ARC Energy Trust announces fourth quarter and year-end 2009 results
Feb 9, 2010
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Three Months Ended Twelve Months Ended
For the years ended December 31 December 31
December 31 2009 2008 2009 2008
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FINANCIAL
(Cdn$ millions, except per
unit and per boe amounts)
Revenue before royalties 278.6 300.8 978.2 1,706.4
Per unit(1) 1.17 1.38 4.16 7.90
Per boe 48.44 50.06 42.18 71.59
Cash flow from operating
activities(2) 143.2 209.4 497.4 944.4
Per unit(1) 0.60 0.96 2.11 4.37
Per boe 24.90 34.85 21.45 39.62
Net income 65.5 82.7 222.8 533.0
Per unit(3) 0.28 0.38 0.96 2.50
Distributions 70.9 127.2 298.5 570.0
Per unit(1) 0.30 0.59 1.28 2.67
Per cent of cash flow
from operating
activities(2) 50 61 60 60
Net debt outstanding(4) 902.4 961.9 902.4 961.9
OPERATING
Production
Crude oil (bbl/d) 27,415 28,935 27,509 28,513
Natural gas (mmcf/d) 189.0 195.1 194.0 196.5
Natural gas liquids (bbl/d) 3,597 3,858 3,689 3,861
Total (boe/d) 62,520 65,313 63,538 65,126
Average prices
Crude oil ($/bbl) 72.61 56.26 62.24 94.20
Natural gas ($/mcf) 4.58 7.48 4.18 8.58
Natural gas liquids ($/bbl) 46.12 45.22 40.67 69.71
Oil equivalent ($/boe) 48.35 49.93 42.07 71.25
Operating netback ($/boe)
Commodity and other
revenue (before hedging) 48.42 50.06 42.17 71.59
Transportation costs (0.92) (0.86) (0.89) (0.80)
Royalties (7.94) (9.14) (6.37) (12.91)
Operating costs (9.91) (10.09) (10.19) (10.13)
Netback (before hedging) 29.65 29.97 24.72 47.75
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TRUST UNITS
(millions)
Units outstanding, end of
period(5) 239.0 219.2 239.0 219.2
Weighted average trust
units(6) 238.5 218.3 235.4 216.0
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TRUST UNIT TRADING STATISTICS
(Cdn$, except volumes) based
on intra-day trading
High 21.89 22.55 21.89 33.95
Low 19.06 15.01 11.73 15.01
Close 19.94 20.10 19.94 20.10
Average daily volume
(thousands) 963 1,523 1,057 975
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(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 fourth quarter of 2009 would be $156 million
($0.65 per unit) and for the full year 2009 would be $518 million
($2.20 per unit). Distributions as a percentage of Cash Flow would be
58 per cent in 2009.
(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) For 2009, includes 0.9 million (1.1 million in 2008) exchangeable
shares exchangeable into 2.720 trust units (2.517 in 2008) each for
an aggregate 2.4 million (2.7 million in 2008) trust units.
(6) Includes trust units issuable for outstanding exchangeable shares at
period end.
ACCOMPLISHMENTS / FINANCIAL UPDATE
- ARC replaced 347 per cent of annual production at an all-in annual
Finding, Development and Acquisition ("FD&A") cost of $6.44 per
barrel of oil equivalent ("boe") before consideration of future
development capital ("FDC") for the proved plus probable reserves
category. This is the third consecutive year of reducing FD&A costs
and brings ARC's three year average FD&A prior to FDC down to $9.57
per boe. FD&A costs including FDC were $11.57 per boe, a 32 per cent
reduction from the $17 per boe achieved in 2008. Additional
information on the reserves evaluation can be found in the "ARC
Energy Trust Releases 2009 Year-end Reserves Information" news
release dated February 9, 2010 and filed on SEDAR at www.sedar.com.
- During the fourth quarter, ARC completed an acquisition for $180
million in cash consideration, prior to normal closing adjustments,
of a partnership owning properties in the Ante Creek area. The
acquisition consisted of producing wells with production of
approximately 2,000 boe per day and undeveloped land holdings. The
acquisition closed on December 21, 2009 therefore the financial
results from the properties have been included in Consolidated
Financial Statements from that date.
- Concurrent with the Ante Creek acquisition, ARC entered into a bought
deal financing agreement to issue 13 million trust units at $19.40
per trust unit to raise gross proceeds of approximately $252 million
and net proceeds of approximately $240 million. The net proceeds of
the offering were received on January 5, 2010 and were used to reduce
the outstanding indebtedness of ARC by $240 million.
- Production volumes for 2009 averaged 63,538 boe per day, a 2.4 per
cent decline compared to 2008 production of 65,126 boe per day. This
decline was due to ARC's reduction of its 2009 capital expenditures
in response to declining commodity prices. The Trust expects 2010
full year average production to increase by approximately 13 per cent
to between 70,500 and 72,500 boe per day with the anticipated start-
up of a company-owned gas plant in the Dawson area in the second
quarter of 2010 and a full year of production from the December 2009
acquisition in Ante Creek.
- Cash flow from operating activities for the full year of 2009 was
$497.4 million, or $2.11 per unit, a significant decline from the
$944.4 million ($4.37 per unit) achieved in fiscal 2008. This decline
was primarily due to a 41 per cent decrease in commodity prices in
2009 compared to 2008. Crude oil prices strengthened in the second
half of 2009 as the economy showed some positive signs of recovery.
Natural gas prices remained soft throughout most of 2009 prior to
recovering somewhat late in the fourth quarter of 2009 ending the
year at $5.70 per mcf. After payment of distributions the Trust was
able to fund 54 per cent of the 2009 capital program with cash flow
from operating activities (73 per cent when including the proceeds
from the distributions re-investment program ("DRIP")) with the
remaining portion funded through debt and working capital.
- The Trust executed a $359.6 million capital expenditure program in
2009 that included the purchase of undeveloped land for $7 million
and $352.6 million of exploration and development activities. A total
of 120 net wells were drilled on ARC's operated properties with a 99
per cent success rate. Included in these capital expenditures is $8.1
million of Alberta Government royalty drilling credits and $3.1
million for British Columbia summer drilling credits. Without these
credits, total capital expenditures would have been $370.8 million.
- ARC's Board of Directors has approved a $610 million capital program
for 2010 that will deliver considerable growth. The program will
include over $264 million slated for the first of many stages of
production growth and expansion of the Montney assets in Northeast
British Columbia. Other major resource play development will take
place at Ante Creek where $72 million has been allocated to drill 14
horizontal wells and expand facilities and at Pembina where $54
million will be spent to drill 16 horizontal wells and 16 vertical
wells targeting the Cardium formation on operated lands. The
remainder of the budget will focus on ARC's base development areas,
exploration opportunities and enhanced oil recovery projects. In
total, ARC plans to drill 211 gross wells on operated properties and
participate in an additional 91 wells on partner operated properties.
ARC plans to finance the 2010 capital program through a combination
of cash flow, existing credit facilities, DRIP proceeds and potential
minor asset disposition proceeds.
- On December 31, 2009, ARC's long-term debt was $846 million. After
the closing of the equity offering on January 5, 2010, long-term debt
was reduced to $606 million leaving ARC with approximately $710
million of unused credit lines. With the current debt level, net debt
to 2009 cash flow from operating activities is 1.2 times. At current
forward prices for commodities, ARC is well positioned to finance the
projected 2010 capital program of $610 million and payout $0.10 per
trust unit per month of distributions while keeping debt at a very
manageable level.
- ARC has hedged approximately 43,000 mcf per day of natural gas for
the period of July 1, 2011 to December 31, 2013 at an average price
of $6.40 per mcf to protect the economics on the ARC owned gas plant
being constructed at Dawson. Overall, commodity price volatility
protection has been established for the 2010 capital budget by
hedging 34 per cent of forecast natural gas volumes at an average
swap price of $5.85 per mcf and 32 per cent of forecast crude oil
volumes at an average floor price of US$74.67 per barrel.
- ARC plans to convert to a dividend paying corporation effective
January 1, 2011. The Board of Directors has approved the overall
strategy and currently the detailed implementation steps are being
defined. The conversion plans will be mailed to unitholders with a
unitholder meeting planned for December of 2010. Current plans would
see a dividend policy similar to the existing distribution policy
with dividends being paid monthly.
- Montney Resource Play Development
Production from the Dawson area was on budget at an average rate of
53.6 mmcf per day throughout the fourth quarter and exited the year
at 59.2 mmcf per day.
During the fourth quarter of 2009, ARC spent $70.8 million on
development activities in the Dawson area including drilling seven
horizontal wells, two of which were completed during the quarter. ARC
tested six horizontal Dawson wells during the quarter at rates
between five and nine mmcf per day of natural gas at a flowing
pressure of 1,200 to 2,200 pounds per square inch. Included in the
fourth quarter spending is $27.8 million for the Dawson Phase 1 60
mmcf per day gas plant discussed below.
For the full year of 2009, ARC drilled 22 horizontal wells in the
Dawson gas fields that are in various stages of completion. Of
these wells, eight were on production by year-end, nine wells are in
the completed and waiting on tie-in category and the remaining five
wells will be completed early in 2010.
ARC is participating in a small development project on partner
operated lands at Sunrise. Four wells have been drilled and
completed. Production commenced at the end of the fourth quarter and
is currently producing at approximately 10 mmcf per day net to ARC's
50 per cent working interest.
The British Columbia Oil and Gas Commission ("OGC") issued final
approval for the 60 mmcf per day Dawson Phase 1 gas plant on November
13, 2009 at which time all on-site construction began. As of January
31, 2010, the mechanical construction of the plant was approximately
70 per cent complete and the electrical work was underway. ARC
expects to complete construction of the plant in early April, with
start-up commissioning of the plant occurring during the rest of the
month. Sales gas is expected to be flowing from the plant by early
May. To date, ARC has spent $57.6 million on the gas plant with an
additional $5.7 million expected to be spent in 2010 prior to the
commissioning. ARC is already well underway with plans to build a
second 60 mmcf per day gas plant at the same location. All long-lead
time equipment has been ordered and the application to construct the
plant is being prepared.
- Enhanced Oil Recovery Initiatives
During 2009, ARC spent $25.7 million on enhanced oil recovery ("EOR")
initiatives and received $2.8 million in government funding for the
Redwater pilot project for net spending of $22.9 million. Work on the
Redwater CO(2) pilot project continues and both the CO(2) injection
and oil production facilities are operating as expected. Results to
date are encouraging but ARC anticipates that it will take until
later in 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 ARC'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 ARC management's analysis of its financial performance and significant trends or external factors that may affect future performance. The MD&A 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 ARC's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements" included at the end of this MD&A.
Executive Overview
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 major operating activities of ARC are the development, production and sale of crude oil, natural gas liquids and natural gas.
ARC's main objective is value creation through the development of large oil and natural gas pools. The business strategy and activities that support this objective are:
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Resource Plays
--------------
- Acquisition and development of land and producing properties with
large volumes of oil and gas in place, such as the Montney
development in Dawson in northeastern British Columbia, Ante Creek in
northern Alberta and the Cardium formation at Pembina in central
Alberta.
Conventional Oil & Gas Production
---------------------------------
- Maximizing production while controlling operating costs on oil and
gas wells located within ARC's seven core producing areas all of
which are located in western Canada. ARC's total production in 2009
was almost evenly split between commodities with 51 per cent of
production from natural gas and 49 per cent from oil and gas liquids.
Conventional oil and gas properties continue to be developed to
increase the recoverable reserves through development drilling,
optimization and waterflood programs. Within ARC's core areas many
properties would be considered "resource plays" due to the
substantial reserves still in place and the advancement of proved
horizontal drilling and multi-stage fracture stimulation technology
to develop these reserves.
- The periodic acquisition of strategic producing and undeveloped
properties to enhance current production or provide the potential for
future drilling locations and if successful, additional production
and reserves.
Enhanced Oil Recovery ("EOR")
-----------------------------
- Evaluation and implementation of enhanced oil recovery programs to
increase ARC's recoverable reserves in existing oil pools. ARC has a
non-operated interest in the Weyburn and Midale units in
Saskatchewan. Operators of both these units have implemented CO(2)
injection programs to increase recoverable oil reserves. In 2008 ARC
advanced this strategy of enhanced oil recovery with the initiation
of a CO(2) pilot program at Redwater.
>>
ARC's goal is to provide superior long-term returns to unitholders. ARC's structure provides returns to unitholders through both the receipt of monthly cash distributions and the potential for capital appreciation.
Currently, ARC distributes
Capital appreciation for ARC's unitholders would be associated with increased market values for ARC's production and reserves. ARC's management strives to replace or grow both production and reserves through drilling new wells and associated oil and natural gas development activities. The vast majority of the annual capital budget is being deployed on a balanced drilling program of low and moderate risk wells, well tie-ins and other related costs, and the acquisition of undeveloped land. ARC continues to focus on major properties with significant upside, with the objective to replace production declines through internal development opportunities. ARC's normalized reserves per unit have increased by 10 per cent to 1.57 per unit from 1.42 per unit in 2008 while production per thousand trust units decreased slightly from 0.29 to 0.27. Since year-end 2007, ARC has increased normalized reserves per unit by 16 per cent, and normalized production per thousand trust units has declined by 10 per cent while ARC has made distributions of
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Table 1
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Per Trust Unit 2009 2008 2007
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Normalized production per unit(1)(2) 0.27 0.29 0.30
Normalized reserves per unit(1)(3) 1.57 1.42 1.35
Distributions per unit $1.28 $2.67 $2.40
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(1) Normalized indicates that all periods as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional trust units were issued (or repurchased) at a period
end price for the reserves per unit calculation and at an annual
average price for the production per unit calculation in order to
achieve a net debt balance of 15 per cent of total capitalization
each year. The normalized amounts are presented to enable
comparability of per unit values.
(2) Production per unit represents daily average production (boe) per
thousand trust units and is calculated based on daily average
production divided by the normalized weighted average trust units
outstanding including trust units issuable for exchangeable shares.
(3) Reserves per unit are calculated based on proved plus probable
reserves (boe), as determined by ARC's independent reserve evaluator
at period end, divided by period end trust units outstanding
including trust units issuable for exchangeable shares.
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ARC's business plan has resulted in significant operational success as seen in Table 2 where ARC's trailing five year annualized return per unit was 12.4 per cent.
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Table 2
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Total Returns(1)
($ per unit except for Trailing Trailing Trailing
per cent) One Year Three Year Five Year
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Distributions per unit 1.28 6.35 10.74
Capital (depreciation) appreciation
per unit (0.16) (2.36) 2.04
Total return per unit 6.9% 20.0% 79.5%
Annualized total return per unit 6.9% 6.3% 12.4%
S&P/TSX Capped Energy Trust Index 43.5% 2.5% 9.1%
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(1) Calculated as at December 31, 2009.
Financial Highlights for the year-ended December 31, 2009
Table 3
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(Cdn $ millions, except
per unit and volume data) 2009 2008 % Change
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Cash flow from operating activities 497.4 944.4 (47)
Cash flow from operating activities
per unit(1) 2.11 4.37 (52)
Net income 222.8 533.0 (58)
Net income per unit(2) 0.96 2.50 (62)
Distributions per unit(3) 1.28 2.67 (52)
Distributions as a per cent of cash
flow from operating activities 60 60 -
Average daily production (boe/d)(4) 63,538 65,126 (2)
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(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 distribution
record 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.
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2009 Guidance and Financial Highlights
Table 4 is a summary of ARC's 2009 and 2010 Guidance and a review of 2009 actual results compared to guidance.
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Table 4
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2009 2009 2010
Guidance Actual % Variance Guidance
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Production (boe/d) 63,000- 63,538 - 70,500-
64,000 72,500
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Expenses ($/boe):
Operating costs 10.50 10.19 (3) 10.30
Transportation 0.90 0.89 (1) 1.00
G&A expenses (cash &
non-cash)(1) 2.10 2.26 8 2.85
Interest 1.30 1.11 (15) 1.40
Capital expenditures
($ millions) 365 360 (1) 610
Annual weighted average
trust units and trust
units issuable (millions)(2) 238 235 (1) 254
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(1) 2009 G&A guidance amount of $2.10 per boe included $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 the non-cash portion of the Whole Unit
Plan. 2010 G&A guidance amount of $2.85 per boe includes $2 per
boe for cash G&A costs, $0.90 per boe for cash Whole Unit Plan costs
and a recovery of $0.05 per boe for the non-cash portion of the Whole
Unit Plan.
(2) 2010 Annual weighted average trust units has been revised to reflect
the increase in the equity offering that closed in January 2010 from
10.1 million to 13 million units.
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Actual results for 2009 are in-line with guidance amounts with the exception of the following:
G&A expenses - total cash G&A costs were
Interest expense - was below guidance for the full year of 2009 due to ARC's ability to cash fund more capital expenditures in the last half of 2009 with the uplift in commodity prices, therefore drawing less funds from debt and saving on interest expense.
The 2010 Guidance provides unitholders with information on management's expectations for results of operations, excluding any acquisitions or dispositions for 2010. Readers are cautioned that the 2010 Guidance may not be appropriate for other purposes.
Cash Flow from Operating Activities
Cash flow from operating activities decreased by 47 per cent in 2009 to
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Table 5
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($ per
($ millions) trust unit) (% Change)
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2008 Cash flow from Operating
Activities 944.4 4.37 -
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Volume variance (46.2) (0.21) (5)
Price variance (682.0) (3.15) (72)
Cash (losses) and gains on risk
management contracts 95.1 0.44 10
Royalties 159.9 0.74 17
Expenses:
Transportation (1.6) (0.01) (0.2)
Operating(1) 6.1 0.03 0.6
Cash G&A 7.7 0.04 0.8
Interest 7.2 0.03 0.8
Taxes (0.3) - -
Realized foreign exchange loss 1.9 0.01 0.2
Weighted average trust units - (0.22) -
Non-cash and other items(2) 5.2 0.02 -
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2009 Cash flow from Operating
Activities 497.4 2.09 -
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(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.
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2010 Cash Flow from Operating Activities Sensitivity
Table 6 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:
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Table 6
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Impact on Annual Cash
flow from operating
activities(4)
Business Environment(1) Assumption Change $/Unit
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Oil price (US$WTI/bbl)(2)(3) $ 75.00 $ 1.00 $ 0.04
Natural gas price (Cdn$AECO/mcf)(2)(3) $ 5.50 $ 0.10 $ 0.03
Cdn$/US$ exchange rate(2)(3)(5) 1.05 $ 0.01 $ 0.03
Interest rate on debt(2) % 4.00 % 1.0 $ 0.01
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.03
Gas production volumes (mmcf/d) 240.0 % 1.0 $ 0.01
Operating expenses per boe $ 10.30 % 1.0 $ 0.01
Cash G&A and LTIP expenses per boe $ 2.85 % 10.0 $ 0.03
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(1) Calculations are performed independently and may not be indicative of
actual results that would occur when multiple variables change at the
same time.
(2) Prices and rates are indicative of published forward prices and rates
at the time of this MD&A. The calculated impact on annual cash flow
from operating activities would only be applicable within a limited
range of these amounts.
(3) Analysis does not include the effect of hedging contracts.
(4) Assumes constant working capital.
(5) Includes impact of foreign exchange on crude oil prices that 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.
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Net Income
Net income in 2009 was
In 2009, ARC recorded a
In 2009, ARC recorded a
The above amounts were offset by a
Production
Production volumes averaged 63,538 boe per day in 2009 compared to 65,126 boe per day in 2008 as detailed in Table 7. The decrease in 2009 production is a result of the reduction of the capital expenditure program.
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Table 7
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Production 2009 2008 % Change
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Light & medium crude oil (bbl/d) 26,423 27,239 (3)
Heavy oil (bbl/d) 1,086 1,274 (15)
Natural gas (mmcf/d) 194.0 196.5 (1)
NGL (bbl/d) 3,689 3,861 (4)
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Total production (boe/d)(1) 63,538 65,126 (2)
% Natural gas production 51 50 2
% Crude oil and liquids production 49 50 (2)
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(1) Reported production for a period may include minor adjustments from
previous production periods.
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Light and medium crude oil production decreased to 26,423 boe per day compared to 27,239 boe per day in 2008, while heavy oil production declined by 188 boe per day. Compared to 2008, the total crude oil production is down approximately 1,000 barrels per day. Natural gas production was 194 mmcf per day in 2009, a decrease of one per cent from the 196.5 mmcf per day produced in 2008. This slight decline was primarily due to plant turnarounds completed at third party facilities that shut-in gas production.
ARC's objective is to maintain annual production through the drilling of wells and other development activities to the full extent possible, while giving consideration to capital spending constraints and the economics of developing ARC's resources. In fulfilling this objective, there may be fluctuations in production depending on the timing of new wells coming on-stream. During 2009, ARC drilled 145 gross wells (120 net wells) on operated properties; 37 gross oil wells, and 108 gross natural gas wells with a 99 per cent success rate.
ARC expects that 2010 full year production will average approximately 70,500 to 72,500 boe per day and that a total of 211 gross wells (195 net) will be drilled by ARC on operated properties with participation in an additional 91 gross wells (18 net) to be drilled on ARC's non-operated properties. ARC estimates that the 2010 drilling program and the start-up of a new gas plant in the Dawson area will increase production in 2010 by 11 per cent to 14 per cent over 2009 production levels. The planned capital expenditures for 2010 have been increased to approximately
Table 8 summarizes ARC's production by core area:
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Table 8
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2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
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Central AB 6,984 1,279 27.7 1,083
N.E. BC & N.W. AB 13,794 715 74.4 672
Northern AB 9,004 4,096 24.5 821
Pembina & Redwater 13,560 9,412 19.0 978
S.E. AB & S.W. Sask. 8,841 1,027 46.9 13
S.E. Sask. & MB 11,357 10,980 1.5 122
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Total 63,538 27,509 194.0 3,689
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2008
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
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Central AB 7,495 1,406 29.2 1,218
N.E. BC & N.W. AB 12,678 802 67.6 613
Northern AB 9,791 4,516 26.1 921
Pembina & Redwater 13,707 9,495 19.7 936
S.E. AB & S.W. Sask. 9,701 985 52.2 11
S.E. Sask. & MB 11,754 11,309 1.7 162
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Total 65,126 28,513 196.5 3,861
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(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 9:
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Table 9
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Revenue
($ millions) 2009 2008 % Change
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Oil revenue 625.0 983.1 (36)
Natural gas revenue 296.0 616.8 (52)
NGL revenue 54.8 98.5 (44)
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Total commodity revenue 975.8 1,698.4 (43)
Other revenue 2.4 8.0 (70)
Total revenue 978.2 1,706.4 (43)
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Commodity Prices Prior to Hedging
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Table 10
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2009 2008 % Change
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Average Benchmark Prices
AECO gas ($/mcf)(1) 4.13 8.13 (49)
WTI oil (US$/bbl)(2) 61.93 99.66 (38)
Cdn$ / US$ foreign exchange rate 1.13 1.05 8
WTI oil (Cdn$/bbl) 69.70 104.30 (33)
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ARC Realized Prices Prior to Hedging
Oil ($/bbl) 62.24 94.20 (34)
Natural gas ($/mcf) 4.18 8.58 (51)
NGL ($/bbl) 40.67 69.71 (42)
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Total commodity revenue before
hedging ($/boe) 42.07 71.25 (41)
Other revenue ($/boe) 0.11 0.34 (68)
Total revenue before hedging ($/boe) 42.18 71.59 (41)
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(1) Represents the AECO monthly posting.
(2) WTI represents posting price of West Texas Intermediate oil.
>>
Oil prices continued to recover in the second half of 2009 with US$WTI prices averaging
Natural gas prices softened throughout 2009 with a strengthening in the fourth quarter. 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 cash flows, and to protect acquisition and capital expenditures economics.
Gain or loss on risk management contracts comprise realized and unrealized gains or losses on contracts that do not meet the accounting definition requirements of an effective hedge, even though ARC 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 Consolidated Statements of Income and Deficit.
Lower natural gas prices in 2009 resulted in realized cash gains of
ARC's 2009 results include an unrealized total mark-to-market loss of
Table 11 summarizes the total gain (loss) on risk management contracts for the year-over-year change as of the 2009 year-end:
<<
Table 11
-------------------------------------------------------------------------
Risk Management Crude Foreign
Contracts Oil & Natural Curr- Inter- 2009 2008
($ millions) Liquids Gas ency Power(3) est Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (14.8) 28.5 2.0 (1.1) 4.8 19.4 (75.7)
Unrealized gain
(loss) on
contracts(2) 5.0 (2.5) - (4.8) (5.4) (7.7) 68.0
-------------------------------------------------------------------------
Total (loss) gain
on risk management
contracts (9.8) 26.0 2.0 (5.9) (0.6) 11.7 (7.7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized gain (loss) on contracts represents the change in fair
value of the contracts during the period.
(3) Amounts presented in Table 11 exclude a $1.5 million realized loss
and an unrealized loss of $3.8 million for ARC's power contracts that
have been designated as effective hedges for accounting purposes.
Realized gains and losses on these contracts are recorded in
operating costs and unrealized gains and losses are recorded in the
Consolidated Statement of Comprehensive Income and Accumulated Other
Comprehensive Income.
>>
ARC currently limits the amount of forecast production that can be hedged to a maximum 50 per cent with the balance of production being sold at market prices. In addition, project specific hedges may be entered into from time to time to protect the economics of certain capital expenditures. Table 12 is an indicative summary of ARC's positions for crude oil and natural gas as at
<<
Table 12
-------------------------------------------------------------------------
Hedge Positions
As at December 31,
2009(1)(2) Q1 2010 Q2 2010
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 95.36 9,000 96.81 8,000
Bought Put 76.17 9,000 77.19 8,000
Sold Put 62.80 2,000 62.80 2,000
-------------------------------------------------------------------------
Natural Gas Cdn$/mcf mcf/day Cdn$/mcf mcf/day
-------------------------------------------------------------------------
Sold Call 5.92 75,825 5.77 95,825
Bought Put 5.92 75,825 5.77 95,825
Sold Put - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Hedge Positions
As at December 31,
2009(1)(2) Q3 2010(3) Q4 2010
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 96.81 8,000 96.81 8,000
Bought Put 77.19 8,000 77.19 8,000
Sold Put 62.80 2,000 62.80 2,000
-------------------------------------------------------------------------
Natural Gas Cdn$/mcf mcf/day Cdn$/mcf mcf/day
-------------------------------------------------------------------------
Sold Call 5.77 95,825 5.92 75,825
Bought Put 5.77 95,825 5.92 75,825
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. Please refer to note 13 in the
Notes to the Consolidated Financial Statements for full details of
ARC's risk management positions as of December 31, 2009.
(3) During the last half of 2009, ARC 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. In addition to
contracts listed above, ARC has entered into fixed price swaps
starting in 2011 and ending in December 2013 at an average price of
$6.40 per mcf for 42,654 mcf per day.
>>
Table 12 should be interpreted as follows using the first quarter 2010 crude oil hedges as an example. To accurately analyze ARC's hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading.
<<
- If the market price is below $62.80, ARC will receive $76.17 less the
difference between $62.80 and the market price on 2,000 bbl per day.
For example, if the market price is $62.75, ARC will receive $76.12
on 2,000 bbl per day.
- If the market price is between $62.80 and $76.17, ARC will receive
$76.17 on 9,000 bbl per day.
- If the market price is between $76.17 and $95.36, ARC will receive
the market price on 9,000 bbl per day.
- If the market price exceeds $95.36, ARC will receive $95.36 on 9,000
bbl per day.
>>
Operating Netbacks
ARC's operating netback, before realized hedging gains and losses, decreased 48 per cent to
ARC's 2009 netback, after realized hedging gains and losses, was
The components of operating netbacks are summarized in Table 13:
<<
Table 13
-------------------------------------------------------------------------
Crude Heavy 2009 2008
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 62.51 55.74 4.18 40.67 42.07 71.25
Other revenue - - - - 0.10 0.34
-------------------------------------------------------------------------
Total revenue 62.51 55.74 4.18 40.67 42.17 71.59
Royalties (9.63) (5.34) (0.50) (13.03) (6.37) (12.91)
Transportation (0.18) (1.15) (0.26) - (0.89) (0.80)
Operating costs(1) (12.88) (12.46) (1.33) (7.85) (10.19) (10.13)
-------------------------------------------------------------------------
Netback prior to hedging 39.82 36.79 2.09 19.79 24.72 47.75
Realized (loss) gain on
risk management
contracts(2) (1.65) - 0.40 - 0.54 (3.17)
-------------------------------------------------------------------------
Netback after hedging 38.17 36.79 2.49 19.79 25.26 44.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 15.4 per cent (
The Alberta Government's
Royalty rates in the other western provinces vary due to production levels and price but to a lesser extent than Alberta royalty rates. Table 14 estimates the royalties applicable to production from ARC's properties at various price levels.
<<
Table 14
-------------------------------------------------------------------------
Provincial Royalty Rates - Forecast for 2010
-------------------------------------------------------------------------
Edmonton posted oil (Cdn/$/bbl)(1) $60 $80 $100
AECO natural gas (Cdn$/mcf)(1) $4.00 $5.50 $6.50
-------------------------------------------------------------------------
Alberta royalty rate 12.6% 18.1% 22.6%
Saskatchewan royalty rate(2) 17.9% 17.9% 17.9%
British Columbia royalty rate(2) 17.0% 17.0% 17.0%
Manitoba royalty rate(2) 13.0% 13.0% 13.0%
-------------------------------------------------------------------------
Total Corporate Royalty Rate 14.6% 17.8% 20.4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Canadian dollar denominated prices before quality differentials.
(2) Royalty rate includes Crown, Freehold and Gross Override royalties
for all jurisdictions in which ARC operates.
>>
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 is 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 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 remained flat at
Looking ahead to 2010, ARC expects to incur full year operating costs of
General and Administrative Expenses ("G&A") 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 4.9 per cent to
Cash G&A in 2010 is expected to increase by approximately
ARC paid out
Table 15 is a breakdown of G&A and trust unit incentive compensation expense under the Whole Unit Plan:
<<
Table 15
-------------------------------------------------------------------------
G&A and Trust Unit Incentive Compensation
Expense
($ millions except per boe) 2009 2008 % Change
-------------------------------------------------------------------------
G&A expenses 56.1 55.6 1
Operating recoveries (15.4) (16.8) (8)
-------------------------------------------------------------------------
Cash G&A expenses before Whole Unit Plan 40.7 38.8 5
Cash Expense - Whole Unit Plan 11.7 21.3 (45)
-------------------------------------------------------------------------
Cash G&A expenses including Whole
Unit Plan 52.4 60.1 (13)
Accrued compensation - Whole Unit Plan (0.1) 1.1 (109)
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 52.3 61.2 (15)
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense per boe 2.26 2.57 (12)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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 total return performance of ARC 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. A performance multiplier is applied to the PTUs based on the percentile rank of ARC's total unitholder return compared to its peers. 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 year of RTUs and PTUs outstanding:
<<
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 703 635 1,338
Vested in the period (355) (261) (616)
Forfeited in the period (52) (28) (80)
-------------------------------------------------------------------------
Balance, end of period(1) 1,052 1,305 2,357
Estimated distributions to vesting date(2) 183 318 501
-------------------------------------------------------------------------
Estimated units upon vesting after
distributions 1,235 1,623 2,858
Performance multiplier(3) - 1.2 -
-------------------------------------------------------------------------
Estimated total units upon vesting 1,235 1,996 3,231
-------------------------------------------------------------------------
Trust unit price at December 31, 2009 19.94 19.94 19.94
Estimated total value upon vesting 24.6 39.8 64.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 1.2 at December 31, 2009 based on an average calculation of all
outstanding grants. The performance multiplier is assessed each
period end based on actual results of ARC 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, ARC'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 December 31, 2009:
<<
Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
December 31, 2009 Performance multiplier
(units thousands and $ millions --------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 1,235 1,235 1,235
PTUs - 1,623 3,246
-------------------------------------------------------------------------
Total units(1) 1,235 2,858 4,482
-------------------------------------------------------------------------
Trust unit price(2) 19.94 19.94 19.94
Trust unit distributions per month(2) 0.10 0.10 0.10
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting(3) 24.6 57.0 89.4
-------------------------------------------------------------------------
2010 11.0 19.7 28.4
2011 8.2 16.8 25.3
2012 5.4 20.5 35.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $19.94 and $0.10 per trust unit
distributions based on the unit price and distribution levels in
place at December 31, 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, ARC estimates that between
Provision for Non-recoverable Accounts Receivable
For the year ended
Interest and Financing Charges
Interest and financing charges decreased to
Foreign Exchange Gains and Losses
ARC 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 was a
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 2009, a future income tax recovery of
The corporate income tax rate applicable to 2009 is 29 per cent; however, ARC and its subsidiaries did not pay any cash income taxes for fiscal 2009. Due to ARC'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 ARC.
Management continues to work on the plan for converting ARC Energy Trust to a corporation on
<<
Table 18
-------------------------------------------------------------------------
Income Tax Cdn $ millions at
Pool type December, 2009 Annual deductibility
-------------------------------------------------------------------------
Canadian Oil and Gas
Property Expense 951.6 10% declining balance
Canadian Development Expense 391.1 30% declining balance
Canadian Exploration Expense 105.6 100%
Undepreciated Capital Cost 432.2 Primarily 25% declining
balance
Non-Capital Losses 181.9 100%
Research and Experimental
Expenditures 0.8 100%
Other 15.2 Various rates, 7%
declining balance to 20%
-------------------------------------------------------------------------
Total Federal Tax Pools 2,078.4
-------------------------------------------------------------------------
Additional Alberta Tax Pools 155.5 Various rates, 25%
declining balance to 100%
-------------------------------------------------------------------------
Total Federal and Provincial Pools 2,233.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Returns to shareholders post conversion will be impacted by the reduction of cash flow required to pay current income taxes, if any. Over the long-term, we would expect Canadian investors who hold their trust units in a taxable account to 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, ARC expects there will be an opportunity to convert trust units to shares of the new corporation in a non-taxable manner; however, unitholders 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
-------------------------------------------------------------------------
DD&A Rate
($ millions except per boe amounts) 2009 2008 % Change
-------------------------------------------------------------------------
Depletion of oil & gas assets(1) 377.1 370.3 2
Accretion of asset retirement
obligation(2) 9.3 9.3 -
-------------------------------------------------------------------------
Total DD&A 386.4 379.6 2
DD&A rate per boe 16.66 15.93 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.
>>
Goodwill
The goodwill balance of
Accounting standards require that the goodwill balance be assessed for impairment at least annually or more frequently if events or changes in circumstances indicate that the balance might be impaired. If such impairment exists, it would be charged to income in the period in which the impairment occurs. ARC has determined that there was no goodwill impairment as of
Capital Expenditures and Net Acquisitions
Capital expenditures, excluding acquisitions and dispositions, totaled
Of the total amount spent in 2009,
Included in the above capital expenditures is
In addition to the total capital expenditures during the year, ARC completed a corporate acquisition to purchase directly and indirectly all of the units of a general partnership formed to hold oil and gas assets in Ante Creek and other areas of northern Alberta ("Ante Creek") for
ARC completed net property dispositions of both producing property and undeveloped land of
A breakdown of capital expenditures and net acquisitions is shown in Table 20:
<<
Table 20
-------------------------------------------------------------------------
Capital Expenditures
($ millions) 2009 2008 % Change
-------------------------------------------------------------------------
Geological and geophysical 13.7 27.1 (49)
Drilling and completions 214.3 305.4 (30)
Plant and facilities 110.0 90.4 22
Undeveloped land 7.0 122.4 (94)
Other capital 14.6 3.3 342
-------------------------------------------------------------------------
Total capital expenditures 359.6 548.6 (34)
-------------------------------------------------------------------------
Producing property acquisitions(1) 8.2 1.4 100
Undeveloped land property acquisitions 14.5 53.5 (73)
Producing property dispositions(1) (37.3) (0.2) (100)
Undeveloped land property dispositions (5.9) (3.7) 59
Corporate acquisition(2) 178.9 - 100
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 518.0 599.6 (14)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
(2) Represents total consideration for the transactions, including fees
but is prior to the related future income tax liability and asset
retirement cost obligation.
>>
Approximately 73 per cent of the
<<
Table 21
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
2009 2008
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------
Expenditures 359.6 158.4 518.0 548.6 51.0 599.6
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 54% - 38% 68% - 62%
Proceeds from
Distribution
re-investment plan
("DRIP") 19% - 13% 23% - 21%
Debt 27% 100% 49% 9% 100% 17%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Asset Retirement Obligation and Reclamation Fund
At
Included in the
ARC has established two reclamation funds to finance future asset retirement obligations; one fund has been restricted to finance obligations specifically associated with the Redwater property, with the main fund financing all other obligations. Future contributions for the two funds will vary over time in order to provide for the total estimated future abandonment and reclamation costs that are to be incurred upon abandonment of ARC's properties. Minimum contributions to the Redwater fund over the next 46 years will be approximately
ARC's reclamation funds totaled
Capitalization, Financial Resources and Liquidity
A breakdown of ARC's capital structure is outlined in Table 22, as at
<<
Table 22
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per cent and December 31, December 31,
ratio amounts) 2009 2008
-------------------------------------------------------------------------
Long-term debt 846.1 901.8
Working capital deficit(1) 56.3 60.1
-------------------------------------------------------------------------
Net debt obligations(2) 902.4 961.9
Market value of trust units and exchangeable
shares(3) 4,765.7 4,405.9
-------------------------------------------------------------------------
Total capitalization(4) 5,668.1 5,367.8
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 15.9% 17.9%
Net debt to cash flow from operating activities 1.8 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Working capital is calculated as current liabilities less the current
assets as they appear on the Consolidated Balance Sheets, and
excludes current unrealized amounts pertaining to risk management
contracts and the current portion of future income taxes.
(2) Net debt is a non-GAAP measure and therefore it may not be comparable
with the calculation of similar measures for other entities.
(3) Calculated using the total trust units outstanding at December 31
including the total number of trust units issuable for exchangeable
shares at December 31, multiplied by the closing trust unit price of
$19.94 and $20.10 for 2009 and 2008, respectively.
(4) 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 ARC.
>>
At
The credit facility syndicate includes 11 domestic and international banks. ARC's debt agreements contain a number of covenants all of which were met as at
<<
- Long-term debt and letters of credit not to exceed three times
annualized net income before non-cash items and interest expense;
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times annualized net income before non-cash items and
interest expense; and
- Long-term debt and letters of credit not to exceed 50 per cent of the
book value of unitholders' equity and long-term debt, letters of
credit and subordinated debt.
>>
ARC's long-term strategy is to keep debt at less than 2.0 times cash flow from operating activities and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels in 2009. Debt to trailing cash flow from operating activities of 1.0 times at
The weak global economic situation in 2008 and 2009 impacted ARC along with all other oil and gas entities by restricting access to capital and increasing borrowing costs. The credit situation improved dramatically during the third and fourth quarters of 2009 in the three markets that ARC typically uses to raise capital; equity, bank debt and long-term notes.
ARC entered into a bought deal equity offering with a group of underwriters on
Credit conditions in the debt markets have improved dramatically in the last six months. Based on discussions with the 11 banks in ARC's revolving credit syndicate, management believes that ARC could expect to renew the
ARC also accesses long-term debt from large institutional investors by issuing long-term notes with an average term normally of five to 10 years. The cost of this debt is based upon two factors: first, the current rate of long-term government bonds and second, ARC's credit spread. Similar to bank credit spreads, these spreads increased significantly in 2008 and early 2009 but are now declining. ARC's average interest rate on its outstanding long-term notes is 5.9 per cent with the last series of notes issued in 2009 at a blended rate of 7.5 per cent. Based upon recent issues by ARC's peers, management believes ARC could access additional funds by issuing long-term notes at a rate similar to or lower than our historical average of 5.9 per cent.
ARC expects to finance its 2010 capital program with cash flow from operating activities, proceeds from the DRIP and existing credit capacity. If ARC undertook any major acquisitions, management would finance the transactions with a combination of debt and equity in a cost effective manner.
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 2009, ARC raised proceeds of
On
Distributions
ARC declared distributions of
The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders:
<<
- a portion of capital expenditures;
- annual contribution to the reclamation funds;
- debt principal repayments;
- income taxes if any; and
- certain obligations for future payments relative to the long-term
incentive compensation under the Whole Unit Plan.
>>
Cash flow from operating activities and distributions in total and per unit are summarized in Table 23:
<<
Table 23
-------------------------------------------------------------------------
Cash flow from operating % %
activities and 2009 2008 Change 2009 2008 Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from operating
activities 497.4 944.4 (47) 2.11 4.37 (52)
Net reclamation fund
contributions(1) (4.6) (2.2) 100 (0.01) (0.01) -
Capital expenditures
funded with cash flow
from operating
activities (194.3) (372.2) (48) (0.83) (1.72) (52)
Other(2) - - - 0.01 0.03 (67)
-------------------------------------------------------------------------
Distributions 298.5 570.0 (48) 1.28 2.67 (52)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
>>
ARC 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 ARC 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. ARC'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 ARC's financial flexibility is maintained by a review
of ARC'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 ARC to use debt to finance
these expenditures. In 2009, ARC funded 54 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 ARC's capital expenditure program is dependent on
the commodity price environment and is subject to the approval and
discretion of the Board of Directors.
>>
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 24 illustrates the comparison of distributions to net income as a measure of long-term sustainability. With the decline in commodity prices in 2009 relative to 2008, distributions were reduced from
<<
Table 24
-------------------------------------------------------------------------
Net income and Distributions
($ millions except per cent) 2009 2008 2007
-------------------------------------------------------------------------
Net income 222.8 533.0 495.3
Distributions 298.5 570.0 498.0
-------------------------------------------------------------------------
Excess (Shortfall) (75.7) (37.0) (2.7)
Excess (Shortfall) as per cent
of net income (34%) (7%) (1%)
-------------------------------------------------------------------------
Cash flow from operating activities 497.4 944.4 704.9
Distributions as a per cent of cash
flow from operating activities 60% 60% 71%
Average distribution per unit per month $0.11 $0.22 $0.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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.
<<
Table 25
-------------------------------------------------------------------------
Taxable Return of
Calendar Year Distributions Portion Capital
-------------------------------------------------------------------------
2010 YTD(2) 0.10 0.10 -
2009 1.28 1.24 0.04
2008 2.67 2.62 0.05
2007 2.40 2.32 0.08
2006(1) 2.60 2.55 0.05
2005 1.94 1.90 0.04
2004 1.80 1.69 0.11
2003 1.78 1.51 0.27
2002 1.58 1.07 0.51
2001 2.41 1.64 0.77
2000 1.86 0.84 1.02
1999 1.25 0.26 0.99
1998 1.20 0.12 1.08
1997 1.40 0.31 1.09
1996 0.81 - 0.81
-------------------------------------------------------------------------
Cumulative $ 25.08 $ 18.17 $ 6.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on distributions paid and payable in 2006.
(2) Based on distributions declared at January 31, 2010 and estimated
taxable portion of 2010 distributions of 97 per cent.
>>
Please refer to the Trust's website at www.arcresources.com for details of the monthly distribution amounts and distribution dates for 2010.
Taxation of Distributions
Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable). The return of capital component reduces the cost basis of the trust units held. For 2009, distributions declared in the calendar year will be 97 per cent return on capital or
Environmental Initiatives Impacting ARC
There are no new material environmental initiatives impacting ARC at this time.
Contractual Obligations and Commitments
ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC's cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 26.
<<
Table 26
-------------------------------------------------------------------------
Payments due by period
-------------------------------------------------------------------------
1 year 2-3 4-5 Beyond Total
years years 5 years
-------------------------------------------------------------------------
Debt repayments(1) 34.8 571.7 107.4 132.2 846.1
Interest payments(2) 20.1 35.5 24.2 20.8 100.6
Reclamation fund
contributions(3) 4.9 8.9 7.7 64.2 85.7
Purchase commitments 41.2 37.1 15.9 14.9 109.1
Transportation commitments(4) 4.8 26.6 24.2 7.1 62.7
Operating leases 4.0 13.0 14.9 74.4 106.3
Risk management contract
premiums(5) 1.6 - - - 1.6
-------------------------------------------------------------------------
Total contractual obligations 111.4 692.8 194.3 313.6 1,312.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 ARC's commitments related to its risk management program and have been recorded at fair market value at
ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC 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. ARC's 2010 capital budget has been approved by the Board at
The 2010 capital budget of
ARC 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 ARC's financial position or results of operations and therefore the commitment table (Table 26) does not include any commitments for outstanding litigation and claims.
ARC has certain sales contracts with aggregators whereby the price received by ARC is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table (Table 26) as it is of a routine nature and is part of normal course of operations.
Off Balance Sheet Arrangements
ARC has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table (Table 26), 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
<<
Fourth Quarter Financial and Operational Results
- During the fourth quarter, ARC completed an acquisition for $180
million in cash consideration prior to normal closing adjustments of
a partnership owning properties in the Ante Creek area. The
acquisition consisted of producing wells with production of
approximately 2,000 boe per day and undeveloped land holdings. This
acquisition closed on December 21, 2009 and therefore financial
results from the properties have been included in the Consolidated
Financial Statements from that date.
- Announced concurrent with the Ante Creek acquisition was a bought
deal financing where ARC entered into an agreement to sell 13 million
trust units at $19.40 per trust unit to raise gross proceeds of
approximately $252 million and net proceeds of approximately $240
million. The net proceeds of the offering were received on January 5,
2010 at which time they reduced the outstanding indebtedness of ARC
by $240 million.
- ARC's fourth quarter production was 62,520 boe per day, a decrease of
2,793 boe per day from the fourth quarter of 2008 production of
65,313. The decrease in production is attributable, in large part, to
the natural declines on ARC's properties as a result of the reduced
capital spending throughout 2009.
- ARC spent $117.3 million on capital expenditures before net
acquisitions in the fourth quarter compared to $169.4 million in
2008. ARC had an active fourth quarter drilling 39 gross wells (38
net wells) on operated properties with a 100 per cent success rate.
Included in ARC's fourth quarter capital expenditures is $20.8
million incurred on the Dawson phase 1 60 mmcf per day gas plant
scheduled to be commissioned early in the second quarter of 2010.
- The fourth quarter netback before hedging decreased slightly to
$29.65 per boe as compared to $29.97 for the same period of 2008.
While ARC's realized crude oil price was 29 per cent higher in the
fourth quarter of 2009 than the same period in 2008, the realized
natural gas price was 39 per cent lower than in the fourth quarter of
2008.
- Cash G&A expenses before payments made under the Whole Unit Plan in
the fourth quarter decreased to $1.73 per boe as compared to $1.78
for the same period in 2008. The decrease in 2009 is attributable to
a decreased bonus accrual in 2009 reflecting the lower overall
commodity price environment observed throughout 2009.
Table 27
-------------------------------------------------------------------------
Fourth Quarter Financial and
Operational Highlights
(Cdn$ millions except per
unit and per cent) Q4 2009 Q4 2008 % Change
-------------------------------------------------------------------------
Production (boe/d) 62,520 65,313 (4)
Cash flow from operating activities 143.2 209.4 (32)
Per unit $ 0.61 $ 0.96 (36)
Distributions 70.9 127.2 (44)
Per unit $ 0.30 $ 0.58 (48)
Per cent of cash flow from
operating activities 50 61 (18)
Net income 65.5 82.7 (21)
Per unit $ 0.28 $ 0.38 (26)
-------------------------------------------------------------------------
Prices
WTI (US$/bbl) 76.17 58.75 30
Cdn$/US$ exchange rate 1.06 1.21 (12)
Realized oil price (Cdn $/bbl) 72.61 56.26 29
AECO gas monthly index (Cdn $/mcf) 4.23 6.79 (38)
Realized gas price (Cdn $/mcf) 4.58 7.48 (39)
-------------------------------------------------------------------------
Operating netback ($/boe)
Revenue, before hedging 48.42 50.06 (3)
Royalties (7.94) (9.14) (13)
Transportation (0.92) (0.86) 7
Operating costs (9.91) (10.09) (2)
Netback (before hedging) 29.65 29.97 (1)
Cash hedging gain (loss) (0.47) 2.38 (120)
Netback (after hedging) 29.18 $ 32.35 (10)
-------------------------------------------------------------------------
Capital expenditures 117.3 169.4 (31)
Net acquisitions and dispositions(1) 180.0 27.6 552
Capital funded with cash flow from
operating activities (per cent) 73 65 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents total consideration for the transactions, including fees
but is prior to the related future income tax liability and asset
retirement cost obligation.
>>
Critical Accounting Estimates
ARC 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.
ARC'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 ARC 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.
>>
ARC 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 ARC's environmental, health and safety policies.
Disclosure Controls and Procedures
As of
Internal Control over Financial Reporting
Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of ARC's internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in
Financial Reporting Update
Current Year Accounting Changes
Effective
Effective
Future Accounting Changes
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 applies prospectively to business combinations on or after
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 ARC for business combinations occurring on or after
International Financial Reporting Standards ("IFRS")
In
ARC 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. Resource requirements have been identified and all IFRS requirements will be met with internal employees supplemented with consultants as required. Regular progress reporting to the Audit Committee of the Board of Directors on the status of the IFRS conversion has been implemented along with scheduled training sessions throughout 2010. At this time, ARC has begun the process of training key personnel within the accounting and finance functions as well as the management team. This has occurred through external IFRS oil and gas training and workshops that have been attended by key members of the accounting and finance team in 2009 and early 2010. A training session has been scheduled for the Audit Committee in June, 2010.
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 of 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 ARC'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.
>>
ARC has completed the scoping and diagnostic phase and has prepared draft analysis for the impact analysis and evaluation phase. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to ARC's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this MD&A.
First-Time Adoption of IFRS
IFRS 1, "First-Time Adoption of International Financial Reporting Standards" ("IFRS 1"), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate for ARC which at this time are summarized as follows:
<<
- Business Combinations - IFRS 1 would allow ARC to use the IFRS rules
for business combinations on a prospective basis rather than re-
stating all business combinations. The IFRS business combination
rules converge with the new CICA Hanbook section 1582 that is also
effective for ARC on January 1, 2011, however, early adoption is
permitted.
- Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option
to value the PP&E assets at their deemed cost being the Canadian
GAAP net book value assigned to these assets as at the date of
transition, January 1, 2010. This amendment is permissible for
entities, such as ARC, who currently follow the full cost accounting
guideline under Canadian GAAP that accumulates all oil and gas
assets into one cost centre. Under IFRS, ARC's PP&E assets must be
divided into smaller cost centers. The net book value of the assets
on the date of transition will be allocated to the new cost centers
on the basis of ARC's reserve volumes or values at that point in
time.
- Share-Based Payments - IFRS 1 allows ARC an exemption on IFRS 2,
"Share-Based Payments" to equity instruments granted on or before
November 2, 2002 or which vested before ARC's transition date to
IFRS.
>>
The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of operations. At this time, ARC has identified key differences that will impact the financial statements as follows:
<<
- Re-classification of Exploration and Evaluation ("E&E") expenditures
from PP&E - Upon transition to IFRS, ARC will re-classify all E&E
expenditures that are currently included in the PP&E balance on the
Consolidated Balance Sheet. This will consist of the book value for
ARC's undeveloped land that relates to exploration properties. E&E
assets will not be depleted and must be assessed for impairment when
indicators suggest the possibility of impairment.
- Calculation of depletion expense for PP&E assets - Upon transition to
IFRS, ARC has the option to calculate depletion using a reserve base
of proved reserves or both proved and probable reserves, as compared
to the Canadian GAAP method of calculating depletion using only
proved reserves. ARC has not concluded at this time which method for
calculating depletion will be used.
- Impairment of PP&E assets - Under IFRS, impairment of PP&E must be
calculated at a more granular level than what is currently required
under Canadian GAAP. Impairment calculations will be performed at the
cash generating unit level using either total proved or proved plus
probable reserves.
- Due to the recent withdrawal of the exposure draft on IAS 12 Income
Taxes in November 2009 and the issuance of the exposure draft on IAS
37 Provisions, Contingent Liabilities and Contingent Assets in
January 2010, Management is still determining the impact of these
revised standards on its IFRS transition and expects to have all
additional potential material impact areas identified during the
first quarter of 2010 and approved by the audit committee during the
second quarter of 2010.
>>
In addition to accounting policy differences, ARC's transition to IFRS will impact the internal controls over financial reporting, the disclosure controls and procedures, ARC's business activities and IT systems as follows:
<<
- Internal controls over financial reporting ("ICFR") - As the review
of ARC's accounting policies is completed, an assessment will be
made to determine changes required for ICFR. As an example,
additional controls will be implemented for the IFRS 1 changes such
as the allocation of ARC's PP&E as well as the process for re-
classifying ARC's E&E expenditures from PP&E. This will be an
ongoing process through 2010 to ensure that all changes in
accounting policies include the appropriate additional controls and
procedures for future IFRS reporting requirements.
- Disclosure controls and procedures - Throughout the transition
process, ARC will be assessing stakeholders' information
requirements and will ensure that adequate and timely information is
provided so that all stakeholders are kept apprised. Management
anticipates to deliver investor presentations during the fourth
quarter of 2011 to explain the differences between the historical
Canadian GAAP statements and the IFRS statements.
- Business activities - Management has been cognizant of the upcoming
transition to IFRS and as such has worked with our counterparties
and lenders to ensure that agreement references to Canadian GAAP
statements are modified to allow for IFRS statements. Based on the
expected changes to ARC's accounting policies at this time, there
are no foreseen issues with the existing wording of debts covenants
and related agreements as a result of the conversion to IFRS.
During the 2010 quarterly meetings held with ARC's lenders there
will be an update on IFRS as it relates to ARC and management will
continue to monitor these areas closely as final policy choices are
made.
- IT systems - ARC has completed most of the system updates required
in order to ready the company for IFRS reporting. The modifications
were not significant, however, deemed critical in order to allow for
reporting of both Canadian GAAP and IFRS statements in 2010 as well
as the modifications required to track PP&E costs and E&E costs with
a more granular level of detail for IFRS reporting. Additional
system modifications may be required based on final policy
choices. Additional system modifications may be required based on
final policy choices.
>>
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 ARC. 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 MD&A 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 MD&A contains forward-looking information and statements pertaining to the following: all of the matters under the heading "2009 Guidance and Financial Highlights" which contains guidance for 2010, the future expenditure plans for 2010 and expected production under the heading "Production", the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia and future operating costs under the heading "Operating Netbacks", the expected increase in cash G&A in 2010 and the expected payments in 2010 under the Whole Unit Plan under the heading "General and Administrative Expenses ("G&A") and Trust Unit Incentive Compensation", the increase in interest rates in 2010 as a result of the renewal of our credit facility under the heading "Interest and Financing Charges" and the costs and opportunity for renewal of the bank facility and other information relating to financing the 2010 capital expenditures under the heading: "Capitalization, Financial Resources and Liquidity", the payment of income taxes in the future by ARC and the availability of a non-taxable conversion of trust unit to shares on the conversion of the trust structure to a corporation under the heading "Taxes", and a number of other matters, including the amount of future asset retirement; 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 MD&A 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 MD&A 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 MD&A and in ARC's Annual Information Form).
The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, 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.
<<
ANNUAL HISTORICAL REVIEW
-------------------------------------------------------------------------
For the year ended December 31
(Cdn $ millions, except
per unit amounts) 2009 2008 2007 2006 2005
-------------------------------------------------------------------------
FINANCIAL
Revenue before royalties 978.2 1,706.4 1,251.6 1,230.5 1,165.2
Per unit(1) 4.16 7.90 5.95 6.02 6.10
Cash flow from operating
activities(2) 497.4 944.4 704.9 734.0 616.7
Per unit - basic(1) 2.11 4.37 3.35 3.59 3.23
Per unit - diluted 2.11 4.37 3.35 3.58 3.20
Net income 222.8 533.0 495.3 460.1 356.9
Per unit - basic(3) 0.96 2.50 2.39 2.28 1.90
Per unit - diluted 0.96 2.50 2.39 2.27 1.88
Distributions 298.5 570.0 498.0 484.2 376.6
Per unit(4) 1.28 2.67 2.40 2.40 1.99
Total assets 3,914.5 3,766.7 3,533.0 3,479.0 3,251.2
Total liabilities 1,540.1 1,624.6 1,491.3 1,550.6 1,415.5
Net debt outstanding(5) 902.4 961.9 752.7 739.1 578.1
Weighted average trust
units (millions)(6) 235.4 216.0 210.2 204.4 191.2
Trust units outstanding
and issuable at period
end (millions)(6) 239.0 219.2 213.2 207.2 202.0
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 13.7 27.1 14.9 11.4 9.2
Land 7.0 122.4 77.5 32.4 9.1
Drilling and completions 214.3 305.4 229.5 240.5 191.8
Plant and facilities 110.0 90.4 72.1 77.6 55.0
Other capital 14.6 3.3 3.2 2.6 3.7
Total capital expenditures 359.6 548.6 397.2 364.5 268.8
Property acquisitions
(dispositions), net (20.5) 51.0 42.5 115.2 91.3
Corporate acquisitions(7) 178.9 - - 16.6 505.0
Total capital expenditures
and net acquisitions 518.0 599.6 439.7 496.3 865.1
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,509 28,513 28,682 29,042 23,282
Natural gas (mmcf/d) 194.0 196.5 180.1 179.1 173.8
Natural gas liquids (bbl/d) 3,689 3,861 4,027 4,170 4,005
Total (boe per day 6:1) 63,538 65,126 62,723 63,056 56,254
Average prices
Crude oil ($/bbl) 62.24 94.20 69.24 65.26 61.11
Natural gas ($/mcf) 4.18 8.58 6.75 6.97 8.96
Natural gas liquids ($/bbl) 40.67 69.71 54.79 52.63 49.92
Oil equivalent ($/boe) 42.07 71.25 54.54 53.33 56.54
-------------------------------------------------------------------------
RESERVES
(company interest)(8)
Proved plus probable
reserves
Crude oil and NGL (mbbl) 153,413 153,020 158,341 162,193 163,385
Natural gas (bcf) 1,353.2 1,012.2 768.2 743.6 741.7
Total (mboe) 378,953 321,723 286,370 286,125 286,997
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TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 21.89 33.95 23.86 30.74 27.58
Low 11.73 15.01 18.90 19.20 16.55
Close 19.94 20.10 20.40 22.30 26.49
Average daily volume
(thousands) 1,057 975 597 706 656
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-------------------------------------------------------------------------
(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) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters. Refer to non-GAAP section.
(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) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.
(8) Company interest reserves are the gross interest reserves plus the
royalty interest prior to the deduction of royalty burdens.
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2009
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 278.6 239.2 235.2 225.2
Per unit(1) 1.17 1.01 0.99 0.98
Cash flow from operating activities(2) 143.2 125.6 104.3 124.3
Per unit - basic(1) 0.60 0.53 0.44 0.54
Per unit - diluted 0.60 0.53 0.44 0.54
Net income 65.5 68.9 66.1 22.3
Per unit - basic(3) 0.28 0.29 0.28 0.10
Per unit - diluted 0.28 0.29 0.28 0.10
Distributions 70.9 70.6 75.0 82.0
Per unit(4) 0.30 0.30 0.32 0.36
Total assets 3,914.5 3,642.9 3,672.5 3,733.1
Total liabilities 1,540.1 1,278.4 1,323.1 1,392.1
Net debt outstanding(5) 902.4 705.4 737.6 781.5
Weighted average trust units(6) 238.5 237.7 236.6 228.9
Trust units outstanding and
issuable(6) 239.0 238.1 237.1 236.0
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 2.9 3.0 5.0 2.8
Land 2.0 4.5 0.2 0.2
Drilling and completions 66.1 61.0 18.6 68.5
Plant and facilities 35.3 26.1 23.6 25.1
Other capital 11.0 1.6 1.5 0.6
Total capital expenditures 117.3 96.2 48.9 97.2
Property acquisitions (dispositions)
net 1.1 (30.1) 2.3 6.2
Corporate acquisitions(7) 178.9 - - -
Total capital expenditures and net
acquisitions 297.3 66.1 51.2 103.4
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,415 26,921 26,917 28,806
Natural gas (mmcf/d) 189.0 193.1 200.2 193.8
Natural gas liquids (bbl/d) 3,597 3,717 3,679 3,764
Total (boe per day 6:1) 62,520 62,824 63,969 64,872
Average prices
Crude oil ($/bbl) 72.61 67.74 62.74 46.44
Natural gas ($/mcf) 4.58 3.25 3.73 5.20
Natural gas liquids ($/bbl) 46.12 38.92 38.89 38.86
Oil equivalent ($/boe) 48.35 41.31 40.32 38.40
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 21.89 20.20 19.25 20.90
Low 19.06 15.48 14.12 11.73
Close 19.94 20.20 17.81 14.15
Average daily volume (thousands) 963 1,038 988 1,240
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-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2008
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 300.8 485.7 512.0 407.9
Per unit(1) 1.38 2.24 2.38 1.91
Cash flow from operating activities(2) 209.4 251.4 273.4 209.9
Per unit - basic(1) 0.96 1.16 1.27 0.98
Per unit - diluted 0.96 1.16 1.27 0.98
Net income 82.7 311.7 57.3 81.3
Per unit - basic(3) 0.38 1.46 0.27 0.39
Per unit - diluted 0.38 1.46 0.27 0.38
Distributions 127.2 171.3 144.7 126.8
Per unit(4) 0.59 0.80 0.68 0.60
Total assets 3,766.7 3,687.5 3,664.3 3,592.6
Total liabilities 1,624.6 1,530.8 1,689.6 1,560.4
Net debt outstanding(5) 961.9 773.2 756.1 770.1
Weighted average trust units(6) 218.3 216.6 215.2 213.8
Trust units outstanding and
issuable(6) 219.2 217.4 215.8 214.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.7 1.3 16.4 5.5
Land 17.1 18.6 57.8 28.8
Drilling and completions 117.1 91.4 32.6 64.4
Plant and facilities 30.5 24.2 24.1 11.6
Other capital 1.0 0.9 0.4 1.0
Total capital expenditures 169.4 136.4 131.3 111.3
Property acquisitions (dispositions)
net 27.6 13.1 0.3 10.1
Corporate acquisitions(7) - - - -
Total capital expenditures and net
acquisitions 197.0 149.5 131.6 121.4
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,935 28,509 27,541 29,064
Natural gas (mmcf/d) 195.1 192.0 194.7 204.3
Natural gas liquids (bbl/d) 3,858 3,822 3,906 3,856
Total (boe per day 6:1) 65,313 64,325 63,896 66,976
Average prices
Crude oil ($/bbl) 56.26 114.20 118.32 89.72
Natural gas ($/mcf) 7.48 8.68 10.41 7.80
Natural gas liquids ($/bbl) 45.22 82.87 82.29 68.54
Oil equivalent ($/boe) 49.93 81.42 87.73 66.67
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 22.55 33.30 33.95 27.06
Low 15.01 22.33 25.19 20.00
Close 20.10 23.10 33.95 26.38
Average daily volume (thousands) 1,523 841 659 863
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters. Refer to non-GAAP section.
(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) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.
CONSOLIDATED BALANCE SHEETS (unaudited)
As at December 31
(Cdn$ millions) 2009 2008
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents (Note 5) $ - $ 40.0
Accounts receivable (Note 6) 115.9 110.0
Prepaid expenses 18.2 16.8
Risk management contracts (Note 13) 5.9 24.4
Future income taxes (Note 15) 7.1 3.9
-------------------------------------------------------------------------
147.1 195.1
Reclamation funds (Note 7) 33.2 28.2
Risk management contracts (Note 13) 3.2 9.2
Property, plant and equipment (Note 8) 3,573.4 3,376.6
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,914.5 $ 3,766.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 9) $ 166.7 $ 194.4
Distributions payable 23.7 32.5
Risk management contracts (Note 13) 12.9 23.5
-------------------------------------------------------------------------
203.3 250.4
Risk management contracts (Note 13) 1.0 3.4
Long-term debt (Note 10) 846.1 901.8
Accrued long-term incentive compensation (Note 21) 10.9 14.2
Asset retirement obligations (Note 11) 149.9 141.5
Future income taxes (Note 15) 328.9 313.3
-------------------------------------------------------------------------
Total liabilities 1,540.1 1,624.6
-------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 22)
SUBSEQUENT EVENT (Note 23)
NON-CONTROLLING INTEREST
Exchangeable shares (Note 16) 36.0 42.4
UNITHOLDERS' EQUITY
Unitholders' capital (Note 17) 2,917.6 2,600.7
Deficit (Note 18) (578.6) (502.9)
Accumulated other comprehensive (loss)
income (Note 18) (0.6) 1.9
-------------------------------------------------------------------------
Total unitholders' equity 2,338.4 2,099.7
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,914.5 $ 3,766.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For the three and twelve months ended December 31
Three Months Ended Twelve Months Ended
(Cdn$ millions, except December 31 December 31
per unit amounts) 2009 2008 2009 2008
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and
natural gas liquids $ 278.6 $ 300.8 $ 978.2 $ 1,706.4
Royalties (45.6) (54.9) (147.8) (307.7)
-------------------------------------------------------------------------
233.0 245.9 830.4 1,398.7
Gain (loss) on risk
management contracts
(Note 13)
Realized (1.7) 32.8 19.4 (75.7)
Unrealized 0.2 42.0 (7.7) 68.0
-------------------------------------------------------------------------
231.5 320.7 842.1 1,391.0
-------------------------------------------------------------------------
EXPENSES
Transportation 5.3 5.2 20.6 19.0
Operating 57.0 60.7 236.2 241.5
General and administrative 13.8 14.0 52.3 61.2
Provision for non-
recoverable accounts
receivable (Note 6) (1.3) 14.0 (1.7) 32.0
Interest and financing
charges (Note 10) 5.9 8.1 25.7 32.9
Depletion, depreciation
and accretion
(Notes 8 and 11) 96.1 96.2 386.4 379.6
(Gain) loss on foreign
exchange (Note 14) (9.7) 61.2 (70.0) 89.4
-------------------------------------------------------------------------
167.1 259.4 649.5 855.6
-------------------------------------------------------------------------
Capital and other taxes (0.1) - (0.3) -
Future income tax recovery
(Note 15) 1.9 22.3 32.8 4.5
-------------------------------------------------------------------------
Net income before non-
controlling interest 66.2 83.6 225.1 539.9
Non-controlling interest
(Note 16) (0.7) (0.9) (2.3) (6.9)
-------------------------------------------------------------------------
Net income $ 65.5 $ 82.7 $ 222.8 $ 533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of
period $ (573.2) $ (458.4) $ (502.9) $ (465.9)
Distributions paid or
declared (Note 19) (70.9) (127.2) (298.5) (570.0)
-------------------------------------------------------------------------
Deficit, end of period
(Note 18) $ (578.6) $ (502.9) $ (578.6) $ (502.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per unit
(Note 17)
Basic and Diluted $ 0.28 $ 0.38 $ 0.96 $ 2.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME (unaudited)
For the three and twelve months ended December 31
Three Months Ended Twelve Months Ended
December 31 December 31
(Cdn$ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
Net income $ 65.5 $ 82.7 $ 222.8 $ 533.0
Other comprehensive (loss)
income, net of tax
Losses and gains on
financial instruments
designated as cash
flow hedges(1) (0.5) 0.6 (3.9) (2.2)
De-designation of cash
flow hedge(2) (Note 13) - - - 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 13) 0.3 (0.9) 1.1 (2.9)
Net unrealized gains
(losses) on available-
for-sale reclamation
funds' investments(4) - - 0.3 (0.1)
-------------------------------------------------------------------------
Other comprehensive (loss)
income (0.2) (0.3) (2.5) 4.8
-------------------------------------------------------------------------
Comprehensive income $ 65.3 $ 82.4 $ 220.3 $ 537.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other
comprehensive (loss)
income, beginning of
period (0.4) 2.2 1.9 (2.9)
Other comprehensive (loss)
income (0.2) (0.3) (2.5) 4.8
-------------------------------------------------------------------------
Accumulated other
comprehensive (loss)
income, end of period
(Note 18) $ (0.6) $ 1.9 $ (0.6) $ 1.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts are net of tax of $0.1 million and $1.3 million,
respectively, for the three months and twelve months ended
December 31, 2009 (net of tax of $0.2 million and $0.8 million,
respectively, for the three and twelve months ended December 31,
2008).
(2) Amount is net of tax of $3.6 million for the twelve months ended
December 31, 2008.
(3) Amounts are net of tax of $0.1 million and $0.4 million,
respectively, for the three and twelve months ended December 31, 2009
(net of tax of $0.3 million and $1 million, respectively, for the
three and twelve months ended December 31, 2008).
(4) Nominal future income tax impact for the three months ended
December 31, 2009 and $0.1 million for the twelve months ended
December 31, 2009 (nominal for the three and twelve months ended
December 31, 2008).
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and twelve months ended December 31
Three Months Ended Twelve Months Ended
December 31 December 31
(Cdn$ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 65.5 $ 82.7 $ 222.8 $ 533.0
Add items not involving
cash:
Non-controlling interest
(Note 16) 0.7 0.9 2.3 6.9
Future income tax
recovery (Note 15) (1.9) (22.3) (32.8) (4.5)
Depletion, depreciation
and accretion
(Notes 8 and 11) 96.1 96.2 386.4 379.6
Non-cash (gain) loss on
risk management
contracts (Note 13) (0.2) (42.0) 7.7 (68.0)
Non-cash (gain) loss on
foreign exchange
(Note 14) (8.8) 61.6 (69.0) 88.5
Non-cash trust unit
incentive compensation
expense (recovery)
(Note 21) 4.7 (4.2) 0.6 1.0
Expenditures on site
restoration and reclamation
(Note 11) (4.8) (4.7) (8.7) (12.4)
Change in non-cash working
capital (8.1) 41.2 (11.9) 20.3
-------------------------------------------------------------------------
143.2 209.4 497.4 944.4
-------------------------------------------------------------------------
CASH FLOWS FROM FINANCING
ACTIVITIES
Issue of long-term debt
under revolving credit
facilities, net 224.5 164.0 (120.7) 105.9
Issue of Senior Secured Notes - - 152.9 -
Repayment of Senior Secured
Notes (6.3) (7.1) (18.9) (7.1)
Issue of trust units 0.5 0.5 255.0 4.9
Trust unit issue costs (0.5) - (13.8) -
Cash distributions paid
(Note 19) (56.1) (117.6) (242.3) (458.8)
Change in non-cash working
capital (4.3) (1.5) 1.6 (0.4)
-------------------------------------------------------------------------
157.8 38.3 13.8 (355.5)
-------------------------------------------------------------------------
CASH FLOWS FROM INVESTING
ACTIVITIES
Corporate acquisition
(Note 4) (178.9) - (178.9) -
Acquisition of petroleum
and natural gas properties (1.1) (27.6) (11.8) (51.2)
Proceeds on disposition
of petroleum and natural
gas properties - - 32.3 0.2
Capital expenditures (116.5) (169.9) (359.4) (548.1)
Net reclamation fund
contributions (Note 7) (1.5) (1.3) (4.6) (2.2)
Change in non-cash working
capital (3.0) 3.5 (28.8) 45.4
-------------------------------------------------------------------------
(301.0) (195.3) (551.2) (555.9)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS - 52.4 (40.0) 33.0
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD - (12.4) 40.0 7.0
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ - $ 40.0 $ - $ 40.0
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
December 31, 2009 and 2008
(all tabular amounts in Cdn$ millions, except per unit amounts)
1. STRUCTURE OF THE TRUST
ARC Energy Trust ("ARC" or "the Trust") was formed on May 7, 1996
pursuant to a Trust indenture (the "Trust Indenture") that has been
amended from time to time, most recently on May 15, 2006.
Computershare Trust Company of Canada was appointed as Trustee under
the Trust Indenture. The beneficiaries of ARC are the holders of the
Trust units.
ARC was created for the purposes of issuing trust units to the public
and investing the funds so raised to purchase a royalty in the
properties of ARC Resources Ltd. ("ARC Resources"). The Trust
Indenture was amended on June 7, 1999 to convert ARC from a closed-
end to an open-ended investment Trust. The current business of ARC
includes investment in energy business-related assets including, but
not limited to, petroleum and natural gas-related assets, gathering,
processing and transportation assets. The operations of ARC consist
of the acquisition, development, exploitation and disposition of
these assets and the distribution of the net cash proceeds from these
activities to the unitholders.
2. SUMMARY OF ACCOUNTING POLICIES
The Consolidated Financial Statements have been prepared by
management following Canadian generally accepted accounting
principles ("GAAP"). Effective January 1, 2011, ARC will be required
to prepare Consolidated Financial Statements in accordance with
International Financial Reporting Standards ("IFRS").
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets
and liabilities and the disclosure of contingencies at the date of
the financial statements, and revenues and expenses during the
reporting year. Actual results could differ from those estimated.
The amounts recorded for depreciation and depletion of petroleum and
natural gas property and equipment and for asset retirement
obligations are based on estimates of petroleum and natural gas
reserves and future costs. Estimates of reserves also provide the
basis for determining whether the carrying value of property, plant
and equipment is impaired. Accounts receivable are recorded at the
estimated net recoverable amount which involves estimates of
uncollectable accounts. Goodwill impairment tests involve estimates
of ARC's fair value. By their nature, these estimates are subject to
measurement uncertainty, and the impact on the financial statements
of future periods could be material.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of ARC and
its subsidiaries. Any reference to "the Trust" or "ARC" throughout
these Consolidated Financial Statements refers to the Trust and its
subsidiaries. All inter-entity transactions have been eliminated.
Revenue Recognition
Revenue associated with the sale of crude oil, natural gas, and
natural gas liquids ("NGLs") owned by ARC are recognized when title
passes from ARC to its customers.
Transportation
Costs paid by ARC for the transportation of natural gas, crude oil
and NGLs from the wellhead to the point of title transfer are
recognized when the transportation is provided.
Joint Interests
ARC conducts many of its oil and gas production activities through
jointly controlled operations and the financial statements reflect
only ARC's proportionate interest in such activities.
Depletion and Depreciation
Depletion of petroleum and natural gas properties and depreciation of
production equipment are calculated on the unit-of-production basis
based on:
(a) total estimated proved reserves calculated in accordance with
National Instrument 51-101, Standards of Disclosure for Oil and
Gas Activities;
(b) total capitalized costs, excluding undeveloped lands, plus
estimated future development costs of proved undeveloped
reserves, including future estimated asset retirement costs; and
(c) relative volumes of petroleum and natural gas reserves and
production, before royalties, converted at the energy equivalent
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil.
Whole Trust Unit Incentive Plan Compensation
ARC has established a Whole Trust Unit Incentive Plan (the "Whole
Unit Plan") for employees, independent directors and long-term
consultants who otherwise meet the definition of an employee of ARC.
Compensation expense associated with 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 intrinsic valuation method
is used as participants of the Whole Unit Plan receive a cash payment
on a fixed vesting date. This valuation incorporates the year-end
unit price, the number of RTUs and PTUs outstanding at each period
end, and certain management estimates. As a result, large
fluctuations, even recoveries, in compensation expense may occur due
to changes in the underlying unit price. In addition, compensation
expense is amortized and recognized in earnings over the vesting
period of the Whole Unit Plan with a corresponding increase or
decrease in liabilities. Classification between accrued liabilities
and accrued long-term incentive compensation is dependent on the
expected payout date.
ARC charges amounts relating to head office employees to general and
administrative expense, amounts relating to field employees to
operating expense and amounts relating to geologists and
geophysicists to property, plant and equipment.
ARC has not incorporated an estimated forfeiture rate for RTUs and
PTUs that will not vest, rather it accounts for actual forfeitures as
they occur.
Cash Equivalents
Cash equivalents include short-term investments, such as money market
deposits or similar type instruments, with an original maturity of
three months or less when purchased.
Reclamation Funds
Reclamation funds hold investment grade assets and cash and cash
equivalents. Investments are categorized as either held-to-maturity
or available-for-sale assets, which are initially measured at fair
value. Held-to-maturity investments are subsequently measured at
amortized cost using the effective interest method. Available-for-
sale investments are subsequently measured at fair value with changes
in fair value recognized in other comprehensive income, net of tax.
Investments carried at amortized cost are subject to impairment
losses in the event of an other than temporary decline in market
value.
Property, Plant and Equipment ("PP&E")
ARC follows the full cost method of accounting. All costs of
exploring, developing, enhancing and acquiring petroleum and natural
gas properties, including asset retirement costs, are capitalized and
accumulated in one cost centre as all operations are in Canada.
Maintenance and repairs are charged against earnings, and renewals
and enhancements that extend the economic life of the PP&E are
capitalized. Gains and losses are not recognized upon disposition of
petroleum and natural gas properties unless such a disposition would
alter the rate of depletion by 20 per cent or more.
Impairment
ARC places a limit on the aggregate carrying value of PP&E, which may
be amortized against revenues of future periods.
Impairment is recognized if the carrying amount of the PP&E exceeds
the sum of the undiscounted cash flows expected to result from ARC's
proved reserves. Cash flows are calculated based on third party
quoted forward prices, adjusted for ARC's contract prices and quality
differentials.
Upon recognition of impairment, ARC would then measure the amount of
impairment by comparing the carrying amounts of the PP&E to an amount
equal to the estimated net present value of future cash flows from
proved plus risked probable reserves. ARC's risk-free interest rate
is used to arrive at the net present value of the future cash flows.
Any excess carrying value above the net present value of ARC's future
cash flows would be recorded as a permanent impairment and charged
against net income.
The cost of unproved properties is excluded from the impairment test
described above and subject to a separate impairment test. In the
case of impairment, the book value of the impaired properties is
moved to the petroleum and natural gas depletable base.
Goodwill
ARC must record goodwill relating to a corporate acquisition when the
total purchase price exceeds the fair value for accounting purposes
of the net identifiable assets and liabilities of the acquired
company. The goodwill balance is assessed for impairment annually at
year-end or as events occur that could result in an indication of
impairment. Impairment is recognized based on the fair value of the
reporting entity compared to the book value of the reporting entity.
If the fair value of the entity is less than the book value,
impairment is measured by allocating the fair value to the
identifiable assets and liabilities as if the entity had been
acquired in a business combination for a purchase price equal to its
fair value. The excess of the fair value over the amounts assigned to
the identifiable assets and liabilities is the fair value of the
goodwill. Any excess of the book value of goodwill over this implied
fair value of goodwill is the impairment amount. Impairment is
charged to earnings in the period in which it occurs.
Goodwill is stated at cost less impairment and is not amortized.
Asset Retirement Obligations
ARC recognizes an Asset Retirement Obligation ("ARO") in the period
in which it is incurred when a reasonable estimate of the fair value
can be made. On a periodic basis, management will review these
estimates and changes, if any, will be applied prospectively. The
fair value of the estimated ARO is recorded as a long-term liability,
with a corresponding increase in the carrying amount of the related
asset. The capitalized amount is depleted on a unit-of-production
basis over the life of the reserves. The liability amount is
increased each reporting period due to the passage of time and the
amount of accretion is charged to earnings in the period. Revisions
to the estimated timing of cash flows or to the original estimated
undiscounted cost would also result in an increase or decrease to the
ARO. Actual costs incurred upon settlement of the obligation are
charged against the ARO to the extent of the liability recorded.
Income Taxes
ARC follows the liability method of accounting for income taxes.
Under this method, income tax liabilities and assets are recognized
for the estimated tax consequences attributable to differences
between the amounts reported in the financial statements of ARC and
ARC's corporate subsidiaries and their respective tax base, using
substantively enacted future income tax rates. The effect of a change
in income tax rates on future tax liabilities and assets is
recognized in income in the period in which the change occurs,
provided that the income tax rates are substantively enacted.
Temporary differences arising on acquisitions result in future income
tax assets and liabilities.
Basic and Diluted per Trust Unit Calculations
Basic net income per unit is computed by dividing net income after
non-controlling interest by the weighted average number of trust
units outstanding during the period. Diluted net income per unit
amounts are calculated based on net income before non-controlling
interest divided by dilutive trust units. Dilutive trust units are
arrived at by adding weighted average trust units to trust units
issuable on conversion of exchangeable shares, and to the potential
dilution that would occur if rights were exercised at the beginning
of the period. The treasury stock method assumes that proceeds
received from the exercise of in-the-money rights and the
unrecognized trust unit incentive compensation are used to repurchase
units at the average market price.
Financial Instruments
Financial assets, financial liabilities and non-financial derivatives
are measured at fair value on initial recognition. Measurement in
subsequent periods depends on whether the financial instrument has
been classified as held-for-trading, available-for-sale, held-to-
maturity, loans and receivables, or other financial liabilities.
a. Held-for-trading
Financial assets and liabilities designated as held-for-trading
are subsequently measured at fair value with changes in those fair
values charged immediately to earnings. With the exception of risk
management contracts that qualify for hedge accounting, ARC
classifies all risk management contracts as held-for-trading. Cash
and cash equivalents are also classified as held-for-trading.
b. Available-for-sale assets
Available-for-sale financial assets are subsequently measured at
fair value with changes in fair value recognized in Other
Comprehensive Income ("OCI"), net of tax. Amounts recognized in
OCI for available-for-sale financial assets are charged to
earnings when the asset is derecognized or when there is an other
than temporary asset impairment. ARC classifies its reclamation
funds as available-for-sale assets.
c. Held-to-maturity investments, loans and receivables and other
financial liabilities
Held-to-maturity investments, loans and receivables, and other
financial liabilities are subsequently measured at amortized cost
using the effective interest method. ARC classifies accounts
receivable to loans and receivables, and accounts payable,
distributions payable and long-term debt to other financial
liabilities.
Transaction costs are expensed as incurred for all financial
instruments.
ARC has elected January 1, 2003 as the effective date to identify and
measure embedded derivatives in financial and non-financial contracts
that are not closely related to the host contracts.
ARC is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the
normal course of operations. A variety of derivative instruments are
used by ARC to reduce its exposure to fluctuations in commodity
prices, foreign exchange rates, and interest rates. The fair values
of these derivative instruments are based on an estimate of the
amounts that would have been received or paid to settle these
instruments prior to maturity. ARC considers all of these
transactions to be effective economic hedges; however, most of ARC's
contracts do not qualify or have not been designated as effective
hedges for accounting purposes.
For transactions that do not qualify for hedge accounting, ARC
applies the fair value method of accounting by recording an asset or
liability on the Consolidated Balance Sheet and recognizing changes
in the fair value of the instruments in earnings during the current
period.
For derivative instruments that do qualify as effective accounting
hedges, policies and procedures are in place to ensure that the
required documentation and approvals are obtained. This documentation
specifically ties the derivative financial instruments to their use,
and in the case of commodities, to the mitigation of market price
risk associated with cash flows expected to be generated. When
applicable, ARC also identifies all relationships between hedging
instruments and hedged items, as well as its risk management
objective and the strategy for undertaking hedge transactions. This
would include linking the particular derivative to specific assets
and liabilities on the Consolidated Balance Sheet or to specific firm
commitments or forecasted transactions.
Where specific hedges are executed, ARC assesses, both at the
inception of the hedge and on an ongoing basis, whether the
derivative used in the particular hedging transaction is effective in
offsetting changes in fair value or cash flows of the hedged item.
Hedge accounting is discontinued prospectively when the derivative no
longer qualifies as an effective hedge, or the derivative is
terminated or sold, or upon the sale or early termination of the
hedged item. ARC has currently designated a portion of its financial
electricity contracts as effective cash flow hedges.
In a cash flow hedging relationship, the effective portion of the
change in the fair value of the hedging derivative is recognized in
OCI while the ineffective portion is recognized in earnings. When
hedge accounting is discontinued, the amounts previously recognized
in Accumulated Other Comprehensive Income ("AOCI") are reclassified
to earnings during the periods when the variability in the cash flows
of the hedged item affects earnings. Gains and losses on derivatives
are reclassified immediately to earnings when the hedged item is sold
or early terminated.
When hedge accounting is applied to a derivative used to hedge an
anticipated transaction and it is determined that the anticipated
transaction will not occur within the originally specified time
period, hedge accounting is discontinued and the unrealized gains and
losses are reclassified from AOCI to earnings.
Foreign Currency Translation
Monetary assets and liabilities denominated in a foreign currency are
translated at the rate of exchange in effect at the Consolidated
Balance Sheet date. Revenues and expenses are translated at the
period average rates of exchange. Translation gains and losses are
included in earnings in the period in which they arise.
Non-Controlling Interest
ARC must record non-controlling interest when exchangeable shares
issued by a subsidiary of ARC are transferable to third parties. Non-
controlling interest on the Consolidated Balance Sheet is recognized
based on the fair value of the exchangeable shares upon issuance plus
the accumulated earnings attributable to the non-controlling
interest. Net income is reduced for the portion of earnings
attributable to the non-controlling interest. As the exchangeable
shares are converted to Trust units, the non-controlling interest on
the Consolidated Balance Sheet is reduced by the cumulative book
value of the exchangeable shares and Unitholders' capital is
increased by the corresponding amount.
3. NEW ACCOUNTING POLICIES
Current Year Accounting Changes
Effective January 1, 2009, ARC 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 ARC or its Consolidated Financial
Statements. This standard was adopted prospectively.
Effective December 31, 2009, ARC adopted CICA issued amendments to
Handbook Section 3862, Financial Instruments - Disclosures. The
amendments include enhanced disclosures relating to the fair value of
financial instruments and the liquidity risk associated with
financial instruments. Section 3862 now requires that all financial
instruments measured at fair value be categorized into one of three
hierarchy levels. Refer to Note 13 Financial Instruments and Risk
Management for enhanced fair value disclosures and Note 9 Financial
Liabilities and Liquidity Risk for liquidity risk disclosures. The
amendments are consistent with recent amendments to financial
instrument disclosure standards in IFRS.
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 applies prospectively
to business combinations on or after January 1, 2011 with earlier
application permitted. ARC is currently assessing the impact of the
standard.
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 ARC for business
combinations occurring on or after January 1, 2011 with early
application permitted. ARC is currently assessing the impact of the
standard.
4. CORPORATE ACQUISITIONS
On December 21, 2009, ARC acquired all of the issued and outstanding
shares of two legal entities - 1504793 Alberta Ltd. and PetroBakken
General Partnership No. 1 (collectively "Ante Creek") - for total
consideration of $178.9 million. The allocation of the purchase price
and consideration paid were as follows:
Net Assets Acquired
---------------------------------------------------------------------
Property, plant and equipment $ 231.0
Asset retirement obligations (4.0)
Future income taxes (48.1)
---------------------------------------------------------------------
Total net assets acquired $ 178.9
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration Paid
---------------------------------------------------------------------
Cash and fees paid $ 178.9
---------------------------------------------------------------------
Total consideration paid $ 178.9
---------------------------------------------------------------------
---------------------------------------------------------------------
The acquisition of Ante Creek has been accounted for as an asset
acquisition pursuant to EIC - 124.
The future income tax liability on acquisition was based on the
difference between the fair value of the acquired net assets of
$178.9 million and the associated tax basis of $35.8 million.
These Consolidated Financial Statements incorporate the results of
operations of the acquired Ante Creek properties from December 21,
2009.
5. CASH AND CASH EQUIVALENTS
Cash and cash equivalents are nil as at December 31, 2009
($40 million in Canadian Treasury Bills as at December 31, 2008).
6. FINANCIAL ASSETS AND CREDIT RISK
Credit risk is the risk of financial loss to ARC if a partner or
counterparty to a product sales contract or financial instrument
fails to meet its contractual obligations. ARC is exposed to credit
risk with respect to its cash equivalents, accounts receivable,
reclamation funds, and risk management contracts. Most of ARC's
accounts receivable relate to oil and natural gas sales and are
subject to typical industry credit risks. ARC manages this credit
risk as follows:
- By entering into sales contracts with only established credit
worthy counterparties as verified by a third party rating agency,
through internal evaluation or by requiring security such as
letters of credit;
- By limiting exposure to any one counterparty in accordance with
ARC's credit policy; and
- By restricting cash equivalent investments, reclamation fund
investments, and risk management transactions to counterparties
that, at the time of transaction, are not less than investment
grade.
The majority of the credit exposure on accounts receivable at
December 31, 2009 pertains to accrued revenue for December 2009
production volumes. ARC 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 ARC by the 25th day of the month following
production. Joint interest receivables are typically collected within
one to three months following production. At December 31, 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.
For the year ended December 31, 2009, ARC recorded a recovery of
$1.7 million for amounts received on balances previously included in
ARC's allowance for doubtful accounts. The recovery includes
$1.2 million for settlement of oil revenues that were previously due
from SemCanada Crude ("SemCanada"), a counterparty that marketed a
portion of ARC's production and had filed for protection under the
Companies' Creditors Arrangement Act in 2008. The remaining
$0.5 million is composed of $0.6 million recovered from one
counterparty and $0.1 million written off for balances deemed
uncollectable from various counterparties.
ARC's allowance for doubtful accounts was $0.8 million as at
December 31, 2009 and $32 million as at December 31, 2008. In 2008,
ARC recorded a provision for the full receivable of $30.6 million due
from SemCanada. As noted above, upon settlement of the SemCanada oil
revenue claim, ARC recovered $1.2 million and has written off the
balance in the allowance of $28.8 million. As at December 31, 2009,
$0.6 million remains in the allowance for the SemCanada gas revenue
claim. The remaining movement of $1.2 million is composed of
$0.6 million settled on balances previously included in the provision
and $0.6 million written off for balances deemed uncollectable.
During the twelve months of 2009 ARC 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
December 31, 2009, $4.4 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.
7. RECLAMATION FUNDS
---------------------------------------------------------------------
December 31, 2009 December 31, 2008
---------------------------------------------------------------------
Unrestricted Restricted Unrestricted Restricted
---------------------------------------------------------------------
Balance, beginning
of year $ 11.2 $ 17.0 $ 14.4 $ 11.7
Contributions 6.2 5.3 5.8 5.9
Reimbursed
expenditures(1) (5.9) (1.8) (9.7) (1.0)
Interest earned
on funds 0.7 0.1 0.8 0.4
Net unrealized gains
and losses on
available-for-sale
investments 0.4 - (0.1) -
---------------------------------------------------------------------
Balance, end of
year(2) $ 12.6 $ 20.6 $ 11.2 $ 17.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by ARC due to
timing differences and discretionary reimbursements.
(2) As at December 31, 2009 the unrestricted reclamation fund held
$0.2 million in cash and cash equivalents (nil at December 31,
2008), with the balance held in investment grade assets.
ARC has established two reclamations funds to finance future asset
retirement obligations; one fund has been restricted to finance
obligations specifically associated with the Redwater property, with
the unrestricted fund financing all other obligations. Contributions
to the restricted and unrestricted reclamation funds and interest
earned on the balances have been deducted from the cash distributions
to the unitholders. The Board of Directors of ARC Resources has
approved voluntary contributions to the unrestricted reclamation fund
over a 20-year period that currently results in minimum annual
contributions of $6 million ($6 million in 2008) based upon
properties owned as at December 31, 2009. Required contributions to
the restricted reclamation fund will vary over time and have been
disclosed in Note 22. Contributions for both funds are continually
reassessed to ensure that the funds are sufficient to finance the
majority of future abandonment obligations. Interest earned on the
funds is retained within the funds.
For the years ended December 31, 2009 and December 31, 2008, nominal
amounts relating to available-for-sale reclamation fund assets were
classified from accumulated other comprehensive income into earnings.
As at December 31, 2009 all reclamation fund assets are reflected at
fair value. The fair values are obtained from third parties,
determined directly by reference to quoted market prices.
8. PROPERTY, PLANT AND EQUIPMENT
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Property, plant and equipment, at cost $ 6,242.8 $ 5,668.9
Accumulated depletion and depreciation (2,669.4) (2,292.3)
---------------------------------------------------------------------
Property, plant and equipment, net $ 3,573.4 $ 3,376.6
---------------------------------------------------------------------
---------------------------------------------------------------------
The calculation of 2009 depletion and depreciation included an
estimated $1,060 million ($872 million in 2008) for future
development costs associated with proved undeveloped reserves and
excluded $268.9 million ($287.5 million in 2008) for the book value
of unproved properties.
ARC performed a ceiling test calculation at December 31, 2009 to
assess the recoverable value of property plant and equipment
("PP&E"). Based on the calculation, the value of future net revenues
from ARC's reserves exceeded the carrying value of ARC's PP&E at
December 31, 2009. The benchmark prices used in the calculation were
as follows:
WTI Oil AECO Gas Cdn$/US$
Year (US$/bbl) (Cdn$/mmbtu) Exchange Rates
---------------------------------------------------------------------
2010 80.00 5.96 0.95
2011 83.00 6.79 0.95
2012 86.00 6.89 0.95
2013 89.00 6.95 0.95
2014 92.00 7.05 0.95
2015 93.84 7.16 0.95
2016 95.72 7.42 0.95
2017 97.64 7.95 0.95
2018 99.59 8.52 0.95
2019 101.58 8.69 0.95
---------------------------------------------------------------------
Remainder(1) 2.0% 2.0% 0.95
---------------------------------------------------------------------
(1) Percentage change represents the change in each year after 2019
to the end of the reserve life.
9. FINANCIAL LIABILITIES AND LIQUIDITY RISK
Liquidity risk is the risk that ARC will not be able to meet its
financial obligations as they become due. ARC actively manages its
liquidity through cash, distribution policy, and debt and equity
management strategies. Such strategies include continuously
monitoring forecasted and actual cash flows from operating, financing
and investing activities, available credit under existing banking
arrangements and opportunities to issue additional Trust units.
Management believes that future cash flows generated from these
sources will be adequate to settle ARC's financial liabilities.
The following table details ARC's financial liabilities as at
December 31, 2009:
---------------------------------------------------------------------
($ millions) 1 year 2 - 3 4 - 5 Beyond Total
years years 5 years
---------------------------------------------------------------------
Accounts payable
and accrued
liabilities(1) 166.7 - - - 166.7
Distributions
payable(2) 18.9 - - - 18.9
Risk management
contracts(3) 14.8 2.1 - - 16.9
Senior secured
notes and interest 47.1 109.9 131.6 152.9 441.5
Revolving credit
facilities - 497.3 - - 497.3
Working capital
facility 7.9 - - - 7.9
Accrued long-term
incentive
compensation(1) 28.4 36.0 - - 64.4
---------------------------------------------------------------------
Total financial
liabilities 283.8 645.3 131.6 152.9 1,213.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Liabilities under the Whole Trust Unit Incentive Plan represent
the total amount expected to be paid out on vesting.
(2) Amounts payable for the distribution represents the net cash
payable after distribution reinvestment.
(3) Amounts payable for the risk management contracts have been
included gross at their future value.
ARC actively maintains credit and working capital facilities to
ensure that it has sufficient available funds to meet its financial
requirements at a reasonable cost. Refer to Note 10 for further
details on available amounts under existing banking arrangements and
Note 12 for further details on capital management.
10. LONG-TERM DEBT
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Syndicated credit facilities:
Cdn$ denominated(1) $ 423.0 $ 399.5
US$ denominated 74.3 240.6
Working capital facility 7.9 2.1
Senior secured notes:
Master Shelf Agreement
5.42% US$ Note 78.5 91.9
4.94% US$ Note 6.3 14.7
2004 Note Issuance
4.62% US$ Note 54.5 76.5
5.10% US$ Note 65.4 76.5
2009 Note Issuance
7.19% US$ Note 70.6 -
8.21% US$ Note 36.6 -
6.50% Cdn$ Note 29.0 -
---------------------------------------------------------------------
Total long-term debt outstanding $ 846.1 $ 901.8
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Syndicated credit facility balance was reduced on January 5,
2010. Refer to Note 23 for further details.
Credit Facilities
ARC has an $800 million secured, annually extendible, financial
covenant-based syndicated credit facility. ARC also has in place a
$25 million demand working capital facility. The working capital
facility is also 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 December 31, 2009, four per cent at
December 31, 2008) or, at ARC's option, Canadian dollar bankers'
acceptances or U.S. dollar LIBOR loans, plus a stamping fee. At the
option of ARC, 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 syndicated 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. During 2009, the weighted-average interest rate under the
credit facility was 1.1 per cent (3.8 per cent in 2008).
Senior Secured Notes Issued Under a Master Shelf Agreement
These senior secured notes were issued in two separate tranches
pursuant to an Uncommitted Master Shelf Agreement. The terms and
rates of these senior secured notes are summarized below:
---------------------------------------------------------------------
Remaining Coupon Maturity Principal
Issue Date Principal Rate Date Payment Terms
---------------------------------------------------------------------
October 19, US$6.0 4.94% October 19, Five equal
2002 2010 installments
beginning
October 19, 2006
December 15, US$75.0 5.42% December 15, Eight equal
2005 2017 installments
beginning
December 15,
2010
---------------------------------------------------------------------
---------------------------------------------------------------------
In the second quarter of 2009 ARC extended its Uncommitted Master
Shelf Agreement from May 2009 to April 2012. The extended agreement
allows for an aggregate draw of up to US$225 million in notes at a
rate equal to the related U.S. treasuries corresponding to the term
of the notes plus an appropriate credit risk adjustment at the time
of issuance.
Senior Secured Notes not Subject to the Master Shelf Agreement
2004 Note Issuance
These notes were issued on April 27, 2004 via a private placement in
two tranches. The terms and rates of these senior secured notes are
summarized below.
2009 Note Issuance
These notes were issued on April 14, 2009 via a private placement in
three tranches. The terms and rates of these senior secured notes are
summarized below.
---------------------------------------------------------------------
Remaining Coupon Maturity
Issue Date Principal Rate Date Payment Terms
---------------------------------------------------------------------
April 27, US$52.1 4.62% April 27, Six equal
2004 2014 installments
beginning
April 27, 2009
April 27, US$62.5 5.10% April 27, Five equal
2004 2016 installments
beginning
April 27, 2012
April 14, US$67.5 7.19% April 14, Five equal
2009 2016 installments
beginning
April 14, 2012
April 14, US$35.0 8.21% April 14, Five equal
2009 2021 installments
beginning
April 14, 2017
April 14, Cdn$29.0 6.50% April 14, Five equal
2009 2016 installments
beginning
April 14, 2012
---------------------------------------------------------------------
---------------------------------------------------------------------
Credit Capacity
The following table summarizes ARC's available credit capacity and
the current amounts drawn as at December 31, 2009:
---------------------------------------------------------------------
Credit
Capacity Drawn Remaining
---------------------------------------------------------------------
Syndicated Credit Facility $ 800.0 $ 497.3 $ 302.7
Working Capital Facility 25.0 7.9 17.1
Senior Secured Notes Subject
to a Master Shelf Agreement(1) 235.5 84.8 150.7
Senior Secured Notes Not Subject
to a Master Shelf Agreement 256.1 256.1 -
---------------------------------------------------------------------
Total $ 1,316.6 $ 846.1 $ 470.5
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Total credit capacity is US$225 million.
Debt Covenants
The following are the significant financial covenants governing the
revolving credit facilities:
- Long-term debt and letters of credit not to exceed three times
trailing twelve month net income before non-cash items and
interest expense;
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times trailing twelve month net income before non-
cash items and interest expense; and
- Long-term debt and letters of credit not to exceed 50 per cent of
the book value of unitholders' equity and long-term debt, letters
of credit, and subordinated debt.
In the event that ARC enters into a material acquisition whereby the
purchase price exceeds 10 per cent of the book value of ARC's assets,
the ratio in the first covenant is increased to 3.5 times, while the
third covenant is increased to 55% for the subsequent six month
period. As at December 31, 2009, ARC had $2 million in letters of
credit ($1.9 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.
Supplemental disclosures
The fair value of all senior secured notes as at December 31, 2009,
is $347.3 million compared to a carrying value of $340.9 million
($289.9 million compared to $259.6 million as at December 31, 2008),
and is calculated as the present value of principal and interest
payments discounted at ARC's credit adjusted risk free rate.
Amounts of US$16.4 million due under the senior secured notes
(includes US$6 million attributable to the Master Shelf Agreement)
and $7.9 million due under ARC'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 2009 was $2.6 million more than interest expense
($1.6 million more in 2008).
ARC'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.
11. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligations were estimated by
management based on ARC's net ownership interest in all wells and
facilities, estimated costs to reclaim and abandon the wells and
facilities and the estimated timing of the costs to be incurred in
future periods. ARC has estimated the net present value of its total
asset retirement obligations to be $149.9 million as at December 31,
2009 ($141.5 million in 2008) based on a total future undiscounted
liability of $1.36 billion ($1.32 billion in 2008). At December 31,
2009 management estimates that these payments are expected to be made
over the next 51 years with the majority of payments being made in
years 2050 to 2060. ARC's weighted average credit adjusted risk free
rate of 6.5 per cent (6.6 per cent in 2008) and an inflation rate of
two per cent (two per cent in 2008) were used to calculate the
present value of the asset retirement obligations. During the year,
no gains or losses were recognized on settlements of asset retirement
obligations.
The following table reconciles ARC's asset retirement obligations:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of year $ 141.5 $ 140.0
Increase in liabilities relating to
corporate acquisitions 4.0 -
Increase in liabilities relating to
development activities 1.7 2.0
Increase in liabilities relating to
change in estimate 2.1 2.6
Settlement of reclamation liabilities
during the year (8.7) (12.4)
Accretion expense 9.3 9.3
---------------------------------------------------------------------
Balance, end of year $ 149.9 $ 141.5
---------------------------------------------------------------------
---------------------------------------------------------------------
12. CAPITAL MANAGEMENT
The objective of ARC when managing its capital is to maintain a
conservative structure that will allow it 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
ARC 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 ARC's capital structure, management's objective is to
limit net debt to less than two times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
December 31, 2009 ARC's net debt to annualized cash flow from
operating activities ratio is 1.8 and its net debt to total
capitalization ratio is 15.9 per cent.
---------------------------------------------------------------------
($ millions, except per unit December 31, December 31,
and per cent amounts) 2009 2008
---------------------------------------------------------------------
Long-term debt 846.1 901.8
Accounts payable and accrued liabilities 166.7 194.4
Distributions payable 23.7 32.5
Cash and cash equivalents, accounts
receivable and prepaid expenses (134.1) (166.8)
---------------------------------------------------------------------
Net debt obligations(1) 902.4 961.9
---------------------------------------------------------------------
Trust units outstanding and issuable for
exchangeable shares (millions) 239.0 219.2
Trust unit price(2) 19.94 20.10
---------------------------------------------------------------------
Market capitalization(1) 4,765.7 4,405.9
Net debt obligations(1) 902.4 961.9
---------------------------------------------------------------------
Total capitalization(1) 5,668.1 5,367.8
---------------------------------------------------------------------
Net debt as a percentage of total
capitalization 15.9% 17.9%
Net debt obligations to annualized cash
flow from operating activities 1.8 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 December 31, 2009 and December 31, 2008
respectively.
ARC manages its capital structure and makes adjustments to it in
response to changes in economic conditions and the risk
characteristics of the underlying assets. ARC 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 ARC is subject to various
covenants under its credit facilities. Compliance with these
covenants is monitored on a quarterly basis and as at December 31,
2009 ARC is in compliance with all covenants. Refer to Note 10 for
further details.
13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial Instrument Classification and Measurement
Financial instruments of ARC carried on the Consolidated Balance
Sheet are carried at amortized cost with the exception of cash and
cash equivalents, reclamation fund assets and risk management
contracts, which are carried at fair value. With the exception of
ARC's senior secured notes, there were no significant differences
between the carrying value of financial instruments and their
estimated fair values as at December 31, 2009. The fair value of the
ARC's senior secured notes is disclosed in Note 10.
All of ARC's cash and cash equivalents, risk management contracts,
and reclamation fund investments are transacted in active markets.
ARC classifies the fair value of these transactions according to the
following hierarchy based on the amount of observable inputs used to
value the instrument.
- Level 1 - Quoted prices are available in active markets for
identical assets or liabilities as of the reporting date. Active
markets are those in which transactions occur in sufficient
frequency and volume to provide pricing information on an ongoing
basis.
- Level 2 - Pricing inputs are other than quoted prices in active
markets included in Level 1. Prices in Level 2 are either
directly or indirectly observable as of the reporting date. Level
2 valuations are based on inputs, including quoted forward prices
for commodities, time value and volatility factors, which can be
substantially observed or corroborated in the marketplace.
- Level 3 - Valuations in this level are those with inputs for the
asset or liability that are not based on observable market data.
ARC's cash and cash equivalents, reclamation fund assets and risk
management contracts have been assessed on the fair value hierarchy
described above. ARC's cash and cash equivalents and reclamation fund
assets are classified as Level 1 and risk management contracts as
Level 2. Assessment of the significance of a particular input to the
fair value measurement requires judgment and may affect the placement
within the fair value hierarchy level.
Market Risk Management
ARC is exposed to a number of market risks that are part of its
normal course of business. ARC 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 ARC'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 ARC'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
ARC's operational results and financial condition 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
December 31, 2009. The sensitivity is based on a $15 increase and $15
decrease in the price of US$ WTI crude oil and a $1.50 increase and
$1.50 decrease in the price of Cdn$ 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 December 31, 2009 and ARC's next reporting date.
---------------------------------------------------------------------
Increase in Commodity Price Decrease in Commodity Price
---------------------------------------------------------------------
Crude oil Natural gas Crude oil Natural gas
---------------------------------------------------------------------
Net income
(decrease)
increase $ (21.7) $ (54.6) $ 19.1 $ 54.1
---------------------------------------------------------------------
---------------------------------------------------------------------
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 ARC'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
ARC has both fixed and variable interest rates on its debt. Changes
in interest rates could result in an increase or decrease in the
amount ARC pays to service variable interest rate debt, potentially
impacting distributions to unitholders. Changes in interest rates
could also result in fair value risk on ARC's fixed rate senior
secured notes. Fair value risk of the senior secured notes is
mitigated due to the fact that ARC does not intend to settle its
fixed rate debt prior to maturity.
If interest rates applicable to floating rate debt at December 31,
2009 were to have increased by 50 bps (0.5 per cent) it is estimated
that ARC's net income would decrease by $1.9 million. Management does
not expect interest rates to decrease.
Foreign Exchange Risk
North American oil and natural gas prices are based upon U.S. dollar
denominated commodity prices. As a result, the price received by
Canadian producers is affected by the Canadian/U.S. dollar exchange
rate that may fluctuate over time. In addition ARC has U.S. dollar
denominated debt and interest obligations of which future cash
repayments are directly impacted by the exchange rate in effect on
the repayment date. Variations in the Canadian/U.S. dollar exchange
rate could also have a positive or negative impact on distributions
to unitholders.
The following table demonstrates the effect of exchange rate
movements on net income due to changes in the fair value of risk
management contracts in place at December 31, 2009 as well as the
unrealized gain or loss on revaluation of outstanding US$ denominated
debt. The sensitivity is based on a $0.10 Cdn$/US$ increase and $0.10
Cdn$/US$ decrease in the foreign exchange rate.
---------------------------------------------------------------------
Increase in Decrease in
Cdn$/US$ rate Cdn$/US$ rate
---------------------------------------------------------------------
Increase gain/decrease loss
(increase loss/decrease gain) on
risk management contracts $ 1.5 $ (1.5)
(Increase loss/decrease gain)
increase gain/decrease loss on
foreign exchange (28.6) 29.5
---------------------------------------------------------------------
Net income (decrease) increase $ (27.1) $ 28.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Increases and decreases in foreign exchange rates applicable to US$
payables and receivables would have a nominal impact on ARC's net
income for the period ended December 31, 2009.
Risk Management Contracts
ARC uses a variety of derivative instruments to reduce its exposure
to fluctuations in commodity prices, foreign exchange rates, interest
rates and power prices. ARC considers all of these transactions to be
effective economic hedges; however, the majority of ARC's contracts
do not qualify as effective hedges for accounting purposes.
Following is a summary of all risk management contracts in place as
at December 31, 2009 that do not qualify for hedge accounting:
---------------------------------------------------------------------
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-Jan-10 31-Mar-10 Collar 1,000 $65.00 - $80.00
1-Jan-10 31-Dec-10 Collar 4,000 $70.00 - $90.00
1-Jan-10 31-Dec-10 Collar 2,000 $75.00 - $95.00
1-Jan-10 31-Dec-10 3-way collar 2,000 $80.00 $60.00 $95.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Monthly average
---------------------------------------------------------------------
Financial AECO Natural Gas Swap Contracts(2)
---------------------------------------------------------------------
Sold
Volume Swap
Term Contract GJ/d Cdn$/GJ
---------------------------------------------------------------------
1-Jan-10 31-Dec-10 Swap 80,000 $5.61
1-Jan-11 31-Dec-13 Swap 20,000 $6.16
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) AECO 7a monthly index
---------------------------------------------------------------------
Financial NYMEX Natural Gas Swap Contracts(3)
---------------------------------------------------------------------
Volume Sold Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
1-Apr-10 31-Oct-10 Swap 20,000 $6.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) Last 3 Day Settlement
---------------------------------------------------------------------
Financial Basis Swap Contract(4)
---------------------------------------------------------------------
Volume Basis Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
1-Jan-10 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 ($0.4067)
---------------------------------------------------------------------
---------------------------------------------------------------------
(4) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO 7a
monthly index
---------------------------------------------------------------------
US$ Debt Repayment Contracts
---------------------------------------------------------------------
Notional
Volume Swap Swap
Settlement Date Contract US$ millions Cdn$/US$ US$/Cdn$
---------------------------------------------------------------------
21-Jan-10 Forward 20.00 $1.0480 $0.9542
---------------------------------------------------------------------
---------------------------------------------------------------------
---------------------------------------------------------------------
Financial Electricity Heat Rate Contracts(5)
---------------------------------------------------------------------
Heat
Volume AESO Power AECO 5a multiplied Rate
Term Contract MWh $/MWh $/GJ by GJ/MWh
---------------------------------------------------------------------
1-Jan-10 Heat Rate Receive Pay AECO
31-Dec-10 Swap 10 AESO 5a x 9.15
1-Jan-11 Heat Rate Receive Pay AECO
31-Dec-11 Swap 15 AESO 5a x 9.08
1-Jan-12 Heat Rate Receive Pay AECO
31-Dec-13 Swap 10 AESO 5a x 9.15
---------------------------------------------------------------------
---------------------------------------------------------------------
(5) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index
---------------------------------------------------------------------
Financial Electricity Contracts(6)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Jan-10 31-Dec-12 Swap 5 $72.495
---------------------------------------------------------------------
---------------------------------------------------------------------
(6) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index
Following is a summary of all risk management contracts in place as
at December 31, 2009 that qualify for hedge accounting:
---------------------------------------------------------------------
Financial Electricity Contracts(7)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Jan-10 31-Dec-10 Swap 5 $63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(7) Alberta Power Pool (monthly average 24x7), AECO 5a monthly index
At December 31, 2009, the fair value of the contracts that were not
designated as accounting hedges was a loss of $4.3 million. ARC
recorded a gain on risk management contracts of $11.7 million in the
statement of income for the year ended December 31, 2009
($7.7 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
ARC's financial risk management contracts that have not been
designated as effective accounting hedges:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Fair value, beginning of year $ 3.4 $ (64.6)
Fair value, end of year(1) (4.3) 3.4
---------------------------------------------------------------------
Change in fair value of contracts in the year (7.7) 68.0
Realized gain (loss) in the year 19.4 (75.7)
---------------------------------------------------------------------
Gain (loss) on risk management contracts $ 11.7 $ (7.7)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $3.5 million at
December 31, 2009 ($0.9 million loss at December 31, 2008).
During 2007 ARC entered into treasury rate lock contracts in order to
manage ARC'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.
ARC's electricity contracts are intended to manage price risk on
electricity consumption. Portions of ARC's financial electricity
contracts were designated as effective accounting hedges on their
respective contract dates. A realized loss of $1.5 million for the
year ended December 31, 2009 (gain of $3.9 million in 2008) has been
included in operating costs on these electricity contracts. The
accumulated unrealized fair value loss of $0.5 million on these
contracts has been recorded on the Consolidated Balance Sheet at
December 31, 2009 with the movement in fair value recorded in OCI,
net of tax. The fair value movement for the year ended December 31,
2009 is an unrealized loss of $3.8 million. As at December 31, 2009
all 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 ARC's financial risk
management contracts that have been designated as effective
accounting hedges:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Fair value, beginning of year $ 3.3 $ (3.4)
Change in fair value of financial
electricity contracts (3.8) (0.7)
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 year(1) $ (0.5) $ 3.3
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts designated as
effective accounting hedges equals a loss of $0.5 million at
December 31, 2009 ($3.4 million gain at December 31, 2008).
14. GAIN (LOSS) ON FOREIGN EXCHANGE
The following is a summary of the total gain (loss) on US$
denominated transactions:
---------------------------------------------------------------------
Three Months Twelve Months
Ended Ended
December 31 December 31
---------------------------------------------------------------------
2009 2008 2009 2008
---------------------------------------------------------------------
Unrealized gain (loss) on
US$ denominated debt $ 5.7 $ (63.9) $ 66.3 $ (90.8)
Realized gain on US$
denominated debt repayments 3.1 2.3 2.7 2.3
---------------------------------------------------------------------
Total non-cash gain (loss) on
US$ denominated transactions 8.8 (61.6) 69.0 (88.5)
Realized cash gain (loss) on
US$ denominated transactions 0.9 0.4 1.0 (0.9)
---------------------------------------------------------------------
Total foreign exchange gain
(loss) $ 9.7 $ (61.2) $ 70.0 $ (89.4)
---------------------------------------------------------------------
---------------------------------------------------------------------
15. INCOME TAXES
In 2007, Income Trust tax legislation was passed resulting in a two-
tiered tax structure subjecting distributions to the federal
corporate income tax rate plus a deemed 13 per cent provincial income
tax at the Trust level commencing in 2011. On March 4, 2009
legislation was passed providing that the provincial component of the
tax on ARC is to be calculated based on the general provincial rate
in each province in which ARC has a permanent establishment. This is
the same way that a corporation would calculate its provincial tax
rate. The provincial component of the tax was substantively enacted
as of December 31, 2009 but was not substantively enacted as of
December 31, 2008. ARC has reflected a reduced tax rate in the
calculation of future income taxes in 2009.
The tax provision differs from the amount computed by applying the
combined Canadian federal and provincial statutory income tax rates
to income before future income tax recovery as follows:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Income before future income tax recovery
and non-controlling interest $ 192.3 $ 535.4
---------------------------------------------------------------------
Canadian statutory rate(1) 29.0% 32.4%
---------------------------------------------------------------------
Expected income tax expense at statutory
rates 55.8 173.4
Effect on income tax of:
Net income of ARC (86.0) (181.2)
Effect of change in corporate tax rate 7.2 (8.9)
Unrealized loss (gain) on foreign exchange (9.7) 13.4
Change in estimated pool balances (0.7) (1.0)
Other non-deductible items 0.6 (0.2)
---------------------------------------------------------------------
Future income tax recovery $ (32.8) $ (4.5)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The statutory rate consists of the combined Trust and Trust's
subsidiaries statutory tax rate
The net future income tax liability is comprised of the following:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 418.3 $ 381.4
Risk management contracts - 1.7
Other comprehensive income - 0.8
Long-term debt 8.5 0.2
Future tax assets:
Asset retirement obligations (37.6) (35.8)
Non-capital losses (49.9) (24.4)
Risk management contracts (1.1) -
Other comprehensive loss (0.1) -
Trust unit incentive compensation expense (8.2) (8.3)
Attributed Canadian royalty income (4.5) (4.6)
CEC, SR&ED pools and deductible share
issue costs (3.6) (1.6)
---------------------------------------------------------------------
Net future income tax liability $ 321.8 $ 309.4
---------------------------------------------------------------------
Net future income tax asset, current $ 7.1 $ 3.9
Net future income tax liability, long-term $ 328.9 $ 313.3
---------------------------------------------------------------------
---------------------------------------------------------------------
The petroleum and natural gas properties and facilities owned by ARC
have an approximate tax basis of $2.23 billion ($2.07 billion in
2008) available for future use as deductions from taxable income.
Included in this tax basis are estimated non-capital loss carry
forwards of $181.9 million ($86.9 million in 2008) that expire in the
years 2027 through 2029. The following is a summary of the estimated
ARC tax pools:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Canadian oil and gas property expenses $ 951.6 $ 1,001.3
Canadian development expenses 391.1 360.7
Canadian exploration expenses 105.6 41.5
Undepreciated capital costs 432.2 414.5
Non-capital losses 181.9 86.9
SR&ED tax pools 0.8 0.3
Other 15.2 7.0
---------------------------------------------------------------------
Estimated tax basis, federal 2,078.4 1,912.2
---------------------------------------------------------------------
Provincial tax pools 155.5 155.9
---------------------------------------------------------------------
Estimated tax basis, federal and provincial $ 2,233.9 $ 2,068.1
---------------------------------------------------------------------
---------------------------------------------------------------------
No current income taxes were paid or payable in both 2009 and 2008.
16. EXCHANGEABLE SHARES
ARC is authorized to issue an unlimited number of ARL Exchangeable
Shares that can be converted (at the option of the holder) into trust
units at any time. The number of Trust units issuable upon conversion
is based upon the exchange ratio in effect at the conversion date.
The exchange ratio is calculated monthly based on the cash
distribution paid divided by the 10 day weighted average unit price
preceding the record date and multiplied by the opening exchange
ratio. The exchangeable shares are not eligible for distributions
and, in the event that they are not converted, any outstanding shares
are redeemable by ARC for Trust units on August 28, 2012. The ARL
Exchangeable Shares are publicly traded.
---------------------------------------------------------------------
December 31, December 31,
(units thousands) 2009 2008
---------------------------------------------------------------------
Balance, beginning of year 1,092 1,310
Exchanged for trust units(1) (221) (218)
---------------------------------------------------------------------
Balance, end of year 871 1,092
Exchange ratio, end of year 2.71953 2.51668
Trust units issuable upon conversion,
end of year 2,369 2,748
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During 2009, 220,573 ARL exchangeable shares were converted to
trust units at an average exchange ratio of 2.59547, compared to
218,455 exchangeable shares at an average exchange ratio of
2.36901 during the year ended 2008.
The non-controlling interest on the Consolidated Balance Sheet
consists of the fair value of the exchangeable shares upon issuance
plus the accumulated earnings attributable to the non-controlling
interest. The net income attributable to the non-controlling interest
on the Consolidated Statement of Income represents the cumulative
share of net income attributable to the non-controlling interest
based on the Trust units issuable for exchangeable shares in
proportion to total Trust units issued and issuable at each period
end.
Following is a summary of the non-controlling interest for 2009 and
2008:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Non-controlling interest, beginning
of year $ 42.4 $ 43.1
Reduction of book value for conversion to
trust units (8.7) (7.6)
Current period net income attributable to
non-controlling interest 2.3 6.9
---------------------------------------------------------------------
Non-controlling interest, end of year 36.0 42.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 43.3 $ 41.0
---------------------------------------------------------------------
---------------------------------------------------------------------
17. UNITHOLDERS' CAPITAL
ARC is authorized to issue 650 million Trust units of which
236.6 million units were issued and outstanding as at December 31,
2009 (216.4 million as at December 31, 2008).
ARC has in place a Distribution Reinvestment and Optional Cash
Payment Program ("DRIP") in conjunction with the Trusts' transfer
agent to provide the option for unitholders to reinvest cash
distributions into additional trust units issued from treasury at a
five per cent discount to the prevailing market price with no
additional fees or commissions.
ARC is an open ended mutual fund under which unitholders have the
right to request redemption directly from ARC. Trust units tendered
by holders are subject to redemption under certain terms and
conditions including the determination of the redemption price at the
lower of the closing market price on the date units are tendered or
90 per cent of the weighted average trading price for the 10 day
trading period commencing on the tender date. Cash payments for trust
units tendered for redemption are limited to $100,000 per month with
redemption requests in excess of this amount eligible to receive a
note from ARC Resources Ltd. accruing interest at 4.5 per cent and
repayable within 20 years.
---------------------------------------------------------------------
December 31, 2009 December 31, 2008
---------------------------------------------------------------------
Number Number
of trust of trust
(units thousands) units $ units $
---------------------------------------------------------------------
Balance, beginning of year 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 16) 572 8.6 517 7.6
Issued on exercise of
employee rights - - 238 4.2
Distribution reinvestment
program 4,134 67.0 5,448 123.2
Trust unit issue costs, net
of tax(1) - (11.7) - -
---------------------------------------------------------------------
Balance, end of year(2) 236,615 2,917.6 216,435 2,600.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount is net of tax of $2.1 million for the period ended
December 31, 2009.
(2) The number of Trust units outstanding increased significantly on
January 5, 2010. Refer to Note 23 for further details.
Net income per trust unit has been determined based on the following:
---------------------------------------------------------------------
Three Months Twelve Months
Ended Ended
December 31 December 31
---------------------------------------------------------------------
(units thousands) 2009 2008 2009 2008
---------------------------------------------------------------------
Weighted average trust
units(1) 236,138 215,579 233,025 213,259
Trust units issuable on
conversion of exchangeable
shares(2) 2,369 2,748 2,369 2,748
Dilutive impact of rights(3) - 2 - 50
---------------------------------------------------------------------
Diluted trust units and
exchangeable shares 238,507 218,329 235,394 216,057
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 December 31, 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.
18. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Accumulated earnings $ 2,946.9 $ 2,724.1
Accumulated distributions (3,525.5) (3,227.0)
---------------------------------------------------------------------
Deficit (578.6) (502.9)
Accumulated other comprehensive (loss) income (0.6) 1.9
---------------------------------------------------------------------
Deficit and accumulated other comprehensive
(loss) income $ (579.2) $ (501.0)
---------------------------------------------------------------------
---------------------------------------------------------------------
The accumulated other comprehensive (loss) income balance is composed
of the following items:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Unrealized gains and losses on financial
instruments designated as cash flow
hedges $ (0.7) $ 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 year $ (0.6) $ 1.9
---------------------------------------------------------------------
---------------------------------------------------------------------
19. 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 Twelve Months
Ended Ended
December 31 December 31
---------------------------------------------------------------------
2009 2008 2009 2008
---------------------------------------------------------------------
Cash flow from operating
activities $ 143.2 $ 209.4 $ 497.4 $ 944.4
Deduct:
Cash withheld to fund
current period capital
expenditures (70.8) (80.9) (194.3) (372.2)
Net reclamation fund
contributions (1.5) (1.3) (4.6) (2.2)
---------------------------------------------------------------------
Distributions(1) 70.9 127.2 298.5 570.0
Accumulated distributions,
beginning of period 3,454.6 3,099.8 3,227.0 2,657.0
---------------------------------------------------------------------
Accumulated distributions,
end of period $ 3,525.5 $ 3,227.0 $ 3,525.5 $ 3,227.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0.30 $ 0.59 $ 1.28 $ 2.67
Accumulated distributions
per unit, beginning of
period $ 24.68 $ 23.11 $ 23.70 $ 21.03
Accumulated distributions
per unit, end of period(3) $ 24.98 $ 23.70 $ 24.98 $ 23.70
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include accrued and non-cash amounts of
$14.9 million and $56.2 million for the three and twelve months
ended December 31, 2009, respectively ($9.7 million and
$111.2 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 ARC in July 1996.
20. TRUST UNIT INCENTIVE RIGHTS PLAN
The Trust Unit Incentive Rights Plan (the "Rights Plan") was
established in 1999 and authorized ARC to grant up to 8,000,000
rights to its employees, independent directors and long-term
consultants to purchase Trust units, of which 7,866,088 were granted
before the plan was discontinued in 2004 and replaced with the Whole
Trust Unit Incentive Plan (see Note 21). During 2008 the remaining
238,000 rights were exercised, at a weighted average exercise price
of $10.40. As at December 31, 2008 all rights issued under the Rights
Plan had been exercised or cancelled.
21. WHOLE TRUST UNIT INCENTIVE PLAN
The Whole Trust Unit Incentive Plan (the "Whole Unit Plan") results
in employees, officers and directors (the "plan participants")
receiving cash compensation in relation to the value of a specified
number of underlying notional trust units. The Whole Unit Plan
consists of Restricted Trust Units ("RTUs") for which the number of
trust units is fixed and will vest evenly over a period of three
years and Performance Trust Units ("PTUs") for which the number of
trust units is variable and will vest at the end of three years.
Upon vesting, the plan participant receives 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 future performance of ARC compared to its peers
based on a performance multiplier. The performance multiplier is
based on the percentile rank of ARC's Total Unitholder Return. The
cash compensation issued upon vesting of the PTUs may range from zero
to two times the value of the PTUs originally granted.
During the year, cash payments of $16.6 million were made to
employees relating to the Whole Unit Plan compared to $28.2 million
in 2008. In October 2008, vesting periods were revised from April and
October to March and September of each year commencing in 2009.
Non-cash compensation expense associated with the Whole Unit Plan is
determined based on the intrinsic value of the Whole Trust Units at
each period end and is expensed in the statement of income and
capitalized on the balance sheet over the vesting period. As the
value of the RTUs and PTUs is dependent upon the trust unit price,
the expense recorded may fluctuate over time.
ARC recorded non-cash compensation expense of $(0.1) million and
$0.7 million to general and administrative and operating expenses,
respectively, and capitalized $0.1 million to property, plant and
equipment in the year ended December 31, 2009 for the estimated
change in the Plan liability ($1.1 million, $(0.1) million, and
$0.6 million for the year ended December 31, 2008). The non-cash
compensation expense was based on the December 31, 2009 unit price of
$19.94 ($20.10 at December 31, 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 year
ended December 31, 2009:
---------------------------------------------------------------------
(thousands) Number of RTUs Number of PTUs
---------------------------------------------------------------------
Balance, beginning of year 756 959
Granted 703 635
Vested (355) (261)
Forfeited (52) (28)
---------------------------------------------------------------------
Balance, end of year 1,052 1,305
---------------------------------------------------------------------
---------------------------------------------------------------------
The change in the net accrued long-term incentive compensation
liability relating to the Whole Trust Unit Incentive Plan can be
reconciled as follows:
---------------------------------------------------------------------
December 31, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of year $ 31.9 $ 30.3
Change in net liabilities in the year
General and administrative expense (0.1) 1.1
Operating expense 0.7 (0.1)
Property, plant and equipment 0.1 0.6
---------------------------------------------------------------------
Balance, end of year(1) $ 32.6 $ 31.9
---------------------------------------------------------------------
Current portion of liability(2) 22.4 18.8
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 10.9 $ 14.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $0.7 million of recoverable amounts recorded in accounts
receivable as at December 31, 2009 ($1.1 million for 2008).
(2) Included in accounts payable and accrued liabilities on the
Consolidated Balance Sheet.
22. COMMITMENTS AND CONTINGENCIES
Following is a summary of ARC's contractual obligations and
commitments as at December 31, 2009:
---------------------------------------------------------------------
Payments Due by Period
---------------------------------------------------------------------
2011- 2013- There-
($ millions) 2010 2012 2014 after Total
---------------------------------------------------------------------
Debt repayments(1) 34.8 571.7 107.4 132.2 846.1
Interest payments(2) 20.1 35.5 24.2 20.8 100.6
Reclamation fund
contributions(3) 4.9 8.9 7.7 64.2 85.7
Purchase commitments 41.2 37.1 15.9 14.9 109.1
Transportation
commitments(4) 4.8 26.6 24.2 7.1 62.7
Operating leases 4.0 13.0 14.9 74.4 106.3
Risk management
contract premiums(5) 1.6 - - - 1.6
---------------------------------------------------------------------
Total contractual
obligations 111.4 692.8 194.3 313.6 1,312.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Long-term and short-term debt.
(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 2010.
(5) Fixed premiums to be paid in future periods on certain commodity
risk management contracts.
In addition to the above Risk management contract premiums, ARC has
commitments related to its risk management program (see Note 13). As
the premiums are part of the underlying risk management contract,
they have been recorded at fair market value at December 31, 2009 on
the balance sheet as part of risk management contracts.
ARC enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is
estimated that ARC has committed to capital expenditures equal to
approximately one quarter of its capital budget by means of giving
the necessary authorizations to incur the expenditures in a future
period. ARC's 2010 capital budget has been approved by the Board at
$610 million. This commitment has not been disclosed in the
commitment table as it is of a routine nature and is part of normal
course of operations for active oil and gas companies and trusts.
The 2010 capital budget of $610 million includes approximately
$20 million for leasehold development costs related to ARC's new
office space in downtown Calgary. The operating lease commitments for
the new space are included in the table above.
ARC 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 ARC's financial position
or results of operations and therefore the above table does not
include any commitments for outstanding litigation and claims.
23. SUBSEQUENT EVENTS
On January 5, 2010 ARC issued 13 million trust units at a price of
$19.40 per trust unit for total net proceeds of approximately
$240 million. A portion of the net proceeds has been used to repay
bank indebtedness of approximately $180 million which was incurred to
fund the Ante Creek purchase outlined in Note 4, with the remainder
used to repay other outstanding bank indebtedness.
Note: Barrels of oil equivalent (boe) may be misleading, particularly if
used in isolation. In accordance with NI 51-101, a boe conversion ratio
for natural gas of 6 mcf: 1 bbl has been used, which is based on an
energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
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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
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ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer
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%SEDAR: 00015954E %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