ARC Energy Trust announces third quarter 2009 results
Nov 5, 2009
<<
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
-------------------------------------------------------------------------
FINANCIAL
(Cdn$ millions, except per
unit and per boe amounts)
Revenue before royalties 239.2 485.7 699.6 1,405.6
Per unit(1) 1.01 2.24 2.98 6.53
Per boe 41.39 82.06 40.12 78.84
Cash flow from operating
activities(2) 125.6 251.4 354.2 734.8
Per unit(1) 0.53 1.16 1.51 3.41
Per boe 21.73 42.48 20.31 41.22
Net income 68.9 311.7 157.3 450.3
Per unit(3) 0.29 1.46 0.68 2.12
Distributions 70.6 171.3 227.6 442.8
Per unit(1) 0.30 0.80 0.98 2.08
Per cent of cash flow
from operating
activities(2) 56 68 64 60
Net debt outstanding(4) 705.4 773.2 705.4 773.2
OPERATING
Production
Crude oil (bbl/d) 26,921 28,509 27,541 28,372
Natural gas (mmcf/d) 193.1 192.0 195.7 197.0
Natural gas liquids (bbl/d) 3,717 3,822 3,720 3,862
Total (boe/d) 62,824 64,325 63,881 65,063
Average prices
Crude oil ($/bbl) 67.74 114.2 58.77 107.20
Natural gas ($/mcf) 3.25 8.68 4.05 8.94
Natural gas liquids ($/bbl) 38.92 82.87 38.89 77.92
Oil equivalent ($/boe) 41.31 81.42 40.00 78.44
Operating netback ($/boe)
Commodity and other
revenue (before
hedging)(5) 41.39 82.06 40.11 78.84
Transportation costs (0.83) (0.80) (0.88) (0.77)
Royalties (6.53) (15.00) (5.86) (14.18)
Operating costs (9.68) (10.19) (10.28) (10.14)
Netback (before hedging) 24.35 56.07 23.09 53.75
-------------------------------------------------------------------------
TRUST UNITS
(millions)
Units outstanding, end of
period(6) 238.1 217.4 238.1 217.4
Weighted average trust
units(7) 237.7 216.6 234.5 215.2
-------------------------------------------------------------------------
TRUST UNIT TRADING STATISTICS
(Cdn$, except volumes) based
on intra-day trading
High 20.20 33.30 20.90 33.95
Low 15.48 22.33 11.73 20.00
Close 20.20 23.10 20.20 23.10
Average daily volume
(thousands) 1,038 841 1,088 790
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares. Per unit distributions are based on
the number of trust units outstanding at each distribution record
date.
(2) Cash flow from operating activities is a GAAP measure. Historically,
Management has disclosed Cash Flow as a non-GAAP measure calculated
using cash flow from operating activities less the change in non-cash
working capital and the expenditures on site restoration and
reclamation as they appear on the Consolidated Statements of Cash
Flows. Cash Flow for the third quarter of 2009 would be
$124.8 million ($0.52 per unit) and $361.9 million ($1.54 per unit)
year-to-date. Distributions as a percentage of Cash Flow would be 57
per cent for the third quarter of 2009 (63 per cent year-to-date).
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Includes other revenue.
(6) For the third quarter of 2009, includes 0.9 million (1.1 million in
2008) exchangeable shares exchangeable into 2.679 trust units (2.431
in 2008) each for an aggregate 2.5 million (2.7 million in 2008)
trust units.
(7) Includes trust units issuable for outstanding exchangeable shares at
period end.
ACCOMPLISHMENTS/FINANCIAL UPDATE
--------------------------------
- Production volumes for the quarter were 62,824 boe per day, a decline
of two per cent compared to the second quarter. The Trust continues
to expect full year average production between 63,000 and 64,000 boe
per day.
- Operating costs decreased to $9.68 per boe in the quarter compared to
$10.19 per boe in the third quarter of 2008. Total operating costs
decreased $4.3 million, or seven per cent in the third quarter of
2009 as compared to the third quarter of 2008. The decrease in costs
is primarily attributed to lower power costs in 2009 as well as cost
savings and efficiencies achieved by the operations team. The Trust
estimates that full year 2009 operating costs will be approximately
$243 million or approximately $10.50 per boe based on annual
production of between 63,000 and 64,000 boe per day.
- Cash flow from operating activities was $125.6 million, or $0.53 per
unit, a significant decline from the $251.4 million ($1.16 per unit)
achieved in the comparable quarter in 2008. This decline was due to a
49 per cent decrease in commodity prices in the third quarter of 2009
compared to the same period in 2008. Crude oil prices strengthened
during the third quarter compared to the first half of 2009 as the
economy showed some positive signs of recovery. Natural gas prices
continued to soften throughout the third quarter reaching a low of
$1.94 per mcf, however they did begin to recover early in the fourth
quarter. After payment of distributions the Trust was able to fund 55
per cent of the third quarter capital program with cash flow from
operating activities (72 per cent when including the quarterly
proceeds from the distributions re-investment program ("DRIP")) with
the remaining portion being funded through proceeds from property
dispositions that were completed in the quarter.
- The Trust executed a $96.2 million capital expenditure program in the
third quarter of 2009 that included: drilling 11 oil wells in the
Ante Creek, Pembina and Goodlands areas, drilling six natural gas
wells in the Dawson area, and spending $11 million on the new gas
plant at Dawson. Of the wells drilled in the third quarter, two
natural gas wells and seven oil wells were completed; as well 10
wells were completed that were drilled in previous quarters. Included
in the third quarter capital expenditures is a crown land acquisition
in Pembina for $2.4 million where the Trust is planning to drill nine
horizontal oil wells into the Cardium zone during the fourth quarter
and into 2010. During the quarter, the Trust closed a disposition of
non-core assets in southeast Saskatchewan for proceeds of $33.5
million that were used to fund a portion of the third quarter capital
expenditures. Full year capital expenditures are now expected to be
approximately $365 million, an increase of $15 million over second
quarter guidance as the Trust has chosen to increase capital spending
in Alberta and British Columbia to take advantage of royalty
incentives announced by those provinces.
- At September 30, 2009 the Trust had a net debt balance of $705.4
million, approximately $680 million of unused credit available and a
net debt to annualized year-to-date cash flow from operating
activities of 1.5 times. At this time, the Trust is well positioned
to finance the remainder of the 2009 capital program and the
projected 2010 capital program.
- ARC plans to convert to a Corporation on January 1, 2011. The Board
of Directors has approved the overall strategy and currently the
detailed implementation steps are being defined.
- The Trust's board of directors has approved a $575 million capital
program for 2010 that will encompass considerable growth. The program
will include over $250 million slated for the first of many stages of
production growth and continued expansion of the Montney assets in
Northeast British Columbia with the remainder focused on ARC base
development areas, exploration opportunities and enhanced oil
recovery projects. ARC plans to drill 203 gross wells on operated
properties and plans to participate in an additional 91 wells on
partner operated properties. The Trust plans to finance the 2010
capital program through a combination of cash flow, existing credit
facilities, DRIP proceeds and potential minor assets disposition
proceeds. Additional details can be found in the November 5, 2009
news release titled "ARC Energy Trust Announces a $575 million
Capital Budget for 2010" and filed on www.sedar.com.
- Montney Resource Play Development
Production from the Dawson area was on budget at an average rate of
53.3 mmcf per day throughout the third quarter. The decreased
production rates when compared to the second quarter of 2009 were as
a result of the planned turnaround of a third party gas plant that
shut-in production for the full Dawson field periodically during the
month of September.
During the third quarter of 2009, the Trust spent $41.7 million on
development activities in the Dawson area including drilling four
horizontal wells and two vertical wells that were drilled and
completed during the quarter. ARC tested eight Dawson horizontal
wells during the quarter at rates between seven and 11 mmcf per day
of natural gas at a flowing pressure of 1,600 to 2,000 pounds per
square inch.
At this time, the Trust has 23 wells drilled in the Dawson gas field
that are in various stages of completion. In the completed and
waiting on tie-in category are 18 wells (11 horizontal and seven
vertical), while the remaining five wells (all horizontal) are yet to
be completed. In addition to these Dawson wells, ARC has drilled five
vertical wells and two horizontal wells in the Sunrise-Sunset area,
none of which are tied-in.
In the Montney West lands, ARC drilled a well at Sunset to hold land
that was due to expire in the fourth quarter of 2009 allowing ARC to
pursue future drilling opportunities on this land. ARC is
participating in a small development project on partner operated
lands at Sunrise. Current plans call for the drilling of four
horizontal wells, construction of pipelines and a gathering system
and the expansion of a third party operated gas plant. At quarter
end, two horizontal wells had been drilled that will be completed in
the fourth quarter. Assuming that the drilling and construction go as
planned, production from this area should be approximately 10 mmcf
per day net to ARC's 50 per cent working interest by the beginning of
2010.
Due to regulatory delays in receiving final approvals, we now believe
the Dawson Phase 1, 60 mmcf per day gas plant start-up will be early
in the second quarter of 2010. Year-to-date $29.8 million has been
spent on the gas plant. The British Columbia Oil and Gas Commission
("OGC") has granted conditional approvals, prior to final permit
approval, for: site grading (which is completed), pounding pilings
(completed pounding 1,350 pilings), mobilizing mechanical
contractor's trailers and equipment to site (in progress) and setting
major equipment skids (modules are being transported to site). Once
final permit approval is received from the OGC all on-site
construction will begin.
- Enhanced Oil Recovery Initiatives
During the third quarter, the Trust spent $7.5 million on enhanced
oil recovery ("EOR") initiatives and received $2.8 million in funding
from the Alberta Government for the Redwater pilot project for net
spending of $4.7 million during the quarter. Work on the Redwater
CO(2) pilot project continues and both the CO(2) injection and oil
production facilities are operating. Results to date are encouraging
but the Trust anticipates that it will take until the first quarter
of 2010 to determine to what extent the pilot has been successful in
mobilizing incremental volumes of oil. While the pilot project may
indicate enhanced recovery, the outlook for crude oil prices and the
cost and availability of CO(2) will be determining factors in the
Trust's ability to achieve commercial viability for a full scale EOR
scheme at Redwater.
MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
>>
This management's discussion and analysis ("MD&A") is the Trust management's analysis of its financial performance and significant trends or external factors that may affect future performance. It is dated
The MD&A contains Non-GAAP measures and forward-looking statements and readers are cautioned that the MD&A should be read in conjunction with the Trust's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements" included at the end of this MD&A.
ARC's Business
ARC Energy Trust ("ARC") or ("the Trust") is an actively managed oil and natural gas entity formed to provide investors with indirect ownership in cash generating energy assets, that currently consist of oil and natural gas assets. The cash flow from operating activities is based on the production and sale of crude oil, natural gas liquids and natural gas.
ARC is one of the top 20 producers of conventional oil and natural gas in western
ARC's Objective
ARC's objective is to be one of the top performing oil and gas companies in
<<
Table 1
-------------------------------------------------------------------------
Full year Full year
Per Trust Unit Q3 2009 YTD 2009 2008 2007
-------------------------------------------------------------------------
Normalized production per
unit(1)(2) 0.27 0.28 0.29 0.30
Normalized reserves per
unit(1)(3) N/A N/A 1.42 1.35
Distributions per unit 0.30 0.98 $2.67 $2.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Normalized indicates that all periods as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional trust units were issued (or repurchased) at a period
end price for the reserves per unit calculation and at an annual
average price for the production per unit calculation in order to
achieve a net debt balance of 15 per cent of total capitalization
each year. The normalized amounts are presented to enable
comparability of per unit values.
(2) Production per unit represents daily average production (boe) per
thousand trust units and is calculated based on daily average
production divided by the normalized weighted average trust units
outstanding including trust units issuable for exchangeable shares.
(3) Reserves per unit are calculated based on proved plus probable
reserves (boe) at period end divided by period end trust units
outstanding including trust units issuable for exchangeable shares.
>>
Currently the Trust distributes
ARC's business plan has resulted in significant operational success as seen in Table 2 where the Trust's trailing five year annualized return per unit was 14.3 per cent. However, commodity prices and the current economic downturn are significant factors impacting the profitability of ARC and capital appreciation of our trust units in the market place. The impact of these external factors has led to a negative return for the trailing one year despite the successful execution of ARC's business plan and operational successes.
<<
Table 2
-------------------------------------------------------------------------
Total Returns(1)
($ per unit except for Trailing Trailing Trailing
per cent) One Year Three Year Five Year
-------------------------------------------------------------------------
Distributions per unit $ 1.57 $ 6.65 $ 10.89
Capital appreciation per unit $ (2.90) $ (7.01) $ 3.35
Total return per unit (4.3)% 0.6% 95.3%
Annualized total return per unit (4.3)% 0.2% 14.3%
S&P/TSX Capped Energy Trust Index (12.0)% (2.4)% 9.4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Calculated as at September 30, 2009.
>>
2009 Third Quarter Financial and Operational Results
Following is a discussion of ARC's 2009 guidance and third quarter financial and operating results.
2009 Guidance and Financial Highlights
Table 3 is a summary of the Trust's 2009 Guidance and a review of 2009 actual results compared to guidance:
<<
Table 3
-------------------------------------------------------------------------
Revised
2009 2009
Guidance Actual YTD % Change
-------------------------------------------------------------------------
Production (boe/d) 63,000-64,000 63,881 -
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs(1) 10.50 10.28 (2)
Transportation(2) 0.90 0.88 (2)
G&A expenses (cash & non-cash)(3) 2.10 2.20 5
Interest 1.30 1.14 (12)
Capital expenditures ($ millions)(4) 365 242.3 -
Annual weighted average trust units
and trust units issuable (millions) 238 235 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The Trust has revised full year 2009 operating costs from the
original estimate of $10.70 per boe to be approximately $10.50 per
boe or $243 million based on annual production of between 63,000 and
64,000 boe per day. This decrease is to reflect lower electricity
costs recorded throughout the third quarter and overall costs savings
being achieved by the operations team.
(2) Full year transportation expense has been revised downward to $0.90
per boe from $1.00 per boe based on reduced estimates for oil
trucking requirements throughout the third and fourth quarters.
(3) G&A guidance amount of $2.10 per boe includes $1.75 per boe for cash
G&A costs, $0.55 per boe for cash Whole Unit Plan costs and a
recovery of $0.20 per boe for non-cash portion of the Whole Unit
Plan.
(4) Full year capital expenditures are now expected to be approximately
$365 million, an increase of $15 million over second quarter guidance
as the Trust has chosen to increase capital spending in Alberta and
British Columbia to take advantage of royalty incentives announced by
those provinces.
>>
The 2009 Guidance provides unitholders with information on Management's expectations for results of operations, excluding any acquisitions or dispositions for 2009. Readers are cautioned that the 2009 Guidance may not be appropriate for other purposes.
Table 4 is a review of the financial highlights and operating results for the third quarter and the first nine months of 2009.
<<
Table 4
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
(Cdn $ millions, except % %
per unit and volume data) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 125.6 251.4 (50) 354.2 734.8 (52)
Cash flow from operating
activities per unit(1) 0.53 1.16 (54) 1.51 3.41 (56)
Net income 68.9 311.7 (78) 157.3 450.3 (65)
Net income per unit(2) 0.29 1.46 (80) 0.68 2.12 (68)
Distributions per unit(3) 0.30 0.80 (63) 0.98 2.08 (53)
Distributions as a per
cent of cash flow from
operating activities 56 68 (18) 64 60 7
Average daily production
(boe/d)(4) 62,824 64,325 (2) 63,881 65,063 (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
period end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units outstanding excluding trust units
issuable for exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf: 1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of boe in isolation may be
misleading.
>>
Net Income
Net income in the third quarter of 2009 was
In the third quarter of 2008, the Trust recorded a
In the third quarter of 2009, the Trust recorded a
A measure of sustainability is the comparison of net income to distributions. Net income incorporates all costs including depletion expense and other non-cash expenses whereas cash flow from operating activities measures the cash generated in a given period before the cost of acquiring or replacing the associated reserves produced. Therefore, net income may be more representative of the profitability of the entity and thus a relevant measure against which to measure distributions to illustrate sustainability. As net income is sensitive to fluctuations in commodity prices and the impact of risk management contracts, currency fluctuations and other non-cash items, it is expected that there will be deviations between annual net income and distributions. Table 5 illustrates the comparison of distributions to net income as a measure of long-term sustainability. Distributions have been reduced from
<<
Table 5
-------------------------------------------------------------------------
Net income and Distributions Third
($ millions except quarter Full year Full year
per cent) 2009 YTD 2009 2008 2007
-------------------------------------------------------------------------
Net income 68.9 157.3 533.0 495.3
Distributions 70.6 227.6 570.0 498.0
-------------------------------------------------------------------------
Excess (Shortfall) (1.7) (70.3) (37.0) (2.7)
Excess (Shortfall) as
per cent of net income (2%) (45%) (7%) (1%)
-------------------------------------------------------------------------
Cash flow from operating
activities 125.6 354.2 944.4 704.9
Distributions as a per cent
of cash flow from
operating activities 56% 64% 60% 71%
Average distribution per
unit per month $0.10 $0.11 $0.22 $0.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Cash Flow from Operating Activities
Cash flow from operating activities decreased by 50 per cent in the third quarter of 2009 to
<<
Table 6
-------------------------------------------------------------------------
($ per
($ millions) trust unit) (% Change)
-------------------------------------------------------------------------
Q3 2008 Cash flow from Operating
Activities 251.4 1.16 -
-------------------------------------------------------------------------
Volume variance (11.3) (0.05) (4.5)
Price variance (235.2) (1.10) (93.6)
Cash (losses) and gains on risk
management contracts 41.0 0.19 16.3
Royalties 51.1 0.24 20.3
Expenses:
Transportation - - -
Operating(1) 5.5 0.03 2.2
Cash G&A (7.3) (0.03) (2.9)
Interest 1.4 0.01 0.6
Taxes (0.2) - (0.1)
Realized foreign exchange loss 0.8 - 0.3
Weighted average trust units - (0.05) -
Non-cash and other items(2) 28.4 0.13 11.3
-------------------------------------------------------------------------
Q3 2009 Cash flow from Operating
Activities 125.6 0.53 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes non-cash portion of Whole Unit Plan expense recorded in
operating costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
>>
Year-to-date cash flow from operating activities decreased by 52 per cent in 2009 to
<<
Table 6a
-------------------------------------------------------------------------
($ per
($ millions) trust unit) (% Change)
-------------------------------------------------------------------------
YTD 2008 Cash flow from Operating
Activities 734.8 3.41 -
-------------------------------------------------------------------------
Volume variance (30.6) (0.14) (4.2)
Price variance (675.4) (3.12) (91.9)
Cash (losses) and gains on risk
management contracts 129.6 0.60 17.6
Royalties 150.6 0.70 20.5
Expenses:
Transportation (1.5) (0.01) (0.2)
Operating(1) 1.0 - 0.1
Cash G&A 0.1 - -
Interest 5.1 0.02 0.7
Taxes (0.2) - -
Realized foreign exchange loss 1.3 0.01 0.2
Weighted average trust units - (0.14) -
Non-cash and other items(2) 39.4 0.18 5.4
-------------------------------------------------------------------------
YTD 2009 Cash flow from Operating
Activities 354.2 1.51 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes non-cash portion of Whole Unit Plan expense recorded in
operating costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
>>
2009 Cash Flow from Operating Activities Sensitivity
Table 7 illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the business environment and the resulting impact on cash flows from operating activities in total and per trust unit:
<<
Table 7
-------------------------------------------------------------------------
Impact on Annual Cash
flow from operating
activities(2)
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 60.00 $ 1.00 $ 0.04
Natural gas price (Cdn$AECO/mcf)(1) $ 4.35 $ 0.10 $ 0.02
Cdn$/US$ exchange rate(3) 1.15 $ 0.01 $ 0.03
Interest rate on debt % 3.90 % 1.0 $ 0.02
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.02
Gas production volumes (mmcf/d) 189.0 % 1.0 $ 0.01
Operating expenses per boe $ 10.50 % 1.0 $ 0.01
Cash G&A and LTIP expenses per boe $ 2.30 % 10.0 $ 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.
(3) Includes impact of foreign exchange on crude oil prices which are
presented in U.S. dollars. This amount does not include a foreign
exchange impact relating to natural gas prices as they are presented
in Canadian dollars in this sensitivity.
>>
Production
Production volumes averaged 62,824 boe per day in the third quarter of 2009 compared to 64,325 boe per day in the same period of 2008 as detailed in Table 8. The decrease in third quarter 2009 production is a result of turnarounds at the Dawson property as well as natural production declines as a result of the decreased capital spending in 2009.
<<
Table 8
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
% %
Production 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Light & medium crude
oil (bbl/d) 25,930 27,211 (5) 26,561 27,073 (2)
Heavy oil (bbl/d) 991 1,298 (24) 981 1,299 (24)
Natural gas (mmcf/d) 193.1 192.0 1 195.7 197.0 (1)
NGL (bbl/d) 3,717 3,822 (3) 3,720 3,862 (4)
-------------------------------------------------------------------------
Total production
(boe/d)(1) 62,824 64,325 (2) 63,881 65,063 (2)
% Natural gas production 51 50 51 50
% Crude oil and liquids
production 49 50 49 50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>
Light and medium crude oil production decreased to 25,930 boe per day compared to 27,211 boe per day in 2008, while heavy oil production declined by 307 boe per day. When compared to the second quarter of 2009, the total crude oil production is relatively flat, as a result of a successful drilling program at Goodlands, Pembina and Ante Creek that helped to offset natural decline. Natural gas production was 193.1 mmcf per day in the third quarter of 2009, an increase of one per cent from the 192 mmcf per day produced in the third quarter of 2008 but down 3.5 per cent from the second quarter of 2009. The decrease in production over the second quarter of 2009 is due primarily to the planned turnaround completed at a third party facility that shut-in production at Dawson periodically throughout the month of September as well as other turnarounds in the Northern Alberta district that occurred during the month of July.
The Trust's objective is to maintain annual production through the drilling of wells and other development activities to the full extent possible while giving considerations to capital spending constraints. In fulfilling this objective, there may be fluctuations in production depending on the timing of new wells coming on-stream. During the third quarter of 2009, the Trust drilled 17 gross wells (16 net wells) on operated properties; 11 gross oil wells, and six gross natural gas wells with a 100 per cent success rate. Of the wells drilled during the third quarter, two gas wells and seven oil wells were completed. Five of the oil wells completed were brought on production during the quarter.
The Trust expects that 2009 full year production will average approximately 63,000 to 64,000 boe per day and that a total of 146 gross wells (120 net) will be drilled by ARC on operated properties with participation in an additional 54 gross wells to be drilled on the Trust's non-operated properties. The Trust estimates that the revised 2009 drilling program will add sufficient production from new wells to offset the majority of production declines on existing properties, however, overall production is expected to decrease by 1,000 to 2,000 boe per day relative to 2008 production levels. The planned capital expenditures for 2009 have been increased to approximately
Table 9 summarizes the Trust's production by core area:
<<
Table 9
-------------------------------------------------------------------------
Three Months Ended September 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,218 1,370 28.4 1,106
N.E. BC & N.W. AB 13,517 703 72.8 673
Northern AB 8,551 3,891 23.1 806
Pembina & Redwater 13,609 9,298 19.9 992
S.E. AB & S.W. Sask. 8,951 1,053 47.3 12
S.E. Sask. & MB 10,978 10,605 1.5 127
-------------------------------------------------------------------------
Total 62,824 26,920 193.0 3,716
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Months Ended September 30, 2008
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,428 1,380 29.0 1,218
N.E. BC & N.W. AB 12,241 749 65.6 556
Northern AB 9,464 4,363 24.6 997
Pembina & Redwater 13,972 9,866 19.1 921
S.E. AB & S.W. Sask. 9,629 977 51.9 8
S.E. Sask. & MB 11,591 11,175 1.8 122
-------------------------------------------------------------------------
Total 64,235 28,510 192.0 3,822
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is
northwest, S.E. is southeast and S.W. is southwest.
>>
Table 9a summarizes the Trust's production by core area for the nine months of 2009:
<<
Table 9a
-------------------------------------------------------------------------
Nine Months Ended September 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,089 1,281 28.2 1,108
N.E. BC & N.W. AB 13,868 722 74.9 673
Northern AB 9,005 4,072 24.6 837
Pembina & Redwater 13,540 9,374 19.2 962
S.E. AB & S.W. Sask. 8,923 1,016 47.4 13
S.E. Sask. & MB 11,456 11,076 1.5 127
-------------------------------------------------------------------------
Total 63,881 27,541 195.8 3,720
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine Months Ended September 30, 2008
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,549 1,405 29.5 1,228
N.E. BC & N.W. AB 12,492 811 66.4 601
Northern AB 10,058 4,662 26.7 952
Pembina & Redwater 13,599 9,405 19.7 911
S.E. AB & S.W. Sask. 9,826 991 52.9 12
S.E. Sask. & MB 11,539 11,098 1.8 158
-------------------------------------------------------------------------
Total 65,063 28,372 197.0 3,862
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is
northwest, S.E. is southeast and S.W. is southwest.
>>
Revenue
Revenue decreased to
A breakdown of revenue is outlined in Table 10:
<<
Table 10
-------------------------------------------------------------------------
Revenue Three Months Ended Nine Months Ended
September 30 September 30
% %
($ millions) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Oil revenue 167.7 299.5 (44) 441.8 833.3 (47)
Natural gas revenue 57.7 153.3 (62) 216.3 482.6 (55)
NGL revenue 13.3 29.1 (54) 39.5 82.4 (52)
-------------------------------------------------------------------------
Total commodity revenue 238.7 481.9 (50) 697.6 1,398.3 (50)
Other revenue 0.5 3.8 (87) 2.0 7.3 (73)
-------------------------------------------------------------------------
Total revenue 239.2 485.7 (51) 699.6 1,405.6 (50)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commodity Prices Prior to Hedging
Table 11
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
% %
2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 3.03 9.27 (67) 4.10 8.58 (52)
WTI oil (US$/bbl)(2) 68.29 118.18 (42) 57.13 113.39 (50)
Cdn$ / US$ exchange rate 1.10 1.04 6 1.16 1.02 14
WTI oil (Cdn$/bbl) 74.90 121.77 (38) 66.08 114.99 (43)
-------------------------------------------------------------------------
ARC Realized Prices
Prior to Hedging
Oil ($/bbl) 67.74 114.20 (41) 58.77 107.20 (45)
Natural gas ($/mcf) 3.25 8.68 (63) 4.05 8.94 (55)
NGL ($/bbl) 38.92 82.87 (53) 38.89 77.91 (50)
-------------------------------------------------------------------------
Total commodity revenue
before hedging ($/boe) 41.31 81.42 (49) 40.00 78.44 (49)
Other revenue ($/boe) 0.08 0.64 (88) 0.11 0.40 (73)
-------------------------------------------------------------------------
Total revenue before
hedging ($/boe) 41.39 82.06 (50) 40.11 78.84 (49)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents posting price of West Texas Intermediate oil.
>>
Oil prices continued to recover in the third quarter of 2009 with US$WTI prices averaging
Natural gas prices softened throughout the third quarter of 2009. Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged
Prior to hedging activities, ARC's total realized commodity price was
Risk Management and Hedging Activities
ARC maintains an ongoing risk management program to reduce the volatility of revenues in order to increase the certainty of distributions, protect acquisition economics, and fund capital expenditures.
Gain or loss on risk management contracts comprise realized and unrealized gains or losses on risk management contracts that do not meet the accounting definition requirements of an effective hedge, even though the Trust considers all risk management contracts to be effective economic hedges. Accordingly, gains and losses on such contracts are shown as a separate category in the statement of income.
Lower natural gas prices in the third quarter of 2009 resulted in realized cash gains of
ARC's third quarter 2009 results include an unrealized total mark-to- market loss of
In the third quarter of 2008, the Trust recorded a significant unrealized gain on risk management contracts as commodity prices, and in particular oil prices, declined significantly at the end of the quarter when compared to the previous reporting period. The realized cash losses in the third quarter of 2008 were mostly attributable to crude oil contracts where the market prices were in excess of ARC's contracted price.
Table 12 summarizes the total gain (loss) on risk management contracts for the third quarter of 2009 as compared to the same period in 2008:
<<
Table 12
-------------------------------------------------------------------------
Risk Management Crude Foreign Q3 Q3
Contracts Oil & Natural Curr- Inter- 2009 2008
($ millions) Liquids Gas ency Power(3) est Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (3.6) 10.4 0.2 (0.3) - 6.7 (34.3)
Unrealized (loss)
gain on
contracts(2) 12.1 (11.4) - (1.4) - (0.7) 187.5
-------------------------------------------------------------------------
Total (loss) gain
on risk management
contracts 8.5 (1.0) 0.2 (1.7) - 6.0 153.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
(3) Amounts presented in Table 12 exclude a $0.3 million realized loss
and an unrealized loss of $0.4 million for the Trust's power
contracts that have been designated as effective hedges for
accounting purposes. Realized gains and losses on these contracts are
recorded in operating costs and unrealized gains and losses are
recorded in the Consolidated Statement of Comprehensive Income and
Accumulated Other Comprehensive Income.
>>
Table 12a summarizes the total gain (loss) on risk management contracts for the first nine months of 2009 as compared to the same period in 2008:
<<
Table 12a
-------------------------------------------------------------------------
Risk Management Crude Foreign YTD YTD
Contracts Oil & Natural Curr- Inter- 2009 2008
($ millions) Liquids Gas ency Power(3) est Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (10.5) 26.6 1.0 (0.8) 4.8 21.1 (108.5)
Unrealized (loss)
gain on
contracts(2) 7.2 (4.9) - (4.8) (5.4) (7.9) 26.0
-------------------------------------------------------------------------
Total (loss) gain
on risk management
contracts (3.3) 21.7 1.0 (5.6) (0.6) 13.2 (82.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
(3) Amounts presented in Table 12a exclude a $1.1 million realized loss
and an unrealized loss of $3.6 million for the Trust's power
contracts that have been designated as effective hedges for
accounting purposes. Realized gains and losses on these contracts are
recorded in operating costs and unrealized gains and losses are
recorded in the Consolidated Statement of Comprehensive Income and
Accumulated Other Comprehensive Income.
>>
The Trust currently limits the amount of forecast production that can be hedged to a maximum 50 per cent with the remaining 50 per cent of production being sold at market prices. The following table is an indicative summary of the Trust's positions for crude oil and natural gas as at
<<
Table 13
-------------------------------------------------------------------------
Hedge Positions
As at September 30, 2009(1)(2)
Q4 2009 Q1 2010
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 83.02 7,000 96.50 5,000
Bought Put 67.61 9,500 75.05 5,000
Sold Put 42.89 2,500 - -
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 5.52 93,370 6.80 5,000
Bought Put 4.84 93,370 6.80 5,000
Sold Put 4.50 20,000 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Hedge Positions
As at September 30, 2009(1)(2)
Q2 2010(3) Q3-Q4 2010
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 96.50 4,000 96.50 4,000
Bought Put 75.05 4,000 75.05 4,000
Sold Put - - - -
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 6.80 5,000 6.80 5,000
Bought Put 6.80 5,000 6.80 5,000
Sold Put - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The prices and volumes noted above represent averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price.
(2) In addition to positions shown here, ARC has entered into additional
basis positions until October 2012, an energy equivalent swap until
December 31, 2009. Please refer to note 8 in the Notes to the
Consolidated Financial Statements for full details of the Trust's
risk management positions as of September 30, 2009.
(3) The natural gas contract listed for 2010 is a fixed price swap
starting in 2010 and ending in December 2013. During the quarter, the
Trust took advantage of favorable forward curve pricing for natural
gas and entered into a long-term contract for a small portion of
future forecast production.
>>
Table 13 should be interpreted as follows using the fourth quarter 2009 crude oil hedges as an example. To accurately analyze the Trust's hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading.
<<
- If the market price is below $42.89, ARC will receive $67.61 less the
difference between $42.89 and the market price on 2,500 bbl per day.
For example if the market price is $42.85, the Trust will receive
$67.57 on 2,500 bbl per day.
- If the market price is between $42.89 and $67.61, ARC will receive
$67.61 on 9,500 bbl per day.
- If the market price is between $67.61 and $83.02, ARC will receive
the market price on 9,500 per day.
- If the market price exceeds $83.02, ARC will receive $83.02 on 7,000
per day.
>>
Operating Netbacks
The Trust's operating netback, before realized hedging gains and losses, decreased 57 per cent to
The Trust's third quarter 2009 netback, after realized hedging gains and losses, was
The components of operating netbacks are summarized in Table 14 and 14a:
<<
Table 14
-------------------------------------------------------------------------
Crude Heavy Q3 2009 Q3 2008
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 67.98 61.54 3.25 38.92 41.31 81.42
Other revenue - - - - 0.08 0.64
-------------------------------------------------------------------------
Total revenue 67.98 61.54 3.25 38.92 41.39 82.06
Royalties (10.71) (7.52) (0.40) (12.65) (6.53) (15.00)
Transportation (0.14) (0.64) (0.25) - (0.83) (0.80)
Operating costs(1) (13.58) (9.79) (1.18) (9.37) (9.68) (10.19)
-------------------------------------------------------------------------
Netback prior to hedging 43.55 43.59 1.42 16.90 24.35 56.07
Realized gain (loss) on
risk management
contracts(2) (1.63) - 0.58 - 1.12 (5.79)
-------------------------------------------------------------------------
Netback after hedging 41.92 43.59 2.00 16.90 25.47 50.28
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 14a
-------------------------------------------------------------------------
YTD YTD
Crude Heavy 2009 2008
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 58.99 52.59 4.05 38.89 40.00 78.44
Other revenue - - - - 0.11 0.40
-------------------------------------------------------------------------
Total revenue 58.99 52.59 4.05 38.89 40.11 78.84
Royalties (8.73) (4.73) (0.47) (12.33) (5.86) (14.18)
Transportation (0.15) (1.12) (0.26) - (0.88) (0.77)
Operating costs(1) (13.11) (12.52) (1.34) (8.45) (10.28) (10.14)
-------------------------------------------------------------------------
Netback prior to hedging 37.00 34.22 1.98 18.11 23.09 53.75
Realized gain (loss) on
risk management
contracts(2) (1.56) - 0.50 - 0.88 (6.08)
-------------------------------------------------------------------------
Netback after hedging 35.44 34.22 2.48 18.11 23.97 47.67
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
(2) Realized loss on risk management contracts include the settlement
amounts for crude oil and natural gas and power contracts. Foreign
exchange and interest contracts are excluded from the net back
calculation.
>>
Royalties as a percentage of pre-hedged commodity revenue net of transportation decreased to 16.1 per cent (
The Alberta Government's
Following the implementation of the ARF, the Alberta Government introduced certain transitional rates and incentive programs to provide royalty relief to producers and in turn encourage continued drilling activity in the province. ARC will be eligible for the Alberta programs assuming the necessary criteria are met and required elections are filed. The drilling credit program applies to new wells drilled between
During the third quarter of 2009 the British Columbia government announced a new Stimulus Package designed to attract investment and produce immediate economic benefits for the province. The stimulus package included royalty incentives in the form of reduced royalty rates for wells drilled in the province between
Operating costs decreased to
The Trust has revised full year 2009 operating costs from the original estimate of
General and Administrative ("G&A") Expenses and Trust Unit Incentive
Compensation
G&A, prior to long-term incentive payments under the Whole Unit Plan and net of overhead recoveries on operated properties, increased 13 per cent to
A cash payment was made under the Whole Unit Plan in
Table 15 is a breakdown of G&A and trust unit incentive compensation expense under the Whole Unit Plan:
<<
Table 15
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
G&A and Trust Unit Incentive
Compensation Expense % %
($ millions except per boe) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
G&A expenses 13.5 13.3 2 42.1 40.3 4
Operating recoveries (3.3) (4.3) (23) (11.3) (12.2) (7)
-------------------------------------------------------------------------
Cash G&A expenses before
Whole Unit Plan 10.2 9.0 13 30.8 28.1 10
Cash Expense - Whole Unit
Plan 6.1 - - 11.7 14.4 (19)
-------------------------------------------------------------------------
Cash G&A expenses including
Whole Unit Plan 16.3 9.0 81 42.5 42.5 -
Accrued compensation -
Whole Unit Plan (0.4) (5.5) (93) (4.0) 4.7 (185)
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense 15.9 3.5 354 38.5 47.2 (18)
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense per boe 2.75 0.59 366 2.20 2.65 (17)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
A non-cash Whole Unit Plan recovery ("non-cash compensation recovery") of
Whole Unit Plan
The Whole Unit Plan is designed to offer each employee, officer and director (the "plan participants") cash compensation in relation to the value of a specified number of underlying trust units. The Whole Unit Plan consists of Restricted Trust Units ("RTUs") for which the number of units is fixed and will vest over a period of three years and Performance Trust Units ("PTUs") for which the number of units is variable and will vest at the end of three years.
Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying trust units plus accrued distributions. The cash compensation issued upon vesting of the PTUs is dependent upon the performance of the Trust compared to its peers and indicated by the performance multiplier. The performance multiplier is based on the percentile rank of the Trust's total unitholder return compared to its peers. Total return is calculated as the sum of the change in the market price of the trust units in the period plus the amount of distributions in the period. The performance multiplier ranges from zero, if ARC's performance ranks in the bottom quartile, to two for top quartile performance.
Table 16 shows the changes to the Whole Unit Plan during the first nine months of 2009 along with the estimated value upon vesting of the plan as at September 30, 2009:
<<
Table 16
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and $ millions Number of Number of Total RTUs
except per unit) RTUs PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 756 959 1,715
Granted in the period 697 634 1,331
Vested in the period (355) (262) (617)
Forfeited in the period (43) (24) (67)
-------------------------------------------------------------------------
Balance, end of period(1) 1,055 1,307 2,362
Estimated distributions to vesting date(2) 184 317 501
-------------------------------------------------------------------------
Estimated units upon vesting after
distributions 1,239 1,624 2,863
Performance multiplier(3) - 1.3 -
-------------------------------------------------------------------------
Estimated total units upon vesting 1,239 2,062 3,301
-------------------------------------------------------------------------
Trust unit price at September 30, 2009 20.20 20.20 20.20
Estimated total value upon vesting
($ millions) 25.0 41.7 66.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on underlying units before performance multiplier and accrued
distributions.
(2) Represents estimated additional units to be issued equivalent to
estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and was estimated to
be 1.3 at September 30, 2009 based on an average calculation of all
outstanding grants. The performance multiplier is assessed each
period end based on actual results of the Trust relative to its peers
except during the first year of each grant where a performance
multiplier of 1.0 is used.
>>
The value associated with the RTUs and PTUs is expensed in the statement of income over the vesting period with the expense amount being determined by the trust unit price, the number of PTUs to be issued on vesting, and distributions. In periods where substantial trust unit price fluctuation occurs, the Trust's G&A expense is subject to significant volatility.
Table 17 is a summary of the range of future expected payments under the Whole Unit Plan based on variability of the performance multiplier and units outstanding as at September 30, 2009:
<<
Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
September 30, 2009 Performance multiplier
(units thousands and $ millions --------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 1,239 1,239 1,239
PTUs - 1,624 3,248
-------------------------------------------------------------------------
Total units(1) 1,239 2,863 4,487
-------------------------------------------------------------------------
Trust unit price(2) 20.20 20.20 20.20
Trust unit distributions per month(2) 0.10 0.10 0.10
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting(3) 25.0 57.8 90.6
-------------------------------------------------------------------------
2010 11.1 20.0 28.8
2011 8.4 17.0 25.7
2012 5.5 20.8 36.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes additional estimated units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumes a
future trust unit price of $20.20 and $0.10 per trust unit
distributions based on the unit price and distribution levels in
place at September 30, 2009.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in March
and September of each year and at that time is reflected as a
reduction of cash flow from operating activities.
>>
Due to the variability in the future payments under the plan, the Trust estimates that between
Interest and financing charges
Interest and financing charges decreased to
Foreign Exchange Gains and Losses
The Trust recorded a gain of
Realized foreign exchange gains or losses arise from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements. There were no cash realized foreign exchange gains during the quarter, however a non-cash realized gain of
Unrealized foreign exchange gains and losses are due to revaluation of U.S. denominated debt balances. The volatility of the Canadian dollar during the reporting period has a direct impact on the unrealized component of the foreign exchange gain or loss. The unrealized gain or loss impacts net income but does not impact cash flow from operating activities as it is a non-cash amount. From
Taxes
In the third quarter of 2009, a future income tax recovery of
The corporate income tax rate applicable to 2009 is 29 per cent; however the Trust and its subsidiaries did not pay any material cash income taxes for the third quarter of 2009. Due to the Trust's structure, currently, both income tax and future tax liabilities are passed on to the unitholders by means of royalty payments made between ARC Resources and the Trust.
Management continues to work on the plan for converting ARC Energy Trust to a corporation on
<<
Table 18
-------------------------------------------------------------------------
Income Cdn $ millions at
Tax Pool type September 30, 2009 Annual deductibility
-------------------------------------------------------------------------
Canadian Oil and Gas
Property Expense 959.5 10% declining balance
Canadian Development Expense 384.6 30% declining balance
Canadian Exploration Expense 98.9 100%
Un-depreciated Capital Cost 388.3 Primarily 25% declining
balance
Non-Capital Losses 166.5 100%
Research and Experimental
Expenditures 0.8 100%
Other 16.2 Various rates, 7%
declining balance to 20%
-------------------------------------------------------------------------
Total Federal Tax Pools 2,014.8
-------------------------------------------------------------------------
Additional Alberta Tax Pools 155.5 Various rates, 25%
declining balance to 100%
-------------------------------------------------------------------------
Total Federal and Provincial Pools 2,170.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Returns to shareholders post conversion will be impacted by the reduction of cash flow required to pay current income taxes, if any. Over the longer term, we would expect Canadian investors who hold their trust units in a taxable account will be relatively indifferent on an after tax basis as to whether ARC is structured as a corporation or as a trust in 2011. However, Canadian tax deferred investors (those holding their trust units in a tax deferred vehicle such as an RRSP, RRIF or pension plan) and foreign investors will realize a lower after tax return on distributions in taxable years after 2011 due to the introduction of the SIFT Tax should ARC stay as a trust, and their inability to claim the dividend tax credit if ARC converts to a corporation.
If a conversion from the trust structure to a corporation is approved by the unitholders, the income tax payable by unitholders will vary and each unitholder should consult their own tax advisor for details on the direct impact to themselves.
Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate increased to
A breakdown of the DD&A rate is summarized in Table 19:
<<
Table 19
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
DD&A Rate
($ millions except per % %
boe amounts) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Depletion of oil and gas
assets(1) 93.3 91.1 2 283.3 276.5 2
Accretion of asset
retirement obligation(2) 2.4 2.3 4 7.0 6.9 1
-------------------------------------------------------------------------
Total DD&A 95.7 93.4 2 290.3 283.4 2
DD&A rate per boe 16.55 15.79 5 16.65 15.90 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>
Capital Expenditures and Net Acquisitions
Capital expenditures, excluding acquisitions and dispositions, totaled
Of the total amount spent in the third quarter,
In addition to capital expenditures on development activities during the third quarter, the Trust completed small property acquisitions of
For the remainder of 2009, the Trust expects to drill 39 gross wells (38 net wells) on operated properties, complete all wells in inventory and proceed with construction of the Dawson gas plant that is expected to be operational by early second quarter of 2010. Total capital expenditures are forecast to be
A breakdown of capital expenditures and net acquisitions is shown in Table 20:
<<
Table 20
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
Capital Expenditures % %
($ millions) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Geological and geophysical 3.0 1.3 131 10.8 23.3 (54)
Drilling and completions 61.0 91.4 (33) 148.1 188.3 (21)
Plant and facilities 26.1 24.2 8 74.8 59.9 25
Undeveloped land purchased
at crown land sales 4.5 18.6 (76) 4.9 105.3 (95)
Other capital 1.6 0.9 78 3.7 2.3 61
-------------------------------------------------------------------------
Total capital expenditures
before net acquisitions 96.2 136.4 (29) 242.3 379.1 (36)
-------------------------------------------------------------------------
Producing property
acquisitions(1) 6.8 - 100 7.0 0.3 100
Undeveloped land property
acquisitions 0.4 13.1 (97) 8.7 26.9 (68)
Producing property
dispositions(1) (37.3) - 100 (37.3) (0.1) 100
Undeveloped land property
dispositions - - - - (3.7) -
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 66.1 149.5 (56) 220.7 402.5 (45)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
>>
Approximately 72 per cent of the
<<
Table 21
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30, 2009 September 30, 2008
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------
Expenditures 96.2 (30.1) 66.1 136.4 13.1 149.5
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 55% - 80% 57% - 53%
Proceeds from
Distribution
re-investment plan
("DRIP") 17% - 24% 29% - 26%
Debt/(Excess funding) 28% 100% (4%) 14% 100% 21%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 21a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30, 2009 September 30, 2008
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------
Expenditures 242.3 (21.6) 220.7 379.1 23.4 402.5
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 51% - 56% 77% - 72%
Proceeds from
Distribution
re-investment plan
("DRIP") 21% - 23% 23% 38% 24%
Debt/(Excess
funding)(1) 28% 100% 21% - 62% 4%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The Trust's debt balance was reduced by $240 million with the net
proceeds of the equity offering completed in the first quarter. These
proceeds are intended to fund a portion of ARC's expenditures in the
Montney resource play.
>>
Asset Retirement Obligation and Reclamation Fund
At
Included in the
ARC's reclamation funds held
Capitalization, Financial Resources and Liquidity
A breakdown of the Trust's capital structure is outlined in Table 22, as at
<<
Table 22
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per cent and September 30, December 31,
ratio amounts) 2009 2008
-------------------------------------------------------------------------
Net debt obligations(1) 705.4 961.9
Market value of trust units and exchangeable
shares(2) 4,809.6 4,405.9
-------------------------------------------------------------------------
Total capitalization(3) 5,515.0 5,367.8
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 12.8% 17.9%
Net debt to annualized YTD cash flow from
operating activities 1.5 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net debt is a non-GAAP measure and therefore it may not be comparable
with the calculation of similar measures for other entities. It is
calculated as long-term debt plus current liabilities less the
current assets as they appear on the Consolidated Balance Sheets. Net
debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(2) Calculated using the total trust units outstanding at September 30
and December 31 including the total number of trust units issuable
for exchangeable shares at September 30 and December 31 multiplied by
the closing trust unit price of $20.20 and $20.10 at September 30,
2009 and December 31, 2008, respectively.
(3) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
>>
At
As at
As a result of the weakened global economic situation, the Trust along with all other oil and gas entities may have restricted access to capital and increased borrowing costs. Although the Trust's business and asset base have not changed, the lending capacity of all financial institutions has been diminished and risk premiums have increased. These issues will impact the Trust as it reviews financing alternatives for the 2010 capital program, assesses potential future acquisition opportunities and manages future cash flow decremented by lower commodity prices and higher borrowing costs. The Trust intends to finance its 2010 capital program with cash flow, existing credit facilities, proceeds from the DRIP, potential asset dispositions and new borrowings or equity if necessary. Beyond that, the Trust may need to access additional capital and/or curtail capital expenditure plans and will look to do so in the most cost effective manner possible.
Unitholders' Equity
At
Unitholders electing to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP may do so at a five per cent discount to the prevailing market price with no additional fees or commissions. During the first nine months of 2009, the Trust raised proceeds of
Distributions
ARC declared distributions of
The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders:
<<
- The portion of capital expenditures that are funded with cash flow
from operating activities. In the first nine months of 2009, the
Trust withheld approximately 35 per cent of cash flow from operating
activities to fund 51 per cent of the capital program excluding
acquisitions. The remaining portion of capital expenditures was
financed by proceeds from the DRIP program, proceeds from net
dispositions and debt.
- An annual contribution to the reclamation funds, with $11.3 million
scheduled to be contributed in 2009. The reclamation funds are
segregated bank accounts or subsidiary trusts and the balances will
be drawn on in future periods as the Trust incurs abandonment and
reclamation costs over the life of its properties.
- Debt principal repayments on the Trust's credit facility from time to
time as determined by the board of directors. The Trust's current
debt level is well within the covenants specified in the debt
agreements and, accordingly, there are no current mandatory
requirements for repayment.
- Income taxes that are not passed on to unitholders. The Trust has a
liability for future income taxes due to the excess of book value
over the tax basis of the assets of the Trust and its corporate
subsidiaries. The Trust currently, and up until January 1, 2011, may
minimize or eliminate cash income taxes in corporate subsidiaries by
maximizing deductions, however in future periods there may be cash
income taxes if deductions are not sufficient to eliminate taxable
income. Taxability of the Trust is currently passed on to unitholders
in the form of taxable distributions whereby corporate income taxes
are eliminated at the Trust level. The Trust taxation legislation,
which will take effect in 2011, will result in taxes payable at the
Trust level and therefore distributions to unitholders would decrease
if ARC remained as a trust.
- Working capital requirements as determined by the board of directors.
Certain working capital amounts may be deducted from cash flow from
operating activities, however such amounts would be minimal and the
Trust does not anticipate any such deductions in the foreseeable
future.
- The Trust has certain obligations for future payments relative to
employee long-term incentive compensation under the Whole Unit Plan.
Presently, the Trust estimates that $25 million to $90.6 million will
be paid out pursuant to such commitments in 2010 through 2012 subject
to vesting provisions and future performance of the Trust. These
amounts will reduce cash flow from operating activities and may in
turn reduce distributions in future periods.
>>
Cash flow from operating activities and distributions in total and per unit are summarized in Table 23 and Table 23a:
<<
Table 23
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30 September 30
Cash flow from operating % %
activities and 2009 2008 Change 2009 2008 Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from operating
activities 125.6 251.4 (50) 0.53 1.16 (54)
Net reclamation fund
contributions(1) (2.3) (1.7) 35 (0.01) (0.01) -
Capital expenditures
funded with cash flow
from operating
activities (52.7) (78.4) (33) (0.22) (0.36) (39)
Other(2) - - - - 0.01 -
-------------------------------------------------------------------------
Distributions 70.6 171.3 (59) 0.30 0.80 (62)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 23a
-------------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30 September 30
Cash flow from operating % %
activities and 2009 2008 Change 2009 2008 Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from operating
activities 354.2 734.8 (52) 1.51 3.41 (56)
Net reclamation fund
contributions(1) (3.1) (0.9) 244 (0.01) - -
Capital expenditures
funded with cash flow
from operating
activities (123.5) (291.1) (58) (0.53) (1.35) (61)
Other(2) - - - 0.01 0.02 (50)
-------------------------------------------------------------------------
Distributions 227.6 442.8 (49) 0.98 2.08 (53)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operated activities are based on weighted average outstanding trust
units in the period.
>>
The Trust continually assesses distribution levels, in light of commodity prices, capital expenditure programs and production volumes, to ensure that distributions are in line with the long-term strategy and objectives of the Trust as per the following guidelines:
<<
- To maintain a level of distributions that, in normal times, in the
opinion of Management and the Board of Directors, is sustainable for
a minimum period of six months after factoring in the impact of
current commodity prices on cash flows. The Trust's objective is to
normalize the effect of volatility of commodity prices rather than to
pass on that volatility to unitholders in the form of fluctuating
monthly distributions.
- To ensure that the Trust's financial flexibility is maintained by a
review of the Trust's debt to equity and debt to cash flow from
operating activities levels. The use of cash flow from operating
activities and proceeds from equity offerings to fund capital
development activities reduces the requirements of the Trust to use
debt to finance these expenditures. In the first nine months of 2009,
the Trust funded 51 per cent of capital development activities with a
portion of cash flow from operating activities. Distributions and the
actual amount of cash flows withheld to fund the Trust's capital
expenditure program is dependent on the commodity price environment
and is subject to the approval and discretion of the Board of
Directors.
>>
The actual amount of future monthly distributions is proposed by Management and is subject to the approval and discretion of the Board of Directors. The Board reviews future distributions in conjunction with their review of quarterly financial and operating results.
Please refer to the Trust's website at www.arcenergytrust.com for details of the monthly distribution amounts and distribution dates for 2009.
Environmental Initiatives Impacting the Trust
There are no new environmental initiatives impacting the Trust at this time.
Contractual Obligations and Commitments
The Trust has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, and lease rental obligations and employee agreements. These obligations are of a recurring and consistent nature and impact the Trust's cash flows in an ongoing manner. The Trust also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 24.
<<
Table 24
-------------------------------------------------------------------------
Payments due by period
-------------------------------------------------------------------------
1 year 2-3 4-5 Beyond Total
years years 5 years
-------------------------------------------------------------------------
Debt repayments(1) 31.5 350.6 109.8 145.2 637.1
Interest payments(2) 20.7 37.8 27.6 26.2 112.3
Reclamation fund
contributions(3) 5.3 9.5 8.3 67.9 91.0
Purchase commitments 25.9 13.3 4.5 2.6 46.3
Transportation commitments(4) 3.5 21.9 24.6 7.8 57.8
Operating leases 5.1 11.2 14.8 76.3 107.4
Risk management contract
premiums(5) 5.5 0.3 - - 5.8
-------------------------------------------------------------------------
Total contractual obligations 97.5 444.6 189.6 326.0 1,057.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed payments for transporting production from the Dawson gas plant,
expected to be operational in early second quarter of 2010.
(5) Fixed premiums to be paid in future periods on certain commodity risk
management contracts.
>>
The above noted risk management contract premiums are part of the Trust's commitments related to its risk management program and have been recorded at fair market value at
The Trust enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that the Trust has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. The Trust's 2009 capital budget has been approved by the Board at
The 2009 capital budget of
The Trust is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on the Trust's financial position or results of operations and therefore the commitment table (Table 24) does not include any commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price received by the Trust is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table (Table 24) as it is of a routine nature and is part of normal course of operations.
Off Balance Sheet Arrangements
The Trust has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 24), which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of
Critical Accounting Estimates
The Trust has continuously evolved and documented its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.
The Trust's financial and operating results incorporate certain estimates including:
<<
- estimated revenues, royalties and operating costs on production as at
a specific reporting date but for which actual revenues and costs
have not yet been received;
- estimated capital expenditures on projects that are in progress;
- estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves that the Trust expects to recover
in the future;
- estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and
foreign exchange rates;
- estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
- estimated future recoverable value of property, plant and equipment
and goodwill.
>>
The Trust has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.
The ARC leadership team's mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with the Trust's environmental, health and safety policies.
Internal Control over Financial Reporting
ARC is required to comply with National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to as Canadian SOX ("C-Sox"). The certification of interim filings for the interim period ended
Financial Reporting Update
Future Accounting Changes
International Financial Reporting Standards ("IFRS")
In
The Trust has commenced the process to transition from current Canadian GAAP to IFRS. Internal staff has been appointed to lead the conversion project along with sponsorship from the leadership team. Regular progress reporting to the audit committee of the Board of Directors on the status of the IFRS conversion has been implemented.
<<
ARC's project consists of three key phases:
- Scoping and diagnostic phase - this phase involves performing a high
level impact analysis to identify areas that may be affected by the
transition to IFRS. The results of this analysis are priority ranked
according to complexity and the amount of time required to assess the
impact changes in transitioning to IFRS.
- Impact analysis and evaluation phase - during this phase, items
identified in the diagnostic are addressed according to the priority
levels assigned to them. This phase involves analysis of policy
choices allowed under IFRS and their impact on the financial
statements. In addition, certain potential differences are further
investigated to assess whether there may be a broader impact to the
Trust's debt agreements, compensation arrangements or management
reporting systems. The conclusion of the impact analysis and
evaluation phase will require the audit committee of the Board of
Directors to review and approve all accounting policy choices as
proposed by Management.
- Implementation phase - involves implementation of all changes
approved in the impact analysis phase and will include changes to
information systems, business processes, modification of agreements
and training of all staff who are impacted by the conversion.
>>
The Trust has completed the scoping and diagnostic phase and expects to complete the impact analysis and evaluation phase during the fourth quarter of 2009.
In
Non-GAAP Measures
Management uses certain key performance indicators ("KPIs") and industry benchmarks such as distributions as a per cent of cash flow from operating activities, operating netbacks ("netbacks"), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, reserves per unit and production per unit, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for the Trust. These KPIs and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities.
Forward-looking Information and Statements
This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices and ARC's commodity risk management programs; the amount of future asset retirement obligations; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures, future tax treatment of income trusts and future taxes payable by ARC; ARC's income tax pools and the future impact of the implementation of IFRS on ARC's financial statements.
The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures; ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Additional Information
Additional information relating to ARC can be found on SEDAR at www.sedar.com.
<<
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per unit
amounts) 2009 2008
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 239.2 235.2 225.2 300.8
Per unit(1) 1.01 0.99 0.98 1.38
Cash flow from operating activities 125.6 104.3 124.3 209.4
Per unit - basic(1) 0.53 0.44 0.54 0.96
Per unit - diluted 0.53 0.44 0.54 0.96
Net income 68.9 66.1 22.3 82.7
Per unit - basic(2) 0.29 0.28 0.10 0.38
Per unit - diluted 0.29 0.28 0.10 0.38
Distributions 70.6 75.0 82.0 127.2
Per unit - basic(3) 0.30 0.32 0.36 0.59
Total assets 3,642.9 3,672.5 3,733.1 3,766.7
Total liabilities 1,278.4 1,323.1 1,392.1 1,624.6
Net debt outstanding(4) 705.4 737.6 781.5 961.9
Weighted average trust units(5) 237.7 236.6 228.9 218.3
Trust units outstanding and
issuable(5) 238.1 237.1 236.0 219.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.0 5.0 2.8 3.7
Land 4.5 0.2 0.2 17.1
Drilling and completions 61 18.6 68.5 117.1
Plant and facilities 26.1 23.6 25.1 30.5
Other capital 1.6 1.5 0.6 1.0
Total capital expenditures 96.2 48.9 97.2 169.4
Property acquisitions (dispositions)
net (30.1) 2.3 6.2 27.6
Total capital expenditures and net
acquisitions 66.1 51.2 103.4 197.0
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 26,921 26,917 28,806 28,935
Natural gas (mmcf/d) 193.1 200.2 193.8 195.1
Natural gas liquids (bbl/d) 3,717 3,679 3,764 3,858
Total (boe per day 6:1) 62,824 63,969 64,872 65,313
Average prices
Crude oil ($/bbl) 67.74 62.74 46.44 56.26
Natural gas ($/mcf) 3.25 3.73 5.20 7.48
Natural gas liquids ($/bbl) 38.92 38.89 38.86 45.22
Oil equivalent ($/boe) 41.31 40.32 38.40 45.93
-------------------------------------------------------------------------
TRUST UNIT TRADING PRICES
(based on intra-day trading)
High 20.20 19.25 20.90 22.55
Low 15.48 14.12 11.73 15.01
Close 20.20 17.81 14.15 20.10
Average daily volume (thousands) 1,038 988 1,240 1,523
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 485.7 512.0 407.9 338.0
Per unit(1) 2.24 2.38 1.91 1.59
Cash flow from operating activities 251.4 273.4 209.9 173.7
Per unit - basic(1) 1.16 1.27 0.98 0.82
Per unit - diluted 1.16 1.27 0.98 0.82
Net income 311.7 57.3 81.3 106.3
Per unit - basic(2) 1.46 0.27 0.39 0.51
Per unit - diluted 1.46 0.27 0.39 0.51
Distributions 171.3 144.7 126.8 125.8
Per unit - basic(3) 0.80 0.68 0.60 0.60
Total assets 3,687.5 3,664.3 3,592.6 3,533.0
Total liabilities 1,530.8 1,689.6 1,560.4 1,491.3
Net debt outstanding(4) 773.2 756.1 770.1 752.7
Weighted average trust units(5) 216.6 215.2 213.8 212.5
Trust units outstanding and
issuable(5) 217.4 215.8 214.7 213.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 1.3 16.4 5.5 3.0
Land 18.6 57.8 28.8 42.6
Drilling and completions 91.4 32.6 64.4 75.2
Plant and facilities 24.2 24.1 11.6 17.9
Other capital 0.9 0.4 1.0 0.6
Total capital expenditures 136.4 131.3 111.3 139.3
Property acquisitions (dispositions)
net 13.1 0.3 10.1 5.0
Total capital expenditures and net
acquisitions 149.5 131.6 121.4 144.3
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,509 27,541 29,064 28,682
Natural gas (mmcf/d) 192.0 194.7 204.3 187.4
Natural gas liquids (bbl/d) 3,822 3,906 3,856 4,067
Total (boe per day 6:1) 64,325 63,896 66,976 63,989
Average prices
Crude oil ($/bbl) 114.20 118.32 89.72 77.53
Natural gas ($/mcf) 8.68 10.41 7.80 6.32
Natural gas liquids ($/bbl) 82.87 82.29 68.54 62.75
Oil equivalent ($/boe) 81.42 87.73 66.67 57.26
-------------------------------------------------------------------------
TRUST UNIT TRADING PRICES
(based on intra-day trading)
High 33.30 33.95 27.06 21.55
Low 22.33 25.19 20.00 18.90
Close 23.10 33.95 26.38 20.40
Average daily volume (thousands) 841 659 863 624
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(3) Based on number of trust units outstanding at each distribution date.
(4) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(5) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
CONSOLIDATED BALANCE SHEETS (unaudited)
As at September 30 and December 31
(Cdn$ millions) 2009 2008
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents (Note 3) $ - $ 40.0
Accounts receivable (Note 4) 104.3 110.0
Prepaid expenses 19.3 16.8
Risk management contracts (Note 8) 5.0 24.4
Future income taxes 6.4 3.9
-------------------------------------------------------------------------
135.0 195.1
Reclamation funds 31.8 28.2
Risk management contracts (Note 8) 3.6 9.2
Property, plant and equipment 3,314.9 3,376.6
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,642.9 $ 3,766.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 168.3 $ 194.4
Distributions payable 23.6 32.5
Risk management contracts (Note 8) 12.1 23.5
-------------------------------------------------------------------------
204.0 250.4
Risk management contracts (Note 8) 1.3 3.4
Long-term debt (Note 5) 637.1 901.8
Accrued long-term incentive compensation (Note 13) 8.3 14.2
Asset retirement obligations (Note 6) 145.6 141.5
Future income taxes 282.1 313.3
-------------------------------------------------------------------------
Total liabilities 1,278.4 1,624.6
-------------------------------------------------------------------------
NON-CONTROLLING INTEREST
Exchangeable shares (Note 9) 37.8 42.4
UNITHOLDERS' EQUITY
Unitholders' capital (Note 10) 2,900.3 2,600.7
Deficit (Note 11) (573.2) (502.9)
Accumulated other comprehensive (loss)
income (Note 11) (0.4) 1.9
-------------------------------------------------------------------------
Total unitholders' equity 2,326.7 2,099.7
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,642.9 $ 3,766.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For the three and nine months ended September 30
Three Months Ended Nine Months Ended
(Cdn$ millions, except September 30 September 30
per unit amounts) 2009 2008 2009 2008
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and
natural gas liquids $ 239.2 $ 485.7 $ 699.6 $ 1,405.6
Royalties (37.7) (88.8) (102.2) (252.8)
-------------------------------------------------------------------------
201.5 396.9 597.4 1,152.8
Gain (loss) on risk
management contracts
(Note 8)
Realized 6.7 (34.3) 21.1 (108.5)
Unrealized (0.7) 187.5 (7.9) 26.0
-------------------------------------------------------------------------
207.5 550.1 610.6 1,070.3
-------------------------------------------------------------------------
EXPENSES
Transportation 4.8 4.8 15.3 13.8
Operating 55.9 60.2 179.2 180.8
General and administrative 15.9 3.5 38.5 47.2
Provision for non-
recoverable accounts
receivable (Note 4) (0.4) - (0.4) 18.0
Interest and financing
charges (Note 5) 6.4 7.8 19.8 24.9
Depletion, depreciation
and accretion 95.7 93.4 290.3 283.4
(Gain) loss on foreign
exchange (34.9) 16.3 (60.3) 28.1
-------------------------------------------------------------------------
143.4 186.0 482.4 596.2
-------------------------------------------------------------------------
Capital and other taxes (0.2) - (0.2) -
Future income tax recovery
(expense) 5.7 (48.4) 30.9 (17.8)
-------------------------------------------------------------------------
Net income before non-
controlling interest 69.6 315.7 158.9 456.3
Non-controlling interest
(Note 9) (0.7) (4.0) (1.6) (6.0)
-------------------------------------------------------------------------
Net income $ 68.9 $ 311.7 $ 157.3 $ 450.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of
period $ (571.5) $ (598.8) $ (502.9) $ (465.9)
Distributions paid or
declared (Note 12) (70.6) (171.3) (227.6) (442.8)
-------------------------------------------------------------------------
Deficit, end of period
(Note 11) $ (573.2) $ (458.4) $ (573.2) $ (458.4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per unit
(Note 10)
Basic $ 0.29 $ 1.46 $ 0.68 $ 2.12
Diluted $ 0.29 $ 1.46 $ 0.68 $ 2.12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME (unaudited)
For the three and nine months ended September 30
Three Months Ended Nine Months Ended
September 30 September 30
(Cdn$ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
Net income $ 68.9 $ 311.7 $ 157.3 $ 450.3
Other comprehensive
income (loss), net of tax
Losses on financial
instruments designated
as cash flow hedges(1) (0.5) (0.8) (3.4) (2.8)
De-designation of cash
flow hedge(2) (Note 8) - - - 10.0
Gains and losses on
financial instruments
designated as cash flow
hedges in prior periods
realized in net income
in the current period(3)
(Note 8) 0.2 (0.5) 0.8 (2.0)
Net unrealized gains
(losses) on available-
for-sale reclamation
funds' investments(4) 0.5 (0.1) 0.3 (0.1)
-------------------------------------------------------------------------
Other comprehensive income
(loss) 0.2 (1.4) (2.3) 5.1
-------------------------------------------------------------------------
Comprehensive income $ 69.1 $ 310.3 $ 155.0 $ 455.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other comp-
rehensive (loss) income,
beginning of period (0.6) 3.6 1.9 (2.9)
Other comprehensive income
(loss) 0.2 (1.4) (2.3) 5.1
-------------------------------------------------------------------------
Accumulated other comp-
rehensive (loss) income,
end of period (Note 11) $ (0.4) $ 2.2 $ (0.4) $ 2.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts are net of tax of $0.2 million and $1.2 million,
respectively, for the three months and nine months ended September
30, 2009 (net of tax of $0.3 million and $1 million, respectively,
for the three and nine months ended September 30, 2008).
(2) Amount is net of tax of $3.6 million for the nine months ended
September 30, 2008.
(3) Amounts are net of tax of $0.1 million and $0.3 million,
respectively, for the three and nine months ended September 30, 2009
(net of tax of $0.2 million and $0.7 million, respectively, for the
three and nine months ended September 30, 2008).
(4) Amounts are net of tax of $0.2 million and $0.1 million,
respectively, for the three and nine months ended September 30, 2009
(nominal future income tax impact for the three and nine months ended
September 30, 2008).
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and nine months ended September 30
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
(Cdn$ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 68.9 $ 311.7 $ 157.3 $ 450.3
Add items not involving
cash:
Non-controlling interest
(Note 9) 0.7 4.0 1.6 6.0
Future income tax
(recovery) expense (5.7) 48.4 (30.9) 17.8
Depletion, depreciation
and accretion 95.7 93.4 290.3 283.4
Non-cash loss (gain) on
risk management con-
tracts (Note 8) 0.7 (187.5) 7.9 (26.0)
Non-cash (gain) loss on
foreign exchange (34.9) 15.5 (60.2) 26.9
Non-cash trust unit
incentive compensation
(recovery) expense
(Note 13) (0.6) (6.9) (4.1) 5.1
Expenditures on site
restoration and reclamation
(Note 6) (1.0) (1.8) (3.9) (7.8)
Change in non-cash working
capital 1.8 (25.4) (3.8) (20.9)
-------------------------------------------------------------------------
125.6 251.4 354.2 734.8
-------------------------------------------------------------------------
CASH FLOWS FROM FINANCING
ACTIVITIES
Repayment of long-term debt
under revolving credit
facilities, net (35.6) (6.6) (345.2) (45.6)
Issue of Senior Secured Notes - - 152.9 -
Repayment of Senior Secured
Notes - - (12.6) -
Issue of trust units 0.5 0.5 254.5 4.3
Trust unit issue costs (0.2) - (13.3) -
Cash distributions paid
(Note 12) (54.9) (132.5) (186.2) (341.2)
Change in non-cash working
capital 3.9 1.7 5.9 1.1
-------------------------------------------------------------------------
(86.3) (136.9) (144.0) (381.4)
-------------------------------------------------------------------------
CASH FLOWS FROM INVESTING
ACTIVITIES
Acquisition of petroleum and
natural gas properties (2.2) (13.1) (10.7) (23.6)
Proceeds on disposition of
petroleum and natural gas
properties 32.3 - 32.3 0.2
Capital expenditures (96.5) (137.6) (242.9) (378.0)
Net reclamation fund
contributions (2.3) (1.7) (3.1) (0.9)
Change in non-cash working
capital 29.4 37.9 (25.8) 41.9
-------------------------------------------------------------------------
(39.3) (114.5) (250.2) (360.4)
-------------------------------------------------------------------------
DECREASE IN CASH AND CASH
EQUIVALENTS - - (40.0) (7.0)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD - - 40.0 7.0
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ - $ - $ - $ -
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
September 30, 2009 and 2008
(all tabular amounts in Cdn$ millions, except per unit amounts)
1. SUMMARY OF ACCOUNTING POLICIES
The unaudited interim Consolidated Financial Statements follow the
same accounting policies as the most recent annual audited financial
statements, except as highlighted in Note 2. The interim Consolidated
Financial Statement note disclosures do not include all of those
required by Canadian generally accepted accounting principles
("GAAP") applicable for annual Consolidated Financial Statements.
Accordingly, these interim Consolidated Financial Statements should
be read in conjunction with the audited Consolidated Financial
Statements included in the Trust's 2008 annual report.
2. NEW ACCOUNTING POLICIES
Current Year Accounting Changes
Effective January 1, 2009, the Trust adopted Section 3064, Goodwill
and Intangible Assets issued by the Canadian Institute of Chartered
Accountants ("CICA"). Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. This new
section has no current impact on the Trust or its Consolidated
Financial Statements.
This standard was adopted prospectively.
Future Accounting Changes
A. Business Combinations
The CICA issued Handbook section 1582 "Business Combinations" that
replaces the previous business combinations standard. Under this
guidance, the purchase price used in a business combination is based
on the fair value of shares exchanged at the market price at
acquisition date. Under the current standard, the purchase price used
is based on the market price of shares for a reasonable period before
and after the date the acquisition is agreed upon and announced. In
addition, the guidance generally requires all acquisition costs to be
expensed. Current standards allow for the capitalization of these
costs as part of the purchase price. This new Section also addresses
contingent liabilities, which will be required to be recognized at
fair value on acquisition, and subsequently remeasured at each
reporting period until settled. Currently, standards require only
contingent liabilities that are payable to be recognized. The new
guidance requires negative goodwill to be recognized in earnings
rather than the current standard of deducting from non-current
assets in the purchase price allocation. This standard will be
effective for the Trust on January 1, 2011, with prospective
application.
B. Consolidated Financial Statements and Non-controlling Interest
The CICA issued Handbook Sections 1601 "Consolidated Financial
Statements", and 1602 "Non-controlling Interests", which replaces
existing guidance under Section 1600 "Consolidated Financial
Statements". Section 1601 establishes standards for the preparation
of Consolidated Financial Statements. Section 1602 provides guidance
on accounting for a non-controlling interest in a subsidiary in
Consolidated Financial Statements subsequent to a business
combination. These standards will be effective for the Trust for
business combinations occurring on or after January 1, 2011.
C. Financial Instruments - Disclosures
The CICA issued amendments to Handbook Section 3862, Financial
Instruments - Disclosures. The amendments include enhanced
disclosures related to the fair value of financial instruments and
the liquidity risk associated with financial instruments. The
amendments will be effective for annual financial statements for
fiscal years ending after September 30, 2009. The amendments are
consistent with recent amendments to financial instrument disclosure
standards in International Financial Reporting Standards "IFRS". The
Trust will include these additional disclosures in its annual
Consolidated Financial Statements for the year ending December 31,
2009.
3. CASH AND CASH EQUIVALENTS
Cash equivalents are nil as at September 30, 2009 ($40 million in
Canadian Treasury Bills as at December 31, 2008).
4. FINANCIAL ASSETS AND CREDIT RISK
The majority of the credit exposure on accounts receivable at
September 30, 2009 pertains to accrued revenue for September 2009
production volumes. The Trust transacts with a number of oil and
natural gas marketing companies and commodity end users ("commodity
purchasers"). Commodity purchasers and marketing companies typically
remit amounts to the Trust by the 25th day of the month following
production. Joint interest receivables are typically collected within
one to three months following production. At September 30, 2009, no
one counterparty accounted for more than 25 per cent of the total
accounts receivable balance and the largest commodity purchaser
receivable balance is fully secured with Letters of Credit.
In the third quarter of 2009, the Trust recorded a recovery of $0.4
million for amounts received on balances previously included in the
Trust's allowance for doubtful accounts. The Trust's allowance for
doubtful accounts was $31.6 million as at September 30, 2009 and $32
million as at December 31, 2008. During the first nine months of 2009
the Trust did not record any additional provision for non-collectible
accounts receivable.
When determining whether amounts that are past due are collectable,
management assesses the credit worthiness and past payment history of
the counterparty, as well as the nature of the past due amount. ARC
considers all amounts greater than 90 days to be past due. As at
September 30, 2009, $6.9 million of accounts receivable are past due,
excluding amounts described above, all of which are considered to be
collectable.
Maximum credit risk is calculated as the total recorded value of cash
equivalents, accounts receivable, reclamation funds, and risk
management contracts at the balance sheet date.
5. LONG-TERM DEBT
---------------------------------------------------------------------
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility - Cdn$
denominated $ 213.4 $ 399.5
Syndicated credit facility - US$
denominated 54.7 240.6
Working capital facility 14.0 2.1
Senior secured notes
5.42% US$ Note 80.4 91.9
4.94% US$ Note 12.9 14.7
4.62% US$ Note 55.8 76.5
5.10% US$ Note 67.0 76.5
7.19% US$ Note 72.4 -
8.21% US$ Note 37.5 -
6.50% Cdn$ Note 29.0 -
---------------------------------------------------------------------
Total long-term debt
outstanding $ 637.1 $ 901.8
---------------------------------------------------------------------
---------------------------------------------------------------------
Revolving Credit Facilities
The Trust has an $800 million secured, annually extendible, financial
covenant-based syndicated credit facility. The Trust also has in
place a $25 million demand working capital facility. The working
capital facility is secured and is subject to the same covenants as
the syndicated credit facility.
Borrowings under the syndicated credit facility bear interest at bank
prime (2.25 per cent at September 30, 2009, four per cent at December
31, 2008) or, at the Trust's option, Canadian dollar bankers'
acceptances or U.S. dollar LIBOR loans, plus a stamping fee. At the
option of the Trust, the lenders will review the syndicated credit
facility each year and determine whether they will extend the
revolving period for another year. In the event that the credit
facility is not extended at any time before the maturity date, the
loan balance will become repayable on the maturity date. The maturity
date of the current syndicated credit facility is April 15, 2011. All
drawings under the facility are subject to stamping fees. These
stamping fees vary between a minimum of 60 basis points ("bps") to a
maximum of 110 bps.
As at September 30, 2009, the Trust had $1.9 million in letters of
credit ($2 million in 2008), no subordinated debt, and was in
compliance with all covenants.
The payment of principal and interest are allowable deductions in the
calculation of cash available for distribution to unitholders and
rank ahead of cash distributions payable to unitholders. Should the
properties securing this debt generate insufficient revenue to repay
the outstanding balances, the unitholders have no direct liability
Senior Secured Notes
The fair value of senior secured notes as at September 30, 2009, is
$349.3 million ($289.9 million as at December 31, 2008), and is
calculated as the present value of principal and interest payments
discounted at the Trust's credit adjusted risk free rate.
Supplemental disclosures
Amounts of US$16.4 million due under the senior secured notes and
$14 million due under the Trust's working capital facility in the
next 12 months have not been included in current liabilities as
Management has the ability and intent to refinance this amount
through the syndicated credit facility.
Interest paid during the third quarter of 2009 was $4.8 million less
than interest expense (equal in the third quarter of 2008).
During the third quarter of 2009, the weighted-average interest rate
under the credit facility was 0.9 per cent (3.6 per cent in 2008) and
1.2 per cent for the nine months ended September 30, 2009 (four per
cent in 2008).
At September 30, 2009, the Trust had approximately $680 million of
total unused credit available.
The Trust's total long-term debt is secured in the form of a floating
charge on all lands and assignments and a negative pledge on
petroleum and natural gas properties.
6. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the Trust's asset retirement
obligations:
---------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 141.5 $ 140.0
Increase in liabilities relating to
development activities 0.5 2.0
Increase in liabilities relating to
change in estimate 0.5 2.6
Settlement of reclamation liabilities
during the period (3.9) (12.4)
Accretion expense 7.0 9.3
---------------------------------------------------------------------
Balance, end of period $ 145.6 $ 141.5
---------------------------------------------------------------------
---------------------------------------------------------------------
The Trust's weighted average credit adjusted risk free rate as at
September 30, 2009 was 6.5 per cent (6.6 per cent as at December 31,
2008).
7. CAPITAL MANAGEMENT
The Trust's objective when managing its capital is to maintain a
conservative structure that will allow the Trust to:
- Fund its development and exploration program;
- Provide financial flexibility to execute on strategic
opportunities;
- Maintain a level of distributions that, in normal times, in the
opinion of Management and the Board of Directors, is sustainable
for a minimum period of six months in order to normalize the
effect of commodity price volatility to unitholders; and
- Maintain a level of distributions which will transfer tax
liabilities to unitholders and minimize taxes paid by the Trust.
The Trust manages the following capital:
- Trust units and exchangeable shares;
- Long-term debt; and
- Working capital (defined as current assets less current
liabilities excluding risk management contracts and future income
taxes).
When evaluating the Trust's capital structure, management's objective
is to limit net debt to less than 2.0 times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
September 30, 2009 the Trust's net debt to annualized cash flow from
operating activities ratio is 1.5 and its net debt to total
capitalization ratio is 12.8 per cent.
---------------------------------------------------------------------
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Long-term debt 637.1 901.8
Accounts payable and accrued liabilities 168.3 194.4
Distributions payable 23.6 32.5
Cash and cash equivalents, accounts
receivable and prepaid expenses (123.6) (166.8)
---------------------------------------------------------------------
Net debt obligations(1) 705.4 961.9
---------------------------------------------------------------------
Trust units outstanding and issuable for
exchangeable shares (millions) 238.1 219.2
Trust unit price(2) 20.20 20.10
---------------------------------------------------------------------
Market capitalization(1) 4,809.6 4,405.9
Net debt obligations(1) 705.4 961.9
---------------------------------------------------------------------
Total capitalization(1) 5,515.0 5,367.8
---------------------------------------------------------------------
Net debt as a percentage of total
capitalization 12.8% 17.9%
Net debt obligations to annualized cash
flow from operating activities 1.5 1.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Market capitalization, net debt obligations and total
capitalization as presented do not have any standardized meaning
prescribed by Canadian GAAP and therefore may not be comparable
with the calculation of similar measures for other entities.
(2) TSX close price as at September 30, 2009 and December 31, 2008
respectively.
The Trust manages its capital structure and makes adjustments to it
in response to changes in economic conditions and the risk
characteristics of the underlying assets. The Trust is able to change
its capital structure by issuing new trust units, exchangeable
shares, new debt or changing its distribution policy.
In addition to internal capital management the Trust is subject to
various covenants under its credit facilities. Compliance with these
covenants is monitored on a quarterly basis and as at September 30,
2009 the Trust is in compliance with all covenants. Refer to Note 5
for further details.
8. MARKET RISK MANAGEMENT
The Trust is exposed to a number of market risks that are part of its
normal course of business. The Trust has a risk management program in
place that includes financial instruments as disclosed in the risk
management section of this note.
ARC's risk management program is overseen by its Risk Committee based
on guidelines approved by the Board of Directors. The objective of
the risk management program is to support the Trust's business plan
by mitigating adverse changes in commodity prices, interest rates and
foreign exchange rates.
In the sections below, ARC has prepared sensitivity analyses in an
attempt to demonstrate the effect of changes in these market risk
factors on the Trust's net income. For the purposes of the
sensitivity analyses, the effect of a variation in a particular
variable is calculated independently of any change in another
variable. In reality, changes in one factor may contribute to changes
in another, which may magnify or counteract the sensitivities. For
instance, trends have shown a correlation between the movement in the
foreign exchange rate of the Canadian dollar to the U.S. dollar and
the West Texas Intermediate posting ("WTI") crude oil price.
Commodity price risk
The Trust's operational results and financial condition, and
therefore the amount of distributions paid to unitholders, are
largely dependent on the commodity prices received for oil and
natural gas production. Commodity prices have fluctuated widely
during recent years due to global and regional factors including
supply and demand fundamentals, inventory levels, weather, economic,
and geopolitical factors. Movement in commodity prices could have a
significant positive or negative impact on distributions to
unitholders.
ARC manages the risks associated with changes in commodity prices by
entering into a variety of risk management contracts (see Risk
Management Contracts below). The following table illustrates the
effects of movement in commodity prices on net income due to changes
in the fair value of risk management contracts in place at September
30, 2009. The sensitivity is based on a $15 increase and $15 decrease
in the price of US$ WTI crude oil and a $2 increase and $2 decrease
in the price of Cdn$ AECO natural gas. The commodity price
assumptions are based on Management's assessment of reasonably
possible changes in oil and natural gas prices that could occur
between September 30, 2009 and the Trust's next reporting date.
---------------------------------------------------------------------
Increase in Commodity Price Decrease in Commodity Price
---------------------------------------------------------------------
($ millions) Crude oil Natural gas Crude oil Natural gas
---------------------------------------------------------------------
Net income
(decrease)
increase (12.2) (8.1) 18.1 14.4
---------------------------------------------------------------------
As noted above, the sensitivities are hypothetical and based on
Management's assessment of reasonably possible changes in commodity
prices between the balance sheet date and the Trust's next reporting
date. The results of the sensitivity should not be considered to be
predictive of future performance. Changes in the fair value of risk
management contracts cannot generally be extrapolated because the
relationship of change in certain variables to a change in fair value
may not be linear.
Interest Rate Risk
The Trust has both fixed and variable interest rates on its debt.
Changes in interest rates could result in a significant increase or
decrease in the amount the Trust pays to service variable interest
rate debt, potentially impacting distributions to unitholders.
Changes in interest rates could also result in fair value risk on the
Trust's fixed rate senior secured notes. Fair value risk of the
senior secured notes is mitigated due to the fact that the Trust does
not intend to settle its fixed rate debt prior to maturity.
If interest rates applicable to floating rate debt at September 30,
2009 were to have increased by 50 bps (0.5 per cent) it is estimated
that the Trust's net income would decrease by $1.1 million.
Management does not expect interest rates to decrease.
Foreign Exchange Risk
North American oil and natural gas prices are based upon U.S. dollar
denominated commodity prices. As a result, the price received by
Canadian producers is affected by the Canadian/U.S. dollar exchange
rate that may fluctuate over time. In addition the Trust has U.S.
dollar denominated debt of which future cash repayments are directly
impacted by the exchange rate in effect on the repayment date.
Variations in the Canadian/U.S. dollar exchange rate could also have
a significant positive or negative impact on distributions to
unitholders.
As at September 30, 2009 no risk management contracts pertaining to
foreign exchange were outstanding.
If foreign exchange rates applicable to U.S. denominated debt were to
have increased or decreased by $0.10Cdn$/US$ it is estimated that the
Trust's net income for the period ended September 30, 2009 would
decrease or increase by $27 million, respectively. Increases and
decreases in foreign exchange rates applicable to US$ payables and
receivables would have a nominal impact on the Trust's net income for
the period ended September 30, 2009.
Risk Management Contracts
The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices, foreign exchange rates,
interest rates and power prices. The Trust considers all of these
transactions to be effective economic hedges; however, the majority
of the Trust's contracts do not qualify as effective hedges for
accounting purposes.
Following is a summary of all risk management contracts in place as
at September 30, 2009 that do not qualify for hedge accounting:
---------------------------------------------------------------------
Financial WTI Crude Oil Option Contracts In Conjunction with 2005
Redwater and North Pembina Cardium Unit Acquisition(1)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
1-Oct-09 31-Dec-09 Put Spread 2,500 $55.00 $40.00 -
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------
Financial WTI Crude Oil Option Contracts(1)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
1-Oct-09 31-Dec-09 Collar 3,000 $70.00 - $82.50
1-Oct-09 31-Mar-10 Collar 1,000 $65.00 - $80.00
1-Jan-10 31-Dec-10 Collar 4,000 $70.00 - $90.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Monthly average
---------------------------------------------------------------------
Financial Cdn$ WTI Crude Oil Option Contracts(2)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d Cdn$/bbl Cdn$/bbl Cdn$/bbl
---------------------------------------------------------------------
1-Oct-09 31-Dec-09 Collar 2,000 $65.00 - $75.00
1-Oct-09 31-Dec-09 Collar 1,000 $70.00 - $80.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Monthly average
---------------------------------------------------------------------
Financial AECO Natural Gas Option Contracts(3)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
1-Oct-09 31-Oct-09 Collar 20,000 $4.00 - $4.75
1-Oct-09 31-Oct-09 Collar 20,000 $4.25 - $5.00
1-Oct-09 31-Dec-09 3-way collar 20,000 $6.50 $4.50 $8.00
1-Nov-09 31-Dec-09 Collar 10,000 $5.25 - $6.25
1-Nov-09 31-Dec-09 Collar 10,000 $4.50 - $5.81
1-Nov-09 31-Dec-09 Collar 5,000 $4.50 - $5.77
1-Nov-09 31-Dec-09 Collar 5,000 $4.50 - $5.80
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) AECO 7a monthly index
---------------------------------------------------------------------
Financial AECO Natural Gas Swap Contracts(4)
---------------------------------------------------------------------
Bought
Volume Swap Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
1-Oct-09 31-Oct-09 Covered Swap 20,000 $3.10 $6.00(5)
1-Oct-09 31-Oct-09 Covered Swap 10,000 $4.25 $6.00
1-Oct-09 31-Dec-09 Swap 10,000 $4.06 -
1-Nov-09 31-Dec-09 Swap 10,000 $4.25 -
1-Nov-09 31-Dec-09 Swap 20,000 $5.10 -
1-Jan-10 31-Dec-13 Swap 5,000 $6.80 -
---------------------------------------------------------------------
---------------------------------------------------------------------
(4) AECO 7a monthly index
(5) AECO 5a monthly index
---------------------------------------------------------------------
Energy Equivalent Swap
---------------------------------------------------------------------
Term Contract Volume Swap
---------------------------------------------------------------------
Financial AECO Natural
Gas Sales Contract(6)
1-Oct-09 31-Dec-09 Swap 10,000 GJ/d Cdn$ 4.67/GJ
Financial Cdn$ WTI Crude
Oil Purchase Contract(7)
1-Oct-09 31-Dec-09 Swap 650 bbl/d Cdn$ 71.95/bbl
---------------------------------------------------------------------
---------------------------------------------------------------------
(6) AECO 5a monthly index
(7) Monthly average
---------------------------------------------------------------------
Financial Basis Swap Contract(8)
---------------------------------------------------------------------
Volume Basis Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
1-Oct-09 31-Oct-10 Basis Swap-L3d 50,000 ($1.0430)
1-Nov-10 31-Oct-11 Basis Swap-Ld 15,000 ($0.4850)
1-Nov-11 31-Oct-12 Basis Swap-Ld 15,000 ($0.4067)
---------------------------------------------------------------------
---------------------------------------------------------------------
(8) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO 7a
monthly index
---------------------------------------------------------------------
Financial Electricity Heat Rate Contracts(9)
---------------------------------------------------------------------
Heat
Volume AESO Power AECO 5(a) multiplied Rate
Term Contract MWh $/MWh $/GJ by GJ/MWh
---------------------------------------------------------------------
1-Jan-10 Heat Rate Receive Pay AECO
31-Dec-13 Swap 5 AESO 5(a) x 9.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(9) Alberta Power Pool (monthly average 24x7), AECO 5a monthly
index
---------------------------------------------------------------------
Financial Electricity Contracts(10)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Oct-09
31-Dec-12 Swap 5 $72.495
---------------------------------------------------------------------
---------------------------------------------------------------------
(10) Alberta Power Pool (monthly average 24x7)
Following is a summary of all risk management contracts in place as
at September 30, 2009 that qualify for hedge accounting:
Financial Electricity Contracts(11)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Oct-09
31-Dec-09 Swap 15 $59.33
1-Jan-10
31-Dec-10 Swap 5 $63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(11) Alberta Power Pool (monthly average 24x7)
At September 30, 2009, the fair value of the contracts that were not
designated as accounting hedges was a loss of $4.5 million. The Trust
recorded a gain on risk management contracts of $13.2 million in the
statement of income for the nine months ended September 30, 2009
($82.5 million loss in 2008). This amount includes the realized and
unrealized gains and losses on risk management contracts that do not
qualify as effective accounting hedges.
The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have not been
designated as effective accounting hedges:
---------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30, September 30,
2009 2008
---------------------------------------------------------------------
Fair value, beginning of period $ 3.4 $ (64.6)
Fair value, end of period(1) (4.5) (38.6)
---------------------------------------------------------------------
Change in fair value of contracts
in the period (7.9) 26.0
Realized gain (loss) in the period 21.1 (108.5)
---------------------------------------------------------------------
Gain (loss) on risk management
contracts $ 13.2 $ (82.5)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $8.6 million at
September 30, 2009 ($24.7 million loss at September 30, 2008).
During 2007 the Trust entered into treasury rate lock contracts in
order to manage the Trust's interest rate exposure on future debt
issuances. During 2008 it was determined that the previously
anticipated debt issuance was no longer expected to occur and the
associated treasury rate lock contracts were unwound at a loss of
$13.6 million. The loss was reclassified from Other Comprehensive
Income ("OCI"), net of tax $10 million and recognized in net income.
The Trust's electricity contracts are intended to manage price risk
on electricity consumption. Portions of the Trust's financial
electricity contracts were designated as effective accounting hedges
on their respective contract dates. A realized loss of $0.3 million
and $1.1 million for the three and nine months ended September 30,
2009 (gain of $0.7 million and $2.8 million respectively in 2008) has
been included in operating costs on these electricity contracts. The
accumulated unrealized fair value loss of $0.3 million on these
contracts has been recorded on the Consolidated Balance Sheet at
September 30, 2009 with the movement in fair value recorded in OCI,
net of tax. The fair value movement for the nine months ended
September 30, 2009 is an unrealized loss of $3.6 million. As at
September 30, 2009 $0.2 million of the unrealized fair value loss is
attributed to contracts that will settle over the next twelve months.
The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have been designated
as effective accounting hedges:
---------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30, September 30,
2009 2008
---------------------------------------------------------------------
Fair value, beginning of period $ 3.3 $ (3.4)
Change in fair value of financial
electricity contracts (3.6) (0.4)
Change in fair value of treasury
rate lock contracts prior to
de-designation - (6.2)
Reclassification of loss on treasury
rate lock contracts to net income - 13.6
---------------------------------------------------------------------
Fair value, end of period(1) $ (0.3) $ 3.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts designated as
effective accounting hedges equals a loss of $0.3 million at
September 30, 2009 ($3.6 million gain at September 30, 2008).
All of the Trust's risk management contracts are transacted in liquid
markets; fair values are determined using a valuation model based on
published, third party, and market based price and rate information.
9. EXCHANGEABLE SHARES
---------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, December 31,
(units thousands) 2009 2008
---------------------------------------------------------------------
Balance, beginning of period 1,092 1,310
Exchanged for trust units(1) (159) (218)
---------------------------------------------------------------------
Balance, end of period 933 1,092
Exchange ratio, end of period 2.67944 2.51668
Trust units issuable upon conversion,
end of period 2,500 2,748
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first nine months of 2009, 159,291 ARL exchangeable
shares were converted to trust units at an average exchange ratio
of 2.55449, compared to 218,455 exchangeable shares at an average
exchange ratio of 2.36901 during the year ended 2008.
Following is a summary of the non-controlling interest for 2009 and
2008:
---------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Non-controlling interest,
beginning of period $ 42.4 $ 43.1
Reduction of book value for
conversion to trust units (6.2) (7.6)
Current period net income
attributable to non-controlling
interest 1.6 6.9
---------------------------------------------------------------------
Non-controlling interest, end of
period 37.8 42.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated earnings attributable
to non-controlling interest $ 42.6 $ 41.0
---------------------------------------------------------------------
---------------------------------------------------------------------
10. UNITHOLDERS' CAPITAL
---------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Number of Number of
trust trust
(units thousands) units $ units $
---------------------------------------------------------------------
Balance, beginning of period 216,435 2,600.7 210,232 2,465.7
Issued for cash 15,474 253.0 - -
Issued on conversion of ARL
exchangeable shares (Note 9) 407 6.2 517 7.6
Issued on exercise of employee
rights - - 238 4.2
Distribution reinvestment
program 3,335 51.7 5,448 123.2
Trust unit issue costs, net of
tax(1) - (11.3) - -
---------------------------------------------------------------------
Balance, end of period 235,651 2,900.3 216,435 2,600.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount is net of tax of $2 million for the period ended September
30, 2009.
Net income per trust unit has been determined based on the following:
---------------------------------------------------------------------
Three Nine
Months Ended Months Ended
September 30 September 30
---------------------------------------------------------------------
(units thousands) 2009 2008 2009 2008
---------------------------------------------------------------------
Weighted average trust units(1) 235,182 213,859 231,976 212,480
Trust units issuable on conversion
of exchangeable shares(2) 2,500 2,727 2,500 2,727
Dilutive impact of rights(3) - 2 - 65
---------------------------------------------------------------------
Diluted trust units and
exchangeable shares 237,682 216,588 234,476 215,272
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average trust units exclude trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the year-end exchange ratio.
(3) There are no rights outstanding as of September 30, 2009 and
therefore, no dilutive impact. Previously outstanding rights were
dilutive and therefore were included in the diluted unit
calculation for 2008.
Basic net income per unit has been calculated based on net income
after non-controlling interest divided by weighted average trust
units. Diluted net income per unit has been calculated based on net
income before non-controlling interest divided by diluted trust
units.
11. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME
---------------------------------------------------------------------
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Accumulated earnings $ 2,881.4 $ 2,724.1
Accumulated distributions (3,454.6) (3,227.0)
---------------------------------------------------------------------
Deficit $ (573.2) $ (502.9)
Accumulated other comprehensive
(loss) income (0.4) 1.9
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive (loss) income $ (573.6) $ (501.0)
---------------------------------------------------------------------
---------------------------------------------------------------------
The accumulated other comprehensive (loss) income balance is composed
of the following items:
---------------------------------------------------------------------
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Unrealized gains and losses on
financial instruments designated
as cash flow hedges $ (0.5) $ 2.0
Net unrealized gains and losses on
available-for-sale reclamation
funds' investments 0.1 (0.1)
---------------------------------------------------------------------
Accumulated other comprehensive
(loss) income, end of period $ (0.4) $ 1.9
---------------------------------------------------------------------
---------------------------------------------------------------------
12. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS
Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operating activities is
reduced by reclamation fund contributions including interest earned
on the funds, a portion of capital expenditures and, when applicable,
debt repayments. The portion of cash flow from operating activities
withheld to fund capital expenditures and to make debt repayments is
at the discretion of the Board of Directors.
Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
---------------------------------------------------------------------
Cash flow from
operating activities $ 125.6 $ 251.4 $ 354.2 $ 734.8
Deduct:
Cash withheld to fund
current period
capital expenditures (52.7) (78.4) (123.5) (291.1)
Net reclamation fund
contributions (2.3) (1.7) (3.1) (0.9)
---------------------------------------------------------------------
Distributions(1) 70.6 171.3 227.6 442.8
Accumulated
distributions,
beginning of period 3,384.0 2,928.5 3,227.0 2,657.0
---------------------------------------------------------------------
Accumulated
distributions, end of
period $ 3,454.6 $ 3,099.8 $ 3,454.6 $ 3,099.8
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per
unit(2) $ 0.30 $ 0.80 $ 0.98 $ 2.08
Accumulated
distributions per unit,
beginning of period $ 24.38 $ 22.31 $ 23.70 $ 21.03
Accumulated
distributions per unit,
end of period(3) $ 24.68 $ 23.11 $ 24.68 $ 23.11
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include accrued and non-cash amounts of
$15.6 million and $41.3 million for the three and nine months
ended September 30, 2009 ($39 million and $102 million for the
same periods in 2008).
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of the Trust in July 1996.
13. WHOLE TRUST UNIT INCENTIVE PLAN
Compensation expense associated with the Whole Trust Unit Incentive
Plan ("the Whole Unit Plan") is granted in the form of Restricted
Trust Units ("RTUs") and Performance Trust Units ("PTUs") and is
determined based on the intrinsic value of the Whole Trust Units at
each period end.
The Trust recorded non-cash compensation recovery of $4 million and
$0.1 million to general and administrative and operating expenses,
respectively, and capitalized $0.7 million to property, plant and
equipment in the nine months ended September 30, 2009 for the
estimated change in the Plan liability ($4.6 million, $0.5 million,
and $1.1 million for the nine months ended September 30, 2008). The
non-cash compensation recovery was based on the September 30, 2009
unit price of $20.20 ($23.10 at September 30, 2008), accrued
distributions, a performance multiplier, and the estimated number of
units to be issued on maturity.
The following table summarizes the RTU and PTU movement for the nine
months ended September 30, 2009:
---------------------------------------------------------------------
Number of RTUs Number of PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 756 959
Granted 697 634
Vested (355) (262)
Forfeited (43) (24)
---------------------------------------------------------------------
Balance, end of period 1,055 1,307
---------------------------------------------------------------------
---------------------------------------------------------------------
The change in the net accrued long-term incentive compensation
liability relating to the Whole Trust Unit Incentive Plan can be
reconciled as follows:
---------------------------------------------------------------------
September 30, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 31.9 $ 30.3
Change in net liabilities in the
period
General and administrative expense (4.0) 1.1
Operating expense (0.1) (0.1)
Property, plant and equipment (0.7) 0.6
---------------------------------------------------------------------
Balance, end of period (1) $ 27.1 $ 31.9
---------------------------------------------------------------------
Current portion of liability (2) 19.3 18.8
---------------------------------------------------------------------
Accrued long-term incentive
compensation $ 8.3 $ 14.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $0.5 million of recoverable amounts recorded in accounts
receivable as at September 30, 2009 ($1.1 million for 2008).
(2) Included in Accounts payable and accrued liabilities on the
Consolidated Balance Sheet.
During the first nine months of 2009, cash payments of $16.6 million
were made to employees relating to the Whole Unit Plan compared to
$18.3 million in 2008. In October 2008, vesting periods were revised
from April and October to March and September of each year
commencing in 2009.
Boe conversion ratio for natural gas of 6 mcf: 1 bbl has been used,
which is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and
statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans", "intends",
"strategy" and similar expressions are intended to identify forward-looking
information or statements. In particular, but without limiting the foregoing,
this news release contains forward-looking information and statements
pertaining to the following: the volumes and estimated value of ARC's oil and
gas reserves; the life of ARC's reserves; the volume and product mix of ARC's
oil and gas production; future oil and natural gas prices and ARC's commodity
risk management programs; the amount of future asset retirement obligations;
future liquidity and financial capacity; future results from operations and
operating metrics; future costs, expenses and royalty rates; future interest
costs; future development, exploration, acquisition and development activities
(including drilling plans) and related capital expenditures, future tax
treatment of income trusts and future taxes payable by ARC; and ARC's tax
pools.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
ARC including, without limitation: that ARC will continue to conduct its
operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing (and
in certain circumstances, the implementation of proposed) tax, royalty and
regulatory regimes; the accuracy of the estimates of ARC's reserve and
resource volumes; certain commodity price and other cost assumptions; and the
continued availability of adequate debt and equity financing and cash flow to
fund its planned expenditures; ARC believes the material factors, expectations
and assumptions reflected in the forward-looking information and statements
are reasonable but no assurance can be given that these factors, expectations
and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
changes in the demand for or supply of ARC's products; unanticipated operating
results or production declines; changes in tax or environmental laws, royalty
rates or other regulatory matters; changes in development plans of ARC or by
third party operators of ARC's properties, increased debt levels or debt
service requirements; inaccurate estimation of ARC's oil and gas reserve and
resource volumes; limited, unfavorable or a lack of access to capital markets;
increased costs; a lack of adequate insurance coverage; the impact of
competitors; and certain other risks detailed from time to time in ARC's
public disclosure documents (including, without limitation, those risks
identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news
release speak only as of the date of this news release, and none of ARC or its
subsidiaries assumes any obligation to publicly update or revise them to
reflect new events or circumstances, except as may be required pursuant to
applicable laws.
ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with a current enterprise value of approximately $5.4 billion.
The Trust expects 2009 oil and gas production to average 63,000 to 64,000 of
barrels of oil equivalent per day from six core areas in western Canada. ARC
Energy Trust units trade on the TSX under the symbol AET.UN and ARC Resources
exchangeable shares trade under the symbol ARX. ARC Energy Trust trades on the
TSX under the symbol AET.UN and its exchangeable shares trade under the symbol
ARX.
ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer
>>
%SEDAR: 00001245E %CIK: 0001029509
For further information: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., 2100, 440 - 2nd Avenue S.W., Calgary, AB T2P 5E9 www.arcenergytrust.com