economic wells and substantially improves the value of future reserves and upside potential at Glacier.
As a result of the changes in the royalty incentives and royalty curves, we estimate an effective royalty rate of less than 7% for the life of our new Glacier wells. We expect our corporate royalty rate to be in the range of 13% to 15% for the second half of 2010. Alberta royalty rates will continue to fluctuate based on commodity prices, individual well productivity, and our ongoing capital development plans.
Operating Costs
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Operating costs
($000) $ 22,812 $ 25,114 (9)% $ 70,088 $ 96,175 (27)%
per boe $ 10.21 $ 11.55 (12)% $ 10.67 $ 12.40 (14)%
Total operating costs and operating costs per boe decreased for the three and nine months ended September 30, 2010 as compared to the same periods of 2009. The lower overall total operating costs has been primarily due to reduced production from our asset dispositions completed in the third quarter of 2009 and the second quarter of 2010. Additional benefits are being realized from increased lower operating cost production at Glacier since the second quarter of 2010. We anticipate that corporate operating costs will further decrease as a result of lower cost production resulting from our Glacier gas plant (100% Advantage working interest) that was completed in the second quarter of 2010. Operating costs at Glacier during the second quarter of 2010 decreased to approximately $3.00/boe which has significantly improved the netbacks realized from our Montney gas production. We estimate that operating costs at Glacier will be further reduced to a target of approximately $1.75/boe when production reaches 100 mmcf/d. We will seek further opportunities to improve our operating cost structure and expect corporate operating costs for the second half of 2010 to be between $9.75 and $10.25/boe.
General and Administrative
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
General and
administrative
Cash expense
($000) $ 5,869 $ 7,010 (16)% $ 18,560 $ 20,549 (10)%
per boe $ 2.63 $ 3.22 (18)% $ 2.82 $ 2.66 6%
Non-cash expense
($000) $ 3,707 $ 6,214 (40)% $ 10,838 $ 7,903 37%
per boe $ 1.66 $ 2.86 (42)% $ 1.65 $ 1.02 62%
Employees at
September 30 127 133 (5)%
Cash general and administrative ("G&A") expense for the three and nine months ended September 30, 2010 has decreased as compared to the same periods of 2009 due to cost savings and reduced staff levels attributable to the asset dispositions and incremental costs incurred in 2009 associated with our corporate conversion and reorganization.
Non-cash G&A expense for the three months ended September 30, 2010 decreased significantly due to an expense recorded in 2009 related to vacated office space. During the third quarter of 2009 we were able to consolidate office space as a result of reducing staff levels and certain office space was completely vacated. Therefore, we were required to recognize $3.8 million as non-cash G&A expense with a corresponding liability representing the full amount of all future related lease payments for such vacated office space. For the nine months ended September 30, 2010, non-cash G&A was 37% higher than the same period of the prior year due to our equity-based compensation plan. Advantage's compensation plan includes a Restricted Share Performance Incentive Plan ("RSPIP" or the "Plan") as approved by the shareholders with the purpose to retain and attract employees, to reward and encourage performance, and to focus employees on operating and financial performance that results in lasting shareholder return. The Plan authorizes the Board of Directors to grant restricted shares to service providers of the Corporation, including directors, officers, employees and consultants. The number of restricted shares granted is based on the Corporation's share price return for a twelve-month period and compared to the performance of a peer group approved by the Board of Directors. The share price return is calculated at the end of each and every quarter and is primarily based on the twelve-month change in the share price. If the share price return for a twelve-month period is positive, a restricted share grant will be calculated based on the return. If the share price return for a twelve-month period is negative, but the return is still within the top two-thirds of the approved peer group performance, the Board of Directors may grant a discretionary restricted share award. Compensation cost related to the Plan is recognized as equity-based compensation expense within G&A expense over the service period and incorporates the share grant price, the estimated number of restricted shares to vest, and certain management estimates. For the nine months ended September 30, 2010, we granted 2,547,020 restricted shares at an average grant price of $6.93 per restricted share and recognized $13.5 million of equity-based compensation expense, including a non-cash amount of $10.8 million, related to restricted shares granted to service providers. During the nine months ended September 30, 2010 we issued 974,365 shares to service providers in accordance with the vesting provisions of the Plan. As at September 30, 2010, 3,302,187 restricted shares remain unvested and will vest to service providers over the next two years with a total of $11.2 million in compensation cost to be recognized over the future service periods.
Management Internalization
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Management
internalization
($000) $ - $ - -% $ - $ 1,724 (100)%
per boe $ - $ - -% $ - $ 0.22 (100)%
In 2006, Advantage Energy Income Fund (the "Fund") and Advantage Investment Management Ltd. (the "Manager") reached an agreement to internalize a pre-existing management contract arrangement. As part of the agreement, the Fund agreed to purchase all of the outstanding shares of the Manager pursuant to the terms of the arrangement, thereby eliminating the management fee and performance incentive effective April 1, 2006. The Trust Unit consideration issued in exchange for the outstanding shares of the Manager was placed in escrow for a three-year period and was deferred and amortized into income as management internalization expense over the specific vesting periods. As of June 23, 2009, the final Trust Units held in escrow vested and there is no subsequent management internalization expense recognized.
Interest on Bank Indebtedness
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Interest
expense ($000) $ 3,326 $ 6,331 (47)% $ 10,131 $ 14,686 (31)%
per boe $ 1.49 $ 2.91 (49)% $ 1.54 $ 1.89 (18)%
Average effective
interest rate 4.9% 5.6% (0.7)% 5.1% 4.4% 0.7%
Bank indebtedness
at September 30
($000) $263,306 $330,800 (20)%
Total interest expense has decreased for both the three and nine months ended September 30, 2010 as compared to 2009. During the first half of 2009, Advantage experienced significantly lower average interest rates as bank lending rates declined in response to rate reductions enacted by central banks to stimulate the economy. This reduced interest expense was partially offset by additional interest expense on a higher average debt balance during that period. In June 2009 our credit facility was renewed and was subject to generally higher basis point and stamping fee adjustments as was typically applied by financial institutions at that time. Therefore, our average effective interest rate for the nine months ended September 30, 2010 is higher than the same period of 2009; however, this has been significantly offset by lower interest expense on the reduced bank indebtedness that resulted from the various asset dispositions and both the equity financing and convertible debenture issuance during the period. Our revolving credit facility was renewed in June 2010 and is now subject to basis point and stamping fee adjustments ranging from 1.25% to 3.75% depending on the Corporation's debt to cash flow ratio. The Corporation's interest rates are primarily based on short term bankers acceptance rates plus a stamping fee. We monitor the debt level to ensure an optimal mix of financing and cost of capital that will provide a maximum return to our shareholders. Our current credit facilities have been a favorable financing alternative with an effective interest rate of 5.1% for the nine months ended September 30, 2010.
Interest and Accretion on Convertible Debentures
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Interest on
convertible
debentures
($000) $ 2,348 $ 3,354 (30)% $ 9,183 $ 11,332 (19)%
per boe $ 1.05 $ 1.54 (32)% $ 1.40 $ 1.46 (4)%
Accretion on
convertible
debentures
($000) $ 938 $ 612 53% $ 3,158 $ 1,975 60%
per boe $ 0.42 $ 0.28 50% $ 0.48 $ 0.25 92%
Convertible
debentures
maturity value
at September 30
($000) $148,544 $132,221 12%
Interest on convertible debentures for the three and nine months ended September 30, 2010 has decreased compared to 2009 due to the maturity of the 8.25% debentures on February 1, 2009, the 8.75% debentures on June 30, 2009, the 7.50% debentures on October 1, 2009, and the 6.50% debentures on June 30, 2010. The reduced interest has been partially offset by additional interest on our new 5.00% convertible debentures that were issued on December 31, 2009. Accretion on convertible debentures has increased for the three and nine months ended September 30, 2010 as compared to the same periods of 2009 due to the higher accretion expense on the new 5.00% convertible debentures as a result of the greater value assigned to the equity component of the debenture representing the conversion option available to debentureholders. Both interest and accretion expense decreased from the second quarter of 2010 as the 6.50% debentures matured.
Depletion, Depreciation and Accretion
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Depletion,
depreciation
and accretion
($000) $ 58,122 $ 62,499 (7)% $169,018 $204,598 (17)%
per boe $ 26.01 $ 28.75 (10)% $ 25.72 $ 26.39 (3)%
Depletion and depreciation of petroleum and natural gas properties is provided on the "unit-of-production" method based on total proved reserves. Accretion represents the increase in the asset retirement obligation liability each reporting period due to the passage of time. The depletion, depreciation and accretion ("DD&A") provision has decreased for the three and nine months ended September 30, 2010 compared to 2009 due to lower production resulting from the asset dispositions that closed during the periods and a lower average rate of D&D per boe. Our DD&A per boe has decreased during 2010 as compared to 2009 due to a higher proportion of proved reserves as compared to capital expenditures and future development capital.
Taxes
Current taxes paid or payable for the nine months ended September 30, 2010 amounted to $1.0 million, comparable to the expense for the same period of 2009. Current taxes primarily represent Saskatchewan resource surcharge, which is based on the petroleum and natural gas revenues earned within the province of Saskatchewan.
Future income taxes arise from differences between the accounting and tax bases of our assets and liabilities. For the nine months ended September 30, 2010, the Corporation recognized a total future income tax reduction of $3.2 million compared to a future income tax reduction of $3.9 million for the same period of 2009. The future income tax reduction for 2010 is comparable to 2009, although the loss before taxes for the prior year was significantly higher, due to a $23.0 million future income tax expense impact recognized in the third quarter of 2009 related to the corporate conversion that was completed during that period. As at September 30, 2010, the Corporation had a total future income tax liability balance of $40.3 million, compared to $43.5 million at December 31, 2009. 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.
Net Loss
Three months ended Nine months ended
September 30 September 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Net loss ($000) $(16,915) $(53,293) (68)% $(26,039) $(72,213) (64)%
per share -
basic and
diluted $ (0.10) $ (0.33) (70)% $ (0.16) $ (0.48) (67)%
Net loss and net loss per share for the three and nine months ended September 30, 2010 have decreased as compared to the same periods of 2009. During the third quarter of 2009 and the second quarter of 2010 we completed several asset dispositions that have generally reduced all revenues and expenses as compared to the prior year. However, with our new 100% working interest Glacier gas plant that came on-stream during the second quarter of 2010, our corporate natural gas production has increased 15% as compared to the third quarter of 2009 thereby exceeding disposed production. Revenue for 2010 has also been positively impacted by higher commodity prices as compared to 2009. However, our major challenge continues to be the natural gas price environment that has remained weak and adversely impacts revenue which generally results in our recognized net loss. Low revenues were partially mitigated by our commodity hedging program that resulted in a net realized derivative gain of $35.3 million for the nine months ended September 30, 2010 and a non-cash unrealized derivative gain of $19.5 million relating to the valuation of commodity hedging contracts outstanding as at September 30, 2010 that will not settle until the remainder of 2010 and 2011. Our realized derivative gain has decreased during 2010 as compared to 2009 as we have less natural gas production hedged for this year at lower average prices. We continue to experience low royalty rates due to weak natural gas prices and Alberta Provincial royalty reduction incentive plans relative to our capital development program. Operating costs have continued to improve through increased production volumes at Glacier, divestment of higher cost non-core assets and an aggressive optimization program that continues to demonstrate positive benefits. We anticipate that corporate operating costs will further improve as a result of lower cost production from our Glacier property as we reach a targeted production rate of 100 mmcf/d by the second quarter of 2011. Our net loss for 2010 is also reduced as compared to the 2009 periods due to significant costs incurred during the third quarter of 2009 attributed to the corporate conversion, including the recognition of several one-time costs in G&A expense and a future income tax expense of $23.0 million.
Cash Netbacks
Three months ended
September 30
2010 2009
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 72,722 $ 32.54 $ 68,470 $ 31.49
Realized gain on derivatives 10,613 4.75 24,631 11.33
Royalties (10,272) (4.60) (8,749) (4.02)
Operating costs (22,812) (10.21) (25,114) (11.55)
-------------------------------------------------------------------------
Operating $ 50,251 $ 22.48 $ 59,238 $ 27.25
General and administrative(1) (5,869) (2.63) (7,010) (3.22)
Interest(2) (3,277) (1.47) (6,309) (2.91)
Interest on convertible
debentures(2) (2,348) (1.05) (3,354) (1.54)
Income and capital taxes (307) (0.14) (352) (0.16)
-------------------------------------------------------------------------
Funds from operations and
cash netbacks $ 38,450 $ 17.19 $ 42,213 $ 19.42
-------------------------------------------------------------------------
Nine months ended
September 30
2010 2009
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $243,147 $ 37.00 $260,495 $ 33.60
Realized gain on derivatives 35,342 5.38 70,215 9.06
Royalties (35,327) (5.38) (37,620) (4.85)
Operating costs (70,088) (10.67) (96,175) (12.40)
-------------------------------------------------------------------------
Operating $173,074 $ 26.33 $196,915 $25.41
General and administrative(1) (18,560) (2.82) (20,549) (2.66)
Interest(2) (9,970) (1.52) (14,664) (1.89)
Interest on convertible
debentures(2) (9,183) (1.40) (11,332) (1.46)
Income and capital taxes (966) (0.15) (976) (0.13)
-------------------------------------------------------------------------
Funds from operations and
cash netbacks $134,395 $ 20.44 $149,394 $19.27
-------------------------------------------------------------------------
(1) General and administrative expense excludes non-cash G&A and non-cash
equity-based compensation expense.
(2) Interest excludes non-cash accretion expense.
Funds from operations decreased in total for the three and nine months ended September 30, 2010 compared to the same periods of 2009 primarily due to our asset dispositions completed in the third quarter of 2009 and the second quarter of 2010 that generally impacted all revenues and expenses. However, revenue for the third quarter of 2010 actually increased when compared to the same period of the prior year primarily due to slightly stronger commodity prices and completion of the Glacier gas plant whereby we have realized production rates exceeding 50 mmcf/d (8,300 boe/d). Funds from operations per boe or cash netbacks decreased when compared to 2009 primarily due to lower realized derivative gains as we have less natural gas production hedged for 2010 at lower average prices. However, our successful commodity price risk management program has still enabled us to realize significant gains on derivatives of $35.3 million for the nine months ended September 30, 2010 that has helped to offset the continued weak natural gas prices and positively impact funds from operations. Funds from operations has also benefited during this year from higher commodity prices and continued cost reductions. Although natural gas prices have improved as compared to 2009, it is important to note that they still remain weak and pose a continuing challenge to the entire natural gas industry. In fact, when comparing the current quarter to the second quarter of 2010, our funds from operations per boe decreased 13% to $17.19/boe from $19.76/boe as commodity prices decreased. Royalties per boe increased slightly from 2009 due to the higher commodity prices while operating costs per boe decreased as we continue to realize benefits from our divestment of higher cost assets and the addition of lower cost production due to the completion of our Glacier gas plant. Interest expense has also continued to decrease as we utilized proceeds from the various asset dispositions and both the equity financing and convertible debenture issuance during the periods to repay bank indebtedness and maturing convertible debentures.
Contractual Obligations and Commitments
The Corporation has contractual obligations in the normal course of operations including purchases of assets and services, operating agreements, transportation commitments, sales contracts, bank indebtedness and convertible debentures. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. The following table is a summary of the Corporation's remaining contractual obligations and commitments. Advantage has no guarantees or off-balance sheet arrangements other than as disclosed.
Payments due by period
($ millions) Total 2010 2011 2012 2013 2014 2015
-------------------------------------------------------------------------
Building leases $ 3.5 $ 0.9 $ 1.5 $ 1.1 $ - $ - $ -
Pipeline/
transportation 28.4 1.1 6.6 6.5 6.2 6.2 1.8
Capital lease
obligations 0.9 0.1 0.8 - - - -
Bank
indebtedness(1) 263.3 - - 263.3 - - -
Convertible
debentures(2) 148.5 - 62.3 - - - 86.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total
contractual
obligations $444.6 $ 2.1 $ 71.2 $270.9 $ 6.2 $ 6.2 $ 88.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The Corporation's bank indebtedness does not have specific maturity
dates. It is governed by a credit facility agreement with a syndicate
of financial institutions. Under the terms of the agreement, the
facility is reviewed annually, with the next review scheduled in June
2011. The facility is revolving, and is extendible at each annual
review for a further 364 day period at the option of the syndicate.
If not extended, the credit facility is converted at that time into a
one-year term facility, with the principal payable at the end of such
one-year term. Management fully expects that the facility will be
extended at each annual review.
(2) As at September 30, 2010, Advantage had $148.5 million convertible
debentures outstanding (excluding interest payable during the various
debenture terms). Each series of convertible debentures are
convertible to shares based on an established conversion price. All
remaining obligations related to convertible debentures can be
settled through the payment of cash or issuance of shares at
Advantage's option.
Liquidity and Capital Resources
The following table is a summary of the Corporation's capitalization structure.
($000, except as otherwise indicated) September 30, 2010
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 263,306
Working capital deficit(1) 62,011
-------------------------------------------------------------------------
Net debt $ 325,317
-------------------------------------------------------------------------
Shares outstanding 163,719,893
Shares closing market price ($/share) $ 6.50
-------------------------------------------------------------------------
Shares outstanding market value $ 1,064,179
-------------------------------------------------------------------------
Convertible debentures maturity value (long-term) $ 148,544
-------------------------------------------------------------------------
Total capitalization $ 1,538,040
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Working capital deficit includes accounts receivable, prepaid
expenses and deposits, accounts payable and accrued liabilities, and
the current portion of capital lease obligations.
Advantage monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the business and industry in general. The capital structure of the Corporation is composed of working capital, bank indebtedness, convertible debentures, capital lease obligations and shareholders' equity. Advantage may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing either through bank indebtedness or convertible debenture issuances, refinancing current debt, issuing other financial or equity-based instruments, declaring a dividend, implementing a dividend reinvestment plan, adjusting capital spending, or disposing of assets. The capital structure is reviewed by Management and the Board of Directors on an ongoing basis.
Management of the Corporation's capital structure is facilitated through its financial and operational forecasting processes. The forecast of the Corporation's future cash flows is based on estimates of production, commodity prices, forecast capital and operating expenditures, and other investing and financing activities. The forecast is regularly updated based on new commodity prices and other changes, which the Corporation views as critical in the current environment. Selected forecast information is frequently provided to the Board of Directors. This continual financial assessment process further enables the Corporation to mitigate risks. The Corporation continues to satisfy all liabilities and commitments as they come due. We have an established $525 million credit facility agreement with a syndicate of financial institutions; the balance of which at September 30, 2010 was $263.3 million. This facility is comprised of a $20 million revolving operating loan facility and a $505 million extendible revolving credit facility which is due for its next renewal in June 2011. The Corporation additionally has convertible debentures that will mature in 2011 and 2015, whereby we have the option to settle such obligations by cash or through the issuance of shares. The current economic situation has placed considerable pressure on commodity prices. Natural gas prices have remained weak throughout 2009 and 2010 due to the ailing economy as well as high inventory levels with AECO gas presently trading at approximately $3.65/mcf. Crude oil has improved since early 2009 and is relatively more stable with WTI at approximately US$87/bbl. The outlook for the Corporation from prolonged weak natural gas prices would be reductions in operating netbacks and funds from operations. Management has partially mitigated this risk through our commodity hedging program but the lower natural gas price environment has still had a significant negative impact. In order to strengthen our financial position and balance our cash flows, in 2009 we completed an equity financing, two asset dispositions, and issued 5.00% convertible debentures and in 2010 we completed two additional asset dispositions. These steps have allowed us to repay significant bank indebtedness and maturing convertible debentures and also enabled us to focus capital spending on our Glacier Montney natural gas resource play.
We believe that Advantage has implemented strategies to protect our business as much as possible in the current industry and economic environment. We have implemented a strategy to balance funds from operations and our capital program expenditure requirements. A successful hedging program was also executed to help reduce the volatility of funds from operations. However, we are still exposed to risks as a result of the current economic situation. We continue to closely monitor the possible impact on our business and strategy, and will make adjustments as necessary with prudent management.
Shareholders' Equity and Convertible Debentures
Advantage has utilized a combination of equity, convertible debentures and bank debt to finance acquisitions and development activities.
As at September 30, 2010, the Corporation had 163.7 million shares outstanding. During 2010 we have issued 974,365 shares to employees in accordance with the vesting provisions of the RSPIP. As at November 11, 2010, shares outstanding have increased to 164.1 million.
The Corporation had $148.5 million convertible debentures outstanding at September 30, 2010 that were immediately convertible to 13.0 million shares based on the applicable conversion prices (December 31, 2009 - $218.5 million outstanding and convertible to 15.8 million shares). During the nine months ended September 30, 2010, there were no conversions of debentures. The principal amount of 6.50% convertible debentures matured on June 30, 2010 and was settled with $69.9 million in cash. As at November 11, 2010, the convertible debentures outstanding have not changed from September 30, 2010. We have $62.3 million of 7.75% and 8.00% debentures that mature in December 2011 and $86.2 million of 5.00% debentures that mature in January 2015. These obligations can be settled through the payment of cash or issuance of shares at Advantage's option.
Bank Indebtedness, Credit Facility and Other Obligations
At September 30, 2010, Advantage had bank indebtedness outstanding of $263.3 million. Bank indebtedness has increased $13.0 million since December 31, 2009, primarily the result of our significant capital expenditure program during this year. However, we have successfully reduced our bank indebtedness by $67.5 million or 20% since September 30, 2009. The Corporation's credit facility is $525 million, comprised of a $20 million extendible revolving operating loan facility and a $505 million extendible revolving loan facility (the "Credit Facilities"). The Credit Facilities are collateralized by a $1 billion floating charge demand debenture covering all assets of the Corporation. As well, the borrowing base for the Corporation's credit facilities is determined through utilizing our regular reserve estimates. The banking syndicate thoroughly evaluates the reserve estimates based upon their own commodity price expectations to determine the amount of the borrowing base. Revisions or changes in the reserve estimates and commodity prices can have either a positive or a negative impact on the borrowing base of the Corporation. The next annual review is scheduled to occur in June 2011. There can be no assurance that the $525 million credit facility will be renewed at the current borrowing base level at that time.
Advantage had a working capital deficiency of $62.0 million as at September 30, 2010. Our working capital includes items expected for normal operations such as trade receivables, prepaids, deposits, trade payables and accruals as well as the current portion of capital lease obligations. Our working capital deficiency increased significantly during the third quarter of 2010 due to accounts payable and accrued liabilities associated with our capital expenditure program. Working capital varies primarily due to the timing of such items, the current level of business activity including our capital expenditure program, commodity price volatility, and seasonal fluctuations. We do not anticipate any problems in meeting future obligations as they become due given the level 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 has a capital lease obligation on various equipment used in its operations. The total amount of principal obligation outstanding at September 30, 2010 is $0.9 million, bearing interest at an effective rate of 5.8%, and is collateralized by the related equipment. The lease expires in 2011.
Capital Expenditures
Three months ended Nine months ended
September 30 September 30
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Land and seismic $ 1,121 $ 559 $ 3,286 $ 2,266
Drilling, completions
and workovers 50,910 29,914 113,912 72,052
Well equipping and
facilities 13,438 12,161 36,886 36,540
Other 22 24 306 162
-------------------------------------------------------------------------
$ 65,491 $ 42,658 $ 154,390 $ 111,020
Property dispositions 1,032 (243,565) (69,450) (245,184)
-------------------------------------------------------------------------
Net capital expenditures $ 66,523 $ (200,907) $ 84,940 $ (134,164)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Advantage's exploitation and development program is focused primarily at Glacier, Alberta where we are developing a significant natural gas resource play. Our preference is to operate a high percentage of our properties such that we can maintain control of capital expenditures, operations and cash flows. Advantage's acquisition strategy has been to acquire long-life properties with strong drilling opportunities while retaining a balance of year round access and risk.
For the nine months ended September 30, 2010, the Corporation spent a net $154.4 million and drilled a total of 40.5 net (50.0 gross) wells at a 97.5% success rate. Total capital spending included $129.9 million at Glacier, $5.1 million at Sunset, $3.6 million at Nevis, $3.2 million in Saskatchewan, and the remaining balance at other areas. However, we continue to focus on development of our Montney natural gas resource play at Glacier where Advantage will continue to employ a phased development approach. Phase II was completed during the second quarter of 2010 and costs incurred were lower than anticipated due to our successful drilling program which demonstrated well productivities that exceeded internal expectations and reduced drilling and completion costs. Construction of our facilities and gas gathering system expansions were completed ahead of schedule and on-budget leading to an earlier than anticipated commissioning of Advantage's 100% working interest gas plant in March 2010. The Glacier gas plant has been operating at its design capacity with throughput rates between 50 and 55 mmcf/d. Our Phase III expansion began at the end of the second quarter of 2010 and is expected to be completed in the second quarter of 2011. Phase III includes the drilling of 28 net (28 gross) horizontal wells and the fabrication of a new processing train to facilitate expansion of our Glacier gas plant to a targeted production capacity of 100 mmcf/d. We have now drilled 21 horizontal wells of our Phase III program with 3 more wells currently drilling and 4 wells remaining to drill. The first 7 wells drilled have now been completed and tested with 14 wells waiting on completions. We currently have production of approximately 75 mmcf/d tested and behind pipe. Additional wells will be brought on-production in the future to maintain our facilities at capacity prior to completing the Phase III expansion. The amount of excess field production capability above our current plant capacity is a result of our successful drilling program which demonstrated well test rates that exceeded expectations and proved up a large portion of our undrilled acreage at Glacier. Fabrication of the new processing train components is nearing completion and we expect equipment to be delivered to the plant site in December for final installation and construction to begin. The sales lateral looping expansion to 100 mmcf/d is now completed with the meter station upgrade underway.
On May 31 and June 3, 2010, we closed two additional asset dispositions of non-core natural gas weighted properties for net proceeds of $66.1 million, subject to further adjustments, and representing production of approximately 1,700 boe/d. The net proceeds from the dispositions were utilized to reduce outstanding debt. During the third quarter of 2010 we had a $1.0 million adjustment related to finalizing prior completed asset dispositions.
Sources and Uses of Funds
The following table summarizes the various funding requirements during the nine months ended September 30, 2010 and 2009 and the sources of funding to meet those requirements:
Nine months ended
September 30
($000) 2010 2009
-------------------------------------------------------------------------
Sources of funds
Funds from operations $ 134,395 $ 149,394
Property dispositions 69,450 245,184
Increase in bank indebtedness 13,470 -
Decrease in working capital 12,774 -
Units issued, net of costs - 96,779
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 230,089 $ 491,357
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Uses of funds
Expenditures on fixed assets $ 154,390 $ 111,020
Convertible debenture maturities 69,927 82,107
Expenditures on asset retirement 4,464 4,490
Reduction of capital lease obligations 1,308 974
Decrease in bank indebtedness - 256,968
Distributions to Unitholders - 23,481
Increase in working capital - 12,317
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 230,089 $ 491,357
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Funds from operations decreased during the nine months ended September 30, 2010 compared to 2009, due to reduced production attributed to asset dispositions and lower realized derivative gains from less natural gas production hedged for this year at lower average prices. However, funds from operations were positively impacted during 2010 from an improvement in both crude oil and natural gas prices and continued cost reduction efforts. Significant asset dispositions were completed in both 2010 and 2009 with proceeds utilized to generally repay bank indebtedness and convertible debenture maturities. Bank indebtedness increased modestly in 2010 as would be expected due to our very active capital expenditure program that included finalizing our Glacier Phase II program and beginning Phase III that comprises expanding the Glacier gas plant targeting 100 mmcf/d and drilling 28 wells. During the second quarter of 2010 our 6.50% convertible debentures matured and were settled with $69.9 million in cash. We have focused on balancing our funds from operations and expenditures on fixed assets to maintain a strong balance sheet and preserve financial flexibility.
Quarterly Performance
($000, except
as otherwise 2010 2009
indicated) Q3 Q2 Q1 Q4 Q3 Q2
-------------------------------------------------------------------------
Daily production
Natural gas
(mcf/d) 104,714 107,821 87,346 84,466 91,200 124,990
Crude oil
and NGLs
(bbls/d) 6,835 7,395 7,975 8,488 8,431 10,212
Total
(boe/d) 24,287 25,365 22,533 22,566 23,631 31,044
Average prices
Natural gas
($/mcf)
Excluding
hedging $ 3.51 $ 3.81 $ 5.26 $ 4.28 $ 2.89 $ 3.56
Including
hedging $ 4.80 $ 5.58 $ 6.87 $ 6.90 $ 6.10 $ 5.63
AECO
monthly
index $ 3.72 $ 3.86 $ 5.35 $ 4.18 $ 3.03 $ 3.66
Crude oil
and NGLs
($/bbl)
Excluding
hedging $ 61.84 $ 64.66 $ 67.23 $ 63.04 $ 56.99 $ 55.89
Including
hedging $ 59.01 $ 61.80 $ 62.42 $ 57.85 $ 54.02 $ 54.51
WTI
($US/bbl) $ 76.21 $ 77.98 $ 78.79 $ 76.17 $ 68.29 $ 59.62
Total
revenues
(before
royalties) $ 83,335 $ 96,377 $ 98,777 $ 98,782 $ 93,101 $114,659
Net income
(loss) $(16,915) $(22,279) $ 13,155 $(14,213) $(53,293) $(37,810)
per share
- basic $ (0.10) $ (0.14) $ 0.08 $ (0.09) $ (0.33) $ (0.26)
- diluted $ (0.10) $ (0.14) $ 0.08 $ (0.09) $ (0.33) $ (0.26)
Funds from
operations $ 38,450 $ 45,605 $ 50,340 $ 50,083 $ 42,213 $ 51,590
Distributions
declared $ - $ - $ - $ - $ - $ -
($000, except
as otherwise 2009 2008
indicated) Q1 Q4
----------------------------------
Daily production
Natural gas
(mcf/d) 117,968 120,694
Crude oil
and NGLs
(bbls/d) 10,942 11,413
Total
(boe/d) 30,603 31,529
Average prices
Natural gas
($/mcf)
Excluding
hedging $ 5.36 $ 7.15
Including
hedging $ 6.52 $ 7.61
AECO
monthly
index $ 5.64 $ 6.79
Crude oil
and NGLs
($/bbl)
Excluding
hedging $ 43.41 $ 53.65
Including
hedging $ 54.54 $ 61.67
WTI
($US/bbl) $ 43.21 $ 58.75
Total
revenues
(before
royalties) $ 122,950 $ 149,205
Net income
(loss) $ 18,890 $ (95,477)
per share
- basic $ 0.13 $ (0.67)
- diluted $ 0.13 $ (0.67)
Funds from
operations $ 55,591 $ 69,370
Distributions
declared $ 17,266 $ 45,514
The table above highlights the Corporation's and Fund's performance for the third quarter of 2010 and also for the preceding seven quarters. Production was relatively stable during mid-2008 while during the fourth quarter of 2008 and the first quarter of 2009, production decreased as we experienced freezing conditions from early cold weather in December and a slow recovery from such cold weather conditions. An extended third party facility outage began in August 2008 and resulted in 1,100 boe/d of reduced production at our Lookout Butte property. This outage continued through much of 2009 but was completed and our production came back on in November 2009. Production increased in the second quarter of 2009 due to recovery from cold weather conditions that caused brief production outages and additional production from a number of wells drilled during the first quarter of 2009 but delayed until after March 31, 2009 such that we could benefit from the 5% Alberta Provincial royalty rate available on such wells. We experienced a significant decrease in production during the third quarter of 2009 as we completed asset dispositions that closed in July 2009. The disposed properties represented approximately 8,100 boe/d of production. As the third quarter of 2009 still included 1,725 boe/d from the disposed properties, production in the fourth quarter of 2009 actually increased 3% from the prior quarter due to a few new wells and return of production from our Lookout Butte property, partially offset by some natural declines and cold weather conditions that typically cause production interruptions. Production for the first quarter of 2010 was comparable to the fourth quarter of 2009 but increased dramatically during the second quarter of 2010 as our new gas plant was completed and production from Glacier was increased to between 50 and 55 mmcf/d. We also completed two additional asset dispositions during the end of the second quarter of 2010 representing approximately 1,700 boe/d that resulted in modestly lower production. The full impact of these recent dispositions resulted in the decrease in production for the third quarter of 2010. Our financial results, particularly revenues and funds from operations, have declined since 2008, as commodity prices began to decline in response to the financial crisis that materialized in the fall of 2008 and commodity prices continued on a downward trend through to the third quarter of 2009. We experienced improvements in commodity prices during the fourth quarter of 2009 and the first quarter of 2010 that increased our revenues and funds from operations; however, natural gas prices still remained low. During the second and third quarters of 2010, commodity prices weakened again, particular natural gas, which has decreased our revenues and funds from operations. We recognized a considerable net loss in the fourth quarter of 2008, a combined result of falling commodity prices and a $120.3 million impairment of our entire balance of goodwill. In the first quarter of 2009, the global economy showed no clear sign of recovery and commodity prices, particularly natural gas, were weak in comparison to prior quarters. However, Advantage was still able to report net income as we recognized both realized and unrealized gains on our derivative contracts and moderately lower expenses, including operating costs. Natural gas prices continued to worsen during the second and third quarters of 2009 resulting in the recognition of net losses for the periods. The third quarter 2009 net loss was also impacted by additional costs incurred related to the corporate conversion, including a $23.0 million future income tax expense, and increased depletion and depreciation expense from a higher DD&A rate per boe that resulted from the asset dispositions. The net loss decreased during the fourth quarter of 2009 as commodity prices began to improve, but still remained low. Partially offsetting the net losses experienced during 2009 is the continuing reduction in costs including royalties and operating costs. We recognized net income during the first quarter of 2010 with improved crude oil prices. As natural gas prices remained weak, we recognized both realized and unrealized gains on our derivative contracts that positively impacted net income. Commodity prices worsened in the second and third quarters of 2010, particularly natural gas, resulting in net losses during these quarters.
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 Corporation's financial results and financial condition.
Management relies on the estimate of reserves as prepared by the Corporation'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 and impairment of petroleum and natural gas properties. The reserve estimates are also used to assess the borrowing base for the Corporation'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 Corporation.
Management's process of determining the provision for future income taxes, the provision for asset retirement obligation costs and related accretion expense, the fair values initially assigned to the convertible debentures liability and equity components, and the fair values assigned to any acquired company's assets and liabilities in a business combination is based on estimates. These estimates are significant and can include proved and probable reserves, future production rates, future petroleum and natural gas prices, future costs, future interest rates, future tax rates and other relevant assumptions. Revisions or changes in any of these estimates can have either a positive or a negative impact on asset and liability values and net income.
In accordance with GAAP, derivative assets and liabilities are recorded at their fair values at the reporting date, with unrealized gains and losses recognized directly into net income and comprehensive income in the same period. The fair value of derivatives outstanding is an estimate based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are non-cash items and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices and foreign exchange rates as compared to the valuation assumptions.
International Financial Reporting Standards
In February 2008, the Canadian Institute of Chartered Accountants ("CICA") confirmed that Canadian GAAP for publicly accountable enterprises will be replaced by International Financial Reporting Standards ("IFRS") for the fiscal years beginning on or after January 1, 2011. Accordingly, the conversion from Canadian GAAP to IFRS will be applicable to the Corporation's reporting for the first quarter 2011, for which the current and comparative information will be prepared under IFRS. We expect the transition to IFRS will impact accounting, financial reporting, processes, internal controls over financial reporting, taxes, and information systems. Management has engaged its key personnel responsible and developed an overall plan to address IFRS implementation. We anticipate no impact on the Corporations operations or business strategy from conversion to IFRS.
Phase one of our plan consisted of a high level assessment to identify key areas of Canadian GAAP versus IFRS differences that would most likely impact the Corporation. This assessment was completed in early 2009.
Phase two commenced in the third quarter of 2009 and involved the detailed assessment, from an accounting, financial reporting and business perspective, of the changes that would be caused by the conversion to IFRS. Specific accounting processes and policy review included: property, plant and equipment, exploration and evaluation costs, depreciation, impairment of assets, decommissioning liabilities and provisions, deferred income taxes, financial reporting and information systems. The deliverables for this phase include specific accounting policies for the above mentioned topics and also includes IFRS transitional choices. This phase is currently still in progress but is being finalized. The most significant change identified for Advantage, as with many companies in the oil and gas industry, will be associated with accounting for property, plant and equipment ("PP&E"). During the early stages of this phase, we had concentrated on the accounting for PP&E and have now primarily completed our assessments with key policy choices to be approved and finalized. We have now also evaluated most other accounting issues identified whereby differences between Canadian GAAP and IFRS exist for Advantage and have completed preliminary assessments and developed draft accounting policies.
Phase three involves the execution of the work completed in phase two, by making changes to business and accounting processes and supporting information systems, as well as the formal documentation of the final approved accounting policies and procedures compliant with IFRS. This phase is progressing well and is expected to be completed between the end of 2010 and early 2011. Details surrounding the collection of comparative financial and other data in 2010 are currently being finalized in this phase. We are also in the process of finalizing our accounting policies and determining the financial impacts. We have completed our initial draft IFRS transitional balance sheet as of January 1, 2010 and our first quarter 2010 financial statements based on preliminary selected accounting policies. Our external auditors have started their audit work of our transitional balance sheet and review of our first quarter 2010 financial statements. Their work is not yet completed and we will have ongoing discussions with them through the entire process. We have now started to prepare draft IFRS financial statements for the second and third quarters of 2010 and believe we are on schedule to complete the conversion within the required deadline. The draft transitional balance sheet and quarterly financial statements are subject to change depending upon the finalization and approval of accounting policies.
Education and training of key financial employees has been primarily completed. Training of other staff, management, and the Board is ongoing throughout the conversion project. Advantage views education and training as critical to our financial reporting controls and is a permanent process that we will continue. We will begin an education program for key stakeholders upon finalizing the impacts of the IFRS conversion project.
The Corporation has identified the following areas as having the greatest potential impact on the accounting policies, financial reporting and information systems requirements upon conversion to IFRS. Differences between IFRS and Canadian GAAP in addition to those referred to below, may still be identified based on further detailed analysis and other changes in IFRS prior to conversion in 2011. Advantage has not yet finalized all of its accounting policies or transitional choices and as such is unable to quantify the impact on the financial statements of adopting IFRS at this time. Any accounting policy selections or potential impacts referred to below are preliminary and are not finalized until all policies have been selected, approved by the Board of Directors, and completion of the corresponding audit and reviews by our external auditors. We continue to monitor other IFRS developments that may impact our choice of accounting policies.
a) Property, plant and equipment
The Corporation, like many Canadian oil and gas reporting issuers, applies the "full cost" concept in accounting for its oil and gas assets. Under full cost, capital expenditures are maintained in a single cost centre for each country, and the cost centre is subject to a single depletion and depreciation calculation and impairment test. IFRS will require the Corporation to make a much more detailed assessment of its oil and gas assets that will impact depreciation and impairment calculations. Included in this assessment is an ongoing appraisal of exploration and evaluation expenditures ("E&E"). Under Canadian GAAP, it is necessary to track costs associated with unproved properties that would be excluded from depletion and depreciation calculations. Under IFRS, a company may choose to expense E&E associated costs or capitalize such costs without recording depreciation expense until the expenditures are determined to represent technically feasible and commercially viable projects at which time the costs are moved to development properties. Advantage currently anticipates that it will select to capitalize E&E costs except for costs incurred before the acquisition of rights to explore, and to begin depreciating when technically feasible and commercially viable. We do not anticipate this to have a material impact on our financial results other than to the extent that expenditures may be incurred related to unsuccessful wells or projects that will be expensed in the period incurred.
b) Depreciation
For Canadian GAAP purposes, the full cost method of accounting for oil and gas properties requires a single calculation of depletion and depreciation of the carrying value of PP&E based on proved reserves. However, IFRS requires an allocation of the amount recognized as PP&E to each significant identified component and each component depreciated separately, utilizing an appropriate method of depreciation. This component depreciation of PP&E will result in an increased number of calculations of depreciation expense and may impact the amount of depreciation expense recognized. IFRS also permits the option of using either proved or proved and probable reserves in the depreciation calculation. Advantage has not concluded at this time which reserves it will use but we expect that utilizing proved and probable reserves would have a material decrease in the amount of depreciation expense recognized.
c) Impairment of Assets
Under Canadian GAAP, impairment calculations are prepared according to a two-step test generally conducted at a country level. Step one involves a comparison of the PP&E carrying value to the undiscounted net cash flows of proved reserves. If a company should fail step one, step two is completed to measure the amount of impairment whereby the PP&E carrying value is compared to a calculated fair value with any excess carrying value above the fair value recognized as an impairment loss. Impairment losses recognized under Canadian GAAP are not subsequently reversed. Under IFRS, impairment testing is completed at an individual asset group or "Cash Generating Unit" level ("CGU") when indicators suggest there may be impairment. A CGU is defined as the smallest group of assets that produce independent cash flows. Impairment of assets at a CGU level use a one-step approach for testing and measuring asset impairment, with asset carrying values compared to the higher of "Value in Use" and "Fair Value less Costs to Sell". The IFRS methodology may result in the possibility of more frequent impairments in the carrying value of PP&E. However, under IFRS previous impairment losses (except for goodwill) must be reversed where circumstances change such that the previously recognized impairment has been reduced. Advantage has completed an initial assessment of CGU's as of the transition date and has determined there to be approximately 10 to 12 CGU's. The number of CGU's is subject to change as Advantage's portfolio of assets may change through development activities, acquisitions or dispositions.
d) Decommissioning Liabilities
Both Canadian GAAP and IFRS require a company to provide for a liability related to decommissioning PP&E. Both methodologies are similar and we have determined there to be no significant difference for Advantage, other than a potential difference related to discount rates. Canadian GAAP requires that the decommissioning liability be discounted at a credit-adjusted risk-free rate while IFRS requires that the decommissioning liability be discounted at an appropriate rate with either the cash flows or rate adjusted for risks. As a result, there currently is the possibility of using a risk-free rate or a credit-adjusted risk-free rate. Advantage is still evaluating this and has not made a decision on the discount rate at this time. Utilizing a risk-free rate would result in a material increase in the decommissioning liability under IFRS.
e) Deferred Income Taxes
Future income taxes under Canadian GAAP and deferred income taxes under IFRS are similar for Advantage and we are continuing to evaluate this complex area. However, any differences in decommissioning liabilities and PP&E, including depreciation, will impact the carrying value as reported on the balance sheet and therefore result in a difference in the balance of deferred taxes reported under IFRS.
f) First Time Adoption of International Financial Reporting Standards
IFRS 1 provides the framework for the first time adoption of IFRS and specifies that an entity shall apply the principles under IFRS retrospectively. IFRS 1 also specifies that the adjustments that arise on retrospective conversion to IFRS from other GAAP should be directly recognized in retained earnings. Certain optional exemptions and mandatory exceptions to retrospective application are provided under IFRS 1. Advantage has chosen to apply an exemption that allows an entity that used full cost accounting, at adoption of IFRS, to measure exploration and evaluation assets at the amount measured under its previous GAAP for those assets. The entity may also measure its oil and gas assets in the development and production phases, by allocating the amount determined under the entities previous GAAP to the underlying assets and areas pro rata using reserve volumes or reserve values as of that date. Advantage has made a preliminary allocation based on proved and probable reserves values discounted at 10%. The allocation process had no impact on Advantage's carrying value of PP&E. As a result of applying this exemption, Advantage will also be required to complete an impairment test under IFRS on the transition date. A preliminary impairment test has been completed for the tentatively determined CGU's and there is currently no impairment at transition date.
Advantage has also elected not to reevaluate prior completed business combinations under Canadian GAAP and has simply reviewed such prior business combinations accounting to ensure that no assets were recognized that would be inappropriate under IFRS. We have not found any such items and there will be no impact from choosing this exemption.
g) Financial Reporting
The adoption of IFRS will result in different presentation and additional disclosure requirements in the financial statements. Draft IFRS financial statements including notes have been prepared and are being reviewed with our external auditors and Board of Directors. We anticipate that review and discussion of the presentation and disclosures will continue until the first interim financial statements are released for the quarter ended March 31, 2011.
h) Information Systems
The adoption of IFRS will have an impact on information systems requirements. We have evaluated our financial reporting systems and have made current changes to accommodate IFRS. We will continue assessing the need for additional system upgrades or modifications to ensure an efficient conversion to IFRS and to improve ongoing processes.
i) Internal Controls
In accordance with the Corporations approach to certification of internal controls required under Canadian Securities Administrators' National instrument 52-109 and SOX 302 and 404, all entity level, information technology, disclosures and business process controls will require updating and testing to reflect changes arising from our conversion to IFRS. Upon review with internal audit, we have determined there to be minimal updating of processes, controls and documentation required. We will work on updating our processes, controls and documentation during the final phase of IFRS conversion.
Disclosure Controls and Internal Controls over Financial Reporting
Disclosure controls and procedures have been designed to provide reasonable assurance that information required to be disclosed by the Corporation is recorded, processed, summarized and reported within the time periods specified under the Canadian securities law. Advantage's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation, that the disclosure controls and procedures as of the end of September 30, 2010, are effective and provide reasonable assurance that material information related to the Corporation is made known to them by others within Advantage.
Advantage's Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal controls over financial reporting ("ICFR"). They have, as at the quarter ended September 30, 2010, designed ICFR or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The control framework Advantage's officers used to design the ICFR is the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations.
Advantage's Chief Executive Officer and Chief Financial Officer are required to disclose any change in the internal controls over financial reporting that occurred during our most recent interim period that has materially affected, or is reasonably likely to affect, the Corporation's internal controls over financial reporting. No material changes in the internal controls were identified during the period ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
It should be noted that a control system, including Advantage's disclosure and internal controls and procedures, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
Outlook
During the first half of 2010, we successfully completed our Phase II Montney development program at Glacier which involved drilling horizontal wells to build production inventory and delineate our land block. Construction on Advantage's 100% working interest gas plant and gathering system expansion was completed ahead of schedule and on-budget leading to an earlier than anticipated commissioning during March 2010. The Glacier gas plant has since been operating at its design capacity with throughput rates between 50 and 55 mmcf/d.
Phase III of our Glacier development project which is targeted to increase production to 100 mmcf/d began at the end of the second quarter of 2010 and is expected to be completed in the second quarter of 2011. Phase III includes the drilling of 28 net (28 gross) horizontal wells and the fabrication of a new processing train to facilitate expansion of the gas plant. We have now drilled 21 horizontal wells of our Phase III program with 3 more wells currently drilling and 4 wells remaining to drill. The first 7 wells drilled have now been completed and tested with 14 wells waiting on completions. We currently have production of approximately 75 mmcf/d tested and behind pipe. Additional wells will be brought on-production in the future to maintain our facilities at capacity prior to completing the Phase III expansion. The amount of excess field production capability above our current plant capacity is a result of our successful drilling program which demonstrated well test rates that exceeded expectations and proved up a large portion of our undrilled acreage at Glacier. Fabrication of the new processing train components is nearing completion and we expect equipment to be delivered to the plant site in December for final installation and construction to begin. The sales lateral looping expansion to 100 mmcf/d is now completed with the meter station upgrade underway.
Advantage's corporate capital budget for the twelve month period ending June 2011 was set at $219 million ($200 million net of drilling credits) with approximately 80% of the capital budget allocated to Glacier for Phase III. In conjunction with the anticipated production increase at Glacier, corporate production is forecast to grow to approximately 30,000 boe/d in the second quarter of 2011 representing a 25% increase over the period, of which Glacier will represent 55% of total production. Advantage's capital budget reinforces our strategy to focus on projects that generate economic growth during lower commodity price cycles, balance cash flow and capital requirements and reduce our cost structure. Advantage's strong hedging program significantly enhances our cash flow which provides an opportunity to leverage capital spending during this low supply cost environment and to capitalize on the Alberta Royalty Incentive Programs. Management will review the capital program on a regular basis in the context of prevailing economic conditions and make adjustments as deemed necessary to the program, subject to approval by the Board of Directors.
Our guidance for the twelve months ending June 2011 is as follows:
Total
H2 2010 H1 2011 12 Months
(estimate) (estimate) (estimate)
-------------------------------------------------------------------------
Production Average
(boe/d) 23,500 - 24,300 26,600 - 27,200 25,050 - 25,750
Exit Rate (boe/d) ~24,000 ~30,000
Royalty Rate (%) 13% - 15% 13% - 15% 13% - 15%
Operating Costs
($/boe) $ 9.75 - $10.25 $8.50 - $9.00 $9.10 - $9.65
Capital
Expenditures*
($ million) $120 - $130 $70 - $80 $190 - $210*
-------------------------------------------------------------------------
* - Capital expenditures are net of total drilling credits of $19
million over the 12 month period.
Looking forward, Advantage is well positioned to pursue future development plans at Glacier with our strong balance sheet, solid hedging position and improved financial flexibility. With an inventory of over 500 drilling locations at Glacier and a growing inventory of drilling opportunities in Central Alberta and Saskatchewan, Management will continue to employ a disciplined approach to allocate capital to the highest return projects to create long term growth in shareholder value.
Additional Information
Additional information relating to Advantage can be found on SEDAR at www.sedar.com and the Corporation's website at www.advantageog.com. Such other information includes the annual information form, the annual information circular - proxy statement, press releases, material contracts and agreements, and other financial reports. The annual information form will be of particular interest for current and potential shareholders as it discusses a variety of subject matter including the nature of the business, description of our operations, general and recent business developments, risk factors, reserves data and other oil and gas information.
November 11, 2010
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
September 30, December 31,
(thousands of dollars) 2010 2009
-------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Accounts receivable $ 35,783 $ 54,531
Prepaid expenses and deposits 6,550 9,936
Derivative asset (note 8) 34,537 30,829
-------------------------------------------------------------------------
76,870 95,296
Derivative asset (note 8) 5,276 323
Fixed assets (note 2) 1,743,430 1,831,622
-------------------------------------------------------------------------
$ 1,825,576 $ 1,927,241
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 103,518 $ 111,901
Current portion of capital lease
obligations (note 3) 826 1,375
Current portion of convertible debentures - 69,553
Derivative liability (note 8) 3,053 12,755
Future income taxes 8,320 4,704
-------------------------------------------------------------------------
115,717 200,288
Derivative liability - 1,165
Capital lease obligations - 759
Bank indebtedness (note 5) 261,254 247,784
Convertible debentures (note 4) 133,442 130,658
Asset retirement obligations (note 6) 57,430 68,555
Future income taxes 31,967 38,796
Other liability 2,615 3,431
-------------------------------------------------------------------------
602,425 691,436
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (note 7) 2,196,696 2,190,409
Convertible debentures equity component
(note 4) 15,896 18,867
Contributed surplus (note 7) 17,344 7,275
Deficit (1,006,785) (980,746)
-------------------------------------------------------------------------
1,223,151 1,235,805
-------------------------------------------------------------------------
$ 1,825,576 $ 1,927,241
-------------------------------------------------------------------------
Commitments (note 9)
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Loss,
Comprehensive Loss and Deficit
(thousands of dollars, Three months ended Nine months ended
except for per share Sept. 30, Sept. 30, Sept. 30, Sept. 30,
amounts) (unaudited) 2010 2009 2010 2009
-------------------------------------------------------------------------
Revenue
Petroleum and
natural gas $ 72,722 $ 68,470 $ 243,147 $ 260,495
Realized gain on
derivatives
(note 8) 10,613 24,631 35,342 70,215
Unrealized gain
(loss) on
derivatives
(note 8) 3,688 (9,136) 19,528 (9,314)
Royalties (10,272) (8,749) (35,327) (37,620)
-------------------------------------------------------------------------
76,751 75,216 262,690 283,776
-------------------------------------------------------------------------
Expenses
Operating 22,812 25,114 70,088 96,175
General and
administrative 9,576 13,224 29,398 28,452
Management
internalization - - - 1,724
Interest 3,326 6,331 10,131 14,686
Interest and
accretion on
convertible
debentures 3,286 3,966 12,341 13,307
Depletion,
depreciation
and accretion 58,122 62,499 169,018 204,598
-------------------------------------------------------------------------
97,122 111,134 290,976 358,942
-------------------------------------------------------------------------
Loss before taxes (20,371) (35,918) (28,286) (75,166)
Future income tax
expense (reduction) (3,763) 17,023 (3,213) (3,929)
Income and capital
taxes 307 352 966 976
-------------------------------------------------------------------------
(3,456) 17,375 (2,247) (2,953)
-------------------------------------------------------------------------
Net loss and
comprehensive loss (16,915) (53,293) (26,039) (72,213)
Deficit, beginning of
period (989,870) (913,240) (980,746) (877,054)
Distributions
declared - - - (17,266)
-------------------------------------------------------------------------
Deficit, end of
period $(1,006,785) $ (966,533) $(1,006,785) $ (966,533)
-------------------------------------------------------------------------
Net loss per share
(note 7)
Basic and diluted $ (0.10) $ (0.33) $ (0.16) $ (0.48)
-------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
Three months ended Nine months ended
(thousands of Sept. 30, Sept. 30, Sept. 30, Sept. 30,
dollars) (unaudited) 2010 2009 2010 2009
-------------------------------------------------------------------------
Operating Activities
Net loss $ (16,915) $ (53,293) $ (26,039) $ (72,213)
Add (deduct) items not
requiring cash:
Unrealized loss
(gain) on
derivatives (3,688) 9,136 (19,528) 9,314
Equity-based
compensation
(note 7) 3,707 2,433 10,838 4,122
Non-cash general
and administrative - 3,781 - 3,781
Management
internalization - - - 1,724
Accretion on other
liability 49 22 161 22
Accretion on
convertible
debentures 938 612 3,158 1,975
Depletion,
depreciation and
accretion 58,122 62,499 169,018 204,598
Future income tax
expense (reduction) (3,763) 17,023 (3,213) (3,929)
Expenditures on
asset retirement (2,603) (868) (4,464) (4,490)
Changes in non-cash
working capital 12,689 9,326 17,295 (13,398)
-------------------------------------------------------------------------
Cash provided by
operating activities 48,536 50,671 147,226 131,506
-------------------------------------------------------------------------
Financing Activities
Units issued, less
costs - 96,900 - 96,779
Convertible debenture
maturities (note 4) - (52,268) (69,927) (82,107)
Increase (decrease)
in bank indebtedness (10,179) (315,361) 13,470 (256,968)
Reduction of capital
lease obligations (617) (329) (1,308) (974)
Distributions to
Unitholders - - - (23,481)
Changes in non-cash
working capital - - (310) -
-------------------------------------------------------------------------
Cash used in
financing activities (10,796) (271,058) (58,075) (266,751)
-------------------------------------------------------------------------
Investing Activities
Expenditures on fixed
assets (65,491) (42,658) (154,390) (111,020)
Property dispositions (1,032) 243,565 69,450 245,184
Changes in non-cash
working capital 28,783 19,480 (4,211) 1,081
-------------------------------------------------------------------------
Cash provided by
(used in) investing
activities (37,740) 220,387 (89,151) 135,245
-------------------------------------------------------------------------
Net change in cash - - - -
Cash, beginning of
period - - - -
-------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-------------------------------------------------------------------------
Supplementary Cash
Flow Information
Interest paid $ 5,855 $ 7,095 $ 15,972 $ 22,135
Taxes paid $ 300 $ 450 $ 900 $ 1,060
see accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2010 (unaudited)
All tabular amounts in thousands except as otherwise indicated.
The interim consolidated financial statements of Advantage Oil & Gas Ltd.
("Advantage" or the "Corporation") have been prepared by management in
accordance with Canadian generally accepted accounting principles
("GAAP") using the same accounting policies as those set out in note 2 to
the consolidated financial statements for the year ended December 31,
2009. These interim financial statement note disclosures do not include
all of those required by Canadian GAAP applicable for annual financial
statements. The interim consolidated financial statements should be read
in conjunction with the audited consolidated financial statements for the
year ended December 31, 2009 as set out in the Corporation's Annual
Report.
Certain comparative figures have been reclassified to conform to the
current period presentation.
1. Business and Structure of Advantage Oil & Gas Ltd.
Advantage Oil & Gas Ltd. is an intermediate oil and natural gas
development and production corporation with properties located in
Western Canada. Advantage was created on July 9, 2009, through the
completion of a plan of arrangement pursuant to an information
circular dated June 5, 2009. Advantage Energy Income Fund (the
"Fund") was dissolved and converted into the corporation, Advantage
Oil and Gas Ltd., with each Trust Unit converted into one Common
Share. The figures for the three and nine month periods ended
September 30, 2009 therefore include results of the Fund up to
July 9, 2009. Advantage does not currently pay a dividend.
2. Fixed Assets
Accumulated
Depletion and Net Book
September 30, 2010 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 3,295,842 $ 1,555,308 $ 1,740,534
Furniture and equipment 12,090 9,194 2,896
---------------------------------------------------------------------
$ 3,307,932 $ 1,564,502 $ 1,743,430
---------------------------------------------------------------------
Accumulated
Depletion and Net Book
December 31, 2009 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural
gas properties $ 3,218,785 $ 1,390,784 $ 1,828,001
Furniture and equipment 11,785 8,164 3,621
---------------------------------------------------------------------
$ 3,230,570 $ 1,398,948 $ 1,831,622
---------------------------------------------------------------------
In May 2010, Advantage closed two asset dispositions for net proceeds
of $66.1 million, subject to further adjustments.
3. Capital Lease Obligations
The Corporation has capital leases on a variety of fixed assets.
Future minimum lease payments at September 30, 2010 consist of the
following:
2010 $ 78
2011 779
-----------------------------------------
857
Less amounts representing
interest (31)
-----------------------------------------
Current portion $ 826
-----------------------------------------
4. Convertible Debentures
The balance of debentures outstanding at September 30, 2010 and
changes in the liability and equity components during the nine months
ended September 30, 2010 are as follows:
6.50% 7.75%
---------------------------------------------
Trading symbol AAV.DBE AAV.DBD
Debentures
outstanding $ - $ 46,766
---------------------------------------------
Liability component:
Balance at
December 31, 2009 $ 69,553 $ 45,574
Accretion of
discount 374 462
Matured (69,927) -
---------------------------------------------
Balance at
September 30, 2010 $ - $ 46,036
---------------------------------------------
Equity component:
Balance at
December 31, 2009 $ 2,971 $ 2,286
Expired (2,971) -
---------------------------------------------
Balance at
September 30, 2010 $ - $ 2,286
---------------------------------------------
8.00% 5.00% Total
---------------------------------------------------------
Trading symbol AAV.DBG AAV.DBH
Debentures
outstanding $ 15,528 $ 86,250 $ 148,544
---------------------------------------------------------
Liability component:
Balance at
December 31, 2009 $ 15,227 $ 69,857 $ 200,211
Accretion of
discount 112 2,210 3,158
Matured - - (69,927)
---------------------------------------------------------
Balance at
September 30, 2010 $ 15,339 $ 72,067 $ 133,442
---------------------------------------------------------
Equity component:
Balance at
December 31, 2009 $ 798 $ 12,812 $ 18,867
Expired - - (2,971)
---------------------------------------------------------
Balance at
September 30, 2010 $ 798 $ 12,812 $ 15,896
---------------------------------------------------------
The principal amount of 6.50% convertible debentures matured on June 30,
2010 and was settled with $69.9 million in cash.
There were no conversions of convertible debentures during the nine months
ended September 30, 2010.
5. Bank Indebtedness
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Revolving credit facility $ 263,306 $ 250,262
Discount on Bankers Acceptances and
other fees (2,052) (2,478)
---------------------------------------------------------------------
Balance, end of period $ 261,254 $ 247,784
---------------------------------------------------------------------
Advantage's credit facilities of $525 million is comprised of a
$20 million extendible revolving operating loan facility from one
financial institution and a $505 million extendible revolving loan
facility from a syndicate of financial institutions (the "Credit
Facilities"). Amounts borrowed under the Credit Facilities bear
interest at a floating rate based on the applicable Canadian prime
rate, US base rate, LIBOR rate or bankers' acceptance rate plus
between 1.25% and 3.75% depending on the type of borrowing and the
Corporation's debt to cash flow ratio. The Credit Facilities are
collateralized by a $1 billion floating charge demand debenture
covering all assets of the Corporation. The amounts available to
Advantage from time to time under the Credit Facilities are based
upon the borrowing base determined semi-annually by the lenders. The
revolving period for the Credit Facilities will end in June 2011
unless extended at the option of the syndicate for a further 364 day
period. If the Credit Facilities are not extended, they will convert
to non-revolving term facilities due 365 days after the last day of
the revolving period. The credit facilities prohibit the Corporation
from entering into any derivative contract where the term of such
contract exceeds three years. Further, the aggregate of such
contracts cannot hedge greater than 60% of total estimated petroleum
and natural gas production over two years and 50% over the third
year. The Credit Facilities contain standard commercial covenants for
credit facilities of this nature. The only financial covenant is a
requirement for Advantage to maintain a minimum cash flow to interest
expense ratio of 3.5:1, determined on a rolling four-quarter basis.
This covenant was met at September 30, 2010. Breach of any covenant
will result in an event of default in which case Advantage has 20
days to remedy such default. If the default is not remedied or
waived, and if required by the lenders, the administrative agent of
the lenders has the option to declare all obligations under the
credit facilities to be immediately due and payable without further
demand, presentation, protest, days of grace, or notice of any kind.
Interest payments under the debentures are subordinated to the
repayment of any amounts owing under the credit facilities and are
not permitted if the Corporation is in default of such credit
facilities or if the amount of outstanding indebtedness under such
facilities exceeds the then existing current borrowing base. For the
nine months ended September 30, 2010, the average effective interest
rate on the outstanding amounts under the facility was approximately
5.1% (September 30, 2009 - 4.4%). Advantage also has issued letters
of credit totaling $9.6 million at September 30, 2010 (December 31,
2009 - $1.3 million).
6. Asset Retirement Obligations
A reconciliation of the asset retirement obligations is provided
below:
Nine
months ended Year ended
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 68,555 $ 73,852
Accretion expense 3,464 5,297
Liabilities incurred 972 699
Change in estimates 2,655 16,419
Property dispositions (13,752) (22,275)
Liabilities settled (4,464) (5,437)
---------------------------------------------------------------------
Balance, end of period $ 57,430 $ 68,555
---------------------------------------------------------------------
7. Shareholders' Equity
(a) Share capital
(i) Authorized
The Corporation is authorized to issue an unlimited number
of shares without nominal or par value.
(ii) Issued
Number of Shares Amount
---------------------------------------------------------------------
Balance at December 31, 2009 162,745,528 $ 2,190,409
Issued pursuant to Restricted Share
Performance Incentive Plan 974,365 6,287
---------------------------------------------------------------------
Balance at September 30, 2010 163,719,893 $ 2,196,696
---------------------------------------------------------------------
(b) Contributed surplus
The changes in contributed surplus during the nine months ended
September 30, 2010 and the year ended December 31, 2009 are as
follows:
Nine
months ended Year ended
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 7,275 $ 287
Equity-based compensation 7,098 3,640
Expiration of convertible debentures
equity component (note 4) 2,971 3,348
---------------------------------------------------------------------
Balance, end of period $ 17,344 $ 7,275
---------------------------------------------------------------------
The components of contributed surplus are as follows:
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Expired convertible debentures equity
component $ 6,606 $ 3,635
Equity-based compensation 10,738 3,640
---------------------------------------------------------------------
Balance, end of period $ 17,344 $ 7,275
---------------------------------------------------------------------
(c) Equity-based compensation
Total equity-based compensation expense recorded during the nine
months ended September 30, 2010 was $13.5 million, including
non-cash general and administrative expense of $10.8 million.
During the nine months ended September 30, 2010, 974,365 shares
were issued in satisfaction of grants vesting under the
Restricted Share Performance Incentive Plan ("RSPIP").
The details of restricted shares granted and outstanding at
September 30, 2010 are as follows:
Weighted
average
Restricted fair
Restricted Restricted Restricted Shares value at
Shares Shares Shares Outstand- grant
Date Granted Granted Vested Forfeited ing date
-------------------------------------------------------------------------
January 15, 2009 691,178 487,427 21,973 181,778 $5.49
September 2, 2009 1,453,609 741,842 8,164 703,603 $5.80
October 15, 2009 1,153,314 403,251 5,765 744,298 $7.51
January 12, 2010 779,013 269,544 3,901 505,568 $7.27
April 12, 2010 979,915 332,973 5,070 641,872 $6.97
July 12, 2010 788,092 262,689 335 525,068 $6.53
-------------------------------------------------------------------------
Total 5,845,121 2,497,726 45,208 3,302,187 $6.59
-------------------------------------------------------------------------
(d) Net loss per share
The calculations of basic and diluted net loss per share are
derived from both net loss and weighted average shares
outstanding, calculated as follows:
Three months ended Nine months ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2010 2009 2010 2009
---------------------------------------------------------------------
Net loss
Basic and
diluted $ (16,915) $ (53,293) $ (26,039) $ (72,213)
---------------------------------------------------------------------
Weighted average
shares
outstanding
Basic and
diluted 163,536,868 161,182,480 163,275,757 149,915,761
---------------------------------------------------------------------
The calculation of diluted net loss per share excludes all series of
convertible debentures as the impact would be anti-dilutive. Total
weighted average shares issuable in exchange for the convertible
debentures and excluded from the diluted net loss per share
calculation for the three and nine months ended September 30, 2010
were 13,019,819 and 14,867,004 shares, respectively (three and nine
months ended September 30, 2009 - 8,345,392 and 8,964,955 shares,
respectively). As at September 30, 2010, the total convertible
debentures outstanding were immediately convertible to 13,019,819
shares (September 30, 2009 - 5,792,312 shares).
Restricted shares granted have been excluded from the calculation of
diluted net loss per share for the three and nine months ended
September 30, 2010, as the impact would have been anti-dilutive.
Total weighted average shares issuable in exchange for the restricted
shares and excluded from the diluted net loss per share calculation
for the three and nine months ended September 30, 2010 were 1,417,495
and 1,052,183, respectively (three and nine months ended
September 30, 2009 - 196,831 and 180,076, respectively).
8. Financial Instruments
Financial liabilities
The timing of cash outflows relating to financial liabilities are as
follows:
One to Four to
Less than three five
one year years years Thereafter Total
-------------------------------------------------------------------------
Accounts payable
and accrued
liabilities $ 103,518 $ - $ - $ - $ 103,518
Capital lease
obligations 826 - - - 826
Derivative
liabilities 3,053 - - - 3,053
Bank indebtedness
- principal - 263,306 - - 263,306
- interest 13,602 9,950 - - 23,552
Convertible
debentures
- principal - 62,294 86,250 - 148,544
- interest 9,179 11,058 6,469 - 26,706
Other liability - 2,615 - - 2,615
-------------------------------------------------------------------------
$130,178 $ 349,223 $ 92,719 $ - $ 572,120
-------------------------------------------------------------------------
Interest on bank indebtedness was calculated assuming conversion of the
revolving credit facility to a one-year term facility.
The Corporation's bank indebtedness does not have specific maturity
dates. It is governed by a credit facility agreement with a syndicate
of financial institutions (note 5). Under the terms of the agreement,
the facility is reviewed annually, with the next review scheduled in
June 2011. The facility is revolving, and is extendible at each
annual review for a further 364 day period at the option of the
syndicate. If not extended, the credit facility is converted at that
time into a one-year term facility, with the principal payable at the
end of such one-year term. Management fully expects that the facility
will be extended at each annual review.
Derivative financial instruments
As at September 30, 2010 the Corporation had the following
derivatives in place:
Description of
Derivative Term Volume Average Price
-------------------------------------------------------------------------
Natural gas - AECO
Fixed price January 2010 to December 2010 18,956 mcf/d Cdn$7.29/mcf
Fixed price April 2010 to January 2011 18,956 mcf/d Cdn$7.25/mcf
Fixed price January 2011 to December 2011 9,478 mcf/d Cdn$6.24/mcf
Fixed price January 2011 to December 2011 9,478 mcf/d Cdn$6.24/mcf
Fixed price January 2011 to December 2011 9,478 mcf/d Cdn$6.26/mcf
Crude oil - WTI
Fixed price April 2010 to January 2011 2,000 bbls/d Cdn$69.50/bbl
Fixed price January 2011 to December 2011 1,500 bbls/d Cdn$91.05/bbl
Electricity - Alberta Pool Price
Fixed price January 2010 to December 2010 2.0 MW Cdn$54.46/MWh
As at September 30, 2010, the fair value of the derivatives
outstanding resulted in an asset of approximately $39.8 million
(December 31, 2009 - $31.1 million) and a liability of approximately
$3.1 million (December 31, 2009 - $13.9 million). For the nine months
ended September 30, 2010, $19.5 million was recognized in net loss as
an unrealized derivative gain (September 30, 2009 - $9.3 million
unrealized derivative loss) and $35.3 million was recognized in net
loss as a realized derivative gain (September 30, 2009 -
$70.2 million realized derivative gain).
9. Commitments
Advantage has several lease commitments relating to office buildings
and transportation. The estimated remaining annual minimum operating
lease payments are as follows, of which $2.6 million is recognized in
other liabilities:
2010 $ 2,117
2011 8,048
2012 7,601
2013 6,188
2014 6,150
2015 1,775
---------------------------------
$ 31,879
---------------------------------
Advisory
The information in this press release contains certain forward-looking statements, including within the meaning of the United States Private Securities Litigation Reform Act of 1995. These statements relate to future events or our future intentions or 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", "demonstrate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar expressions and include statements relating to, among other things, individual wells, regions, properties or projects. 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 decisions, activities, 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. For additional risk factors in respect of Advantage and its business, please refer to its Annual Information Form dated March 16, 2010 which is available on SEDAR at www.sedar.com and www.advantageog.com.
References in this press release to initial test production rates, initial "productivity", initial "flow" rates, "flush" production rates and "behind pipe production" are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Advantage.
Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel. "TCF" stands for trillion cubic feet of natural gas. Such conversion rates are based on an energy equivalency conversion method application at the burner tip and do not represent an economic value equivalency at the wellhead.
The Corporation discloses several financial measures that do not have any standardized meaning prescribed under GAAP. These financial measures include funds from operations and cash netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation'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.
%CIK: 0001468079