ARC Energy Trust announces second quarter 2010 results
Aug 4, 2010
CALGARY, Aug. 4 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces the results for the second quarter ended June 30, 2010.
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Three Months Ended Six Months Ended
June 30 June 30
2010 2009 2010 2009
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FINANCIAL
(Cdn$ millions, except per
unit and per boe amounts)
Revenue before royalties 276.7 235.2 590.8 460.4
Per unit(1) 1.09 0.99 2.34 1.98
Per boe 45.92 40.40 48.93 39.49
Cash flow from operating
activities(2) 162.8 104.3 321.5 228.6
Per unit(1) 0.64 0.44 1.27 0.98
Per boe 27.02 17.92 26.63 19.61
Net income 44.9 66.1 184.3 88.4
Per unit(3) 0.18 0.28 0.74 0.38
Distributions 75.3 75.0 150.3 157.0
Per unit(1) 0.30 0.32 0.60 0.68
Per cent of cash flow from
operating activities(2) 46 72 47 69
Net debt outstanding(4) 728.8 737.6 728.8 737.6
OPERATING
Production
Crude oil (bbl/d) 27,354 26,917 27,496 27,857
Natural gas (mmcf/d) 211.2 200.2 214.5 197.0
Natural gas liquids (bbl/d) 3,655 3,679 3,455 3,721
Total (boe/d) 66,208 63,969 66,705 64,418
Average prices
Crude oil ($/bbl) 71.98 62.74 74.12 54.36
Natural gas ($/mcf) 4.12 3.73 4.78 4.45
Natural gas liquids ($/bbl) 53.02 38.89 56.44 38.88
Oil equivalent ($/boe) 45.82 40.32 48.84 39.36
Operating netback ($/boe)
Commodity and other revenue
(before hedging) 45.93 40.41 48.93 39.49
Transportation costs (1.28) (0.85) (1.14) (0.90)
Royalties (7.89) (4.72) (8.24) (5.53)
Operating costs (11.46) (11.02) (10.38) (10.57)
Netback (before hedging) 25.30 23.82 29.17 22.49
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TRUST UNITS
(millions)
Units outstanding, end of
period(5) 253.6 237.1 253.6 237.1
Weighted average trust
units(6) 253.2 236.6 252.5 232.8
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TRUST UNIT TRADING STATISTICS
(Cdn$, except volumes)
based on intra-day trading
High 22.33 19.25 22.49 20.90
Low 19.20 14.12 19.20 11.73
Close 19.73 17.81 19.73 17.81
Average daily volume
(thousands) 1,043 988 1,164 1,113
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(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares. Per unit distributions are based on
the number of trust units outstanding at each distribution record
date.
(2) Cash flow from operating activities is a GAAP measure. Historically,
management has disclosed Cash Flow as a non-GAAP measure calculated
using cash flow from operating activities less the change in non-cash
working capital and the expenditures on site restoration and
reclamation as they appear on the Consolidated Statements of Cash
Flows. Cash Flow for the second quarter of 2010 would be $153.2
million ($0.61 per unit) and $315.2 million ($1.25 per unit) year-to-
date. Distributions as a percentage of Cash Flow would be 49 per cent
for the second quarter of 2010 and 48 per cent year-to-date.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Includes trust units issuable for outstanding exchangeable shares at
period end.
(6) For the second quarter of 2010, includes 0.9 million (0.9 million in
2009) exchangeable shares each exchangeable into 2.798 trust units
(2.634 in 2009) for an aggregate 2.4 million (2.5 million in 2009)
trust units.
ACCOMPLISHMENTS / FINANCIAL UPDATE
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- In June 2010, ARC entered into an Arrangement Agreement to acquire
Storm Exploration Inc. ("Storm") in exchange for approximately 28.4
million ARC trust units (or an equivalent number of exchangeable
shares of ARC Resources Ltd.) and the assumption of approximately $90
million of debt for total consideration of approximately $680
million at the date of announcement. The assets being acquired
produced 9,861 boe per day in April 2010 - 49.8 mmcf per day of gas
and 1,556 boe per day of liquids primarily from the Parkland Montney
field 12 kilometres northwest of ARC's Dawson field. An estimated
28.9 million boe of proved reserves and 43.2 million boe of proved
plus probable reserves are being acquired through this transaction
as well as 90 gross (72 net) sections of land. For more detailed
information on the Arrangement Agreement please refer to ARC's news
release dated June 9, 2010. The Agreement is subject to approval by
Storm's shareholders on August 16, 2010 as well as other various
regulatory approvals.
- Production volumes for the quarter averaged 66,208 boe per day, a
four per cent increase compared to the second quarter of 2009. The
majority of the increase in production was a result of an acquisition
that closed late in 2009 with the remainder attributed to increased
production in the greater Dawson area. ARC's new Dawson gas plant
commenced operations during the second quarter, with the first
shipment of sales gas occurring early in May. A number of start-up
issues were addressed during the months of May and June, with the
plant operating at approximately 65 per cent of its 60 mmcf per day
capacity during that time period. The plant is now running at full
capacity. Assuming the Storm acquisition closes in late August, ARC
expects full year average production to be between 72,500 and 74,500
boe per day.
- Cash flow from operating activities was $162.8 million ($0.64 per
unit) in the second quarter of 2010, a 56 per cent increase from the
$104.3 million ($0.44 per unit) achieved in the comparable quarter in
2009. This increase was primarily attributed to higher commodity
prices for both crude oil and natural gas and increased volumes.
Crude oil prices increased by 15 per cent to $71.98 per barrel in the
second quarter of 2010 from $62.74 per barrel in the second quarter
of 2009. Natural gas prices also improved throughout the second
quarter relative to the second quarter in 2009, averaging $4.12 per
mcf. However, both crude oil and natural gas prices have declined
since the end of the first quarter of 2010 as a result of continued
concern over the economy and surplus natural gas supplies in North
America.
- During the second quarter of 2010, ARC issued US$150 million of
senior notes at a fixed rate of 5.36 per cent with an average life of
ten years. Proceeds from the note issuance were applied against
general borrowings from ARC's syndicated credit facility. 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' acceptances or US dollar LIBOR loans, plus a stamping fee.
With a net debt to annualized year-to-date cash flow from operating
activities ratio of 1.1 times, ARC continues to be well positioned to
finance the remainder of its 2010 capital program from cash flow and
available credit.
- Capital expenditures for the quarter totaled $144 million. During the
quarter, ARC drilled four oil wells and 11 natural gas wells with a
100 per cent success rate. Year-to-date, capital expenditures are
$272 million. After payment of distributions, ARC funded 75 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 being 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 that has allowed for the
postponement of certain drilling programs, cost reductions achieved
to date, and the re-allocation of capital from gas drilling to oil
drilling. No material impact is anticipated on production volumes.
This reduction in capital budget has been achieved despite
approximately $40 million having been spent on unbudgeted land
acquisitions.
- ARC plans to convert to a dividend paying corporation effective
January 1, 2011. The board of directors has approved the overall
strategy and the detailed implementation steps are currently being
defined. The conversion plan will be mailed to unitholders prior to a
unitholder meeting planned for December 15, 2010. Current plans would
see a dividend policy similar to the existing distribution policy
with dividends being paid monthly.
- Montney Resource Play Development
Production from the greater Dawson area increased throughout the
quarter with peak daily production of 100 mmcf per day being achieved
following the commissioning of the Dawson gas plant. Average
production will increase during the third quarter as production from
the plant is now at the design capacity and facility maintenance in
the area is completed.
During the second quarter of 2010, ARC spent $71.1 million on
development activities in the Dawson area including drilling 11
horizontal wells and completing fourteen horizontal wells. ARC
incurred $9.2 million of capital expenditures on the construction of
its Dawson Phase 1 gas plant during the second quarter and
anticipates total costs for the Phase 1 gas plant, including
associated pipeline infrastructure and an acid gas disposal well, to
be approximately $70 million. To date, ARC has drilled 21 wells of
its planned 32-well 2010 drilling program at Dawson. Cost
reduction initiatives and drilling and completions efficiencies have
resulted in savings of approximately $15 million on this program on a
year-to-date basis. Average production capabilities for the 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 the 11 remaining wells
budgeted for 2010 at Dawson will be deferred until 2011. This will
result in a $45 million reduction in the capital budget for Dawson
in 2010 with the funds being redeployed into land acquisition and
oil directed drilling activities elsewhere in our portfolio.
During April 2010, ARC submitted an application for the Phase 2
portion of the Dawson gas plant to the British Columbia Oil and Gas
Commission ("OGC"). Phase 2 consists of the construction of a second
60 mmcf per day train at the Dawson gas plant and, if approved, is
anticipated to increase the plant processing capacity from 60 mmcf
per day to 120 mmcf per day at a cost of approximately $50 million.
Preliminary feedback from the OGC has been positive to date.
Construction of Phase 2 is expected to be completed in the first
quarter of 2011, with the commissioning and start-up occurring in the
second quarter.
Engineering design work on the Sunrise plant is proceeding on
schedule. The required public consultation process was initiated in
April with the expectation that ARC will submit its plans to the
British Columbia Oil and Gas Commission in the third quarter of 2010.
Completion of the gas plant is planned for the first quarter of 2012.
ARC has also begun preliminary planning for a fourth gas plant for
the greater Dawson area to be on stream in 2013.
Over the past four months, ARC has acquired 80 net sections of land
(21,000 hectares) in twp 83 - 85 W6 northwest of Dawson. This
increases ARC's undeveloped land base in the main Montney fairway to
214 gross sections (198 net) and will increase further to 278 gross
sections (245 net) when the Storm acquisition closes.
- Ante Creek Montney Resource Play Development
During the second quarter ARC drilled one well. 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
seen production increase to 6,700 boe per day during the quarter with
peak daily production of 8,200 boe per day. Approximately 45 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 second quarter, ARC brought on
production all seven wells that were drilled in the first quarter
(five horizontal and two vertical). Thirty-day initial production
rates for each of the five horizontal wells averaged approximately
150 boe per day. ARC expects to spend at least another $30 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 second quarter of 2010, ARC spent $3.2 million on enhanced
oil recovery ("EOR") initiatives. Work on the Redwater CO(2) pilot
project continues and both the CO(2) injection and oil production
facilities are operating. Results to date are encouraging. 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 August 4, 2010 and should be read in conjunction with the unaudited Consolidated Financial Statements for the period 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 energy company and 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 with large volumes of oil and gas in place.
ARC's most significant resource plays include the Montney development
at Dawson, northeastern British Columbia, Ante Creek in northern
Alberta and the Cardium formation at Pembina in central Alberta. In
June 2010, ARC entered into an Arrangement Agreement to acquire the
Parkland Montney field in northeastern British Columbia through an
acquisition of Storm Exploration Inc.
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's total production for the six months ended June 30, 2010 was
balanced with 54 per cent of production from natural gas and 46 per
cent production from oil and natural gas liquids. 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. In 2008, ARC initiated
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 ARC's inception in July 1996, ARC has distributed $3.7 billion or $25.58 per unit. The remaining cash flow is used to fund reclamation costs and a portion of capital expenditures. During the first half of 2010, cash flow and proceeds from the DRIP program funded $204 million of capital expenditures and a net withdrawal of $1.4 million to the reclamation funds.
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 through drilling new wells and associated 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 Q2 2010 YTD 2010 2009 2008
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Normalized production, boe
per unit(1)(2) 0.27 0.27 0.27 0.29
Normalized reserves, boe
per unit(1)(3) N/A N/A 1.57 1.42
Distributions per unit $0.30 $0.60 $1.28 $2.67
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(1) Normalized indicates that all periods as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional trust units were issued (or repurchased) at a period
end price for the reserves per unit calculation and at an annual
average price for the production per unit calculation in order to
achieve a net debt balance of 15 per cent of total capitalization
each year. The normalized amounts are presented to enable
comparability of per unit values.
(2) Production per unit represents daily average production (boe) per
thousand trust units and is calculated based on daily average
production divided by the normalized weighted average trust units
outstanding including trust units issuable for exchangeable shares.
(3) Reserves per unit are calculated based on proved plus probable
reserves (boe), as determined by ARC's independent reserve evaluator
solely at year-end, divided by period end trust units outstanding
including trust units issuable for exchangeable shares.
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ARC's business plan has resulted in significant operational success and contributed to a trailing five year annualized return per unit of 9.4 per cent (Table 2).
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Table 2
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Total Returns(1) Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
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Distributions per unit 1.20 5.75 10.44
Capital appreciation per unit 1.92 (2.01) (0.21)
Annualized total return per unit 17.7% 6.0% 9.4%
Total return per unit 17.7% 19.0% 57.0%
S&P/TSX Exploration & Producers Index
total return 11.9% (8.8)% 27.3%
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(1) Calculated as at June 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 second quarter as compared to guidance:
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Table 3
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2010 Guidance 2010 Actual % Change
YTD
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Production (boe/d) 72,500 - 74,500 66,705 -
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Expenses ($/boe):
Operating costs 10.30 10.38 1
Transportation 1.00 1.14 14
G&A expenses (cash & non-cash) 2.85 3.12 9
Interest 1.40 1.52 9
Capital expenditures ($ millions) 625 272.3 -
Annual weighted average trust
units and trust units issuable
(millions) 264 253 -
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These guidance figures assume that the Storm acquisition will close on August 17, 2010. The first half 2010 results were in line with guidance with the exception of transportation, general and administrative ("G&A") expenses, and interest. Transportation exceeded guidance due to transportation costs incurred on a take-or-pay contract relating to gas deliveries from the Dawson Phase 1 gas plant that commenced two months prior to the commissioning of the plant. Cash G&A expenses to date are $2.49 per boe as compared to guidance of $2 per boe. G&A exceeded guidance due to higher staff compensation cost arising from a special performance bonus approved by the Board of Directors due to exceptional 2009 results. Interest exceeded guidance as a result of a one-time make whole premium payment on the early retirement of some senior secured notes. Revisions to the guidance for the aforementioned items have not been made at this time as these items are expected to normalize during the course of 2010. The 2010 Guidance provides unitholders with information on management's expectations for results of operations, excluding any acquisitions or dispositions for 2010. Readers are cautioned that the 2010 Guidance may not be appropriate for other purposes.
2010 Second Quarter Financial and Operational Results
Financial Highlights
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Table 4
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Three Months Ended Six Months Ended
June 30 June 30
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(Cdn$ millions,
except per unit
and volume data) 2010 2009 % Change 2010 2009 % Change
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Cash flow from
operating
activities 162.8 104.3 56 321.5 228.6 41
Cash flow from
operating
activities per
unit(1) 0.64 0.44 45 1.27 0.98 30
Net income 44.9 66.1 (32) 184.3 88.4 108
Net income per
unit(2) 0.18 0.28 (36) 0.74 0.38 95
Distributions
per unit(3) 0.30 0.32 (6) 0.60 0.68 (12)
Distributions
as a per cent
of cash flow
from operating
activities 46 72 (36) 47 69 (32)
Average daily
production
(boe/d)(4) 66,208 63,969 4 66,705 64,418 4
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(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
period end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units outstanding excluding trust units
issuable for exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf: 1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of boe in isolation may be
misleading.
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Cash Flow from Operating Activities
Cash flow from operating activities increased by 56 per cent in the second quarter of 2010 to $162.8 million from $104.3 million in the second quarter of 2009. The increase was primarily attributed to higher commodity prices and increased cash gains on risk management contracts offset by higher royalties. Details of the change in cash flow from operating activities in the second quarter of 2009 to the second quarter of 2010 are presented in Table 5.
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Table 5
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($ per
($ millions) trust unit) (% Change)
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Q2 2009 Cash flow from Operating
Activities 104.3 0.44 -
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Volume variance 8.2 0.03 7.9
Price variance 33.3 0.14 31.9
Cash gains on risk management
contracts 20.7 0.09 19.8
Royalties (20.0) (0.08) (19.2)
Expenses:
Transportation (2.8) (0.01) (2.7)
Operating(1) (5.5) (0.02) (5.3)
Cash G&A (1.5) (0.01) (1.4)
Interest 0.2 - 0.2
Realized foreign exchange gain 0.1 - 0.1
Weighted average trust units - (0.05) -
Non-cash and other items(2) 25.8 0.11 24.7
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Q2 2010 Cash flow from Operating
Activities 162.8 0.64 -
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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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Year-to-date cash flow from operating activities increased by 41 per cent in 2010 to $321.5 million from $228.6 million in the first half of 2009. The increase was attributed to higher commodity prices and higher volumes, offset by higher royalties. Details of the change in cash flow from operating activities during the first half of 2009 to the first half of 2010 are presented in Table 5a.
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Table 5a
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($ per
($ millions) trust unit) (% Change)
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YTD 2009 Cash flow from Operating
Activities 228.6 0.98 -
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Volume variance 16.3 0.07 7.2
Price variance 114.0 0.49 49.9
Cash gains on risk management
contracts 5.7 0.02 2.5
Royalties (34.9) (0.15) (15.3)
Expenses:
Transportation (3.2) (0.01) (1.4)
Operating(1) (2.1) (0.01) (0.9)
Cash G&A (12.3) (0.05) (5.4)
Interest (5.0) (0.02) (2.2)
Realized foreign exchange loss (0.4) - (0.2)
Weighted average trust units - (0.11) -
Non-cash and other items(2) 14.8 0.06 6.5
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YTD 2010 Cash flow from Operating
Activities 321.5 1.27 -
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(1) Excludes non-cash portion of Whole Unit Plan expense recorded in
operating costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
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2010 Cash Flow from Operating Activities Sensitivity
Table 6 illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the business environment and the resulting impact on cash flows from operating activities in total and per trust unit:
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Table 6
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Impact on Annual
Cash Flow from
Operating Activities(4)
Business Environment(1) Assumption Change $/Unit
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Oil price (US$WTI/bbl)(2)(3) $ 85.00 $ 1.00 $ 0.04
Natural gas price (Cdn$AECO/mcf)(2)(3) $ 4.25 $ 0.10 $ 0.03
Cdn$/US$ exchange rate(2)(3)(5) 1.05 $ 0.01 $ 0.03
Interest rate on debt(2) % 4.00 % 1.0 $ 0.01
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.03
Gas production volumes (mmcf/d) 240.0 % 1.0 $ 0.01
Operating expenses per boe $ 10.30 % 1.0 $ 0.01
Cash G&A and 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 they are presented
in Canadian dollars in this sensitivity.
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Net Income
Net income in the second quarter of 2010 was $44.9 million ($0.18 per unit), a $21.2 million decrease as compared to $66.1 million ($0.28 per unit) in the second quarter of 2009. While ARC realized higher revenues net of royalties and realized risk management contracts of $42.2 million compared to the second quarter of the prior year, net income was impacted by the following non-cash items during the second quarter of 2010 relative to the second quarter in 2009:
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- Higher foreign exchange losses of $52.6 million resulting from a
$12.6 million foreign exchange loss compared to a $40 million foreign
exchange gain in the second quarter of 2009.
- Higher unrealized risk management contracts gain of $7.2 million
resulting from a $6.6 million unrealized risk management contracts
gain compared to a $0.6 million unrealized risk management contracts
loss in the second quarter of 2009.
- Lower future income tax recovery of $7.3 million resulting from a
$5.7 million future income tax recovery compared to a $13 million
future income tax recovery in the second quarter of 2009.
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Production
Production volumes averaged 66,208 boe per day in the second quarter of 2010 compared to 63,969 boe per day in the same period of 2009 as detailed in Table 7. The increase in second quarter 2010 production is a result of an acquisition that closed in late 2009, new wells coming on production and the start-up of a new gas plant in the Dawson area that began processing gas in May 2010.
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Table 7
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Three Months Ended Six Months Ended
June 30 June 30
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Production 2010 2009 % Change 2010 2009 % Change
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Light & medium
crude oil
(bbl/d) 26,439 25,901 2 26,557 26,805 (1)
Heavy oil
(bbl/d) 915 1,016 (10) 939 1,051 (11)
Natural gas
(mmcf/d) 211.2 200.2 5 214.5 197.0 9
Natural gas
liquids ("NGL")
(bbl/d) 3,655 3,679 (1) 3,455 3,721 (7)
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Total production
(boe/d)(1) 66,208 63,969 4 66,705 64,418 4
% Natural gas
production 53 52 2 54 51 6
% Crude oil and
liquids
production 47 48 (2) 46 49 (6)
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(1) Reported production for a period may include minor adjustments from
previous production periods.
>>
Second quarter 2010 light and medium crude oil production increased to 26,439 barrels per day compared to 25,901 barrels per day in 2009, while heavy oil production declined by 101 barrels per day. The increase in light and medium oil production is mainly attributable to the acquisition of additional properties in Ante Creek in late 2009 and a successful drilling program at Goodlands, which helped offset natural decline. Natural gas production was 211.2 mmcf per day in the second quarter of 2010, an increase of five per cent from the 200.2 mmcf per day produced in the second quarter of 2009. The increase is also mainly attributable to the late 2009 acquisition of Ante Creek properties as well as new production from wells in the Montney West area that were tied into the new Dawson gas plant.
ARC's objective is to maintain annual production, to the fullest extent possible, through the drilling of wells and other development activities while giving consideration to capital spending constraints and the economics of developing ARC's resources. In fulfilling this objective, there may be fluctuations in production resulting from the timing of new wells coming on-stream. During the second quarter of 2010, ARC drilled 15 gross wells (15 net wells) on operated properties; 4 gross oil wells, and 11 gross natural gas wells with a 100 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. ARC estimates that total 2010 production will increase from a range of 11 to 14 per cent over 2009 production levels as a result of its 2010 drilling program and the start-up of its new gas plant in the Dawson area.
Table 8 summarizes ARC's production by core area:
<<
Table 8
-------------------------------------------------------------------------
Three Months Ended June 30, 2010
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,684 1,391 25.7 1,009
N.E. BC & N.W. AB 16,286 664 89.1 773
Northern AB 10,826 4,453 33.3 820
Pembina & Redwater 13,117 9,355 17.1 915
S.E. AB & S.W. Sask. 8,469 1,055 44.4 11
S.E. Sask. & MB 10,826 10,436 1.6 127
-------------------------------------------------------------------------
Total 66,208 27,354 211.2 3,655
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Months Ended June 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,918 1,084 28.4 1,101
N.E. BC & N.W. AB 14,477 708 78.3 718
Northern AB 8,981 3,976 25.2 801
Pembina & Redwater 13,214 9,181 18.7 919
S.E. AB & S.W. Sask. 9,026 1,001 48.1 12
S.E. Sask. & MB 11,353 10,967 1.5 128
-------------------------------------------------------------------------
Total 63,969 26,917 200.2 3,679
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 half of 2010:
<<
Table 8a
-------------------------------------------------------------------------
Six Months Ended June 30, 2010
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,638 1,311 25.9 1,008
N.E. BC & N.W. AB 16,577 677 91.0 724
Northern AB 10,913 4,579 32.9 859
Pembina & Redwater 13,124 9,322 18.3 752
S.E. AB & S.W. Sask. 8,542 1,050 44.9 12
S.E. Sask. & MB 10,911 10,557 1.5 100
-------------------------------------------------------------------------
Total 66,705 27,496 214.5 3,455
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six Months Ended June 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,023 1,236 28.1 1,108
N.E. BC & N.W. AB 14,050 731 75.8 674
Northern AB 9,235 4,163 25.3 853
Pembina & Redwater 13,504 9,413 18.9 946
S.E. AB & S.W. Sask. 8,909 998 47.4 13
S.E. Sask. & MB 11,697 11,315 1.5 127
-------------------------------------------------------------------------
Total 64,418 27,856 197.0 3,721
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $276.7 million in the second quarter of 2010, an increase of $41.5 million over 2009 revenue of $235.2 million. Of the $41.5 million increase, $40.5 million related to the increase in commodity prices for crude oil, natural gas, and natural gas liquids, with the remaining $1 million attributable to higher volumes.
A breakdown of revenue is outlined in Table 9:
<<
Table 9
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
Revenue June 30 June 30
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Oil revenue 179.2 153.7 17 368.9 274.1 35
Natural gas
revenue 79.2 68.0 16 185.5 158.6 17
NGL revenue 17.6 13.0 35 35.3 26.2 35
-------------------------------------------------------------------------
Total commodity
revenue 276.0 234.7 18 589.7 458.9 29
Other revenue 0.7 0.5 40 1.1 1.5 (27)
-------------------------------------------------------------------------
Total revenue 276.7 235.2 18 590.8 460.4 28
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commodity Prices Prior to Hedging
Table 10
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Average
Benchmark
Prices
AECO gas
($/mcf)(1) 3.86 3.66 5 4.60 4.64 (1)
WTI oil
(US$/bbl)(2) 77.99 59.62 31 78.39 51.46 52
Cdn$/US$
exchange rate 1.03 1.16 11 1.03 1.20 14
WTI oil
(Cdn$/bbl) 80.07 69.25 16 81.00 61.59 32
-------------------------------------------------------------------------
ARC Realized
Prices Prior
to Hedging
Oil ($/bbl) 71.98 62.74 15 74.12 54.36 36
Natural gas
($/mcf) 4.12 3.73 10 4.78 4.45 7
NGL ($/bbl) 53.02 38.89 36 56.44 38.88 45
-------------------------------------------------------------------------
Total commodity
revenue before
hedging ($/boe) 45.82 40.32 14 48.84 39.36 24
Other revenue
($/boe) 0.11 0.09 22 0.09 0.13 (31)
-------------------------------------------------------------------------
Total revenue
before hedging
($/boe) 45.93 40.41 14 48.93 39.49 24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents posting price of West Texas Intermediate oil.
>>
Oil prices continued to recover in the second quarter of 2010 with WTI averaging US$77.99 per barrel as compared to US$59.62 per barrel for the second 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 partially mitigated by a narrowing of price differentials. 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 $71.98 per barrel, a 15 per cent increase over the second quarter 2009 realized price of $62.74 per barrel.
Natural gas prices increased by five percent in the second quarter of 2010 in comparison to the second quarter of 2009. Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged $3.86 per mcf in the second quarter of 2010 compared to $3.66 per mcf in the same period of 2009. ARC's realized gas price, before hedging, increased by ten per cent to $4.12 per mcf compared to $3.73 per mcf in the second quarter of 2009. From April 2010 to June 2010, the AECO daily index steadily increased. The start-up of the Dawson gas plant and the subsequent increase in ARC's gas production coincided with the increase in gas prices so that ARC's realized gas price for the quarter was higher than both the quarterly average AECO monthly index and AECO daily index. 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 being unusually high for this time of year. The forward curve for natural gas prices has remained constant from the first quarter of 2010 to the second quarter of 2010, with prices expected to range from $3.50 to $4.50 per mcf for the remaining two quarters of 2010.
Prior to hedging activities, ARC's total realized commodity price was $45.82 per boe in the second quarter of 2010, a 14 per cent increase from the $40.32 per boe received prior to hedging in the second quarter of 2009.
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 second quarter of 2010, ARC realized $18.8 million of cash gains on its risk management contracts. The largest contributor to the cash gains was $17.9 million recorded on ARC's natural gas swaps, offset by cash losses of $3.5 million on ARC's natural gas basis swap contracts.
In the second quarter of 2010, ARC recorded a $6.6 million unrealized mark-to-market gain on its risk management contracts, resulting in a net fair value of $86 million at June 30, 2010. The net gain position is primarily attributed to ARC's crude oil contracts, with the June 30, 2010 forward outlook on WTI softening slightly from March 31, 2010. ARC also recorded a $14.9 million unrealized loss on its natural gas contracts that was due to the realization of gains during the second quarter of 2010 that had been recognized in previous periods. The fair value of risk management contracts represent the expected market price to buy-out ARC's contracts as of June 30, 2010 and may differ from what will eventually be realized.
Table 11 summarizes the total gain (loss) on risk management contracts for the second quarter of 2010 as compared to the same period in 2009:
<<
Table 11
-------------------------------------------------------------------------
Risk
Management
Contracts Crude Oil Natural Foreign Q2 2010 Q2 2009
($ millions) & Liquids Gas Currency Power(3) Total Total
-------------------------------------------------------------------------
Realized
cash gain
(loss) on
contracts(1) 3.0 14.4 0.3 1.1 18.8 (1.9)
Unrealized
gain (loss)
on
contracts(2) 18.7 (14.9) 0.7 2.1 6.6 (0.6)
-------------------------------------------------------------------------
Total gain
(loss) on
risk
management
contracts 21.7 (0.5) 1.0 3.2 25.4 (2.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $0.2 million realized gain
and a $0.5 million unrealized gain for ARC's power contracts that
have been designated as effective hedges for accounting purposes
(2009 - realized losses of $0.9 million and unrealized losses of $0.2
million, respectively). Realized gains and losses on these contracts
are recorded in operating costs and unrealized gains and losses are
recorded in the Consolidated Statement of Comprehensive Income and
Accumulated Other Comprehensive Income.
>>
Table 11a summarizes the total gain (loss) on risk management contracts for the first half of 2010 as compared to the same period in 2009:
<<
Table 11a
-------------------------------------------------------------------------
Risk
Management
Contracts Crude Oil Natural Foreign YTD 2010 YTD 2009
($ millions) & Liquids Gas Currency Power(3) Total Total
-------------------------------------------------------------------------
Realized
cash gain on
contracts(1) 3.2 14.6 1.6 0.7 20.1 14.4
Unrealized
gain (loss)
on
contracts(2) 16.2 69.3 0.1 4.7 90.3 (7.2)
-------------------------------------------------------------------------
Total gain
on risk
management
contracts 19.4 83.9 1.7 5.4 110.4 7.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 nominal realized loss and a
$0.5 million unrealized gain for ARC's power contracts that have been
designated as effective hedges for accounting purposes (2009 -
realized losses of $0.8 million and unrealized losses of $3.2
million, respectively). Realized gains and losses on these contracts
are recorded in operating costs and unrealized gains and losses are
recorded in the Consolidated Statement of Comprehensive Income and
Accumulated Other Comprehensive Income.
>>
ARC currently limits the amount of forecast production that can be hedged to a maximum 50 per cent. The following table is a summary of ARC's risk management contract positions for crude oil and natural gas as at June 30, 2010.
<<
Table 12
-------------------------------------------------------------------------
Hedge Positions
As at June 30, 2010(1)(2)
Q3 2010 Q4 2010
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 92.00 15,000 92.00 15,000
Bought Put 76.67 15,000 76.67 15,000
Sold Put 59.09 11,000 59.09 11,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Swap 5.60 101,101 5.61 87,110
Sold Call 5.05 10,000 5.05 10,000
Bought Put 4.00 10,000 4.00 10,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Hedge Positions
As at June 30, 2010(1)(2)
Q1 2011 Q2-Q4 2011
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 100.00 5,000 100.00 5,000
Bought Put 80.00 5,000 80.00 5,000
Sold Put 60.00 5,000 60.00 5,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Swap 6.06 45,000 6.06 45,000(3)
Sold Call - - - -
Bought Put - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The prices and volumes noted above represent averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price based on offsetting basis
positions and the quarter end exchange rate.
(2) In addition to positions shown here, ARC has entered into additional
basis positions. Please refer to note 7 in the Notes to the
Consolidated Financial Statements for full details of ARC's risk
management positions as of June 30, 2010.
(3) The natural gas positions for 2011 extend until December 31, 2013 for
the same volume and price levels.
>>
Table 12 should be interpreted as follows, using the third quarter 2010 crude oil hedges as an example. To accurately analyze ARC's hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading. The following provides examples of how the chart above can be interpreted for approximate values for the third quarter of 2010:
<<
- 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.
- 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 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 exceeds $92 per barrel, ARC will receive $92 per
barrel on 15,000 barrels per day.
>>
Operating Netbacks
ARC's operating netback, before realized hedging gains and losses, increased six per cent to $25.30 per boe in the second quarter of 2010 compared to $23.82 per boe in the same period of 2009. The increase in netbacks is due mainly to the increase in commodity prices partially offset by an increase in royalties in the period.
ARC's second quarter 2010 netback, after realized hedging gains and losses, was $28.38 per boe, a 21 per cent increase from the same period in 2009. The 2010 netback includes net gains recorded on ARC's crude oil and natural gas risk management contracts during the quarter of $3.08 per boe compared to a net loss of $0.46 per boe recorded for the same period in 2009.
The components of operating netbacks are summarized in Table 13:
<<
Table 13
-------------------------------------------------------------------------
Heavy Q2 2010 Q2 2009
Netbacks Crude Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted
average
sales price 72.29 63.00 4.12 53.02 45.82 40.32
Other revenue - - - - 0.11 0.09
-------------------------------------------------------------------------
Total revenue 72.29 63.00 4.12 53.02 45.93 40.41
Royalties (12.65) (8.68) (0.57) (16.17) (7.89) (4.72)
Transportation (0.38) (1.18) (0.34) - (1.28) (0.85)
Operating
costs(1) (15.74) (15.42) (1.38) (10.10) (11.46) (11.02)
-------------------------------------------------------------------------
Netback prior
to hedging 43.52 37.72 1.83 26.75 25.30 23.82
Realized gain
(loss) on risk
management
contracts(2) 1.73 - 0.75 - 3.08 (0.46)
-------------------------------------------------------------------------
Netback after
hedging 45.25 37.72 2.58 26.75 28.38 23.36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 74.45 65.49 4.78 56.44 48.84 39.36
Other revenue - - - - 0.09 0.13
-------------------------------------------------------------------------
Total revenue 74.45 65.49 4.78 56.44 48.93 39.49
Royalties (13.02) (8.47) (0.63) (17.39) (8.24) (5.53)
Transportation (0.25) (1.14) (0.31) - (1.14) (0.90)
Operating
costs(1) (13.43) (13.28) (1.37) (8.60) (10.38) (10.57)
-------------------------------------------------------------------------
Netback prior
to hedging 47.75 42.60 2.47 30.45 29.17 22.49
Realized gain
on risk
management
contracts(2) 0.82 - 0.38 - 1.53 0.76
-------------------------------------------------------------------------
Netback after
hedging 48.57 42.60 2.85 30.45 30.70 23.25
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 include the
settlement amounts for crude oil and natural gas and power contracts.
Foreign exchange and interest contracts are excluded from the net
back calculation.
>>
Royalties as a percentage of pre-hedged commodity revenue net of transportation increased from 11.9 per cent ($4.72 per boe) in the second quarter of 2009 to 17.2 per cent ($7.89 per boe) in 2010. In the second quarter of 2009, ARC recorded one-time credits relating to additional operating cost deductions that are applied in determining the natural gas royalties in British Columbia. In addition, with the increase in commodity prices in the second quarter of 2010 relative to the same period in 2009, the price component of crown royalty rates contributed to the increase in royalties.
The Alberta Royalty Framework ("Framework" or "ARF") took effect January 1, 2009 and provides for sliding scale crown royalty rates, whereby rates increase in high commodity price environments and decrease in low commodity price environments. The 2010 royalty rate is in line with management's expectations due to the low natural gas price environment.
Royalty rates in the other western provinces vary with production levels and price but to a lesser extent than Alberta royalty rates. Table 14 estimates the royalties applicable to production from ARC's properties at various price levels.
<<
Table 14
-------------------------------------------------------------------------
Royalty Rates - Forecast for 2010
-------------------------------------------------------------------------
Edmonton posted oil (Cdn/$/bbl)(1) $60 $80 $100
AECO natural gas (Cdn$/mcf)(1) $4.00 $5.50 $6.50
-------------------------------------------------------------------------
Alberta royalty rate 12.6% 18.1% 22.6%
Saskatchewan royalty rate(2) 17.9% 17.9% 17.9%
British Columbia royalty rate(2) 17.0% 17.0% 17.0%
Manitoba royalty rate(2) 13.0% 13.0% 13.0%
-------------------------------------------------------------------------
Total Corporate Royalty Rate 14.6% 17.8% 20.4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 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 June 30, 2010, ARC has received or accrued credits of $8.1 million and estimates it will generate a maximum $15.5 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. During the second quarter of 2010 the Alberta government clarified specific details of their competitive review that resulted in changes to some of the existing programs. These changes will come into effect January 1, 2011.
During 2009, the British Columbia government announced a new stimulus package designed to attract investment and produce immediate economic benefits for the province. The stimulus package included royalty incentives in the form of reduced royalty rates for wells drilled in the province between September 1, 2009 and June 30, 2010 and modifications to the existing deep well drilling program to increase available credits and expand depth criteria whereby additional wells may qualify for the program. ARC estimates that the deep well drilling credits could save approximately $1 million per horizontal well drilled. These credits will be recorded as a reduction to royalty expense to the extent that royalties are incurred on the well drilled.
In addition, the British Columbia government implemented a two per cent maximum royalty rate for a period of 12 months on wells drilled and produced from between September 30, 2009 and June 30, 2010. The majority of ARC's Montney wells qualify for the deep drilling credit. For wells that do not qualify, the impact of the two per cent maximum royalty incentive is approximately $1 million per well at natural gas prices of $3 per mcf to $2.5 million per well at natural gas prices of $7 per mcf. Wells that qualify for the drilling credit program must draw down the drilling credit before qualifying for the reduced royalty program. Management plans to drill wells in British Columbia on operated properties during the incentive period in order to maximize the total benefit to ARC and its unitholders. During the first six months of 2010, new wells drilled that qualified for the two per cent royalty incentive were brought on production.
Operating costs increased to $11.46 per boe in the second quarter of 2010 compared to $11.02 per boe in 2009. The increase is attributable to higher power costs and higher than normal seasonal maintenance costs. Furthermore, the start-up of the Dawson gas plant and some of its initial operational challenges discussed previously slightly impacted the total increase in operating costs. ARC has entered into financial contracts to protect netbacks against high power costs. During the second quarter of 2010 and 2009, ARC recorded a realized gain of $0.19/boe and a loss of $0.08/boe, respectively, on risk management contracts related to power hedging.
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 41 per cent to $14.4 million in the second quarter of 2010 from $10.2 million in 2009. The increase in G&A is mainly due to higher compensation levels in the second quarter of 2010 relative to the same period in 2009 and an increase in rent expense due to the relocation of ARC's head office. ARC realized higher operating recoveries from its partners due to a larger capital program, which partially offset the increase in G&A.
ARC did not make any payments under the Whole Unit Plan in the second quarter of 2010. For the six months ended June 30, 2010 a cash payment was made of $15.1 million, of which $11 million was recorded in G&A with the remaining $4.1 million recorded to operating costs and property, plant and equipment. The next cash payment under the Whole Unit Plan is scheduled to occur in September 2010.
Table 15 is a breakdown of G&A and incentive compensation expense under the Whole Unit Plan:
<<
Table 15
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
G&A and Trust Unit
Incentive
Compensation
Expense
($ millions except
per boe) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
G&A expenses 18.7 13.8 36 37.7 28.6 32
Operating
recoveries (4.3) (3.6) 20 (7.6) (8.0) (5)
-------------------------------------------------------------------------
Cash G&A expenses
before Whole
Unit Plan 14.4 10.2 41 30.1 20.6 46
Cash Expense -
Whole Unit Plan - - - 11.0 5.6 96
-------------------------------------------------------------------------
Cash G&A expenses
including Whole
Unit Plan 14.4 10.2 41 41.1 26.2 57
Accrued
compensation -
Whole Unit Plan 2.1 7.3 (71) (3.4) (3.6) (6)
-------------------------------------------------------------------------
Total G&A and
incentive
compensation
expense 16.5 17.5 (6) 37.7 22.6 67
-------------------------------------------------------------------------
Total G&A and
incentive
compensation
expense per
boe 2.74 2.99 (8) 3.12 1.94 61
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
A non-cash Whole Unit Plan expense of $2.1 million ($0.35 per boe) was recorded in the second quarter of 2010 compared to an expense of $7.3 million ($1.25 per boe) in the second 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 six months of 2010 along with the estimated value upon vesting of the plan as at June 30, 2010:
<<
Table 16
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and Number of Number of Total
$ millions except per unit) RTUs PTUs RTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 1,052 1,305 2,357
Granted in the period 241 224 465
Vested in the period (249) (151) (400)
Forfeited in the period (48) (99) (147)
-------------------------------------------------------------------------
Balance, end of period(1) 996 1,279 2,275
Estimated distributions to
vesting date(2) 166 289 455
-------------------------------------------------------------------------
Estimated units upon vesting
after distributions 1,162 1,568 2,730
Performance multiplier(3) - 1.1 -
-------------------------------------------------------------------------
Estimated total units upon vesting 1,162 1,730 2,892
-------------------------------------------------------------------------
Trust unit price at June 30, 2010 19.73 19.73 19.73
Estimated total value upon
vesting ($ millions) 22.9 34.1 57.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 1.1 at June 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 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 June 30, 2010:
<<
Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan
as at June 30, 2010 Performance multiplier
(units thousands and $ millions -------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated units to vest
RTUs 1,162 1,162 1,162
PTUs - 1,568 3,136
-------------------------------------------------------------------------
Total units(1) 1,162 2,730 4,298
-------------------------------------------------------------------------
Trust unit price(2) 19.73 19.73 19.73
Trust unit distributions per month(2) 0.10 0.10 0.10
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting(3) 22.9 53.9 84.8
-------------------------------------------------------------------------
2010 4.8 9.1 13.5
2011 9.4 17.3 25.0
2012 6.9 20.7 34.5
2013 1.8 6.8 11.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $19.73 and $0.10 per trust unit
distributions based on the unit price and distribution levels in
place at June 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 $22.9 million and $84.8 million will be paid out from 2010 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 remained unchanged at $7.4 million in the second quarter of 2010 from $7.6 million in 2009 as net debt remained consistent between June 30, 2009 and June 30, 2010. As at June 30, 2010, ARC has $670.8 million of long-term debt outstanding, of which $488.5 million was fixed at a weighted average interest rate of 5.8 per cent. On the remaining $182.3 million, ARC pays a floating interest rate based on current market rates plus a credit spread of 60 to 70 basis points. Approximately 69 per cent (US$433.2 million) of ARC's debt outstanding is denominated in U.S. dollars.
Foreign Exchange Gains and Losses
ARC recorded a loss of $12.6 million in the second quarter of 2010 on foreign exchange transactions compared to a gain of $40 million in 2009. These amounts include both realized and unrealized foreign exchange gains and losses.
Table 18 shows the various components of foreign exchange gains and losses:
<<
Table 18
-------------------------------------------------------------------------
Foreign Exchange Three Months Ended Six Months Ended
Gains/Losses June 30 June 30
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Unrealized (loss)
gain on U.S.
denominated
debt (20.5) 42.6 (148) (29.8) 28.3 (205)
Realized gain
(loss) on U.S.
denominated
debt 7.5 (2.9) 359 28.3 (3.0) -
Realized gain
(loss) on U.S.
denominated
transactions 0.4 0.3 33 (0.3) 0.1 (400)
-------------------------------------------------------------------------
Total foreign
exchange (loss)
gain (12.6) 40.0 (132) (1.8) 25.4 (107)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Realized foreign exchange gains or losses arise from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements. During the second quarter of 2010, ARC realized a $7.5 million foreign exchange gain resulting from $91.6 million of net repayment of long-term debt under its credit facilities and a $6.4 million repayment of senior secured notes during the quarter. This debt repayment was financed with the issuance of US$150 million of new senior notes.
Unrealized foreign exchange gains and losses are due to the revaluation of U.S. denominated debt balances. The volatility of the Canadian dollar during the reporting period has a direct impact on the unrealized component of the foreign exchange gain or loss. The unrealized gain or loss impacts net income but does not impact cash flow from operating activities as it is a non-cash item. From March 31, 2010 to June 30, 2010, the Cdn$/US$ exchange rate increased from 1.02 to 1.06 resulting in an unrealized loss of $13 million on U.S. dollar denominated debt, offset by the removal of $7.5 million of realized foreign exchange gains from the unrealized foreign exchange balance. This results in a net unrealized foreign exchange loss of $20.5 million.
Taxes
In the second quarter of 2010, a future income tax recovery of $5.7 million was recorded compared to $13 million in 2009. The reduction in recovery in 2010 was primarily attributed to temporary differences associated with the carrying value of ARC's property, plant and equipment and its accumulated tax pools.
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 second 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 strategy and the detailed implementation steps are currently being defined. The conversion plan will be mailed to unitholders prior to a unitholder meeting planned for 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.
Management continues to refine its plan for converting ARC Energy Trust to a corporation on January 1, 2011. Following the conversion, the corporation expects to allocate its 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 $2.2 billion of income tax pools for federal tax purposes, taxable income will be reduced or potentially eliminated for the initial period post conversion. The income tax pools (detailed in Table 19) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.
<<
Table 19
-------------------------------------------------------------------------
Cdn$ millions at
Income Tax Pool type June 30, 2010 Annual deductibility
-------------------------------------------------------------------------
Canadian Oil and Gas
Property Expense 961.9 10% declining balance
Canadian Development Expense 406.4 30% declining balance
Canadian Exploration Expense 85.4 100%
Un-depreciated Capital Cost 524.8 Primarily 25%
declining balance
Non-Capital Losses 160.3 100%
Research and Experimental
Expenditures 22.2 100%
Other 27.7 Various rates, 7%
declining balance to 20%
-------------------------------------------------------------------------
Total Federal Tax Pools 2,188.7
-------------------------------------------------------------------------
Additional Alberta Tax Pools 177.6 Various rates, 25%
declining balance to 100%
-------------------------------------------------------------------------
Total Federal and Provincial Pools 2,366.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
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.
Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate remained fairly consistent at $16.86 per boe in the second quarter of 2010 from $16.89 per boe in the second quarter of 2009. ARC posted a large increase in proved reserves at year-end 2009; however, these reserves were offset by a significant increase in the future development costs required to convert proven undeveloped reserves to proven producing reserves. In the second quarter of 2010, ARC relocated to a new head office and began depreciating the associated leasehold improvements and construction costs. In previous periods, nominal depreciation had been recognized.
A breakdown of the DD&A rate is summarized in Table 20:
<<
Table 20
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
DD&A Rate
($ millions except
per boe amounts) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Depletion of oil
and gas
assets(1) 98.3 94.9 4 197.5 190.0 4
Depreciation of
fixed assets 0.8 - 100 0.8 - 100
Accretion of asset
retirement
obligation(2) 2.5 2.3 9 4.9 4.6 7
-------------------------------------------------------------------------
Total DD&A 101.6 97.2 5 203.2 194.6 4
DD&A rate
per boe 16.86 16.89 - 16.83 16.69 1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 $144 million in the second quarter of 2010 compared to $48.9 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 second quarter, $75.2 million was spent on ARC's resource plays, including $71.1 million for the Montney resource play in Northeast British Columbia and $2.4 million for the Cardium resource play in Alberta. A total of $58.5 million was spent on ARC's conventional oil and gas properties, $3.2 million on ARC's enhanced oil recovery initiatives, and the balance of $7.1 million was spent on corporate capital items relating mainly to ARC's new office space in downtown Calgary. Total capital expenditures are forecast to be $625 million in 2010.
A breakdown of capital expenditures and net acquisitions is shown in Table 21:
<<
Table 21
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
Capital
Expenditures
($ millions) 2010 2009 % Change 2010 2009 % Change
-------------------------------------------------------------------------
Geological and
geophysical 3.6 5.0 (28) 10.2 7.8 31
Drilling and
completions 84.9 18.6 356 162.1 87.1 86
Plant and
facilities 26.9 23.6 14 56.4 48.7 16
Undeveloped land
purchased at
crown land
sales 21.5 0.2 - 25.4 0.4 -
Other capital 7.1 1.5 373 18.2 2.1 767
-------------------------------------------------------------------------
Total capital
expenditures
before net
acquisitions 144.0 48.9 194 272.3 146.1 86
-------------------------------------------------------------------------
Producing
property
acquisitions(1) - 0.1 (100) 6.3 0.2 -
Undeveloped
land property
acquisitions - 2.2 (100) - 8.3 (100)
Producing
property
dispositions(1) - - - - - -
Undeveloped
land property
dispositions - - - - - -
-------------------------------------------------------------------------
Total capital
expenditures
and net
acquisitions 144.0 51.2 181 278.6 154.6 80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
>>
Approximately 71 per cent of the $144 million capital program in the second quarter of 2010 was financed with cash flow from operating activities and proceeds from the distribution re-investment plan ("DRIP") compared to 90 per cent for the same period of 2009. On a year-to date basis, ARC has funded 75 per cent of the capital expenditures with cash flow from operating activities and proceeds from DRIP as compared to 73 per cent for the first six months of 2009.
<<
Table 22
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30, 2010 June 30, 2009
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------
Expenditures 144.0 - 144.0 48.9 2.3 51.2
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating
activities 60% - 60% 55% - 53%
Proceeds from
distribution
re-investment
plan ("DRIP") 11% - 11% 35% - 33%
Debt/(excess funding) 29% - 29% 10% 100% 14%
-------------------------------------------------------------------------
100% - 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 22a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Six Months Ended Six Months Ended
June 30, 2010 June 30, 2009
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------
Expenditures 272.3 6.3 278.6 146.1 8.5 154.6
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 63% - 62% 49% - 46%
Proceeds from
distribution
re-investment
plan ("DRIP") 12% - 11% 24% - 23%
Debt/(excess funding) 25% 100% 27% 27% 100% 31%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Asset Retirement Obligation and Reclamation Fund
At June 30, 2010, ARC recorded an Asset Retirement Obligation ("ARO") of $146 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 to reflect ARC's cost of borrowing for the period ended June 30, 2010.
Included in the June 30, 2010 ARO balance is a $0.6 million increase related to development activities and changes in estimates in the first six months of 2010, a decrease of $5.7 million relating to the change in estimated future obligations, $4.9 million for accretion expense in the period and a reduction of $3.7 million for actual abandonment expenditures incurred in the first six 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. Future contributions for the two funds will vary over time in order to provide for the total estimated future abandonment and reclamation costs that are to be incurred upon abandonment of ARC's properties. Minimum contributions to the Redwater fund over the next 46 years will be approximately $86 million. The general fund has no minimum contribution requirement; however, the board of directors has approved voluntary contributions that currently result in annual contributions of $6 million.
ARC's reclamation funds totaled $31.9 million as at June 30, 2010, compared to $33.2 million as at December 31, 2009. Under the terms of ARC's investment policy, reclamation fund investments and excess cash can only be invested in Canadian or U.S. Government securities, investment grade corporate bonds, or investment grade short-term money market securities.
Capitalization, Financial Resources and Liquidity
A breakdown of ARC's capital structure is outlined in Table 23, as at June 30, 2010 and December 31, 2009:
<<
Table 23
-------------------------------------------------------------------------
Capital Structure and Liquidity June 30, December 31,
($ millions except per cent and ratio amounts) 2010 2009
-------------------------------------------------------------------------
Long-term debt 670.8 846.1
Working capital deficit(1) 58.0 56.3
-------------------------------------------------------------------------
Net debt obligations(2) 728.8 902.4
Market value of trust units and
exchangeable shares(3) 5,003.5 4,765.7
-------------------------------------------------------------------------
Total capitalization(4) 5,732.3 5,668.1
-------------------------------------------------------------------------
Net debt as a percentage of
total capitalization 12.7% 15.9%
Net debt to annualized YTD cash flow
from operating activities 1.1 1.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Working capital deficit is calculated as current liabilities less
the current assets as they appear on the Consolidated Balance Sheets,
and excludes current unrealized amounts pertaining to risk management
contracts and the current portion of future income taxes.
(2) Net debt is a non-GAAP measure and therefore it may not be comparable
with the calculation of similar measures for other entities.
(3) Calculated using the total trust units outstanding at June 30 and
December 31 including the total number of trust units issuable for
exchangeable shares at June 30 and December 31 multiplied by the
closing trust unit price of $19.73 and $19.94 at June 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.
>>
During the second quarter of 2010, ARC issued US$150 million of long-term notes with a coupon rate of 5.36 per cent and an average life of ten years. Proceeds from the issuance were used to repay existing long-term debt under the syndicated credit facility.
At June 30, 2010, ARC had total credit facilities of $1.4 billion with $670.8 million currently drawn resulting in unused credit available of $742.3 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 US 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 US Base Rate Loans were made 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. 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 will increase 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 June 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 2.0 times cash flow from operating activities and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels throughout 2009 and 2010 and has positioned ARC to remain well below the debt covenant levels of 3.0 times. In 2010, with the closing of the equity offering, debt to cash flow from operating activities ratio declined to 1.1 times from 1.8 times in 2009. The expectation is that an increase in production volumes will result in further declines in this ratio during the course of the year assuming commodity prices remain stable.
The weak global economic situation in 2008 and 2009 impacted ARC along with all other oil and gas entities by restricting access to capital and increasing borrowing costs. The credit situation improved dramatically during the third and fourth quarters of 2009 and the first half of 2010 in the three markets that ARC typically uses to raise capital: equity, bank debt and long- term notes.
ARC also accesses long-term debt from large institutional investors by issuing long-term notes, 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 June 30, 2010, there were 253.6 million trust units issued and issuable for exchangeable shares, an increase of 14.6 million trust units from December 31, 2009 due mostly to the issuance of 13 million trust units as part of an equity offering closed in January 2010. The 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 six months of 2010, ARC raised proceeds of $31.3 million and issued 1.6 million trust units pursuant to the DRIP at an average price of $20.01 per unit.
Distributions
In the second quarter of 2010, ARC declared distributions of $75.3 million ($0.30 per unit), representing 46 per cent of 2010 second quarter cash flow from operating activities compared to distributions of $75 million ($0.32 per unit) representing 72 per cent of cash flow from operating activities in the second quarter of 2009.
The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders:
<<
- a portion of capital expenditures;
- annual contribution to the reclamation funds;
- debt principal repayments;
- income tax if any; and
- certain obligations for future payments relative to the long-term
incentive compensation under the Whole Unit Plan.
>>
Cash flow from operating activities and distributions in total and per unit are summarized in Table 24 and Table 24a:
<<
Table 24
-------------------------------------------------------------------------
Cash flow from Three Months Ended Three Months Ended
operating June 30 June 30
activities and 2010 2009 % Change 2010 2009 % Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 162.8 104.3 56 0.64 0.44 45
Net reclamation
fund
contributions(1) (1.6) (2.3) (30) (0.01) (0.01) -
Capital expenditures
funded with cash
flow from
operating
activities (85.9) (27.0) 218 (0.34) (0.11) 209
Other(2) - - - 0.01 - -
-------------------------------------------------------------------------
Distributions 75.3 75.0 - 0.30 0.32 (6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Table 24a
-------------------------------------------------------------------------
Cash flow from Six Months Ended Six Months Ended
operating June 30 June 30
activities and 2010 2009 % Change 2010 2009 % Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 321.5 228.6 41 1.27 0.98 30
Net reclamation
fund withdrawals
(contributions)(1) 1.4 (0.8) 175 0.01 - -
Capital
expenditures
funded with cash
flow from
operating
activities (172.6) (70.8) 144 (0.68) (0.30) 126
Other(2) - - - - - -
-------------------------------------------------------------------------
Distributions 150.3 157.0 (4) 0.60 0.68 (12)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operated activities are based on weighted average outstanding trust
units in the period.
>>
ARC continually assesses distribution levels, in light of commodity prices, capital expenditure programs and production volumes, to ensure that distributions are in line with the long-term strategy and objectives of ARC as per the following guidelines:
<<
- To maintain a level of distributions that, in normal times, in the
opinion of management and the board of directors, is sustainable for
a minimum period of six months after factoring in the impact of
current commodity prices on cash flows. ARC's objective is to
normalize the effect of volatility of commodity prices rather than to
pass on that volatility to unitholders in the form of fluctuating
monthly distributions.
- To ensure that ARC's financial flexibility is maintained by a review
of ARC's debt to equity and debt to cash flow from operating
activities levels. The use of cash flow from operating activities and
proceeds from equity offerings to fund capital development activities
reduces the requirements of ARC to use debt to finance these
expenditures. In the first six months of 2010, ARC funded 75 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 $0.10 per unit per month in May 2009.
<<
Table 25
-------------------------------------------------------------------------
Net income and Distributions
($ millions except per cent and Second quarter Full year Full year
per unit amounts) 2010 2009 2008
-------------------------------------------------------------------------
Net income 44.9 222.8 533.0
Distributions 75.3 298.5 570.0
-------------------------------------------------------------------------
Excess (Shortfall) (30.4) (75.7) (37.0)
Excess (Shortfall) as per cent
of net income (68%) (34%) (7%)
-------------------------------------------------------------------------
Cash flow from operating activities 162.8 497.4 944.4
Distributions as a per cent of
cash flow from operating activities 46% 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) 0.60 0.58 0.02
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 $ 25.58 $ 18.65 $ 6.93
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on distributions paid and payable in 2006.
(2) Based on distributions declared at June 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) 25.6 263.8 87.7 293.7 670.8
Interest payments(2) 28.0 51.5 41.4 64.2 185.1
Reclamation fund
contributions(3) 4.9 8.9 7.7 64.2 85.7
Purchase commitments 44.1 32.3 14.0 11.9 102.3
Transportation
commitments 8.0 30.0 22.3 17.4 77.7
Operating leases 3.9 14.2 14.7 68.4 101.2
Risk management
contract premiums(4) 0.5 - - - 0.5
-------------------------------------------------------------------------
Total contractual
obligations 115.0 400.7 187.8 519.8 1,223.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 7 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 June 30, 2010 on the balance sheet as part of risk management contracts.
On June 9, 2010, ARC announced that it had entered an Arrangement Agreement whereby ARC will acquire all of the existing and outstanding common shares of Storm Exploration Inc. ("Storm"). Pursuant to the arrangement agreement and subject to Storm's shareholder and regulatory approval, each Storm shareholder can elect to receive either 0.57 of an ARC trust unit or, subject to adjustment, 0.2021 of an ARC Resources Ltd. exchangeable share. At the date of announcement, the transaction was valued at approximately $680 million plus the assumption of approximately $90 million of total debt. The transaction is expected to close on August 17, 2010.
ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. ARC's 2010 capital budget has been approved by the Board at $625 million. 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 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 June 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.
The ARC leadership team's mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with ARC's environmental, health and safety policies.
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 June 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 six months of 2010.
Financial Reporting Update
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 second quarter of 2010, the process of training key accounting and finance personnel as well as the senior management team has continued. Internal and external IFRS training sessions were attended by senior management and members of the audit committee, while individuals within the financial reporting group have continued 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 continues 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 IFRSs and Canadian GAAP have now been quantified. ARC has not yet prepared a full set of annual financial statements under IFRSs; 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.
First Time Adoption of IFRS
Most adjustments required on transition to IFRSs 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 property, plant and equipment that meets the
criteria to be classified as E&E in the opening balance sheet
prepared under IFRS as at January 1, 2010.
- Calculation of depletion expense for PP&E assets - Upon transition to
IFRS, ARC has the option to calculate depletion using a reserve base
of proved reserves or both proved plus probable reserves, as compared
to the Canadian GAAP method of calculating depletion using proved
reserves only. ARC plans to determine its depletion expense using
proved plus probable reserves as its depletion base. Accordingly, ARC
expects that its depletion expense for the six months ended June 30,
2010 would be reduced by approximately $2.00 per boe of production or
approximately $20 million as compared to its current calculation
under Canadian GAAP.
- Impairment of PP&E assets - Under IFRS, impairment of PP&E must be
calculated at a more granular level than what is currently required
under Canadian GAAP. Impairment calculations will be performed by
comparing the carrying values of each cash generating unit to the
higher of its fair value less cost to sell or value in use as defined
under IFRS. Impairment tests are required to be performed on initial
transition to IFRS. At January 1, 2010, no impairment was identified.
- Provisions for asset retirement costs - 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.
Under Canadian GAAP, once recorded, asset retirement obligations are
not adjusted for future changes in discount rates. Though it is
expected that ARC's asset retirement cost will increase as a result
of applying IFRS, the magnitude of the increase is still being
quantified by management.
- 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. It is anticipated
that any documentation changes will be substantively completed by the
end of the third quarter and that testing of amended controls will
commence in the fourth quarter. 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 plans to deliver investor presentations during the
second half of 2010 to explain the most significant changes from its
financial statements prepared under Canadian GAAP statements to those
prepared under IFRS.
- 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 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 Q2 Q1 Q4 Q3 Q2 Q1
Revenue before
royalties 276.7 314.1 278.6 239.2 235.2 225.2
Per unit(1) 1.09 1.25 1.17 1.01 0.99 0.98
Cash flow from
operating activities 162.8 158.7 143.2 125.6 104.3 124.3
Per unit - basic(1) 0.64 0.63 0.60 0.53 0.44 0.54
Per unit - diluted 0.64 0.63 0.60 0.53 0.44 0.54
Net income 44.9 139.4 65.5 68.9 66.1 22.3
Per unit - basic(2) 0.18 0.56 0.28 0.29 0.28 0.10
Per unit - diluted 0.18 0.56 0.28 0.29 0.28 0.10
Distributions 75.3 75.0 70.9 70.6 75.0 82.0
Per unit - basic(3) 0.30 0.30 0.30 0.30 0.32 0.36
Total assets 4,068.5 4,020.1 3,914.5 3,642.9 3,672.5 3,733.1
Total liabilities 1,384.3 1,322.4 1,540.1 1,278.4 1,323.1 1,392.1
Net debt
outstanding(4) 728.8 677.8 902.4 705.4 737.6 781.5
Weighted average
trust units(5) 253.2 251.8 238.5 237.7 236.6 228.9
Trust units
outstanding and
issuable(5) 253.6 252.8 239.0 238.1 237.1 236.0
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 3.6 6.6 2.9 3.0 5.0 2.8
Land 21.5 3.9 2.0 4.5 0.2 0.2
Drilling and
completions 84.9 77.2 66.1 61.0 18.6 68.5
Plant and facilities 26.9 29.5 35.3 26.1 23.6 25.1
Other capital 7.1 11.1 11.0 1.6 1.5 0.6
Total capital
expenditures 144.0 128.3 117.3 96.2 48.9 97.2
Property acquisitions
(dispositions) net - 6.3 1.1 (30.1) 2.3 6.2
Corporate acquisitions - - 178.9 - - -
-------------------------------------------------------------------------
Total capital
expenditures and net
acquisitions 144.0 134.6 297.3 66.1 51.2 103.4
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,354 27,640 27,415 26,921 26,917 28,806
Natural gas
(mmcf/d) 211.2 217.9 189.0 193.1 200.2 193.8
Natural gas
liquids (bbl/d) 3,655 3,252 3,597 3,717 3,679 3,764
Total (boe per
day 6:1) 66,208 67,207 62,520 62,824 63,969 64,872
Average prices
Crude oil ($/bbl) 71.98 76.26 72.61 67.74 62.74 46.44
Natural gas ($/mcf) 4.12 5.42 4.58 3.25 3.73 5.20
Natural gas
liquids ($/bbl) 53.02 60.33 46.12 38.92 38.89 38.86
Oil equivalent
($/boe) 45.82 51.85 48.35 41.31 40.32 38.40
-------------------------------------------------------------------------
TRUST UNIT TRADING
PRICES (based on
intra-day trading)
High 22.33 22.49 21.89 20.20 19.25 20.90
Low 19.20 19.80 19.06 15.48 14.12 11.73
Close 19.73 20.50 19.94 20.20 17.81 14.15
Average daily volume
(thousands) 1,043 1,287 963 1,038 988 1,240
-------------------------------------------------------------------------
-------------------------------------
(Cdn $ millions, except
per unit amounts) 2008
-------------------------------------
FINANCIAL Q4 Q3
Revenue before
royalties 300.8 485.7
Per unit(1) 1.38 2.24
Cash flow from
operating activities 209.4 251.4
Per unit - basic(1) 0.96 1.16
Per unit - diluted 0.96 1.16
Net income 82.7 311.7
Per unit - basic(2) 0.38 1.46
Per unit - diluted 0.38 1.46
Distributions 127.2 171.3
Per unit - basic(3) 0.59 0.80
Total assets 3,766.7 3,687.5
Total liabilities 1,624.6 1,530.8
Net debt
outstanding(4) 961.9 773.2
Weighted average
trust units(5) 218.3 216.6
Trust units
outstanding and
issuable(5) 219.2 217.4
-------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 3.7 1.3
Land 17.1 18.6
Drilling and
completions 117.1 91.4
Plant and facilities 30.5 24.2
Other capital 1.0 0.9
Total capital
expenditures 169.4 136.4
Property acquisitions
(dispositions) net 27.6 13.1
Corporate acquisitions - -
-------------------------------------
Total capital
expenditures and net
acquisitions 197.0 149.5
-------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,935 28,509
Natural gas
(mmcf/d) 195.1 192.0
Natural gas
liquids (bbl/d) 3,858 3,822
Total (boe per
day 6:1) 65,313 64,325
Average prices
Crude oil ($/bbl) 56.26 114.20
Natural gas ($/mcf) 7.48 8.68
Natural gas
liquids ($/bbl) 45.22 82.87
Oil equivalent
($/boe) 49.93 81.42
-------------------------------------
TRUST UNIT TRADING
PRICES (based on
intra-day trading)
High 22.55 33.30
Low 15.01 22.33
Close 20.10 23.10
Average daily volume
(thousands) 1,523 841
-------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(3) Based on number of trust units outstanding at each distribution date.
(4) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(5) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
CONSOLIDATED BALANCE SHEETS (unaudited)
As at June 30 and December 31
(Cdn$ millions) 2010 2009
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 0.3 $ -
Accounts receivable (Note 2) 131.8 115.9
Prepaid expenses 12.0 18.2
Risk management contracts (Note 7) 51.8 5.9
Future income taxes - 7.1
-------------------------------------------------------------------------
195.9 147.1
Reclamation funds 31.9 33.2
Risk management contracts (Note 7) 34.2 3.2
Property, plant and equipment 3,648.9 3,573.4
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 4,068.5 $ 3,914.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 177.0 $ 166.7
Distributions payable 25.1 23.7
Risk management contracts (Note 7) - 12.9
Future income taxes 8.9 -
-------------------------------------------------------------------------
211.0 203.3
Risk management contracts (Note 7) - 1.0
Long-term debt (Note 4) 670.8 846.1
Other long-term liabilities 34.8 10.9
Asset retirement obligations (Note 5) 146.0 149.9
Future income taxes 321.7 328.9
-------------------------------------------------------------------------
Total liabilities 1,384.3 1,540.1
-------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 13)
NON-CONTROLLING INTEREST
Exchangeable shares (Note 8) 37.6 36.0
UNITHOLDERS' EQUITY
Unitholders' capital (Note 9) 3,191.3 2,917.6
Deficit (Note 10) (544.6) (578.6)
Accumulated other comprehensive loss (Note 10) (0.1) (0.6)
-------------------------------------------------------------------------
Total unitholders' equity 2,646.6 2,338.4
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 4,068.5 $ 3,914.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For the three and six months ended June 30
Three Months Ended Six Months Ended
June 30 June 30
(Cdn$ millions, except
per unit amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and
natural gas liquids $ 276.7 $ 235.2 $ 590.8 $ 460.4
Royalties (47.5) (27.5) (99.4) (64.5)
-------------------------------------------------------------------------
229.2 207.7 491.4 395.9
Gain (loss) on risk
management contracts (Note 7)
Realized 18.8 (1.9) 20.1 14.4
Unrealized 6.6 (0.6) 90.3 (7.2)
-------------------------------------------------------------------------
254.6 205.2 601.8 403.1
-------------------------------------------------------------------------
EXPENSES
Transportation 7.7 4.9 13.7 10.5
Operating 69.1 64.2 125.3 123.3
General and administrative 16.5 17.5 37.7 22.6
Interest and financing
charges (Note 4) 7.4 7.6 18.4 13.4
Depletion, depreciation
and accretion 101.6 97.2 203.2 194.6
Loss (gain) on foreign
exchange 12.6 (40.0) 1.8 (25.4)
-------------------------------------------------------------------------
214.9 151.4 400.1 339.0
-------------------------------------------------------------------------
Future income tax
recovery (expense) 5.7 13.0 (15.6) 25.2
-------------------------------------------------------------------------
Net income before
non-controlling interest 45.4 66.8 186.1 89.3
Non-controlling
interest (Note 8) (0.5) (0.7) (1.8) (0.9)
-------------------------------------------------------------------------
Net income $ 44.9 $ 66.1 $ 184.3 $ 88.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of period $ (514.2) $ (562.6) $ (578.6) $ (502.9)
Distributions paid or
declared (Note 11) (75.3) (75.0) (150.3) (157.0)
-------------------------------------------------------------------------
Deficit, end of
period (Note 10) $ (544.6) $ (571.5) $ (544.6) $ (571.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per unit (Note 9)
Basic and Diluted $ 0.18 $ 0.28 $ 0.74 $ 0.38
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED
OTHER COMPREHENSIVE INCOME (unaudited)
For the three and six months ended June 30
Three Months Ended Six Months Ended
June 30 June 30
(Cdn$ millions) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net income $ 44.9 $ 66.1 $ 184.3 $ 88.4
Other comprehensive
income (loss), net of tax
Losses on financial
instruments designated
as cash flow hedges(1) 0.5 (0.8) 0.4 (2.9)
Gains and losses on
financial instruments
designated as cash flow
hedges in prior periods
realized in net income
in the current
period(2) (Note 7) (0.1) 0.7 - 0.6
Net unrealized gains
(losses) on
available-for-sale
reclamation funds'
investments(3) 0.1 (0.1) 0.1 (0.2)
-------------------------------------------------------------------------
Other comprehensive
income (loss) 0.5 (0.2) 0.5 (2.5)
-------------------------------------------------------------------------
Comprehensive income $ 45.4 $ 65.9 $ 184.8 $ 85.9
-------------------------------------------------------------------------
Accumulated other
comprehensive (loss)
income, beginning of
period (0.6) (0.4) (0.6) 1.9
Other comprehensive
income (loss) 0.5 (0.2) 0.5 (2.5)
-------------------------------------------------------------------------
Accumulated other
comprehensive loss, end
of period (Note 10) $ (0.1) $ (0.6) $ (0.1) $ (0.6)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts are net of tax of $0.2 million and $0.1 million,
respectively, for the three and six months ended June 30, 2010 (net
of tax of $0.3 million and $1 million, respectively, for the three
and six months ended June 30, 2009).
(2) Nominal future income tax impact for the three and six months ended
June 30, 2010 (net of tax of $0.2 million for the three and six
months ended June 30, 2009).
(3) Nominal future income tax impact for the three and six months ended
June 30, 2010 (nominal impact for the three and six months ended
June 30, 2009).
See accompanying notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three and six months ended June 30
Three Months Ended Six Months Ended
June 30 June 30
(Cdn$ millions) 2010 2009 2010 2009
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 44.9 $ 66.1 $ 184.3 $ 88.4
Add items not involving cash:
Non-controlling
interest (Note 8) 0.5 0.7 1.8 0.9
Future income tax
(recovery) expense (5.7) (13.0) 15.6 (25.2)
Depletion, depreciation
and accretion 101.6 97.2 203.2 194.6
Non-cash (gain) loss on
risk management
contracts (Note 7) (6.6) 0.6 (90.3) 7.2
Non-cash lease inducement 2.7 - 2.7 -
Non-cash loss (gain) on
foreign exchange 13.0 (39.7) 1.5 (25.3)
Non-cash trust unit
incentive compensation
expense (recovery)
(Note 12) 2.8 8.6 (3.6) (3.5)
Expenditures on site
restoration and reclamation
(Note 5) (2.2) (1.2) (3.7) (2.9)
Change in non-cash working
capital 11.8 (15.0) 10.0 (5.6)
-------------------------------------------------------------------------
162.8 104.3 321.5 228.6
-------------------------------------------------------------------------
CASH FLOWS FROM FINANCING
ACTIVITIES
Repayment of long-term debt
under revolving credit
facilities, net (91.6) (97.2) (321.3) (309.6)
Issue of Senior Notes 159.0 152.9 210.4 152.9
Repayment of Senior Notes (6.4) (12.6) (65.8) (12.6)
Issue of trust units, net of
issue costs 0.6 0.3 240.7 240.9
Cash distributions
paid (Note 11) (59.8) (63.1) (118.6) (131.3)
Change in non-cash working
capital (1.6) 0.1 1.1 2.0
-------------------------------------------------------------------------
0.2 (19.6) (53.5) (57.7)
-------------------------------------------------------------------------
CASH FLOWS FROM INVESTING
ACTIVITIES
Acquisition of petroleum and
natural gas properties - (2.3) (6.3) (8.5)
Capital expenditures (143.6) (47.1) (272.9) (146.4)
Net reclamation fund
(contributions) withdrawals (1.6) (2.3) 1.4 (0.8)
Change in non-cash working
capital (17.8) (33.0) 10.1 (55.2)
-------------------------------------------------------------------------
(163.0) (84.7) (267.7) (210.9)
-------------------------------------------------------------------------
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)
June 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. 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. 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
June 30, 2010 pertains to accrued revenue for June 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 June 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
June 30, 2010, $5.2 million of accounts receivable are past due,
excluding amounts in ARC's allowance for doubtful accounts, all of
which are considered to be collectable. The change in ARC's allowance
for doubtful accounts for the period ended June 30, 2010 is nominal.
Maximum credit risk is calculated as the total recorded value of cash
equivalents, accounts receivable, reclamation funds, and risk
management contracts at the balance sheet date.
3. FINANCIAL LIABILITIES AND LIQUIDITY RISK
Liquidity risk is the risk that ARC will not be able to meet its
financial obligations as they become due. ARC actively manages its
liquidity through cash, distribution policy, and debt and equity
management strategies. Such strategies include continuously
monitoring forecasted and actual cash flows from operating, financing
and investing activities, available credit under existing banking
arrangements and opportunities to issue additional Trust units.
Management believes that future cash flows generated from these
sources will be adequate to settle ARC's financial liabilities.
The following table details ARC's financial liabilities as at
June 30, 2010:
---------------------------------------------------------------------
2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
---------------------------------------------------------------------
Accounts payable and
accrued liabilities(1) 181.4 - - - 181.4
Distributions payable(2) 19.4 - - - 19.4
Risk management
contracts(3) 3.7 2.8 - - 6.5
Senior notes and interest 51.1 135.4 129.1 358.0 673.6
Revolving credit
facilities - 179.9 - - 179.9
Working capital
facility 2.4 - - - 2.4
Accrued long-term
incentive compensation(1) - 35.0 - - 35.0
---------------------------------------------------------------------
Total financial
liabilities 258.0 353.1 129.1 358.0 1,098.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(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
entity-specific risk.
4. LONG-TERM DEBT
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Syndicated credit facilities:
Cdn$ denominated $ 179.9 $ 423.0
US$ denominated - 74.3
Working capital facility 2.4 7.9
Senior notes:
Master Shelf Agreement
5.42% US$ Note 79.6 78.5
4.94% US$ Note 6.4 6.3
4.98% US$ Note 53.0 -
2004 Note Issuance
4.62% US$ Note 27.2 54.5
5.10% US$ Note 25.5 65.4
2009 Note Issuance
7.19% US$ Note 71.6 70.6
8.21% US$ Note 37.1 36.6
6.50% Cdn$ Note 29.0 29.0
2010 Note Issuance
5.36% US$ Note 159.1 -
---------------------------------------------------------------------
Total long-term debt outstanding $ 670.8 $ 846.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Credit Facilities
ARC has an $800 million, annually extendible, financial covenant-
based syndicated credit facility ("the facility"). The maturity date
of the facility is April 15, 2011. ARC also has in place a $25
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 bank prime (2.5 per
cent at June 30, 2010, 2.25 per cent at December 31, 2009), or, at
ARC's option, Canadian dollar bankers' acceptances or U.S. dollar
LIBOR loans, plus a stamping fee. These stamping fees vary between a
minimum of 60 basis points ("bps") to a maximum of 110 bps.
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 is for $1 billion and bears
interest at Canadian bank prime 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.
Additionally, the working capital facility has been increased to
$30 million. The credit facility is annually extendable at the option
of ARC and the financial covenants are the same as those detailed at
December 31, 2009. As a result of the renewal becoming effective
prior to the preparation and release of the second quarter financial
statements, ARC has continued to present its borrowings outstanding
on its credit facility as a long-term liability at June 30, 2010.
During the second quarter of 2010, the weighted-average interest rate
under the credit facility was 1.0 per cent (1.1 per cent for the
second quarter of 2009) and 1.0 per cent for the six months ended
June 30, 2010 (1.4 per cent for the six months ended 2009).
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, 2010 US$50.0 million 4.98% March 5, Five equal
2019 installments
beginning March 5,
2015
---------------------------------------------------------------------
---------------------------------------------------------------------
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 as at June 30,
2010. No consideration was offered in respect of this amendment.
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, 2004 US$25.7 million 4.62% April 27, Six equal
2014 installments
beginning April 27,
2009
April 27, 2004 US$24.0 million 5.10% April 27, Five equal
2016 installments
beginning April 27,
2012
May 27, 2010 US$150.0 million 5.36% May 27, Five equal
2022 installments
beginning May 27,
2018
---------------------------------------------------------------------
---------------------------------------------------------------------
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 as at June 30,
2010. No consideration was offered in respect of this amendment.
Credit Capacity
The following table summarizes ARC's available credit capacity and
the current amounts drawn as at June 30, 2010:
---------------------------------------------------------------------
Credit
Capacity Drawn Remaining
---------------------------------------------------------------------
Syndicated Credit Facility $ 800.0 $ 179.9 $ 620.1
Working Capital Facility 25.0 2.4 22.6
Senior Notes Subject to a
Master Shelf Agreement(1) 238.6 139.0 99.6
Senior Notes Not Subject to
a Master Shelf Agreement 349.5 349.5 -
---------------------------------------------------------------------
Total $ 1,413.1 $ 670.8 $ 742.3
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Total credit capacity is US$225 million.
Supplemental disclosures
The fair value of all senior notes as at June 30, 2010, is $517.6
million compared to a carrying value of $488.5 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 $2.4
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 effective August 4, 2010.
Interest paid during the second quarter of 2010 exceeded interest
expense by $1 million (interest paid was equal to interest expense in
the second quarter of 2009).
5. ASSET RETIREMENT OBLIGATIONS
The following table reconciles ARC's asset retirement obligations:
---------------------------------------------------------------------
Six Months
Ended Year Ended
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 149.9 $ 141.5
Increase in liabilities relating to
corporate acquisitions - 4.0
Increase in liabilities relating to
development activities 0.6 1.7
(Decrease) increase in liabilities
relating to change in estimate (5.7) 2.1
Settlement of reclamation liabilities
during the period (3.7) (8.7)
Accretion expense 4.9 9.3
---------------------------------------------------------------------
Balance, end of period $ 146.0 $ 149.9
---------------------------------------------------------------------
---------------------------------------------------------------------
ARC's weighted average credit adjusted risk free rate as at June 30,
2010 was 6.5 per cent (6.5 per cent as at December 31, 2009).
6. 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 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
June 30, 2010 ARC's net debt to annualized cash flow from operating
activities ratio is 1.1 and its net debt to total capitalization
ratio is 12.7 per cent.
---------------------------------------------------------------------
($ millions, except per unit June 30, December 31,
and per cent amounts) 2010 2009
---------------------------------------------------------------------
Long-term debt 670.8 846.1
Accounts payable and accrued liabilities 177.0 166.7
Distributions payable 25.1 23.7
Cash and cash equivalents, accounts receivable
and prepaid expenses (144.1) (134.1)
---------------------------------------------------------------------
Net debt obligations(1) 728.8 902.4
---------------------------------------------------------------------
Trust units outstanding and issuable for
exchangeable shares (millions) 253.6 239.0
Trust unit price(2) 19.73 19.94
---------------------------------------------------------------------
Market capitalization(1) 5,003.5 4,765.7
Net debt obligations(1) 728.8 902.4
---------------------------------------------------------------------
Total capitalization(1) 5,732.3 5,668.1
---------------------------------------------------------------------
Net debt as a percentage of total
capitalization 12.7% 15.9%
Net debt obligations to annualized cash flow
from operating activities 1.1 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 close price as at June 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 June 30, 2010
ARC is in compliance with all covenants.
7. 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 June 30,
2010. The sensitivity is based on a US$15 per barrel increase and US
$15 per barrel decrease in WTI and a $1.00 per mcf increase and $1.00
per mcf decrease in the price of 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 June 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 $ (29.6) $ (55.4) $ 33.0 $ 51.5
---------------------------------------------------------------------
---------------------------------------------------------------------
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 June 30, 2010
were to have increased by 50 bps (0.5 per cent) it is estimated that
ARC's net income would decrease by $0.7 million. Management does not
expect interest rates to decrease.
Foreign Exchange Risk
North American oil and natural gas prices are based upon U.S. dollar
denominated commodity prices. As a result, the price received by
Canadian producers is affected by the Canadian/U.S. dollar exchange
rate that may fluctuate over time. In addition ARC has U.S. dollar
denominated debt and interest obligations of which future cash
repayments are directly impacted by the exchange rate in effect on
the repayment date. Variations in the Canadian/U.S. dollar exchange
rate could also have a positive or negative impact on distributions
to unitholders.
The following table demonstrates the effect of exchange rate
movements on net income due to changes in the fair value of risk
management contracts in place at June 30, 2010 as well as the
unrealized gain or loss on revaluation of outstanding US$ denominated
debt. The sensitivity is based on a $0.05 Cdn$/US$ increase and $0.05
Cdn$/US$ decrease in the 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 $ (0.1) $ 0.2
(Increase loss/decrease gain) increase
gain/decrease loss on U.S. dollar
denominated debt (19.3) 16.4
---------------------------------------------------------------------
Net income (decrease) increase $ (19.4) $ 16.6
---------------------------------------------------------------------
---------------------------------------------------------------------
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 June 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 June 30, 2010 that do not qualify for hedge accounting:
---------------------------------------------------------------------
Financial WTI Crude Oil Contracts(1)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
1-Jul-10 31-Dec-10 Collar 2,000 $80.00 - $90.00
1-Jul-10 31-Dec-10 Collar 2,000 $75.00 - $95.00
1-Jul-10 31-Dec-10 3-way collar 4,000 $70.00 $57.50 $90.00
1-Jul-10 31-Dec-10 3-way collar 3,000 $80.00 $60.00 $90.00
1-Jul-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 $100.00(2)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Monthly average
(2) Annually settled call
---------------------------------------------------------------------
Financial AECO Natural Gas Swap Contracts(3)
---------------------------------------------------------------------
Volume Sold Swap
Term Contract GJ/d Cdn$/GJ
---------------------------------------------------------------------
1-Jul-10 31-Dec-10 Swap 80,000 $5.61
1-Jan-11 31-Dec-13 Swap 45,000 $6.06
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) AECO 7a monthly index
---------------------------------------------------------------------
Financial AECO Natural Gas Contracts(4)
---------------------------------------------------------------------
Volume Bought Put Sold Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
1-Jul-10 31-Dec-10 Collar 10,000 $4.00 $5.05
---------------------------------------------------------------------
---------------------------------------------------------------------
(4) AECO 7a monthly index
---------------------------------------------------------------------
Financial NYMEX Natural Gas Swap Contracts(5)
---------------------------------------------------------------------
Volume Sold Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
1-Jul-10 31-Oct-10 Swap 20,000 $6.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(5) Last 3 Day Settlement
---------------------------------------------------------------------
Financial Basis Swap Contract(6)
---------------------------------------------------------------------
Volume Sold Swap Bought Swap
Term Contract mmbtu/d US$/mmbtu US$/mmbtu
---------------------------------------------------------------------
1-Jul-10 31-Jul-10 Basis Swap-L3d 20,000 ($0.9000)
1-Jul-10 31-Oct-10 Basis Swap-L3d 50,000 ($1.0430)
1-Nov-10 31-Oct-11 Basis Swap-Ld 15,000 ($0.4850)
1-Nov-11 31-Oct-12 Basis Swap-Ld 15,000 ($0.4067)
---------------------------------------------------------------------
(6) Nymex Last Day (Ld) or Last 3 Day (L3d); AECO 7a
monthly index
---------------------------------------------------------------------
US$ Foreign Exchange Contracts(7)
---------------------------------------------------------------------
Notional Sold Swap
Term Contract US$/month Cdn$/US$
---------------------------------------------------------------------
1-Jul-10 31-Dec-10 Swap $2,000,000 $1.0636
---------------------------------------------------------------------
(7) Settled against monthly average BoC noon day rate
---------------------------------------------------------------------
Financial Electricity Heat Rate Contracts(8)
---------------------------------------------------------------------
AESO multi- Heat
Volume Power AECO 5a plied Rate
Term Contract MWh Cdn$/MWh Cdn$/GJ by GJ/MWh
---------------------------------------------------------------------
1-Jul-10 31-Dec-10 Heat Rate 10 Receive Pay AECO x 9.15
Swap AESO 5a
1-Jan-11 31-Dec-11 Heat Rate 15 Receive Pay AECO x 9.08
Swap AESO 5a
1-Jan-12 31-Dec-12 Heat Rate 15 Receive Pay AECO x 9.09
Swap AESO 5a
1-Jan-13 31-Dec-13 Heat Rate 10 Receive Pay AECO x 9.15
Swap AESO 5a
---------------------------------------------------------------------
---------------------------------------------------------------------
(8) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index
---------------------------------------------------------------------
Financial Electricity Contracts(9)
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Jul-10 31-Dec-12 Swap 5 $72.495
---------------------------------------------------------------------
---------------------------------------------------------------------
(9) Alberta Power Pool (monthly average 24x7)
Following is a summary of all risk management contracts in place as
at June 30, 2010 that qualify for hedge accounting:
---------------------------------------------------------------------
Financial Electricity Contracts
---------------------------------------------------------------------
Volume Bought Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
1-Jul-10 31-Dec-10 Swap 5 $63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
At June 30, 2010, the fair value of the contracts that were not
designated as accounting hedges was $86 million. ARC recorded a
gain on risk management contracts of $110.4 million in the statement
of income for the six months ended June 30, 2010 ($7.2 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:
---------------------------------------------------------------------
Six Months Six Months
Ended Ended
June 30, June 30,
2010 2009
---------------------------------------------------------------------
Fair value, beginning of period $ (4.3) $ 3.4
Fair value, end of period(1) 86.0 (3.8)
---------------------------------------------------------------------
Change in fair value of contracts in
the period 90.3 (7.2)
Realized gain in the period 20.1 14.4
---------------------------------------------------------------------
Gain on risk management contracts $ 110.4 $ 7.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a gain of $78.2 million at
June 30, 2010 ($1.2 million loss at June 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 gain of $0.2 million and a
nominal loss on these electricity contracts for the three and six
months ended June 30, 2010 (loss of $0.9 million and $0.8 million
respectively in 2009) has been included in operating costs on the
statement of income. The accumulated unrealized fair value on these
contracts is nominal and has been recorded on the Consolidated
Balance Sheet at June 30, 2010 with the movement in fair value
recorded in OCI, net of tax. The fair value movement for the period
ended June 30, 2010 is $0.5 million unrealized gain. As at June 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:
---------------------------------------------------------------------
Six Months Six Months
Ended Ended
June 30, June 30,
2010 2009
---------------------------------------------------------------------
Fair value, beginning of period $ (0.5) $ 3.3
Change in fair value of financial
electricity contracts 0.5 (3.2)
---------------------------------------------------------------------
Fair value, end of period(1) $ - $ 0.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts designated as
effective accounting hedges is nominal at June 30, 2010 ($0.1
million gain at June 30, 2009).
8. EXCHANGEABLE SHARES
---------------------------------------------------------------------
Six Months
Ended Year Ended
June 30, December 31,
(units thousands) 2010 2009
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Balance, beginning of period 871 1,092
Exchanged for trust units(1) (5) (221)
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Balance, end of period 866 871
Exchange ratio, end of period 2.79848 2.71953
Trust units issuable upon conversion,
end of period 2,423 2,369
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(1) During the first six months of 2010, 4,940 ARL exchangeable
shares were converted to trust units at an average exchange ratio
of 2.75547, compared to 220,573 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:
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Six Months
Ended Year Ended
June 30, December 31,
2010 2009
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Non-controlling interest, beginning
of period $ 36.0 $ 42.4
Reduction of book value for conversion
to trust units (0.2) (8.7)
Current period net income attributable
to non-controlling interest 1.8 2.3
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Non-controlling interest, end of period 37.6 36.0
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Accumulated earnings attributable to non-
controlling interest $ 45.1 $ 43.3
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9. UNITHOLDERS' CAPITAL
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Six Months Ended Year Ended
June 30, 2010 December 31, 2009
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Number Number
of trust of trust
(units thousands) units $ units $
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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
(Note 8) 14 0.2 572 8.6
Distribution reinvestment
program 1,568 31.3 4,134 67.0
Trust unit issue costs,
net of tax(1) - (10.1) - (11.7)
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Balance, end of period 251,197 3,191.3 236,615 2,917.6
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(1) Amount is net of tax of $2.5 million for the period ended June
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:
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Three Months Ended Six Months Ended
June 30 June 30
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(units thousands) 2010 2009 2010 2009
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Weighted average trust
units(1) 250,788 234,173 250,111 230,346
Trust units issuable
on conversion of
exchangeable shares(2) 2,423 2,457 2,423 2,457
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Diluted trust units and
exchangeable shares 253,211 236,630 252,534 232,803
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(1) Weighted average trust units exclude trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the period end exchange ratio.
Basic net income per unit has been calculated based on net income
after non-controlling interest divided by weighted average trust
units. Diluted net income per unit has been calculated based on net
income before non-controlling interest divided by diluted trust
units.
10. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE LOSS
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June 30, December 31,
2010 2009
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Accumulated earnings $ 3,131.2 $ 2,946.9
Accumulated distributions (3,675.8) (3,525.5)
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Deficit (544.6) (578.6)
Accumulated other comprehensive loss (0.1) (0.6)
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Deficit and accumulated other comp-
rehensive loss $ (544.7) $ (579.2)
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The accumulated other comprehensive loss balance is composed of the
following items:
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June 30, December 31,
2010 2009
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Unrealized gains and losses on financial
instruments designated as cash flow
hedges $ (0.3) $ (0.7)
Net unrealized gains and losses on
available-for-sale reclamation funds'
investments 0.2 0.1
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Accumulated other comprehensive loss,
end of period $ (0.1) $ (0.6)
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11. 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.
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Three Months Ended Six Months Ended
June 30 June 30
2010 2009 2010 2009
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Cash flow from
operating activities $ 162.8 $ 104.3 $ 321.5 $ 228.6
Deduct:
Cash withheld to fund
current period capital
expenditures (85.9) (27.0) (172.6) (70.8)
Net reclamation fund
(contributions)/with-
drawals (1.6) (2.3) 1.4 (0.8)
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Distributions(1) 75.3 75.0 150.3 157.0
Accumulated dist-
ributions, beginning
of period 3,600.5 3,309.0 3,525.5 3,227.0
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Accumulated dist-
ributions, end of
period $ 3,675.8 $ 3,384.0 $ 3,675.8 $ 3,384.0
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Distributions per
unit(2) $ 0.30 $ 0.32 $ 0.60 $ 0.68
Accumulated dist-
ributions per unit,
beginning of period $ 25.28 $ 24.06 $ 24.98 $ 23.70
Accumulated dist-
ributions per unit,
end of period(3) $ 25.58 $ 24.38 $ 25.58 $ 24.38
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(1) Distributions include accrued and non-cash amounts of $15.5
million and $31.7 million for the three and six months ended June
30, 2010 ($11.9 million and $25.7 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.
12. 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 six months of 2010, cash payments of $15.1 million
were made to employees relating to the Whole Unit Plan compared to
$7.8 million in 2009.
The following table summarizes the RTU and PTU movement for the six
months ended June 30, 2010:
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Number of Number of
(thousands) RTUs PTUs
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Balance, beginning of period 1,052 1,305
Granted 241 224
Vested (249) (151)
Forfeited (48) (99)
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Balance, end of period 996 1,279
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The change in the net accrued long-term incentive compensation
liability relating to the Whole Unit Plan can be reconciled as
follows:
---------------------------------------------------------------------
June 30, December 31,
2010 2009
---------------------------------------------------------------------
Balance, beginning of period $ 32.6 $ 31.9
Change in net liabilities in the period
General and administrative expense (3.5) (0.1)
Operating expense (0.1) 0.7
Property, plant and equipment (0.3) 0.1
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Balance, end of period(1) $ 28.7 $ 32.6
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Current portion of liability(2) 17.7 22.4
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Accrued long-term incentive
compensation(3) $ 11.7 $ 10.9
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(1) Includes $0.7 million of recoverable amounts recorded in accounts
receivable as at June 30, 2010 ($0.6 million for 2009).
(2) Included in accounts payable and accrued liabilities on the
Consolidated Balance Sheet.
(3) Included in other long-term liabilities on the Consolidated
Balance Sheet.
13. COMMITMENTS AND CONTINGENCIES
Following is a summary of ARC's contractual obligations and
commitments as at June 30, 2010:
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Payments Due by Period
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2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
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Debt repayments(1) 25.6 263.8 87.7 293.7 670.8
Interest payments(2) 28.0 51.5 41.4 64.2 185.1
Reclamation fund
contributions(3) 4.9 8.9 7.7 64.2 85.7
Purchase commitments 44.1 32.3 14.0 11.9 102.3
Transportation commitments 8.0 30.0 22.3 17.4 77.7
Operating leases 3.9 14.2 14.7 68.4 101.2
Risk management contract
premiums(4) 0.5 - - - 0.5
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Total contractual
obligations 115.0 400.7 187.8 519.8 1,223.3
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(1) Long-term and short-term debt.
(2) Fixed interest payments on senior notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
risk management contracts.
In addition to the above Risk management contract premiums, ARC has
commitments related to its risk management program (see Note 7). As
the premiums are part of the underlying risk management contract,
they have been recorded at fair market value at June 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.
Arrangement Agreement with Storm Exploration Inc.
On June 9, 2010, ARC announced that it entered into an Arrangement Agreement whereby ARC will acquire all of the existing and outstanding common shares of Storm Exploration Inc. ("Storm"). Pursuant to the arrangement agreement, for each Storm share held, Storm shareholders can elect to receive either 0.5700 of an ARC trust unit, or subject to adjustment, 0.2021 of an ARC Resources Ltd. exchangeable share or some combination thereof. At the date of announcement, the transaction was valued at approximately $680 million including the assumption of approximately $90 million of total debt. The transaction is expected to close August 17, 2010, subject to shareholder and regulatory approval, at which time the results of operations of Storm will be included in ARC's consolidated financial statements.
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 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 increase in interest rates in 2010 as a result of the renewal of our credit facility under the heading "Interest and Financing Charges"; 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 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 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.
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 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 under the heading "Accomplishments/Financial Update on pages two and three 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 $5.8 billion. ARC expects 2010 oil and gas production to average 72,500 to 74,500 of barrels of oil equivalent per day from six core areas in western Canada. ARC Energy Trust units trade on the TSX under the symbol AET.UN and ARC Resources exchangeable shares trade under the symbol ARX. ARC Energy Trust trades on the TSX under the symbol AET.UN and its exchangeable shares trade under the symbol ARX.
<<
ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer
>>
%SEDAR: 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