Glacier Production Increased, Lower Operating Costs and Alberta Royalty Incentives Enhance Montney Drilling Economics
(TSX: AAV, NYSE: AAV)
CALGARY, Aug. 12 /CNW/ - Advantage Oil & Gas Ltd. ("Advantage" or the "Corporation") is pleased to announce its unaudited operating and financial results for the second quarter ended June 30, 2010.
Three Three Six Six
months months months months
ended ended ended ended
Financial and Operating June 30, June 30, June 30, June 30,
Highlights 2010 2009 2010 2009
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Financial ($000, except
as otherwise indicated)
Revenue before
royalties(1) $ 96,377 $ 114,659 $ 195,154 $ 237,609
per share(2) $ 0.59 $ 0.79 $ 1.20 $ 1.65
per boe $ 41.75 $ 40.59 $ 45.00 $ 42.59
Funds from operations $ 45,605 $ 51,590 $ 95,945 $ 107,181
per share(2) $ 0.28 $ 0.35 $ 0.59 $ 0.73
per boe $ 19.76 $ 18.26 $ 22.12 $ 19.21
Net loss $ (22,279) $ (37,810) $ (9,124) $ (18,920)
per share(2) $ (0.14) $ (0.26) $ (0.06) $ (0.13)
Expenditures on fixed
assets $ 19,549 $ 15,719 $ 88,899 $ 68,362
Working capital
deficit(3) $ 20,831 $ 131,913 $ 20,831 $ 131,913
Bank indebtedness $ 273,529 $ 644,100 $ 273,529 $ 644,100
Convertible debentures
(maturity value) $ 148,544 $ 184,489 $ 148,544 $ 184,489
Shares outstanding at end
of period (000) 163,303 145,198 163,303 145,198
Basic weighted average
shares (000) 163,264 144,681 163,143 144,189
Operating
Daily Production
Natural gas (mcf/d) 107,821 124,990 97,640 121,498
Crude oil and NGLs
(bbls/d) 7,395 10,212 7,683 10,575
Total boe/d @ 6:1 25,365 31,044 23,956 30,825
Average prices (including
hedging)
Natural gas ($/mcf) $ 5.58 $ 5.63 $ 6.15 $ 6.06
Crude oil and NGLs
($/bbl) $ 61.80 $ 54.51 $ 62.12 $ 54.53
(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 Increased Production, Lower Operating
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Costs & Strong Hedging Gains
----------------------------
- Funds from operations for the second quarter of 2010 was $45.6
million or $0.28 per share. Funds from operations was supported by
increased production, lower operating costs, and hedging gains
partially offset by a 2009 royalty adjustment. As compared to the
second quarter of 2009, total funds from operations decreased 12%
primarily due to the sale of approximately 8,100 boe/d of assets in
July 2009; however, funds from operations per boe grew 8% to
$19.76/boe due to Advantage's improving cost structure.
- Average daily production during the second quarter of 2010 increased
13% to 25,365 boe/d compared to the first quarter of 2010. Production
rates increased due to the ramp-up of our Glacier production from 25
mmcf/d to approximately 50 mmcf/d, partially offset by approximately
500 boe/d of lower production during the second quarter due to the
disposition of non-core natural gas weighted assets representing
production of 1,700 boe/d. Advantage's corporate production increased
by approximately 15% through drill bit growth as compared to the
third quarter of 2009, after adjusting for asset dispositions of
8,100 boe/d completed in July 2009.
- Total operating costs for the second quarter of 2010 decreased 30% to
$24.6 million and decreased 14% on a per boe basis to $10.64/boe as
compared to $35.0 million or $12.40/boe during the second quarter of
2009. Per boe operating costs decreased 5% as compared to the first
quarter of 2010. Operating costs per boe have decreased as a result
of the disposition of higher cost non-core assets, an increasing
contribution of low cost production from Glacier and the continued
optimization of our other assets. Operating costs in the second
quarter of 2010 were slightly impacted by higher workover and
maintenance costs and additional costs required for the start-up of
our new Glacier gas plant.
- Total royalties paid during the second quarter of 2010 decreased 5%
as compared to the same period in 2009. The royalty rate as a
percentage of revenue was 15.1% as compared to 14.4% in the first
quarter of 2010. An increase in the royalty rate during the second
quarter was due to a 2009 Alberta gas cost allowance annual
adjustment which was paid during the period. Going forward, we
anticipate corporate royalty rates to decrease due to the recently
announced changes in the Alberta Royalty framework and benefits from
the royalty incentive programs resulting from our ongoing drilling
program at Glacier.
- For the three and six months ended June 30, 2010, our hedging program
contributed a net gain of $15.5 million and $24.7 million to funds
from operations, respectively. Advantage's consistent hedging program
has helped to stabilize and enhance our cash flow for capital
reinvestment requirements.
- In the last twelve months we have reduced our bank indebtedness by
58% and our convertible debentures outstanding by 19%. As at June 30,
2010, Advantage's bank debt was $273.5 million on a credit facility
of $525 million resulting in an unutilized capacity of approximately
$251.5 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.
- Net capital expenditures during the second quarter of 2010 amounted
to $19.5 million for a total of $88.9 million for the first six
months of 2010. Approximately 83% of our capital program for the
first half of 2010 was invested at Glacier whereby we successfully
completed Phase II of our development program in the second quarter
of 2010 which increased production capability to approximately 50
mmcf/d. Actual capital spending was less than our total capital
budget for the first six months of 2010 as we reduced Glacier costs
and improved well results. The remaining capital expenditures
included 4.5 net (5 gross) light oil wells in Saskatchewan, 2.8 net
(3 gross) wells at Nevis and 2.8 net (4 gross) wells at Sunset in
support of our light oil water flood project development.
Glacier Production Increases to 50 mmcf/d with Reduced Operating Costs
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during Q2 2010
--------------
- Total gross raw inlet volumes at our Glacier gas plant increased to
average 51 mmcf/d (8,500 boe/d) subsequent to our press release on
April 19, 2010 when we announced that our new 100% working interest
gas plant was brought on-stream. Advantage's net sales production
from Glacier during this period averaged approximately 48 mmcf/d
(8,000 boe/d). Glacier operating costs decreased from approximately
$8.75/boe ($1.45/mcf) to approximately $3.00/boe ($0.50/mcf) during
the quarter which has significantly improved the netbacks realized
for our Montney gas production. Operating costs at Glacier are
anticipated to further decrease through 2010 as additional start-up
costs were included in the second quarter of 2010.
- The Glacier gas plant is currently producing at its peak capacity
with several Montney wells constrained due to facility capacity and
several wells have yet to be brought on production that will replace
declines through the remainder of 2010.
- Since December 2009, twelve new operated Upper Montney horizontal
wells have been brought on-stream which have demonstrated an average
30 day IP rate of 5 mmcf/d per well. Three of these wells have
averaged over 8 mmcf/d with one well at 9.6 mmcf/d, despite facility
capacity constraints.
- Capital investment at Glacier during the second quarter of 2010 was
$15.0 million for a total of $74.2 million during the first six
months of 2010. Capital expenditures required to attain our 50 mmcf/d
target were lower than anticipated due to i) our successful drilling
program in 2009 and 2010 which demonstrated well productivities that
exceeded internal expectations and ii) reduced drilling and
completion costs.
Glacier Expansion to 100 mmcf/d (16,667 boe/d) On-Track
-------------------------------------------------------
- The expansion of our Glacier property to 100 mmcf/d is underway with
the deployment of 4 drilling rigs. To date, 6 net (6 gross) new
Montney horizontal wells have been drilled and are awaiting
completion out of our Phase III total program of 28 net (28 gross)
wells.
- A total of 4 net (4 gross) wells remaining from our first quarter of
2010 drilling program have been completed since spring break-up.
Results continue to be strong with test rates ranging from 5.9 to
11.2 mmcf/d and flowing pressures of 464 psig to 1,385 psig. A total
of 38 mmcf/d of new productive capability has already been tested
and is awaiting future tie-in. An additional 1 net (1 gross) well
from Phase II is awaiting completion at this time.
- Fabrication of a new processing train to facilitate expansion of our
Glacier gas plant to 100 mmcf/d has commenced and we are anticipating
equipment delivery to our plant site by year-end with construction to
begin in the first quarter of 2011. The targeted on-stream date for
our expanded Glacier plant is the second quarter of 2011.
Alberta Royalty Incentives Improves Montney Netbacks and Drilling
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Economics
---------
- 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 gas plays with very strong investment returns at Glacier
supported by low operating costs and a favorable royalty structure.
- The most significant impact at Glacier is the change to the Natural
Gas Deep Drilling Program ("NGDDP") in which the qualifying vertical
depth has been reduced to 2,000 metres (from 2,500 metres) and the
program has been made a permanent feature of the Alberta royalty
framework.
- As a result, all Montney horizontal wells drilled at Glacier after
May 1, 2010 will 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.
- These changes have substantially enhanced the future drilling
economics and the value of Montney drilling locations. Advantage
estimates that the drilling economics of our Montney resource at
Glacier generates a before-tax rate of return in excess of 15% at
natural gas prices of $3.00 Cdn per mcf. This is due to the
operating cost efficiencies provided by our 100% working interest
gas plant, the decreasing capital cost structure, the contiguous
nature of our extensive land block and the substantial economic
enhancement created by the recent changes to the Alberta Royalty
incentives.
Additional 'Stacked' Formations above the Montney Provides Future
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Potential
---------
- To date, Advantage has a total of 38 net (47 gross) horizontal wells
and 20 net (21 gross) vertical wells penetrating the Montney
formation at Glacier. All of these wellbores have provided valuable
uphole information in regard to conventional and resource formations
which are 'stacked' directly above the Montney over our extensive
Glacier land block. At this time, we have natural gas indications in
numerous wellbores which will be evaluated in the future through
either new wells or recompletions of existing wells in a staggered
pace to our Montney development. Future Montney drilling locations
will serve to further de-risk the geographical extent of these
additional stacked formations. No new reserves were included for any
of the potential formations located above the Montney in our year-end
2009 reserve report.
- Advantage's first Nikanassin horizontal well was drilled before
spring break-up. Completion operations were conducted recently;
however, mechanical difficulties encountered during the drilling and
completion did not allow for an optimal evaluation of the well. The
horizontal well confirmed the presence of natural gas and will be
further evaluated. A decision to re-attempt the completion, drill
another horizontal well or utilize an existing wellbore will be
determined later in the year. Advantage continues to be optimistic on
the resource potential of the Nikanassin and other formations which
are present over our extensive land block at Glacier.
Hedging Update
--------------
- Advantage's hedging program includes 59% of our net 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 net
production at an average price of Cdn$6.30 AECO per mcf.
- For 2010 we have hedged 34% of our net crude oil production at Cdn
$67.83 per bbl and for 2011 we have hedged 33% of our net crude oil
production at Cdn$88.90 per bbl.
- Additional details on our hedging program are available at our
website at www.advantageog.com.
Looking Forward
---------------
- Our current corporate strategy is to focus on the development of our
Montney natural gas resource play at Glacier, maintain financial
flexibility and optimize our cost structure and operating
efficiencies to deliver economic growth, particularly during lower
commodity price cycles as we are currently experiencing. The enhanced
financial flexibility resulting from the non-core asset dispositions
provides further support to our corporate strategy.
- Looking forward, Advantage is well positioned to deliver growth in
shareholder value. With a current inventory in excess of 500 Montney
drilling locations at Glacier and a growing inventory of
opportunities in our light oil and other natural gas assets,
Advantage is in an enviable position to provide economic growth.
- Our guidance for the twelve months ending June 2011 is as follows:
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Total
H2 2010 H1 2011 12 Months
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Production Average
(boe/d) 23,000 - 23,800 26,600 - 27,200 24,800 - 25,500
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Royalty Rate (%) 13% - 15% 13% - 15 % 13% - 15%
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Operating Costs
($/boe) $ 9.75 - $10.25 $8.50 - $9.00 $9.10 - $9.65
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Capital
Expenditures *
($ 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.
MANAGEMENT'S DISCUSSION & ANALYSIS
The following Management's Discussion and Analysis ("MD&A"), dated as of August 12, 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 six months ended June 30, 2010 and should be read in conjunction with the unaudited consolidated financial statements for the six months ended June 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 Six months ended
June 30 June 30
($000) 2010 2009 % change 2010 2009 % change
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Cash provided by
operating
activities $ 49,550 $ 38,956 27% $ 98,690 $ 80,835 22%
Expenditures on
asset retirement 469 1,045 (55)% 1,861 3,622 (49)%
Changes in
non-cash working
capital (4,414) 11,589 (138)% (4,606) 22,724 (120)%
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Funds from
operations $ 45,605 $ 51,590 (12)% $ 95,945 $107,181 (10)%
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Overview
Three months ended Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
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Cash provided by
operating
activities
($000) $ 49,550 $ 38,956 27% $ 98,690 $ 80,835 22%
Funds from
operations
($000) $ 45,605 $ 51,590 (12)% $ 95,945 $107,181 (10)%
per share(1) $ 0.28 $ 0.35 (20)% $ 0.59 $ 0.73 (19)%
per boe $ 19.76 $ 18.26 8% $ 22.12 $ 19.21 15%
(1) Based on basic weighted average shares outstanding.
In July 2009 we closed two major asset dispositions for net proceeds of $243.2 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 six months ended June 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 have had a modest impact on this quarter and will be completely excluded from our financial and operating results for the third quarter of 2010.
Funds from operations per boe increased when compared to 2009 primarily due to stronger crude oil prices and a continued reduction in operating costs. Although crude oil prices improved and had a positive impact on revenues, natural gas prices were comparable to 2009 and remained low. Through our successful commodity price risk management program, we were able to realize significant gains on derivatives that helped to offset the continued weak natural gas prices and improved funds from operations. When comparing the current quarter to the first quarter of 2010, our funds from operations per boe decreased 20% to $19.76/boe from $24.83/boe as commodity prices significantly decreased during this quarter. 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 increased relative to 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 Six months ended
June 30 June 30
($000) 2010 2009 % change 2010 2009 % change
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Natural gas
excluding
hedging $ 37,349 $ 40,482 (8)% $ 78,659 $ 97,342 (19)%
Realized hedging
gains 17,435 23,516 (26)% 30,101 35,902 (16)%
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Natural gas
including
hedging $ 54,784 $ 63,998 (14)% $108,760 $133,244 (18)%
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Crude oil and NGLs
excluding
hedging $ 43,516 $ 51,939 (16)% $ 91,766 $ 94,683 (3)%
Realized hedging
gains (losses) (1,923) (1,278) 50% (5,372) 9,682 (155)%
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Crude oil and NGLs
including
hedging $ 41,593 $ 50,661 (18)% $ 86,394 $104,365 (17)%
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Total revenue(1) $ 96,377 $114,659 (16)% $195,154 $237,609 (18)%
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(1) Total revenue excludes unrealized derivative gains and losses.
Natural gas, crude oil and NGL revenues, excluding hedging, were negatively impacted for the three and six months ended June 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. Natural gas prices, excluding hedging, for the three months ended June 30, 2010 were modestly higher as compared to the same period of 2009 while for the six months ended June 30, 2010 they were comparable to the prior year. Natural gas prices have been relatively weak for the last two years due to many factors including the poor global economy that has generally reduced demand, higher North American natural gas production, and mild weather conditions that have increased natural gas inventory. Crude oil and NGL prices, excluding hedging, have been higher for 2010 as compared to 2009 which has partially offset reduced revenues from the overall lower production. Given the relatively lower natural gas price environment, our commodity price risk management program has delivered realized natural gas hedging gains of $17.4 million and $30.1 million for the three and six months ended June 30, 2010, respectively. As crude oil prices have increased, we have realized crude oil hedging losses of $1.9 million and $5.4 million for the three and six months ended June 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 revenues. 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 Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
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Natural gas
(mcf/d) 107,821 124,990 (14)% 97,640 121,498 (20)%
Crude oil (bbls/d) 5,231 7,989 (35)% 5,370 8,331 (36)%
NGLs (bbls/d) 2,164 2,223 (3)% 2,313 2,244 3%
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Total (boe/d) 25,365 31,044 (18)% 23,956 30,825 (22)%
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Natural gas (%) 71% 67% 68% 66%
Crude oil (%) 21% 26% 22% 27%
NGLs (%) 8% 7% 10% 7%
Production was lower for 2010 as compared to 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 had a modest impact on this quarter and will be completely excluded from our financial and operating results for the third quarter of 2010. The lower average daily production was partially offset by production increases at Glacier, whereby our corporate average daily production of 25,365 boe/d for the second quarter of 2010 increased 13% above the 22,533 boe/d produced during the first quarter of 2010. On April 19, 2010 we announced that our new 100% working interest gas plant at Glacier ("Glacier gas plant") was brought on-stream ahead of schedule with production rates exceeding 50 mmcf/d (8,300 boe/d). This milestone represents another key step in the development of our significant Montney reserves and resource potential at Glacier. As a result of completing construction early, we were able to start commissioning the plant in March which resulted in production outages during that month to facilitate the tie-in of the gas plant and new pipelines.
We have now commenced Phase III of our Glacier development project which is targeting to increase production to 100 mmcf/d (16,667 boe/d) by the second quarter of 2011 and includes an active drilling program during the remainder of 2010 and into 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 production to average approximately 23,000 to 23,800 boe/d for the second half of 2010.
Commodity Prices and Marketing
Natural Gas
Three months ended Six months ended
June 30 June 30
($/mcf) 2010 2009 % change 2010 2009 % change
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Realized natural
gas prices
Excluding
hedging $ 3.81 $ 3.56 7% $ 4.45 $ 4.43 -%
Including
hedging $ 5.58 $ 5.63 (1)% $ 6.15 $ 6.06 1%
AECO monthly
index $ 3.86 $ 3.66 5% $ 4.60 $ 4.64 (1)%
Realized natural gas prices, excluding hedging, were 7% higher for the three months ended June 30, 2010 and comparable for the six months ended June 30, 2010 as compared to the same periods of 2009. However, our realized natural gas prices, excluding hedging, for this quarter decreased 28% from the first 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. This has significantly mitigated the negative impact from lower natural gas prices and has protected our cash flows and resulting capital expenditure program.
During 2009 and 2010, natural gas prices have remained low from continued high US domestic natural gas production, mild weather conditions, and the ongoing poor 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 have significantly weakened again and AECO gas is presently trading at approximately $3.43/mcf. Although we continue to believe in the longer-term pricing fundamentals for natural gas, we are concerned about the strength and timing of the North American economic recovery which is linked to industrial demand for natural gas. We continue to monitor these market developments closely and will be proactive in implementing an appropriate hedging strategy to mitigate the volatility in our cash flow as a result of fluctuations in natural gas prices.
Crude Oil and NGL
Three months ended Six months ended
June 30 June 30
($/bbl) 2010 2009 % change 2010 2009 % change
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Realized crude
oil prices
Excluding
hedging $ 70.54 $ 61.13 15% $ 72.80 $ 52.74 38%
Including
hedging $ 66.50 $ 59.37 12% $ 67.27 $ 59.17 14%
Realized NGLs
prices
Excluding
hedging $ 50.45 $ 37.06 36% $ 50.17 $ 37.30 35%
Realized crude oil
and NGL prices
Excluding
hedging $ 64.66 $ 55.89 16% $ 65.98 $ 49.47 33%
Including
hedging $ 61.80 $ 54.51 13% $ 62.12 $ 54.53 14%
WTI ($US/bbl) $ 77.98 $ 59.62 31% $ 78.38 $ 51.46 52%
$US/$Canadian
exchange rate $ 0.97 $ 0.86 13% $ 0.97 $ 0.83 17%
Realized crude oil and NGL prices, excluding hedging, increased 16% and 33% for the three and six months ended June 30, 2010, as compared to the same periods of 2009. As compared to the first quarter of 2010, realized crude oil and NGL prices, excluding hedging, have decreased 4% for the second 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$76/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
July to September 2010 47% Cdn$7.27/mcf
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
July to September 2010 37% Cdn$69.50/bbl
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 royalty payments.
For the six months ended June 30, 2010, we recognized in income a net realized derivative gain of $24.7 million (June 30, 2009 - $45.6 million net realized derivative gain) on settled derivative contracts as a result of average market prices decreasing below our established average hedge prices. As at June 30, 2010, the fair value of the derivative contracts outstanding and to be settled was a net asset of approximately $33.0 million, an increase of $15.8 million from the $17.2 million net asset recognized as at December 31, 2009. For the six months ended June 30, 2010, this $15.8 million increase was recognized in income as an unrealized derivative gain (June 30, 2009 - $0.2 million unrealized derivative loss). The valuation of the derivatives is the estimated fair value to settle the contracts as at June 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 Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Royalties ($000) $ 12,197 $ 12,791 (5)% $ 25,055 $ 28,871 (13)%
per boe $ 5.28 $ 4.53 17% $ 5.78 $ 5.17 12%
As a percentage
of revenue,
excluding hedging 15.1% 13.8% 1.3% 14.7% 15.0% (0.3)%
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 decreased for the three and six months ended June 30, 2010 compared to the same periods of 2009 due to lower revenue from reduced production attributable to our asset dispositions. Royalties as a percentage of revenue, excluding hedging, increased modestly for the quarter as compared to the same period of 2009 due to an annual adjustment related to 2009 GCA. However, royalties as a percentage of revenue, excluding hedging, have generally decreased due to the nature of our capital development activities at Glacier that result in natural gas production at lower royalty rates.
Our average corporate royalty rates are significantly impacted by the Alberta Provincial Government's royalty framework that was effective January 1, 2009 for conventional oil, natural gas and oil sands whereby Alberta royalties are now 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. The reduced 5% royalty rate program became a permanent incentive based on the Alberta Government's announcement of March 11, 2010 which will significantly benefit our Glacier development program for wells drilled after March 31, 2011.
On May 27, 2010 the Alberta Government announced 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 Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Operating costs
($000) $ 24,560 $ 35,030 (30)% $ 47,276 $ 71,061 (33)%
per boe $ 10.64 $ 12.40 (14)% $ 10.90 $ 12.74 (14)%
Total operating costs and operating costs per boe decreased for the three and six months ended June 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 during the second quarter of 2010 offset by some additional workover and maintenance costs incurred during the period. 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 was 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 when production reaches 100 mmcf/d to a target of approximately $1.75/boe. 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 Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
General and
administrative
Cash expense
($000) $ 7,247 $ 7,456 (3)% $ 12,691 $ 13,539 (6)%
per boe $ 3.14 $ 2.64 19% $ 2.93 $ 2.43 21%
Non-cash expense
($000) $ 3,380 $ 392 762% $ 7,131 $ 1,689 322%
per boe $ 1.46 $ 0.14 943% $ 1.64 $ 0.30 447%
Employees at
June 30 129 158 (18)%
Cash general and administrative ("G&A") expense for the six months ended June 30, 2010 has decreased 6% as compared to the same period of 2009 partially due to cost savings and reduced staff levels attributable to the asset dispositions. However, as a result of lower production due to the asset dispositions, the cash G&A expense per boe actually increased.
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 six months ended June 30, 2010, we granted 1,758,928 restricted shares at an average grant price of $7.10 per restricted share and recognized $8.6 million of equity-based compensation expense, including a non-cash amount of $7.1 million, related to restricted shares granted to service providers. During the first six months of 2010 we issued 557,550 shares to service providers in accordance with the vesting provisions of the Plan. As at June 30, 2010, 3,138,125 restricted shares remain unvested and will vest to service providers over the next three years with a total of $11.9 million in compensation cost to be recognized over the future service periods.
Management Internalization
Three months ended Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Management
internalization
($000) $ - $ 760 (100)% $ - $ 1,724 (100)%
per boe $ - $ 0.27 (100)% $ - $ 0.31 (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 Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Interest expense
($000) $ 3,043 $ 3,439 (12)% $ 6,805 $ 8,355 (19)%
per boe $ 1.32 $ 1.22 8% $ 1.57 $ 1.50 5%
Average effective
interest rate 4.5% 2.2% 2.3% 5.2% 2.8% 2.4%
Bank indebtedness
at June 30 ($000) $273,529 $644,100 (58)%
Total interest expense has decreased for both the three and six months ended June 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 is now higher; however, this has been significantly offset by lower interest expense on the reduced bank indebtedness that resulted from the third quarter 2009 asset dispositions and equity financing and the December 2009 5.0% convertible debenture issuance. Our revolving credit facility was again 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 5.2% for the six months ended June 30, 2010.
Interest and Accretion on Convertible Debentures
Three months ended Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Interest on
convertible
debentures
($000) $ 3,451 $ 4,009 (14)% $ 6,835 $ 7,978 (14)%
per boe $ 1.50 $ 1.42 6% $ 1.58 $ 1.43 10%
Accretion on
convertible
debentures
($000) $ 1,116 $ 681 64% $ 2,220 $ 1,363 63%
per boe $ 0.48 $ 0.24 100% $ 0.51 $ 0.24 113%
Convertible
debentures
maturity value at
June 30 ($000) $148,544 $184,489 (19)%
Interest on convertible debentures for the three and six months ended June 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, and the 7.50% debentures on October 1, 2009. 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 six months ended June 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. Interest and accretion expense will decrease in future periods as the 6.50% debentures matured on June 30, 2010.
Depletion, Depreciation and Accretion
Three months ended Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Depletion,
depreciation and
accretion ($000) $ 58,875 $ 72,177 (18)% $110,896 $142,099 (22)%
per boe $ 25.51 $ 25.55 -% $ 25.57 $ 25.47 -%
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 six months ended June 30, 2010 compared to 2009 due to lower production resulting from the asset dispositions that closed in the third quarter of 2009 and the second quarter of 2010. However, our DD&A per boe has remained comparable between 2010 and 2009.
Taxes
Current taxes paid or payable for the six months ended June 30, 2010 amounted to $0.6 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 within the province of Saskatchewan.
Future income taxes arise from differences between the accounting and tax bases of the assets and liabilities. For the six months ended June 30, 2010, the Corporation recognized a total future income tax expense of $0.6 million compared to a future income tax reduction of $21.0 million for the same period of 2009. Included in the 2009 future income tax reduction was $8.9 million related to a Government of Canada enacted rate reduction related to the Specified Investment Flow-Through Entity tax legislation that was applicable to the Fund at that time. As at June 30, 2010, the Corporation had a total future income tax liability balance of $44.1 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 Six months ended
June 30 June 30
2010 2009 % change 2010 2009 % change
-------------------------------------------------------------------------
Net loss ($000) $(22,279) $(37,810) (41)% $ (9,124) $(18,920) (52)%
per share -
basic and
diluted $ (0.14) $ (0.26) (46)% $ (0.06) $ (0.13) (54)%
Net loss and net loss per share for the three and six months ended June 30, 2010 have decreased as compared to the same periods of 2009. With the asset dispositions that closed in the third quarter of 2009 and the second quarter of 2010, total revenues and expenses are generally reduced as compared to the prior year. However, our major challenge continues to be the natural gas price environment that has adversely impacted revenues and 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 $24.7 million for the six months ended June 30, 2010. As a result of the commodity price environment, we also recognized a non-cash unrealized derivative gain of $15.8 million for the six months ended June 30, 2010 relating to the valuation of commodity hedging contracts outstanding as at June 30, 2010 that will not settle until 2010 and 2011. 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.
Cash Netbacks
Three months ended
June 30
2010 2009
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $ 80,865 $ 35.03 $ 92,421 $ 32.72
Realized gain on derivatives 15,512 6.72 22,238 7.87
Royalties (12,197) (5.28) (12,791) (4.53)
Operating costs (24,560) (10.64) (35,030) (12.40)
-------------------------------------------------------------------------
Operating $ 59,620 $ 25.83 $ 66,838 $ 23.66
General and administrative(1) (7,247) (3.14) (7,456) (2.64)
Interest(2) (2,989) (1.29) (3,439) (1.22)
Interest on convertible
debentures(2) (3,451) (1.50) (4,009) (1.42)
Income and capital taxes (328) (0.14) (344) (0.12)
-------------------------------------------------------------------------
Funds from operations and
cash netbacks $ 45,605 $ 19.76 $ 51,590 $ 18.26
-------------------------------------------------------------------------
Six months ended
June 30
2010 2009
$000 per boe $000 per boe
-------------------------------------------------------------------------
Revenue $170,425 $ 39.30 $192,025 $ 34.42
Realized gain on derivatives 24,729 5.70 45,584 8.17
Royalties (25,055) (5.78) (28,871) (5.17)
Operating costs (47,276) (10.90) (71,061) (12.74)
-------------------------------------------------------------------------
Operating $122,823 $ 28.32 $137,677 $ 24.68
General and administrative(1) (12,691) (2.93) (13,539) (2.43)
Interest(2) (6,693) (1.54) (8,355) (1.50)
Interest on convertible
debentures(2) (6,835) (1.58) (7,978) (1.43)
Income and capital taxes (659) (0.15) (624) (0.11)
-------------------------------------------------------------------------
Funds from operations and
cash netbacks $ 95,945 $ 22.12 $107,181 $ 19.21
-------------------------------------------------------------------------
(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 six months ended June 30, 2010 compared to the same periods of 2009 primarily due to our dispositions completed in the third quarter of 2009 and the second quarter of 2010 that generally impact all revenues and expenses. However, funds from operations per boe increased when compared to 2009 primarily due to stronger crude oil prices. Although crude oil prices improved and had a positive impact on revenues, natural gas prices were comparable to 2009 and remained low. As a result of our successful commodity price risk management program, we were able to realize significant gains on derivatives that helped to offset the continued weak natural gas prices. Royalties per boe increased slightly resulting from a 2009 GCA adjustment which typically occurs at this time of the year. Operating costs per boe have 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. When comparing the current quarter to the first quarter of 2010, our funds from operations per boe decreased 20% to $19.76 per boe from $24.83 per boe as natural gas prices significantly decreased this quarter.
Contractual Obligations and Commitments
The Corporation has contractual obligations in the normal course of operations including purchases of assets and services, operating agreements, transportation commitments, sales contracts, bank indebtedness and convertible debentures. These obligations are of a recurring and consistent nature and impact cash flow in an ongoing manner. The following table is a summary of the Corporation's remaining contractual obligations and commitments. Advantage has no guarantees or off-balance sheet arrangements other than as disclosed.
Payments due by period
($ millions) Total 2010 2011 2012 2013 2014 2015
-------------------------------------------------------------------------
Building leases $ 4.5 $ 1.9 $ 1.5 $ 1.1 $ - $ - $ -
Pipeline/
transportation 26.7 2.4 6.7 6.6 6.3 4.7 -
Capital lease
obligations 1.4 0.7 0.7 - - - -
Bank
indebtedness(1) 273.5 - - 273.5 - - -
Convertible
debentures(2) 148.5 - 62.3 - - - 86.2
-------------------------------------------------------------------------
Total contractual
obligations $454.6 $ 5.0 $ 71.2 $281.2 $ 6.3 $ 4.7 $ 86.2
-------------------------------------------------------------------------
(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 June 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) June 30, 2010
-------------------------------------------------------------------------
Bank indebtedness (long-term) $ 273,529
Working capital deficit(1) 20,831
-------------------------------------------------------------------------
Net debt $ 294,360
-------------------------------------------------------------------------
Shares outstanding 163,303,078
Shares closing market price ($/share) $ 6.20
-------------------------------------------------------------------------
Shares outstanding market value $ 1,012,479
-------------------------------------------------------------------------
Convertible debentures maturity value (long-term) $ 148,544
-------------------------------------------------------------------------
Total capitalization $ 1,455,383
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 (excluding derivative assets and liabilities), 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 June 30, 2010 was $273.5 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 from mild weather. Natural gas has dropped with AECO gas presently trading at approximately $3.43/mcf. Crude oil has improved since early 2009 and is relatively more stable with WTI at approximately US$76/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 June 30, 2010, the Corporation had 163.3 million shares outstanding. During 2010 we have issued 557,550 shares to employees in accordance with the vesting provisions of the RSPIP. As at August 12, 2010, shares outstanding have increased to 163.5 million.
The Corporation had $148.5 million convertible debentures outstanding at June 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 six months ended June 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 August 12, 2010, the convertible debentures outstanding have not changed from June 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 June 30, 2010, Advantage had bank indebtedness outstanding of $273.5 million. Bank indebtedness increased $23.3 million since December 31, 2009, primarily the result of our significant capital expenditure program during this period. However, we have successfully reduced our bank indebtedness by $370.6 million or 58% since June 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 $20.8 million as at June 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 decreased significantly during the second quarter of 2010 as the 6.50% convertible debentures previously included in the working capital deficiency, matured on June 30, 2010 and was settled with $69.9 million in cash. 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 capital lease obligations on various equipment used in its operations. The total amount of principal obligations outstanding at June 30, 2010 is $1.4 million, bearing interest at effective rates ranging from 5.8% to 6.7%, and is collateralized by the related equipment. The leases expire in 2010 and 2011.
Capital Expenditures
Three months ended Six months ended
June 30 June 30
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Land and seismic $ 81 $ 40 $ 2,165 $ 1,707
Drilling, completions and
workovers 9,933 4,526 63,002 42,138
Well equipping and
facilities 9,436 11,082 23,448 24,379
Other 99 71 284 138
-------------------------------------------------------------------------
$ 19,549 $ 15,719 $ 88,899 $ 68,362
Property dispositions (66,068) (860) (70,482) (1,619)
-------------------------------------------------------------------------
Net capital expenditures $ (46,519) $ 14,859 $ 18,417 $ 66,743
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 six months ended June 30, 2010, the Corporation spent a net $88.9 million and drilled a total of 20.0 net (25 gross) wells at a 100% success rate. Total capital spending included $74.2 million at Glacier, $3.7 million at Sunset, $2.5 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. Costs to complete Phase II were lower than anticipated due to i) our successful drilling program in 2009 and the first quarter of 2010 which demonstrated well productivities that exceeded internal expectations and ii) reduced drilling and completion costs. Construction of our new facilities and gas gathering system expansions were completed ahead of schedule and on-budget leading to an earlier than anticipated commissioning of Advantage's new 100% working interest gas plant which began in March 2010. The new Glacier gas plant is now operating at its peak capacity with throughput rates between 50 and 55 mmcf/d from a total of 27 net (36 gross) Montney wells on production. Additional Phase II wells will be brought on-production in the future to maintain our facilities at capacity prior to the Phase III expansion. The amount of excess field production capability above our current plant capacity is a result of our successful 2009 and first quarter 2010 drilling program which demonstrated well test rates that exceeded expectations and proved up a large portion of our undrilled acreage at Glacier. An additional 6 net (6 gross) wells from our Phase III program have been cased and are waiting on completion.
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.
Sources and Uses of Funds
The following table summarizes the various funding requirements during the six months ended June 30, 2010 and 2009 and the sources of funding to meet those requirements:
Six months ended
June 30
($000) 2010 2009
-------------------------------------------------------------------------
Sources of funds
Funds from operations $ 95,945 $ 107,181
Property dispositions 70,482 1,619
Increase in bank indebtedness 23,649 58,393
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 190,076 $ 167,193
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Uses of funds
Expenditures on fixed assets $ 88,899 $ 68,362
Convertible debenture maturities 69,927 29,839
Increase in working capital 28,698 41,123
Expenditures on asset retirement 1,861 3,622
Reduction of capital lease obligations 691 645
Distributions to Unitholders - 23,481
Trust Unit issue costs - 121
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 190,076 $ 167,193
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Corporation generated lower funds from operations during the six months ended June 30, 2010 compared to 2009, due to lower production due to the asset dispositions that closed in the third quarter of 2009 and the second quarter of 2010. However, funds from operations were positively impacted during 2010 from a continual improvement in crude oil prices, while natural gas prices remained weak. Bank indebtedness increased modestly as would be expected due to our capital expenditure program that was very active during the first half of 2010 with finalizing our Glacier drilling activity and completion of the Glacier gas plant. 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
($000, except
as otherwise 2010 2009
indicated) Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Daily production
Natural gas
(mcf/d) 107,821 87,346 84,466 91,200 124,990 117,968
Crude oil and
NGLs
(bbls/d) 7,395 7,975 8,488 8,431 10,212 10,942
Total
(boe/d) 25,365 22,533 22,566 23,631 31,044 30,603
Average prices
Natural gas
($/mcf)
Excluding
hedging $ 3.81 $ 5.26 $ 4.28 $ 2.89 $ 3.56 $ 5.36
Including
hedging $ 5.58 $ 6.87 $ 6.90 $ 6.10 $ 5.63 $ 6.52
AECO
monthly
index $ 3.86 $ 5.35 $ 4.18 $ 3.03 $ 3.66 $ 5.64
Crude oil
and NGLs
($/bbl)
Excluding
hedging $ 64.66 $ 67.23 $ 63.04 $ 56.99 $ 55.89 $ 43.41
Including
hedging $ 61.80 $ 62.42 $ 57.85 $ 54.02 $ 54.51 $ 54.54
WTI ($US/
bbl) $ 77.98 $ 78.79 $ 76.17 $ 68.29 $ 59.62 $ 43.21
Total revenues
(before
royalties) $ 96,377 $ 98,777 $ 98,782 $ 93,101 $114,659 $122,950
Net income
(loss) $(22,279) $ 13,155 $(14,213) $(53,293) $(37,810) $ 18,890
per share
- basic $ (0.14) $ 0.08 $ (0.09) $ (0.33) $ (0.26) $ 0.13
- diluted $ (0.14) $ 0.08 $ (0.09) $ (0.33) $ (0.26) $ 0.13
Funds from
operations $ 45,605 $ 50,340 $ 49,757 $ 42,104 $ 51,590 $ 55,591
Distributions
declared $ - $ - $ - $ - $ - $ 17,266
($000, except
as otherwise 2008
indicated) Q4 Q3
---------------------------------
Daily production
Natural gas
(mcf/d) 120,694 122,627
Crude oil and
NGLs
(bbls/d) 11,413 11,980
Total
(boe/d) 31,529 32,418
Average prices
Natural gas
($/mcf)
Excluding
hedging $ 7.15 $ 8.65
Including
hedging $ 7.61 $ 7.55
AECO
monthly
index $ 6.79 $ 9.27
Crude oil
and NGLs
($/bbl)
Excluding
hedging $ 53.65 $ 107.96
Including
hedging $ 61.67 $ 100.02
WTI ($US/
bbl) $ 58.75 $ 118.13
Total revenues
(before
royalties) $149,205 $195,384
Net income
(loss) $(95,477) $113,391
per share
- basic $ (0.67) $ 0.81
- diluted $ (0.67) $ 0.79
Funds from
operations $ 69,370 $ 93,345
Distributions
declared $ 45,514 $ 50,743
The table above highlights the Corporation's and Fund's performance for the second 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 will be experienced in the third quarter of 2010. Our financial results, particularly revenues and funds from operations, slightly declined in the third quarter of 2008, as commodity prices began to decline in response to the financial crisis that materialized in the fall of 2008. This trend worsened in the fourth quarter, as a full global recession set in, 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 quarter of 2010, commodity prices weakened again, particular natural gas, which decreased our revenues and funds from operations. The Corporation reported record high net income in the third quarter of 2008 as commodity price declines gave rise to significant unrealized gains on our derivative contracts. 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 quarter of 2010, particularly natural gas, resulting in a net loss during the quarter.
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, internal controls over financial reporting, taxes, information systems and processes. Management has engaged its key personnel responsible and developed an overall plan to address IFRS implementation.
The most significant change identified will be accounting for fixed assets. 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 calculation and impairment test. IFRS will require the Corporation to make a much more detailed assessment of its oil and gas assets. For depletion and depreciation, the Corporation must identify asset components, and determine an appropriate depreciation or depletion method for each component. With regard to impairment test calculations, we must identify "Cash Generating Units", which are defined as the smallest group of assets that produce independent cash flows. An impairment test must be performed individually for all cash generating units when indicators suggest there may be an impairment. The recognition of impairments in a prior year can be reversed subsequently depending on such calculations. It is also important to note that the International Accounting Standards Board ("IASB") is currently undertaking an extractive activities project, to develop accounting standards specifically for businesses like that of the Corporation. However, we anticipate that the project will not be complete prior to IFRS adoption in Canada. We have also identified a number of other areas whereby differences between Canadian GAAP and IFRS are likely to exist for Advantage. However, currently we are concentrating on the accounting for fixed assets and will evaluate these other areas in due course and develop more detailed plans to address the identified issues. Advantage's IFRS conversion project has been developed in three main phases:
Phase One: Scope and Plan
This phase consists of high level assessment to identify key areas of Canadian GAAP versus IFRS differences that would most likely impact the Company. This assessment was completed in early 2009.
Phase Two: Design and Build
This phase commenced in the third quarter of 2009 and involved the detail assessment, from an accounting, reporting and business perspective, of the changes that would be caused by the conversion to IFRS. Specific accounting processes and policy review included: exploration and evaluation costs, property, plant and equipment, depreciation and depletion, asset impairment, provisions and decommissioning liabilities, income tax, systems and financial statement preparation and disclosure. The deliverables for this phase include specific accounting policies for the above mentioned topics and also includes IFRS transitional choices. This phase is currently being finalized.
Phase Three: Implement and Review
This phase 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. Details surrounding the collection of comparative financial and other data in 2010 are also being finalized in this phase. This phase is currently underway and is expected to be completed by the end of 2010. During the third quarter of 2010, we anticipate the finalization of accounting policies with completion of the audit of our transitional balance sheet and external auditor review of our first quarter 2010 financial statements.
Education, training and communication of key financial employees, other staff and management, the Audit Committee and the Board will continue throughout the conversion project.
Accounting Policy Impacts and Decisions:
The Corporation is progressing through its assessment of impacts of adopting IFRS based on the standards as they currently exist, and have identified the following as having the greatest potential to impact 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 its accounting policies or transitional choices and as such is unable to quantify the impact on the financial statements of adopting IFRS.
a) Depreciation
IFRS and Canadian GAAP contain the same basic principles of accounting for property, plant and equipment; however, differences in application do exist. IAS 16 requires an allocation of the amount initially recognized as PP&E to each significant part and the depreciation of each part separately. This method of componentizing PP&E will result in an increased number of calculations of depreciation expense and may impact the amount of depreciation expense. IFRS allows the option of using either proved or proved and probable reserves in the depreciation calculation. Advantage has not concluded at this time which method it will use.
b) Impairment of Assets
Impairment of Assets IAS 36, uses a one-step approach for testing and measuring asset impairment, with asset carrying values being compared to the higher of value in use and fair value less cost to sell. The use of discounted cash flows under IFRS to test and measure asset impairment differs from Canadian GAAP where step one of a two-step approach, uses undiscounted cash flows. Under IFRS, impairment testing is carried out at an individual asset group level ("Cash Generating Unit") versus under Canadian GAAP which is generally at a country level. This will result in the possibility of more frequent write downs in the carrying value under IFRS. However, under IAS 36 previous impairment losses (except for goodwill) must be reversed where circumstances change such that the impairment has been reduced.
c) First Time Adoption of International Financial Reporting Standards IFRS 1
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. In July 2009, an amendment to IFRS 1 was issued that applies to oil and gas assets. The amendment 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 pro rata using reserve volumes or reserve values as of that date.
d) Information Systems
It is anticipated that the adoption of IFRS will have an impact on information systems requirements. We are currently assessing the need for system upgrades or modifications to ensure an efficient conversion to IFRS.
e) Financial Reporting
The adoption of IFRS will result in additional disclosure requirements in the financial statements. Draft IFRS financial statements are currently being prepared. The statements will be reviewed by our external auditors and approved by Management and the Board of Directors.
f) 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.
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 June 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 June 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 June 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 continued with our Phase II Montney development program at Glacier which involved drilling horizontal wells to build production inventory and delineate our land block. In addition, construction continued on Advantage's new 100% working interest gas plant and gathering system expansion. Construction was completed ahead of schedule and on-budget leading to an earlier than anticipated commissioning during March 2010.
Advantage's corporate capital budget for the twelve month period ending June 2011 is set at $219 million ($200 million net of drilling credits). Approximately 80% of the capital budget is allocated to Glacier for Phase III to further develop and delineate our extensive land base and expand processing capacity to 100 mmcf/d. 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.
Phase III of our Glacier development project which is targeted to increase production to 100 mmcf/d is now underway. All required regulatory approvals to upgrade the gas plant to target a production capability of 100 mmcf/d were received, plant equipment fabrication has begun, infrastructure expansion and pipeline work is in progress, and we have secured four rigs that are actively drilling. Currently 6 net (6 gross) additional Montney wells have been drilled in the third quarter of 2010 and are waiting upon completion with another 4 net (4 gross) wells currently being drilled. We anticipate that approximately 50% of our Phase III drilling program, consisting of 28 net (28 gross) wells, will be completed by the end of August 2010.
Our guidance for the twelve months ending June 2011 is as follows:
-------------------------------------------------------------------------
Total
H2 2010 H1 2011 12 Months
-------------------------------------------------------------------------
Production Average
(boe/d) 23,000 - 23,800 26,600 - 27,200 24,800 - 25,500
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.
August 12, 2010
Consolidated Financial Statements
Consolidated Balance Sheets June 30, December 31,
(thousands of dollars) 2010 2009
-------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Accounts receivable $ 43,267 $ 54,531
Prepaid expenses and deposits 6,069 9,936
Derivative asset (note 8) 30,684 30,829
-------------------------------------------------------------------------
80,020 95,296
Derivative asset (note 8) 7,140 323
Fixed assets (note 2) 1,733,370 1,831,622
-------------------------------------------------------------------------
$ 1,820,530 $ 1,927,241
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 68,724 $ 111,901
Current portion of capital lease obligations
(note 3) 1,443 1,375
Current portion of convertible debentures
(note 4) - 69,553
Derivative liability (note 8) 4,752 12,755
Future income taxes 6,767 4,704
-------------------------------------------------------------------------
81,686 200,288
Derivative liability (note 8) - 1,165
Capital lease obligations - 759
Bank indebtedness (note 5) 271,433 247,784
Convertible debentures (note 4) 132,504 130,658
Asset retirement obligations (note 6) 59,215 68,555
Future income taxes 37,283 38,796
Other liability 2,891 3,431
-------------------------------------------------------------------------
585,012 691,436
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Shareholders' Equity
Share capital (note 7) 2,194,145 2,190,409
Convertible debentures equity component
(note 4) 15,896 18,867
Contributed surplus (note 7) 15,347 7,275
Deficit (989,870) (980,746)
-------------------------------------------------------------------------
1,235,518 1,235,805
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 1,820,530 $ 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 Six months ended
except for per share June 30, June 30, June 30, June 30,
amounts) (unaudited) 2010 2009 2010 2009
-------------------------------------------------------------------------
Revenue
Petroleum and natural
gas $ 80,865 $ 92,421 $ 170,425 $ 192,025
Realized gain on
derivatives (note 8) 15,512 22,238 24,729 45,584
Unrealized gain (loss)
on derivatives (note 8) (10,271) (24,575) 15,840 (178)
Royalties (12,197) (12,791) (25,055) (28,871)
-------------------------------------------------------------------------
73,909 77,293 185,939 208,560
-------------------------------------------------------------------------
Expenses
Operating 24,560 35,030 47,276 71,061
General and
administrative 10,627 7,848 19,822 15,228
Management
internalization - 760 - 1,724
Interest 3,043 3,439 6,805 8,355
Interest and accretion
on convertible
debentures 4,567 4,690 9,055 9,341
Depletion, depreciation
and accretion 58,875 72,177 110,896 142,099
-------------------------------------------------------------------------
101,672 123,944 193,854 247,808
-------------------------------------------------------------------------
Loss before taxes (27,763) (46,651) (7,915) (39,248)
Future income tax
expense (reduction) (5,812) (9,185) 550 (20,952)
Income and capital taxes 328 344 659 624
-------------------------------------------------------------------------
(5,484) (8,841) 1,209 (20,328)
-------------------------------------------------------------------------
Net loss and
comprehensive loss (22,279) (37,810) (9,124) (18,920)
Deficit, beginning of
period (967,591) (875,430) (980,746) (877,054)
Distributions declared - - - (17,266)
-------------------------------------------------------------------------
Deficit, end of period $ (989,870) $ (913,240) $ (989,870) $ (913,240)
-------------------------------------------------------------------------
Net loss per share
(note 7)
Basic and diluted $ (0.14) $ (0.26) $ (0.06) $ (0.13)
-------------------------------------------------------------------------
see accompanying Notes to Consolidated Financial Statements
Consolidated Statements of Cash Flows
Three months ended Six months ended
(thousands of dollars) June 30, June 30, June 30, June 30,
(unaudited) 2010 2009 2010 2009
-------------------------------------------------------------------------
Operating Activities
Net loss $ (22,279) $ (37,810) $ (9,124) $ (18,920)
Add (deduct) items not
requiring cash:
Unrealized loss (gain)
on derivatives 10,271 24,575 (15,840) 178
Equity-based
compensation (note 7) 3,380 392 7,131 1,689
Management internalization - 760 - 1,724
Accretion on other
liability 54 - 112 -
Accretion on convertible
debentures 1,116 681 2,220 1,363
Depletion, depreciation
and accretion 58,875 72,177 110,896 142,099
Future income tax
expense (reduction) (5,812) (9,185) 550 (20,952)
Expenditures on asset
retirement (469) (1,045) (1,861) (3,622)
Changes in non-cash
working capital 4,414 (11,589) 4,606 (22,724)
-------------------------------------------------------------------------
Cash provided by
operating activities 49,550 38,956 98,690 80,835
-------------------------------------------------------------------------
Financing Activities
Units issued, less costs - (121) - (121)
Convertible debenture
maturities (note 4) (69,927) (29,839) (69,927) (29,839)
Increase in bank
indebtedness 15,751 31,102 23,649 58,393
Reduction of capital
lease obligations (136) (325) (691) (645)
Distributions to
Unitholders - - - (23,481)
Changes in non-cash
working capital - - (310) -
-------------------------------------------------------------------------
Cash provided by (used
by) financing activities (54,312) 817 (47,279) 4,307
-------------------------------------------------------------------------
Investing Activities
Expenditures on fixed
assets (19,549) (15,719) (88,899) (68,362)
Property dispositions 66,068 860 70,482 1,619
Changes in non-cash
working capital (41,757) (24,914) (32,994) (18,399)
-------------------------------------------------------------------------
Cash provided by (used
in) investing activities 4,762 (39,773) (51,411) (85,142)
-------------------------------------------------------------------------
Net change in cash - - - -
Cash, beginning of period - - - -
-------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-------------------------------------------------------------------------
Supplementary Cash Flow
Information
Interest paid $ 7,204 $ 6,793 $ 10,117 $ 15,040
Taxes paid $ 300 $ 235 $ 600 $ 610
see accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 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.
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 six month periods ended June 30,
2009 are those of the Fund. Advantage does not currently pay a
dividend.
2. Fixed Assets
Accumulated
Depletion and Net Book
June 30, 2010 Cost Depreciation Value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 3,228,726 $ 1,498,575 $ 1,730,151
Furniture and equipment 12,067 8,848 3,219
---------------------------------------------------------------------
$ 3,240,793 $ 1,507,423 $ 1,733,370
---------------------------------------------------------------------
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 June 30, 2010 consist of the
following:
2010 $ 713
2011 779
-----------------------------------------
1,492
Less amounts representing
interest (49)
-----------------------------------------
Current portion $ 1,443
-----------------------------------------
4. Convertible Debentures
The balance of debentures outstanding at June 30, 2010 and changes in
the liability and equity components during the six months ended
June 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 374 307
Matured (69,927) -
-------------------------------------------------------
Balance at June 30, 2010 $ - $ 45,881
-------------------------------------------------------
Equity component:
Balance at December 31,
2009 $ 2,971 $ 2,286
Expired (2,971) -
-------------------------------------------------------
Balance at June 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 74 1,465 2,220
Matured - - (69,927)
---------------------------------------------------------------------
Balance at June 30, 2010 $ 15,301 $ 71,322 $ 132,504
---------------------------------------------------------------------
Equity component:
Balance at December 31,
2009 $ 798 $ 12,812 $ 18,867
Expired - - (2,971)
---------------------------------------------------------------------
Balance at June 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 six
months ended June 30, 2010.
5. Bank Indebtedness
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Revolving credit facility $ 273,529 $ 250,262
Discount on Bankers Acceptances and
other fees (2,096) (2,478)
---------------------------------------------------------------------
Balance, end of period $ 271,433 $ 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 June 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 six months ended June 30,
2010, the average effective interest rate on the outstanding amounts
under the facility was approximately 5.2% (June 30, 2009 - 2.8%).
Advantage also has issued letters of credit totaling $9.6 million at
June 30, 2010 (December 31, 2009 - $1.3 million).
6. Asset Retirement Obligations
A reconciliation of the asset retirement obligations is provided
below:
Six months
ended Year ended
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 68,555 $ 73,852
Accretion expense 2,421 5,297
Liabilities incurred 480 699
Change in estimates 3,372 16,419
Property dispositions (13,752) (22,275)
Liabilities settled (1,861) (5,437)
---------------------------------------------------------------------
Balance, end of period $ 59,215 $ 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 557,550 3,736
---------------------------------------------------------------------
Balance at June 30, 2010 163,303,078 $ 2,194,145
---------------------------------------------------------------------
(b) Contributed surplus
The changes in contributed surplus during the six months ended
June 30, 2010 and the year ended December 31, 2009 are as follows:
Six months
ended Year ended
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 7,275 $ 287
Equity-based compensation 5,101 3,640
Expiration of convertible debentures
equity component (note 4) 2,971 3,348
---------------------------------------------------------------------
Balance, end of period $ 15,347 $ 7,275
---------------------------------------------------------------------
The components of contributed surplus are as follows:
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Expired convertible debentures equity
component $ 6,606 $ 3,635
Equity-based compensation 8,741 3,640
---------------------------------------------------------------------
Balance, end of period $ 15,347 $ 7,275
---------------------------------------------------------------------
(c) Equity-based compensation
Total equity-based compensation expense recorded during the six
months ended June 30, 2010 was $8.6 million, including non-cash
general and administrative expense of $7.1 million. During the six
months ended June 30, 2010, 557,550 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 June 30, 2010 are as follows:
Weighted
average
Restricted Restricted Restricted Restricted fair
Shares Shares Shares Shares value at
Date Granted Granted Vested Forfeited Outstanding grant date
-------------------------------------------------------------------------
January 15,
2009 691,178 487,254 21,560 182,364 $5.49
September 2,
2009 1,453,609 386,990 8,164 1,058,455 $5.80
October 15,
2009 1,153,314 401,117 5,765 746,432 $7.51
January 12,
2010 779,013 268,100 3,901 507,012 $7.27
April 12,
2010 979,915 331,163 4,890 643,862 $6.97
-------------------------------------------------------------------------
Total 5,057,029 1,874,624 44,280 3,138,125 $6.60
-------------------------------------------------------------------------
In July 2010, an RSPIP grant was made to service providers valued at
$6.53 per share or $5.1 million and to be issued in shares, subject
to vesting provisions. No compensation expense was included in
general and administrative expense as this grant occurred after
June 30, 2010.
(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 Six months ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
---------------------------------------------------------------------
Net loss
Basic and
diluted $ (22,279) $ (37,810) $ (9,124) $ (18,920)
---------------------------------------------------------------------
Weighted
average shares
outstanding
Basic and
diluted 163,264,029 144,681,321 163,143,038 144,189,031
---------------------------------------------------------------------
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 six months ended June 30, 2010 were
15,790,596 and 15,805,904 shares (three and six months ended June 30,
2009 - 9,224,648 and 9,279,871 shares, respectively). As at June 30,
2010, the total convertible debentures outstanding were immediately
convertible to 13,019,819 shares (June 30, 2009 - 8,373,448 shares).
Restricted shares granted have been excluded from the calculation of
diluted net loss per share for the three and six months ended
June 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 six months ended June 30, 2010 were 1,061,210 and
929,821 respectively (three and six months ended June 30, 2009 -
89,475 and 52,645, 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 There-
one year years years after Total
---------------------------------------------------------------------
Accounts payable
and accrued
liabilities $ 68,724 $ - $ - $ - $ 68,724
Capital lease
obligations 1,443 - - - 1,443
Derivative
liabilities 4,752 - - - 4,752
Bank indebtedness
- principal - 273,529 - - 273,529
- interest 11,388 11,138 - - 22,526
Convertible
debentures
- principal - 62,294 86,250 - 148,544
- interest 9,563 11,058 8,625 - 29,246
---------------------------------------------------------------------
$ 95,870 $ 358,019 $ 94,875 $ - $ 548,764
---------------------------------------------------------------------
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 June 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 18,956 mcf/d Cdn$7.29/mcf
December 2010
Fixed price April 2010 to 18,956 mcf/d Cdn$7.25/mcf
January 2011
Fixed price January 2011 to 9,478 mcf/d Cdn$6.24/mcf
December 2011
Fixed price January 2011 to 9,478 mcf/d Cdn$6.24/mcf
December 2011
Fixed price January 2011 to 9,478 mcf/d Cdn$6.26/mcf
December 2011
Crude oil - WTI
Fixed price April 2010 to 2,000 bbls/d Cdn$69.50/bbl
January 2011
Fixed price January 2011 to 1,500 bbls/d Cdn$91.05/bbl
December 2011
Electricity - Alberta Pool Price
Fixed price January 2010 to 2.0 MW Cdn$54.46/MWh
December 2010
As at June 30, 2010, the fair value of the derivatives outstanding
resulted in an asset of approximately $37.8 million (December 31,
2009 - $31.1 million) and a liability of approximately $4.8 million
(December 31, 2009 - $13.9 million). For the six months ended
June 30, 2010, $15.8 million was recognized in net loss as an
unrealized derivative gain (June 30, 2009 - $0.2 million unrealized
derivative loss) and $24.7 million was recognized in net loss as a
realized derivative gain (June 30, 2009 - $45.6 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 $2.9 million is recognized in
other liabilities:
2010 $ 4,300
2011 8,173
2012 7,709
2013 6,320
2014 4,710
---------------------------------
$ 31,212
---------------------------------
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