ARC RESOURCES LTD. ANNOUNCES FOURTH QUARTER 2010 RESULTS
CALGARY, Feb. 10 /CNW/ -- CALGARY, Feb. 10 /CNW/ - (ARX - TSX) ARC Resources Ltd. ('ARC') announces the results for the fourth quarter and the year ended December 31, 2010.
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Three Months Ended Twelve Months Ended
December 31 December 31
2010 2009 2010 2009
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FINANCIAL
(Cdn$ millions, except per
share and per boe amounts)
Revenue before royalties 329.3 278.6 1,213.7 978.2
Per share(1) 1.16 1.17 4.59 4.16
Cash flow from operating
activities(2) 186.2 143.2 673.9 497.4
Per share(1) 0.66 0.60 2.55 2.11
Net income (loss) (6.3) 66.2 260.8 225.1
Per share(1) (0.01) 0.28 0.99 0.96
Operating income(3) 50.4 61.7 244.2 181.2
Per share(1) 0.18 0.26 0.92 0.77
Distributions 82.8 70.9 313.5 298.5
Per unit(1) 0.30 0.30 1.20 1.28
Capital expenditures 159.1 117.3 590.9 359.6
Net debt outstanding(4) 872.7 902.4 872.7 902.4
OPERATING
Production
Crude oil (bbl/d) 27,417 27,415 27,341 27,509
Natural gas (mmcf/d) 311.5 189.0 254.2 194.0
Natural gas liquids (bbl/d) 5,355 3,597 4,245 3,689
Total (boe/d) 84,686 62,520 73,954 63,538
Average prices
Crude oil ($/bbl) 76.08 72.61 73.85 62.24
Natural gas ($/mcf) 3.83 4.58 4.21 4.18
Natural gas liquids ($/bbl) 55.10 46.12 53.98 40.67
Oil equivalent ($/boe) 42.18 48.35 44.88 42.07
Operating netback ($/boe)
Commodity and other revenue
(before hedging) 42.26 48.42 44.96 42.17
Transportation costs (1.08) (0.92) (1.10) (0.89)
Royalties (6.03) (7.94) (7.14) (6.37)
Operating costs (9.01) (9.91) (9.70) (10.19)
Netback before hedging 26.14 29.65 27.02 24.72
Realized gain (loss) on
risk management contracts 2.50 (0.42) 2.20 0.54
Netback after hedging 28.64 29.23 29.22 25.26
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EQUITY
(millions)
Shares outstanding, end of
period 284.4 239.0 284.4 239.0
Weighted average shares(5) 283.7 238.5 264.2 235.4
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TRADING STATISTICS
(Cdn$, except volumes) based
on intra-day trading
High 26.04 21.89 26.04 21.89
Low 20.42 19.06 18.77 11.73
Close 25.41 19.94 25.41 19.94
Average daily volume
(thousands) 1,299 963 1,197 1,057
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(1) Prior to the conversion to a corporation, ARC had 'units' outstanding
instead of 'shares'. In all cases, the term per share can be
interpreted as per unit prior to December 31, 2010. Per share amounts
(with the exception of per unit distributions, which are based on the
number of trust units outstanding at each distribution record date)
are based on diluted common shares.
(2) Cash flow from operating activities is a GAAP measure. Historically,
management has disclosed cash flow from operations 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 from operations for the fourth
quarter of 2010 would be $202.6 million ($0.71 per share) and $680.6
million ($2.58 per share) for the full year 2010.
(3) Operating income is a non-GAAP measure and is calculated using net
income (loss) less significant one-time items and items that are not
indicative of operating performance. For 2010 and 2009, operating
income was derived using net income (loss) less unrealized
gains/losses on risk management contracts, net of tax, and unrealized
foreign exchange gains/losses on US$ denominated debt, net of tax.
(4) Net debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Diluted common shares.
ACCOMPLISHMENTS / FINANCIAL UPDATE
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- On December 31, 2010, ARC completed its conversion from a trust to a
dividend paying corporation after receiving securityholders' approval
on December 15, 2010. ARC's business activities remain unchanged and
all officers and directors remain the same. The common shares of ARC
now trade on the Toronto Stock Exchange under the symbol ARX.
- ARC increased its proved plus probable reserves by 29 per cent to 487
million barrels of oil equivalent ('mboe') reflecting continued
success in executing both its capital development program and
strategic acquisitions throughout 2010. Internal capital development
activities contributed 91.3 mboe of additional proved plus probable
reserves while 44 mboe of proved plus probable reserves were added
as a result of ARC's August 2010 acquisition of Storm Exploration
Inc. ('Storm') and other minor acquisitions throughout the year. The
2010 Finding and Development ('F&D') costs for proved plus probable
reserves were $6.47 per barrel of oil equivalent ('boe') before
consideration of future development capital ('FDC') while Finding,
Development, and Acquisition ('FD&A') costs were $9.21 per boe.
Additional information on the reserves evaluation can be found in
the 'ARC Resources Ltd. 2010 Year-end Reserves Increase by 29 per
cent' news release dated February 10, 2011 and filed on SEDAR at
www.sedar.com.
- Production volumes for the quarter averaged a record 84,686 boe per
day, a 22,166 boe per day or 35 per cent increase compared to the
fourth quarter of 2009. The increase in production is attributable to
the successful start-up of the 60 mmcf per day Dawson gas plant in
the second quarter, the acquisition of Storm on August 17, 2010 which
contributed 8,800 boe per day during the fourth quarter and a
successful 2010 drilling program. With the planned shutdown of the
Dawson gas plant for four weeks in the first quarter of 2011 to
facilitate the tie-in of the Phase two construction and the
disposition of 3,400 boe per day on January 31, 2011, ARC expects
first quarter 2011 production to be between 76,500 and 77,500 boe per
day. Full year 2011 production guidance of between 84,000 and 87,000
boe per day remains unchanged.
- Cash flow from operating activities was $186.2 million ($0.66 per
share) in the fourth quarter of 2010, a 30 per cent increase from the
$143.2 million ($0.60 per share) achieved in the fourth quarter of
2009, reflecting increased production volumes, higher crude oil
prices and increased cash gains on risk management contracts.
Continued strengthening of world oil prices contributed to a five
percent increase in ARC's realized fourth quarter 2010 crude oil
price of $76.08 per barrel while natural gas prices, still depressed
by high inventory levels and increased natural gas production in the
United States, remain relatively unchanged from the third quarter of
2010 price of $3.79 per mcf to the fourth quarter of 2010 price of
$3.83 per mcf.
- Operating income, a non-GAAP measure that adjusts net income by
significant one-time items that are not indicative of operating
performance, was $50.4 million in the fourth quarter of 2010, an 18
per cent decrease from the $61.7 million achieved in the fourth
quarter of 2009 due to increases in operating and depletion expense
arising from higher volumes, and increases in general and
administrative and interest expense offsetting increases in revenue.
Net income decreased $72.5 million in the fourth quarter of 2010
from the fourth quarter of 2009, resulting in a net loss of $6.3
million due to an unrealized loss on risk management contracts of
$64.4 million, net of tax.
- ARC recorded cash hedging gains of $65 million in 2010 primarily
associated with the hedging of natural gas. Approximately 50 per cent
of 2011 expected production is hedged and approximately 30 per cent
of 2012 production is hedged to protect future cash flow, to provide
more certainty in achieving projected returns on capital expenditures
and to assist in providing more stable, ongoing dividend payments.
- Capital expenditures for the fourth quarter totaled $159.1 million as
ARC drilled 30 oil wells and 10 natural gas wells with a 100 per cent
success rate. Year-to-date capital expenditures totaled $590.9
million, $34.1 million below 2010 guidance of $625 million as a
result of enhanced cost effectiveness and a focus on high impact
capital projects. Included in the $590.9 million annual capital
expenditures are $61 million of land expenditures and $25 million on
leasehold expenditure costs associated with ARC's corporate office
move in May of 2010.
- ARC's Board of Directors has approved a $625 million capital
expenditures budget for 2011 that will allow for continued growth.
The capital program will focus on oil and liquids rich natural gas
opportunities at Pembina and Ante Creek in Alberta, southeast
Saskatchewan and Parkland in British Columbia as well as continued
development of the Montney gas opportunities in northeast British
Columbia.
- ARC continues to have a very strong balance sheet with a net debt to
annual cash flow from operating activities ratio of 1.3 times and
debt representing approximately 11 per cent of ARC's total
capitalization.
- On January 31, 2011, ARC announced the closing of the disposition of
approximately 3,400 boe per day and approximately 14.7 million boe of
proved plus probable reserves associated with minor properties in
central Alberta for proceeds of $170 million. If these proceeds had
been received prior to year-end, ARC's net debt to annual cash flow
from operating activities would have been 1.0 times.
- The Board of Directors has conditionally declared a dividend of $0.10
per share payable monthly for the remaining two months of the first
quarter of 2011. The dividends have been designated as eligible
dividends under the Income Tax Act (Canada) and are payable as
follows:
Ex-dividend date Record date Payment date Amount
---------------- ----------- ------------ ------
February 24, 2011 February 28, 2011 March 15, 2011 $0.10 per share
March 29, 2011 March 31, 2011 April 15, 2011 $0.10 per share
The declaration of the dividends are conditional upon confirmation by
a monthly press release and are subject to further resolution of the
Board of Directors to reflect any change in dividend levels in
accordance with the dividend policy of ARC and may vary depending on
a variety of factors and conditions existing from time-to-time,
including fluctuations in commodity prices, production levels,
capital expenditure requirements, debt service requirements,
operating costs, royalty burdens, foreign exchange rates and the
satisfaction of solvency tests imposed by the Business Corporations
Act (Alberta) for the declaration and payment of dividends.
The dividend payable on February 15, 2011 was declared on January 17,
2011 at $0.10 per share.
RESOURCE PLAY DEVELOPMENT UPDATE
--------------------------------
- British Columbia Montney
Production from the entire British Columbia Montney Resource Play
('BC Montney'), which includes Dawson, West Montney and Parkland,
averaged 163 mmcf per day of natural gas and 1,600 barrels per day
of liquids for the fourth quarter of 2010. The fourth quarter was
also the first full quarter of production from ARC's Parkland
property acquired as part of the August 17, 2010 Storm acquisition.
During the fourth quarter of 2010, ARC spent $53.8 million on
development activities in the BC Montney area including drilling
three horizontal wells and completing one vertical and eight
horizontal wells.
Construction of the Phase two portion of the Dawson gas plant is well
underway. Completion is still expected for the first quarter of 2011
with commissioning and start-up occurring early in the second quarter
of 2011. The Phase two gas plant is expected to double ARC's Dawson
operated gas plant processing capacity from 60 mmcf per day to 120
mmcf per day at a cost of approximately $45 million. To date, ARC has
incurred $30.8 million on construction costs.
- Ante Creek Montney
Engineering and design work was initiated on the 30 mmcf per day
Ante Creek gas plant. Completion of this long cycle time project is
expected for the first quarter of 2012 and the final cost for the
plant is estimated to be approximately $40 million. ARC drilled
three oil wells into the Montney formation in the fourth quarter. As
a result of a successful 2010 drilling program in Ante Creek, fourth
quarter volumes have increased seven per cent from the third quarter
of 2010 to a record 8,032 boe per day. Approximately 42 per cent of
fourth quarter production consisted of oil and natural gas liquids.
- Cardium
During the fourth quarter, ARC drilled nine wells into the Cardium
formation. ARC continues to be encouraged by the results, with an
initial 30 day production average of 200 barrels of oil per day for
the 12 wells brought on production during the fourth quarter of
2010. ARC expects to spend $90 million in 2011 by drilling 42
horizontal Cardium locations in order to further develop this
reservoir. In addition, extensive work is also planned on waterflood
management in order to optimize reservoir recoveries. ARC operates
approximately 25 per cent of the Pembina Cardium oil field with an
average 65 per cent working interest in 166 gross sections (126 net).
- Enhanced Oil Recovery Initiatives
During the fourth quarter of 2010, CO(2) injection was completed at
the Redwater enhanced oil recovery pilot project. ARC will conduct a
technical analysis 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
------------------------------------
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This management's discussion and analysis ('MD&A') is ARC Resources Ltd. ('ARC' or the 'Corporation') management's analysis of its financial performance and significant trends or external factors that may affect future performance. It is dated February 10, 2011 and should be read in conjunction with the audited Consolidated Financial Statements as at and for the year ended December 31, 2010, the MD&A and the audited Consolidated Financial Statements as at and for the year ended December 31, 2009, the MD&A and the unaudited Consolidated Financial Statements for the periods ended March 31, 2010, June 30, 2010 and September 30, 2010 as well as ARC's Annual Information Form that is filed on SEDAR at www.sedar.com.
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.
CORPORATE CONVERSION
On December 31, 2010, ARC Energy Trust (the 'Trust') effectively completed its conversion to a dividend paying corporation from an income trust pursuant to a Plan of Arrangement (the 'Arrangement') under Section 193 of the Business Corporations Act (Alberta) involving, among others, the Trust, ARC Resources Ltd. and securityholders of the Trust and ARC. Pursuant to the Arrangement, holders ('unitholders') of trust units ('trust units') of the Trust received one common share ('common share') of ARC for each trust unit. In addition, holders of Series A exchangeable shares and Series B exchangeable shares ('Exchangeable Shares') of the Corporation received 2.89162 common shares of ARC for each Exchangeable Share. As a result of the Arrangement, on December 31, 2010 ARC had approximately 284.4 million common shares issued and outstanding.
The Common Shares of ARC trade on the Toronto Stock Exchange (the 'TSX') under the trading symbol ARX. Beginning with the January 31, 2011 record date, shareholders of ARC will receive payments in the form of dividends. Prior to the conversion of the Trust to a corporation on December 31, 2010, distributions were paid to unitholders. Previous historical references to 'unitholders', 'distributions' 'trust units', and 'per unit' have now been replaced by 'shareholders', 'dividends', 'common shares', and 'per share', respectively, where applicable.
Despite the change in legal structure from a trust to a dividend paying corporation, ARC's business activities and business strategy remain unchanged and all officers and directors remain the same.
ABOUT ARC RESOURCES LTD.
ARC, with a total capitalization of approximately $8 billion, is a mid-sized dividend paying Canadian exploration and production company with near term growth prospects. ARC's activities relate to the exploration, development and production of conventional oil and natural gas with an emphasis on the acquisition and development of properties with a large volume of hydrocarbons in place commonly referred to as 'resource plays'. Production from individual oil and natural gas wells naturally decline over time. In any one year, ARC approves a budget to drill new wells to firstly replace declines and potentially increase production. ARC was previously structured as a trust and converted to a corporate structure on December 31, 2010. ARC will continue to operate as an oil and natural gas company, hiring and developing staff with expertise specific to ARC's oil and natural gas operations. As of the end of 2010, ARC had approximately 500 employees with 300 professional and technical staff in the Calgary office and 200 individuals located in ARC's operating areas in western Canada.
ARC is results focused with a goal to provide superior, long-term returns to shareholders through risk-managed value creation. ARC takes a disciplined approach to capital allocation, deploying capital on projects to achieve this goal. Our staff uses their expertise to unlock additional reserves that will lead to higher future production through the exploration for and development of large oil and natural gas pools. Our main activities that support this objective are:
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1. Resource Plays - Geological evaluation, acquisition, development and,
if economically viable, subsequent production from lands and
producing properties with large resource in place.
ARC's most significant resource plays include the Montney development
at Dawson, northeast British Columbia, Ante Creek in northern Alberta
and the Cardium formation at Pembina in central Alberta. ARC's 2011
budgeted capital expenditures are focused on the resource play
development at Ante Creek and Pembina. Where applicable, enhanced oil
recovery programs ('EOR programs') are utilized to increase
recoverability of reserves. ARC has non-operated interests in the
Weyburn and Midale units in Saskatchewan where operators have
implemented CO(2) injection programs to increase recoverable oil
reserves. ARC has completed the injection component of a CO(2) pilot
program at Redwater in Alberta and is currently conducting a
technical analysis of the results.
2. Conventional Oil & Natural Gas Production - Maximizing production
while controlling operating costs on oil and natural gas wells
located within ARC's core producing areas in western Canada. This may
include the periodic acquisition and disposition of strategic
producing and undeveloped properties to enhance current production,
the rationalization of asset portfolios or the provision of potential
future drilling locations and, if successful, additional production
and reserves. Current oil production is predominantly light and
medium quality.
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The following table highlights ARC's production volume and reserve profile for the last five years:
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Table 1
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2010 2009 2008 2007 2006
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Production (boe/d) 73,954 63,538 65,126 62,723 63,056
Proved plus probable
reserves (mmboe) 487.4 379.0 321.7 286.4 286.1
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Total Return to Shareholders
ARC's business plan has resulted in significant operational success and contributed to a trailing five year annualized return per share of eight per cent (Table 2).
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Table 2
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Total Returns(1) Trailing Trailing Trailing
($ per share except for per cent) One Year Three Year Five Year
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Dividends per share 1.20 5.15 10.15
Capital appreciation (depreciation)
per share 5.47 5.01 (1.08)
Total return per share 34.8% 58.1% 48.9%
Annualized total return per share 34.8% 16.5% 8.3%
S&P/TSX Exploration & Producers Index
annualized total return 12.5% 3.9% 4.5%
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(1) Calculated as at December 31, 2010.
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Per Share Metrics
ARC's performance can be measured by its ability to grow both production and reserves. On a per share dividend adjusted basis, normalized production and reserves per share would have increased 15 per cent and 56 per cent, respectively from 2008 to 2010.
A key performance indicator for the future is production and reserves growth on a per share basis. From its 1996 inception, ARC has paid out $3.8 billion to shareholders and financed a large percentage of its acquisitions by issuing additional shares. As we look forward to 2011 and beyond, ARC's goal is to fund both dividends and capital expenditures out of cash flow while accessing cash flow, equity, debt, or proceeds from property dispositions to finance growth capital expenditures or acquisitions. Debt will be used to fund capital to the extent it is prudent to do so while maintaining prudent debt levels. Debt levels at the end of 2010 were within our current target of under two times cash flow from operating activities and 20 per cent of total capitalization.
ARC provides returns to shareholders through both the potential for capital appreciation as production and reserves grow and through a dividend payment of $0.10 per share per month to its shareholders.
Table 3 details ARC's normalized production, reserves and distributions per share/unit, with and without dividend adjustments, over the past three years:
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Table 3
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Per Share 2010 2009 2008
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Normalized production, boe per share(1)(2) 0.30 0.27 0.29
Normalized reserves, boe per share(1)(3) 1.80 1.57 1.42
Dividends/distributions per unit $1.20 $1.28 $2.67
Normalized production, dividend adjusted,
boe per share(4) 0.36 0.32 0.32
Normalized reserves, dividend adjusted,
boe per share(4) 2.31 1.90 1.58
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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 shares were issued (or repurchased) at a period end
price for the reserves per share calculation and at an annual average
price for the production per share 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
share values.
(2) Production per share represents daily average production (boe) per
thousand shares and is calculated based on daily average production
divided by the normalized diluted common shares.
(3) Reserves per share is calculated based on proved plus probable
reserves (boe), as determined by ARC's independent reserve evaluator
solely at year-end, divided by period end shares outstanding.
(4) The dividend adjustment assumes that historical dividends from
January 1, 2008 were reinvested back into ARC shares. This results
in a reduction of the number of shares outstanding and, in turn,
results in higher normalized production per share and normalized
reserves per share.
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ECONOMIC ENVIRONMENT
The global economy grew at an impressive rate of 4.8 per cent in 2010 with emerging markets leading the way at an estimated rate of 7.1 per cent (source: International Monetary Fund). Traditionally, changes in commodity prices have correlated with changes in economic growth. Global trade has recovered significantly since the start of the U.S. recession in late 2007 and equity composites in Canada and the United States have rallied by 15 per cent from September 2010 to December 2010. Equity growth was driven by strong corporate earnings and economic activity in the United States, the world's largest economy, where high unemployment continues to be a key focus resulting in stimulus efforts through government spending and historic low interest rates.
Strong global economic activity and market demand resulted in oil prices averaging US$79.55 per barrel in 2010, a 28 per cent increase over 2009 levels. China exhibited the largest growth in oil consumption of any country in the world, reaching total consumption of over 10 million barrels per day in December 2010, second only in oil consumption to the United States. In 2010, the United States averaged 19.2 million barrels per day of oil consumption (source: International Energy Agency).
In North American markets, natural gas production levels continue to grow due to improving drilling techniques in tight shale and silt formations as well as land tenure commitments. This has resulted in considerable benefit to North American consumers in providing an environmentally-friendly low cost fuel and has benefited natural gas producers who have harnessed these techniques to significantly increase their reserve base and generate profits through reduced cost structures. With added supply, however, natural gas prices have been depressed resulting in an oil to natural gas price ratio of approximately 18 times for 2010, significant deviation from the energy-equivalent six mcf of natural gas to one barrel of oil volumetric ratio.
2010 and 2011 Guidance and Financial Highlights
Table 4 is a summary of ARC's 2010 and 2011 Guidance and a review of 2010 actual results:
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Table 4
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2010 2010 2011
Guidance Actual % Variance Guidance
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Production
Oil (bbls/d) 27,341 27,500-28,500
NGLs (bbls/d) 4,245 4,000-4,800
Natural Gas
(mmcf/d) 254.2 315-322
Total (boe/d) 72,500-74,500 73,954 - 84,000-87,000
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Expenses ($/boe):
Operating costs 10.00 9.70 (3) 9.40-9.70
Transportation 1.10 1.10 - 1.10-1.20
Cash general and
administrative(1) 2.90 2.95 10 2.20-2.40
Interest 1.70 1.57 (8) 1.25-1.40
Capital
expenditures
($ millions) 625 591 (5) 625
Annual weighted
average common
shares (millions) 264 264 - 286
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(1) Cash G&A guidance for 2011 increased due to higher estimated cash
payments expected under the RSU and PSU Plan resulting from an
increase in both share price and the performance multiplier.
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2010 full year actual results are in-line with the 2010 Guidance, with production at the high end of the Guidance range and operating costs and interest expense below Guidance due to disciplined cost management, lower electricity costs and lower than anticipated debt levels.
The 2011 Guidance provides shareholders with information on management's expectations for results of operations. Readers are cautioned that the 2011 Guidance may not be appropriate for other purposes.
2010 FOURTH QUARTER AND 2010 ANNUAL FINANCIAL AND OPERATIONAL RESULTS
Financial Highlights
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Table 5
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Three Months Ended Twelve Months Ended
December 31 December 31
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(Cdn$ millions,
except per share
and volume data) 2010 2009 % Change 2010 2009 % Change
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Cash flow from
operating
activities 186.2 143.2 30 673.9 497.4 35
Cash flow from
operating
activities per
share(1) 0.66 0.61 8 2.55 2.11 21
Net income (loss) (6.3) 66.2 (110) 260.8 225.1 16
Net income (loss)
per share(1) (0.01) 0.28 (104) 0.99 0.96 3
Operating income 47.0 59.5 (21) 219.6 179.1 23
Operating income
per share(1) 0.17 0.25 (34) 0.83 0.76 9
Distributions
per unit(2) 0.30 0.30 - 1.20 1.28 (6)
Average daily
production
(boe/d)(3) 84,686 62,520 35 73,954 63,538 16
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(1) Per share amounts are based on the diluted common shares.
(2) Based on number of trust units outstanding at each distribution
record date.
(3) 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 wellhead. Use of boe in isolation may be
misleading.
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Cash Flow from Operating Activities
Cash flow from operating activities increased by 30 per cent in the fourth quarter of 2010 to $186.2 million from $143.2 million in the fourth quarter of 2009. The increase was primarily attributed to a 35 per cent increase in production and a $21.7 million increase in realized gains on risk management contracts, partially offset by a decrease in natural gas prices and higher total operating costs. Details of the change in cash flow from operating activities in the fourth quarter of 2009 to the fourth quarter of 2010 are presented in Table 6.
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Table 6
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($ per
($ millions) share)
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Q4 2009 Cash flow from Operating Activities 143.2 0.60
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Volume variance 98.8 0.41
Price variance (48.1) (0.20)
Cash gains on risk management contracts 21.7 0.09
Royalties (1.4) (0.01)
Expenses:
Transportation (3.1) (0.01)
Operating(1) (11.7) (0.05)
General and administrative(1) (4.4) (0.02)
Interest (4.6) (0.02)
Taxes - -
Realized foreign exchange gain (0.9) -
Weighted average shares - (0.12)
Non-cash and other items(2) (3.3) (0.01)
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Q4 2010 Cash flow from Operating Activities 186.2 0.66
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(1) Excludes non-cash portion of RSU & PSU Plan expense recorded in
operating and general and administrative costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
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Year-to-date cash flow from operating activities increased by 35 per cent in 2010 to $673.9 million from $497.4 million in the comparable period of 2009. The increase was attributed to higher production volumes and commodity prices as well as an increase in realized gains on risk management contracts, partially offset by higher royalties and higher total operating costs. Details of the change in cash flow from operating activities from 2009 to 2010 are presented in Table 6a.
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Table 6a
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($ per
($ millions) share)
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YTD 2009 Cash flow from Operating Activities 497.4 2.11
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Volume variance 160.4 0.68
Price variance 75.1 0.32
Cash gains on risk management contracts 46.0 0.20
Royalties (45.0) (0.20)
Expenses:
Transportation (9.1) (0.04)
Operating(1) (24.8) (0.11)
General and administrative(1) (22.3) (0.09)
Interest (16.8) (0.07)
Taxes 0.1 -
Realized foreign exchange gain (1.0) -
Weighted average shares - (0.31)
Non-cash and other items(2) 13.9 0.06
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YTD 2010 Cash flow from Operating Activities 673.9 2.55
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(1) Excludes non-cash portion of RSU & PSU Plan expense recorded in
operating and general and administrative costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
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2011 Cash Flow from Operating Activities Sensitivity
Table 7 illustrates sensitivities on pre-hedged operating income items to operational and business environment changes and the resulting impact on cash flows from operating activities per share:
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Table 7
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Impact on Annual
Cash Flow from
Operating Activities(4)
Business Environment(1) Assumption Change $/Share
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Oil price (US$ WTI/bbl)(2)(3) $ 80.00 $ 1.00 0.03
Natural gas price (Cdn$ AECO/mcf)(2)(3) $ 4.00 $ 0.10 0.04
Cdn$/US$ exchange rate(2)(3)(5) 1.00 $ 0.01 0.03
Interest rate on debt(2) % 5.5 % 1.0 0.01
Operational
Liquids production volume (bbl/d) 33,000 % 1.0 0.03
Gas production volumes (mmcf/d) 310 % 1.0 0.02
Operating expenses per boe $ 9.55 % 1.0 0.01
Cash G&A and RSU & PSU expenses
per boe $ 2.30 % 10.0 0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 it is presented in
Canadian dollars in this sensitivity.
>>
Net Income
A net loss of $6.3 million was generated in the fourth quarter of 2010 ($0.01 per share), a $72.5 million decrease compared to net income of $66.2 million ($0.28 per share) in 2009. The change from a net income position to a net loss position is primarily due to an unrealized loss on risk management contracts of $85.9 million ($64.4 million net of tax) in the fourth quarter of 2010 as compared to an unrealized gain on risk management contracts of $0.2 million ($0.2 million net of tax) in 2009. ARC realized higher revenues, net of royalties, and realized risk management gains of $71 million, compared to the fourth quarter of 2009. This increase was partially offset by higher transportation, operating, general and administrative, and interest expenses of $41.8 million. In addition, net income was impacted by higher depletion, depreciation and accretion ('DD&A') expense of $36.2 million from the fourth quarter of 2009 to the fourth quarter of 2010.
For the full year, net income increased from $225.1 million in 2009 to $260.8 million in 2010. The increase in net income of $35.7 million is due to higher revenues, net of royalties, and realized risk management gains of $236.5 million partially offset by higher transportation, operating, general and administrative, and interest expense of $90.9 million. In addition, net income was impacted by the following non-cash items for the full year of 2010 relative to the full year in 2009:
<<
- Higher DD&A expense of $74.7 million
- Lower unrealized foreign exchange gain of $43.2 million
- Higher unrealized gains on risk management contracts of $35.9 million
- Lower future income tax recovery of $27.2 million
>>
Operating income
Operating income is a non-GAAP measure that adjusts net income by significant one-time items and items that are not indicative of operating performance that ARC believes reduces the comparability of ARC's underlying financial performance between periods. For the full year 2010, operating income was $244.1 million, a 35 per cent increase over $181.2 million in 2009. For the fourth quarter of 2010, operating income fell by $11.3 million as increases in operating, general and administrative, interest expense, and DD&A offset the increase in higher revenues.
Table 8 summarizes ARC's operating income:
<<
Table 8
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Net income (loss) (6.3) 66.2 (110) 260.8 225.1 16
Add back or
(deduct):
Unrealized
(gains) losses
on risk
management
contracts,
net of tax 64.4 (0.2) - (21.2) 5.8 (466)
Unrealized
(gains) losses
on foreign
exchange,
net of tax (7.7) (4.3) 79 4.5 (49.7) 109
-------------------------------------------------------------------------
Operating income 50.4 61.7 (18) 244.1 181.2 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Production
Production volumes averaged 84,686 boe per day in fourth quarter of 2010 compared to 62,520 boe per day in the same period of 2009 as detailed in Table 9. Full year 2010 saw a 16 per cent increase in production volumes. The increase in both the fourth quarter 2010 and full year 2010 production is a result of the new gas plant at Dawson coming on-stream in the second quarter of 2010 and operating above its original design capacity of 60 mmcf per day, the Storm acquisition that added approximately 8,800 boe per day for the quarter and approximately 3,400 boe per day for the full year 2010, the acquisition of assets in Ante Creek that closed in late 2009 and new wells brought on production during the year.
<<
Table 9
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
Production 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Light and
medium
crude oil
(bbl/d) 26,455 26,299 1 26,390 26,423 -
Heavy oil
(bbl/d) 962 1,116 (14) 951 1,086 (12)
Natural gas
(mmcf/d) 311.5 189.0 65 254.2 194.0 31
Natural gas
liquids
('NGL')
(bbl/d) 5,355 3,597 49 4,245 3,689 15
-------------------------------------------------------------------------
Total
production
(boe/d)(1) 84,686 62,520 35 73,954 63,538 16
% Natural gas
production 61 50 22 57 51 12
% Crude oil
and liquids
production 39 50 (22) 43 49 (12)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>
ARC's crude oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than four per cent of the total. Fourth quarter and full year 2010 light and medium crude oil production remained relatively unchanged from the prior year. ARC has redirected its focus to exploiting oil and liquids rich properties for 2011 and has reflected this strategy in its 2011 capital budget in order to take advantage of stronger oil prices relative to natural gas.
Natural gas production was 311.5 mmcf per day in the fourth quarter of 2010, an increase of 65 per cent from the 189 mmcf per day produced in the fourth quarter of 2009. For the full year 2010, natural gas production increased 31 per cent from full year 2009.
During the fourth quarter of 2010, ARC drilled 40 gross wells (39 net wells) on operated properties consisting of 30 gross oil wells and 10 gross natural gas wells with a 100 per cent success rate. For the full year 2010, ARC drilled 176 gross wells (165 net wells) on operated properties consisting of 85 gross oil wells and 91 gross natural gas wells with a 100 per cent success rate. A total of 182 wells, excluding acquisitions, were brought on production during 2010.
Looking forward, ARC expects that 2011 full year production will average approximately 84,000 to 87,000 boe per day, that it will drill a total of approximately 166 gross (148 net) wells on operated properties and participate in an additional 83 gross wells (10 net) to be drilled on non-operated properties.
Tables 10 and 10a summarize ARC's production by core area:
<<
Table 10
-------------------------------------------------------------------------
Three Months Ended December 31, 2010
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,411 1,431 24.4 917
N.E. BC & N.W. AB 33,816 699 185.9 2,146
Northern AB 12,590 4,726 40.4 1,128
Pembina 9,619 6,237 14.6 942
Redwater 4,194 3,826 1.6 107
S.E. AB & S.W. Sask. 8,293 1,024 43.5 12
S.E. Sask. & MB 9,763 9,474 1.1 103
-------------------------------------------------------------------------
Total 84,686 27,417 311.5 5,355
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Months Ended December 31, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,674 1,270 26.3 1,010
N.E. BC & N.W. AB 13,562 695 73.2 668
Northern AB 9,003 4,169 24.4 773
Pembina 9,387 5,645 17.3 852
Redwater 4,232 3,880 1.1 174
S.E. AB & S.W. Sask. 8,599 1,059 45.2 13
S.E. Sask. & MB 11,063 10,697 1.5 107
-------------------------------------------------------------------------
Total 62,520 27,415 189.0 3,597
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 10a
-------------------------------------------------------------------------
Year Ended December 31, 2010
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,555 1,372 25.2 981
N.E. BC & N.W. AB 23,656 686 130.0 1,297
Northern AB 11,541 4,598 35.9 968
Pembina 9,143 5,706 16.2 739
Redwater 4,179 3,823 1.3 138
S.E. AB & S.W. Sask. 8,414 1,037 44.2 12
S.E. Sask. & MB 10,466 10,119 1.4 110
-------------------------------------------------------------------------
Total 73,954 27,341 254.2 4,245
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year Ended December 31, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
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 9,408 5,629 17.9 800
Redwater 4,150 3,783 1.1 178
S.E. AB & S.W. Sask. 8,841 1,027 46.9 13
S.E. Sask. & MB 11,357 10,980 1.5 122
-------------------------------------------------------------------------
Total 63,538 27,509 194.0 3,689
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 was $329.3 million in the fourth quarter of 2010, an increase of $50.7 million over 2009 revenue of $278.6 million primarily related to the increase in production volumes. For the full year, revenue increased $235.5 million from $978.2 million in 2009 to $1,213.7 million in 2010.
A breakdown of revenue is outlined in Table 11:
<<
Table 11
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
Revenue December 31 December 31
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Oil revenue 192.0 183.2 5 737.0 625.0 18
Natural gas
revenue 109.6 79.7 38 391.0 296.0 32
NGL revenue 27.1 15.3 77 83.6 54.8 53
-------------------------------------------------------------------------
Total commodity
revenue 328.7 278.2 18 1,211.6 975.8 24
Other revenue 0.6 0.4 50 2.1 2.4 (12)
-------------------------------------------------------------------------
Total revenue 329.3 278.6 18 1,213.7 978.2 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Commodity Prices Prior to Hedging
<<
Table 12
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Average
Benchmark
Prices
AECO gas
($/mcf)(1) 3.58 4.23 (15) 4.12 4.13 -
WTI oil
(US$/bbl)(2) 85.18 76.17 12 79.55 61.93 28
Cdn$ / US$
exchange rate 1.01 1.06 (5) 1.03 1.13 (9)
WTI oil
(Cdn$/bbl) 86.26 80.46 7 81.87 69.70 17
-------------------------------------------------------------------------
ARC Realized
Prices Prior
to Hedging
Oil ($/bbl) 76.08 72.61 5 73.85 62.24 19
Natural gas
($/mcf) 3.83 4.58 (16) 4.21 4.18 1
NGL ($/bbl) 55.10 46.12 19 53.98 40.67 33
-------------------------------------------------------------------------
Total commodity
price before
hedging ($/boe) 42.18 48.35 (13) 44.88 42.07 7
Other revenue
($/boe) 0.08 0.07 14 0.08 0.10 (20)
-------------------------------------------------------------------------
Total revenue
before hedging
($/boe) 42.26 48.42 (13) 44.96 42.17 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents posting price of West Texas Intermediate oil.
>>
Prior to hedging activities, ARC's weighted average commodity price was $42.18 per boe in the fourth quarter of 2010, a decrease of 13 per cent as compared to $48.35 per boe in the fourth quarter of 2009. The decrease in the weighted average realized commodity price is due to a decrease in natural gas prices coupled with the significant increase in the level of natural gas production while maintaining a constant level of liquids production. This has resulted in natural gas production contributing only 33 per cent of total revenue despite contributing 61 per cent to total production for the fourth quarter of 2010, compared to 29 per cent of total revenue and 50 per cent to total production in the fourth quarter of 2009. For the full year 2010, the average weighted commodity price increased seven per cent to $44.96 per boe. While ARC's realized oil price increased 19 per cent, ARC's realized natural gas price remained unchanged from 2009 to 2010.
Oil prices increased throughout 2010, with WTI increasing 28 per cent from 2009 to 2010. The increase continued in the fourth quarter of 2010 with WTI averaging US$85.18 per barrel compared to US$76.17 per barrel for the fourth quarter of 2009. The outlook on oil prices remains positive as the global economy continues to recover. Actual realized oil prices lagged behind the gain in WTI as a result of the strengthening of the Canadian dollar compared to the U.S. dollar. The realized price for ARC's oil, before hedging, was $76.08 per barrel, a five per cent increase over the fourth quarter 2009 realized price of $72.61 per barrel.
AECO monthly posted natural gas prices, the benchmark from which ARC derives the majority of its gas sales, decreased by 15 per cent in the fourth quarter of 2010 to $3.58 per mcf compared to $4.23 per mcf in the fourth quarter of 2009. ARC's realized gas price, before hedging, decreased by 16 per cent to $3.83 per mcf compared to $4.58 per mcf in the fourth quarter of 2009. Despite sustained cold weather in North America, gas prices continue to be depressed, with ARC's realized gas price rising marginally from $3.79 per mcf in the third quarter of 2010 to $3.83 per mcf in the fourth quarter of 2010. The outlook for natural gas prices remains weak with United States gas production up approximately four bcf per day or eight per cent over 2009 and with North American storage levels remaining at near record highs for this time of year. Using the forward curve for natural gas prices as an indicator, AECO prices are expected to range from $3.50 per mcf to $4.50 per mcf for the first quarter of 2011. ARC's realized gas price is based on its natural gas sales portfolio consisting of sales priced at the AECO monthly index, the AECO daily spot market, eastern and midwest United States markets and a portion to aggregators.
Risk Management and Hedging Activities
ARC maintains a risk management program to reduce the volatility of revenues, increase the certainty of cash flows, and to protect acquisition and development economics.
Gains or losses on risk management contracts comprise realized and unrealized gains or losses 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.
During the fourth quarter of 2010, ARC realized a gain of $20 million on its risk management contracts. The largest contributor was a $16.9 million gain on ARC's natural gas swaps and natural gas basis swap contracts. For the full year 2010, ARC realized a gain of $65.4 million on its risk management contracts with $50.2 million arising from ARC's natural gas swaps and natural gas basis swap contracts.
In addition, ARC recorded an $85.9 million unrealized mark-to-market loss on its risk management contracts in the fourth quarter of 2010, resulting in a net fair value gain of $24.6 million at December 31, 2010. The net loss position is primarily attributed to ARC's WTI crude oil contracts, as the December 31, 2010 forward outlook on WTI crude oil prices strengthened from September 30, 2010. The fair value of risk management contracts represent the expected market price to buy out ARC's contracts as of December 31, 2010 and may differ from what will eventually be realized. For the full year 2010, ARC recorded an unrealized gain of $28.2 million primarily as a result of an $85.2 million unrealized gain on natural gas risk management contracts due to the declining outlook on forward natural gas prices and a $59.9 million unrealized loss on crude oil contracts due to the strengthening of forward crude oil prices.
Table 13 summarizes the total (loss) gain on risk management contracts for the fourth quarter of 2010 compared to the same period in 2009:
<<
Table 13
-------------------------------------------------------------------------
Risk Management Crude Foreign Q4 Q4
Contracts Oil & Natural Curr- Inter- 2010 2009
($ millions) Liquids Gas ency Power est Total Total
-------------------------------------------------------------------------
Realized cash
gain on
contracts(1) 2.6 16.9 0.5 - - 20.0 (1.7)
Unrealized
(loss) gain on
contracts(2) (67.9) (17.3) (1.2) 0.6 (0.1) (85.9) 0.2
-------------------------------------------------------------------------
Total (loss)
gain on risk
management
contracts (65.3) (0.4) (0.7) 0.6 (0.1) (65.9) (1.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
>>
Table 13a summarizes the total (loss) gain on risk management contracts for 2010 compared to 2009:
<<
Table 13a
-------------------------------------------------------------------------
Risk Management Crude Foreign YTD YTD
Contracts Oil & Natural Curr- Inter- 2010 2009
($ millions) Liquids Gas ency Power est Total Total
-------------------------------------------------------------------------
Realized cash
gain on
contracts(1) 9.1 50.2 5.7 0.4 - 65.4 19.4
Unrealized
(loss) gain on
contracts(2) (59.9) 85.2 (0.8) 3.8 (0.1) 28.2 (7.7)
-------------------------------------------------------------------------
Total (loss)
gain on risk
management
contracts (50.8) 135.4 4.9 4.2 (0.1) 93.6 11.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
>>
ARC is mitigating the weak outlook on natural gas prices by protecting the selling price on 128 mmcf per day of natural gas for 2011 at $5.85 per mcf. On the liquids side, ARC has protected 20,000 barrels of oil per day for 2011 at a floor price of US$84.30 per barrel on approximately 60 per cent of current liquids production. ARC currently limits the amount of total forecast production that can be hedged to a maximum 55 per cent over the next two years with the remaining 45 per cent of production being sold at market prices. In addition, ARC's hedging policy allows for further hedging on volumes associated with new production arising from specific capital projects and acquisitions at the discretion of the Board. The following table is a summary of ARC's positions for crude oil and natural gas as at December 31, 2010.
<<
Table 14
-------------------------------------------------------------------------
Hedge Positions
As at December 31,
2010(1) 2011 2012
-------------------------------------------------------------------------
Crude Oil(2) US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 89.30 20,000 90.00 16,000
Bought Put 84.30 20,000 90.00 16,000
Sold Put 60.89 12,000 60.00 5,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Swap 5.54 135,000 4.26 21,101
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 based on offsetting basis
positions and the quarter end exchange rate.
(2) For 2011 and 2012, all put positions settle against the monthly
average WTI price, providing protection against monthly volatility;
where disclosed in the hedge note, calls have been sold against
either the monthly average or the annual average WTI price, in which
case ARC will only have a negative settlement if prices average above
the strike price for an entire year providing ARC with greater
potential upside price participation for individual months.
>>
To accurately analyze ARC's hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading. The following provides examples of how Table 14 can be interpreted for approximate values for the first quarter of 2011:
<<
- If the market price exceeds $89.30 per barrel, ARC will receive
$89.30 per barrel on 20,000 barrels per day.
- If the market price is between $84.30 per barrel and $89.30 per
barrel, ARC will receive the market price on 20,000 barrels per day.
- If the market price is between $60.89 per barrel and $84.30 per
barrel, ARC will receive $84.30 per barrel on 20,000 barrels per day.
- If the market price is below $60.89 per barrel, ARC will receive
$84.30 per barrel less the difference between $60.89 per barrel and
the market price on 20,000 barrels per day. For example, if the
market price is at $55 per barrel, ARC will receive $78.41 on 12,000
barrels per day and $84.30 on 8,000 barrels per day.
>>
Operating Netbacks
ARC's operating netback, before realized hedging gains and losses, was $26.14 per boe in the fourth quarter of 2010 compared to $29.65 per boe in the same period of 2009.
ARC's fourth quarter 2010 netback after realized hedging gains and losses, was $28.64 per boe, a two per cent decrease from the same period in 2009. The 2010 netback includes gains recorded on ARC's crude oil and natural gas risk management contracts during the quarter of $2.50 per boe compared to a loss of $0.42 per boe recorded for the same period in 2009.
The components of operating netbacks are summarized in Tables 15 and 15a:
<<
Table 15
-------------------------------------------------------------------------
Crude Heavy Q4 2010 Q4 2009
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 76.54 63.29 3.83 55.10 42.18 48.35
Other revenue - - - - 0.08 0.07
-------------------------------------------------------------------------
Total revenue 76.54 63.29 3.83 55.10 42.26 48.42
Royalties (12.50) (6.03) (0.28) (16.09) (6.03) (7.94)
Transportation (0.26) (0.66) (0.28) - (1.08) (0.92)
Operating costs(1) (15.32) (16.14) (0.98) (7.38) (9.01) (9.91)
-------------------------------------------------------------------------
Netback prior to hedging 48.46 40.46 2.29 31.63 26.14 29.65
Realized gain (loss) on risk
management contracts(2) 1.06 - 0.59 - 2.50 (0.42)
-------------------------------------------------------------------------
Netback after hedging 49.52 40.46 2.88 31.63 28.64 29.23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 15a
-------------------------------------------------------------------------
Crude Heavy 2010 2009
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 74.24 64.07 4.21 53.98 44.88 42.07
Other revenue - - - - 0.08 0.10
-------------------------------------------------------------------------
Total revenue 74.24 64.07 4.21 53.98 44.96 42.17
Royalties (12.50) (7.39) (0.47) (16.77) (7.14) (6.37)
Transportation (0.28) (0.99) (0.29) - (1.10) (0.89)
Operating costs(1) (13.94) (14.39) (1.18) (8.47) (9.70) (10.19)
-------------------------------------------------------------------------
Netback prior to hedging 47.52 41.30 2.27 28.74 27.02 24.72
Realized gain on risk
management contracts(2) 0.95 - 0.54 - 2.20 0.54
-------------------------------------------------------------------------
Netback after hedging 48.47 41.30 2.81 28.74 29.22 25.26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 gain (loss) on risk management contracts includes the
settlement amounts for crude oil and natural gas contracts. Foreign
exchange and power contracts are excluded from the netback
calculation.
>>
Royalties as a percentage of pre-hedged commodity revenue, net of transportation, decreased from 16.7 per cent ($7.94 per boe) in the fourth quarter of 2009 to 14.6 per cent ($6.03 per boe) in 2010. The decrease in the royalty rate is primarily due to the change in production profile, with higher production at properties with lower royalty rates relative to ARC's corporate average royalty rate. ARC has been capitalizing on incentives from the Alberta and British Columbia ('BC') governments for new wells which allow for a five per cent and two per cent royalty rate, respectively. In addition, ARC has also received deep gas drilling credits in BC in 2010 which have been applied against royalties.
Royalty rates in the other western provinces vary with production levels and price but to a lesser extent than Alberta royalty rates. Table 16 estimates the royalties applicable to production from ARC's properties at various price levels for 2011 prior to any provincial incentive programs.
<<
Table 16
-------------------------------------------------------------------------
Edmonton posted oil (Cdn$/bbl)(1) $70 $70 $80 $80
AECO natural gas (Cdn$/mcf)(1) $3.50 $4.50 $3.50 $4.50
-------------------------------------------------------------------------
Alberta royalty rate 13.8% 14.5% 15.6% 16.2%
Saskatchewan royalty rate(2) 18.5% 18.1% 18.6% 18.3%
British Columbia royalty rate(2) 15.4% 18.2% 15.4% 18.2%
Manitoba royalty rate(2) 12.5% 12.5% 12.5% 12.5%
-------------------------------------------------------------------------
Total Corporate Royalty Rate 13.7% 14.9% 14.8% 15.8%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 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 Alberta Royalty Framework ('ARF') on January 1, 2009, the Alberta government introduced certain transitional rates and incentive programs to provide royalty relief to producers and to encourage continued drilling activity in the province. ARC will be eligible for the Alberta programs assuming the necessary criteria are met and required elections are filed. The drilling credit program applies to new wells drilled between April 1, 2009 and March 31, 2011. As at December 31, 2010, ARC has received credits of $11.2 million and estimates it will generate approximately $14.4 million in credits over the life of the program based on forward-looking prices. ARC is automatically eligible for the reduced royalty rate incentive on new production for wells coming on production between April 1, 2009 and March 31, 2011. These wells will receive a crown royalty rate of five per cent subject to certain production limits. These changes will come into effect January 1, 2011.
Operating costs decreased to $9.01 per boe in the fourth quarter of 2010 compared to $9.91 per boe in 2009. The decrease is attributable to the new production from the Dawson gas plant coming on stream at operating cost levels significantly below the corporate average and to lower operating costs relative to the corporate average of the Parkland field which accounted for approximately 85 per cent of the volume acquired through the Storm acquisition.
General and Administrative ('G&A') Expenses and Long-term Incentive Compensation
G&A, prior to the Restricted Share Unit and Performance Share Unit Plan ('RSU & PSU Plan') expense and net of overhead recoveries on operated properties, increased 51 per cent from $9.9 million in the fourth quarter of 2009 to $14.9 million in 2010. The same increase also occurred for the full year 2010, with Cash G&A expenses before RSU & PSU Plan increasing 45 per cent to $59.1 million. The increase in G&A for both the fourth quarter 2010 and the full year 2010 is mainly due to higher compensation levels associated with both increased staffing levels required to execute ARC's growth prospects and stronger performance metrics on ARC's key performance indicators. Annual compensation expenses also increased as ARC's Board of Directors approved a $2.8 million special performance bonus to staff in recognition of exceptional 2009 results. In addition, ARC incurred an increase in rent expense due to the relocation of ARC's head office as well as higher legal and consulting expenses related to the conversion from a trust to a corporation. These increases to G&A were partially offset by higher operating recoveries from ARC's partners due to a larger capital program.
Table 17 is a breakdown of G&A and incentive compensation expense under the RSU & PSU Plan:
<<
Table 17
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
G&A and Incentive
Compensation Expense % %
($ millions except per boe) 2010 2009 Change 2010 2009 Change
-------------------------------------------------------------------------
G&A expenses 19.2 14.0 37 75.0 56.1 34
Operating recoveries (4.3) (4.1) 5 (15.9) (15.4) 3
-------------------------------------------------------------------------
Cash G&A expenses before
RSU & PSU Plan 14.9 9.9 51 59.1 40.7 45
Cash Expense - RSU &
PSU Plan - - - 20.5 11.7 75
-------------------------------------------------------------------------
Cash G&A expenses including
RSU & PSU Plan 14.9 9.9 51 79.6 52.4 52
Accrued compensation - RSU
& PSU Plan 19.8 3.9 408 12.0 (0.1) -
-------------------------------------------------------------------------
Total G&A and incentive
compensation expense 34.7 13.8 151 91.6 52.3 75
-------------------------------------------------------------------------
Total G&A and incentive
compensation expense
per boe 4.45 2.40 85 3.39 2.26 50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Long-Term Incentive Plans - Restricted Share Units & Performance Share Units Plan, Stock Option Plan, and Deferred Share Unit Plan
Restricted Share Units and Performance Share Units Plan
The RSU & PSU Plan (formerly referred to as 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 share units. The RSU & PSU Plan consists of Restricted Share Units ('RSUs') for which the number of units is fixed and will vest over a period of three years and Performance Share Units ('PSUs') 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 share units plus accrued dividends. The cash compensation issued upon vesting of the PSUs is dependent upon the total return performance of ARC compared to its peers. Total return is calculated as a sum of the change in the market price of the common shares in the period plus the amount of dividends in the period. A performance multiplier is applied to the PSUs based on the percentile rank of ARC's total shareholder 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.
ARC did not make any cash payments under the RSU & PSU Plan in the fourth quarter of 2010. For the full year 2010, cash RSU & PSU Plan payments totaled $28 million, of which $20.5 million was recorded in G&A with the remaining $7.5 million recorded to operating costs and property, plant and equipment. The increase in cash RSU & PSU Plan from 2009 to 2010 reflects ARC's increase in share price and a two times performance multiplier due to ARC's shares achieving top quartile total returns to its shareholders compared to its selected peer group. The next cash payment under the RSU & PSU Plan is scheduled to occur in March 2011.
A non-cash RSU & PSU Plan expense of $19.8 million was recorded in the fourth quarter of 2010 compared to $3.9 million in 2009. For the full year 2010, a non-cash RSU & PSU Plan expense of $12 million was recorded compared to a recovery of $0.1 million in 2009. The increase in expense for both periods is due to the increase in ARC's share price and performance multiplier.
Table 18 shows the changes to the RSU & PSU Plan during 2010 along with the estimated value upon vesting of the plan as at December 31, 2010:
<<
Table 18
-------------------------------------------------------------------------
RSU & PSU Plan
(units in thousands and Number of Number of Total
$ millions except per unit) RSUs PSUs RSUs and PSUs
-------------------------------------------------------------------------
Balance, beginning of year 1,052 1,305 2,357
Granted 511 460 971
Vested (459) (321) (780)
Forfeited (87) (143) (230)
-------------------------------------------------------------------------
Balance, end of year(1) 1,017 1,301 2,318
Estimated dividends 74 135 209
-------------------------------------------------------------------------
Estimated units upon vesting
after dividends 1,091 1,436 2,527
Performance multiplier(2) - 1.5 -
-------------------------------------------------------------------------
Estimated units upon vesting 1,091 2,091 3,182
-------------------------------------------------------------------------
Share price at December 31, 2010 25.41 25.41 25.41
Estimated total value upon
vesting ($ millions) 27.7 53.1 80.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on underlying units before performance multiplier and accrued
dividends.
(2) The performance multiplier only applies to PSUs and was estimated to
be 1.5 at December 31, 2010 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 RSUs and PSUs is expensed in the statement of income over the vesting period with the expense amount being determined by the share price, accrued dividends and the number of PSUs to be issued on vesting. In periods where substantial share price fluctuation occurs, ARC's G&A expense is subject to significant volatility.
Due to the variability in the future payments under the plan, ARC estimates that between $27.7 million and $100.6 million will be paid out from 2011 through 2013 based on the current share price, accrued dividends and ARC's market performance relative to its peers. Table 19 is a summary of the range of future expected payments under the RSU & PSU Plan based on variability of the performance multiplier and units outstanding under the RSU & PSU Plan as at December 31, 2010:
<<
Table 19
-------------------------------------------------------------------------
Value of RSU & PSU Plan as at
December 31, 2010 Performance multiplier
(units thousands and $ millions ------------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated units to vest
RSUs 1,091 1,091 1,091
PSUs - 1,436 2,870
-------------------------------------------------------------------------
Total units(1) 1,091 2,527 3,961
-------------------------------------------------------------------------
Share price(2) 25.41 25.41 25.41
-------------------------------------------------------------------------
Value of RSU & PSU Plan upon
vesting(3) 27.7 64.2 100.6
-------------------------------------------------------------------------
2011 13.5 23.0 32.5
2012 10.0 25.6 41.2
2013 4.2 15.6 26.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes additional estimated units to be issued under the RSU & PSU
Plan for accrued dividends.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying share price. Assumes a future share price of
$25.41.
(3) Upon vesting, a cash payment is made equivalent to the value of the
share units or market price of the underlying common shares. 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.
>>
Share Option Plan ('ARC options')
On December 15, 2010, ARC shareholders approved a new ARC Share Option Plan. To date, no ARC options have been granted under this plan. The maximum shares issuable under this plan shall not exceed 14.2 million shares and is subject to the following terms, subject to modification, by ARC's Board of Directors:
<<
- ARC options will have a term not exceeding seven years;
- 50 per cent of a grant will vest on each of the fourth and fifth
anniversary grant dates, respectively;
- Grant price will not be less than the five-day volume weighted
average price of ARC's shares on the TSX preceding the grant date;
and
- Exercise price, at the election of the optionholder, will be either
the grant price or the price calculated by the grant price less all
dividends paid from the grant date to the exercise date.
>>
Deferred Share Unit Plan ('DSU Plan')
On December 15, 2010, ARC shareholders approved a new Directors' DSU Plan. To date, no deferred share units ('DSUs') have been granted under this plan. Non-executive directors will no longer receive RSUs but will instead receive DSUs which allows the holder to redeem the DSUs for a cash payment equal to the number of DSUs multiplied by the weighted average trading price of ARC's shares on the TSX for the five trading days prior to the date of settlement. DSUs are adjusted for dividends. Redemption may occur from the date that the holder ceases to be a director of ARC until December 1 in the following calendar year.
Interest and financing charges
Interest and financing charges increased to $10.5 million in the fourth quarter of 2010 from $5.9 million in 2009. For the full year 2010, interest and financing charges increased 65 per cent from $25.7 million in 2009 to $42.5 million in 2010 as a result of financing charges incurred on the renewal of ARC's credit facility and with increased debt servicing costs associated with the renewed facility. As at December 31, 2010, ARC has $803.5 million of long-term debt outstanding, of which $444.5 million is fixed at a weighted average interest rate of 5.8 per cent. On the remaining $359 million ARC currently pays a floating interest rate based on current market rates plus a credit spread of 225 basis points. Approximately 52 per cent (US$417.8 million) of ARC's debt outstanding is denominated in U.S. dollars.
Foreign Exchange Gains and Losses
ARC recorded a gain of $15.1 million in the fourth quarter of 2010 on foreign exchange transactions compared to a gain of $9.7 million in 2009. These amounts include both realized and unrealized foreign exchange gains and losses.
Table 20 shows the various components of foreign exchange gains and losses:
<<
Table 20
-------------------------------------------------------------------------
Foreign Exchange Gains/Losses Three Months Ended Twelve Months Ended
December 31 December 31
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Unrealized gain (loss)
on U.S. denominated debt 10.3 5.7 81 (6.0) 66.3 (109)
Realized gain on U.S.
denominated debt 4.6 3.1 48 32.9 2.7 -
Realized gain (loss) on
U.S. denominated
transactions 0.2 0.9 (78) (0.1) 1.0 (110)
-------------------------------------------------------------------------
Total foreign exchange gain 15.1 9.7 56 26.8 70.0 (62)
-------------------------------------------------------------------------
>>
Nominal realized foreign exchange gains and losses arising from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements were recorded during the fourth quarter of 2010.
Unrealized foreign exchange gains and losses are due to the 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 item. From September 30, 2010 to December 31, 2010, the Cdn$/US$ exchange rate decreased from 1.03 to 0.99 resulting in an unrealized gain of $15.1 million on U.S. dollar denominated debt.
Taxes
In the fourth quarter of 2010, a future income tax recovery of $18.4 million was recorded compared to $1.9 million in 2009. The fourth quarter 2010 recovery is primarily due to an $85.9 million unrealized loss on risk management contracts.
The corporate income tax rate applicable to 2010 is 28 per cent, however, ARC and its subsidiaries did not pay any material cash income taxes for the fourth quarter of 2010. Up until December 31, 2010, ARC's structure was such that both income tax and future tax liabilities were passed onto the unitholders by means of royalty payments made between ARC and the Trust. With the conversion from a trust structure to a traditional corporate structure effectively completed on December 31, 2010, ARC will be subject to future income taxes and tax liabilities. Current taxes payable by ARC will be subject to normal corporate tax rates. Taxable income as a corporation will vary depending on total income and expenses and with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures. As ARC has accumulated $2.4 billion of income tax pools for federal tax purposes, taxable income will be reduced or potentially eliminated for the initial period post-conversion. Using the current forward commodity price outlook and a modeled future production volume forecast, ARC does not expect to be in a material cash tax-paying position until 2013. The income tax pools (detailed in Table 21) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.
<<
Table 21
-------------------------------------------------------------------------
Cdn$ millions at
Income Tax Pool type December 31, 2010 Annual deductibility
-------------------------------------------------------------------------
Canadian Oil and Gas Property
Expense 982.5 10% declining balance
Canadian Development Expense 504.4 30% declining balance
Canadian Exploration Expense 95.5 100%
Primarily
Undepreciated Capital Cost 619.2 25% declining balance
Non-Capital Losses 183.9 100%
Research and Experimental
Expenditures 22.2 100%
Various rates, 7%
Other 26.0 declining balance to 20%
-------------------------------------------------------------------------
Total Federal Tax Pools 2,433.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Various rates, 25%
Additional Alberta Tax Pools 177.6 declining balance to 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ('DD&A') rate increased slightly to $16.98 per boe in the fourth quarter of 2010 from $16.71 per boe in 2009. For the full year 2010, the DD&A rate increased three per cent from $16.66 per boe in 2009 to $17.08 per boe in 2010. The increase related primarily to the acquisition of Storm, which added both proved and probable reserves to ARC's asset base. ARC, however, only recognizes proved reserves for the purpose of its depletion calculation. As such, actual depletion expense has increased both in the fourth quarter of 2010 over the fourth quarter of 2009 and the full year of 2010 over the full year of 2009 due to the increase in the DD&A rate as well as an increase in production volumes of 35 per cent and 16 per cent quarter over quarter and year over year, respectively. In the second quarter of 2010, ARC relocated to a new head office and began depreciating the associated leasehold improvements and construction costs. In previous periods, nominal depreciation had been recognized.
A breakdown of the DD&A rate is summarized in Table 22:
<<
Table 22
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
DD&A Rate
($ millions except per
boe amounts) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Depletion of oil and gas
assets(1) 128.5 93.8 37 448.1 377.1 19
Depreciation of fixed
assets 1.2 - 100 3.1 - 100
Accretion of asset
retirement obligation(2) 2.6 2.3 13 9.9 9.3 6
-------------------------------------------------------------------------
Total DD&A 132.3 96.1 38 461.1 386.4 19
DD&A rate per boe 16.98 16.71 2 17.08 16.66 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>
Capital Expenditures and Net Acquisitions
Capital expenditures, excluding acquisitions and dispositions, totaled $159.1 million in the fourth quarter of 2010 and $590.9 million for the full year 2010. This amount was incurred on drilling and completions, geological, geophysical, facilities expenditures and undeveloped land.
For the full year 2010, $335.3 million was spent on ARC's resource plays, including $240.3 million for development of the Montney resource play in northeast British Columbia, $42.7 million on undeveloped lands for the Montney resource play, $43 million for the Cardium resource play in Alberta, and $1.7 million on undeveloped lands for the Cardium resource play. The remaining $197.5 million was spent on ARC's conventional oil and gas properties, $16.5 million spent on conventional land purchases, $17.5 million on ARC's enhanced oil recovery initiatives and $24.1 million on leasehold expenditures associated with ARC's corporate office move. Total capital expenditures are forecast to be $625 million in 2011.
A breakdown of capital expenditures and net acquisitions is shown in Table 23:
<<
Table 23
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
Capital Expenditures
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Geological and geophysical 5.6 2.9 93 16.0 13.7 17
Drilling and completions 100.4 66.2 52 358.5 214.3 67
Plant and facilities 42.9 35.2 22 131.4 110.0 19
Undeveloped land purchased
at crown land sales 6.9 2.1 229 60.9 7.0 -
Other capital 3.3 10.9 (70) 24.1 14.6 65
-------------------------------------------------------------------------
Total capital expenditures
before net acquisitions 159.1 117.3 36 590.9 359.6 64
-------------------------------------------------------------------------
Producing property
acquisitions(1) 1.2 1.2 - 8.9 8.2 9
Undeveloped land property
acquisitions - 5.8 (100) - 14.5 (100)
Producing property
dispositions(1) (0.4) - - (3.9) (37.3) (90)
Undeveloped land property
dispositions - (5.9) (100) - (5.9) (100)
Corporate acquisition(2) - 178.9 (100) 652.1 178.9 265
-------------------------------------------------------------------------
Total capital
expenditures and net
acquisitions 159.9 297.3 (46) 1,248.0 518.0 141
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
(2) Represents total consideration paid for corporate acquisitions.
>>
On a regular basis, ARC evaluates its asset portfolio to ensure that all assets still fit our business strategy and may sell assets that do not meet our retention guidelines. On January 31, 2011, ARC disposed of non-core assets in central Alberta that currently produce approximately 3,400 boe per day (60 per cent gas and 40 per cent liquids) for proceeds of $170 million.
Approximately 85 per cent of the $159.1 million capital program in the fourth quarter of 2010 was financed with cash flow from operating activities and proceeds from our Dividend Reinvestment and Optional Cash Payment Program ('DRIP') compared to 73 per cent in 2009. On a year-to-date basis, ARC has funded 75 per cent of the capital expenditures with cash flow from operating activities and proceeds from DRIP, compared to 73 per cent in 2009.
<<
Table 24
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended December 31, 2010
-------------------------------------------------------------------------
Net
Capital Acquisi- Total
Expenditures tions(1) Expenditures
-------------------------------------------------------------------------
Expenditures 159.1 0.8 159.9
-------------------------------------------------------------------------
Cash flow from operating activities 70% - 70%
Proceeds from DRIP 15% - 15%
Debt/(excess funding) 15% 100% 15%
-------------------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes corporate acquisitions based on total consideration paid.
Table 24
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended December 31, 2009
-------------------------------------------------------------------------
Net
Capital Acquisi- Total
Expenditures tions(1) Expenditures
-------------------------------------------------------------------------
Expenditures 117.3 180.0 297.3
-------------------------------------------------------------------------
Cash flow from operating activities 60% - 24%
Proceeds from DRIP 13% - 5%
Debt/(excess funding) 27% 100% 71%
-------------------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes corporate acquisitions based on total consideration paid.
Table 24a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Twelve Months Ended December 31, 2010
-------------------------------------------------------------------------
Net
Capital Acquisi- Total
Expenditures tions(1) Expenditures
-------------------------------------------------------------------------
Expenditures 590.9 657.1 1,248.0
-------------------------------------------------------------------------
Cash flow from operating activities 62% - 30%
Proceeds from DRIP 13% - 6%
Proceeds from equity - 85% 44%
Debt 25% 15% 20%
-------------------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes corporate acquisitions based on total consideration paid.
Table 24a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Twelve Months Ended December 31, 2009
-------------------------------------------------------------------------
Net
Capital Acquisi- Total
Expenditures tions(1) Expenditures
-------------------------------------------------------------------------
Expenditures 359.6 158.4 518.0
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from operating activities 54% - 38%
Proceeds from DRIP 19% - 13%
Proceeds from equity - - -
Debt 27% 100% 49%
-------------------------------------------------------------------------
100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes corporate acquistions based on total consideration paid.
>>
Asset Retirement Obligation and Reclamation Fund
At December 31, 2010, ARC recorded an Asset Retirement Obligation ('ARO') of $169.1 million ($149.9 million at December 31, 2009) for the future abandonment and reclamation of ARC's properties. The estimated ARO includes assumptions in respect of actual costs to abandon wells or reclaim the property as well as annual inflation factors in order to calculate the undiscounted total future liability. The future liability is then discounted at a weighted average credit adjusted risk free rate of 6.5 per cent.
Included in the December 31, 2010 ARO balance is $15 million of additional ARO related to the Storm acquisition, a $1.6 million increase related to development activities, a $0.5 million increase related to the change in estimated future obligations, $9.9 million for accretion expense, and a reduction of $7.8 million for actual abandonment expenditures incurred in 2010.
ARC established a restricted reclamation fund to finance obligations specifically associated with the Redwater property in 2005. Minimum contributions to this fund will be approximately $81 million over the next 45 years. The balance of this fund totaled $25 million at December 31, 2010, compared to $20.6 million at December 31, 2009. Under the terms of ARC's investment policy, reclamation fund investments and excess cash can only be invested in Canadian or U.S. Government securities, investment grade corporate bonds, or investment grade short-term money market securities.
All investments in the unrestricted fund were withdrawn and applied to outstanding bank debt during the fourth quarter of 2010. Environmental stewardship is a core value at ARC and abandonment and reclamation activities will continue to be made in the future in a prudent responsible manner with the oversight of the Health, Safety and Environment Committee of the Board. Future abandonment expenditures will be funded entirely from cash flow from operating activities.
Capitalization, Financial Resources and Liquidity
A breakdown of ARC's capital structure is outlined in Table 25, as at December 31, 2010 and December 31, 2009:
<<
Table 25
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per cent and ratio amounts) December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Long-term debt 803.5 846.1
Working capital deficit(1) 69.1 56.3
-------------------------------------------------------------------------
Net debt obligations(2) 872.6 902.4
Market value of common shares(3) 7,226.6 4,765.7
-------------------------------------------------------------------------
Total capitalization(4) 8,099.2 5,668.1
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 10.8% 15.9%
Net debt to cash flow from operating activities 1.3 1.8
-------------------------------------------------------------------------
(1) Working capital deficit 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 common shares outstanding at December 31,
2010 (total trust units outstanding including the total number of
trust units issuable for exchangeable shares at December 31, 2009)
multiplied by the closing share price of $25.41 for 2010 (closing
trust unit price of $19.94 for 2009).
(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 December 31, 2010, ARC had total credit facilities of $1.6 billion with $803.5 million currently drawn resulting in unused credit available of $779.8 million. On August 3, 2010, ARC signed an agreement to renew its syndicated credit facility for a three-year term, effective August 4, 2010 to August 3, 2013. The renewed facility increases the existing credit facility from $800 million to $1 billion and increases ARC's total credit facilities from $1.4 billion to $1.6 billion. The credit facilities consist of a banking syndicate of 13 domestic and international banks, senior notes, and a Master Shelf agreement with a U.S. institutional investor.
Costs of borrowing under our syndicated credit facility comprise two items: first, the underlying interest rate on Bankers' Acceptances and Prime Loans (CDN dollar loans) or LIBOR Loans and US Base Rate Loans (U.S. denominated borrowings) and second, ARC's credit spread. The credit spread to ARC from the beginning of 2009 to July 2010 ranged between 60 and 70 basis points on all Bankers' Acceptances and LIBOR Loans. No Prime Loans or US Base Rate Loans were drawn during this period. Effective August 2010, under the new bank credit facilities, the credit spread increased to 225 basis points for the remainder of 2010. Future credit spreads to ARC may range from 200 to 350 basis points for Bankers' Acceptances and LIBOR loans depending on ARC's debt to cash flow ratio. In addition to paying interest on the outstanding debt under the revolving syndicated credit facility, ARC is charged a standby fee for the amount of the undrawn facility. This standby fee has ranged from 12.5 to 15 basis points from the beginning of 2009 to July 2010 and now ranges from 50 to 87.5 basis points under the renewed facility. These spreads are adjusted on the first day of the third month after each quarter-end date.
ARC's debt agreements contain a number of covenants all of which were met as at December 31, 2010. These agreements are available at www.sedar.com. The major financial covenants are described below:
<<
- 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 Shareholders' equity and long-term debt, letters of
credit and subordinated debt.
>>
ARC's long-term strategy is to keep debt at less than two times cash flow from operating activities and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels throughout 2009 and 2010 and has positioned ARC to remain well below the debt covenant levels of three times. At the end of 2010, debt to annual cash flow from operating activities was 1.3 times.
ARC typically uses three markets to raise capital: equity, bank debt and long-term notes. All three markets have been accessed by ARC during 2010. Long-term notes are issued to large institutional investors normally with an average term of five to 10 years. The cost of this debt is based upon two factors: the current rate of long-term government bonds and ARC's credit spread. ARC's average interest rate on its outstanding long-term notes is currently 5.8 per cent.
ARC expects to finance its 2011 capital program with cash flow from operating activities, proceeds from the DRIP and existing credit capacity. If ARC undertakes any major acquisitions, management would expect to finance the transactions with a combination of debt and equity in a cost effective manner.
Shareholders' Equity
On December 31, 2010, ARC converted all outstanding trust units and exchangeable shares into common shares on a one share per trust unit basis. At December 31, 2010, there were 284.4 million shares issued, an increase of 47.8 million shares over the balance of trust units issued and issuable from December 31, 2009. This is due primarily to the issuance of 28.4 million trust units and exchangeable shares convertible into trust units in August 2010 in conjunction with the Storm acquisition and the issuance of 13 million trust units from an equity offering that closed in January 2010. The January 2010 equity offering was made concurrent with ARC's $180 million purchase of properties at Ante Creek, with gross and net proceeds of approximately $252 million and $240 million, respectively.
Pursuant to the Arrangement and the conversion from a trust to a corporation, ARC's deficit on December 31, 2010 was reduced to nil through a reduction of Shareholders' Capital by $631.3 million.
Shareholders electing to reinvest dividends or make optional cash payments to acquire shares 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. In 2010, ARC raised proceeds of $74.4 million and issued 3.7 million trust units pursuant to the DRIP at an average price of $20.16 per share.
Distributions/Dividends
In the fourth quarter of 2010, ARC declared distributions of $82.9 million ($0.30 per trust unit) compared to distributions of $70.9 million ($0.30 per trust unit) in 2009. For the full year 2010, ARC declared distributions of $313.5 million ($1.20 per trust unit) compared to distributions of $298.5 million ($1.28 per trust unit) in 2009.
Pursuant to the conversion to a corporation, ARC will now pay dividends to its shareholders effective January 1, 2011, with the first dividend payment to be made on February 15, 2011. ARC continually assesses dividend levels in light of commodity prices, capital expenditure programs and production volumes, to ensure that dividends are in line with the long-term strategy and objectives of ARC as per the following guidelines:
<<
- To maintain a dividend policy 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 that volatility onto shareholders in the form of fluctuating
monthly dividends.
- 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 need to use debt to finance these expenditures. In 2010,
ARC funded 75 per cent of capital development activities with cash
flow from operating activities and DRIP proceeds. Dividends 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.
>>
The actual amount of future monthly dividends is proposed by management and is subject to the approval and discretion of the Board of Directors. The Board reviews future dividends in conjunction with their review of quarterly financial and operating results.
Please refer to ARC's website at www.arcresources.com for details of the monthly dividends amounts and dividend dates for 2011.
Taxation of Distributions and Dividends
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. Effective January 1, 2011, ARC will pay dividends to its shareholders. Dividends from ARC are taxed differently than distributions of the Trust in that dividends do not comprise a return of capital and thus are fully taxable. For a more detailed breakdown, please visit our website at www.arcresources.com. The following table is a summary of historical distributions paid.
<<
Table 26
-------------------------------------------------------------------------
Calendar Year Distributions Taxable Portion Return of Capital
-------------------------------------------------------------------------
2010(2) 1.20 1.02 0.18
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 $26.18 $19.09 $7.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on distributions paid and payable in 2006.
(2) Based on distributions declared at December 31, 2010 and taxable
portion of 2010 distributions of 85 per cent.
>>
Environmental Initiatives Impacting ARC
There are no new material environmental initiatives impacting ARC at this time.
Contractual Obligations and Commitments
ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC's cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 27.
<<
Table 27
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
2-3 4-5 Beyond 5
($ millions) 1 year years years years Total
-------------------------------------------------------------------------
Debt repayments(1) 17.0 437.1 83.0 266.4 803.5
Interest payments(2) 25.8 46.1 36.4 52.3 160.6
Reclamation fund
contributions(3) 4.6 8.3 7.1 60.8 80.8
Purchase commitments 38.7 33.6 12.8 9.2 94.3
Transportation commitments 27.1 46.2 32.5 18.2 124.0
Operating leases 9.0 18.1 14.9 64.7 106.7
Risk management contract
premiums(4) 3.6 2.2 - - 5.8
-------------------------------------------------------------------------
Total contractual obligations 125.8 591.6 186.7 471.6 1,375.7
-------------------------------------------------------------------------
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(1) Long-term and short-term debt.
(2) Fixed interest payments on senior notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) 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 14 of the unaudited Consolidated Financial Statements). As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at December 31, 2010 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 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 2011 capital budget of $625 million has been approved by the Board of Directors. The remaining portion of this commitment, as at December 31, 2010, has not been disclosed in the commitment table (Table 27) as it is of a routine nature and is part of normal course of operations for active oil and gas companies.
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 27) 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 27) 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 27), 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 on the balance sheet as of December 31, 2010.
Critical Accounting Estimates
ARC has continuously refined and documented its management and internal reporting systems to ensure 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.
ARC's 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.
ASSESSMENT OF BUSINESS RISKS
The ARC management team is focused on long-term strategic planning and has identified the key risks, uncertainties and opportunities associated with ARC's business that can impact the financial results as follows:
Volatility of Oil and Natural Gas Prices
ARC's operational results and financial condition, and therefore the amount of capital expenditures and future dividend payments made to shareholders, will be dependent on the prices received for oil and natural gas production. Any movement in oil and natural gas prices will have an effect on ARC's ability to continue with its capital expenditure program and its ability to pay dividends. Future declines in oil and natural gas prices may result in future declines in, or elimination of, any future dividends. Oil and natural gas prices are determined by economic and, in some circumstances, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions, impact prices. ARC may manage the risk associated with changes in commodity prices by entering into oil or natural gas price derivative contracts. If ARC engages in activities to manage its commodity price exposure, it may forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity derivative contracts activities could expose ARC to losses. To the extent that ARC engages in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which it contracts.
Refinancing and Debt Service
ARC currently has a $1 billion financial covenant-based syndicated credit facility with thirteen banks. At the request of ARC, the lenders will review the credit facility each year and determine if they will extend for another year. In the event that the facility is not extended before August 3, 2013, indebtedness under the facility will become repayable at that date. There is also a risk that the credit facility will not be renewed for the same amount or on the same terms. Any of these events could affect ARC's ability to fund ongoing operations and make future dividend payments.
ARC currently has US$418 million of U.S. denominated long-term debt outstanding which requires annual principal repayments in 2011 through 2022. ARC intends to fund these principal repayments with existing credit facilities. In the event ARC is unable to fund future principal repayments it may impact ARC's ability to fund its ongoing operations and make future dividend payments.
ARC is required to comply with covenants under the credit facility. In the event that ARC does not comply with covenants under the credit facility, ARC's access to capital could be restricted or repayment could be required. ARC routinely reviews the covenants based on actual and forecast results and has the ability to make changes to its development plans and/or dividend policy to comply with covenants under the credit facility. If ARC becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lender may foreclose on such assets of ARC or sell the working interests.
Operational Matters
The operation of oil and gas wells involves a number of operating and natural hazards that may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to operating subsidiaries of ARC and possible liability to third parties. ARC maintains liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. ARC may become liable for damages arising from such events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities will reduce dividend payments to shareholders.
Continuing production from a property, and to some extent the marketing of production there from, are largely dependent upon the ability of the operator of the property. Approximately 17 per cent of ARC's production is operated by third parties. ARC has limited ability to influence costs on partner operated properties. Operating costs on most properties have increased steadily over recent years. To the extent the operator fails to perform these functions properly, ARC's revenue from such property may be reduced. Payments from production generally flow through the operator and there is a risk of delayed payment, or non-payment and additional expense in recovering such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of ARC to certain properties. A reduction of future dividend payments to shareholders could result under such circumstances.
Reserves Estimates
The reserves and recovery information contained in ARC's independent reserves evaluation is only an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserves evaluator. The reserves report was prepared using certain commodity price assumptions. If lower prices for crude oil, natural gas liquids and natural gas are realized by ARC and substituted for the price assumptions utilized in those reserves reports, the present value of estimated future net cash flows for ARC's reserves as well as the amount of ARC's reserves would be reduced and the reduction could be significant.
Depletion of Reserves and Maintenance of Dividend
ARC's future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on ARC's success in exploiting its reserves base and acquiring additional reserves. Without reserves additions through acquisition or development activities, ARC's reserves and production will decline over time as the oil and natural gas reserves are produced out. There can be no assurance that ARC will make sufficient capital expenditures to maintain production at current levels nor, as a consequence, that the amount of dividends by ARC to shareholders can be maintained at current levels. There can be no assurance that ARC will be successful in developing or acquiring additional reserves on terms that meet ARC's investment objectives.
Counterparty Risk
ARC assumes customer credit risk associated with oil and gas sales, financial hedging transactions and joint venture participants. In the event that ARC's counterparties default on payments to ARC, cash flows will be impacted and dividend payments to shareholders may be impacted. ARC has established credit policies and controls designed to mitigate the risk of default or non-payment with respect to oil and gas sales, financial hedging transactions and joint venture participants. A diversified sales customer base is maintained and exposure to individual entities is reviewed on a regular basis.
Variations in Interest Rates and Foreign Exchange Rates
Variations in interest rates could result in an increase in the amount ARC pays to service debt. World oil prices are quoted in U.S. dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact ARC's net production revenue. Volatility in interest rates and the Canadian dollar may affect future cash flow from operations and reduce funds available for both dividends and capital expenditures. ARC may initiate certain derivative contracts to attempt to mitigate these risks. To the extent that ARC engages in risk management activities related to foreign exchange rates, it will be subject to credit risk associated with counterparties with which it contracts. An increase in Canadian/U.S. exchange rates may impact future dividend payments to shareholders and the value of ARC's reserves as determined by independent evaluators.
Changes in Income Tax Legislation
In the future, income tax laws or other laws may be changed or interpreted in a manner that adversely affects ARC or its shareholders. Tax authorities having jurisdiction over ARC or its shareholders may disagree with how ARC calculates its income for tax purposes to the detriment of ARC and its shareholders.
Changes in Government Royalty Legislation
Provincial programs related to the oil and natural gas industry may change in a manner that adversely impacts shareholders. ARC currently operates in British Columbia, Alberta, Saskatchewan and Manitoba, all of which have different royalty programs that could be revised at any time. Future amendments to royalty programs in any of ARC's operating jurisdictions could result in reduced cash flow and reduced dividend payments to shareholders.
Acquisitions
The price paid for acquisitions is based on engineering and economic estimates of the potential reserves made by independent engineers modified to reflect the technical views of management. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of oil, natural gas, natural gas liquids and sulphur, future prices of oil, natural gas, natural gas liquids and sulphur and operating costs, future capital expenditures and royalties and other government levies that will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and ARC. In particular, changes in the prices of and markets for oil, natural gas, natural gas liquids and sulphur from those anticipated at the time of making such assessments will affect the amount of future dividends and the value of the shares. In addition, all such estimates involve a measure of geological and engineering uncertainty that could result in lower production and reserves than attributed to the working interests. Actual reserves could vary materially from these estimates. Consequently, the reserves acquired may be less than expected, which could adversely impact cash flow and dividends to shareholders.
Environmental Concerns and Impact on Enhanced Oil Recovery Projects
The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of ARC or its working interests. Such legislation may be changed to impose higher standards and potentially more costly obligations on ARC. Furthermore, management believes the federal political parties appear to favor new programs for environmental laws and regulation, particularly in relation to the reduction of emissions, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which ARC cannot meet. Financial penalties or charges could be incurred as a result of the failure to meet such targets. In particular there is uncertainty regarding the Federal Government's Regulatory Framework for Air Emissions ('Framework'), as issued under the Canadian Environmental Protection Act.
Additionally, the potential impact on ARC's operations and business of the Framework, with respect to instituting reductions of greenhouse gases, is not possible to quantify at this time as specific measures for meeting Canada's commitments have not been developed. Currently, companies are permitted to emit CO(2) into the atmosphere with no requirement to capture and re-inject the emissions. In order for ARC to carry out its enhanced oil recovery program it is necessary to obtain CO(2) at a cost effective rate. Given that companies are not forced to capture their emissions, the infrastructure has not been put in place to facilitate this process. Without any additional provisions from the government, the economic parameters of ARC's enhanced oil recovery programs would be limited.
ARC has established a reclamation fund (the 'Redwater fund') for the purpose of funding future environmental and reclamation obligations at its Redwater property. For ARC's other properties, future environmental and reclamation obligations will be funded with cash flow in future periods. Contributions to the Redwater fund are based on current estimates and there can be no assurances that ARC will be able to satisfy its actual Redwater future environmental and reclamation obligations with the balance of the fund. Actual future environmental and reclamation expenditures could differ significantly from estimated amounts, therefore future cash flows and dividend payments to shareholders may be negatively impacted in future periods.
PROJECT RISKS
ARC manages a variety of small and large projects and plans to spend $625 million on capital projects throughout 2011. Project delays may impact expected revenues from operations. Significant project cost overruns could make a project uneconomic. Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:
<<
- availability of processing capacity;
- availability and proximity of pipeline capacity;
- availability of storage capacity;
- supply of and demand for oil and natural gas;
- availability of alternative fuel sources;
- effects of inclement weather;
- availability of drilling and related equipment;
- unexpected cost increases;
- accidental events;
- changes in regulations;
- availability and productivity of skilled labour; and
- regulation of the oil and natural gas industry by various levels of
government and governmental agencies.
>>
Because of these factors, ARC could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that ARC produces.
Disclosure Controls and Procedures
As of December 31, 2010, an internal evaluation was carried out of the effectiveness of ARC's disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that ARC files or submits under the Exchange Act or under Canadian Securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by ARC in the reports that it files or submits under the Exchange Act or under Canadian Securities Legislation is accumulated and communicated to ARC's management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.
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 Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. The assessment was based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that ARC's internal control over financial reporting was effective as of December 31, 2010. The effectiveness of ARC's internal control over financial reporting as of December 31, 2010 has been audited by Deloitte & Touche LLP, as reflected in their report for 2010. No changes were made to ARC's internal control over financial reporting during the year ending December 31, 2010, that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.
Financial Reporting Update
New Accounting Standards Adopted
In 2010, ARC early adopted CICA Handbook Section 1582 'Business Combinations', which replaces Section 1581 of the same name. Under this standard, the purchase price of a business combination is based on the fair value of consideration exchanged at the acquisition date and any contingent consideration of the acquisition is to be recognized at fair value at the acquisition date and subsequently re-measured at fair value with changes recorded through earnings each period until settled. In addition, this new guidance generally requires all transaction costs to be expensed through the income statement and any negative goodwill is required to be recognized immediately into earnings. This standard has been applied prospectively to record ARC's business combination with Storm.
In accordance with the transitional provisions contained within CICA Handbook Section 1582, ARC has, at the same time as its adoption of Section 1582, adopted CICA Handbook Sections 1601 and 1602, which together replace CICA Handbook Section 1600, 'Consolidated Financial Statements', as described below:
Section 1601 'Consolidated Financial Statements' establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard did not have any impact on ARC's consolidated financial statements.
Section 1602 'Non-Controlling Interests' establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. Upon adoption of this standard, ARC has reclassified its non-controlling interest to equity on its consolidated balance sheet and presented its net income and other comprehensive income attributable to itself and its non-controlling interest on a retrospective basis.
The above CICA Handbook Sections are converged with International Financial Reporting Standards.
International Financial Reporting Standards ('IFRS')
In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without modification, for all financial periods beginning January 1, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by ARC for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.
ARC commenced the process to transition its financial statements from current Canadian GAAP to IFRS in 2008 and has progressed towards completion during 2009 and 2010. ARC's project consists of three key phases: the scoping and diagnostic phase, the impact analysis and evaluation phase and the implementation phase.
<<
- 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 were given a
priority ranking according to their 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 were addressed according to the priority
ranking assigned to them. ARC conducted analysis of policy choices
allowed under IFRS and their impact to the financial statements.
Additionally, certain potential differences were further investigated
to assess if there was any broader impact to ARC's debt agreements,
compensation arrangements or management reporting systems. The impact
analysis and evaluation phase was concluded with the Audit Committee
of the Board of Directors reviewing and approving all accounting
policies proposed by management.
- Implementation phase - involved implementation of all changes
approved in the impact analysis and evaluation phase, included some
changes to existing information systems, the creation of some new
business processes, the modification of some existing debt agreements
and training of staff impacted by the conversion.
>>
Since its inception, the project has been led by internal staff within the financial reporting group with sponsorship from the management team. ARC has effectively completed all phases of its IFRS transition project and continues to review its draft IFRS financial statements and disclosures for completeness and quality assurance. The Audit Committee has approved ARC's IFRS accounting policy selections that have been presented by management to date as disclosed herein.
First Time Adoption of IFRS
Most adjustments required on transition to IFRS will be made retrospectively against opening retained earnings as of the date of the first comparative balance sheet presented, based on standards applicable at that time. IFRS 1 provides entities adopting IFRS for the first time with certain optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS. Management has analyzed the various accounting policy choices available under IFRS 1 and has implemented those determined to be the most appropriate for ARC. Accordingly, it has applied the following IFRS 1 exemptions in its IFRS opening balance sheet:
<<
- Property, Plant and Equipment ('PP&E') - IFRS 1 provides an option to
entities such as ARC who follow the full cost accounting guideline
under Canadian GAAP to value their oil and gas PP&E on the date of
transition to IFRS at its deemed cost, defined as the carrying value
assigned to these assets under Canadian GAAP at the date of
transition, January 1, 2010. Under IFRS, ARC's PP&E must be divided
into multiple cash generating units (CGUs), which is unlike full cost
accounting where all oil and gas assets are accumulated into one cost
centre. The deemed cost of ARC's oil and gas PP&E has been allocated
to seven CGUs based on ARC's proved plus probable reserve values at
January 1, 2010. These CGUs are aligned with the major geographic
regions in which ARC operates and could change in the future as a
result of significant acquisition or disposition activity.
- Business Combinations - IFRS 1 provides an optional exemption to the
requirement to retrospectively restate any business combinations that
have previously been recorded under Canadian GAAP. Accordingly, ARC
will not be recording any adjustments to retrospectively restate any
of its business combinations that have occurred prior to January 1,
2010.
>>
The following is a listing of key areas where accounting policies differ and where accounting policy decisions are necessary that will impact our reported financial position and results of operations:
<<
- Re-classification of Exploration and Evaluation ('E&E') expenditures
from PP&E - Upon transition to IFRS, ARC will reclassify all E&E
expenditures that are currently recognized as PP&E on the
Consolidated Balance Sheets. This consists of the carrying value of
certain undeveloped land that relates to exploration properties. E&E
assets will not be amortized and must be assessed for impairment when
indicators suggest the possibility of impairment as well as upon
transition to PP&E. Management has identified approximately $23
million of its property, plant and equipment that meets the criteria
to be classified as E&E in the opening balance sheet prepared under
IFRS as at January 1, 2010.
- 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 plus probable reserves, as compared
to the Canadian GAAP method of calculating depletion using proved
reserves only. ARC plans to determine its depletion expense using
proved plus probable reserves as its depletion base. Accordingly, ARC
expects that its depletion expense for the year ended December 31,
2010 would be reduced by approximately $2.69 per boe of production or
approximately $72.6 million as compared to its current calculation
under Canadian GAAP.
- Impairment of PP&E assets - Canadian GAAP generally uses a two-step
approach to impairment testing; first comparing asset carrying values
with undiscounted future cash flows to determine whether an
impairment exists, and then measuring impairment by comparing asset
carrying values to their fair value (which is calculated using
discounted cash flows). Under Canadian GAAP, ARC includes all assets
in one impairment test.
IFRS uses a one-step approach for testing and measuring impairment,
with asset carrying values compared directly with the higher of fair
value less costs to sell and value in use. Under IFRS, impairment of
PP&E must be calculated at a more granular level than what is
currently required under Canadian GAAP resulting in impairment
testing being done at the CGU level.
These differences may potentially result in impairment charges where
the carrying value of assets were previously supported under Canadian
GAAP by consolidated undiscounted cash flows, but could not be
supported by cash flows determined on a more granular discounted
basis.
At January 1, 2010 impairment tests were performed in accordance with
IFRS and no impairment was identified.
- Asset retirement obligation - Under IFRS, ARC is required to revalue
its entire liability for asset retirement costs at each balance sheet
date using a current liability-specific discount rate, which can
generally be interpreted to mean the current risk-free rate of
interest. Under Canadian GAAP, obligations are discounted using a
credit-adjusted risk-free rate and, once recorded, the asset
retirement obligation is not adjusted for future changes in discount
rates. At January 1, 2010 ARC's total of its asset retirement
obligations will increase $148.2 million to $298.1 million as the
liability is revalued to reflect the estimated risk free rate of
interest at that time of 4.08%. As a result of this change, ARC's
deferred tax liability is decreased by $36.9 million and the net
offset is recorded as a reduction to deficit.
- Exchangeable shares - Under IFRS, ARC's exchangeable shares meet the
criteria to be considered a puttable financial instrument and are
classified as a current financial liability. They will be recorded on
the statement of financial position at their fair value with any
changes being recorded in the statement of comprehensive income. At
January 1, 2010, ARC's current liability associated with exchangeable
shares under IFRS is $47.2 million. Under Canadian GAAP, exchangeable
shares are classified as non-controlling interest and measured using
the equity method.
- Deferred taxes - Under IFRS, entities that are subject to different
tax rates on distributed and undistributed income must calculate
deferred taxes using the undistributed profits rate, which is the
higher of the two. Canadian GAAP requires each individual tax rate to
be applied to distributed and undistributed profits, respectively. As
a result of using the undistributed profits rate, ARC will record a
reduction in its deferred tax liability of $29.8 million upon
transition to IFRS, with the offset recorded as a reduction to
deficit.
>>
Table 28 summarizes ARC's January 1, 2010 balance sheet under Canadian GAAP and the transitional entries required to present the opening balance sheet under IFRS. ARC has not yet prepared a full set of annual financial statements under IFRS, therefore, amounts are unaudited.
<<
Table 28
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(Cdn$ millions) Canadian GAAP IFRS Adjustments IFRS
-------------------------------------------------------------------------
Current assets 147.1 (7.1) 140.0
Long-term assets 3,767.4 - 3,767.4
-------------------------------------------------------------------------
Total assets 3,914.5 (7.1) 3,907.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current liabilities 203.3 47.2 250.5
Long-term liabilities 1,336.8 74.4 1,411.2
Equity 2,374.4 (128.7) 2,245.7
-------------------------------------------------------------------------
Total liabilities and
equity 3,914.5 (7.1) 3,907.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
In addition to accounting policy differences, ARC's transition to IFRS is expected to impact its internal controls over financial reporting, disclosure controls and procedures, certain of ARC's business activities and IT systems as follows:
<<
- Internal controls over financial reporting ('ICFR') - ARC is
currently in the process of reviewing its ICFR documentation and is
identifying instances where controls must be amended or added in
order to address the accounting policy changes required under IFRS.
No material changes in control procedures are expected as a result of
transition to IFRS.
- Disclosure controls and procedures - ARC has assessed the impact of
transition to IFRS on its disclosure controls and procedures and has
not identified any material changes required in its control
environment. It is expected that there will be increased note
disclosure around certain financial statement items than what is
currently required under Canadian GAAP. Management is currently
drafting its IFRS note disclosure in accordance with current IFRS
standards and continues to monitor requirements put forth by the IASB
in discussion papers and exposure drafts for future disclosure
requirements. Throughout the transition process, ARC has carefully
considered its stakeholders' information requirements and will
continue to ensure that adequate and timely information is provided
to meet these needs.
- Business activities - Management has been cognizant of the upcoming
transition to IFRS, and as such, has worked with its counterparties
and lenders to ensure that any agreements that contain references to
Canadian GAAP financial statements are modified to allow for IFRS
statements. Based on the changes to ARC's accounting policies, no
issues are expected to arise with the existing wording of debt
covenants and related agreements as a result of the conversion to
IFRS. During the 2010 quarterly meetings held with its lenders, ARC
has provided an update on IFRS as it relates to ARC so that
management could adequately address any potential issues prior to
finalizing its IFRS accounting policy choices.
- IT systems - ARC has completed the accounting system updates required
in order to prepare 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 and E&E expenditures at a more
granular level of detail for IFRS reporting.
>>
Non-GAAP Measures
Management uses certain key performance indicators ('KPIs') and industry benchmarks such as operating income, operating netbacks ('netbacks'), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, normalized reserves per share and production per share, normalized dividend adjusted reserves per share and production per share, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability for ARC and provide investors with information that is commonly used by other oil and gas companies. 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 '2010 and 2011 Guidance and Financial Highlights' which contains guidance for 2011, the future expenditure plans and strategy for 2011 and expected production and operations under the heading 'Production', the expectations regarding the pricing of natural gas for 2011 under the heading 'Commodity Prices Prior to Hedging', the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia, the expected provincial royalty rates for 2011 under various commodity pricing outlooks for 2011 under the heading 'Operating Netbacks', the estimated future payments under the RSU & PSU Plan under the heading 'Long-term Incentive Plans - Restricted Share Units & Performance Share Units Plan, Stock Option Plan, and Deferred Share Unit Plan', the estimate of ARC as to when it expects to be in a material cash tax-paying position under the heading 'Taxes', the information as to total capital expenditures forecasted for 2011 under the heading 'Capital Expenditures and Net Acquisitions', the information relating to financing the 2011 capital expenditures under the heading: 'Capitalization, Financial Resources and Liquidity', ARC's estimates of normal course obligations under the heading 'Contractual Obligations and Commitments', the expectations related to the transition from Canadian GAAP to IFRS under the heading 'Financial Reporting Update' and 'First Time Adoption of IFRS', and a number of other matters, including 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; and future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures.
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.
<<
ANNUAL HISTORICAL REVIEW
-------------------------------------------------------------------------
For the year ended
December 31
(Cdn $ millions,
except per share
amounts) 2010 2009 2008 2007 2006
-------------------------------------------------------------------------
FINANCIAL
Revenue before
royalties 1,213.7 978.2 1,706.4 1,251.6 1,230.5
Per share(1) 4.59 4.16 7.90 5.95 6.02
Cash flow from
operating
activities(2) 673.9 497.4 944.4 704.9 734.0
Per share(1) 2.55 2.11 4.37 3.35 3.59
Net income 260.8 225.1 539.9 502.1 466.7
Per share(1) 0.99 0.96 2.50 2.39 2.27
Operating income(3) 244.2 181.2 557.0 495.6 475.5
Per share(1) 0.92 0.77 2.58 2.36 2.32
Distributions 313.5 298.5 570.0 498.0 484.2
Per unit(1) 1.20 1.28 2.67 2.40 2.40
Total assets 4,946.5 3,914.5 3,766.7 3,533.0 3,479.0
Total liabilities 1,752.1 1,540.1 1,624.6 1,491.3 1,550.6
Net debt outstanding(4) 872.7 902.4 961.9 752.7 739.1
Weighted average shares
(millions)(5) 264.2 235.4 216.1 210.4 205.1
Shares outstanding and
issuable (millions) 284.4 239.0 219.2 213.2 207.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 16.0 13.7 27.1 14.9 11.4
Land 60.9 7.0 122.4 77.5 32.4
Drilling and completions 358.5 214.3 305.4 229.5 240.5
Plant and facilities 131.4 110.0 90.4 72.1 77.6
Other capital 24.1 14.6 3.3 3.2 2.6
Total capital
expenditures 590.9 359.6 548.6 397.2 364.5
Property acquisitions
(dispositions), net 5.0 (20.5) 51.0 42.5 115.2
Corporate acquisitions(6) 652.1 178.9 - - 16.6
-------------------------------------------------------------------------
Total capital
expenditures and net
acquisitions 1,248.0 518.0 599.6 439.7 496.3
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,341 27,509 28,513 28,682 29,042
Natural gas (mmcf/d) 254.2 194.0 196.5 180.1 179.1
Natural gas liquids
(bbl/d) 4,245 3,689 3,861 4,027 4,170
Total (boe per day
6:1) 73,954 63,538 65,126 62,723 63,056
Average prices
Crude oil ($/bbl) 73.85 62.24 94.20 69.24 65.26
Natural gas ($/mcf) 4.21 4.18 8.58 6.75 6.97
Natural gas liquids
($/bbl) 53.98 40.67 69.71 54.79 52.63
Oil equivalent ($/boe) 44.88 42.07 71.25 54.54 53.33
-------------------------------------------------------------------------
RESERVES
(company interest)(7)
Proved plus probable
reserves
Crude oil and NGL
(mbbl) 166,553 153,413 153,020 158,341 162,193
Natural gas (bcf) 1,925.2 1,353.2 1,012.2 768.2 743.6
Total (mboe) 487,418 378,953 321,723 286,370 286,125
-------------------------------------------------------------------------
TRADING STATISTICS
(Cdn$, except volumes)
based on intra-day
trading
High 26.04 21.89 33.95 23.86 30.74
Low 18.77 11.73 15.01 18.90 19.20
Close 25.41 19.94 20.10 20.40 22.30
Average daily volume
(thousands) 1,197 1,057 975 597 706
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Per share amounts (with the exception of per unit distributions
which are based on the number of trust units outstanding at each
distribution record date) are based on diluted common 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) Operating income is a non-GAAP measure and is calculated using net
income less significant one-time items and items that are not
indicative of operating performance.
(4) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(5) Diluted common shares.
(6) Represents total consideration for corporate acquisitions including
fees but prior to working capital, asset retirement obligation and
future income tax liability assumed on acquisition.
(7) 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 share amounts) 2010
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 329.3 293.6 276.7 314.1
Per share(1) 1.16 1.10 1.09 1.25
Cash flow from operating
activities 186.2 166.2 162.8 158.7
Per share(1) 0.66 0.62 0.64 0.63
Net income (6.3) 81.0 45.4 140.7
Per share(1) (0.01) 0.30 0.18 0.56
Operating income(2) 50.4 53.0 55.8 84.9
Per share(1) 0.18 0.20 0.22 0.34
Distributions 82.8 80.3 75.3 75.0
Per unit(1) 0.30 0.30 0.30 0.30
Total assets 4,946.5 4,948.6 4,068.5 4,020.1
Total liabilities 1,751.1 1,689.0 1,384.3 1,322.4
Net debt outstanding(3) 872.6 871.1 728.8 677.8
Weighted average shares(4) 283.7 268.0 253.2 251.8
Shares outstanding and
issuable 284.4 283.1 253.6 252.8
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 5.6 0.2 3.6 6.6
Land 6.9 28.6 21.5 3.9
Drilling and completions 100.4 96.0 84.9 77.2
Plant and facilities 42.9 32.1 26.9 29.5
Other capital 3.3 2.6 7.1 11.1
Total capital expenditures 159.1 159.5 144.0 128.3
Property acquisitions
(dispositions), net 0.8 (2.1) - 6.3
Corporate acquisitions(5) - 652.1 - -
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 159.9 809.5 144.0 134.6
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,417 26,959 27,354 27,640
Natural gas (mmcf/d) 311.5 275.0 211.2 217.9
Natural gas liquids
(bbl/d) 5,355 4,690 3,655 3,252
Total (boe per day 6:1) 84,686 77,483 66,208 67,207
Average prices
Crude oil ($/bbl) 76.08 71.07 71.98 76.26
Natural gas ($/mcf) 3.83 3.79 4.12 5.42
Natural gas liquids
($/bbl) 55.10 49.13 53.02 60.33
Oil equivalent ($/boe) 42.18 41.14 45.82 51.85
-------------------------------------------------------------------------
TRADING STATISTICS
(Cdn$) based on intra-day
trading
High 26.04 20.95 22.33 22.49
Low 20.42 19.02 19.20 19.80
Close 25.41 20.55 19.73 20.50
Average daily volume
(thousands) 1,299 1,160 1,043 1,287
-------------------------------------------------------------------------
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except
per share amounts) 2009
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 278.6 239.2 235.2 225.2
Per share(1) 1.17 1.01 0.99 0.98
Cash flow from operating
activities 143.2 125.6 104.3 124.3
Per share(1) 0.60 0.53 0.44 0.54
Net income 66.2 69.6 66.8 22.5
Per share(1) 0.28 0.29 0.28 0.10
Operating income(2) 61.7 45.8 35.3 38.3
Per share(1) 0.26 0.19 0.15 0.17
Distributions 70.9 70.6 75.0 82.0
Per unit(1) 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(3) 902.4 705.4 737.6 781.5
Weighted average shares(4) 238.5 237.7 236.6 228.9
Shares outstanding and
issuable 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(5) 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
-------------------------------------------------------------------------
TRADING STATISTICS
(Cdn$) based on intra-day
trading
High 21.89 20.20 19.25 20.90
Low 19.06 15.48 14.12 11.73
Close 19.94 20.20 17.81 14.15
Average daily volume
(thousands) 963 1,038 988 1,240
-------------------------------------------------------------------------
(1) Per share amounts (with the exception of per unit distributions which
are based on the number of trust units outstanding at each
distribution record date) are based on diluted common shares.
(2) Operating income is a non-GAAP measure and is calculated using net
income less significant one-time items and items that are not
indicative of operating performance.
(3) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(4) Diluted common shares.
(5) Represents total consideration for corporate acquisitions including
fees but prior to working capital, asset retirement obligation and
future income tax liability assumed on acquisition.
CONSOLIDATED BALANCE SHEETS (unaudited)
As at December 31
(Cdn$ millions) 2010 2009
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 0.3 $ -
Accounts receivable (Note 7) 160.5 115.9
Prepaid expenses 12.0 18.2
Risk management contracts (Note 14) 66.8 5.9
Short term investment (Note 14) 3.5 -
Future income taxes (Note 16) - 7.1
-------------------------------------------------------------------------
243.1 147.1
Restricted cash (Note 6) 1.7 -
Reclamation funds (Note 8) 25.0 33.2
Risk management contracts (Note 14) 0.6 3.2
Property, plant and equipment (Note 9) 4,432.9 3,573.4
Goodwill (Note 5) 243.2 157.6
-------------------------------------------------------------------------
Total assets $ 4,946.5 $ 3,914.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 217.8 $ 166.7
Distributions payable 27.7 23.7
Risk management contracts (Note 14) 22.0 12.9
Future income taxes (Note 16) 6.0 -
-------------------------------------------------------------------------
273.5 203.3
Risk management contracts (Note 14) 20.9 1.0
Long-term debt (Note 11) 803.5 846.1
Long-term incentive compensation liability
(Note 20) 26.6 10.9
Other deferred liabilities (Note 22) 25.0 -
Asset retirement obligations (Note 12) 169.1 149.9
Future income taxes (Note 16) 433.5 328.9
-------------------------------------------------------------------------
Total liabilities 1,752.1 1,540.1
-------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 21)
SHAREHOLDERS' EQUITY
Unitholders' capital (Note 18) - 2,917.6
Shareholders' capital (Note 18) 3,194.5 -
Non-controlling interest (Note 17) - 36.0
Deficit (Note 19) - (578.6)
Accumulated other comprehensive loss (Note 19) (0.1) (0.6)
-------------------------------------------------------------------------
Total shareholders' equity 3,194.4 2,374.4
-------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 4,946.5 $ 3,914.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For three and twelve months ended December 31
Three Months Ended Twelve Months Ended
(Cdn$ millions, except per December 31 December 31
share amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and natural
gas liquids $ 329.3 $ 278.6 $1,213.7 $ 978.2
Royalties (47.0) (45.6) (192.8) (147.8)
-------------------------------------------------------------------------
282.3 233.0 1,020.9 830.4
Gain (loss) on risk
management contracts (Note 14)
Realized 20.0 (1.7) 65.4 19.4
Unrealized (85.9) 0.2 28.2 (7.7)
-------------------------------------------------------------------------
216.4 231.5 1,114.5 842.1
-------------------------------------------------------------------------
EXPENSES
Transportation 8.4 5.3 29.7 20.6
Operating 70.2 57.0 261.9 236.2
General and administrative 34.7 13.8 91.6 52.3
Provision for non-recoverable
accounts receivable - (1.3) - (1.7)
Interest and financing
charges (Note 11) 10.5 5.9 42.5 25.7
Depletion, depreciation and
accretion (Notes 9 and 12) 132.3 96.1 461.1 386.4
Gain on foreign exchange
(Note 15) (15.1) (9.7) (26.8) (70.0)
-------------------------------------------------------------------------
241.0 167.1 860.0 649.5
-------------------------------------------------------------------------
Gain on short term
investments (Note 14) - - 0.9 -
Capital and other taxes (0.1) (0.1) (0.2) (0.3)
Future income tax recovery
(Note 16) 18.4 1.9 5.6 32.8
-------------------------------------------------------------------------
Net income (loss) (6.3) 66.2 260.8 225.1
-------------------------------------------------------------------------
Net income (loss) attributable
to:
The Corporation (3.0) 65.5 260.8 222.8
Non-controlling interest
(Note 17) (3.3) 0.7 - 2.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) attributable
to the Corporation $ (3.0) $ 65.5 $ 260.8 $ 222.8
Deficit, beginning of period (545.4) (573.2) (578.6) (502.9)
Distributions paid or declared (82.9) (70.9) (313.5) (298.5)
Reduction of deficit in
accordance with Plan of
Arrangement (Note 1) 631.3 - 631.3 -
-------------------------------------------------------------------------
Deficit, end of period
(Note 19) $ - $ (578.6) $ - $ (578.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per share
(Note 18)
Basic $ (0.01) $ 0.28 $ 1.00 $ 0.96
Diluted $ (0.01) $ 0.28 $ 0.99 $ 0.96
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME (unaudited)
For Three and twelve months ended December 31
Three Months Ended Twelve Months Ended
December 31 December 31
(Cdn$ millions) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net income (loss) $ (6.3) $ 66.2 $ 260.8 $ 225.1
Other comprehensive income
(loss), net of tax(1)
Gains (losses) on financial
instruments designated as
cash flow hedges 0.5 (0.5) 0.5 (3.9)
Gains and losses on
financial instruments
designated as cash flow
hedges in prior periods
realized in net income
in the current period
(Note 14) (0.2) 0.3 0.1 1.1
Net unrealized gains on
available-for-sale
reclamation funds'
investments (0.1) - 0.1 0.3
Gains and losses on
financial instruments
designated as
available-for-sale
reclamation fund
investments in prior
periods realized in net
income in the current
period (Note 8) (0.2) - (0.2) -
-------------------------------------------------------------------------
Other comprehensive income
(loss)(2) - (0.2) 0.5 (2.5)
-------------------------------------------------------------------------
Comprehensive income (loss) $ (6.3) $ 66.0 $ 261.3 $ 222.6
-------------------------------------------------------------------------
Comprehensive (loss) income
attributable to:
The Corporation (3.0) 65.3 261.3 220.3
Non-controlling interest
(Note 17) (3.3) 0.7 - 2.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other comprehensive
(loss) income, beginning of
period (0.1) (0.4) (0.6) 1.9
Other comprehensive income
(loss)(2) - (0.2) 0.5 (2.5)
-------------------------------------------------------------------------
Accumulated other comprehensive
loss, end of period (Note 19) $ (0.1) $ (0.6) $ (0.1) $ (0.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts above are recorded net of a nominal amount of income taxes.
(2) Other comprehensive income attributable to non-controlling interest
is nominal.
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) 2010 2009 2010 2009
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income (loss) $ (6.3) $ 66.2 $ 260.8 $ 225.1
Add items not involving cash:
Future income tax recovery
(Note 16) (18.4) (1.9) (5.6) (32.8)
Depletion, depreciation and
accretion (Notes 9 and 12) 132.3 96.1 461.1 386.4
Non-cash loss (gain) on
risk management contracts
(Note 14) 85.9 (0.2) (28.2) 7.7
Non-cash gain on short term
investments (Note 14) - - (0.9) -
Non-cash lease inducement 1.9 - 6.6 -
Non-cash gain on foreign
exchange (14.9) (8.8) (26.8) (69.0)
Non-cash incentive
compensation expense
(Note 20) 22.1 4.7 13.6 0.6
Expenditures on site
restoration and reclamation
(Note 12) (2.7) (4.8) (7.8) (8.7)
Change in non-cash working
capital (13.7) (8.1) 1.1 (11.9)
-------------------------------------------------------------------------
186.2 143.2 673.9 497.4
-------------------------------------------------------------------------
CASH FLOWS FROM FINANCING
ACTIVITIES
(Repayment) issuance of
long-term debt under revolving
credit facilities, net 45.2 224.5 (241.3) (120.7)
Issue of Senior Notes - - 210.4 152.9
Repayment of Senior Notes (15.6) (6.3) (81.4) (18.9)
Issue of trust units, net of
issue costs 0.6 - 241.8 241.2
Cash distributions paid (59.5) (56.1) (237.1) (242.3)
Change in non-cash working
capital (4.8) (4.3) 0.8 1.6
-------------------------------------------------------------------------
(34.1) 157.8 (106.8) 13.8
-------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Corporate acquisition (Note 5) - (178.9) - (178.9)
Acquisition of petroleum and
natural gas properties (1.2) (1.1) (9.0) (11.8)
Proceeds on disposition of
petroleum and natural gas
properties 0.4 - 3.9 32.3
Capital expenditures (155.7) (116.5) (589.0) (359.4)
Net reclamation fund withdrawals
(contributions) (Note 8) 8.1 (1.5) 8.3 (4.6)
Change in restricted cash
(Note 6) 0.3 - 0.3 -
Change in non-cash working
capital (4.0) (3.0) 18.7 (28.8)
-------------------------------------------------------------------------
(152.1) (301.0) (566.8) (551.2)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS - - 0.3 (40.0)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 0.3 - - 40.0
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 0.3 $ - $ 0.3 $ -
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
>>
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
December 31, 2010 and 2009
(all tabular amounts in Cdn$ millions, except per share amounts)
1. STRUCTURE OF THE BUSINESS
The principal undertakings of ARC Resources Ltd., its predecessor ARC Energy Trust and its subsidiaries, (the 'Corporation' or 'ARC'), are to carry on the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets.
On December 31, 2010, ARC Energy Trust (the 'Trust') effectively completed its conversion from an income trust to a corporation pursuant to the Plan of Arrangement (the 'Arrangement') under Section 193 of the Business Corporations Act (Alberta) that was approved by securityholders at the Joint Special Meeting of Securityholders of ARC Energy Trust and ARC Resources Ltd. on December 15, 2010. The Trust was dissolved and the Corporation, together with its subsidiaries, received all of the assets and assumed all of the liabilities of the Trust. Unitholders of the Trust received one common share of the Corporation for each trust unit held. Exchangeable shareholders received common shares of the Corporation on the same basis as the holders of Trust Units based on the number of Trust Units into which each exchangeable share would be exchangeable into on December 31, 2010. The Board of Directors and senior management of the Trust continued as the Board of Directors and senior management of ARC.
In connection with the Arrangement, ARC assumed all of the obligations of the Trust in respect of Restricted Trust Units ('RTU's') and Performance Trust Units ('PTU's') outstanding under the Long Term Incentive Plan. The Arrangement did not result in the acceleration of vesting of any such awards. Upon vesting, holders of RTU's and PTU's are entitled to receive cash payments on the same terms and conditions that existed prior to the Arrangement except that such cash payments will be based upon the market value of ARC common shares, as adjusted for dividends, rather than upon the market value of the Trust Units, as adjusted for distributions.
Pursuant to the Arrangement, shareholders' capital was reduced by $631.3 million, the amount necessary to eliminate the deficit of the Trust outstanding at the time of the Arrangement.
The Arrangement has been accounted for as a continuity of interests and accordingly, the consolidated financial statements for periods prior to the effective date of the Arrangement reflect the financial position, income and cash flows as if the Corporation had always carried on the business formerly conducted by the Trust. In these and future financial statements ARC will refer to common shares, shareholders and dividends which were formerly referred to as trust units, unitholders and distributions under the trust structure. Comparative amounts in these and future financial statements will reflect the history of the Trust.
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 plant 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 Corporation' or 'ARC' throughout these Consolidated Financial Statements refers to the Corporation 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.
>>
Share Based Compensation
ARC has established a long term incentive plan ('RSU & PSU Plan') for employees, independent directors and long-term consultants who otherwise meet the definition of an employee of ARC. Compensation expense associated with the RSU & PSU Plan is granted in the form of Restricted Share Units ('RSUs') and Performance Share Units ('PSUs') (formerly RTUs and PTUs) and is determined based on the intrinsic value of the RSUs and PSUs at each period end. The intrinsic valuation method is used as participants of the RSU & PSU Plan receive a cash payment on a fixed vesting date. This valuation incorporates the period end share price, the number of RSUs and PSUs 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 share price. In addition, compensation expense is amortized and recognized in earnings over the vesting period of the RSU & PSU 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 recognizes actual forfeitures of RSUs and PSUs as they occur.
Cash Equivalents
Cash equivalents include market deposits and similar type instruments, with an original maturity of three months or less when purchased.
Reclamation Fund
The Reclamation fund holds investment grade assets and cash and cash equivalents. Investments are categorized as available-for-sale assets, which are initially measured at fair value and are subsequently measured at fair value with changes in fair value recognized in other comprehensive income, net of tax.
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. The market interest rate is used to determine 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 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 the recording of future income tax assets and liabilities.
Net Income per Share
Basic net income per share is computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted net income per share amounts are calculated based on net income divided by diluted shares.
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.
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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, restricted cash and short term investments are also classified as held-for-trading.
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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 fund assets as available-for-sale asset.
<<
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, long-term debt and long term incentive compensation liabilities as 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.
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.
3. CHANGE IN ACCOUNTING POLICY
In 2010, ARC early adopted Canadian Institute of Chartered Accountants ('CICA') Handbook Section 1582 'Business Combinations', which replaces Section 1581 of the same name. Under this standard, the purchase price of a business combination is based on the fair value of consideration exchanged at the acquisition date and any contingent consideration of the acquisition is to be recognized at fair value at the acquisition date and subsequently re-measured at fair value with changes recorded through earnings each period until settled. In addition, this new guidance generally requires all transaction costs to be expensed through the income statement and any negative goodwill is required to be recognized immediately into earnings. This standard has been applied prospectively to record ARC's business combination with Storm Exploration Inc. ('Storm') as described in Note 5 of these financial statements.
In accordance with the transitional provisions contained within CICA Handbook Section 1582, ARC has at the same time as its adoption of Section 1582, adopted CICA Handbook Sections 1601 and 1602, which together replace CICA Handbook Section 1600, 'Consolidated Financial Statements', as described below:
Section 1601 'Consolidated Financial Statements' establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard did not have any impact on ARC's consolidated financial statements.
Section 1602 'Non-Controlling Interests' establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. Upon adoption of this standard, ARC has reclassified its non-controlling interest to equity on its consolidated balance sheet and presented its net income and other comprehensive income attributable to itself and its non-controlling interest on a retrospective basis.
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. 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.
The above CICA Handbook Sections are converged with IFRS.
4. NEW ACCOUNTING POLICIES
Future Accounting Changes
International Financial Reporting Standards ('IFRS')
In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without modification, for all financial periods beginning January 1, 2011. The transition to IFRS at January 1, 2011 requires the restatement, for comparative purposes, of amounts reported by ARC for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.
5. CORPORATE ACQUISITIONS
On August 17, 2010, ARC acquired 100 per cent of the existing and outstanding common shares of Storm Exploration Inc. ('Storm') for total consideration of $652.1 million, including the assumption of approximately $96.7 million of Storm bank debt. Storm is a petroleum and natural gas company holding assets that are a strategic fit with ARC's existing asset portfolio. The primary assets acquired are in close proximity to ARC's Dawson field and the goodwill recognized on acquisition is primarily attributed to the expected future cash flows to be derived from synergies which will contribute to operational efficiencies.
The acquisition was settled with the issuance of approximately 23 million trust units and 1.9 million exchangeable shares and was recognized as a business combination in accordance with CICA Handbook Section 1582. The allocation of the components of total consideration to the net assets acquired is as follows:
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Net Assets Acquired
-------------------------------------------------------------------------
Property, plant and equipment $ 712.7
Short term investment (Note 14) 2.9
Risk management contracts 0.7
Goodwill 85.6
Net working capital deficiency (3.3)
Office lease obligation (1.2)
Asset retirement obligations (15.0)
Future income tax liability (130.3)
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Total net assets acquired $ 652.1
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Consideration
Trust units issued (23,003,154 units) $ 449.2
Exchangeable Shares issued (1,924,997 exchangeable shares)(1) 106.2
Bank debt (net of cash acquired) 96.7
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Total consideration paid $ 652.1
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(1) At acquisition date, 1,924,997 ARL Series B exchangeable shares were
issued at an average exchange ratio of 2.82551, for total trust unit
equivalent of 5,439,098 units. See Note 17, 'Exchangeable Shares and
Non-Controlling Interest' for further information.
>>
ARC has recorded $0.8 million of applicable transaction costs to general and administrative expenses on the Consolidated Statements of Income and Deficit. The net working capital deficiency acquired includes $7.2 million of trade accounts receivable, all of which were considered to be collectable at the time of the acquisition and $13.5 million of accounts payable and accrued liabilities. ARC has not recognized any goodwill impairment losses from acquisition date to December 31, 2010.
These Consolidated Financial Statements incorporate the results of operations of the acquired Storm properties from August 17, 2010. For the year ended December 31, 2010, ARC recorded revenue from oil, natural gas and natural gas liquids of $34.3 million and a net loss of $1.4 million in respect of the acquired assets. Had the acquisition occurred on January 1, 2010, for the year ended December 31, 2010, ARC estimates that its pro forma revenues and net income would have been approximately $1,289.3 million and $251.2 million, respectively.
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:
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Net Assets Acquired
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Property, plant and equipment $ 231.0
Asset retirement obligations (4.0)
Future income taxes (48.1)
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Total net assets acquired $ 178.9
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Consideration Paid
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Cash and fees paid $ 178.9
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Total consideration paid $ 178.9
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>>
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.
6. RESTRICTED CASH
Restricted cash at December 31, 2010 represents amounts received from a government agency to fund certain future capital expenditures of the Corporation. If qualifying expenditures under the funding agreement are not made prior to June 30, 2012, any undrawn cash plus interest accrued to date must be repaid. During the year ended December 31, 2010, ARC made $0.3 million of such qualifying expenditures and corresponding withdrawals from the restricted cash balance.
7. 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, short term investments, accounts receivable, reclamation fund, 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:
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- By entering into sales contracts with only established creditworthy
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, 2010 pertains to accrued revenue for December 2010 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, 2010, 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.
ARC's allowance for doubtful accounts was nil as at December 31, 2010 and $0.8 million as at December 31, 2009. ARC did not record any additional provision for non-collectable accounts receivable during the years ended December 31, 2010 and 2009.
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, 2010, $2.1 million of accounts receivable are past due, excluding amounts in ARC's allowance for doubtful accounts, all of which are considered to be collectable.
Maximum credit risk is calculated as the total recorded value of cash and cash equivalents, accounts receivable, short term investments, reclamation fund holdings, and risk management contracts at the balance sheet date.
8. RECLAMATION FUNDS
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December 31, December 31,
2010 2009
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Un- Un-
restricted Restricted restricted Restricted
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Balance, beginning of year $ 12.6 $ 20.6 $ 11.2 17.0
Contributions 8.2 5.8 6.2 5.3
Reimbursed expenditures(1) (7.4) (1.5) (5.9) (1.8)
Interest earned on funds 0.4 0.2 0.7 0.1
Withdrawals (14.0) - - -
Net unrealized gains and
losses on available-for-
sale investments 0.2 (0.1) 0.4 -
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Balance, end of year(2) $ - $ 25.0 $ 12.6 20.6
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(1) Amount differs from actual expenditures incurred by ARC due to timing
differences and discretionary reimbursements.
(2) As at December 31, 2010 the restricted reclamation fund held $0.3
million in cash and cash equivalents (the unrestricted fund held $0.2
million at December 31, 2009), with the balance held in investment
grade assets.
>>
ARC has established a restricted reclamation fund to finance obligations specifically associated with the Redwater property. Required contributions to this fund will vary over time and have been disclosed as commitments in Note 21. Interest earned on the respective investments is retained within the fund.
All investments in the unrestricted fund were withdrawn and applied to outstanding bank debt. Future abandonment expenditures will be funded entirely from cash flow from operating activities.
For the year ended December 31, 2010, $0.2 million (nominal in 2009) relating to available-for-sale reclamation fund assets were reclassified from accumulated other comprehensive income into earnings. At December 31, 2010 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.
9. PROPERTY, PLANT AND EQUIPMENT
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December 31, December 31,
2010 2009
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Property, plant and equipment, at cost $ 7,553.6 $ 6,242.8
Accumulated depletion and depreciation (3,120.7) (2,669.4)
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Property, plant and equipment, net $ 4,432.9 $ 3,573.4
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The calculation of 2010 depletion and depreciation included an estimated $1,514 million ($1,060 million in 2009) for future development costs associated with proved undeveloped reserves and excluded $354.2 million ($268.9 million in 2009) for the book value of unproved properties.
ARC performed a ceiling test calculation at December 31, 2010 to assess the recoverable value of property, plant and equipment ('PP&E'). Based on the calculation, the value of future net revenues from ARC's reserves exceeded the carrying value of ARC's PP&E at December 31, 2010. The benchmark prices used in the calculation were as follows:
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Cdn$/US$
WTI Oil AECO Gas Exchange
Year (US$/bbl) (Cdn$/mmbtu) Rates
-------------------------------------------------------------------------
2011 88.00 4.16 0.98
2012 89.00 4.74 0.98
2013 90.00 5.31 0.98
2014 92.00 5.77 0.98
2015 95.17 6.22 0.98
2016 97.55 6.53 0.98
2017 100.26 6.76 0.98
2018 102.74 6.90 0.98
2019 105.45 7.06 0.98
2020 107.56 7.21 0.98
Remainder(1) 2.0% 2.0% 0.98
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(1) Percentage change represents the change in each year after 2020 to
the end of the reserve life.
>>
For the years ended December 31, 2010 and 2009, $20.9 million and $14.2 million of general and administrative expenses were capitalized to property, plant and equipment, respectively.
10. FINANCIAL LIABILITIES AND LIQUIDITY RISK
Liquidity risk is the risk that ARC will not be able to meet its financial obligations as they become due. ARC actively manages its liquidity through strategies such as continuously monitoring forecasted and actual cash flows from operating, financing and investing activities, available credit under existing banking arrangements and opportunities to issue additional equity. Management believes that future cash flows generated from these sources will be adequate to settle ARC's financial liabilities.
The following table details ARC's financial liabilities as at December 31, 2010:
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2 - 3 4 - 5 Beyond 5
($ millions) 1 year years years years Total
-------------------------------------------------------------------------
Accounts payable and accrued
liabilities(1) 222.9 - - - 222.9
Distributions payable(2) 20.3 - - - 20.3
Risk management contracts(3) 27.7 22.6 0.1 1.4 51.8
Senior notes and interest 41.5 125.5 119.4 318.7 605.1
Revolving credit facilities - 357.7 - - 357.7
Working capital facility 1.3 - - - 1.3
Accrued long-term incentive
compensation(1) - 53.1 - - 53.1
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Total financial liabilities 313.7 558.9 119.5 320.1 1,312.2
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(1) Liabilities under the RSU & PSU Plan represent the total amount
expected to be paid out on vesting.
(2) Amounts payable for the distribution represent the net cash payable
after distribution reinvestment.
(3) Amounts payable under risk management contracts have been presented
at their future value without any reduction for entity-specific risk.
>>
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 11 for further details on available amounts under existing banking arrangements and Note 13 for further details on capital management.
11. LONG-TERM DEBT
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December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Syndicated credit facilities:
Cdn$ denominated $ 357.7 $ 423.0
US$ denominated - 74.3
Working capital facility 1.3 7.9
Senior notes:
Master Shelf Agreement
5.42% US$ Note 65.3 78.5
4.94% US$ Note - 6.3
4.98% US$ Note 49.7 -
2004 Note Issuance
4.62% US$ Note 25.5 54.5
5.10% US$ Note 23.9 65.4
2009 Note Issuance
7.19% US$ Note 67.1 70.6
8.21% US$ Note 34.8 36.6
6.50% Cdn$ Note 29.0 29.0
2010 Note Issuance
5.36% US$ Note 149.2 -
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Total long-term debt outstanding $ 803.5 $ 846.1
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Credit Facilities
ARC has a $1 billion, annually extendible, financial covenant-based syndicated credit facility ('the facility'). The maturity date of the facility is August 3, 2013. ARC also has in place a $30 million demand working capital facility. The working capital facility is subject to the same covenants as the syndicated credit facility.
Borrowings under the facility bear interest at Canadian bank prime (3 per cent at December 31, 2010, 2.25 per cent at December 31, 2009) or US base rate, or, at ARC's option, Canadian dollar bankers' acceptances or U.S. dollar LIBOR loan rates, plus applicable margin and stamping fee. The total stamping fees range between 100 bps and 250 bps on Canadian bank prime and US base rate borrowings and between 200 bps and 350 bps on Canadian dollar bankers' acceptance and U.S. dollar LIBOR borrowings. The undrawn portion of the facility is subject to a standby fee in the range of 50 to 87.5 bps.
During the fourth quarter of 2010, the weighted average interest rate under the credit facility was 3.3 per cent (0.9 per cent for the fourth quarter of 2009) and 1.9 per cent for the year ended December 31, 2010 (1.1 per cent for the year ended 2009).
In the second quarter of 2010, ARC amended its note agreements with its lenders to remove security on its senior notes outstanding and as a result all senior notes outstanding are unsecured.
Senior 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 notes are summarized below.
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Remaining Coupon Maturity Principal Payment
Issue Date Principal Rate Date Terms
-------------------------------------------------------------------------
December 15, US$65.6 million 5.42% December 15, Eight equal
2005 2017 installments
beginning
December 15, 2010
March 5, 2010 US$50.0 million 4.98% March 5, Five equal
2019 installments
beginning March 5,
2015
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>>
Senior Notes not Subject to the Master Shelf Agreement
In the first quarter of 2010, ARC elected to prepay US$58.5 million of outstanding principal on its 2004 Note Issuance. A make whole payment of US$4.8 million was made in conjunction with the note prepayment and is classified as interest and financing charges on the statement of income. The amendment to the 2004 Note agreements was made to align the key provisions in all outstanding senior note agreements.
The senior notes not subject to the Master Shelf Agreement were issued on April 27, 2004, April 14, 2009, and May 27, 2010 via private placements. The terms and rates of these senior notes are summarized below.
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-------------------------------------------------------------------------
Remaining Coupon Maturity Principal Payment
Issue Date Principal Rate Date Terms
-------------------------------------------------------------------------
April 27, US$25.7 million 4.62% April 27, Six equal
2004 2014 installments
beginning
April 27, 2009
April 27, US$24.0 million 5.10% April 27, Five equal
2004 2016 installments
beginning
April 27, 2012
April 14, US$67.5 million 7.19% April 14, Five equal
2009 2016 installments
beginning
April 14, 2012
April 14, US$35.0 million 8.21% April 14, Five equal
2009 2021 installments
beginning
April 14, 2017
April 14, Cdn $29.0 million 6.5% April 14, Five equal
2009 2016 installments
beginning
April 14, 2012
May 27, US$150.0 million 5.36% May 27, Five equal
2010 2022 installments
beginning May 27,
2018
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Credit Capacity
The following table summarizes ARC's available credit capacity and the current amounts drawn as at December 31, 2010:
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-------------------------------------------------------------------------
Credit
Capacity Drawn Remaining
-------------------------------------------------------------------------
Syndicated Credit Facility $ 1,000.0 $ 357.7 $ 642.3
Working Capital Facility 30.0 1.3 28.7
Senior Notes Subject to a
Master Shelf Agreement(1) 223.8 115.0 108.8
Senior Notes Not Subject to
a Master Shelf Agreement 329.5 329.5 -
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Total $ 1,583.3 $ 803.5 $ 779.8
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(1) Total credit capacity is US$225 million.
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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 shareholders' 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 per cent for the subsequent six month period. As at December 31, 2010, ARC had $3.1 million in letters of credit (two million dollars in 2009), no subordinated debt, and was in compliance with all covenants.
Supplemental disclosures
The fair value of all senior notes as at December 31, 2010, is $468.1 million compared to a carrying value of $444.5 million ($347.3 million compared to $340.9 million as at December 31, 2009).
Amounts of US$15.8 million due under the senior notes and $1.3 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 these amounts through the syndicated credit facility.
Interest paid during the fourth quarter of 2010 was $0.1 million more than the interest expense (interest paid during the fourth quarter of 2009 was $2.6 million more than the interest expense). Interest paid in 2010 was $10 million less than the interest expense (interest paid in 2009 was $3.6 million less than the interest expense).
12. 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 $169.1 million as at December 31, 2010 ($149.9 million in 2009) based on a total future undiscounted liability of $1.48 billion ($1.36 billion in 2009). At December 31, 2010 management estimates that these payments are expected to be made over the next 61 years with the majority of payments being made in years 2060 to 2071. ARC's weighted average credit adjusted risk free rate of 6.5 per cent (6.5 per cent in 2009) and an inflation rate of two per cent (two per cent in 2009) were used to calculate the present value of the asset retirement obligations.
The following table reconciles ARC's asset retirement obligations:
<<
-------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Balance, beginning of year $ 149.9 $ 141.5
Increase in liabilities relating to
corporate acquisitions (Note 5) 15.0 4.0
Increase in liabilities relating to development
activities 1.6 1.7
Increase in liabilities relating to change
in estimate 0.5 2.1
Settlement of abandonment and reclamation
liabilities during the year (7.8) (8.7)
Accretion expense 9.9 9.3
-------------------------------------------------------------------------
Balance, end of year $ 169.1 $ 149.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
13. CAPITAL MANAGEMENT
ARC's objective 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;
and
- Maintain a dividend policy 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.
>>
ARC manages the following capital:
<<
- Common 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, 2010 ARC's net debt to annualized cash flow from operating activities ratio is 1.3 and its net debt to total capitalization ratio is 10.8 per cent.
<<
-------------------------------------------------------------------------
($ millions, except per share December 31, December 31,
and per cent amounts) 2010 2009
-------------------------------------------------------------------------
Long-term debt 803.5 846.1
Accounts payable and accrued liabilities 217.8 166.7
Distributions payable 27.7 23.7
Cash and cash equivalents, accounts
receivable, prepaid expenses and
short term investments (176.3) (134.1)
-------------------------------------------------------------------------
Net debt obligations(1) 872.7 902.4
-------------------------------------------------------------------------
Shares outstanding (millions) 284.4 239.0
Share price(2) 25.41 19.94
-------------------------------------------------------------------------
Market capitalization(1) 7,226.6 4,765.7
Net debt obligations(1) 872.7 902.4
-------------------------------------------------------------------------
Total capitalization(1) 8,099.3 5,668.1
-------------------------------------------------------------------------
Net debt as a percentage of total
capitalization 10.8% 15.9%
Net debt obligations to annualized
cash flow from operating activities 1.3 1.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net debt obligations, market capitalization 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 closing price as at December 31, 2010 and December 31, 2009
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 shares, new debt or changing its dividend 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, 2010 ARC is in compliance with all covenants.
14. FINANCIAL INSTRUMENTS AND MARKET RISK MANAGEMENT
Financial Instrument Classification and Measurement
ARC's financial instruments are carried on the Consolidated Balance Sheet at amortized cost with the exception of cash and cash equivalents, restricted cash, short term investments, reclamation fund assets and risk management contracts, which are carried at fair value. With the exception of ARC's senior notes, there were no significant differences between the carrying value of financial instruments and their estimated fair values as at December 31, 2010. The fair value of the ARC's senior notes is disclosed in Note 11.
All of ARC's cash and cash equivalents, restricted cash, short term investments, risk management contracts, and reclamation fund assets 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, restricted cash, reclamation fund assets and risk management contracts have been assessed on the fair value hierarchy described above. ARC's cash and cash equivalents, restricted cash 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.
Pursuant to the Storm acquisition (Note 5), ARC acquired shares in Storm Resources Ltd. at an initial cost of $2.9 million. The short term investment is classified as held for trading and is presented at fair value with any periodic change in fair value being recorded as an unrealized gain or loss in the Consolidated Statements of Income and Deficit. At December 31, 2010, the fair value of ARC's investment in Storm Resources Ltd. was $3.5 million and an unrealized gain of $0.6 million was recorded for the period August 17 to December 31, 2010. ARC classifies this investment as Level 1 in the fair value hierarchy.
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 contracts 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 relative to the U.S. dollar and the West Texas Intermediate ('WTI') posted crude oil price.
Commodity Price Risk
ARC's operational results and financial condition are largely dependent on the commodity prices received for its 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 ARC's net income.
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, 2010. The sensitivity is based on a 10 per cent increase and 10 per cent decrease in the price of WTI and 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, 2010 and ARC's next reporting date.
<<
-------------------------------------------------------------------------
Sensitivity of Commodity Price Risk Management Contracts:
-------------------------------------------------------------------------
Increase in Commodity Price Decrease in Commodity Price
-------------------------------------------------------------------------
Crude oil Natural gas Crude oil Natural gas
-------------------------------------------------------------------------
Net income
(decrease)
increase (86.1) (12.7) 80.8 14.6
-------------------------------------------------------------------------
>>
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. Changes in interest rates could also result in fair value risk on ARC's fixed rate senior notes. Fair value risk of the senior notes is mitigated due to the fact that ARC generally does not intend to settle its fixed rate debt prior to maturity.
If interest rates applicable to variable rate debt and interest rate swaps were to have increased by 50 bps it is estimated that ARC's net income for the year ended December 31, 2010 would decrease by $2.2 million, of which $1.4 million is the result of increased interest expense and $0.8 million is due to the change in fair value of risk management contracts in place at December 31, 2010. Management does not expect interest rates to decrease between December 31, 2010 and ARC's next reporting date.
Foreign Exchange Risk
North American oil and natural gas prices are based upon U.S. dollar denominated commodity prices. As a result, the price received by Canadian producers is affected by the Canadian/U.S. dollar exchange rate that may fluctuate over time. In addition ARC has U.S. dollar denominated debt and interest obligations of which future cash repayments are directly impacted by the exchange rate in effect on the repayment date.
The following table demonstrates the effect of exchange rate movements on net income due to changes in the fair value of risk management contracts in place at December 31, 2010 as well as the unrealized gain or loss on revaluation of outstanding US$ denominated debt. The sensitivity is based on a 5 per cent increase and 5 per cent decrease in the Cdn$/US$ foreign exchange rate.
<<
-------------------------------------------------------------------------
Sensitivity of Foreign Exchange Exposure: Increase in Decrease in
Cdn$/US$ Cdn$/US$
rate rate
-------------------------------------------------------------------------
Risk management contracts $ 2.1 $ (2.1)
U.S. dollar denominated debt (15.6) 15.6
-------------------------------------------------------------------------
Net income (decrease) increase $ (13.5) $ 13.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Increases and decreases in foreign exchange rates applicable to U.S. dollar denominated payables and receivables would have a nominal impact on ARC's net income for the period ended December 31, 2010.
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, 2010 that do not qualify for hedge accounting. All contracts call for monthly average settlement unless otherwise noted:
<<
-------------------------------------------------------------------------
Financial WTI Crude Oil Contracts
-------------------------------------------------------------------------
Bought
Volume Put Sold Put Sold Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl(1)
-------------------------------------------------------------------------
1-Jan-11 31-Dec-11 3-way collar 5,000 $80.00 $60.00 $100.00
1-Jan-11 31-Dec-11 Collar 8,000 $85.00 - $85.00
1-Jan-11 31-Dec-11 3-way collar 5,000 $85.00 $60.00 $85.00
1-Jan-12 31-Dec-12 Collar 1,000 $90.00 - $90.00
1-Jan-12 31-Dec-12 3-way collar 5,000 $90.00 $60.00 $90.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Annually settled call
-------------------------------------------------------------------------
Financial WTI Crude Oil Swap Contracts
-------------------------------------------------------------------------
Volume
Term Contract bbl/d US$/bbl
-------------------------------------------------------------------------
1-Jan-12 31-Dec-12 Sold Swap 10,000 $90.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial CWTI Crude Oil Contracts
-------------------------------------------------------------------------
Bought
Volume Put Sold Put Sold Call
Term Contract bbl/d Cdn$/bbl Cdn$/bbl Cdn$/bbl(2)
-------------------------------------------------------------------------
1-Jan-11 31-Dec-11 3-way collar 2,000 $90.00 $65.00 $90.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(2) Annually settled call
-------------------------------------------------------------------------
Financial WTI Crude Oil Calendar Spread Contracts(3)
-------------------------------------------------------------------------
Volume Spread
Term Contract bbl/d US$/bbl
-------------------------------------------------------------------------
1-Jan-11 31-Dec-11 1st vs 2nd 2,000 ($0.07)
month
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(3) ARC pays the prompt contract monthly average; ARC receives the second
delivery month contract average plus the calendar spread
-------------------------------------------------------------------------
Financial AECO Natural Gas Swap Contracts(4)
-------------------------------------------------------------------------
Volume
Term Contract GJ/d Cdn$/GJ
-------------------------------------------------------------------------
1-Jan-11 31-Dec-11 Sold Swap 135,000 $5.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(4)AECO 7a monthly index
-------------------------------------------------------------------------
Financial NYMEX Natural Gas Swap Contracts(5)
-------------------------------------------------------------------------
Volume
Term Contract mmbtu/d US$/mmbtu
-------------------------------------------------------------------------
1-Jan-12 31-Dec-12 Sold Swap 20,000 $5.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(5) Last Day Settlement
-------------------------------------------------------------------------
Financial Basis Swap Contract(6)
-------------------------------------------------------------------------
Volume
Term Contract mmbtu/d US$/mmbtu
-------------------------------------------------------------------------
1-Jan-11 31-Oct-11 Sold Swap 15,000 ($0.4850)
- L3d
1-Jan-11 31-Dec-12 Sold Swap 30,000 ($0.6067)
- Ld
1-Nov-11 31-Oct-12 Sold Swap 15,000 ($0.4067)
- L3d
1-Jan-12 31-Dec-12 Sold Swap 20,000 ($0.4850)
- Ld
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(6) Nymex Last Day (Ld) or Last 3 Day (L3d); AECO 7a monthly index
-------------------------------------------------------------------------
US$ Debt Repayment Contracts
-------------------------------------------------------------------------
Settlement Notional Swap Swap
Date Contract US$ millions Cdn$/US$ US$/Cdn$
-------------------------------------------------------------------------
14-Apr-11 Forward 3.9 $1.0225 $0.9780
27-Apr-11 Forward 7.6 $1.0229 $0.9776
27-May-11 Forward 4.0 $1.0182 $0.9821
6-Sep-11 Forward 1.3 $1.0212 $0.9792
14-Oct-11 Forward 3.9 $1.0224 $0.9781
25-Nov-11 Forward 4.0 $1.0189 $0.9815
12-Apr-12 Forward 17.4 $1.0150 $0.9852
27-Apr-12 Forward 12.3 $1.0150 $0.9852
29-May-12 Forward 4.0 $1.0150 $0.9852
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Interest Rate Contracts(7)
-------------------------------------------------------------------------
Principal
US$ Fixed Floating
Term Contract millions Rate Rate
-------------------------------------------------------------------------
1-Jan-11 22-May-22 Swap 25.0 5.36% LIBOR + 2.09%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(7) Receive fixed rate; pay floating rate
-------------------------------------------------------------------------
Financial Electricity Heat Rate Contracts(8)
-------------------------------------------------------------------------
Heat
Volume AESO Power AECO 5a multiplied Rate
Term Contract MWh Cdn$/MWh Cdn$/GJ by GJ/MWh
-------------------------------------------------------------------------
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-12 swap 15 AESO 5a x 9.10
1-Jan-13 Heat rate Receive Pay AECO
31-Dec-13 swap 10 AESO 5a x 9.15
-------------------------------------------------------------------------
(8) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index
-------------------------------------------------------------------------
Financial Electricity Contracts(9)
-------------------------------------------------------------------------
Volume Swap
Term Contract MWh Cdn$/MWh
-------------------------------------------------------------------------
1-Jan-11 31-Dec-12 Bought Swap 5 $72.50
-------------------------------------------------------------------------
(9) Alberta Power Pool (monthly average 24x7)
>>
At December 31, 2010 there were no contracts in place that have been designated as accounting hedges.
At December 31, 2010, the fair value of the contracts that were not designated as accounting hedges was $24.6 million. ARC recorded a gain on risk management contracts of $93.6 million in the statement of income for the year ended December 31, 2010 ($11.7 million gain in 2009). 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,
2010 2009
-------------------------------------------------------------------------
Fair value, beginning of year $ (4.3) $ 3.4
Fair value, end of year(1) 24.6 (4.3)
-------------------------------------------------------------------------
Change in fair value of contracts in the year 28.9 (7.7)
Fair value of contracts acquired in
Corporate Acquisition (Note 5) (0.7) -
Realized gain in the year 65.4 19.4
-------------------------------------------------------------------------
Gain on risk management contracts $ 93.6 $ 11.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a gain of $16.8 million at
December 31, 2010 ($3.5 million loss at December 31, 2009).
>>
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 $0.5 million for the year ended December 31, 2010 (loss of $1.5 million in 2009) has been included in operating costs on the statement of income.
The contracts that were designated as effective accounting hedges were expired at December 31, 2010, therefore the unrealized fair value relating to these contracts is nil. The fair value movement of $0.5 million represents amounts previously recorded to Other Comprehensive Income, net of tax, that have since been charged to the statement of income. The following table reconciles the movement in the fair value of ARC's financial risk management contracts that were designated as effective accounting hedges:
<<
-------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Fair value, beginning of year $ (0.5) $ 3.3
Change in fair value of financial
electricity contracts 0.5 (3.8)
-------------------------------------------------------------------------
Fair value, end of year(1) $ - $ (0.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Intrinsic value of risk management contracts designated as effective
accounting hedges equals nil at December 31, 2010 ($0.5 million loss
at December 31, 2009).
>>
15. GAIN (LOSS) ON FOREIGN EXCHANGE
The following is a summary of the total gain (loss) on US$ denominated transactions:
<<
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Unrealized gain (loss) on
US$ denominated debt $ 10.3 $ 5.7 $ (6.0) $ 66.3
Realized gain on US$
denominated debt
repayments 4.6 3.1 32.9 2.7
-------------------------------------------------------------------------
Total non-cash gain on
US$ denominated
transactions 14.9 8.8 26.9 69.0
Realized cash gain (loss)
on US$ denominated
transactions 0.2 0.9 (0.1) 1.0
-------------------------------------------------------------------------
Total foreign exchange
gain $ 15.1 $ 9.7 $ 26.8 $ 70.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
16. INCOME TAXES
On December 31, 2010, the Corporation effectively converted from a publicly traded income trust to a publicly traded corporation by way of a plan of arrangement (see Note 1). As a result, for the year ended December 31, 2010, the Corporation's future income tax recovery was calculated on the basis of it being a corporation. For the year ended December 31, 2009, the Corporation's future income tax recovery was calculated on the basis of it being a publicly traded income trust in accordance with legislation applicable to certain income trusts.
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,
2010 2009
-------------------------------------------------------------------------
Income before future income tax recovery
and non-controlling interest $ 255.2 $ 192.3
-------------------------------------------------------------------------
Canadian statutory rate(1) 28.0% 29.0%
-------------------------------------------------------------------------
Expected income tax expense at
statutory rates 71.4 55.8
Effect on income tax of:
Net income of ARC Energy Trust (75.5) (86.0)
Effect of change in corporate tax rate (0.8) 7.2
Unrealized loss (gain) on foreign exchange 0.8 (9.7)
Change in estimated pool balances (0.2) (0.7)
Other non-deductible items (1.3) 0.6
-------------------------------------------------------------------------
Future income tax recovery $ (5.6) $ (32.8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The statutory rate consists of the combined statutory tax rate for
the Corporation and its subsidiaries for the year ended December 31,
2010 and the combined statutory tax rate for the Trust and its
subsidiaries for the year ended December 31, 2009.
The net future income tax liability is comprised of the following:
-------------------------------------------------------------------------
December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 553.0 $ 418.3
Risk management contracts 11.2 -
Long-term debt 7.7 8.5
Future tax assets:
Asset retirement obligations (42.3) (37.6)
Non-capital losses (54.0) (49.9)
Risk management contracts (5.1) (1.1)
Other comprehensive loss - (0.1)
Share/Trust unit incentive compensation
expense (12.0) (8.2)
Attributed Canadian royalty income (4.5) (4.5)
Make whole payment (1.0) -
CEC, SR&ED pools and deductible share
issue costs (13.5) (3.6)
-------------------------------------------------------------------------
Net future income tax liability $ 439.5 $ 321.8
-------------------------------------------------------------------------
Net future income tax (asset) liability,
current $ 6.0 $ (7.1)
Net future income tax liability, long-term $ 433.5 $ 328.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
The petroleum and natural gas properties and facilities owned by ARC have an approximate tax basis of $2.6 billion ($2.23 billion in 2009) available for future use as deductions from taxable income. Included in this tax basis are estimated non-capital loss carryforwards of $183.9 million ($181.9 million in 2009) that expire in the years 2027 through 2030. The following is a summary of the estimated ARC tax pools:
<<
-------------------------------------------------------------------------
December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Canadian oil and gas property expenses $ 982.5 $ 951.6
Canadian development expenses 504.4 391.1
Canadian exploration expenses 95.5 105.6
Undepreciated capital costs 619.2 432.2
Non-capital losses 183.9 181.9
SR&ED tax pools 22.2 0.8
Other 26.0 15.2
-------------------------------------------------------------------------
Estimated tax basis, federal 2,433.7 2,078.4
-------------------------------------------------------------------------
Provincial tax pools 177.6 155.5
-------------------------------------------------------------------------
Estimated tax basis, federal and provincial $ 2,611.3 $ 2,233.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
At December 31, 2010 $1.7 million of current taxes were payable for Storm Exploration Inc. relating to the acquisition of Storm (Note 5). No current income taxes were paid in 2010 and 2009 by ARC Energy Trust or ARC Resources Ltd.
17. EXCHANGEABLE SHARES AND NON-CONTROLLING INTEREST
Prior to the Arrangement, the Trust was authorized to issue an unlimited number of exchangeable shares that could be converted (at the option of the holder) into trust units at any time. The number of trust units issuable upon conversion was based on the exchange ratio in effect at the conversion date. The exchange ratio was 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 exchange ratio. The exchangeable shares were not eligible to receive distributions.
On August 17, 2010, pursuant to the Storm acquisition described in Note 5, a second series of exchangeable shares was issued. These shares were classified as 'Series B' exchangeable shares and shared the same nature, terms and conditions of the original 'Series A' exchangeable shares. The Series B exchangeable shares were valued at $55.18 per share at issue date which was determined based on the exchange ratio and the trading price of ARC's trust unit in effect at that time.
Pursuant to the Plan of Arrangement all Series A and Series B exchangeable shares outstanding as at December 31, 2010 were exchanged for common shares of ARC based on the exchange ratio in effect on December 31, 2010 and subsequently cancelled.
<<
-------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
(units thousands) 2010 2009
-------------------------------------------------------------------------
Balance, beginning of year 871 1,092
Issued for acquisition consideration (Note 5) 1,925 -
Exchanged for trust units(1) (149) (221)
Exchanged for common shares pursuant to
the Arrangement (Note 1) (2,647) -
-------------------------------------------------------------------------
Balance, end of year - 871
Exchange ratio, end of year 2.89162 2.71953
Trust units issuable upon conversion,
end of year - 2,369
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) During 2010, 11,352 Series A and 137,522 Series B exchangeable shares
were converted to trust units at an average exchange ratio of 2.82276
and 2.84957, respectively. During 2009 220,573 Series A exchangeable
shares were converted at an average exchange ratio of 2.59547.
>>
During 2009, non-controlling interest on the Consolidated Balance Sheet consists of the fair value of the exchangeable shares at the time of issuance plus the accumulated earnings attributable to the non-controlling interest. The net income attributable to non-controlling interest on the Consolidated Statements of Income and Other Comprehensive Income is based on the number of 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 2010 and 2009:
<<
-------------------------------------------------------------------------
Year Ended Year Ended
December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Non-controlling interest, beginning of year $ 36.0 $ 42.4
Increase associated with issuance for
exchangeable shares (Note 5) 106.2 -
Reduction of book value for conversion
to trust units (7.9) (8.7)
Reduction pursuant to the Arrangement (Note 1) (134.3) -
Current period net income attributable to
non-controlling interest - 2.3
-------------------------------------------------------------------------
Non-controlling interest, end of year $ - $ 36.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
18. SHAREHOLDERS' CAPITAL
On December 31, 2010, pursuant to the Arrangement, all outstanding trust units were exchanged for common shares of the Corporation and the balance of Shareholders' Capital was reduced by $631.3 million, the deficit of the Trust at the time of the Arrangement.
ARC is authorized to issue an unlimited number of common shares and 50 million preferred shares issuable in series.
ARC has in place a Divided Reinvestment and Optional Cash Payment Program ('DRIP') in conjunction with the Corporation's transfer agent to provide the option for shareholders to reinvest cash dividends into common shares issued from treasury at a five per cent discount to the prevailing market price with no additional fees or commissions.
<<
Trust Units
-------------------------------------------------------------------------
Year Ended Year Ended
December 31, 2010 December 31, 2009
-------------------------------------------------------------------------
Number of Number of
(units thousands) trust units $ trust units $
-------------------------------------------------------------------------
Balance, beginning of year 236,615 2,917.6 216,435 2,600.7
Issued for cash 13,000 252.3 15,474 253.0
Issued on conversion of ARL
exchangeable shares
(Note 17) 424 7.9 572 8.6
Issued for acquisition
consideration (Note 5) 23,003 449.2 - -
Issued pursuant to the
distribution reinvestment
program 3,683 74.4 4,134 67.0
Trust unit issue costs,
net of tax(1) - (10.0) - (11.7)
Exchanged pursuant to
the Arrangement (276,725) (3,691.4) - -
-------------------------------------------------------------------------
Balance, end of year - - 236,615 2,917.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amount is net of tax of $2.5 million for the year ended December 31,
2010 (net of tax of $2.1 million for the year ended December 31,
2009).
Common Shares
-------------------------------------------------------------------------
Year Ended Year Ended
December 31, 2010 December 31, 2009
-------------------------------------------------------------------------
Number of Number of
(shares thousands) shares $ Shares $
-------------------------------------------------------------------------
Balance, beginning of year - - - -
Issued for trust units
pursuant to the
Arrangement 276,725 3,691.4 - -
Issued for ARL
exchangeable shares
pursuant to the
Arrangement 7,654 134.4 - -
Elimination of deficit
pursuant to the
Arrangement - (631.3) - -
-------------------------------------------------------------------------
Balance, end of year 284,379 3,194.5 - -
-------------------------------------------------------------------------
Net income per common share has been determined based on the following:
-------------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
(thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Weighted average common
shares, basic 276,110 236,138 259,903 233,025
Diluted common shares 283,723 238,507 264,220 235,394
-------------------------------------------------------------------------
-------------------------------------------------------------------------
19. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE LOSS
-------------------------------------------------------------------------
December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Accumulated earnings $ 3,207.7 $ 2,946.9
Accumulated distributions (3,839.0) (3,525.5)
Reduction of deficit pursuant to the
Arrangement (Note 1) 631.3 -
-------------------------------------------------------------------------
Deficit - (578.6)
Accumulated other comprehensive loss (0.1) (0.6)
-------------------------------------------------------------------------
Deficit and accumulated other
comprehensive loss $ (0.1) $ (579.2)
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>>
20. LONG TERM INCENTIVE PLAN
ARC's share-based Long Term Incentive Plan - Restricted Share Units and Performance Share Units (the 'RSU & PSU Plan'), formerly the Whole Trust Unit Incentive 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 share units. The RSU & PSU Plan consists of Restricted Share Units ('RSUs') for which the number of share units is fixed and will vest evenly over a period of three years and Performance Share Units ('PSUs') for which the number of share units is variable and will vest at the end of three years.
Upon vesting of the RSUs, the plan participant receives a cash payment based on the fair value of the underlying share units plus all dividends accrued since the grant date. The cash compensation of the PSUs issued upon vesting is further dependent upon an adjustment to the final number of PSU awards that eventually vest based on a performance multiplier. The performance multiplier is calculated using the percentile rank of ARC's Total Shareholder Return relative to its peers and can result in cash compensation issued upon vesting of the PSUs ranging from zero to two times the value of the PSUs originally granted.
During the year, cash payments of $28.0 million were made to employees relating to the RSU & PSU Plan compared to $16.6 million in 2009.
Compensation expense associated with the RSU & PSU Plan is determined by the change in intrinsic value of ARC's shares at each period end and is accrued over the vesting period. A portion of the total compensation cost associated with the RSU & PSU Plan is capitalized and recorded as Property, Plant and Equipment to reflect the portion that is directly attributable to spending on capital projects. As the value of the RSUs and PSUs is dependent upon the share price, the cost recorded may fluctuate over time.
ARC recorded non-cash compensation expense of $12.0 million and $1.6 million to general and administrative and operating expenses, respectively, and capitalized $2.1 million to property, plant and equipment in the year ended December 31, 2010 for the estimated change in the RSU & PSU Plan liability ($(0.1) million, $0.7 million, and $0.1 million for the year ended December 31, 2009). The compensation expense was based on the December 31, 2010 share price of $25.41 ($19.94 at December 31, 2009), accrued dividends, and a performance multiplier.
The following table summarizes the RSU and PSU movement for the year ended December 31, 2010:
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Number of Number of
(thousands) RSUs PSUs
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Balance, beginning of year 1,052 1,305
Granted 511 460
Vested (459) (321)
Forfeited (87) (143)
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Balance, end of year 1,017 1,301
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>>
The change in the net accrued long-term incentive compensation liability relating to the RSU & PSU Plan can be reconciled as follows:
<<
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December 31, December 31,
2010 2009
-------------------------------------------------------------------------
Balance, beginning of year $ 32.6 $ 31.9
Change in net liabilities in the year
General and administrative expense 12.0 (0.1)
Operating expense 1.6 0.7
Property, plant and equipment 2.1 0.1
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Balance, end of year(1) $ 48.3 $ 32.6
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Current portion of liability(2) 22.7 22.4
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Long-term incentive compensation liability $ 26.6 $ 10.9
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(1) Includes $1 million of recoverable amounts recorded in accounts
receivable as at December 31, 2010 ($0.7 million for 2009).
(2) Included in accounts payable and accrued liabilities on the
Consolidated Balance Sheet.
>>
21. COMMITMENTS AND CONTINGENCIES
Following is a summary of ARC's contractual commitments as at December 31, 2010:
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Payments Due by Period
-------------------------------------------------------------------------
2-3 4-5 Beyond 5
($ millions) 1 year years years years Total
-------------------------------------------------------------------------
Debt repayments(1) 17.0 437.1 83.0 266.4 803.5
Interest payments(2) 25.8 46.1 36.4 52.3 160.6
Reclamation fund
contributions(3) 4.6 8.3 7.1 60.8 80.8
Purchase commitments 38.7 33.6 12.8 9.2 94.3
Transportation commitments 27.1 46.2 32.5 18.2 124.0
Operating leases 9.0 18.1 14.9 64.7 106.7
Risk management contract
premiums(4) 3.6 2.2 - - 5.8
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Total contractual
commitments 125.8 591.6 186.7 471.6 1,375.7
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(1) Long-term and short term debt.
(2) Fixed interest payments on senior notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) 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 14). As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at December 31, 2010 on the Consolidated 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 2011 capital budget of $625 million has been approved by its Board of Directors. This commitment has not been included in the commitment table above as it is of a routine nature and is part of normal course of operations for active oil and gas companies and trusts.
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 contingency amounts for outstanding litigation and claims.
22. OTHER DEFERRED LIABILITIES
Other deferred liabilities comprise certain long term lease inducement liabilities associated with the building lease for ARC's corporate office. This non-cash liability is amortized on a straight line basis over the lease term commencing in March 2010 and extending to March 2024. Amortization associated with this lease inducement has been included in general and administrative expenses.
23. SUBSEQUENT EVENT
Subsequent to December 31, 2010 ARC disposed of minor properties in central Alberta for proceeds of approximately $170 million.
24. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The consolidated financial statements have been prepared in accordance with Canadian GAAP, which differs in some respects from US GAAP. Any differences in accounting principles as they pertain to the accompanying consolidated financial statements are immaterial except as described below:
The application of US GAAP would have the following effect on net income as reported for the years ended December 31, 2010 and December 31, 2009.
<<
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2010 2009
-------------------------------------------------------------------------
Net income as reported for Canadian GAAP $ 260.8 $ 222.8
Adjustments:
Depletion and depreciation(a) 113.2 103.8
Ceiling test write-down(a) - (144.5)
Transaction costs(b) - (0.2)
Research and development costs(c) (0.1) (1.0)
Non-controlling interest(d) - 2.3
Effect of applicable income taxes on the
above adjustments and rate change(h) (28.3) 2.9
Uncertain tax provision(i) 0.6 (1.0)
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Net income under US GAAP $ 346.2 $ 185.1
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Net income per share (Note 18)
-------------------------------------------------------------------------
Basic $ 1.33 $ 0.79
Diluted $ 1.31 $ 0.79
-------------------------------------------------------------------------
Comprehensive Income:
Net income under US GAAP $ 346.2 $ 185.1
Other Comprehensive (loss) income 0.5 (2.5)
-------------------------------------------------------------------------
Comprehensive income $ 346.7 $ 182.6
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>>
The application of US GAAP would have the following effect on the Consolidated Balance Sheets as reported:
<<
2010 2009
-------------------------------------------------------------------------
Canadian Canadian
GAAP US GAAP GAAP US GAAP
-------------------------------------------------------------------------
Property, plant and
equipment(a),(c) $ 4,432.9 $ 3,228.9 $ 3,573.4 $ 2,256.4
Goodwill(b) 243.2 265.4 157.6 179.9
Accounts payable and
accrued liabilities(i) (217.8) (234.2) (166.7) (183.7)
Future income
taxes/Deferred income
taxes(h) (439.5) (129.5) (321.8) 16.4
Non-controlling interest(d) - - (36.0) -
Temporary equity(d),(e),(f) - - - (4,567.6)
Unitholders' capital(e) - - (2,917.6) -
Shareholders'
capital(f),(g) (3,194.5) (6,456.5) - -
Deficit(e),(g) - 4,150.2 578.6 3,166.1
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>>
The above noted differences between Canadian GAAP and US GAAP are the result of the following:
<<
(a) Under Canadian GAAP, 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
plus the cost of unproved properties less impairment. A market
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 estimated future cash flows would be recorded as a
permanent impairment and charged against earnings.
Under US GAAP, companies using the full cost method of accounting for
oil and gas producing activities perform a ceiling test on each cost
centre using discounted estimated future net revenue from proved oil
and gas reserves using a prescribed discount rate of 10 per cent.
Prices to be used in the US GAAP ceiling test are the 12-month
average price prior to the end of the reporting period. For the year
ended December 31, 2010 no ceiling test write-down was recorded
($144.5 million write-down for the year ended December 31, 2009).
Depletion and depreciation charges recorded under US GAAP subsequent
to any US GAAP ceiling test write-down have been adjusted to reflect
the impact of the reduction of depletable costs.
A US GAAP difference also exists relating to the basis of measurement
of proved reserves that is utilized in the depletion calculation.
Under US GAAP, depletion charges are calculated by reference to
proved reserves estimated using average prices for the 12-month
period preceding the end of the reporting period. Under Canadian
GAAP, depletion charges are calculated by reference to proved
reserves estimated using future prices.
(b) 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'). The
acquisition has been accounted for as an asset acquisition under
Canadian GAAP. Under US GAAP, this acquisition qualifies as a
business combination and has been accounted for as a corporate
acquisition. Under Canadian GAAP an iterative calculation is used to
determine the amount of deferred taxes to record in an asset
acquisition. However, as the transaction was accounted for as a
business combination under US GAAP this iterative calculation does
not apply and goodwill results from the difference between the
present value of the tax shield inherent in the fair value of the
asset as compared with the undiscounted deferred tax balance. In its
US GAAP reconciliation, ARC has recorded goodwill of $22.3 million,
recorded transaction costs of $0.2 million, reduced property, plant
and equipment by $29.8 million and reduced its future income tax
liability by $7.5 million, in respect of this acquisition.
(c) Under Canadian GAAP, costs incurred for ARC's Redwater CO(2) pilot
project are capitalized as qualifying development costs. A US GAAP
difference exists as certain costs classified as research and
development costs are required to be expensed in accordance with a
specific guidance contained within US GAAP. Specifically, the US GAAP
Research and Development Standard requires that costs that are
incurred for a particular research and development project that have
no alternative future use must be expensed. Accordingly, for the year
ended December 31, 2010 ARC charged $0.1 million to the income
statement for US GAAP purposes ($1.0 million for the year ended
December 31, 2009).
(d) Under Canadian GAAP, ARC's Exchangeable Shares are classified as non-
controlling interest to reflect a minority ownership in one of ARC's
subsidiaries. As these exchangeable shares must ultimately be
converted into Trust Units, the exchangeable shares are classified as
temporary equity along with the Trust Units for US GAAP purposes
using the applicable exchange ratio.
(e) Under US GAAP, as the Trust Units are redeemable at the option of the
unitholder, the Trust Units must be recorded at their redemption
amount and presented as temporary equity in the Consolidated Balance
Sheet. The redemption amount is determined based on the lower of the
closing market price on the balance sheet date or 90 percent of the
weighted average trading price for the 10 day trading period
commencing on the balance sheet date of the Trust Units and the Trust
Unit equivalent of the exchangeable shares outstanding. Under
Canadian GAAP, all Trust Units are classified as permanent equity.
Changes in redemption value between periods are charged or credited
to deficit. For the year ended December 31, 2010, $1.0 billion was
charged to deficit ($463 million charged to deficit for the year
ending December 31, 2009).
(f) On December 31, 2010 the Trust effectively completed its conversion
from an income trust to a corporation. Pursuant to the Plan of
Arrangement, all outstanding trust units and exchangeable shares were
exchanged for common shares of the Corporation. Under both US and
Canadian GAAP this exchange was recorded at the carrying value of the
trust units and exchangeable shares outstanding at December 31, 2010.
Due to the classification of ARC's trust units and exchangeable
shares as temporary equity under US GAAP, recorded at their
redemption amount, the carrying value of shareholders' equity varies
between US and Canadian GAAP. Prior to the Trust's conversion to a
corporation ARC had classified $6.5 billion as temporary equity, in
accordance with US GAAP.
(g) Under Canadian GAAP, pursuant to the Arrangement, ARC reduced
shareholders' capital by $631.3 million, the amount necessary to
eliminate the deficit of the Trust at the time of the Arrangement.
Under US GAAP, the elimination of a deficit through a reduction in
shareholders' capital is not permitted unless a quasi reorganization
has been effected. ARC's conversion from an income trust to a
corporation does not meet the required conditions to qualify as a
quasi reorganization and therefore the deficit amount has not be
eliminated through the reduction of shareholders' capital.
(h) For year ended December 31, 2010 a deferred income tax expense of
$28.3 million was recorded on current period depletion and
depreciation adjustments for ceiling test write-downs recognized in
prior periods under US GAAP.
For the year ended December 31, 2009, $33.7 million relating to
deferred income tax expense on current period depletion and
depreciation adjustments and tax rate change adjustments on previous
ceiling test write-downs recognized under US GAAP and a future income
tax recovery of $36.3 million relating to the current period ceiling
test write-down was recorded. ARC also reduced its deferred tax
liability compared to Canadian GAAP by $0.3 million relating to
adjustments for the Ante Creek acquisition transaction costs and
Redwater EOR costs expensed to the income statement under US GAAP.
(i) For the year ended December 31, 2010 ARC recorded a reduction to
deferred income tax expense of $0.6 million for uncertain tax
positions including accrued interest and penalties of $0.8 million.
As at December 31, 2010, the total amount included in accounts
payable and accrued liabilities in relation to uncertain tax
positions in the US GAAP Consolidated Balance Sheet was $16.5 million
including accrued interest and penalties of $4.7 million.
(j) In 2010 and 2009, the FASB and SEC issued new and revised standards
all of which were determined not to have a material effect on ARC
except for ASC 805 - Business Combinations for which the reconciling
items noted above have been recorded (see note (b)).
>>
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: all of the matters under the heading '2010 and 2011 Guidance and Financial Highlights' which contains guidance for 2011, the future expenditure plans and strategy for 2011 and expected production and operations under the heading 'Production', the expectations regarding the pricing of natural gas for 2011 under the heading 'Commodity Prices Prior to Hedging', the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia, the expected provincial royalty rates for 2011 under various commodity pricing outlooks for 2011 under the heading 'Operating Netbacks', the estimated future payments under the RSU & PSU Plan under the heading 'Long-term Incentive Plans - Restricted Share Units & Performance Share Units Plan, Stock Option Plan, and Deferred Share Unit Plan', the estimate of ARC as to when it expects to be in a material cash tax-paying position under the heading 'Taxes', the information as to total capital expenditures forecasted for 2011 under the heading 'Capital Expenditures and Net Acquisitions', the information relating to financing the 2011 capital expenditures under the heading: 'Capitalization, Financial Resources and Liquidity', ARC's estimates of normal course obligations under the heading 'Contractual Obligations and Commitments', the expectations related to the transition from Canadian GAAP to IFRS under the heading 'Financial Reporting Update' and 'First Time Adoption of IFRS', and a number of other matters, including 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; and future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures.
The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
ARC Resources Ltd. ('ARC') is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC expects 2011 oil and gas production to average 84,000 to 87,000 barrels of oil equivalent per day from six core areas in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.
ARC RESOURCES LTD.
<<
John P. Dielwart,
Chief Executive Officer
>>
about ARC Resources Ltd., please visit our website www.arcresources.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6427, Toll Free 1-888-272-4900, ARC Resources Ltd., Suite 1200, 308 - 4th Avenue S.W., Calgary, AB, T2P 0H7
