ARC ENERGY TRUST ANNOUNCES THIRD QUARTER 2010 RESULTS
Nov 1, 2010
CALGARY, Nov. 1 /CNW/ - (AET.UN and ARX.A - TSX) ARC Energy Trust ("ARC" or "the Trust") announces the results for the third quarter ended September 30, 2010.
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Three Months Ended Nine Months Ended
September 30 September 30
2010 2009 2010 2009
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FINANCIAL
(Cdn$ millions, except per
unit and per boe amounts)
Revenue before royalties 293.6 239.2 884.4 699.6
Per unit(1) 1.10 1.01 3.43 2.98
Per boe 41.19 41.39 46.06 40.12
Cash flow from operating
activities(2) 166.2 125.6 487.7 354.2
Per unit(1) 0.62 0.53 1.89 1.51
Per boe 23.32 21.73 25.40 20.31
Net income 81.0 69.6 267.1 158.9
Per unit(3) 0.30 0.29 1.04 0.68
Distributions 80.3 70.6 230.6 227.6
Per unit(1) 0.30 0.30 0.90 0.98
Per cent of cash flow from
operating activities(2) 48 56 47 64
Net debt outstanding(4) 871.1 705.4 871.1 705.4
OPERATING
Production
Crude oil (bbl/d) 26,959 26,921 27,315 27,541
Natural gas (mmcf/d) 275.0 193.1 234.9 195.7
Natural gas liquids (bbl/d) 4,690 3,717 3,871 3,720
Total (boe/d) 77,483 62,824 70,337 63,881
Average prices
Crude oil ($/bbl) 71.07 67.74 73.10 58.77
Natural gas ($/mcf) 3.79 3.25 4.39 4.05
Natural gas liquids ($/bbl) 49.13 38.92 53.46 38.89
Oil equivalent ($/boe) 41.14 41.31 45.98 40.00
Operating netback ($/boe)
Commodity and other revenue
(before hedging) 41.19 41.39 46.06 40.11
Transportation costs (1.07) (0.83) (1.11) (0.88)
Royalties (6.51) (6.53) (7.59) (5.86)
Operating costs (9.31) (9.68) (9.98) (10.28)
Netback (before hedging) 24.30 24.35 27.38 23.09
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TRUST UNITS
(millions)
Units outstanding,
end of period(5) 283.1 238.1 283.1 238.1
Weighted average
trust units(6) 268.0 237.7 257.7 234.5
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TRUST UNIT TRADING STATISTICS
(Cdn$, except volumes) based
on intra-day trading
High 20.95 20.20 22.49 20.90
Low 19.02 15.48 19.02 11.73
Close 20.55 20.20 20.55 20.20
Average daily volume
(thousands) 1,160 1,038 1,163 1,088
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(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units (including weighted average
trust units issuable for exchangeable shares). Per unit
distributions are based on the number of trust units outstanding at
each distribution record date.
(2) Cash flow from operating activities is a GAAP measure. Historically,
management has disclosed Cash Flow as a non-GAAP measure calculated
using cash flow from operating activities less the change in non-cash
working capital and the expenditures on site restoration and
reclamation as they appear on the Consolidated Statements of Cash
Flows. Cash Flow for the third quarter of 2010 would be $162.8
million ($0.61 per unit) and $478 million ($1.85 per unit) year-to-
date. Distributions as a percentage of Cash Flow would be 49 per cent
for the third quarter of 2010 and 48 per cent year-to-date.
(3) Net income per unit is based on net income divided by weighted
average trust units outstanding (including weighted average trust
units issuable for exchangeable shares).
(4) Net debt excludes short-term investment, current unrealized amounts
pertaining to risk management contracts and the current portion of
future income taxes.
(5) Includes trust units issuable for outstanding exchangeable shares at
period end.
(6) For the third quarter of 2010, includes 2.7 million (0.9 million in
2009) exchangeable shares each exchangeable into 2.840 trust units as
at September 30, 2010 (2.679 in 2009), for a weighted average of
5 million (2.5 million in 2009) trust units.
ACCOMPLISHMENTS / FINANCIAL UPDATE
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- ARC completed the acquisition of Storm Exploration Inc. ("Storm") on
August 17, 2010 to increase its holdings of large-in-place resources
primarily in the Parkland area of N.E. British Columbia. The
acquisition was paid for by issuing 23 million ARC trust units plus
ARC Resources exchangeable shares convertible into 5.4 million trust
units at closing and the assumption of $96.7 million of debt.
Production from the Storm properties averaged 9,600 boe per day for
the period August 17, 2010 to September 30, 2010, contributing 4,700
boe per day to the third quarter. Approximately 85 per cent of this
production came from the Parkland Montney field located only twelve
kilometres northwest of ARC's Dawson Montney field. At closing, it is
estimated proved reserves were 28.9 million boe (43.2 million boe
proved plus probable). This acquisition met ARC's criteria on every
measure: the assets are located in an area ARC operates in and knows
well, ARC's technical staff has the ability to continue to develop
the area economically and ARC believes that its expertise in
developing Montney gas will deliver incremental value from these
assets.
- Production volumes for the quarter averaged 77,483 boe per day, a
14,659 boe per day or 23 per cent increase compared to the third
quarter of 2009. The majority of the increase in production was a
result of the new Dawson gas plant operating at full capacity of
60 mmcf per day throughout the quarter and the inclusion of 45 days
of production from Storm since its acquisition on August 17, 2010,
with the remainder attributed to successful drilling results
throughout ARC's production base. In September, ARC's production
averaged 83,315 boe per day - 306 mmcf per day of natural gas and
32,357 boe per day of liquids - as a result of continued operating
excellence at the new gas plant and the inclusion of the Storm
volumes for a full month. ARC expects 2010 full year production to
average between 72,500 and 74,500 boe per day.
- Cash flow from operating activities was $166.2 million ($0.62 per
unit) in the third quarter of 2010, a 32 per cent increase from the
$125.6 million ($0.53 per unit) achieved in the comparable quarter in
2009. This increase was primarily due to the increase in cash gains
on risk management contracts, increase in production volumes combined
with higher crude oil prices, a modest increase in the price of
natural gas, and a four per cent reduction in operating costs in the
quarter.
- WTI oil prices ranged from approximately US$70 to US$90 in the third
quarter of 2010 with WTI averaging US$76.21 per barrel compared to
US$68.29 per barrel for the third quarter of 2009. ARC's realized
crude oil price increased by five per cent to $71.07 per barrel in
the third quarter of 2010 from $67.74 per barrel in the third quarter
of 2009.
Realized natural gas prices were also up 17 per cent year over year
from a low of $3.25 per mcf in the third quarter of 2009 to $3.79 per
mcf in the third quarter of 2010. Increasing natural gas production
in the United States has resulted in abundant natural gas supplies in
North America. U.S. producers have continued drilling shale prospects
in the United States to meet land tenure commitments resulting in a
North American oversupply of natural gas and depressed current
natural gas prices. In light of the continued weakness in natural gas
prices, ARC is concentrating its remaining 2010 capital program on
liquids opportunities and on Montney assets in northeast British
Columbia where the economics still support development. ARC reviews
the economics of its drilling programs on a regular basis to ensure
the programs support value creation for unitholders.
To address the prospective weakness in natural gas prices in 2011,
during the third quarter ARC converted an existing three year natural
gas hedge into a fiscal 2011 hedge of 128 mmcf per day at a fixed
price swap of Cdn$5.85 per mcf (AECO). Additionally ARC has 19,000
barrels per day of oil hedged in 2011 with an average floor price of
US$84 per barrel resulting in approximately 45 to 50 per cent of
ARC's 2011 total expected production volumes being hedged at
attractive prices. ARC is now focusing on hedging fiscal 2012
production to protect future cash flow and to provide more certainty
to ongoing distribution/dividend payments.
- In August 2010, ARC renewed its syndicated credit facility,
increasing its bank line of credit from $800 million to $1 billion.
The renewed facility matures in August 2013 and bears interest at
Canadian dollar bankers' acceptance or US dollar LIBOR loan rates,
plus a stamping fee. At quarter-end, ARC had $308 million drawn on
its syndicated credit facility. With a net debt to annualized year-
to-date cash flow from operating activities ratio of 1.3 times and
debt representing approximately 13 per cent of ARC's total
capitalization, ARC continues to have a very strong balance sheet.
- Capital expenditures for the quarter totaled $159.5 million. During
the quarter, ARC drilled 28 oil wells and 45 natural gas wells with a
99 per cent success rate. Year-to-date capital expenditures are
$431.8 million. After payment of distributions, ARC funded 72 per
cent of its 2010 year-to-date capital program with cash flow from
operating activities and proceeds from the distribution re-investment
program ("DRIP") with the remaining portion funded through debt. ARC
has revised its capital expenditure guidance for the full year
downwards by $15 million to $625 million. The reduction in capital is
a result of better than expected production capability from new wells
drilled at Dawson, which has allowed for the postponement of certain
drilling programs and cost reductions achieved to date. No material
impact is anticipated on production volumes. This reduction in
capital budget has been achieved despite spending approximately
$54 million on unbudgeted land acquisitions.
- ARC's board of directors has approved a $625 million capital program
for 2011 that will allow for considerable growth. The capital program
will focus on oil and liquids rich gas opportunities at Pembina and
Ante Creek in Alberta, southeast Saskatchewan and Parkland in British
Columbia and on paced development of the Montney gas opportunities in
northeast British Columbia. ARC plans to drill 166 gross wells on
operated properties and plans to participate in an additional 83
wells on partner operated lands. The 2011 capital program will be
financed through a combination of cash flow, DRIP proceeds, potential
minor asset disposition proceeds and, where necessary, existing
credit facilities. Additional details can be found in the November 1,
2010 news release titled "ARC Energy Trust Announces a $625 million
Capital Budget for 2011, Which Includes a 12 per cent Production
Growth Target" filed on www.sedar.com.
- ARC's planning for the conversion to a dividend paying corporation
effective January 1, 2011 is near completion. All unitholders of
record on November 10, 2010 will be forwarded an information circular
in November detailing the conversion to be voted upon at a joint
meeting of securityholders of ARC on December 15, 2010. Current plans
would see a dividend policy similar to the existing distribution
policy with dividends being paid monthly. Provided that ARC
unitholders approve the conversion to a corporation, ARC's board
intends to approve a $0.10 per share dividend for the month of
January 2011. Additional details can be found in the November 1, 2010
news release titled "ARC Energy Trust Announces Board Approval of
Conversion Plans and Intent to Maintain $0.10 Monthly Dividend Post
Conversion" filed on www.sedar.com.
British Columbia Montney Resource Play Development
Production from the British Columbia Montney Resource Play ("BC
Montney") averaged 139 mmcf per day for the third quarter of 2010,
with the Dawson gas plant operating at full capacity throughout the
quarter and the addition of Parkland volumes after the August 17,
2010 Storm acquisition.
During the third quarter of 2010, ARC spent $58.1 million on
development activities in the BC Montney area including drilling
seven horizontal wells and completing 10 horizontal wells. In
addition, ARC acquired 53 additional sections of land for $28.3
million. For 2010 to date, ARC has drilled and completed 29
horizontal wells in BC Montney. Average production capabilities for
ARC's Dawson wells have exceeded expectations resulting in
approximately 100 mmcf per day of surplus capacity already behind
pipe and waiting on facility capacity. As a result, the drilling of
eight remaining wells at Dawson and three remaining wells on other BC
Montney lands budgeted for 2010 will be deferred until 2011. This
will result in a $45 million reduction in the capital budget for BC
Montney in 2010 with the funds being redeployed into land acquisition
and oil focused drilling activities.
Approval from the British Columbia Oil and Gas Commission ("OGC") for
the Phase 2 portion of the Dawson gas plant was received during the
quarter. Phase 2 consists of the construction of a second 60 mmcf per
day train at the Dawson gas plant, at a cost of approximately
$50 million, and is anticipated to increase ARC's Dawson operated
plant processing capacity to 120 mmcf per day. To date, ARC has
incurred $19.1 million on construction costs. Phase 2 is scheduled to
be completed in the first quarter of 2011 with the commissioning and
start-up occurring in the second quarter.
Ante Creek Montney Resource Play Development
ARC drilled six oil wells into the Montney formation in the third
quarter. Of these six wells, three were completed along with two
additional wells that had been drilled in previous quarters. Together
with the completion of the debottlenecking of ARC's oil treatment
facilities and the expansion of a third party gas plant, these
activities have resulted in an increase of 12 per cent from the
second quarter of 2010 production volumes to a record level 7,486
boe per day during the third quarter of 2010. Approximately 43 per
cent of the production consists of liquids.
Cardium Resource Play Development
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). During the third quarter, ARC drilled nine wells
into the Cardium formation, of which two wells (one vertical and one
horizontal) were brought on production during the quarter with six
other horizontals completed following quarter end. ARC continues to
be encouraged by the results we are seeing with horizontal wells
coming on stream at initial 30 day production rates in the 100 to 200
barrel per day range. ARC expects to spend at least an additional
$20 million during the remainder of the year to further our
understanding of the potential for the recovery of significant
incremental oil volumes through the application of horizontal
drilling and completion technology.
Enhanced Oil Recovery Initiatives
During the third quarter of 2010, ARC spent $8.1 million on enhanced
oil recovery ("EOR") and carbon sequestration initiatives, offset by
funding of $3.6 million from external parties. Work on the Redwater
CO(2) pilot project continues, and both the CO(2) injection and oil
production facilities are operating. With encouraging results to
date, ARC will continue its 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 management's analysis of its financial performance and significant trends or external factors that may affect future performance. It is dated November 1, 2010 and should be read in conjunction with the unaudited Consolidated Financial Statements for the period ended September 30, 2010, the MD&A and the unaudited Consolidated Financial Statements ended June 30, 2010, the MD&A and the unaudited Consolidated Financial Statements ended March 31, 2010 and the audited Consolidated Financial Statements and MD&A as at and for the year ended December 31, 2009, 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.
ARC Energy Trust ("ARC") or ("the Trust") is a mid-sized distribution paying, publicly traded exploration and production company with near term growth prospects, and is one of Canada's largest producers of conventional oil and gas production. Currently structured as a trust, ARC develops and acquires oil and gas properties in western Canada. ARC plans to convert to a dividend paying corporation on January 1, 2011.
ARC's goal is value creation by providing superior, long-term returns to unitholders achieved through the development of large oil and natural gas pools. Our key activities that support this objective are:
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1. Resource Plays - Acquisition and development of land and producing
properties that have geological potential as resource plays.
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. In August
2010, ARC acquired the Parkland Montney field in northeast British
Columbia through an acquisition of Storm Exploration Inc. ("Storm").
2. Conventional Oil & Gas Production - Maximizing production while
controlling operating costs on oil and gas wells located within ARC's
seven core producing areas in western Canada. As well, the periodic
acquisition and disposition of strategic producing and undeveloped
properties to enhance current production or realign asset portfolios
or provide the potential for future drilling locations and if
successful, additional production and reserves. Current oil
production is predominantly light and medium quality.
ARC continues to develop its core areas to increase recoverable
reserves through development drilling, optimization and waterflood
programs.
3. Enhanced Oil Recovery ("EOR") - Evaluation and implementation of
enhanced oil recovery programs to increase ARC's recoverable reserves
in existing oil pools.
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 a CO(2) pilot
program at Redwater in Alberta.
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ARC provides returns to unitholders through monthly cash distributions and the potential for capital appreciation. ARC currently distributes $0.10 per unit per month to its unitholders. Since inception in July 1996, ARC has distributed $3.8 billion or $25.88 per unit. The remaining cash flow is used to fund reclamation costs and a portion of capital expenditures. During the first nine months of 2010, cash flow and proceeds from the Distribution Re-investment Plan ("DRIP") program funded $308 million of capital expenditures.
ARC's unitholders can also benefit from potential capital appreciation associated with increased market values for ARC's production and reserves. ARC's management strives to replace and grow both production and reserves by focusing on oil and natural gas development activities and opportunistic acquisitions. To support this, the majority of ARC's annual capital budget is deployed on a balanced drilling program of low and moderate risk wells, well tie-ins and other related costs and the acquisition of undeveloped land.
Tables 1 and 2 below outline ARC's success in executing its business strategy in pursuit of value creation. Table 1 details ARC's normalized production, reserves and distributions per unit over the past three periods:
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Table 1
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Full year Full year
Per Trust Unit Q3 2010 YTD 2010 2009 2008
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Normalized production,
boe per unit(1)(2) 0.30 0.28 0.27 0.29
Normalized reserves,
boe per unit(1)(3) N/A N/A 1.57 1.42
Distributions per unit $0.30 $0.90 $1.28 $2.67
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(1) Normalized indicates that all periods as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional trust units were issued (or repurchased) at a period
end price for the reserves per unit calculation and at an annual
average price for the production per unit calculation in order to
achieve a net debt balance of 15 per cent of total capitalization
each year. The normalized amounts are presented to enable
comparability of per unit values.
(2) Production per unit represents daily average production (boe) per
thousand trust units and is calculated based on daily average
production divided by the normalized weighted average trust units
outstanding including trust units issuable for exchangeable shares.
(3) Reserves per unit are calculated based on proved plus probable
reserves (boe), as determined by ARC's independent reserve evaluator
solely at year-end, divided by period end trust units outstanding
including trust units issuable for exchangeable shares.
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ARC's business plan has resulted in significant operational success and contributed to a trailing five year annualized return per unit of six per cent (Table 2).
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Table 2
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Total Returns(1) Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
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Distributions per unit 1.20 5.45 10.25
Capital appreciation (depreciation)
per unit 0.35 (0.62) (3.55)
Total return per unit 7.9% 25.3% 34.0%
Annualized total return per unit 7.9% 7.8% 6.0%
S&P/TSX Exploration & Producers Index
annualized total return 3.9% (2.1)% 1.3%
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(1) Calculated as at September 30, 2010.
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2010 Guidance and Financial Highlights
Table 3 is a summary of ARC's 2010 Guidance and a review of 2010 year-to-date actual results for the third quarter as compared to guidance:
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Table 3
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2010
Original 2010 Revised 2010 Actual %
Guidance Guidance YTD Change
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Production (boe/d) 70,500 - 72,500 72,500 - 74,500 70,337 -
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Expenses ($/boe):
Operating costs 10.30 10.00 9.98 (3)
Transportation 1.00 1.10 1.11 11
General and
administrative 2.85 2.85 2.96 4
Interest 1.40 1.70 1.67 20
Capital expenditures
($ millions) 610 625 431.8 -
Annual weighted average
trust units and trust
units issuable
(millions) 254 264 258 2
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Revisions to the Original 2010 Guidance for the full year 2010 have been made to production, operating costs, transportation, interest, capital expenditures, and annual weighted average trust units and trust units issuable. Production, operating costs, transportation, and annual weighted average trust units and trust units issuable have been revised as a result of the Storm acquisition. Interest has been revised as a result of ARC's renewed credit facility. Capital expenditures have been revised as a result of a realignment of ARC's capital program. Currently, the results for the first nine months of 2010 are in-line with the Revised Guidance with the exception of production. With current production at 83,315 boe per day - 306 mmcf per day of natural gas and 32,357 boe per day of liquids - for the month of September 2010, ARC expects 2010 full year average production to be within the Revised 2010 Guidance. The 2010 Revised Guidance provides unitholders with information on management's expectations for results of operations, excluding any acquisitions or dispositions for 2010. Readers are cautioned that the Revised 2010 Guidance may not be appropriate for other purposes.
2010 Third Quarter Financial and Operational Results
Financial Highlights
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Table 4
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Three Months Ended Nine Months Ended
September 30 September 30
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(Cdn$ millions,
except per unit
and volume data) 2010 2009 % Change 2010 2009 % Change
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Cash flow from
operating
activities 166.2 125.6 32 487.7 354.2 38
Cash flow from
operating
activities
per unit(1) 0.62 0.53 17 1.89 1.51 25
Net income 81.0 69.6 16 267.1 158.9 68
Net income
per unit(2) 0.30 0.29 3 1.04 0.68 53
Distributions
per unit(3) 0.30 0.30 - 0.90 0.98 (8)
Distributions
as a per cent
of cash flow
from operating
activities 48 56 (14) 47 64 (27)
Average daily
production
(boe/d)(4) 77,483 62,824 23 70,337 63,881 10
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(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
period end.
(2) Based on net income divided by weighted average trust units
outstanding including weighted average trust units issuable for
exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf:1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the 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 32 per cent in the third quarter of 2010 to $166.2 million from $125.6 million in the third quarter of 2009. The increase was primarily attributed to a 23 per cent increase in production and an $18.6 million increase in realized gains on risk management contracts, partially offset by increased royalties and higher total operating costs. Details of the change in cash flow from operating activities in the third quarter of 2009 to the third quarter of 2010 are presented in Table 5.
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Table 5
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($ per
($ millions) trust unit)
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Q3 2009 Cash flow from Operating Activities 125.6 0.53
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Volume variance 55.8 0.23
Price variance (1.4) (0.01)
Cash gains on risk management contracts 18.6 0.08
Royalties (8.7) (0.04)
Expenses:
Transportation (2.8) (0.01)
Operating(1) (10.9) (0.05)
General and administrative(1) (5.2) (0.02)
Interest (7.2) (0.03)
Taxes 0.1 -
Realized foreign exchange gain 0.1 -
Weighted average trust units - (0.07)
Non-cash and other items(2) 2.2 0.01
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Q3 2010 Cash flow from Operating Activities 166.2 0.62
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(1) Excludes non-cash portion of Whole Unit 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 38 per cent in 2010 to $487.7 million from $354.2 million in the comparable period of 2009. The increase was attributed to higher volumes and an increase in commodity prices, offset by higher royalties. Details of the change in cash flow from operating activities during the first nine months of 2009 to the first nine months of 2010 are presented in Table 5a.
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Table 5a
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($ per
($ millions) trust unit)
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YTD 2009 Cash flow from Operating Activities 354.2 1.51
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Volume variance 70.7 0.30
Price variance 114.1 0.49
Cash gains on risk management contracts 24.3 0.10
Royalties (43.6) (0.19)
Expenses:
Transportation (6.0) (0.03)
Operating(1) (13.0) (0.06)
Cash G&A (17.6) (0.08)
Interest (12.2) (0.05)
Taxes 0.1 -
Realized foreign exchange loss (0.3) -
Weighted average trust units - (0.17)
Non-cash and other items(2) 17.0 0.07
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YTD 2010 Cash flow from Operating Activities 487.7 1.89
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(1) Excludes non-cash portion of Whole Unit Plan expense recorded in
operating costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
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2010 Cash Flow from Operating Activities Sensitivity
Table 6 illustrates sensitivities on pre-hedged operating income items to operational and business environment changes and the resulting impact on cash flows from operating activities in total and per trust unit:
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Table 6
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Impact on Annual
Cash Flow from
Operating Activities(4)
Business Environment(1) Assumption Change $/Unit
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Oil price (US$ WTI/bbl)(2)(3) $ 80.00 $ 1.00 0.04
Natural gas price (Cdn$ AECO/mcf)(2)(3) $ 3.50 $ 0.10 0.03
Cdn$/US$ exchange rate(2)(3)(5) 1.05 $ 0.01 0.03
Interest rate on debt(2) 4.00% % 1.0 0.01
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 0.03
Gas production volumes (mmcf/d) 240 % 1.0 0.01
Operating expenses per boe $ 10.00 % 1.0 0.01
Cash G&A and Whole Unit Plan
expenses per boe $ 2.85 % 10.0 0.03
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(1) Calculations are performed independently and may not be indicative of
actual results that would occur when multiple variables change at the
same time.
(2) Prices and rates are indicative of published forward prices and rates
at the time of this MD&A. The calculated impact on annual cash flow
from operating activities would only be applicable within a limited
range of these amounts.
(3) Analysis does not include the effect of hedging contracts.
(4) Assumes constant working capital.
(5) Includes impact of foreign exchange on crude oil prices that are
presented in U.S. dollars. This amount does not include a foreign
exchange impact relating to natural gas prices as it is presented in
Canadian dollars in this sensitivity.
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Net Income
Net income in the third quarter of 2010 was $81 million ($0.30 per unit), an $11.4 million increase compared to $69.6 million ($0.29 per unit) in the third quarter of 2009. ARC realized higher revenues, net of royalties, and realized risk management gains of $64.3 million, compared to the third quarter of 2009. These increases were partially offset by higher transportation, operating, general and administrative, and interest expense of $23.8 million. In addition, net income was impacted by the following non-cash items during the third quarter of 2010 relative to the third quarter in 2009:
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- Higher unrealized gains on risk management contracts of $24.5 million
- Lower foreign exchange gains of $21.4 million
- Higher depletion, depreciation and accretion ("DD&A") expense of
$29.9 million
>>
Production
Production volumes averaged 77,483 boe per day in the third quarter of 2010 compared to 62,824 boe per day in the same period of 2009 as detailed in Table 7. The increase in third quarter 2010 production is a result of the new gas plant at Dawson operating at full capacity of 60 mmcf per day, the Storm acquisition, which added approximately 4,700 boe per day for the quarter (average production of 9,600 boe per day for the period from August 17 to September 30), an acquisition that closed in late 2009 and new wells on production.
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Table 7
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Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
Production 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Light and medium
crude oil
(bbl/d) 25,994 25,930 - 26,367 26,561 (1)
Heavy oil
(bbl/d) 965 991 (3) 948 981 (3)
Natural gas
(mmcf/d) 275.0 193.1 42 234.9 195.7 20
Natural gas
liquids ("NGL")
(bbl/d) 4,690 3,717 26 3,871 3,720 4
-------------------------------------------------------------------------
Total production
(boe/d)(1) 77,483 62,824 23 70,337 63,881 10
% Natural gas
production 59 51 - 56 51 -
% Crude oil and
liquids
production 41 49 - 44 49 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>
Third quarter 2010 light and medium crude oil production remained constant at 25,994 barrels per day compared to 25,930 barrels per day in 2009. ARC has redirected its focus to exploiting oil and liquids rich properties, and expects to continue this strategy for the 2011 capital program in order to take advantage of stronger oil prices relative to gas. Natural gas production was 275 mmcf per day in the third quarter of 2010, an increase of 42 per cent from the 193.1 mmcf per day produced in the third quarter of 2009. During the third quarter of 2010, ARC drilled 73 gross wells (68 net wells) on operated properties consisting of 28 gross oil wells and 45 gross natural gas wells with a 99 per cent success rate.
ARC expects that 2010 full year production will average approximately 72,500 to 74,500 boe per day, that it will drill a total of approximately 200 gross (185 net) wells on operated properties and participate in an additional 91 gross wells (18 net) to be drilled on non-operated properties. Current production for the month of September 2010 of approximately 83,315 boe per day is 33 per cent greater than the 62,520 boe per day produced in the fourth quarter of 2009.
Table 8 summarizes ARC's production by core area:
<<
Table 8
-------------------------------------------------------------------------
Three Months Ended September 30, 2010
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,536 1,433 24.7 989
N.E. BC & N.W. AB 27,498 711 151.2 1,589
Northern AB 11,652 4,484 36.9 1,013
Pembina 9,040 5,572 16 807
Redwater 4,177 3,830 1.2 145
S.E. AB & S.W. Sask. 8,285 1,024 43.5 11
S.E. Sask. & MB 10,295 9,905 1.5 136
-------------------------------------------------------------------------
Total 77,483 26,959 275.0 4,690
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Months Ended September 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,218 1,370 28.4 1,106
N.E. BC & N.W. AB 13,517 703 72.8 673
Northern AB 8,551 3,891 23.1 806
Pembina 9,382 5,503 18.7 762
Redwater 4,227 3,795 1.2 230
S.E. AB & S.W. Sask. 8,951 1,053 47.3 12
S.E. Sask. & MB 10,978 10,605 1.5 127
-------------------------------------------------------------------------
Total 62,824 26,920 193.0 3,716
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is
northwest, S.E. is southeast and S.W. is southwest.
>>
Table 8a summarizes ARC's production by core area for the first nine months of 2010:
<<
Table 8a
-------------------------------------------------------------------------
Nine Months Ended September 30, 2010
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,604 1,352 25.5 1,002
N.E. BC & N.W. AB 20,233 681 111.3 1,013
Northern AB 11,187 4,555 34.3 913
Pembina 8,982 5,527 16.7 671
Redwater 4,173 3,822 1.2 148
S.E. AB & S.W. Sask. 8,455 1,042 44.4 12
S.E. Sask. & MB 10,703 10,336 1.5 112
-------------------------------------------------------------------------
Total 70,337 27,315 234.9 3,871
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Nine Months Ended September 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,089 1,281 28.2 1,108
N.E. BC & N.W. AB 13,868 722 74.9 673
Northern AB 9,005 4,072 24.6 837
Pembina 9,418 5,623 18.1 782
Redwater 4,122 3,751 1.1 180
S.E. AB & S.W. Sask. 8,923 1,016 47.4 13
S.E. Sask. & MB 11,456 11,076 1.5 127
-------------------------------------------------------------------------
Total 63,881 27,541 195.8 3,720
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $293.6 million in the third quarter of 2010, an increase of $54.4 million over 2009 revenue of $239.2 million primarily related to the increase in production volumes.
A breakdown of revenue is outlined in Table 9:
<<
Table 9
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
Revenue September 30 September 30
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Oil revenue 176.1 167.7 5 545.0 441.8 23
Natural gas
revenue 95.9 57.7 66 281.4 216.3 30
NGL revenue 21.2 13.3 59 56.5 39.5 43
-------------------------------------------------------------------------
Total commodity
revenue 293.2 238.7 23 882.9 697.6 27
Other revenue 0.4 0.5 (20) 1.5 2.0 (25)
-------------------------------------------------------------------------
Total revenue 293.6 239.2 23 884.4 699.6 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Commodity Prices Prior to Hedging
<<
Table 10
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Average
Benchmark
Prices
AECO gas
($/mcf)(1) 3.72 3.03 23 4.30 4.10 5
WTI oil
(US$/bbl)(2) 76.21 68.29 12 77.65 57.13 36
Cdn$/US$
exchange rate 1.04 1.10 (5) 1.04 1.16 (10)
WTI oil
(Cdn$/bbl) 79.19 74.90 6 80.39 66.08 22
-------------------------------------------------------------------------
ARC Realized
Prices Prior
to Hedging
Oil ($/bbl) 71.07 67.74 5 73.10 58.77 24
Natural gas
($/mcf) 3.79 3.25 17 4.39 4.05 8
NGL ($/bbl) 49.13 38.92 26 53.46 38.89 37
-------------------------------------------------------------------------
Total commodity
revenue before
hedging ($/boe) 41.14 41.31 - 45.98 40.00 15
Other revenue
($/boe) 0.05 0.08 (38) 0.08 0.11 (27)
-------------------------------------------------------------------------
Total revenue
before hedging
($/boe) 41.19 41.39 - 46.06 40.11 15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents posting price of West Texas Intermediate oil.
>>
Prior to hedging activities, ARC's total realized commodity price remained relatively unchanged at $41.14 per boe in the third quarter of 2010 compared to the third quarter of 2009, despite an increase in ARC's oil, natural gas, and NGL realized prices. The significant increase in the level of gas production and a steady level of liquids production over the past year has resulted in gas production contributing only 33 per cent of total revenue despite contributing 59 per cent to total production for the third quarter of 2010, compared to 24 per cent of total revenue and 51 per cent to total production in the third quarter of 2009.
Oil prices continued to recover in the third quarter of 2010 with WTI averaging US$76.21 per barrel compared to US$68.29 per barrel for the third quarter of 2009. Actual realized oil prices lagged behind WTI as a result of the strengthening of the Canadian dollar compared to the U.S. dollar and a widening of price differentials. The widening of the oil price differential in the Canadian market was primarily attributed to an oil pipeline rupture in the United States owned by a third-party company. ARC's crude oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than five per cent of the total. The realized price for ARC's oil, before hedging, was $71.07 per barrel, a five per cent increase over the third quarter 2009 realized price of $67.74 per barrel.
Benchmark natural gas prices increased by 23 per cent in the third quarter of 2010 compared to the third quarter of 2009. Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged $3.72 per mcf in the third quarter of 2010 compared to $3.03 per mcf in the same period of 2009. ARC's realized gas price, before hedging, increased by 17 per cent to $3.79 per mcf compared to $3.25 per mcf in the third quarter of 2009. Despite the increase in gas prices in the current quarter relative to the prior year's quarter, gas prices continue to remain weak, with ARC's realized gas price falling from $4.12 per mcf in the second quarter of 2010 to $3.79 per mcf in the third quarter of 2010. 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 mid-west United States markets and a portion to aggregators. The outlook on natural gas prices remains weak with North American storage levels remaining at near record highs for this time of year. The forward curve for natural gas prices continues to decline, with AECO prices expected to range from $3.50 to $4.50 per mcf for the fourth quarter of 2010.
Risk Management and Hedging Activities
ARC maintains a risk management program to reduce the volatility of revenues and 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 third quarter of 2010, ARC realized $25.3 million of cash gains on its risk management contracts. The largest contributor to the cash gains was $18.7 million recorded on ARC's natural gas swaps and natural gas basis swap contracts.
In addition, ARC recorded a $23.8 million unrealized mark-to-market gain on its risk management contracts, resulting in a net fair value of $110.5 million at September 30, 2010. The net gain position is primarily attributed to ARC's natural gas contracts, with the September 30, 2010 forward outlook on both AECO and NYMEX benchmark gas prices softening from June 30, 2010. The fair value of risk management contracts represent the expected market price to buy out ARC's contracts as of September 30, 2010 and may differ from what will eventually be realized.
In order to address the weak outlook on gas prices, in the third quarter of 2010 ARC added additional price protection for 2011 by reconfiguring an existing three year natural gas hedge into a 2011 hedge position. This has resulted in ARC protecting 128 mmcf per day of natural gas for 2011 at $5.85 per mcf. ARC currently produces approximately 300 mmcf per day of natural gas.
Table 11 summarizes the total gain (loss) on risk management contracts for the third quarter of 2010 compared to the same period in 2009:
<<
Table 11
-------------------------------------------------------------------------
Risk
Management
Contracts Crude Oil Natural Foreign Q3 2010 Q3 2009
($ millions) & Liquids Gas Currency Power(3) Total Total
-------------------------------------------------------------------------
Realized
cash gain
(loss) on
contracts(1) 3.3 18.7 3.6 (0.3) 25.3 6.7
Unrealized
gain (loss)
on
contracts(2) (8.2) 33.2 0.3 (1.5) 23.8 (0.7)
-------------------------------------------------------------------------
Total gain
(loss) on
risk
management
contracts (4.9) 51.9 3.9 (1.8) 49.1 6.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized gain (loss) on contracts represents the change in fair
value of the contracts during the period.
(3) Amounts presented in Table 11 exclude a $0.3 million realized loss
and a $0.2 million unrealized loss for ARC's power contracts that
have been designated as effective hedges for accounting purposes
(2009 - realized loss of $0.3 million and unrealized loss of
$0.4 million, respectively). Realized gains and losses on these
contracts are recorded in operating costs and unrealized gains and
losses are recorded in the Consolidated Statement of Comprehensive
Income and Accumulated Other Comprehensive Income.
>>
Table 11a summarizes the total gain (loss) on risk management contracts for the first nine months of 2010 compared to the same period in 2009:
<<
Table 11a
-------------------------------------------------------------------------
Risk
Management
Contracts Crude Oil Natural Foreign YTD 2010 YTD 2009
($ millions) & Liquids Gas Currency Power(3) Total Total
-------------------------------------------------------------------------
Realized
cash gain on
contracts(1) 6.5 33.3 5.2 0.4 45.4 21.1
Unrealized
gain (loss)
on
contracts(2) 8.0 102.5 0.4 3.2 114.1 (7.9)
-------------------------------------------------------------------------
Total gain
on risk
management
contracts 14.5 135.8 5.6 3.6 159.5 13.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized gain (loss) on contracts represents the change in fair
value of the contracts during the period.
(3) Amounts presented in Table 11a exclude a $0.3 million realized loss
and a $0.3 million unrealized gain for ARC's power contracts that
have been designated as effective hedges for accounting purposes
(2009 - realized losses of $1.1 million and unrealized losses of
$3.6 million, respectively). Realized gains and losses on these
contracts are recorded in operating costs and unrealized gains and
losses are recorded in the Consolidated Statement of Comprehensive
Income and Accumulated Other Comprehensive Income.
>>
ARC currently limits the amount of total forecast production that can be hedged to a maximum 55 per cent two years out with the remaining 45 per cent of production being sold at market prices. In addition, ARC's hedging policy allows for further hedging on volumes associated with new production arising from specific capital projects and acquisitions to the discretion of the board. The following table is an indicative summary of ARC's positions for crude oil and natural gas as at September 30, 2010.
<<
Table 12
-------------------------------------------------------------------------
Hedge Positions
As at September 30, 2010(1)
Q4 2010 2011 2012
-------------------------------------------------------------------------
Crude Oil(2) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 92.00 15,000 89.27 19,000 90.00 4,000
Bought Put 76.67 15,000 84.01 19,000 90.00 4,000
Sold Put 59.09 11,000 60.61 12,000 60.00 4,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Swap 5.61 87,110 5.54 135,000 - -
Sold Call 5.05 10,000 - - - -
Bought Put 4.00 10,000 - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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;
all calls have been sold against the annual average WTI price, as a
result ARC will only have a negative settlement if prices average
above the strike price for an entire year, providing ARC with greater
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 12 can be interpreted for approximate values for the fourth quarter of 2010:
<<
- If the market price exceeds $92 per barrel, ARC will receive $92 per
barrel on 15,000 barrels per day.
- If the market price is between $76.67 per barrel and $92 per barrel,
ARC will receive the market price on 15,000 barrels per day.
- If the market price is between $59.09 per barrel and $76.67 per
barrel, ARC will receive $76.67 per barrel on 15,000 barrels per day.
- If the market price is below $59.09 per barrel, ARC will receive
$76.67 per barrel less the difference between $59.09 per barrel and
the market price on 11,000 barrels per day. For example if the market
price is at $55 per barrel, ARC will receive $72.58 per barrel on
11,000 barrels per day and $76.67 per barrel on 4,000 barrels per
day.
>>
Operating Netbacks
ARC's operating netback, before realized hedging gains and losses, was unchanged at $24.30 per boe in the third quarter of 2010 compared to $24.35 per boe in the same period of 2009.
ARC's third quarter 2010 netback after realized hedging gains and losses, was $27.39 per boe, an eight per cent increase 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 $3.09 per boe compared to a gain of $1.12 per boe recorded for the same period in 2009.
The components of operating netbacks are summarized in Table 13:
<<
Table 13
-------------------------------------------------------------------------
Heavy Q3 2010 Q3 2009
Netbacks Crude Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted
average
sales price 71.42 61.74 3.79 49.13 41.14 41.31
Other revenue - - - - 0.05 0.08
-------------------------------------------------------------------------
Total revenue 71.42 61.74 3.79 49.13 41.19 41.39
Royalties (11.42) (6.80) (0.45) (16.63) (6.51) (6.53)
Transportation (0.34) (0.90) (0.26) - (1.07) (0.83)
Operating
costs(1) (13.61) (15.03) (1.13) (8.33) (9.31) (9.68)
-------------------------------------------------------------------------
Netback prior
to hedging 46.05 39.01 1.95 24.17 24.30 24.35
Realized gain
(loss) on risk
management
contracts(2) 1.39 - 0.74 - 3.09 1.12
-------------------------------------------------------------------------
Netback after
hedging 47.44 39.01 2.69 24.17 27.39 25.47
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 13a
-------------------------------------------------------------------------
Heavy YTD 2010 YTD 2009
Netbacks Crude Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted
average
sales price 73.45 64.27 4.39 53.46 45.98 40.00
Other revenue - - - - 0.08 0.11
-------------------------------------------------------------------------
Total revenue 73.45 64.27 4.39 53.46 46.06 40.11
Royalties (12.49) (7.90) (0.56) (17.09) (7.59) (5.86)
Transportation (0.28) (1.09) (0.29) - (1.11) (0.88)
Operating
costs(1) (13.50) (13.81) (1.28) (8.60) (9.98) (10.28)
-------------------------------------------------------------------------
Netback prior
to hedging 47.18 41.47 2.26 27.77 27.38 23.09
Realized gain
on risk
management
contracts(2) 0.91 - 0.52 - 2.07 0.88
-------------------------------------------------------------------------
Netback after
hedging 48.09 41.47 2.78 27.77 29.45 23.97
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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, remained effectively unchanged at 16.2 percent ($6.51 per boe) in 2010 compared to 16.1 per cent ($6.53 per boe) in the third quarter of 2009.
The Alberta Royalty Framework ("Framework" or "ARF") took effect January 1, 2009 and provides for sliding scale crown royalty rates whereby rates increase in high commodity price environments and decrease in low commodity price environments. The 2010 royalty rate is in line with management's expectations due to the low natural gas price environment.
Royalty rates in the other western provinces vary with production levels and price but to a lesser extent than Alberta royalty rates. Table 14 estimates the royalties applicable to production from ARC's properties at various price levels.
<<
Table 14
-------------------------------------------------------------------------
Edmonton posted oil (Cdn/$/bbl)(1) $60 $80
AECO natural gas (Cdn$/mcf)(1) $4.00 $5.50
-------------------------------------------------------------------------
Alberta royalty rate 12.8% 18.3%
Saskatchewan royalty rate(2) 17.8% 17.7%
British Columbia royalty rate(2) 17.0% 17.0%
Manitoba royalty rate(2) 13.0% 13.0%
-------------------------------------------------------------------------
Total Corporate Royalty Rate 14.7% 17.9%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 ARF, 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 September 30, 2010, ARC has received or accrued credits of $9.2 million and estimates it will generate approximately $14 million credit 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 $9.31 per boe in the third quarter of 2010 compared to $9.68 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 long-term incentive payments under the Whole Unit Plan and net of overhead recoveries on operated properties, increased 38 per cent to $14.1 million in the third quarter of 2010 from $10.2 million in 2009. The increase in G&A is mainly due to increased staffing levels required to execute ARC's growth prospects and the associated higher compensation levels in the third quarter of 2010 relative to the same period in 2009. In addition, ARC incurred an increase in rent expense due to the relocation of ARC's head office and one-time transaction costs of $0.8 million associated with the Storm acquisition. These increases to G&A were partially offset by higher operating recoveries from ARC's partners due to a larger capital program.
A cash payment was made under the Whole Unit Plan in September 2010 for $13.5 million, of which $9.5 million was recorded in G&A with the remaining $4 million recorded to operating costs and property, plant and equipment. This compares to a payment of $8.6 million in September 2009, of which $6.1 million was recorded in G&A. The September 2010 cash payment reflected a two times performance multiplier due to ARC trust units achieving top quartile total returns to its unitholders compared to its selected peer group. The next cash payment under the Whole Unit Plan is scheduled to occur in March 2011.
Table 15 is a breakdown of G&A and incentive compensation expense under the Whole Unit Plan:
<<
Table 15
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
G&A and Trust Unit
Incentive
Compensation
Expense
($ millions
except per boe) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
G&A expenses 18.1 13.5 34 55.8 42.1 33
Operating
recoveries (4.0) (3.3) 21 (11.6) (11.3) 3
-------------------------------------------------------------------------
Cash G&A expenses
before Whole
Unit Plan 14.1 10.2 38 44.2 30.8 44
Cash Expense -
Whole Unit Plan 9.5 6.1 56 20.5 11.7 75
-------------------------------------------------------------------------
Cash G&A expenses
including Whole
Unit Plan 23.6 16.3 45 64.7 42.5 52
Accrued
compensation -
Whole Unit Plan (4.4) (0.4) 100 (7.8) (4.0) 95
-------------------------------------------------------------------------
Total G&A and
incentive
compensation
expense 19.2 15.9 21 56.9 38.5 48
-------------------------------------------------------------------------
Total G&A and
incentive
compensation
expense per
boe 2.72 2.75 (1) 2.96 2.20 35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
A non-cash Whole Unit Plan recovery of $4.4 million ($0.62 per boe) was recorded in the third quarter of 2010 compared to $0.4 million ($0.07 per boe) in the third quarter of 2009. The expense recorded fluctuates from quarter to quarter based on the value of the underlying trust unit and the amount of Whole Unit Plan grants outstanding.
Whole Unit Plan
The Whole Unit Plan is designed to offer each employee, officer and director (the "plan participants") cash compensation in relation to the value of a specified number of underlying trust units. The Whole Unit Plan consists of Restricted Trust Units ("RTUs") for which the number of units is fixed and will vest over a period of three years and Performance Trust Units ("PTUs") for which the number of units is variable and will vest at the end of three years.
Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying trust units plus accrued distributions. The cash compensation issued upon vesting of the PTUs is dependent upon the total return performance of ARC compared to its peers. Total return is calculated as a sum of the change in the market price of the trust units in the period plus the amount of distributions in the period. A performance multiplier is applied to the PTUs based on the percentile rank of ARC's total unitholder return compared to its peers. The performance multiplier ranges from zero, if ARC's performance ranks in the bottom quartile, to two for top quartile performance.
Table 16 shows the changes to the Whole Unit Plan during the first nine months of 2010 along with the estimated value upon vesting of the plan as at September 30, 2010:
<<
Table 16
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and Number of Number of Total RTUs
$ millions except per unit) RTUs PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 1,052 1,305 2,357
Granted in the period 504 459 963
Vested in the period (459) (321) (780)
Forfeited in the period (64) (120) (184)
-------------------------------------------------------------------------
Balance, end of period(1) 1,033 1,323 2,356
Estimated distributions to vesting
date(2) 65 116 181
-------------------------------------------------------------------------
Estimated units upon vesting after
distributions 1,098 1,439 2,537
Performance multiplier(3) - 0.9 -
-------------------------------------------------------------------------
Estimated total units upon vesting 1,098 1,336 2,434
-------------------------------------------------------------------------
Trust unit price at September 30, 2010 20.55 20.55 20.55
Estimated total value upon vesting
($ millions) 22.6 27.4 50.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on underlying units before performance multiplier and accrued
distributions.
(2) Represents estimated additional units to be issued equivalent to
estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and was estimated to
be 0.9 at September 30, 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 RTUs and PTUs is expensed in the statement of income and deficit over the vesting period with the expense amount being determined by the trust unit price, the number of PTUs to be issued on vesting, and distributions. In periods where substantial trust unit price fluctuation occurs, ARC's G&A expense is subject to significant volatility.
Table 17 is a summary of the range of future expected payments under the Whole Unit Plan based on variability of the performance multiplier and units outstanding under the Whole Unit Plan as at September 30, 2010:
<<
Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan
as at September 30, 2010 Performance multiplier
(units thousands and $ millions -------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated units to vest
RTUs 1,098 1,098 1,098
PTUs - 1,439 2,878
-------------------------------------------------------------------------
Total units(1) 1,098 2,537 3,976
-------------------------------------------------------------------------
Trust unit price(2) 20.55 20.55 20.55
Trust unit distributions per month(2) 0.10 0.10 0.10
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting(3) 22.6 52.1 81.7
-------------------------------------------------------------------------
2011 11.2 18.8 26.6
2012 8.1 20.8 33.5
2013 3.3 12.5 21.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes additional estimated units to be issued under the Whole Unit
Plan for accrued distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumes a
future trust unit price of $20.55 and $0.10 per trust unit
distributions based on the unit price and distribution levels in
place at September 30, 2010.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in March
and September of each year and at that time is reflected as a
reduction of cash flow from operating activities.
>>
Due to the variability in the future payments under the plan, ARC estimates that between $22.6 million and $81.7 million will be paid out from 2011 through 2013 based on the current trust unit price, distribution levels and ARC's market performance relative to its peers.
Interest and financing charges
Interest and financing charges increased to $13.6 million in the third quarter of 2010 from $6.4 million in 2009 as a result of financing charges incurred on the renewal of ARC's credit facility coupled with increased debt servicing costs associated with the renewed facility. As at September 30, 2010, ARC has $788.8 million of long-term debt outstanding, of which $475 million was fixed at a weighted average interest rate of 5.8 per cent. On the remaining $313.8 million, ARC currently pays a floating interest rate based on current market rates plus a credit spread of 225 basis points. Approximately 57 per cent (US$433 million) of ARC's debt outstanding is denominated in U.S. dollars.
Foreign Exchange Gains and Losses
ARC recorded a gain of $13.5 million in the third quarter of 2010 on foreign exchange transactions compared to a gain of $34.9 million in 2009. These amounts include both realized and unrealized foreign exchange gains and losses.
Table 18 shows the various components of foreign exchange gains and losses:
<<
Table 18
-------------------------------------------------------------------------
Foreign Exchange Three Months Ended Nine Months Ended
Gains/Losses September 30 September 30
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Unrealized gain
(loss) on U.S.
denominated
debt 13.5 32.4 (58) (16.3) 60.6 (127)
Realized gain
(loss) on U.S.
denominated
debt - 2.5 (100) 28.3 (0.5) -
Realized (loss)
gain on U.S.
denominated
transactions - - - (0.3) 0.2 (250)
-------------------------------------------------------------------------
Total foreign
exchange gain 13.5 34.9 (61) 11.7 60.3 (81)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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 third 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 June 30, 2010 to September 30, 2010, the Cdn$/US$ exchange rate decreased from 1.06 to 1.03 resulting in an unrealized gain of $13.5 million on U.S. dollar denominated debt.
Taxes
In the third quarter of 2010, a future income tax recovery of $2.8 million was recorded compared to $5.7 million in 2009.
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 third quarter of 2010. Currently, ARC's structure is such that both income tax and future tax liabilities are passed on to the Unitholders by means of royalty payments made between ARC Resources and the Trust.
ARC plans to convert to a dividend paying corporation effective January 1, 2011. The board of directors has approved the overall conversion strategy with detailed implementation steps to be outlined in an information circular to be sent to Unitholders in November prior to a joint meeting of securityholders of ARC Energy Trust and ARC Resources Ltd. on December 15, 2010. If a conversion from the trust structure to a corporation is approved by the Unitholders, ARC expects there will be an opportunity to convert trust units to shares of the new corporation in a non-taxable manner. However, Unitholders should consult their own tax advisor for details on the direct impact to themselves. In addition, current plans would see a dividend policy similar to the existing distribution policy with dividends being paid monthly.
Following the conversion, the corporation expects to allocate its after-tax cash flow to fund a portion of capital expenditures, periodic debt repayments, site reclamation expenditures, and cash payments to shareholders in the form of dividends. Current taxes payable by ARC after converting to a corporation will be subject to normal corporate tax rates. Taxable income as a corporation will vary depending on total income and expenses and vary with changes to commodity prices, costs, claims for both accumulated tax pools and tax pools associated with current year expenditures. As ARC has accumulated $2.4 billion of income tax pools for federal tax purposes, taxable income will be reduced or potentially eliminated for the initial period post conversion. Using the current forward commodity price outlook and a modeled future production volume forecast, ARC does not expect to be in a material cash tax paying position until 2014. The income tax pools (detailed in Table 19) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.
<<
Table 19
-------------------------------------------------------------------------
Cdn$ millions at
Income Tax Pool type September 30, 2010 Annual deductibility
-------------------------------------------------------------------------
Canadian Oil and Gas
Property Expense 987.5 10% declining balance
Canadian Development Expense 500.2 30% declining balance
Canadian Exploration Expense 93.8 100%
Undepreciated Capital Cost 596.4 Primarily 25%
declining balance
Non-Capital Losses 214.0 100%
Research and Experimental
Expenditures 22.2 100%
Other 28.8 Various rates, 7%
declining balance to 20%
-------------------------------------------------------------------------
Total Federal Tax Pools 2,442.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Additional Alberta Tax Pools 177.6 Various rates, 25%
declining balance to 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
After conversion, returns to shareholders are expected to be impacted by the reduction of cash flow required to pay current income taxes, if any. Over the long term, we would expect Canadian investors who hold their trust units in a taxable account to be relatively indifferent on an after-tax basis as to whether ARC is structured as a corporation or as a trust after 2010. However, Canadian tax deferred investors (those holding their trust units in a tax-deferred vehicle such as an RRSP, RRIF or pension plan) and foreign investors will realize a lower after-tax return on distributions in taxable years after 2010 due to the introduction of the SIFT Tax should ARC remain as a trust, and their inability to claim the dividend tax credit if ARC converts to a corporation. Again, ARC unitholders should consult with their own tax advisor for advice with respect to the tax consequences of the conversion to their own particular circumstances.
Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate increased to $17.62 per boe in the third quarter of 2010 from $16.55 per boe in the third quarter of 2009. The increase related primarily to the acquisition of Storm, to which ARC added both proved and probable reserves to its asset base but only recognized proved reserves for the purposes of the depletion rate calculation. As such, actual depletion expense has increased from $93.3 million in the third quarter of 2009 to $122.1 million due to the increase in the DD&A rate as well as an increase in volumes of 23 per cent in the comparable periods. In the second quarter of 2010, ARC relocated to a new head office and began depreciating the associated leasehold improvements and construction costs. In previous periods, nominal depreciation had been recognized.
A breakdown of the DD&A rate is summarized in Table 20:
<<
Table 20
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
DD&A Rate
($ millions
except per
boe amounts) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Depletion of oil
and gas
assets(1) 122.1 93.3 31 319.6 283.3 13
Depreciation of
fixed assets 1.1 - 100 1.9 - 100
Accretion of asset
retirement
obligation(2) 2.4 2.4 - 7.3 7.0 4
-------------------------------------------------------------------------
Total DD&A 125.6 95.7 31 328.8 290.3 13
DD&A rate
per boe 17.62 16.55 6 17.12 16.65 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 $159.5 million in the third quarter of 2010 compared to $96.2 million in the same period of 2009. This amount was incurred on drilling and completions, geological, geophysical, facilities expenditures, and undeveloped land.
Of the total amount spent in the third quarter, $99.4 million was spent on ARC's resource plays, including $86.5 million for the Montney resource play in northeast British Columbia and $10.3 million for the Cardium resource play in Alberta. A total of $53 million was spent on ARC's conventional oil and gas properties, $4.5 million on ARC's enhanced oil recovery initiatives, and the balance of $2.6 million was spent on corporate capital items. Total capital expenditures are forecast to be $625 million in 2010.
A breakdown of capital expenditures and net acquisitions is shown in Table 21:
<<
Table 21
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
Capital
Expenditures
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Geological and
geophysical 0.2 3.0 (93) 10.4 10.8 (4)
Drilling and
completions 96.0 61.0 57 258.1 148.1 74
Plant and
facilities 32.1 26.1 23 88.5 74.8 18
Undeveloped land
purchased at
crown land
sales 28.6 4.5 536 54.0 4.9 -
Other capital 2.6 1.6 63 20.8 3.7 462
-------------------------------------------------------------------------
Total capital
expenditures
before net
acquisitions 159.5 96.2 66 431.8 242.3 78
-------------------------------------------------------------------------
Producing
property
acquisitions(1) 1.4 6.8 (79) 7.7 7.0 10
Undeveloped
land property
acquisitions - 0.4 (100) - 8.7 (100)
Producing
property
dispositions(1) (3.5) (37.3) (91) (3.5) (37.3) (91)
Corporate
acquisition(2) 652.1 - - 652.1 - -
-------------------------------------------------------------------------
Total capital
expenditures
and net
acquisitions 809.5 66.1 - 1,088.8 220.7 393
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
(2) Represents total consideration paid for the corporate acquisition.
>>
During the third quarter of 2010, ARC completed a $652.1 million acquisition of Storm. The fair values of net assets acquired are shown in Table 21a:
<<
Table 21a
-------------------------------------------------------------------------
Storm Fair Value of Net Assets
($ millions) August 17, 2010
-------------------------------------------------------------------------
Property, plant and equipment 712.7
Goodwill 85.6
Asset retirement obligation (15.0)
Future income tax liability (130.3)
Other (0.9)
-------------------------------------------------------------------------
Total fair value of net assets acquired 652.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
On a regular basis, ARC evaluates its asset portfolio to ensure that all assets still meet our needs with the view to selling assets that do not meet our retention guidelines. ARC has engaged a third party to market lands in central Alberta that currently produce approximately 3,500 boe per day. While ARC expects that one or more transactions will close prior to year-end 2010, there is no certainty that the sales will occur.
Approximately 65 per cent of the $159.5 million capital program in the third quarter of 2010 was financed with cash flow from operating activities and proceeds from DRIP compared to 72 per cent for the same period of 2009. On a year-to-date basis, ARC has funded 72 per cent of the capital expenditures with cash flow from operating activities and proceeds from DRIP, similar to the first nine months of 2009. Net acquisitions of $650 million for the third quarter of 2010 primarily relate to the acquisition of Storm for $652.1 million of which $555.4 million was funded through equity issuance and the remaining $96.7 million funded through the assumption of Storm debt (net of Storm cash).
<<
Table 22
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30, 2010 September 30, 2009
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions(1) itures itures itions itures
-------------------------------------------------------------------------
Expenditures 159.5 650.0 809.5 96.2 (30.1) 66.1
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating
activities 53% - 10% 55% - 80%
Proceeds from DRIP 12% - 2% 17% - 24%
Proceeds from equity - 85% 69% - - -
Debt/(excess funding) 35% 15% 19% 28% 100% (4%)
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 22a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Nine Months Ended Nine Months Ended
September 30, 2010 September 30, 2009
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions(1) itures itures itions itures
-------------------------------------------------------------------------
Expenditures 431.8 656.4 1,088.2 242.3 (21.6) 220.7
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating
activities 60% - 24% 51% - 56%
Proceeds from DRIP 12% - 5% 21% - 23%
Proceeds from equity - 85% 51% - - -
Debt 28% 15% 20% 28% 100% 21%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net acquisitions for corporate acquisitions represents total
consideration paid for the corporate acquisition.
>>
Asset Retirement Obligation and Reclamation Fund
At September 30, 2010, ARC recorded an Asset Retirement Obligation ("ARO") of $162.9 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 September 30, 2010 ARO balance is $15 million of additional ARO related to the Storm acquisition, a $1.3 million increase related to development activities, a decrease of $5.5 million relating to the change in estimated future obligations, $7.3 million for accretion expense, and a reduction of $5.1 million for actual abandonment expenditures incurred in the first nine months of 2010.
ARC has established two reclamation funds to finance future asset retirement obligations; one fund has been restricted to finance obligations specifically associated with the Redwater property, with the general fund financing all other obligations. Minimum contributions to the Redwater fund over the next 46 years will be approximately $86 million. The general fund has no minimum contribution requirement; however, the board of directors has approved voluntary contributions that will result in contributions of $6 million for 2010.
ARC's reclamation funds totaled $33.3 million as at September 30, 2010, compared to $33.2 million as at December 31, 2009. Under the terms of ARC's investment policy, reclamation fund investments and excess cash can only be invested in Canadian or U.S. Government securities, investment grade corporate bonds, or investment grade short-term money market securities.
Capitalization, Financial Resources and Liquidity
A breakdown of ARC's capital structure is outlined in Table 23, as at September 30, 2010 and December 31, 2009:
<<
Table 23
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per cent September 30, December 31,
and ratio amounts) 2010 2009
-------------------------------------------------------------------------
Long-term debt 788.8 846.1
Working capital deficit(1) 82.3 56.3
-------------------------------------------------------------------------
Net debt obligations(2) 871.1 902.4
Market value of trust units and
exchangeable shares(3) 5,817.7 4,765.7
-------------------------------------------------------------------------
Total capitalization(4) 6,688.8 5,668.1
-------------------------------------------------------------------------
Net debt as a percentage of
total capitalization 13.0% 15.9%
Net debt to annualized YTD 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 short-term investment, current unrealized amounts
pertaining to risk management contracts and the current portion of
future income taxes.
(2) Net debt is a non-GAAP measure and therefore it may not be comparable
with the calculation of similar measures for other entities.
(3) Calculated using the total trust units outstanding at September 30
and December 31 including the total number of trust units issuable
for exchangeable shares at September 30 and December 31 multiplied by
the closing trust unit price of $20.55 and $19.94 at September 30,
2010 and December 31, 2009, respectively.
(4) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by ARC.
>>
At September 30, 2010, ARC had total credit facilities of $1.6 billion with $788.8 million currently drawn resulting in unused credit available of $813 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 are made up of a banking syndicate that includes 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 U.S. Base Rate Loans (U.S. denominated borrowings) and second, ARC's credit spread. The credit spread to ARC in 2009 and 2010 ranged between 60 and 70 basis points on all Bankers' Acceptances and LIBOR Loans. No Prime Loans or U.S. Base Rate Loans were drawn during this period. Under the new bank credit facilities, the credit spread has increased to a range between 200 and 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 in 2009 and 2010 and increased to 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 September 30, 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 Unitholders' 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 the third quarter debt to cash flow from operating activities ratio was 1.3 times. This ratio is expected to remain steady for the remainder of the year assuming commodity prices remain stable.
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 2010 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.
Unitholders' Equity
At September 30, 2010, there were 283.1 million trust units issued and issuable for exchangeable shares, an increase of 44.2 million trust units 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 as part of an equity offering 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.
Unitholders electing to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP may do so at a five per cent discount to the prevailing market price with no additional fees or commissions. During the first nine months of 2010, ARC raised proceeds of $50.6 million and issued 2.6 million trust units pursuant to the DRIP at an average price of $19.59 per unit.
Distributions
In the third quarter of 2010, ARC declared distributions of $80.3 million ($0.30 per unit), representing 48 per cent of 2010 third quarter cash flow from operating activities compared to distributions of $70.6 million ($0.30 per unit) representing 56 per cent of cash flow from operating activities in the third quarter of 2009.
The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders:
<<
- a portion of capital expenditures;
- annual contribution to the reclamation funds;
- debt principal repayments;
- income tax, if any; and
- certain obligations for future payments relative to the long-term
incentive compensation under the Whole Unit Plan.
>>
Cash flow from operating activities and distributions in total and per unit are summarized in Table 24 and Table 24a:
<<
Table 24
-------------------------------------------------------------------------
Cash flow from Three Months Ended Three Months Ended
operating September 30 September 30
activities and 2010 2009 % Change 2010 2009 % Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 166.2 125.6 32 0.62 0.53 17
Net reclamation
fund
contributions(1) (1.2) (2.3) 48 - (0.01) -
Capital
expenditures
funded with cash
flow from
operating
activities (84.7) (52.7) 61 (0.32) (0.22) 45
Other(2) - - - - - -
-------------------------------------------------------------------------
Distributions 80.3 70.6 14 0.30 0.30 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 24a
-------------------------------------------------------------------------
Cash flow from Nine Months Ended Nine Months Ended
operating September 30 September 30
activities and 2010 2009 % Change 2010 2009 % Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 487.7 354.2 38 1.89 1.51 25
Net reclamation
fund withdrawals
(contributions)(1) 0.2 (3.1) 106 - (0.01) -
Capital
expenditures
funded with cash
flow from
operating
activities (257.3) (123.5) 108 (1.00) (0.53) 89
Other(2) - - - 0.01 0.01 -
-------------------------------------------------------------------------
Distributions 230.6 227.6 1 0.90 0.98 (8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operated activities are based on weighted average outstanding trust
units (including weighted average trust units issuable for
exchangeable shares).
>>
ARC continually assesses distribution levels in light of commodity prices, capital expenditure programs and production volumes, to ensure that distributions are in line with the long-term strategy and objectives of ARC as per the following guidelines:
<<
- To maintain a level of distributions that, in normal times, in the
opinion of management and the board of directors, is sustainable for
a minimum period of six months after factoring in the impact of
current commodity prices on cash flows. ARC's objective is to
normalize the effect of volatility of commodity prices rather than to
pass that volatility on to Unitholders in the form of fluctuating
monthly distributions.
- To ensure that ARC's financial flexibility is maintained by a review
of ARC's debt to equity and debt to cash flow from operating
activities levels. The use of cash flow from operating activities and
proceeds from equity offerings to fund capital development activities
reduces the requirements of ARC to use debt to finance these
expenditures. In the first nine months of 2010, ARC funded 72 per
cent of capital development activities with a portion of cash flow
from operating activities and DRIP proceeds. Distributions and the
actual amount of cash flows withheld to fund ARC's capital
expenditure program is dependent on the commodity price environment
and is subject to the approval and discretion of the board of
directors.
>>
A measure of sustainability is the comparison of net income to distributions. Net income incorporates all costs including depletion expense and other non-cash expenses whereas cash flow from operating activities measures the cash generated in a given period before the cost of acquiring or replacing the associated reserves produced. Therefore, net income may be more representative of the profitability of the entity and thus a relevant measure against which to measure distributions to illustrate sustainability. As net income is sensitive to fluctuations in commodity prices and the impact of risk management contracts, currency fluctuations and other non-cash items, it is expected that there will be deviations between annual net income and distributions.
Table 25 illustrates the comparison of distributions to net income as a measure of long-term sustainability. With the decline in commodity prices in 2009 relative to 2008, distributions were reduced from $0.15 per unit per month in December 2008, to $0.12 per unit per month in January 2009, and subsequently to the current rate of $0.10 per unit per month in May 2009.
<<
Table 25
-------------------------------------------------------------------------
Nine months
Net income and Distributions ended
($ millions except per cent and September 30, Full year Full year
per unit amounts) 2010 2009 2008
-------------------------------------------------------------------------
Net income 267.1 225.1 539.9
Distributions 230.6 298.5 570.0
-------------------------------------------------------------------------
Excess (Shortfall) 36.5 (73.4) (30.1)
Excess (Shortfall) as per cent
of net income 14% (33%) (6%)
-------------------------------------------------------------------------
Cash flow from operating activities 487.7 497.4 944.4
Distributions as a per cent of cash
flow from operating activities 47% 60% 60%
Average distribution per unit per
month $0.10 $0.11 $0.22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
The actual amount of future monthly distributions is proposed by management and is subject to the approval and discretion of the board of directors. The board reviews future distributions in conjunction with their review of quarterly financial and operating results.
<<
Table 26
-------------------------------------------------------------------------
Calendar Year Distributions Taxable Portion Return of Capital
-------------------------------------------------------------------------
2010 YTD(2) 0.90 0.87 0.03
2009 1.28 1.24 0.04
2008 2.67 2.62 0.05
2007 2.40 2.32 0.08
2006(1) 2.60 2.55 0.05
2005 1.94 1.90 0.04
2004 1.80 1.69 0.11
2003 1.78 1.51 0.27
2002 1.58 1.07 0.51
2001 2.41 1.64 0.77
2000 1.86 0.84 1.02
1999 1.25 0.26 0.99
1998 1.20 0.12 1.08
1997 1.40 0.31 1.09
1996 0.81 - 0.81
-------------------------------------------------------------------------
Cumulative $25.88 $18.94 $6.94
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on distributions paid and payable in 2006.
(2) Based on distributions declared at September 30, 2010 and estimated
taxable portion of 2010 distributions of 97 per cent.
>>
Please refer to ARC's website at www.arcresources.com for details of the monthly distribution amounts and distribution dates for 2010.
Taxation of Distributions
Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable). The return of capital component reduces the cost basis of the trust units held. For a more detailed breakdown, please visit our website at www.arcresources.com.
Environmental Initiatives Impacting ARC
There are no new material environmental initiatives impacting ARC at this time.
Contractual Obligations and Commitments
ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC's cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 27.
<<
Table 27
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
Beyond 5
($ millions) 1 year 2-3 years 4-5 years years Total
-------------------------------------------------------------------------
Debt repayments(1) 28.3 389.7 85.5 285.3 788.8
Interest payments(2) 27.0 49.8 39.7 60.9 177.4
Reclamation fund
contributions(3) 4.9 8.9 7.7 64.2 85.7
Purchase commitments 31.1 28.1 12.8 10.4 82.4
Transportation
commitments 9.5 31.3 26.6 9.0 76.4
Operating leases 7.1 15.8 14.8 66.5 104.2
Risk management
contract premiums(4) 3.0 2.0 - - 5.0
-------------------------------------------------------------------------
Total contractual
obligations 110.9 525.6 187.1 496.3 1,319.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 9 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 September 30, 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 2010 capital budget of $625 million has been approved by the board of directors. The remaining portion of this commitment, as at September 30, 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 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 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 September 30, 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 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. They include, but are not limited to:
<<
- volatility of oil and natural gas prices;
- refinancing and debt service;
- counterparty risk;
- variations in interest rates and foreign exchange rates;
- reserves estimates;
- changes in income tax legislation;
- changes in government royalty legislation;
- acquisitions;
- environmental concerns and impact on enhanced oil recovery projects;
- operational matters;
- depletion of reserves and maintenance of distribution; and
- project risks.
>>
Internal Control over Financial Reporting
ARC is required to comply with National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to as Canadian SOX ("C-Sox"). The certification of interim filings for the interim period ended September 30, 2010 requires that ARC disclose in the interim MD&A any changes in ARC's internal control over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect ARC's internal control over financial reporting. ARC confirms that no such changes were made to the internal controls over financial reporting during the first nine months of 2010.
Financial Reporting Update
New Accounting Standards Adopted
During the third quarter of 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.
In 2008, ARC commenced the process to transition its financial statements from current Canadian GAAP to IFRS and has been progressing towards completion throughout 2009 and into 2010. ARC's project consists of three key phases: the scoping and diagnostic phase, the impact analysis and evaluation phase and the implementation phase. A wholesome description of ARC's IFRS project phases and ARC's progress to the end of 2009 is contained within ARC's MD&A for the year ended December 31, 2009.
Throughout the third quarter of 2010, the process of training key accounting and finance personnel as well as the senior management team has continued, with individuals within the financial reporting group continuing to participate in various seminars and industry discussion groups regarding the application of current IFRSs and potential future changes to the standards.
Internal staff within the financial reporting group continue to lead the conversion project along with sponsorship from the management team. The project continues to progress according to the project plan and ARC expects to be completed in time to meet its 2011 financial reporting requirements.
Many of the differences between IFRS and Canadian GAAP have now been quantified. ARC has not yet prepared a full set of annual financial statements under IFRS, therefore, amounts are unaudited. In some areas, the impacts of identified differences are still being determined. In June 2010, management presented a draft opening balance sheet and draft first quarter 2010 statement of income and balance sheet prepared under IFRS as well as key accounting policy choices to the audit committee for their review. The audit committee has approved ARC's IFRS accounting policy selections that have been presented by management to date as disclosed herein.
Throughout the third quarter the project team focused on presentation and disclosure requirements under IFRS. Draft financial statements and note disclosures are being prepared and will be presented to the audit committee in the fourth quarter for their review.
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:
<<
- 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 Sheet. 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 PP&E 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 nine months ended
September 30, 2010 would be reduced by approximately $2.30 per boe of
production or approximately $45 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. It is expected that the asset retirement obligation will
increase $148.2 million at January 1, 2010 to $298.1 million upon
transition to IFRS if the liability is revalued to reflect the
estimated risk-free rate of interest at that time of 4.08 per cent.
If the liability is to be discounted using ARC's credit-adjusted
risk-free rate of interest of 6.52 per cent, the asset retirement
obligation calculated under Canadian GAAP at January 1, 2010 of
$149.9 is not expected to materially change. The offset to any
increase will be recorded as an increase to deficit.
- Exchangeable shares - Under IFRS, exchangeable shares are considered
a puttable financial instrument and will be 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.
>>
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 been
assessing its stakeholders' information requirements and will ensure
that adequate and timely information is provided to meet these needs.
ARC management delivered an investor presentation in August 2010 to
explain the most significant expected changes from its financial
statements prepared under Canadian GAAP statements to those prepared
under IFRS. The presentation is available on the ARC website at
www.arcresources.com.
- 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 expected changes to ARC's accounting
policies at this time, no issues are expected 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 provides an update on IFRS as it relates to ARC so that
management can communicate any potential issues as final accounting
policy choices are made.
- IT systems - ARC has completed the accounting system updates required
in order to ready the company for IFRS reporting. The modifications
were not significant, however, deemed critical in order to allow for
reporting of both Canadian GAAP and IFRS statements in 2010 as well
as the modifications required to track PP&E 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 distributions as a per cent of cash flow from operating activities, operating netbacks ("netbacks"), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, reserves per unit and production per unit, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for ARC. These KPIs and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities.
Forward-looking Information and Statements
This MD&A contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this MD&A contains forward-looking information and statements pertaining to the following: all of the matters under the heading "2010 Guidance and Financial Highlights" which contains guidance for 2010, the future expenditure plans for 2010 and expected production and operations under the heading "Production", the expectations regarding the pricing of natural gas for 2010 under the heading "Commodity Prices Prior to Hedging", the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia and future operating costs under the heading "Operating Netbacks", the plans for converting ARC Energy Trust to a corporation and the payment of income taxes in the future by ARC and the availability of a non-taxable conversion of trust units to shares on the conversion of the trust structure to a corporation under the heading "Taxes", the information as to total capital expenditures forecasted for 2010 under the heading "Capital Expenditures and Net Acquisitions", the information relating to financing the 2010 capital expenditures under the heading: "Capitalization, Financial Resources and Liquidity", 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.
<<
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2010 2009
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 293.6 276.7 314.1 278.6
Per unit(1) 1.10 1.09 1.25 1.17
Cash flow from operating activities 166.2 162.8 158.7 143.2
Per unit - basic and diluted(1) 0.62 0.64 0.63 0.60
Net income 81.0 45.4 140.7 66.2
Per unit - basic and diluted(1) 0.30 0.18 0.56 0.28
Distributions 80.3 75.3 75.0 70.9
Per unit(2) 0.30 0.30 0.30 0.30
Total assets 4,948.6 4,068.5 4,020.1 3,914.5
Total liabilities 1,689.0 1,384.3 1,322.4 1,540.1
Net debt outstanding(3) 871.1 728.8 677.8 902.4
Weighted average trust units(4) 268.0 253.2 251.8 238.5
Trust units outstanding and
issuable(4) 283.1 253.6 252.8 239.0
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 0.2 3.6 6.6 2.9
Land 28.6 21.5 3.9 2.0
Drilling and completions 96.0 84.9 77.2 66.1
Plant and facilities 32.1 26.9 29.5 35.3
Other capital 2.6 7.1 11.1 11.0
Total capital expenditures 159.5 144.0 128.3 117.3
Property (dispositions)
acquisitions, net (2.1) - 6.3 1.1
Corporate acquisitions 652.1 - - 178.9
-------------------------------------------------------------------------
Total capital expenditures and
net acquisitions 809.5 144.0 134.6 297.3
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 26,959 27,354 27,640 27,415
Natural gas (mmcf/d) 275.0 211.2 217.9 189.0
Natural gas liquids (bbl/d) 4,690 3,655 3,252 3,597
Total (boe per day 6:1) 77,483 66,208 67,207 62,520
Average prices
Crude oil ($/bbl) 71.07 71.98 76.26 72.61
Natural gas ($/mcf) 3.79 4.12 5.42 4.58
Natural gas liquids ($/bbl) 49.13 53.02 60.33 46.12
Oil equivalent ($/boe) 41.14 45.82 51.85 48.35
-------------------------------------------------------------------------
TRUST UNIT TRADING PRICES
(based on intra-day trading)
High 20.95 22.33 22.49 21.89
Low 19.02 19.20 19.80 19.06
Close 20.55 19.73 20.50 19.94
Average daily volume (thousands) 1,160 1,043 1,287 963
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2009 2008
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 239.2 235.2 225.2 300.8
Per unit(1) 1.01 0.99 0.98 1.38
Cash flow from operating activities 125.6 104.3 124.3 209.4
Per unit - basic and diluted(1) 0.53 0.44 0.54 0.96
Net income 69.6 66.8 22.5 83.6
Per unit - basic and diluted(1) 0.29 0.28 0.10 0.38
Distributions 70.6 75.0 82.0 127.2
Per unit(2) 0.30 0.32 0.36 0.59
Total assets 3,642.9 3,672.5 3,733.1 3,766.7
Total liabilities 1,278.4 1,323.1 1,392.1 1,624.6
Net debt outstanding(3) 705.4 737.6 781.5 961.9
Weighted average trust units(4) 237.7 236.6 228.9 218.3
Trust units outstanding and
issuable(4) 238.1 237.1 236.0 219.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.0 5.0 2.8 3.7
Land 4.5 0.2 0.2 17.1
Drilling and completions 61.0 18.6 68.5 117.1
Plant and facilities 26.1 23.6 25.1 30.5
Other capital 1.6 1.5 0.6 1.0
Total capital expenditures 96.2 48.9 97.2 169.4
Property (dispositions)
acquisitions, net (30.1) 2.3 6.2 27.6
Corporate acquisitions - - - -
-------------------------------------------------------------------------
Total capital expenditures and
net acquisitions 66.1 51.2 103.4 197.0
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 26,921 26,917 28,806 28,935
Natural gas (mmcf/d) 193.1 200.2 193.8 195.1
Natural gas liquids (bbl/d) 3,717 3,679 3,764 3,858
Total (boe per day 6:1) 62,824 63,969 64,872 65,313
Average prices
Crude oil ($/bbl) 67.74 62.74 46.44 56.26
Natural gas ($/mcf) 3.25 3.73 5.20 7.48
Natural gas liquids ($/bbl) 38.92 38.89 38.86 45.22
Oil equivalent ($/boe) 41.31 40.32 38.40 49.93
-------------------------------------------------------------------------
TRUST UNIT TRADING PRICES
(based on intra-day trading)
High 20.20 19.25 20.90 22.55
Low 15.48 14.12 11.73 15.01
Close 20.20 17.81 14.15 20.10
Average daily volume (thousands) 1,038 988 1,240 1,523
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus weighted
average trust units issuable for exchangeable shares.
(2) Based on number of trust units outstanding at each distribution date.
(3) Net debt excludes short-term investment, current unrealized amounts
pertaining to risk management contracts and the current portion of
future income taxes.
(4) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
CONSOLIDATED BALANCE SHEETS (unaudited)
As at September 30 and December 31
(Cdn$ millions) 2010 2009
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 0.3 $ -
Short-term investment (Note 9) 3.8 -
Accounts receivable (Note 4) 143.9 115.9
Prepaid expenses 17.1 18.2
Risk management contracts (Note 9) 83.1 5.9
Future income taxes - 7.1
-------------------------------------------------------------------------
248.2 147.1
Reclamation funds 33.3 33.2
Risk management contracts (Note 9) 27.5 3.2
Property, plant and equipment 4,396.4 3,573.4
Goodwill (Note 3) 243.2 157.6
-------------------------------------------------------------------------
Total assets $ 4,948.6 $ 3,914.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 216.0 $ 166.7
Distributions payable 27.6 23.7
Risk management contracts (Note 9) 0.2 12.9
Future income taxes 18.2 -
-------------------------------------------------------------------------
262.0 203.3
Risk management contracts (Note 9) 0.1 1.0
Long-term debt (Note 6) 788.8 846.1
Other long-term liabilities 35.4 10.9
Asset retirement obligations (Note 7) 162.9 149.9
Future income taxes 439.8 328.9
-------------------------------------------------------------------------
Total liabilities 1,689.0 1,540.1
-------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 15)
UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 3,662.4 2,917.6
Non-controlling interest (Note 10) 142.7 36.0
Deficit (Note 12) (545.4) (578.6)
Accumulated other comprehensive loss (Note 12) (0.1) (0.6)
-------------------------------------------------------------------------
Total unitholders' equity 3,259.6 2,374.4
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 4,948.6 $ 3,914.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For the three and nine months ended September 30
Three Months Ended Nine Months Ended
September 30 September 30
(Cdn$ millions, except
per unit amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and
natural gas liquids $ 293.6 $ 239.2 $ 884.4 $ 699.6
Royalties (46.4) (37.7) (145.8) (102.2)
-------------------------------------------------------------------------
247.2 201.5 738.6 597.4
Gain (loss) on risk management
contracts (Note 9)
Realized 25.3 6.7 45.4 21.1
Unrealized 23.8 (0.7) 114.1 (7.9)
-------------------------------------------------------------------------
296.3 207.5 898.1 610.6
-------------------------------------------------------------------------
EXPENSES
Transportation 7.6 4.8 21.3 15.3
Operating 66.4 55.9 191.7 179.2
General and administrative 19.2 15.9 56.9 38.5
Provision for non-recoverable
accounts receivable - (0.4) - (0.4)
Interest and financing
charges (Note 6) 13.6 6.4 32.0 19.8
Depletion, depreciation
and accretion 125.6 95.7 328.8 290.3
Gain on foreign exchange (13.5) (34.9) (11.7) (60.3)
-------------------------------------------------------------------------
218.9 143.4 619.0 482.4
-------------------------------------------------------------------------
Gain on short-term
investment (Note 9) 0.9 - 0.9 -
Capital and other taxes (0.1) (0.2) (0.1) (0.2)
Future income tax recovery
(expense) 2.8 5.7 (12.8) 30.9
-------------------------------------------------------------------------
Net income 81.0 69.6 267.1 158.9
-------------------------------------------------------------------------
Net income attributable to:
The Trust 79.5 68.9 263.8 157.3
Non-controlling interest
(Note 10) 1.5 0.7 3.3 1.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income attributable to
the Trust $ 79.5 $ 68.9 $ 263.8 $ 157.3
Deficit, beginning of period (544.6) (571.5) (578.6) (502.9)
Distributions paid or
declared (Note 13) (80.3) (70.6) (230.6) (227.6)
-------------------------------------------------------------------------
Deficit, end of period
(Note 12) $ (545.4) $ (573.2) $ (545.4) $ (573.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per unit (Note 11)
Basic and Diluted $ 0.30 $ 0.29 $ 1.04 $ 0.68
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME (unaudited)
For the three and nine months ended September 30
Three Months Ended Nine Months Ended
September 30 September 30
(Cdn$ millions) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net income $ 81.0 $ 69.6 $ 267.1 $ 158.9
Other comprehensive income
(loss), net of tax
Losses on financial
instruments designated
as cash flow hedges(1) (0.4) (0.5) - (3.4)
Gains and losses on
financial instruments
designated as cash flow
hedges in prior periods
realized in net income
in the current period(2)
(Note 9) 0.3 0.2 0.3 0.8
Net unrealized gains
on available-for-sale
reclamation
funds' investments(3) 0.1 0.5 0.2 0.3
-------------------------------------------------------------------------
Other comprehensive income
(loss)(4) - 0.2 0.5 (2.3)
-------------------------------------------------------------------------
Comprehensive income $ 81.0 $ 69.8 $ 267.6 $ 156.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Comprehensive income
attributable to:
The Trust 79.5 69.1 264.3 155.0
Non-controlling interest
(Note 10) 1.5 0.7 3.3 1.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other
comprehensive (loss) income,
beginning of period (0.1) (0.6) (0.6) 1.9
Other comprehensive
income (loss)(4) - 0.2 0.5 (2.3)
-------------------------------------------------------------------------
Accumulated other
comprehensive loss,
end of period (Note 12) $ (0.1) $ (0.4) $ (0.1) $ (0.4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of a nominal tax impact for the three months ended September 30,
2010 and $0.1 million for the nine months ended September 30, 2010
(net of tax of $0.2 million and $1.2 million, respectively, for the
three and nine months ended September 30, 2009).
(2) Amounts are net of tax of $0.1 million for the three and nine months
ended September 30, 2010 (net of tax of $0.1 million and $0.3 million
for the three and nine months ended September 30, 2009).
(3) Amounts are net of tax of $0.1 million for the three and nine months
ended September 30, 2010 (net of tax of $0.2 million and $0.1 million
for the three and nine months ended September 30, 2009).
(4) Other comprehensive income attributable to non-controlling interest
for the three and nine months ended September 30, 2010 and 2009 is
nominal.
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and nine months ended September 30
Three Months Ended Nine Months Ended
September 30 September 30
(Cdn$ millions) 2010 2009 2010 2009
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 81.0 $ 69.6 $ 267.1 $ 158.9
Add items not involving cash:
Future income tax
(recovery) expense (2.8) (5.7) 12.8 (30.9)
Depletion, depreciation
and accretion 125.6 95.7 328.8 290.3
Non-cash (gain) loss on
risk management
contracts (Note 9) (23.8) 0.7 (114.1) 7.9
Non-cash gain on short-term
investment (Note 9) (0.9) - (0.9) -
Non-cash lease inducement 2.0 - 4.7 -
Non-cash gain on foreign
exchange (13.4) (34.9) (11.9) (60.2)
Non-cash trust unit
incentive compensation
recovery (Note 14) (4.9) (0.6) (8.5) (4.1)
Expenditures on site
restoration and
reclamation (Note 7) (1.4) (1.0) (5.1) (3.9)
Change in non-cash
working capital 4.8 1.8 14.8 (3.8)
-------------------------------------------------------------------------
166.2 125.6 487.7 354.2
-------------------------------------------------------------------------
CASH FLOWS FROM FINANCING
ACTIVITIES
Issuance (repayment) of
long-term debt under
revolving credit
facilities, net 34.8 (35.6) (286.5) (345.2)
Issue of Senior Notes - - 210.4 152.9
Repayment of Senior Notes - - (65.8) (12.6)
Issue of trust units,
net of issue costs 0.5 0.3 241.2 241.2
Cash distributions paid
(Note 13) (59.0) (54.9) (177.6) (186.2)
Change in non-cash working
capital 4.5 3.9 5.6 5.9
-------------------------------------------------------------------------
(19.2) (86.3) (72.7) (144.0)
-------------------------------------------------------------------------
CASH FLOWS FROM INVESTING
ACTIVITIES
Acquisition of petroleum
and natural gas properties (1.5) (2.2) (7.8) (10.7)
Proceeds on disposition of
petroleum and natural
gas properties 3.5 32.3 3.5 32.3
Capital expenditures (160.4) (96.5) (433.3) (242.9)
Net reclamation fund
(contributions) withdrawals (1.2) (2.3) 0.2 (3.1)
Change in non-cash
working capital 12.6 29.4 22.7 (25.8)
-------------------------------------------------------------------------
(147.0) (39.3) (414.7) (250.2)
-------------------------------------------------------------------------
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)
<<
September 30, 2010 and 2009
(all tabular amounts in Cdn$ millions, except per unit amounts)
1. SUMMARY OF ACCOUNTING POLICIES
The unaudited interim Consolidated Financial Statements follow the
same accounting policies as the most recent annual audited financial
statements except as noted below in Note 2 "Change in Accounting
Policy". The interim Consolidated Financial Statement note
disclosures do not include all of those required by Canadian
generally accepted accounting principles ("GAAP") applicable for
annual Consolidated Financial Statements. Accordingly, these interim
Consolidated Financial Statements should be read in conjunction with
the audited Consolidated Financial Statements included in ARC's 2009
annual report.
2. CHANGE IN ACCOUNTING POLICY
During the third quarter of 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
Exploration Inc. ("Storm") as described in Note 3 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.
The above CICA Handbook Sections are converged with International
Financial Reporting Standards.
3. CORPORATE ACQUISITIONS
On August 17, 2010, ARC acquired 100 per cent of the existing and
outstanding common shares of 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 ARL 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:
---------------------------------------------------------------------
Net Assets Acquired(1)
---------------------------------------------------------------------
Property, plant and equipment $ 712.7
Short-term investment (Note 9) 2.9
Risk management contracts 0.7
Goodwill 85.6
Net working capital deficiency (3.3)
Office lease obligation (1.2)
Asset retirement obligation (15.0)
Future income tax liability (130.3)
---------------------------------------------------------------------
Total net assets acquired $ 652.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Consideration
---------------------------------------------------------------------
Trust units issued (23,003,154 units) $ 449.2
Exchangeable Shares issued (1,924,997 ARL
exchangeable shares)(2) 106.2
Bank debt (net of cash acquired) 96.7
---------------------------------------------------------------------
Total consideration paid $ 652.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The above amounts are estimates, which were made by management at
the time of preparation of these financial statements based on
information then available. Amendments may be made to these
amounts as values subject to estimate are finalized.
(2) At acquisition date, 1,924,997 ARL Series B exchangeable shares
were issued at an exchange ratio of 2.82551, for total trust unit
equivalent of 5,439,098 trust units. See Note 10, "Exchangeable
Shares" 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 working capital deficiency acquired includes
$7.2 million of trade accounts receivable, all of which are
considered to be collectable and $13.5 million of accounts payables
and accrued liabilities. ARC has not recognized any goodwill
impairment losses from acquisition date to September 30, 2010.
These Consolidated Financial Statements incorporate the results of
operations of the acquired Storm properties from August 17, 2010. For
the three months ended September 30, 2010, ARC recorded revenue from
oil, natural gas and natural gas liquids of $11.5 million and net
loss of $3.6 million in respect of the acquired assets. Had the
acquisition occurred on January 1, 2010, for the nine months ended
September 30, 2010, ARC estimates that its pro forma revenues and
net income would have been approximately $960 million and $260
million, respectively.
4. FINANCIAL ASSETS AND CREDIT RISK
Credit risk is the risk of financial loss to ARC if a partner or
counterparty to a product sales contract or financial instrument
fails to meet its contractual obligations. ARC is exposed to credit
risk with respect to its cash equivalents, accounts receivable,
reclamation funds, and risk management contracts. Most of ARC's
accounts receivable relate to oil and natural gas sales and are
subject to typical industry credit risks. ARC manages this credit
risk as follows:
- By entering into sales contracts with only established credit
worthy counterparties as verified by a third party rating agency,
through internal evaluation or by requiring security such as
letters of credit;
- By limiting exposure to any one counterparty in accordance with
ARC's credit policy; and
- By restricting cash equivalent investments, reclamation fund
investments, and risk management transactions to counterparties
that, at the time of transaction, are not less than investment
grade.
The majority of the credit exposure on accounts receivable at
September 30, 2010 pertains to accrued revenue for September 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 September 30, 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.
When determining whether amounts that are past due are collectable,
management assesses the credit worthiness and past payment history of
the counterparty, as well as the nature of the past due amount. ARC
considers all amounts greater than 90 days to be past due. As at
September 30, 2010, $5.1 million of accounts receivable are past due,
excluding amounts in ARC's allowance for doubtful accounts, all of
which are considered to be collectable. The change in ARC's allowance
for doubtful accounts for the nine months ended September 30, 2010 is
nominal.
Maximum credit risk is calculated as the total recorded value of cash
equivalents, accounts receivable, reclamation funds, and risk
management contracts at the balance sheet date.
5. FINANCIAL LIABILITIES AND LIQUIDITY RISK
Liquidity risk is the risk that ARC will not be able to meet its
financial obligations as they become due. ARC actively manages its
liquidity through cash, distribution policy, and debt and equity
management strategies. Such strategies include continuously
monitoring forecasted and actual cash flows from operating, financing
and investing activities, available credit under existing banking
arrangements and opportunities to issue additional Trust units.
Management believes that future cash flows generated from these
sources will be adequate to settle ARC's financial liabilities.
The following table details ARC's financial liabilities as at
September 30, 2010:
---------------------------------------------------------------------
2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
---------------------------------------------------------------------
Accounts payable and
accrued liabilities(1) 220.5 - - - 220.5
Distributions payable(2) 20.2 - - - 20.2
Risk management
contracts(3) 46.3 1.8 - - 48.1
Senior notes and interest 49.4 131.6 125.2 346.2 652.4
Revolving credit
facilities - 308.0 - - 308.0
Working capital facility 5.8 - - - 5.8
Accrued long-term
incentive compensation(1) - 33.7 - - 33.7
---------------------------------------------------------------------
Total financial
liabilities 342.2 475.1 125.2 346.2 1,288.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Liabilities under the Whole Trust Unit Incentive Plan represent
the total amount expected to be paid out on vesting.
(2) Amounts payable for the distribution represents the net cash
payable after distribution reinvestment.
(3) Amounts payable under risk management contracts have been
presented at their future value without any reduction for risk.
6. LONG-TERM DEBT
---------------------------------------------------------------------
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Syndicated credit facilities:
Cdn$ denominated $ 308.0 $ 423.0
US$ denominated - 74.3
Working capital facility 5.8 7.9
Senior notes:
Master Shelf Agreement
5.42% US$ Note 77.2 78.5
4.94% US$ Note 6.2 6.3
4.98% US$ Note 51.5 -
2004 Note Issuance
4.62% US$ Note 26.4 54.5
5.10% US$ Note 24.7 65.4
2009 Note Issuance
7.19% US$ Note 69.5 70.6
8.21% US$ Note 36.0 36.6
6.50% Cdn$ Note 29.0 29.0
2010 Note Issuance
5.36% US$ Note 154.5 -
---------------------------------------------------------------------
Total long-term debt outstanding $ 788.8 $ 846.1
---------------------------------------------------------------------
---------------------------------------------------------------------
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
(three per cent at September 30, 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 banker's 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 third quarter of 2010, the weighted-average interest rate
under the credit facility was 2.4 per cent (0.9 per cent for the
third quarter of 2009) and 1.5 per cent for the nine months ended
September 30, 2010 (1.2 per cent for the nine months 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
The terms and rates of the senior notes issued under the Master Shelf
Agreement are the same as those detailed at December 31, 2009, with
the exception of a new tranche issued on March 5, 2010.
---------------------------------------------------------------------
Remaining Coupon Maturity Principal Payment
Issue Date Principal Rate Date Terms
---------------------------------------------------------------------
March 5, US$50.0 million 4.98% March 5, Five equal
2010 2019 installments beginning
March 5, 2015
---------------------------------------------------------------------
---------------------------------------------------------------------
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 were
made to align the key provisions in all outstanding senior note
agreements.
The terms and rates of the remaining senior notes not subject to the
Master Shelf Agreement are the same as those detailed at December 31,
2009, with the exception of the aforementioned 2004 notes and a new
tranche issued on May 27, 2010.
---------------------------------------------------------------------
Remaining Coupon Maturity Principal Payment
Issue Date Principal Rate Date Terms
---------------------------------------------------------------------
April 27, US$25.7 million 4.62% April 27, Six equal installments
2004 2014 beginning April 27,
2009
April 27, US$24.0 million 5.10% April 27, Five equal
2004 2016 installments beginning
April 27, 2012
May 27, US$150.0 million 5.36% May 27, Five equal
2010 2022 installments beginning
May 27, 2018
---------------------------------------------------------------------
---------------------------------------------------------------------
Credit Capacity
The following table summarizes ARC's available credit capacity and
the current amounts drawn as at September 30, 2010:
---------------------------------------------------------------------
Credit
Capacity Drawn Remaining
---------------------------------------------------------------------
Syndicated Credit Facility $ 1,000.0 $ 308.0 $ 692.0
Working Capital Facility 30.0 5.8 24.2
Senior Notes Subject to a
Master Shelf Agreement(1) 231.7 134.9 96.8
Senior Notes Not Subject to
a Master Shelf Agreement 340.1 340.1 -
---------------------------------------------------------------------
Total $ 1,601.8 $ 788.8 $ 813.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Total credit capacity is US$225 million.
Supplemental disclosures
The fair value of all senior notes as at September 30, 2010, is
$526.2 million compared to a carrying value of $475 million
($347.3 million compared to $340.9 million as at December 31, 2009).
Amounts of US$21.8 million due under the senior notes and
$5.8 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 third quarter of 2010 was $6.4 million less
than the interest expense (interest paid during the third quarter of
2009 was $4.8 million less than the interest expense).
7. ASSET RETIREMENT OBLIGATIONS
The following table reconciles ARC's asset retirement obligations:
---------------------------------------------------------------------
Nine Months
Ended Year Ended
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 149.9 $ 141.5
Increase in liabilities relating to
corporate acquisitions (Note 3) 15.0 4.0
Increase in liabilities relating to
development activities 1.3 1.7
(Decrease) increase in liabilities
relating to change in estimate (5.5) 2.1
Settlement of reclamation liabilities
during the period (5.1) (8.7)
Accretion expense 7.3 9.3
---------------------------------------------------------------------
Balance, end of period $ 162.9 $ 149.9
---------------------------------------------------------------------
---------------------------------------------------------------------
ARC's weighted average credit adjusted risk free rate as at
September 30, 2010 was 6.5 per cent (6.5 per cent as at December 31,
2009).
8. CAPITAL MANAGEMENT
The objective of ARC when managing its capital is to maintain a
conservative structure that will allow it to:
- Fund its development and exploration program;
- Provide financial flexibility to execute on strategic
opportunities; and
- Maintain a level of distributions that, in normal times, in the
opinion of Management and the Board of Directors, is sustainable
for a minimum period of six months in order to normalize the
effect of commodity price volatility to unitholders.
ARC manages the following capital:
- Trust units and exchangeable shares;
- Long-term debt; and
- Working capital (defined as current assets less current
liabilities excluding short-term investment, 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
September 30, 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 13 per cent.
---------------------------------------------------------------------
($ millions, except per unit September 30, December 31,
and per cent amounts) 2010 2009
---------------------------------------------------------------------
Long-term debt 788.8 846.1
Accounts payable and accrued liabilities 216.0 166.7
Distributions payable 27.6 23.7
Cash and cash equivalents, accounts
receivable and prepaid expenses (161.3) (134.1)
---------------------------------------------------------------------
Net debt obligations(1) 871.1 902.4
---------------------------------------------------------------------
Trust units outstanding and issuable
for exchangeable shares (millions) 283.1 239.0
Trust unit price(2) 20.55 19.94
---------------------------------------------------------------------
Market capitalization(1) 5,817.7 4,765.7
Net debt obligations(1) 871.1 902.4
---------------------------------------------------------------------
Total capitalization(1) 6,688.8 5,668.1
---------------------------------------------------------------------
Net debt as a percentage of total
capitalization 13.0% 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 September 30, 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 trust units, exchangeable shares,
new debt or changing its distribution policy.
In addition to internal capital management ARC is subject to various
covenants under its credit facilities. Compliance with these
covenants is monitored on a quarterly basis and as at September 30,
2010 ARC is in compliance with all covenants.
9. FINANCIAL INSTRUMENTS AND MARKET RISK MANAGEMENT
Financial Instrument Classification and Measurement
Pursuant to the Storm acquisition (Note 3), 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 September 30, 2010, the fair value of ARC's
investment in Storm Resources Ltd. was $3.8 million and an unrealized
gain of $0.9 million was recorded for the period August 17 to
September 30, 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 distributions to unitholders.
ARC manages the risks associated with changes in commodity prices by
entering into a variety of risk management contracts (see Risk
Management Contracts below). The following table illustrates the
effects of movement in commodity prices on net income due to changes
in the fair value of risk management contracts in place at
September 30, 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 September 30, 2010 and
ARC's next reporting date.
---------------------------------------------------------------------
Sensitivity of Risk Management Contracts:
---------------------------------------------------------------------
Increase in Decrease in
Commodity Price Commodity Price
---------------------------------------------------------------------
Natural Natural
Crude oil gas Crude oil gas
---------------------------------------------------------------------
Net income (decrease)
increase (50.1) (13.9) 48.3 14.0
---------------------------------------------------------------------
---------------------------------------------------------------------
As noted above, the sensitivities are hypothetical and based on
management's assessment of reasonably possible changes in commodity
prices between the balance sheet date and ARC's next reporting date.
The results of the sensitivity should not be considered to be
predictive of future performance. Changes in the fair value of risk
management contracts cannot generally be extrapolated because the
relationship of change in certain variables to a change in fair value
may not be linear.
Interest Rate Risk
ARC has both fixed and variable interest rates on its debt. Changes
in interest rates could result in an increase or decrease in the
amount ARC pays to service variable interest rate debt, potentially
impacting distributions to unitholders. Changes in interest rates
could also result in fair value risk on ARC's fixed rate senior
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 floating rate debt at September 30,
2010 were to have increased by 50 bps (0.5 per cent) it is estimated
that ARC's annualized net income would decrease by $1.2 million.
Management does not expect interest rates to decrease.
Foreign Exchange Risk
North American oil and natural gas prices are based upon U.S. dollar
denominated commodity prices. As a result, the price received by
Canadian producers is affected by the Canadian/U.S. dollar exchange
rate that may fluctuate over time. In addition ARC has U.S. dollar
denominated debt and interest obligations of which future cash
repayments are directly impacted by the exchange rate in effect on
the repayment date. Variations in the Canadian/U.S. dollar exchange
rate could also have a positive or negative impact on distributions
to unitholders.
The following table demonstrates the effect of exchange rate
movements on net income due to changes in the fair value of risk
management contracts in place at September 30, 2010 as well as the
unrealized gain or loss on revaluation of outstanding US$ denominated
debt. The sensitivity is based on a 5 per cent increase and 5 per
cent decrease in the Cdn$/US$ foreign exchange rate.
---------------------------------------------------------------------
Increase in Decrease in
Cdn$/US$ Cdn$/US$
rate rate
---------------------------------------------------------------------
(Increase loss/decrease gain) increase
gain/decrease loss on risk management
contracts $ (0.7) $ 0.7
(Increase loss/decrease gain) increase
gain/decrease loss on U.S. dollar
denominated debt (4.5) 4.5
---------------------------------------------------------------------
Net income (decrease) increase $ (5.2) $ 5.2
---------------------------------------------------------------------
---------------------------------------------------------------------
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 September 30, 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 September 30, 2010 that do not qualify for hedge accounting:
---------------------------------------------------------------------
Financial WTI Crude Oil Contracts(1)
---------------------------------------------------------------------
Bought
Volume Put Sold Put Sold Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
1-Sep-10 31-Dec-10 3-way collar 4,000 $70.00 $57.50 $90.00
1-Sep-10 31-Dec-10 Collar 2,000 $75.00 - $95.00
1-Sep-10 31-Dec-10 Collar 2,000 $80.00 - $90.00
1-Sep-10 31-Dec-10 3-way collar 3,000 $80.00 $60.00 $90.00
1-Sep-10 31-Dec-10 3-way collar 4,000 $80.00 $60.00 $95.00
1-Jan-11 31-Dec-11 3-way collar 5,000 $80.00 $60.00 $100.00(2)
1-Jan-11 31-Dec-11 Collar 7,000 $85.00 - $85.00(2)
1-Jan-11 31-Dec-11 3-way collar 5,000 $85.00 $60.00 $85.00(2)
1-Jan-12 31-Dec-12 3-way collar 4,000 $90.00 $60.00 $90.00(2)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Monthly average
(2) Annually settled call
---------------------------------------------------------------------
Financial CWTI Crude Oil Contracts(3)
---------------------------------------------------------------------
Bought
Volume Put Sold Put Sold Call
Term Contract bbl/d Cdn$/bbl Cdn$/bbl Cdn$/bbl
1-Jan-11 31-Dec-11 3-way collar 2,000 $90.00 $65.00 $90.00(4)
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) Monthly average
(4) Annually settled call
---------------------------------------------------------------------
Financial AECO Natural Gas Swap Contracts(5)
---------------------------------------------------------------------
Volume Sold Swap
Term Contract GJ/d Cdn$/GJ
---------------------------------------------------------------------
1-Oct-10 31-Dec-10 Swap 80,000 $5.61
1-Jan-11 31-Dec-11 Swap 135,000 $5.54
---------------------------------------------------------------------
---------------------------------------------------------------------
(5) AECO 7a monthly index
---------------------------------------------------------------------
Financial AECO Natural Gas Contracts(6)
---------------------------------------------------------------------
Volume Bought Put Sold Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
1-Oct-10 31-Dec-10 Collar 10,000 $4.00 $5.05
---------------------------------------------------------------------
---------------------------------------------------------------------
(6) AECO 7a monthly index
---------------------------------------------------------------------
Financial NYMEX Natural Gas Swap Contracts(7)
---------------------------------------------------------------------
Volume Sold Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
1-Oct-10 31-Oct-10 Swap 20,000 $6.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(7) Last 3 Day Settlement
---------------------------------------------------------------------
Financial Basis Swap Contract(8)
---------------------------------------------------------------------
Volume Sold Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
1-Oct-10 31-Oct-10 Swap 50,000 ($1.0430)
1-Jan-11 31-Dec-12 Swap 10,000 ($0.6500)
1-Nov-10 31-Oct-11 Swap 15,000 ($0.4850)
1-Nov-11 31-Oct-12 Swap 15,000 ($0.4067)
---------------------------------------------------------------------
---------------------------------------------------------------------
(8) Nymex Last Day (Ld) or Last 3 Day (L3d); AECO 7a monthly index
---------------------------------------------------------------------
US$ Foreign Exchange Contracts(9)
---------------------------------------------------------------------
Notional Sold Swap
Term Contract US$/month Cdn$/US$
---------------------------------------------------------------------
1-Jan-11 31-Dec-11 Swap $2,000,000 $1.0622
---------------------------------------------------------------------
---------------------------------------------------------------------
(9) Settled against monthly average BoC noon day rate
---------------------------------------------------------------------
Financial Electricity Heat Rate Contracts(10)
---------------------------------------------------------------------
AESO multi- Heat
Volume Power AECO 5a plied Rate
Term Contract MWh Cdn$/MWh Cdn$/GJ by GJ/MWh
---------------------------------------------------------------------
1-Oct-10 31-Dec-10 Heat Rate 10 Receive Pay AECO x 9.15
Swap AESO 5a
1-Jan-11 31-Dec-11 Heat Rate 15 Receive Pay AECO x 9.08
Swap AESO 5a
1-Jan-12 31-Dec-12 Heat Rate 15 Receive Pay AECO x 9.10
Swap AESO 5a
1-Jan-13 31-Dec-13 Heat Rate 10 Receive Pay AECO x 9.15
Swap AESO 5a
---------------------------------------------------------------------
---------------------------------------------------------------------
(10) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index
---------------------------------------------------------------------
Financial Electricity Contracts(11)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Oct-10 31-Dec-12 Swap 5 $72.50
---------------------------------------------------------------------
---------------------------------------------------------------------
(11) Alberta Power Pool (monthly average 24x7)
Following is a summary of all risk management contracts in place as
at September 30, 2010 that qualify for hedge accounting:
---------------------------------------------------------------------
Financial Electricity Contracts(11)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Oct-10 31-Dec-10 Swap 5 $63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
At September 30, 2010, the fair value of the contracts that were not
designated as accounting hedges was $110.5 million. ARC recorded a
gain on risk management contracts of $159.5 million in the statement
of income and deficit for the nine months ended September 30, 2010
($13.2 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:
---------------------------------------------------------------------
Nine Months Nine Months
Ended Ended
September 30, September 30,
2010 2009
---------------------------------------------------------------------
Fair value, beginning of period $ (4.3) $ 3.4
Fair value, end of period(1) 110.5 (4.5)
---------------------------------------------------------------------
Change in fair value of contracts in
the period 114.8 (7.9)
Fair value of contracts acquired in
Corporate Acquisition (Note 3) (0.7) -
Realized gain in the period 45.4 21.1
---------------------------------------------------------------------
Gain on risk management contracts $ 159.5 $ 13.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a gain of $113.2 million at
September 30, 2010 ($8.6 million loss at September 30, 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 $0.3 million on these
electricity contracts for the three and nine months ended September
30, 2010 (loss of $0.3 million and $1.1 million respectively in 2009)
has been included in operating costs on the statement of income. The
accumulated unrealized fair value on these contracts is a loss of
$0.2 million and has been recorded on the Consolidated Balance Sheet
at September 30, 2010 with the movement in fair value recorded in
Other Comprehensive Income, net of tax. The fair value movement for
the nine month period ended September 30, 2010 is $0.3 million
unrealized gain. As at September 30, 2010 the total unrealized fair
value is attributed to contracts that will settle over the next
twelve months. The following table reconciles the movement in the
fair value of ARC's financial risk management contracts that have
been designated as effective accounting hedges:
---------------------------------------------------------------------
Nine Months Nine Months
Ended Ended
September 30, September 30,
2010 2009
---------------------------------------------------------------------
Fair value, beginning of period $ (0.5) $ 3.3
Change in fair value of financial
electricity contracts 0.3 (3.6)
---------------------------------------------------------------------
Fair value, end of period(1) $ (0.2) $ (0.3)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts designated as
effective accounting hedges equals a loss of $0.2 million at
September 30, 2010 ($0.3 million loss at September 30, 2009).
10. EXCHANGEABLE SHARES
ARC is authorized to issue an unlimited number of ARC Resources Ltd.
("ARL") exchangeable shares that can be converted (at the option of
the holder) into trust units at any time. The number of trust units
issuable upon conversion is based upon the exchange ratio in effect
at the conversion date. The exchange ratio is calculated monthly
based on the cash distribution paid divided by the ten day weighted
average unit price preceding the record date and multiplied by the
opening exchange ratio.
On August 17, 2010, pursuant to the Storm acquisition described in
Note 3, ARL issued a second series of exchangeable shares. These
shares have been classified as ARL "Series B" exchangeable shares and
share the same nature, terms and conditions of the original "Series
A" exchangeable shares. The exchangeable shares are not eligible for
distributions and, in the event that they are not converted, Series A
shares are redeemable by ARC for trust units on August 28, 2012 and
Series B shares on August 17, 2013. ARL Series A exchangeable shares
are publically traded on the Toronto Stock Exchange, but the Series B
are not currently listed. 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.
---------------------------------------------------------------------
Nine Months
Ended Year Ended
September 30, December 31,
(units thousands) 2010 2009
---------------------------------------------------------------------
Balance, beginning of period 871 1,092
Issued for acquisition consideration
(Note 3) 1,925 -
Exchanged for trust units(1) (52) (221)
---------------------------------------------------------------------
Balance, end of period 2,744 871
Exchange ratio, end of period 2.84014 2.71953
Trust units issuable upon conversion,
end of period 7,793 2,369
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first nine months of 2010, 5,052 ARL Series A
exchangeable shares were converted to trust units at an average
exchange ratio of 2.75653 and 46,883 ARL Series B exchangeable
shares were converted to trust units at an average exchange ratio
of 2.83412, compared to 220,573 Series A exchangeable shares at
an average exchange ratio of 2.59547 during the year ended 2009.
Following is a summary of the non-controlling interest for 2010 and
2009:
---------------------------------------------------------------------
Nine Months
Ended Year Ended
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Non-controlling interest, beginning of
period $ 36.0 $ 42.4
Issued for acquisition consideration
(Note 3) 106.2 -
Reduction of book value for conversion
to trust units (2.8) (8.7)
Current period net income attributable
to non-controlling interest 3.3 2.3
---------------------------------------------------------------------
Non-controlling interest, end of period 142.7 36.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 46.6 $ 43.3
---------------------------------------------------------------------
---------------------------------------------------------------------
11. UNITHOLDERS' CAPITAL
---------------------------------------------------------------------
Nine Months Ended Year Ended
September 30, 2010 December 31, 2009
---------------------------------------------------------------------
Number Number
of trust of trust
(units thousands) units $ units $
---------------------------------------------------------------------
Balance, beginning of
period 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 147 2.8 572 8.7
Issued on acquisition of
Storm (Note 3) 23,003 449.2 - -
Distribution reinvestment
program 2,585 50.6 4,134 67.0
Trust unit issue costs,
net of tax(1) - (10.1) - (11.8)
---------------------------------------------------------------------
Balance, end of period 275,350 3,662.4 236,615 2,917.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount is net of tax of $2.5 million for the period ended
September 30, 2010 (net of tax of $2.1 million for the year ended
December 31, 2009).
Net income per trust unit has been determined based on the following:
---------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
---------------------------------------------------------------------
(units thousands) 2010 2009 2010 2009
---------------------------------------------------------------------
Weighted average trust
units 262,960 235,182 254,441 231,976
Weighted average trust
units issuable on
conversion of
exchangeable shares 5,038 2,500 3,215 2,500
---------------------------------------------------------------------
Diluted trust units 267,998 237,682 257,656 234,476
---------------------------------------------------------------------
---------------------------------------------------------------------
Basic net income per unit has been calculated based on net income
attributable to ARC Energy Trust divided by weighted average trust
units. Diluted net income per unit has been calculated based on net
income divided by diluted trust units.
12. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE LOSS
---------------------------------------------------------------------
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Accumulated earnings $ 3,210.7 $ 2,946.9
Accumulated distributions (3,756.1) (3,525.5)
---------------------------------------------------------------------
Deficit (545.4) (578.6)
Accumulated other comprehensive loss (0.1) (0.6)
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive loss $ (545.5) $ (579.2)
---------------------------------------------------------------------
---------------------------------------------------------------------
The accumulated other comprehensive loss balance is composed of the
following items:
---------------------------------------------------------------------
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Unrealized gains and losses on financial
instruments designated as cash flow
hedges $ (0.4) $ (0.7)
Net unrealized gains and losses on
available-for-sale reclamation funds'
investments 0.3 0.1
---------------------------------------------------------------------
Accumulated other comprehensive loss,
end of period $ (0.1) $ (0.6)
---------------------------------------------------------------------
---------------------------------------------------------------------
13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS
Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operating activities is
reduced by reclamation fund contributions including interest earned
on the funds, a portion of capital expenditures and, when applicable,
debt repayments. The portion of cash flow from operating activities
withheld to fund capital expenditures and to make debt repayments is
at the discretion of the Board of Directors.
Three Months Ended Nine Months Ended
September 30 September 30
2010 2009 2010 2009
---------------------------------------------------------------------
Cash flow from operating
activities $ 166.2 $ 125.6 $ 487.7 $ 354.2
Deduct:
Cash withheld to fund
current period capital
expenditures (84.7) (52.7) (257.3) (123.5)
Net reclamation fund
(contributions)
withdrawals (1.2) (2.3) 0.2 (3.1)
---------------------------------------------------------------------
Distributions(1) 80.3 70.6 230.6 227.6
Accumulated distributions,
beginning of period 3,675.8 3,384.0 3,525.5 3,227.0
---------------------------------------------------------------------
Accumulated distributions,
end of period $ 3,756.1 $ 3,454.6 $ 3,756.1 $ 3,454.6
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0.30 $ 0.30 $ 0.90 $ 0.98
Accumulated distributions
per unit, beginning of
period $ 25.58 $ 24.38 $ 24.98 $ 23.70
Accumulated distributions
per unit, end of
period(3) $ 25.88 $ 24.68 $ 25.88 $ 24.68
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include accrued and non-cash amounts of $21.3
million and $53 million, respectively for the three and nine
months ended September 30, 2010 ($15.6 million and $41.3 million
for the same periods in 2009).
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of ARC in July 1996.
14. WHOLE TRUST UNIT INCENTIVE PLAN
Compensation expense associated with the Whole Trust Unit Incentive
Plan ("the Whole Unit Plan") is granted in the form of Restricted
Trust Units ("RTUs") and Performance Trust Units ("PTUs") and is
determined based on the intrinsic value of the Whole Trust Units at
each period end. Upon vesting, the plan participant receives a cash
payment based on the fair value of the underlying trust units plus
accrued distributions.
During the first nine months of 2010, cash payments of $28.6 million
were made to employees relating to the Whole Unit Plan compared to
$16.6 million in 2009.
The following table summarizes the RTU and PTU movement for the nine
months ended September 30, 2010:
---------------------------------------------------------------------
Number of Number of
(thousands) RTUs PTUs
---------------------------------------------------------------------
Balance, beginning of period 1,052 1,305
Granted 504 459
Vested (459) (321)
Forfeited (64) (120)
---------------------------------------------------------------------
Balance, end of period 1,033 1,323
---------------------------------------------------------------------
---------------------------------------------------------------------
The change in the net accrued long-term incentive compensation
liability relating to the Whole Unit Plan can be reconciled as
follows:
---------------------------------------------------------------------
September 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 32.6 $ 31.9
Change in net liabilities in the period
General and administrative expense (7.8) (0.1)
Operating expense (0.7) 0.7
Property, plant and equipment (1.3) 0.1
---------------------------------------------------------------------
Balance, end of period(1) $ 22.8 $ 32.6
---------------------------------------------------------------------
Current portion of liability(2) 11.8 22.4
---------------------------------------------------------------------
Accrued long-term incentive
compensation(3) $ 11.5 $ 10.9
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $0.5 million of recoverable amounts recorded in accounts
receivable as at September 30, 2010 ($0.7 million for 2009).
(2) Included in accounts payable and accrued liabilities on the
Consolidated Balance Sheet.
(3) Included in other long-term liabilities on the Consolidated
Balance Sheet.
15. COMMITMENTS AND CONTINGENCIES
Following is a summary of ARC's contractual obligations and
commitments as at September 30, 2010:
---------------------------------------------------------------------
Payments Due by Period
---------------------------------------------------------------------
2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
---------------------------------------------------------------------
Debt repayments(1) 28.3 389.7 85.5 285.3 788.8
Interest payments(2) 27.0 49.8 39.7 60.9 177.4
Reclamation fund
contributions(3) 4.9 8.9 7.7 64.2 85.7
Purchase commitments 31.1 28.1 12.8 10.4 82.4
Transportation commitments 9.5 31.3 26.6 9.0 76.4
Operating leases 7.1 15.8 14.8 66.5 104.2
Risk management contract
premiums(4) 3.0 2.0 - - 5.0
---------------------------------------------------------------------
Total contractual
obligations 110.9 525.6 187.1 496.3 1,319.9
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 9). As
the premiums are part of the underlying risk management contract,
they have been recorded at fair market value at September 30, 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 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 is involved in litigation and claims arising in the normal course
of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on ARC's financial position
or results of operations and therefore the above table does not
include any commitments for outstanding litigation and claims.
16. COMPARATIVES
Certain comparative figures have been reclassified to conform to the
current year's presentation.
>>
Boe conversion ratio for natural gas of 6 mcf: 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Forward-looking Information and Statements
This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: those items outlined and described under the heading "Forward-looking information and Statements" at the end of the MD&A section of this news release; and those items relating to the expected 2010 full year production, the 2011 capital program, the conversion of ARC Energy Trust to a dividend paying corporation, future production from Dawson and plans for Phase 2 of the Dawson gas plant, and future fourth quarter 2010 capital expenditures for the Cardium Resource Play under the heading "Accomplishments/Financial Update" on pages two to four of this news release.
The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties; increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Additional Information
Additional information relating to ARC can be found on SEDAR at www.sedar.com.
ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with a current enterprise value of approximately $7 billion. The Trust expects 2010 oil and gas production to average 72,500 to 74,500 barrels of oil equivalent per day from six core areas in western Canada. ARC Energy Trust units trade on the TSX under the symbol AET.UN and ARC Resources exchangeable shares trade under the symbol ARX.A.
<<
ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer
>>
%SEDAR: 00015954E %CIK: 0001029509
For further information: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., 1200, 308 - 4th Avenue S.W., Calgary, AB, T2P 0H7, www.arcresources.com