ARC Energy Trust announces fourth quarter and year-end 2007 results
Feb 14, 2008
CALGARY, Feb. 14 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC"
or "the Trust") announces the results for the fourth quarter and the year
ended December 31, 2007.
<<
Three Months Ended Twelve Months Ended
December 31 December 31
2007 2006 2007 2006
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FINANCIAL
($CDN millions, except per
unit and per boe amounts)
Revenue before royalties 338.0 292.5 1,251.6 1,230.5
Per unit(1) 1.59 1.42 5.95 6.02
Per boe 57.42 49.95 54.67 53.46
Cash flow from operating
activities(2) 173.7 159.3 704.9 734.0
Per unit(1) 0.82 0.77 3.35 3.59
Per boe 29.51 27.22 30.79 31.89
Net income 106.3 56.6 495.3 460.1
Per unit(3) 0.51 0.28 2.39 2.28
Distributions 125.8 122.3 498.0 484.2
Per unit(1) 0.60 0.60 2.40 2.40
Per cent of cash flow from
operating activities(2) 72 77 71 66
Net debt outstanding(4) 752.7 739.1 752.7 739.1
Total capital expenditures
and net acquisitions 144.3 214.9 439.7 496.3
OPERATING
Production
Crude oil (bbl/d) 28,682 29,605 28,682 29,042
Natural gas (mmcf/d) 187.4 179.5 180.1 179.1
Natural gas liquids (bbl/d) 4,067 4,144 4,027 4,107
Total (boe/d) 63,989 63,663 62,723 63,056
Average prices
Crude oil ($/bbl) 77.53 58.26 69.24 65.26
Natural gas ($/mcf) 6.32 6.99 6.75 6.97
Natural gas liquids ($/bbl) 62.75 46.51 54.79 52.63
Oil equivalent ($/boe) 57.26 49.82 54.54 53.33
Operating netback ($/boe)
Commodity and other revenue
(before hedging)(5) 57.42 49.95 54.67 53.46
Transportation costs (0.69) (0.64) (0.72) (0.63)
Royalties (10.46) (8.80) (9.59) (9.66)
Operating costs (9.64) (9.13) (9.54) (8.49)
Netback (before hedging) 36.63 31.37 34.82 34.68
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TRUST UNITS
(millions)
Units outstanding,
end of period 210.2 204.3 210.2 204.3
Units issuable for
exchangeable shares 2.9 2.9 2.9 2.9
Total units outstanding and
issuable for exchangeable
shares, end of period 213.2 207.2 213.2 207.2
Weighted average units(6) 212.5 206.5 210.2 204.4
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TRUST UNIT TRADING STATISTICS
($CDN, except volumes) based
on intra-day trading
High 21.55 29.22 23.86 30.74
Low 18.90 19.20 18.90 19.20
Close 20.40 22.30 20.40 22.30
Average daily volume
(thousands) 624 1,125 597 706
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(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares. Per unit distributions are based on
the number of trust units outstanding at each distribution record
date.
(2) Cash flow from operating activities is a GAAP measure. Historically,
management has disclosed Cash Flow, as a non-GAAP measure calculated
using cash flow from operating activities less the change in non-cash
working capital and the expenditures on site restoration and
reclamation as they appear on the Consolidated Statements of Cash
Flows. Cash Flow for the fourth quarter of 2007 would be $194 million
($0.91 per unit) and year-to-date 2007 Cash Flow would be
$728.8 million ($3.47 per unit). Distributions as a percentage of
Cash Flow would be 65 per cent for the fourth quarter of 2007 and 68
per cent for year-to-date 2007. Please refer to the non-GAAP measures
section in the MD&A for further details.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Includes other revenue.
(6) Includes trust units issuable for outstanding exchangeable shares at
period end.
ACCOMPLISHMENTS / FINANCIAL UPDATE
----------------------------------
- Cash flow from operating activities in the fourth quarter of 2007
increased nine per cent to $173.7 million ($0.82 per unit) from
$159.4 million ($0.77 per unit) in the same period of 2006. Excluding
changes in working capital and site restoration and reclamation
expenditures, Cash Flow increased 11 per cent to $194 million
($0.91 per unit) from $174.4 million ($0.85 per unit) in the fourth
quarter of 2006, principally due to a 15 per cent increase in the
Trust's average realized commodity price.
- Prior to hedging activities, ARC's total realized commodity price was
$57.26 per boe in the fourth quarter of 2007, compared to $49.82 per
boe received prior to hedging in the fourth quarter of 2006 as a
result of high oil prices that were partially offset by softer gas
prices in 2007. ARC's total realized price for the full year in 2007
was $54.54 per boe, a two per cent increase over 2006 realized prices.
Although U.S. dollar denominated oil prices were high throughout the
second half of the year, the strengthening of the Canadian dollar
throughout the third quarter of 2007 offset the increase in U.S.
dollar denominated oil prices.
- Production volume averaged 62,723 boe per day in 2007 compared to
63,056 boe per day in 2006. Achieving the Trust's goal of maintaining
consistent production in 2007 proved to be a challenge for the Trust
as access to third party processing facilities was periodically
restricted throughout the year. Late in the fourth quarter of 2007,
the Trust brought on new production in both the Dawson and Pouce
areas, achieving exit production of 65,000 boe per day in December
2007.
- The Trust had an active fourth quarter, drilling 77 gross wells
(69 net wells) on operated properties with a 100 per cent success
rate. For the full year of 2007, the Trust drilled 278 gross wells
(220 net wells) on operated properties; 99 gross oil wells, three
water injection wells, and 172 gross natural gas wells with a
99 per cent success rate.
- Capital expenditures for the fourth quarter, including $42.6 million
for land purchases, were $139.3 million, bringing year-to-date capital
expenditures to $397.2 million. Seventy-seven per cent of full year
capital expenditures have been funded from cash flow from operating
activities and the proceeds from the Distribution Re-investment Plan
("DRIP"). The remaining 23 per cent of capital expenditures along with
minor acquisitions of $42.5 million in 2007 were entirely funded
through debt.
- The majority of the $42.6 million spent on land in the fourth quarter
(year-to-date $77.5 million), was spent in the Dawson area of British
Columbia to purchase land adjacent to a new gas discovery that ARC
made at Sunrise. The Sunrise 9-13-78-18W6 discovery well encountered
150 metres of greater than three per cent porosity gas bearing rock in
the Montney formation. Although testing is not complete, ARC believes
the well confirms the presence of a large gas resource associated with
the Sunrise lands.
- The Trust recorded all-in annual Finding, Development and Acquisition
("FD&A") cost of $19.00 per barrel of oil equivalent ("boe") in 2007
before consideration of future development capital ("FDC") for the
proved plus probable reserves category. This is a 15 per cent
reduction from the $22.42 per boe FD&A cost realized in 2006.
Including FDC, the FD&A cost was $20.03 per boe. The three year
average FD&A cost is $16.57 per boe for the proved plus probable
category before FDC; including FDC, the three year average FD&A cost
is $19.19 per boe. For additional information please refer to the
reserves news release dated February 14, 2008 (posted on
www.sedar.com).
- Based on our operating netback of $34.82 per boe, the one year recycle
ratio is 1.8 times, using $19 per boe proved plus probable FD&A cost
prior to FDC.
- The Trust distributed $125.8 million in the fourth quarter of 2007
with full year distributions of $498 million. The Trust announced 2008
first quarter distributions will remain at $0.20 per unit per month, a
level that has been maintained since October 2005. Since inception in
1996, the Trust has distributed $21.03 per unit for a total of
$2.66 billion.
- Subsequent to year-end 2007, ARC purchased a 50 per cent working
interest in five sections of land at Sunrise in northeastern British
Columbia that are contiguous to the lands purchased during 2007.
- The Trust posted record net income of $495.3 million in 2007 that is
an eight per cent increase over the $460.1 million recorded in
2006.
NEW BOARD APPOINTMENT
---------------------
- ARC is pleased to announce the appointment of James C. Houck to ARC's
Board of Directors, effective February 14, 2008. Mr. Houck is an
independent businessman with over 25 years of energy industry
experience, most recently as President & CEO of Western Oil Sands. The
majority of his business career was spent with ChevronTexaco Inc,
where he held a number of senior officer positions, including
President, Worldwide Power and Gasification, Inc, and Vice President
and General Manager, Alternate Energy Dept. Earlier in his career,
Mr. Houck held various positions of increasing responsibility in
Texaco's conventional oil and gas operations. Mr. Houck, with his
experience in the oil and gas sector will be an asset to our Board.
REGULATORY CHANGES
------------------
- On October 25, 2007, the Alberta Government announced increases in the
royalty rates that will result in an approximate 10 per cent increase
in the Trust's royalty rates from approximately 18 per cent of revenue
to 20 per cent of revenue commencing on January 1, 2009. The impact of
the royalty increase was to decrease the net present value of the
Trust's reserves by approximately two to three per cent when using a
10 per cent discount rate and using GLJ forecast prices as at
January 1, 2008. The New Alberta Royalty Framework will impact future
drilling decisions in order for the Trust to maintain acceptable rates
of return on its capital deployed.
- On October 30, 2007, the Finance Minister announced, as part of the
2007 Economic Statement, changes to the tax system including reduction
of the corporate income tax rate from 22.1 per cent to 15 per cent by
2012. The reductions will be phased in between 2008 and 2012.
Legislation enacting the measures announced in the Economic Statement
received Royal Assent on December 14, 2007. The reduction in the
general corporate tax rate will also apply to the taxation of Income
Trusts, reducing the combined federal and deemed provincial tax rate
for distributions to 28 per cent in 2012.
>>
MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
This management's discussion and analysis ("MD&A") is the Trust
management's analysis of its financial performance and significant trends or
external factors that may affect future performance. It is dated February 13,
2008 and should be read in conjunction with the audited consolidated financial
statements for the year ended December 31, 2007 and the audited consolidated
financial statements and MD&A for the year ended December 31, 2006 and MD&A
for the quarters ended March 31, 2007, June 30, 2007, September 30, 2007 as
well as the Trust's Annual Information Form.
The MD&A contains forward-looking statements and readers are cautioned
that the MD&A should be read in conjunction with the Trust's disclosure under
"Forward-Looking Statements" included at the end of this MD&A.
Non-GAAP Measures
Historically, management used the non-GAAP measure Cash Flow or cash flow
from operations to analyze operating performance, leverage and liquidity. We
have now chosen to utilize the GAAP measure cash flow from operating
activities instead of Cash Flow. There are two differences between the two
measures and cash flow from operating activities; positive or negative changes
in non-cash working capital and the deduction of expenditures on site
restoration and reclamation as they appear on the Consolidated Statements of
Cash Flows. Although management feels that Cash Flow is a valued measure of
funds generated by the Trust during the reported quarter, we have changed our
disclosure to only discuss the GAAP measure in the MD&A in order to avoid any
potential confusion by readers of our financial information and in our
opinion, to more fully comply with the intent of certain regulatory
requirements.
Our historical measure of Cash Flow reflected revenues and costs for the
three months reported in the quarter. This amount, however, comprised accruals
for at least one month of revenue and approximately two months of costs. The
oil and gas industry is designed such that revenues are typically collected on
the 25th day of the month following the actual production month. Royalties are
typically paid two months following the actual production month and operating
costs are paid as the invoices are received. This can take several months;
however, most invoices for operated properties are paid within approximately
two months of the production month. In the event that commodity prices and or
volumes have changed significantly from the last month of the previous
reporting period over the last month of the current reporting period, a
difference could occur between cash flow from operating activities and our
historical non-GAAP measure of Cash Flow or cash flow from operations.
Additionally, periods where the Trust spends a significant amount on site
restoration and reclamation would result in a difference between cash flow
from operating activities and Cash Flow.
At the time of writing this MD&A, substantially all revenues have been
collected for the production period of December 2007. Management performs
analysis on the amounts collected to ensure that the amounts accrued for
December are accurate. Analysis is also performed regularly on royalties and
operating costs to ensure that amounts have been accurately accrued.
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 to analyze financial and operating
performance. Management feels that these KPIs and benchmarks are key measures
of profitability and overall sustainability for the Trust. These KPIs and
benchmarks as presented do not have any standardized meaning prescribed by
Canadian GAAP and therefore may not be comparable with the calculation of
similar measures for other entities.
Executive Overview
ARC Energy Trust ("the Trust") is one of the top 20 producers of
conventional oil and gas in western Canada. In terms of oil and gas entities
operating in western Canada and listed on the Toronto Stock Exchange, ARC
ranks 14 with a total capitalization as at February 13, 2008 of $5.7 billion
based on a closing unit price of $23.15.
It is the Trust's objective to provide superior and sustainable long-term
returns to unitholders by focusing on the key strategic objectives of the
business plan. The Trust, which to date has conducted business exclusively in
western Canada, acquires, develops and optimizes oil and natural gas
properties to generate a cash flow stream. The Trust at December 31, 2007,
held an interest in an excess of 18,000 wells with approximately 6,400 wells
operated by the Trust and the remainder operated by joint venture partners,
primarily major oil and gas companies. ARC's 2007 production averaged 62,723
boe per day of which 74 per cent was operated by the Trust. The Trust's
business plan is to continually develop its reserves and/or acquire new
reserves in order to maintain its productive capacity while distributing the
remainder of its cash flows to unitholders in the form of monthly
distributions. The Trust employs a conservative payout policy to provide for
cash funding of a portion of ongoing capital development programs and
maintaining low debt levels to facilitate further growth.
The key objectives of the Trust's business plan are identified below. The
Trust was successful in meeting all of its objectives in 2007 as discussed
below and will continue to focus on these items in 2008.
<<
- Managing commodity price risk - Commodity prices are by far the key
variable in determining the profitability of the Trust. Each $1 per
barrel change in the Canadian price of oil impacts the annual revenue
of the Trust by approximately $10 million and each $0.25 per mcf
change in natural gas prices at AECO impacts annual revenue by
$16 million. Commodity prices are outside of management's control,
however, it is a strategic objective of the Trust to maintain a
balanced production profile between natural gas and crude oil. Also,
the Trust maintains an active risk management program to
protect a portion of cash flows giving greater certainty to
distributions and increasing the certainty that acceptable rates of
returns are achieved on capital deployed during the course of the
year.
- Replacing annual reserves - The Trust's proved plus probable reserves
were maintained after producing 22.9 mmboe throughout 2007. As at
December 31, 2007 company interest reserves of 286.4 mmboe were within
one per cent of the 286.1 mmboe recorded as at December 31, 2006. The
reserves were slightly increased through a combination of the $397.2
million 2007 capital development program and property acquisitions
(net of dispositions) of $42.5 million. The Trust recorded all-in
annual Finding, Development and Acquisition ("FD&A") cost of $19.00
per barrel of oil equivalent ("boe") in 2007 before consideration of
future development capital ("FDC") for the proved plus probable
reserves category. This is a 15 per cent reduction from the $22.42
per boe FD&A cost realized in 2006. Including FDC, the FD&A cost was
$20.03 per boe. For additional information please refer to the
reserves news release dated February 14, 2008 (posted on
www.sedar.com).
- Ensuring acquisitions are strategic and enhance unitholder returns -
The Trust added producing properties in southeast Saskatchewan that
were synergistic with the Trust's existing operations in 2007 and also
significantly increased its land ownership in northeastern British
Columbia providing an increase in its inventory of future development
opportunities.
- Controlling costs - The Trust has been diligent in ensuring that costs
incurred for capital projects were reasonable and competitive amongst
service providers, which has led to a moderate cost savings throughout
2007. The Trust drills approximately 300 wells per year that are added
to its operating base. It is expected that operating costs will
continue to increase over time as there is a high percentage of fixed
costs for the Trust's properties that results in a trend of increasing
operating costs as new production is brought on to replace declines on
existing properties.
- Conservatively utilizing debt - The Trust's net debt levels were
under 15 per cent of total capitalization and debt to 2007 cash flow
from operating activities was less than 1.1 times for the year ended
2007. The Trust's debt levels are one of the lowest in the oil and
gas sector.
- Continuously developing the expertise of our staff and seeking to hire
and retain the best in the industry - The Trust runs an active
training and development program for its employees and encourages
personal development. The Trust continues to assess compensation
levels in the industry to ensure that the Trust's compensation is
competitive in order to attract and retain the best employees. The
Trust's long-term incentive plan for employees is directly tied to the
Trust's units providing alignment between employees and investors.
- Building relationships and conducting business in a way that is viewed
as fair and equitable - ARC employees, leadership team and directors
work hard to build the ARC "franchise value" through honest,
transparent dealings with our business partners. "Treating all people
with respect" is a key message inside and outside the organization.
This basic business fundamental allows us to build enduring
relationships with joint venture partners, land owners, investors,
banks and lending institutions, governments and the investment
community.
- Promoting the use of proven and effective technologies - The Trust
continues to research new technologies in an effort to conduct its
operations in the most efficient and cost effective manner. The Trust
has committed a portion of its 2008 capital expenditure budget towards
continued research into tertiary recovery methods.
- Being an industry leader in health, safety and environmental
performance - The Trust continues to focus on operating
in a safe, reliable and responsible fashion. The Trust is committed to
the platinum level of CAPP Stewardship reporting and continues to
achieve Gold Level Champion reporter status under the Canada Climate
Change voluntary climate registry initiative. The Trust's commitment
to pursue additional CO(2) injection opportunities is expected to have
the two-fold benefit of enhanced recovery of reserves and the capture
and containment of CO(2) emissions that will benefit the environment.
The Trust's commitment to safety is evidenced by zero lost time
incidents for both employees and contract employees of the Trust in
2007.
- Continuing to actively support local initiatives in the communities in
which we live and work - The Trust is very actively involved in
charitable and philanthropic causes both in Calgary and in the rural
communities in which it operates. ARC continued to be a strong
supporter of the United Way, Alberta Cancer Foundation, Canadian
Sport Centre Calgary, Alberta Children's Hospital and many
community organizations in rural centres. The Trust allocates up to
0.5 per cent of its net income for donations, which resulted in $1.8
million of cash donations made to charitable organizations in 2007.
The Trust also provided business expertise and employee volunteers to
charities.
>>
Historical Performance
Management and the Trust's directors are committed to providing superior
long-term returns to unitholders. In the future the Trust's business strategy
will continue to be reviewed to address changes in the business and regulatory
environment in order to ensure that unitholder value is optimized. The Trust,
while primarily focused on adding value through internal development of
drilling opportunities, continually looks to execute minor property
acquisitions and dispositions in order to enhance and streamline the Trust's
portfolio of oil and natural gas assets. The Trust will continue to assess
larger accretive acquisition opportunities. Acquisitions are evaluated
internally and acquisitions in excess of $25 million are subject to Board
approval.
The following chart illustrates ARC's production and reserves per unit
that have been achieved while making distributions over the last three years,
of $6.79 per unit or $1.4 billion.
<<
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Per Trust Unit 2007 2006 2005
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Normalized production per unit(1) 0.30 0.31 0.32
Normalized reserves per unit(1) 1.35 1.40 1.51
Distributions per unit $2.40 $2.40 $1.99
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(1) Normalized indicates that all years as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional trust units were issued (or repurchased) at a period
end price for the reserves per unit calculation and at an annual
average price for the production per unit calculation in order to
achieve a net debt balance of 15 per cent of total capitalization
each year. The normalized amounts are presented to enable
comparability of annual per unit values.
>>
The result of the Trust's business plan has been providing unitholders
with the following one, three and five year returns, on the basis of
reinvestment of distributions in trust units as follows:
<<
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Total Returns Three
($ per unit except for per cent) One Year Year Five Year
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Distributions per unit $ 2.40 $ 6.79 $ 10.39
Capital appreciation per unit $ (1.90) $ 2.50 $ 8.50
Total return per unit $ 0.50 $ 9.29 $ 18.89
Annualized total return per unit % 2.3 % 15.3 % 24.3
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>>
To the end of 2007, the Trust has provided cumulative distributions of
$21.03 per unit and capital appreciation of $10.40 per unit for a total return
of $31.43 per unit (21.9 per cent annualized total return) for unitholders who
invested in the Trust at inception in 1996. The Trust has announced 2008
distributions of $0.20 per unit per month through March 2008.
Regulatory Changes
Beyond 2008, regulatory issues include the implementation of new royalty
rates for production in the Province of Alberta in 2009. The Alberta
Government announced increases in the royalty rates in 2007 that will result
in an approximate 10 per cent increase in the Trust's royalty rates from
approximately 18 per cent of revenue to 20 per cent of revenue commencing on
January 1, 2009. The impact of the royalty increase was to decrease the net
present value of the Trust's reserves by approximately two to three per cent
when using a 10 per cent discount rate and using GLJ forecast prices as at
January 1, 2008. The New Alberta Royalty Framework will impact future drilling
decisions in order for the Trust to maintain acceptable rates of return on its
capital deployed.
Further, the Trust will be subject to a Federal income tax on
distributions commencing on January 1, 2011. The Trust's management is
reviewing the options for structural changes and working closely with legal
and business advisors to determine a course of action and potential
restructuring to maximize value in the best interest of unitholders.
2007 Annual Financial and Operational Results
Following is a discussion of ARC's 2007 annual financial and operating
results.
Financial Highlights
<<
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(CDN $ millions, except
per unit and volume data) 2007 2006 % Change
-------------------------------------------------------------------------
Cash flow from operating activities 704.9 734.0 (4)
Cash flow from operating activities
per unit(1) 3.35 3.59 (7)
Net income 495.3 460.1 8
Net income per unit(2) 2.39 2.28 5
Distributions per unit(3) 2.40 2.40 -
Distributions as a per cent of cash
flow from operating activities 71 66 8
Average daily production (boe/d)(4) 62,723 63,056 (1)
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(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
year-end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units outstanding excluding trust units
issuable for exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf:1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of boe in isolation may be
misleading.
>>
Net Income
Net income in 2007 was $495.3 million ($2.39 per unit), an increase of
$35.2 million from $460.1 million ($2.28 per unit) in 2006. This resulted from
a $13 million gain on the sale of the Trust's long-term investment as well as
a significant future income tax recovery of $121.3 million, attributed to the
reduction in legislated future corporate income tax rates in addition to
recording a future tax asset for tax legislation commencing in 2011 related to
ARC Energy Trust.
Cash Flow from Operating Activities
Cash flow from operating activities decreased by four per cent in 2007 to
$704.9 million from $734 million in 2006. The decrease in 2007 cash flow from
operating activities is detailed in the following table.
<<
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($ per
trust (%
($ millions) unit) variance)
-------------------------------------------------------------------------
2006 Cash flow from Operating Activities 734.0 3.59
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Volume variance (6.5) (0.03) (1)
Price variance 27.6 0.14 4
Cash gains on risk management contracts (15.1) (0.07) (2)
Royalties 2.8 0.01 -
Expenses:
Transportation (1.9) (0.01) -
Operating(1) (23.9) (0.11) (3)
Cash G&A (9.6) (0.05) (1)
Interest (5.2) (0.03) (1)
Taxes 0.4 - -
Realized foreign exchange gain (0.4) - -
Weighted average trust units - (0.10) -
Non-cash and other items(2) 2.7 0.01 -
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2007 Cash flow from Operating Activities 704.9 3.35 (4)
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(1) Excludes non-cash portion of LTIP expense recorded in operating
costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.
Production
Production volume averaged 62,723 boe per day in 2007 compared to 63,056
boe per day in 2006 as detailed in the table below. Late in the fourth quarter
of 2007, the Trust brought on new production in both the Dawson and Pouce
areas, achieving exit production of 65,000 boe per day in December 2007.
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Production 2007 2006 % Change
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Light & medium crude oil (bbl/d) 27,366 27,674 (1)
Heavy oil (bbl/d) 1,316 1,368 (13)
Natural gas (mcf/d) 180,086 179,067 1
NGL (bbl/d) 4,027 4,170 (3)
-------------------------------------------------------------------------
Total production (boe/d)(1) 62,723 63,056 (1)
% Natural gas production 48 47
% Crude oil and liquids production 52 53
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(1) Reported production for a period may include minor adjustments
from previous production periods.
>>
Oil production decreased slightly to 28,682 boe per day from 29,042 boe
per day in 2006. Natural gas production was 180.1 mmcf per day in 2007,
essentially unchanged from the 179.1 mmcf per day produced in 2006. The stable
production was a result of ARC's active 2007 internal drilling program
particularly in northern and southeast Alberta as well as southwestern
Saskatchewan. The Trust drilled six horizontal natural gas wells in the Dawson
area as well as 144 natural gas wells in southeastern Alberta and southwestern
Saskatchewan during 2007.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During 2007, the Trust drilled 278 gross wells
(220 net wells) on operated properties; 99 gross oil wells, three water
injection wells and 172 gross natural gas wells with a 99 per cent success
rate.
The Trust expects that 2008 full year production will be approximately
63,000 boe per day and that 310 gross wells (252 net wells) will be drilled by
ARC on operated properties with participation in an additional 140 gross wells
to be drilled on the Trust's non-operated properties. The Trust estimates that
the 2008 drilling program will add sufficient production from new wells to
offset production declines on existing properties.
The following table summarizes the Trust's production by core area:
<<
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2007
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,967 1,596 30.3 1,319
Northern AB & BC 19,797 5,773 74.8 1,552
Pembina & Redwater 13,703 9,474 19.2 1,034
S.E. AB & S.W. Sask. 10,040 1,044 53.9 10
S.E. Sask. & MB 11,216 10,795 1.9 112
-------------------------------------------------------------------------
Total 62,723 28,682 180.1 4,027
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-------------------------------------------------------------------------
2006
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 8,206 1,553 31.3 1,433
Northern AB & BC 18,897 6,194 67.6 1,452
Pembina & Redwater 13,950 9,453 20.0 1,157
S.E. AB & S.W. Sask. 10,743 1,071 58.0 9
S.E. Sask. & MB 11,260 10,771 2.2 119
-------------------------------------------------------------------------
Total 63,056 29,042 179.1 4,170
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
southwest.
Commodity Prices Prior to Hedging
-------------------------------------------------------------------------
2007 2006 % Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 6.61 6.98 (5)
WTI oil (US$/bbl)(2) 72.37 66.25 9
USD/CAD foreign exchange rate 0.94 0.88 7
WTI oil (CDN $/bbl) 77.35 75.00 3
-------------------------------------------------------------------------
ARC Realized Prices Prior to Hedging
Oil ($/bbl) 69.24 65.26 6
Natural gas ($/mcf) 6.75 6.97 (3)
NGL ($/bbl) 54.79 52.63 4
-------------------------------------------------------------------------
Total commodity revenue
before hedging ($/boe) 54.54 53.33 2
Other revenue ($/boe) 0.13 0.13 -
Total revenue before hedging ($/boe) 54.67 53.46 2
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>
Although oil prices have achieved record highs throughout 2007 peaking at
US$95.58 per barrel and averaging US$72.37 per barrel for the full year, the
strengthening of the Canadian dollar relative to the U.S. dollar was
responsible for eroding most of the gains and negatively impacted the price of
oil in Canadian dollar terms. The price of oil in U.S. dollars increased by
nine per cent for the full year of 2007, however, the Canadian dollar
equivalent increased by only three per cent. The foreign exchange rate reached
record highs in 2007 with the Canadian dollar peaking at an exchange rate of
1.09 Canadian per U.S. dollar in November 2007. The average USD/CAD foreign
exchange rate was 0.94 for the full year of 2007 and the Canadian dollar
closed on December 31, 2007 at 1.01 per U.S. dollar. The negative correlation
between the Canadian dollar and U.S. dollar denominated West Texas
Intermediate oil prices should lessen the impact on the Trust of any future
declines in the price of oil.
The Trust's oil production consists predominantly of light and medium
crude oil while heavy oil accounts for less than three per cent of the Trust's
liquids production. The realized price for the Trust's oil, before hedging,
increased six per cent to $69.24 from $65.26 for the full year of 2006.
Alberta AECO Hub natural gas prices, which are commonly used as an
industry reference, averaged $6.61 per mcf in 2007 compared to $6.98 per mcf
in 2006. Natural gas prices were stronger in the first half of the year but
declined throughout the third and fourth quarters. ARC's realized gas price,
before hedging, decreased by three per cent to $6.75 per mcf compared to
$6.97 per mcf in 2006. ARC's realized gas price is based on prices received at
the various markets in which the Trust sells its natural gas. ARC's natural
gas sales portfolio consists of gas sales priced at the AECO monthly index,
the AECO daily spot market, eastern and mid-west United States markets and a
portion to aggregators.
Prior to hedging activities, ARC's total realized commodity price was
$54.67 per boe in 2007, a two per cent increase from the $53.46 per boe
received prior to hedging in 2006.
<<
Revenue
Revenue increased to a historical high of $1.25 billion in 2007. The
increase in revenue was attributable to higher realized oil prices which were
partially offset by lower realized natural gas prices as compared to 2006.
A breakdown of revenue is as follows:
-------------------------------------------------------------------------
Revenue
($ millions) 2007 2006 % Change
-------------------------------------------------------------------------
Oil revenue 724.9 691.8 5
Natural gas revenue 443.4 455.7 (3)
NGL revenue 80.5 80.1 -
-------------------------------------------------------------------------
Total commodity revenue 1,248.8 1,227.6 2
Other revenue 2.9 2.9 -
Total revenue 1,251.7 1,230.5 2
-------------------------------------------------------------------------
>>
Risk Management and Hedging Activities
ARC continues to maintain an ongoing risk management program to reduce
the volatility of revenues in order to increase the certainty of
distributions, protect acquisition economics, and fund capital expenditures.
The risk management program was revised in 2005 to maintain a significant
portion of upside price participation on production volumes that has resulted
in cash hedging gains, net of premiums, of $14.1 million in 2007 and $29.3
million in 2006.
The Trust currently limits the amount of forecast production that can be
hedged to 50 per cent with the other 50 per cent of production being sold for
market prices.
During 2007, the WTI U.S. dollar posted oil price increased to a high of
US$95.98 per barrel with an annual average posted price of US$72.37 per
barrel. From a corporate perspective this has had a positive impact on the
Trust's revenue, however, this has resulted in a loss recorded for the Trust's
oil risk management contracts. During 2007 ARC had an unrealized total
mark-to-market loss year-over-year of $55.9 million with a net unrealized
mark-to-market liability of $68 million as at December 31, 2007. The
mark-to-market values represent the market price to buy-out the Trust's
contracts as of December 31, 2007 and may be different from what will
eventually be realized.
The most significant portion of ARC's total unrealized mark-to-market
position at year end was a $35.3 million loss relating to the Redwater and
NPCU hedged volumes of 5,000 bbl per day, which limits upside price potential
to $85 and $90 per barrel in 2008 and 2009 respectively. When these properties
were acquired in 2005, the acquisition economics were based on crude oil
prices of approximately CAD$57.50 per barrel. The remainder of the mark-to-
market loss results in potential settling of commodity, foreign exchange and
interest rates above the level of the Trust's hedges as disclosed in Note 11
to the Consolidated Financial Statements.
During 2007 ARC entered into a number of hedging transactions including
the following:
<<
- Energy equivalent swap: ARC has entered into an energy equivalent
swap in order to shift its price exposure to be more heavily weighted
towards crude oil for the period of April 1 through October 31, 2008.
Through the use of financial contracts, ARC has rebalanced its price
exposure from a forecasted 50:50 to a 52:48 oil-gas weighting. ARC
achieved this rebalancing by selling AECO natural gas at $7.10 per GJ
and buying crude oil at CDN$73.95 per barrel.
- In light of the significant increase in value of the Canadian dollar
during the last 12 months, ARC implemented a program to lock in
exchange rates on future principal repayments on U.S. dollar
denominated senior secured notes. These transactions effectively lock
in the unrealized foreign exchange gains on the U.S. denominated
debt. Although the unrealized foreign exchange gains will continue to
fluctuate quarter-to-quarter with changes in the exchange rate, these
financial transactions have effectively fixed the economic gains of
the change in exchange rates from the rate at which the U.S.
denominated debt was issued and the rate at which the future payments
have been committed. At the end of the year ARC had US$218 million of
U.S. denominated senior secured debt outstanding (CDN$215.5 million)
requiring annual principal repayments of varying amounts extending
until December 15, 2017. As at December 31, 2007, ARC had locked in
the foreign exchange rate for a total of US$127.2 million of its
principal repayments in years 2012 through 2017 at an average rate
with the Canadian dollar slightly greater than par (1.02 CAD$/US$).
- Natural gas protection through to March 2009: In the fall of 2007 ARC
entered into natural gas collars to protect prices as far out as
March 2009. For the period from November 2008 to March 2009, ARC has
purchased NYMEX natural gas puts at $8.50 per mmbtu and sold calls at
$11.00 per mmbtu.
The percentage of forecast volumes hedged in 2008 is: 43 per cent in the
first quarter, 36 per cent in the second quarter, 26 per cent in the third
quarter and 23 per cent in the fourth quarter.
The following table is an indicative summary of the Trust's positions for
crude oil, natural gas and related foreign exchange for the next twelve months
as at December 31, 2007.
-------------------------------------------------------------------------
Hedge Positions
As at December 31, 2007(1)(2)
Q1 2008 Q2 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 94.08 19,000 89.04 13,000
Bought Put 75.14 20,000 70.47 15,500
Sold Put 54.91 11,500 54.96 11,500
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.02 47,478 8.41 41,101
Bought Put 6.87 47,478 6.64 41,101
Sold Put 4.75 10,551 4.97 31.101
-------------------------------------------------------------------------
Foreign Exchange CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.0750 3.0 1.0750 3.0
Sold Put 1.0300 3.0 1.0300 3.0
Swap - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q3 2008 Q4 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 90.00 10,000 90.00 10,000
Bought Put 68.13 10,000 68.13 10,000
Sold Put 51.07 7,000 51.07 7,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.41 41,101 8.88 27,840
Bought Put 6.64 41,101 6.82 27,840
Sold Put 4.97 31,101 5.04 10,480
-------------------------------------------------------------------------
Foreign Exchange CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.0750 3.0 - -
Sold Put 1.0300 3.0 - -
Swap - - - -
-------------------------------------------------------------------------
(1) The prices and volumes noted above represents 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. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to the Trust's website at www.arcenergytrust.com under
"Hedging Program" within the "Investor Relations" section for details
on the Trust's hedging positions as of December 31, 2007.
The above table should be interpreted as follows using the first quarter
2008 Crude oil hedges as an example. To accurately analyze the Trust's hedge
position, contracts need to be modeled separately as using average prices and
volumes may be misleading.
- If the market price is below $54.91, ARC will receive $75.14 less the
difference between $54.91 and the market price on 11,500 barrels per
day. For example if the market price is $54.90, the Trust will
receive $75.13 on 11,500 barrels per day.
- If the market price is between $54.91 and $75.14, ARC will receive
$75.14 on 20,000 barrels per day.
- If the market price is between $75.14 and $94.08, ARC will receive
the market price on 20,000 barrels per day.
- If the market price exceeds $94.08, ARC will receive $94.08 on 19,000
barrels per day and the market price for the remaining 1,000 hedged
volumes.
>>
Gain or Loss on Risk Management Contracts
Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
ARC realized gains on natural gas contracts throughout the year as a
result of soft prices where ARC's floor protection level exceeded the market
price. ARC's crude oil contracts posted a loss for the year of $5.7 million as
a result of record high oil prices that exceeded some of the Trust's ceiling
contracts during the second half of the year. On foreign exchange and interest
rates, ARC realized gains during the last three quarters of the year
particularly on U.S. dollar put-spreads that protected ARC from an
appreciating Canadian dollar.
The following is a summary of the total gain (loss) on risk management
contracts for the year-over-year change as of the 2007 year-end:
<<
-------------------------------------------------------------------------
Interest
Risk Management Contracts Crude Oil Natural & Foreign 2007 2006
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) (5.7) 15.4 4.4 14.1 29.3
Unrealized gain (loss)
on contracts(2) (60.2) (2.9) 7.2 (55.9) (4.6)
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts (65.9) 12.5 11.6 (41.8) 24.7
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in
fair value of the contracts during the period.
Operating Netbacks
The Trust's operating netback, after realized hedging gains, decreased one
per cent to $35.44 per boe in 2007 compared to $35.95 per boe in 2006. The
decrease in netbacks in 2007 is primarily due to a decrease in the realized
gain on risk management contracts, a decrease in gas prices, as well as an
increase in operating costs and transportation. These items were partially
offset by a decrease in royalties and an increase in revenues as a result of
higher oil prices in 2007.
The components of operating netbacks are shown below:
-------------------------------------------------------------------------
Crude Heavy 2007 2006
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 70.20 49.17 6.75 54.79 54.54 53.33
Other revenue - - - - 0.13 0.13
Total revenue 70.20 49.17 6.75 54.79 54.67 53.46
Royalties (11.33) (4.34) (1.25) (14.90) (9.59) (9.66)
Transportation (0.27) (1.09) (0.20) - (0.72) (0.63)
Operating costs(1) (11.84) (12.16) (1.26) (7.73) (9.54) (8.49)
-------------------------------------------------------------------------
Netback prior to hedging 46.76 31.58 4.04 32.16 34.82 34.68
Realized gain (loss) on
risk management contracts (0.07) - 0.23 - 0.62 1.27
-------------------------------------------------------------------------
Netback after hedging 46.69 31.58 4.27 32.16 35.44 35.95
-------------------------------------------------------------------------
(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.
>>
Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs remained constant at 18 per cent for both 2007 and 2006
at $9.59 per boe and $9.66 per boe respectively. The Trust has made a
preliminary assessment of the impact of the new Alberta Royalty legislation
effective January 1, 2009 and we estimate that the total royalties payable on
the Trust's production will increase by approximately 10 per cent at current
commodity prices calculated using expected 2009 production rates. This
estimate will vary based on prices, production decline of existing wells and
performance and location of new wells drilled. The 10 per cent increase in
royalties payable which equates to approximately a two per cent increase in
the Trust's royalty rate takes into account that approximately 37 per cent of
the Trust's production is outside the Province of Alberta. The royalty change
in 2009 on a property by property basis is highly variable with decreased
royalties on some properties, primarily shallow gas wells, and a doubling of
royalties on Alberta high rate oil production properties. The New Alberta
Royalty Framework will impact future drilling decisions in order for the Trust
to maintain acceptable rates of return on its capital deployed.
Operating costs increased to $9.54 per boe compared to $8.49 per boe in
2006. Total operating costs increased $23 million or, 12 per cent, in 2007.
This increase was due to a combination of costs including the additional
operating costs associated with approximately 300 new wells brought on stream
in 2007, increased labour costs for field staff and some service providers
particularly in northern operations, increased electricity consumption and
costs for well re-activations in the Redwater and NPCU areas. There are a high
percentage of fixed operating costs for the Trust's properties resulting in a
trend of increased operating costs on a per boe basis as the properties'
production declines over time. The Trust estimates that full year 2008
operating costs will be approximately $235 million or approximately $10.20 per
boe based on annual production of approximately 63,000 boe per day.
Transportation costs increased 14 per cent to $0.72 per boe in 2007
compared to $0.63 per boe in 2006 as a result of ongoing challenges in
Saskatchewan where shipping restrictions are in place for the Enbridge
pipeline. The Trust is required to truck all new production that exceeds our
historical capacity for the Enbridge pipeline. Investors can expect
transportation prices to increase again once the winter drilling program
begins and new production levels increase. An expansion of the Enbridge
pipeline is expected to be completed sometime in early 2008, however,
transportation costs for 2008 are still expected to increase to $0.80 per boe
based on annual production of 63,000 boe per day.
General and Administrative Expenses and Trust Unit Incentive Compensation
G&A net of overhead recoveries on operated properties increased four per
cent to $49.1 million in 2007 from $47.1 million in 2006. Increases in G&A
expenses for 2007 were due to increased staff levels, higher compensation
costs and increased long-term incentive benefits. As a result of a tight
labour market, the costs associated with hiring, compensating and retaining
employees and consultants have risen. The anticipated increase in G&A costs
was partially offset by higher overhead recoveries attributed to high levels
of capital and operating activity throughout 2007 and as a result of
incremental overhead charged on new and existing operated properties.
The Trust paid out $12.7 million under the Whole Trust Unit Incentive
Plan ("Whole Unit Plan") in 2007 compared to $5.2 million in 2006
($9.6 million and $3.5 million of the payouts were allocated to G&A in 2007
and 2006, respectively, and the remainder to operating costs and property,
plant and equipment). The higher cash payment in 2007 resulted from the
Trust's first payments for performance units issued under the plan in 2004.
The next cash payment under the Whole Unit Plan is scheduled to occur in April
2008.
The following is a breakdown of G&A and trust unit incentive compensation
expense:
<<
-------------------------------------------------------------------------
G&A and Trust Unit Incentive
Compensation Expense
($ millions except per boe) 2007 2006 % Change
-------------------------------------------------------------------------
G&A expenses 52.7 45.8 15
Operating recoveries (16.4) (12.9) 27
-------------------------------------------------------------------------
Cash G&A expenses before Whole Unit Plan 36.3 32.9 10
Cash Expense - Whole Unit Plan 9.6 3.5 174
-------------------------------------------------------------------------
Cash G&A expenses including Whole Unit Plan 45.9 36.4 26
-------------------------------------------------------------------------
Accrued compensation - Rights Plan - 2.5 (100)
Accrued compensation - Whole Unit Plan 3.2 8.2 (61)
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 49.1 47.1 4
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense per boe 2.15 2.05 5
-------------------------------------------------------------------------
>>
A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $3.2 million ($0.14 per boe) was recorded in 2007
compared to $10.7 million ($0.47 per boe) in 2006. This non-cash amount
relates to estimated costs of the Whole Unit Plan to December 31, 2007. The
2006 amounts also include estimated costs of the Trust Unit Incentive Rights
Plan ("Rights Plan") that was fully expensed at December 31, 2006 with the
exception of a small portion recorded in March 2007.
Rights Plan
The rights plan was replaced by a Whole Unit Plan during 2004 after which
no further rights under the rights plan were issued. The Rights Plan, provided
employees, officers and independent directors the right to purchase units at a
specified price. The rights have a five year term and vest equally over three
years. The exercise price of the rights is adjusted downwards from time to
time by the amount that distributions to unitholders, in any calendar quarter
exceed 2.5 per cent of the Trust's net book value of property, plant and
equipment. During 2007, 0.1 million rights were exercised and 0.2 million
rights remained outstanding as at December 31, 2007. All of the rights have
been fully expensed since March 31, 2007 and are scheduled to expire on or
before December 31, 2008.
Whole Unit Plan
In March 2004, the Board of Directors approved a new Whole Unit Plan to
replace the Rights Plan for new awards granted subsequent to the first quarter
of 2004. The new Whole Unit Plan results in employees, officers and directors
(the "plan participants") receiving cash compensation in relation to the value
of a specified number of underlying units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
Upon vesting, the plan participant is entitled to receive a cash payment
based on the fair value of the underlying trust units plus accrued
distributions. The cash compensation issued upon vesting of the PTUs is
dependent upon the performance of the Trust compared to its peers and
indicated by the performance multiplier. The performance multiplier is based
on the percentile rank of the Trust's total unitholder return compared to its
peers. Total return is calculated as the sum of the change in the market price
of the trust units in the period plus the amount of distributions in the
period. The performance multiplier ranges from zero, if ARC's performance
ranks in the bottom quartile, to two for top quartile performance.
The following table shows the changes during the year of RTUs and PTUs
outstanding:
<<
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and $ millions Number of Number of Total RTUs
except per unit) RTUs PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of year 648 683 1,331
Granted in the year 422 362 784
Vested in the year (286) (110) (396)
Forfeited in the year (38) (32) (70)
-------------------------------------------------------------------------
Balance, end of year(1) 746 903 1,649
-------------------------------------------------------------------------
Estimated distributions to vesting date(2) 226 249 475
Estimated units upon vesting
after distributions 972 1,152 2,124
Performance multiplier(3) - 1.7 -
-------------------------------------------------------------------------
Estimated total units upon vesting 972 1,958 2,931
-------------------------------------------------------------------------
Trust unit price at December 31, 2007 $20.40 $20.40 $20.40
Estimated total value upon vesting $19.8 $39.9 $59.8
-------------------------------------------------------------------------
(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 1.7 at December 31, 2007 based on a weighted average calculation
of all outstanding grants. The performance multiplier is assessed
each period end based on actual results of the Trust relative to its
peers.
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 unit price, the number of PTUs to be issued on vesting, and distributions.
Therefore, the expense recorded in the statement of income fluctuates over
time.
Below is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
December 31, 2007 Performance Multiplier
------------------------------
(units thousands and $ millions
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 972 972 972
PTUs - 1,253 2,513
-------------------------------------------------------------------------
Total units(1) 972 2,225 3,485
-------------------------------------------------------------------------
Trust unit price(2) $20.40 $20.40 $20.40
Trust unit distributions per month(2) $0.20 $0.20 $0.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting 19.8 45.4 71.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Officers 2.1 13.9 25.8
Directors 1.5 1.5 1.5
Staff 16.2 30.0 43.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total payments under Whole Unit Plan(3) 19.8 45.4 71.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2008 8.8 16.0 23.1
2009 6.9 14.9 23.0
2010 4.1 14.5 25.0
-------------------------------------------------------------------------
(1) Includes additional estimated units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumes
future trust unit price of $20.40 per trust unit and distributions of
$0.20 per unit per month based on current levels.
(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 April
and October of each year and at that time is reflected as a reduction
of cash flow from operating activities.
>>
Due to the variability in the future payments under the plan, the Trust
estimates that between $19.8 million and $71.1 million will be paid out from
2008 through 2010 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.
Interest Expense
Interest expense increased to $36.9 million in 2007 from $31.8 million in
2006 due to an increase in short-term interest rates, and higher debt balances
as a result of the Trust's capital expenditure and acquisitions activity which
was funded $135.7 million with debt. As at December 31, 2007, the Trust had
$714.5 million of debt outstanding, of which $215.5 million was fixed at a
weighted average rate of 5.1 per cent and $499 million was floating at current
market rates plus a credit spread of 60 basis points. Fifty-two per cent of
the Trust's debt is denominated in U.S. dollars. The cumulative decline of
1.25 per cent in the U.S. interest rates announced in January 2008 by the
Federal Reserve Board should result in lower borrowing costs for the Trust in
2008.
Foreign Exchange Gains and Losses
The Trust recorded a gain of $69.4 million ($3.03 per boe) on foreign
exchange transactions compared to a loss of $4.2 million ($0.18 per boe) in
2006. These amounts include both realized and unrealized foreign exchange
gains and losses.
Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The volatility of the Canadian dollar during
the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow from operating activities as it is a non-cash
amount. From December 31, 2006 to December 31, 2007, the CAD$/US$ exchange
rate has increased from 0.86 to 1.01 creating an unrealized gain of
$64.6 million on U.S. dollar denominated debt.
Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements. Included in the 2007 realized foreign exchange gain was a gain of
$5 million relating, in part, to a repayment of US$6 million of debt in
October 2007. The debt was issued in 2002 when the CAD$/US$ foreign exchange
rate was approximately 0.64 and strengthened considerably to 1.04 on repayment
in 2007.
Taxes
In 2007, a future income tax recovery of $121.3 million was included in
income compared to an $87.1 million recovery in 2006. The significant increase
in the future income tax recovery in 2007 was due to the legislated reduction
in the future corporate income tax rates in the fourth quarter of 2007 whereby
the Trust's expected future corporate income tax rate decreased to 25.8 per
cent from the 29.4 per cent prior to the rate reduction. The future income tax
recovery in 2006 was also due to legislated reductions in the future corporate
income tax rates.
At December 31, 2007, the Trust and the Trust's subsidiaries had tax
pools of approximately $1.84 billion. The tax pools consist of $1.66 billion
of tangible and intangible capital assets, $13.8 million of non-capital loss
carry-forwards which expire at various periods to 2026, and $171.4 million of
other tax pools. Included in the above tax basis are the Trust's tax pools of
approximately $537.7 million.
On October 31, 2006, the Finance Minister announced the Federal
Government's plan regarding the taxation of Income Trusts. Currently,
distributions paid to unitholders, other than returns of capital, are claimed
as a deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and is paid by the unitholders. The Trust tax
legislation that received Royal Assent on June 22, 2007, will result in a two-
tiered tax structure whereby distributions would first be subject to the
federal corporate income tax rate plus a deemed 13 per cent provincial income
tax at the Trust level commencing in 2011 (or earlier, if trusts that were
publicly traded as of October 31, 2006 exceed the normal growth guidelines
announced by the Minister on December 15, 2006), and then unitholders would be
subject to tax on the distribution as if it were a taxable dividend paid by a
taxable Canadian corporation. As a result, the future tax position of the
Trust, the parent entity, is now required to be reflected in the consolidated
future income tax calculation. The Trust recorded a $35.6 million one time
increase in earnings and a corresponding decrease to its future income tax
liability in the second quarter as a result of timing differences within the
Trust that had not been previously recognized. The initial recognition of
$35.6 million comprised $24.7 million for pre-2007 generated temporary
differences and $10.9 million for temporary differences relating to the
current year.
On October 30, 2007, the Finance Minister announced, as part of the 2007
Economic Statement, changes to the tax system including reduction of the
corporate income tax rate from 22.1 per cent to 15 per cent by 2012. The
reductions will be phased in between 2008 and 2012. Legislation enacting the
measures announced in the Economic Statement received Royal Assent on
December 14, 2007. The reduction in the general corporate tax rate will also
apply to the taxation of Income Trusts, reducing the combined federal and
deemed Provincial tax rate for distributions to 28 per cent in 2012.
The Federal Government has also indicated that they will seek to
collaborate with the provinces and territories to reach a combined federal-
provincial-territorial statutory corporate income tax rate of 25 per cent,
reflecting a 10 per cent provincial rate, equal to the current Alberta tax
rate. It is uncertain whether this collaboration will also affect the tax on
Income Trusts by reducing the proposed deemed provincial rate of 13 per cent.
On December 20, 2007, the Finance Minister announced technical amendments
to provide some clarification to the Trust tax legislation. As part of the
announcement the Minister indicated that the federal government intends to
provide legislation in 2008 to permit Income Trusts to convert to taxable
Canadian corporations without any undue tax consequences to investors or the
Trust.
Management and the Board of Directors continue to review the impact of
this tax on our business strategy and while there has not been a decision as
to ARC's future direction at this time we are of the opinion that the
conversion from a trust to a corporation may be the most logical and tax
efficient alternative for ARC unitholders. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the after-tax distribution amount in 2011 to taxable Canadian investors
will remain approximately the same, however, will decline for both tax-
deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign
investors.
The Trust tax rate applicable to 2007 is 34 per cent; however, the
application of the Trust tax should be deferred until 2011 as the Trust has
not exceeded the normal growth guidelines announced by the Minister. The Trust
does not anticipate that the Trust taxation legislation guidelines, which
limit the growth of the Trust up to 2011, will impair the Trust's ability to
annually replace or grow reserves in the next three years as the guidelines
allow sufficient growth targets. The corporate income tax rate applicable to
2007 is 32.1 per cent, however the Trust and its subsidiaries did not pay any
material cash income taxes for fiscal 2007. Due to the Trust's structure,
currently, both income tax and future tax liabilities are passed on to the
unitholders by means of royalty payments made between ARC Resources and the
Trust.
Federal capital taxes were eliminated effective January 1, 2006 pursuant
to the Federal Government budget of May 2, 2006.
Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate increased to
$16.23 per boe in 2007 from $15.64 per boe in 2006. The higher DD&A rate is
driven by an increase in the Trust's property, plant and equipment ("PP&E")
value on the Trust's balance sheet along with an increase in the future
development costs and a small decrease in the proved reserves recorded in the
Trust's January 1, 2008 reserve report.
<<
A breakdown of the DD&A rate is a follows:
-------------------------------------------------------------------------
DD&A Rate
($ millions except
per boe amounts) 2007 2006 % Change
-------------------------------------------------------------------------
Depletion of oil & gas assets(1) 360.0 348.9 3
Accretion of asset retirement obligation(2) 11.5 11.1 4
-------------------------------------------------------------------------
Total DD&A 371.5 360.0 3
DD&A rate per boe 16.23 15.64 4
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the PP&E balance and is being
depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>
Goodwill
The goodwill balance of $157.6 million arose as a result of the
acquisition of Star Oil and Gas in 2003. The goodwill balance was determined
based on the excess of total consideration paid plus the future income tax
liability less the fair value of the assets for accounting purposes acquired
in the transaction.
Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. The Trust has determined that there was no goodwill impairment as of
December 31, 2007.
Capital Expenditures and Net Acquisitions
Total capital expenditures, excluding acquisitions and dispositions,
totaled $397.2 million in 2007 compared to $364.5 million in 2006. This amount
was incurred on drilling and completions, geological, geophysical and
facilities expenditures, and undeveloped acreage. The $77.5 million purchases
of undeveloped land in 2007 have increased the Trust's land holdings to
536,232 net acres that will help sustain the drilling opportunities of the
Trust which will, if successful, provide future production and reserves.
In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $42.5 million in 2007. The most
significant property acquisition was the purchase of properties in southeast
Saskatchewan late in the third quarter for $24.8 million. The acquisition
contributed approximately 350 boe per day of incremental production to the
Trust's fourth quarter results.
During the year, the Trust drilled 278 gross wells (220 net wells) on
operated properties; consisting of 99 gross oil wells, three water injection
wells, and 172 gross natural gas wells most of which were shallow gas wells
with a success rate of 99 per cent. In addition, the Trust participated in
156 gross wells (33 net wells) drilled by other operators.
Proved plus probable oil and gas reserves were effectively maintained at
286.4 mmboe at year-end 2007 as a result of the Trust's 2007 capital
expenditure program and property acquisitions.
Over the course of 2006 and 2007, the Trust has spent $762 million on
capital expenditures, a portion of which has funded the following activities:
<<
- At our Dawson area in British Columbia, ARC spent $99 million of
capital to drill, complete and tie in 10 horizontal and 13 vertical
wells. ARC also expanded its compression facilities and signed a
long-term contract with a third party processor to facilitate
processing additional gas volumes in the area. ARC's production grew
from 19 mmcf per day to 45 mmcf per day over the two year period. In
addition, ARC has been building for the future by spending $100
million on acquiring 44,000 net acres of undeveloped land in the
area.
- At our Ante Creek area, ARC has focused on a combination of infill
and highly successful stepout pool extension drilling. ARC has spent
$61 million on drilling, completions, tie-ins, facilities, and land
purchases. ARC drilled 25 wells that resulted in positive reserves
growth and record production in the area of 5,100 boe per day for the
month of December 2007.
- In Southeast Saskatchewan we have spent $108 million and increased
production as a result of drilling 41 wells in the area including 35
new horizontal oil wells two successful exploration locations and one
new vertical injection well.
- ARC's 2007 exit production at Redwater was 4,300 boe per day, which
represents a 20 per cent increase over production at the time that
ARC closed the Redwater acquisition in December 2005. To achieve
these results, ARC invested $20 million focused mainly on a
combination of optimization and reactivation projects and the
drilling of infill vertical wells that were identified through
seismic data acquired in 2006.
- ARC drilled 313 net wells in our Southeast Alberta and Southwest
Saskatchewan area including 305 shallow gas wells and eight new oil
wells.
A breakdown of capital expenditures and net acquisitions is shown below:
-------------------------------------------------------------------------
Capital Expenditures
($ millions) 2007 2006 % Change
-------------------------------------------------------------------------
Geological and geophysical 14.9 11.4 31
Drilling and completions 229.5 240.5 (5)
Plant and facilities 72.1 77.6 (7)
Undeveloped land 77.5 32.4 139
Other capital 3.2 2.6 23
-------------------------------------------------------------------------
Total capital expenditures 397.2 364.5 9
-------------------------------------------------------------------------
Producing property acquisitions(1) 47.1 124.0 (62)
Producing property dispositions(1) (4.6) (8.8) 48
Corporate acquisitions(2) - 16.6 (100)
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 439.7 496.3 (11)
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
(2) Represents total consideration for the transactions, including fees
but is prior to the related future income tax liability, asset
retirement obligation and working capital assumed on acquisition.
Approximately 49 per cent of the $397.2 million capital program was
financed with cash flow from operating activities in 2007 compared to 65 per
cent in 2006. Property acquisitions were financed through debt and working
capital.
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Develop- Net Total Develop- Net Total
ment Acqui- Expend- ment Acqui- Expend-
Capital sitions itures Capital sitions itures
-------------------------------------------------------------------------
Expenditures 397.2 42.5 439.7 364.5 131.8 496.3
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating
activities 49% - 44% 65% - 48%
Proceeds from DRIP
and Rights Plan 28% - 25% 30% - 22%
Debt 23% 100% 31% 5% 100% 30%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
>>
ARC has announced a $395 million capital expenditure budget for 2008 that
consists of a robust drilling and development program on its diverse asset
base. The 2008 capital budget is being deployed as a balanced drilling program
of low and moderate risk wells, well tie-ins and other related costs, and the
acquisition of undeveloped land. The Trust continues to focus on major
properties with significant upside, with the objective to replace production
declines through internal development opportunities. The 2008 capital
expenditure budget anticipates the drilling of 252 net operated wells and the
addition of new production from the capital development program to replace
declines at existing properties and develop the recently acquired land
holdings in the Dawson area of British Columbia. The 2008 capital budget also
allows for a portion of spending to further research and pursue Enhanced
Recovery Initiatives such as CO(2) injection and NGC development. Current
projections of cash flows, low debt levels and a strong working capital
position provide the Trust with the financial flexibility to fund the 2008
capital expenditure program.
Long-Term Investment
During the second quarter of 2007, the Trust sold its investment in the
shares of a private company that was involved in the acquisition of oil sands
leases. The transaction closed on June 25, 2007. The Trust recorded a cash
gain of $13.3 million with total proceeds of $33.3 million recorded as part of
cash flow from investing activities.
Asset Retirement Obligation and Reclamation Fund
At December 31, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $140 million ($177.3 million at December 31, 2006) for
future abandonment and reclamation of the Trust's properties. The ARO
decreased in 2007 as a result of a change in management's estimate of the
timing of when costs will be incurred. 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 undiscounted total future liability has increased to
$1.3 billion as at December 31, 2007 as compared to $1 billion at December 31,
2006, as a significant portion of the costs are now projected to be incurred
in years 2048 to 2058 as compared to years 2017 to 2021 as estimated on
December 31, 2006. The present value impact of this change in estimate
resulted in a $34.4 million reduction in the ARO balance at December 31, 2007.
Included in the December 31, 2007 ARO balance is a $3.8 million increase
related to development activities in 2007. The ARO liability was also
increased by $11.5 million for accretion expense in 2007 ($11.1 million in
2006) and was reduced by $18.2 million ($10.6 million in 2006) for actual
abandonment expenditures incurred in 2007.
As a result of the Redwater acquisition in December 2005, the Trust set
up a second reclamation fund (the "Redwater Fund") in 2006 to fund future
abandonment obligations attributed solely to the Redwater properties. The
Trust makes annual contributions to the Redwater fund and may utilize the
funds only for abandonment activities for the Redwater property. With the
addition of the Redwater Fund, the Trust now maintains two reclamation funds
that together held $26.1 million at December 31, 2007. 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 the Trust's properties. The Trust currently estimates that
$220 million will be contributed to the funds over the next 50 years to
provide for future abandonment and reclamation costs.
In total, ARC contributed $12.1 million cash to its reclamation funds in
2007 ($12.1 million in 2006) and earned interest of $1.4 million ($1 million
in 2006) on the fund balances. The fund balances were reduced by $18.1 million
for cash-funded abandonment expenditures in 2007 ($5.7 million in 2006). Under
the terms of the Trust's investment policy, reclamation fund investments and
excess cash can only be invested in Canadian or U.S. Government securities,
investment grade corporate bonds, or investment grade short-term money market
securities.
<<
Capitalization, Financial Resources and Liquidity
A breakdown of the Trust's capital structure is as follows as at
December 31, 2007 and 2006:
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per unit
and per cent amounts) 2007 2006
-------------------------------------------------------------------------
Amount drawn under revolving credit facilities 499.0 426.1
Senior secured notes 215.5 261.0
Working capital deficit excluding short-term debt(1) 38.2 52.0
-------------------------------------------------------------------------
Net debt obligations 752.7 739.1
-------------------------------------------------------------------------
Trust units outstanding and issuable for
exchangeable shares (thousands) 213.2 207.2
Market price per unit at end of year 20.40 22.30
Market value of trust units and exchangeable share 4,349.3 4,620.0
-------------------------------------------------------------------------
Total capitalization(2) 5,102.0 5,359.1
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 14.8% 13.8%
Net debt obligations 752.7 739.1
Cash flow from operating activities 704.9 734.0
Net debt to cash flow from operating activities 1.1 1.0
-------------------------------------------------------------------------
(1) The working capital deficit excludes the balances for the current
portion of risk management contracts and the current portion of
future income taxes.
(2) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
The Trust has a syndicated three year revolving credit facility allowing
for maximum borrowing of up to $800 million. The debt is secured by all the
Trust's oil and gas properties and has the following major covenants:
-------------------------------------------------------------------------
Covenant Position as at December 31, 2007
-------------------------------------------------------------------------
Long-term debt and letters of Long-term debt and letters of credit
credit not to exceed three times of 0.9 times annualized net income
annualized net income before before non-cash items and interest
non-cash items and interest expense expense
-------------------------------------------------------------------------
Long-term debt, letters of credit Long-term debt, letters of credit
and subordinated debt not to exceed and subordinated debt of 0.9 times
four times annualized net income annualized net income before
before non-cash items and interest non-cash items and interest expense
expense
-------------------------------------------------------------------------
Long-term debt and letters of Long-term debt and letters of credit
credit not to exceed 50 per cent of of 26.5 per cent of the sum of
the sum of the book of value of unitholders' equity, long-term debt,
unitholders' equity, long-term debt, letters of credit, and subordinated
letters of credit, and subordinated debt
debt
-------------------------------------------------------------------------
>>
As indicated by the above table, the Trust is not close to breaching any
of its covenants and has additional potential borrowing capacity above the
$800 credit facility. The Trust's objective is to limit debt to under
2.0 times cash flow from operating activities and 20 per cent of total
capitalization. In addition to the $800 million credit facility, the Trust has
outstanding senior secured notes in the amount of $215.5 million as at
December 31, 2007, which do not reduce the available borrowings under the
credit facility. The Trust had $4.8 million of letters of credit outstanding
at December 31, 2007 and no subordinated debt. As at December 31, 2007, the
Trust was in compliance with all covenants.
During the third quarter the Trust entered into treasury lock contracts
in order to manage its interest rate exposure on future debt issuances.
Treasury locks enable the Trust to synthetically secure current market rates
for a future fixed rate funding. These instruments hedge only the underlying
treasury yield and not the credit spread applicable to ARC that is determined
at the time of issuance. Based on the transactions completed during the
quarter the Trust has locked in an effective U.S. ten year treasury rate of
4.8082 per cent on a notional amount of US$125 million. As at December 31,
2007 the mark-to-market value of these contracts was CDN$7.4 million loss.
The Trust intends to finance its $395 million 2008 capital program with
cash flow from operating activities and the proceeds of the DRIP with any
remainder financed with debt. If necessary, ARC has access to additional
capital through its current credit facility, a new issue of senior secured
notes, or by issuing equity. In the event that the Trust enters into a
material acquisition where the purchase price exceeds 10 per cent of the book
value of the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times, respectively.
Unitholders' Equity
At December 31, 2007, there were 213.2 million trust units issued and
issuable for exchangeable shares, an increase of six million trust units from
December 31, 2006. The increase in number of trust units outstanding is mainly
attributable to the 5.6 million trust units issued pursuant to the DRIP during
2007 at an average price of $19.93 per trust unit.
The Trust had 0.2 million rights outstanding as of December 31, 2007
under an employee plan where further rights issuances were discontinued in
2004. The rights have a five-year term and vested equally over three years
from the date of grant. The remaining rights may be exercised to purchase
trust units at an average adjusted exercise price of $8.50 per unit as at
December 31, 2007. All of the rights were fully vested at December 31, 2007
and will expire on or before December 31, 2008.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees
may elect to have units purchased for them on the market with the cash
received upon vesting.
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 2007, the Trust raised proceeds of $110.7 million and
issued 5.6 million trust units pursuant to the DRIP.
Distributions
ARC declared distributions of $498 million ($2.40 per unit), representing
71 per cent of 2007 cash flow from operating activities compared to
distributions of $484.2 million ($2.40 per unit), representing 66 per cent of
cash flow from operating activities in 2006.
Monthly distributions for 2007 were $0.20 per unit. Revisions, if any, to
the monthly distribution are normally announced on a quarterly basis in the
context of prevailing and anticipated commodity prices at that time.
The following items may be deducted from cash flow from operating
activities to arrive at distributions to unitholders:
<<
- The portion of capital expenditures that are funded with cash flow
from operating activities. In 2007, the Trust withheld 27 per cent of
2007 cash flow from operating activities to fund 49 per cent of the
capital program excluding acquisitions. The remaining portion of
capital expenditures was financed by proceeds from the DRIP program
and debt.
- An annual contribution to the reclamation funds, with $13.5 million
being contributed in 2007 including interest earned on the fund
balances. The reclamation funds are segregated bank accounts or
subsidiary trusts and the balances will be drawn on in future periods
as the Trust incurs abandonment and reclamation costs over the life
of its properties.
- Debt principal repayments from time to time as determined by the
Board of Directors. The Trust's current debt level is well within the
covenants specified in the debt agreements and, accordingly, there
are no current mandatory requirements for repayment. Refer to
the "Capital Structure and Liquidity" section of this MD&A for a
detailed review of the debt covenants.
- Income taxes that are not passed on to unitholders. The Trust has a
liability for future income taxes due to the excess of book value
over the tax basis of the assets of the Trust and its corporate
subsidiaries. The Trust currently, and up until January 1, 2011, may
minimize or eliminate cash income taxes in corporate subsidiaries by
maximizing deductions, however in future periods there may be cash
income taxes if deductions are not sufficient to eliminate taxable
income. Taxability of the Trust is currently passed on to unitholders
in the form of taxable distributions whereby corporate income taxes
are eliminated at the Trust level. The Trust taxation legislation,
which will take effect in 2011, will result in taxes payable at the
Trust level and therefore distributions to unitholders will decrease.
- Working capital requirements as determined by the Board of Directors.
Certain working capital amounts may be deducted from cash flow from
operating activities, however such amounts would be minimal and the
Trust does not anticipate any such deductions in the foreseeable
future.
- The Trust has certain obligations for future payments relative to
employee long-term incentive compensation. Presently, the Trust
estimates that $19.8 million to $71.1 million will be paid out
pursuant to such commitments in 2008 through 2010 subject to vesting
provisions and future performance of the Trust. These amounts will
reduce cash flow from operating activities and may in turn reduce
distributions in future periods.
Cash flow from operating activities and distributions in total and per
unit were as follows:
-------------------------------------------------------------------------
Cash flow from operating % %
activities and 2007 2006 Change 2007 2006 Change
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 704.9 734.0 (4) 3.35 3.59 (7)
Reclamation fund
contributions(1) (13.5) (13.1) 3 (0.06) (0.06) -
Capital expenditures
funded with cash
flow from operating
activities (193.4) (236.7) (18) (0.92) (1.16) (21)
Other(2) - - - 0.03 0.03 -
-------------------------------------------------------------------------
Distributions 498.0 484.2 3 2.40 2.40 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 year plus trust units issuable for exchangeable shares
at year-end.
The Trust continually assesses distribution levels, in light of commodity
prices and production volumes, to ensure that distributions are in line with
the long-term strategy and objectives of the Trust as per the following
guidelines:
- To maintain a level of distributions that, in the opinion of
Management and the Board of Directors, is sustainable for a minimum
period of six months. The Trust's objective is to normalize the
effect of volatility of commodity prices rather than to pass on that
volatility to unitholders in the form of fluctuating monthly
distributions.
- To ensure that the Trust's financial flexibility is maintained by a
review of the Trust's debt to equity and debt to cash flow from
operating activities levels. The use of cash flow from operating
activities to fund capital development activities reduces the
requirements of the Trust to use debt to finance these expenditures.
In 2007 the Trust funded 49 per cent of capital development
activities with 27 per cent of cash flow from operating activities.
The actual amount of cash flows withheld to fund the Trust's capital
expenditure program is dependent on the commodity price environment
and is at the discretion of the Board of Directors.
The actual amount of future monthly distributions is proposed by
management and is subject to the approval and discretion of the Board of
Directors. The Board reviews future distributions in conjunction with their
review of quarterly financial and operating results.
Monthly distributions for the first quarter of 2008 have been set at $0.20
per unit subject to monthly review based on commodity price fluctuations.
Revisions, if any, to the monthly distribution are normally announced on a
quarterly basis in the context of prevailing and anticipated commodity prices
at that time.
Historical Distributions by Calendar Year
The following table presents distributions paid and payable for each
calendar period.
-------------------------------------------------------------------------
Calendar Year Distributions Taxable Portion Return of Capital
-------------------------------------------------------------------------
2008 YTD(2) 0.20 0.20 0.00
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 $21.23 $14.41 $6.82
-------------------------------------------------------------------------
(1) Based on distributions paid and payable in 2006.
(2) Based on distributions declared at January 31, 2008 and estimated
taxable portion of 2008 distributions of 98 per cent.
>>
Please refer to the Trust's website at www.arcenergytrust.com for details
on 2007 monthly distributions and distribution dates for 2008.
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 2007, distributions paid in the
calendar year will be 97 per cent return on capital or $2.32 per unit for the
year (taxable) and three per cent return of capital or $0.08 per unit for the
year (tax deferred). For a more detailed breakdown, please visit our website
at www.arcenergytrust.com.
Per Unit Results and Sustainability
Due to natural production declines, the Trust must continually develop
its reserves and/or acquire new reserves in an effort to maintain reserves,
production and cash flow levels on which distributions are paid. The Trust
facilitates this by withholding a portion of cash flow from operating
activities to fund a portion of ongoing capital development activities and
maintain moderate debt levels; this is evidenced by the Trust's moderate
payout of distributions as compared to cash flow from operating activity
levels. Oil and gas royalty trusts hold assets that are depleting and
unitholders should expect production, revenue, cash flows and distributions to
decline over the long-term if reserves cannot be economically replaced. The
Trust has an inventory of internal development prospects that we expect will
enable the Trust to maintain production for a minimum period of two years. The
Trust measures its sustainability and success in terms of per unit
distributions, production, reserves, and cash flow from operating activities
in addition to the ability to maintain low debt levels and the annual
replacement of reserves.
Following is a summary of the historical debt-adjusted production and
reserves per unit and reserve life index ("RLI") on which the Trust assesses
performance and sustainability:
<<
-------------------------------------------------------------------------
3 Year
Per trust unit ratios 2007 2006 2005 Total
-------------------------------------------------------------------------
Production per unit(1):
Unadjusted 0.30 0.31 0.29 -
Debt-adjusted(3) 0.26 0.27 0.26 -
Normalized(4) 0.30 0.31 0.32 -
-------------------------------------------------------------------------
Reserves per unit(2):
Unadjusted 1.34 1.38 1.42 -
Debt-adjusted(3) 1.15 1.19 1.28 -
Normalized(4) 1.35 1.40 1.51 -
-------------------------------------------------------------------------
Reserve life index(5) 12.5 12.4 12.9 -
Cash flow from operating
activities per unit $3.35 $3.59 $3.23 $10.17
Distributions per unit $2.40 $2.40 $1.99 $6.79
Distributions as a per cent
of cash flow from operating
activities 71 66 61 66
Per cent of cash flow from
operating activities retained 29 34 39 34
-------------------------------------------------------------------------
(1) Represents daily average production per thousand units. Calculated
based on annual daily average production divided by weighted average
trust units outstanding including trust units issuable for
exchangeable shares.
(2) Calculated based on proved plus probable reserves divided by period
end trust units outstanding including trust units issuable for
exchangeable shares.
(3) Debt-adjusted indicates that all years as presented have been
adjusted to reflect a nil net debt to capitalization. It is assumed
that additional trust units were issued 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 reduce the net debt
balance to zero in each year. The debt-adjusted amounts are presented
to enable comparability of annual per unit values.
(4) Normalized indicates that all years 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 annual per unit values.
(5) Calculated based on proved plus probable reserves divided by annual
2008 production estimate of 63,000 boe per day for 2007 RLI.
>>
During the 2005 to 2007 time period the Trust's normalized production per
unit has decreased only slightly from 0.32 to 0.30 boe of daily average
production per thousand trust units. Normalized reserves per unit have
decreased just over 10 per cent during this time to 1.35 from 1.51 boe of
proved plus probable reserves per trust unit. These levels of production and
reserves per unit occurred even with the payout of $1.4 billion of
distributions ($6.79 per trust unit and 66 per cent of cash flow from
operating activities) during the 2005 through 2007 time period. This indicates
that the Trust has grown production levels to help offset natural production
declines and developed its reserve base. The normalized production per unit is
a key measure as it indicates the ability to generate cash flows from core
operations that in turn impacts the level of cash that may be distributed to
unitholders. The Trust expects to replace production in 2008 from internal
development opportunities.
To compare the Trust's results with oil and gas companies that retain all
of their cash flow from operating activities to grow production and reserves,
the Trust looks at normalized and distribution-adjusted production and
reserves per unit which calculates the total reserves and production per
initial investment with the assumption that distributions are reinvested
through the DRIP plan. Consequently, the reserves and production per initial
investment increase over time as the investor's number of trust units increase
with distribution reinvestment. The Trust's normalized daily average
production per initial investment has increased from 0.35 boe per thousand
trust units in 2005 to 0.40 in 2007, while normalized reserves per initial
investment have increased from 1.66 boe at January 1, 2005 to 1.82 boe at
December 31, 2007. Based on the assumption of re-investment of the
distributions for additional trust units, one trust unit purchased on January
1, 2005 would have grown to 1.35 trust units on December 31, 2007. A
unitholder can replicate this by participating in the DRIP so that the number
of units they own increases over time.
The Trust's RLI decreased slightly to 12.5 years in 2007 from 12.9 years
in 2005. The RLI is a measure of the remaining average life of the reserves
based on a current production estimate for 2008 of 63,000 boe per day. The
Trust's high RLI is indicative of the high quality of assets and the
relatively low production decline rate of the properties. The acquisition of
the Redwater and NPCU properties in 2005 resulted in an increase in the RLI
due to the long reserve life of the properties. In addition, the Trust has
been able to replace reserves through the drill bit throughout 2006 and 2007
as no significant acquisitions have been completed during that time and yet
the Trust produced almost 46 million barrels of oil equivalent during those
two years. A high RLI is key for a royalty trust as it is indicates the
potential sustainability of production levels and cash flows over a longer
period of time.
The Trust's distribution policy centres around the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The Trust has maintained distributions at $0.20 per
unit per month since October 2005. This consistent level of distributions has
allowed the Trust to finance $193.4 million of capital expenditures through
cash flow from operating activities in 2007. In addition, low natural gas
prices and high Canadian dollar values observed in 2007, which negatively
impacted the Trust's cash flow from operating activities, did not cause the
Trust to cut distributions - this was an anomaly amongst the Trust's peers.
The Trust's distribution as a per cent of cash flow from operating activities
for 2007 was 71 per cent. The moderate level of distributions is indicative of
the Trust's commitment to fund ongoing development activities with cash flow
from operating activities to enable long-term sustainability.
An additional measure of sustainability is the comparison of net income
to distributions. Net income incorporates all costs including depletion
expense and other non-cash expenses whereas cash flow from operating
activities measures the cash generated in a given period before the cost of
the associated reserves. Therefore, net income may be more representative of
the profitability of the entity and thus a relevant measure against which to
measure distributions to illustrate sustainability. As net income is sensitive
to fluctuations in commodity prices, it is expected that there will be
deviations between annual net income and distributions. The following table
illustrates the annual shortfall of distributions to net income as a measure
of long-term sustainability.
<<
-------------------------------------------------------------------------
Net income and distributions Trailing
($ millions except per cent) 2007 2006 2005 3 years
-------------------------------------------------------------------------
Net income 495.3 460.1 356.9 1,312.3
Distributions 498.0 484.2 376.6 1,358.8
-------------------------------------------------------------------------
Shortfall (2.7) (24.1) (19.7) (46.5)
Shortfall as
per cent of net income (1%) (5%) (6%) (4%)
Distributions as a per
cent of cash flow from
operating activities 71% 66% 61% 66%
-------------------------------------------------------------------------
Contractual Obligations and Commitments
The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, and lease
rental obligations and employee agreements. These obligations are of a
recurring and consistent nature and impact the Trust's cash flows in an
ongoing manner. The Trust also has contractual obligations and commitments
that are of a less routine nature as disclosed in the following table.
-------------------------------------------------------------------------
Commitments Payments due by period
----------------------------------------
2009- 2011-
($ millions) 2008 2010 2012 Thereafter Total
-------------------------------------------------------------------------
Debt repayments(1) 5.9 540.8 51.5 116.3 714.5
Interest payments(2) 11.0 20.2 15.5 13.7 60.4
Reclamation fund
contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 10.1 4.1 4.0 6.0 24.2
Operating leases(4) 6.2 8.9 12.4 88.1 115.6
Risk Management
contract premiums(5) 13.2 2.3 - - 15.5
-------------------------------------------------------------------------
Total contractual
obligations 52.2 586.5 92.3 296.0 1,027.0
-------------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest. In the event that
the credit facility is not extended at any time before the maturity
date, the loan balance will become payable on the maturity date which
is April 15, 2010.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property acquired in 2005.
(4) Available option expiring February 2008 to reduce office lease
commitment.
(5) Fixed premiums to be paid in future periods on certain risk
management contracts.
>>
The above noted risk management contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has commitments related to its risk management program. As
the premiums are part of the underlying risk management contract, they have
been recorded at fair market value at December 31, 2007 on the balance sheet
as part of risk management contracts.
The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2008 capital budget has
been approved by the Board at $395 million. This commitment has not been
disclosed in the commitment table as it is of a routine nature and is part of
normal course of operations for active oil and gas companies and trusts.
The above noted operating leases include amounts for the Trust's head
office lease. The current lease expires in May 2010. In December 2007, the
Trust entered into a 13 year lease commitment beginning in 2010 for office
space in a new building that is under construction in downtown Calgary. The
new lease commitment is reflected in the table above.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the commitment table does not include any
commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.
Off Balance Sheet Arrangements
The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table above, which were entered into
in the normal course of operations. All leases have been treated as operating
leases whereby the lease payments are included in operating expenses or G&A
expenses depending on the nature of the lease. No asset or liability value has
been assigned to these leases in the balance sheet as of December 31, 2007.
Fourth Quarter Financial and Operational Results
The Trust had an active fourth quarter with $139.3 million spent on
capital development activities that contributed to quarterly average
production of 63,989 boe per day. The Trust distributions were 72 per cent of
cash flow from operating activities. The remaining 28 per cent was used to
fund $44.5 million of the fourth quarter capital development program and make
contributions to the reclamation fund. The fourth quarter was an active one
for the Trust with the drilling of 77 gross wells on operated properties and
new production coming on-stream in the Dawson area of British Columbia.
<<
- The Trust's fourth quarter production was 63,989 boe per day, a
slight increase from the fourth quarter of 2006 where production was
63,663. As compared to the third quarter of 2007, the Trust's
production increased five per cent or 2,881 boe per day. This was
primarily as a result of approximately 350 boe per day from an
acquisition that the Trust completed late in the third quarter of
2007 as well as new production in the Dawson area of British Columbia
of approximately 1,400 boe per day.
- The Trust spent $139.3 million on capital development activities and
undeveloped land in the fourth quarter compared to $121.9 million in
2006. The Trust had a very active fourth quarter with the drilling of
77 gross wells (69 net wells) on operated properties with a 100 per
cent success rate. The Trust expanded its inventory of undeveloped
land acreage with the purchase of $42.6 million of land in the fourth
quarter. The land acquired was in core areas where the Trust has
identified strategic development opportunities.
- The fourth quarter netback before hedging increased 17 per cent to
$36.63 per boe as compared to $31.37 for the same period of 2006.
Record high oil prices, offset by increased royalties and operating
costs lower gas prices contributed to the high netback recorded for
the quarter.
- Cash G&A expenses in the fourth quarter increased to $1.96 per boe as
compared to $1.74 for the same period in 2006. The majority of the
increase is attributable to a larger whole unit plan payment made in
October of 2007.
-------------------------------------------------------------------------
Fourth Quarter Financial and
Operational Highlights
(CDN$ millions except per
unit and per cent) Q4 2007 Q4 2006 % Change
-------------------------------------------------------------------------
Production (boe/d) 63,989 63,663 1
Cash flow from operating
activities 173.7 159.3 9
Per unit $ 0.82 $ 0.77 (6)
Distributions 125.8 122.3 3
Per unit $ 0.60 $ 0.60 -
Per cent of cash flow from
operating activities 72 77 (6)
Net income 106.3 56.6 88
Per unit $ 0.51 $ 0.28 82
-------------------------------------------------------------------------
Prices
WTI (US$/bbl) 90.63 60.22 50
USD/CAD exchange rate 1.02 0.87 17
Realized oil price (CDN $/bbl) 77.53 58.26 33
AECO gas monthly index (CDN $/mcf) 6.00 6.36 (6)
Realized gas price (CDN $/mcf) 6.32 6.99 (10)
-------------------------------------------------------------------------
Operating netback ($/boe)
Revenue, before hedging 57.42 49.94 15
Royalties (10.46) (8.80) 19
Transportation (0.69) (0.64) 8
Operating costs (9.64) (9.13) 6
Netback (before hedging) 36.63 31.37 17
Cash hedging gain (loss) (0.20) 1.68 (112)
Netback (after hedging) $ 36.43 $ 33.05 10
-------------------------------------------------------------------------
Capital expenditures 139.3 121.9 14
Capital funded with cash flow from
operating activities (per cent) 32 28 14
-------------------------------------------------------------------------
Critical Accounting Estimates
The Trust has continuously evolved and documented its management and
internal reporting systems to provide assurance that accurate, timely internal
and external information is gathered and disseminated.
The Trust's financial and operating results incorporate certain estimates
including:
- estimated revenues, royalties and operating costs on production as at
a specific reporting date but for which actual revenues and costs
have not yet been received;
- estimated capital expenditures on projects that are in progress;
- estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves that the Trust expects to recover
in the future;
- estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and
foreign exchange rates;
- estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
- estimated future recoverable value of property, plant and equipment
and goodwill.
>>
The Trust has hired individuals and consultants who have the skills
required to make such estimates and ensures that individuals or departments
with the most knowledge of the activity are responsible for the estimates.
Further, past estimates are reviewed and compared to actual results, and
actual results are compared to budgets in order to make more informed
decisions on future estimates.
The ARC leadership team's mandate includes ongoing development of
procedures, standards and systems to allow ARC staff to make the best
decisions possible and ensuring those decisions are in compliance with the
Trust's environmental, health and safety policies.
Disclosure Controls and Procedures
As of December 31, 2007, an internal evaluation was carried out of the
effectiveness of the Trust's disclosure controls and procedures as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in
Canada by Multilateral Instrument 52-109, Certification of Disclosure in
Issues' Annual and Interim Filings. Based on that evaluation, the President
and Chief Executive Officer and the Senior Vice President Finance and Chief
Financial Officer concluded that the disclosure controls and procedures are
effective to ensure that the information required to be disclosed in the
reports that the Trust files or submits under the Exchange Act or under
Canadian Securities legislation is recorded, processed, summarized and
reported, within the time periods specified in the rules and forms therein.
Disclosure controls and procedures include, without limitation, controls and
procedures designed to ensure that the information required to be disclosed by
the Trust in the reports that it files or submits under the Exchange Act or
under Canadian Securities legislation is accumulated and communicated to the
Trust's management, including the senior executive and financial officers, as
appropriate to allow timely decisions regarding the required disclosure.
Internal Controls over Financial Reporting
Internal control over financial reporting is a process designed to
provide reasonable assurance that all assets are safeguarded, transactions are
appropriately authorized and to facilitate the preparation of relevant,
reliable and timely information. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements.
Management has assessed the effectiveness of the company's internal control
over financial reporting as defined in Rule 13a-15 under the US Securities
Exchange Act of 1934 and as defined in Canada by Multilateral Instrument 52-
109, Certification of Disclosure in Issues' Annual and Interim Filings. The
assessment was based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Management concluded that the Trust's internal control over
financial reporting was effective as of December 31, 2007. The effectiveness
of the Trust's internal control over financial reporting as of December 31,
2007 has been audited by Deloitte & Touche LLP, as reflected in their report
for 2007. No changes were made to our internal controls over financial
reporting during the year ending December 31, 2007, that have materially
affected, or are reasonably likely to materially affect, our internal controls
over financial reporting.
Financial Reporting Update
During 2007, the Trust completed the implementation of the new CICA
Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section
3855, Financial Instruments - Recognition and Measurement, Section 3861,
Financial Instruments - Disclosure and Presentation, and Section 3865, Hedges
that deal with the presentation of equity, recognition, measurement,
disclosure, and presentation of financial instruments, and comprehensive
income. As required by the new standards, adoption has been applied
prospectively as at January 1, 2007 and prior periods have not been restated.
The adoption of these standards has had no material impact on the Trust's Net
Income or Cash Flows. See notes 3 and 11 in the Notes to the Consolidated
Financial Statements for further details.
Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if they
result in financial statements that provide more reliable and relevant
information. Changes in policy are applied retrospectively unless it is
impractical to determine the period or cumulative impact of the change.
Corrections of prior period errors are applied retrospectively and changes in
accounting estimates are applied prospectively by including these changes in
net income. In addition, disclosure is required for all future accounting
changes when an entity has not applied a new source of GAAP that has been
issued but is not yet effective.
Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards:
Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures, and Section 3863, Financial Instruments -
Presentation. These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance. This Section is expected to have minimal impact on the Trust's
financial statements.
Sections 3862 and 3863 specify standards of presentation and enhanced
disclosure on financial instruments. Increased disclosure will be required on
the nature and extent of risks arising from financial instruments and how the
entity manages those risks.
In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards concerning
goodwill are unchanged from the standards included in the previous Section
3062. The Trust is currently evaluating the impact of the adoption of this new
Section, however does not expect a material impact on its Consolidated
Financial Statements.
Update on Legislation Changes Impacting the Trust
Broad-based Federal Tax Reductions
On October 30, 2007 the Federal Government presented the fall economic
statement that proposed significant reductions in corporate income tax rates
from 22.1 per cent to 15 per cent. The reductions will be phased in between
2008 and 2012. In addition, the Government announced that it plans to
collaborate with the provinces and territories to reach a 25 per cent combined
federal-provincial-territorial statutory corporate income tax rate. The
reduction in the federal rate will also reduce the SIFT tax rate to 28 per
cent as compared to the rate of 31.5 per cent previously announced.
Alberta Government Royalty Regime
In September 2007, the Alberta Government announced the results of the
royalty review that was performed by an independent panel and on October 25,
2007, the Alberta Government announced The New Royalty Framework,
("framework"), which will take effect on January 1, 2009 and is projected by
the government to increase royalties by approximately $1.4 billion in 2010 or
an increase of 20 per cent over revenue forecasts by the Alberta Government
for that year. Subsequent to that time the Alberta Government has made some
concessions to the proposed royalty increases and industry is still awaiting
final legislation in order to fully assess the impact. Our understanding is
that at current commodity prices the increases comprise an average 57 per cent
increase in conventional oil royalties and a 10 per cent increase in gas
royalties. The maximum royalty rates increasing from the current maximums of
30 per cent and 35 per cent for old and new tier rates respectively to rates
that will range up to 50 per cent.
The framework proposes new, simplified royalty formulas for conventional
oil and natural gas that will operate on sliding scales which are determined
by commodity prices and well productivity. The formulas eliminate the
conventional oil and natural gas tiers and several royalty exemption and
relief programs. Enhanced Oil Recovery and Innovative Energy Technology
Program Royalty relief programs have been retained.
Based on our current estimates, the Trust expects that the total
corporate royalties payable will increase by approximately 10 per cent in
2009. This estimate will vary based on prices, production decline of existing
wells and performance and location of new wells drilled. The 10 per cent
increase in royalties payable, which equates to approximately a two per cent
increase in the Trust's overall royalty rate, takes into account that greater
than 37 per cent of the Trust's forecast production is from outside the
Province of Alberta. The royalty change in 2009 on a property by property
basis is highly variable with decreased royalties on some properties,
primarily shallow gas wells, and a doubling of royalties on Alberta high rate
oil production properties. The New Alberta Royalty Framework will impact
future drilling decisions in order for the Trust to maintain acceptable rates
of return on its capital deployed. The Trust reviews all of its capital
expenditures on a project by project basis; with higher royalties in the
Province of Alberta, projects previously deemed economic may no longer meet
the Trust's investment objectives.
Federal Government's Trust Tax Legislation
In 2007, the Federal Government introduced and passed into law Trust
taxation that will result in a tax of 28 per cent (previously 31.5 per cent as
discussed above) on all Trust distributions commencing January 1, 2011. Cash
flow earned by the Trust and not distributed has always been and continues to
form part of taxable income at the Trust level, which may result in cash taxes
being paid if there are not sufficient tax pool claims and deductions obtained
upon incurring capital expenditures or acquiring assets.
The Trust recorded a $35.6 million one time increase in earnings and a
corresponding decrease to its future income tax liability as a result of
timing differences within the Trust that have not been previously recognized
as the Trust's tax pools were in excess of the net book value of the Trust's
assets. The initial recognition of $35.6 million comprises $24.7 million for
pre-2007 generated temporary differences and $10.9 million for temporary
differences relating to the current year. This amount was recorded in the
second quarter results and is reflected in the 2007 year-to-date results.
Management and the Board of Directors continue to review the impact of
this tax on our business strategy and while there has not been a decision as
to ARC's future direction at this time we are of the opinion that the
conversion from a trust to a corporation may be the most logical and tax
efficient alternative for ARC unitholders. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the after-tax distribution amount in 2011 to taxable Canadian investors
will remain approximately the same, however, will decline for both tax-
deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign
investors.
Climate Change Programs
On March 8, 2007, the Alberta government introduced legislation to reduce
greenhouse gas emission intensity. Bill 3 states that facilities emitting more
than 100,000 tonnes of greenhouse gases per year must reduce their emissions
intensity by 12 per cent over the average emissions levels of 2003, 2004 and
2005; if they are not able to do so, these facilities are required to pay
$15 per tonne for every tonne above the 12 per cent target, effective as of
July 1, 2007. At this time, the Trust has determined that the impact of this
legislation would be minimal based on ARC's existing facilities ownership.
In April 2007, the Federal Government announced a new climate change plan
that calls for greenhouse gas emissions to be reduced by 20 per cent below
current levels by 2020. Firms may employ the following strategies to achieve
the targets. They will be able to:
<<
- make in-house reductions;
- take advantage of domestic emissions trading;
- purchase offsets;
- use the Clean Development Mechanism under the Kyoto Protocol; and,
- invest in a technology fund.
>>
The Trust is waiting for additional information so as to fully assess
what impact, if any, this new legislation will have on its operations.
On January 24, 2008 the Alberta Government announced their plan to reduce
projected emissions in the province by 50 per cent under the new climate
change plan by 2050. This will result in real reductions of 14 per cent below
2005 levels. The Alberta Government stated they will form a
government-industry council to determine a go-forward plan for implementing
technologies, which will significantly reduce greenhouse gas emissions by
capturing air emissions from industrial sources and locking them permanently
underground in deep rock formations.
In addition the plan calls for energy conservation by individuals and for
increased investment in clean energy technologies and incentives for expanding
the use of renewable and alternative energy sources such as bioenergy, wind,
solar power, hydrogen and geothermal energy. Initiatives under this theme will
account for 18 per cent of Alberta's reductions. A detailed implementation
plan will be developed and released in the spring of 2008.
United States Proposed Changes to Qualifying Dividends
A bill was introduced into United States Congress on March 23, 2007 that
could deny qualified dividend income treatment to the distributions made by
the Trust to its U.S. unitholders. The bill is in the first step of the
legislative process and it is uncertain whether it will eventually be passed
into law in its current form. If the bill is passed in its current form,
distributions received by U.S. unitholders would no longer qualify for the
15 per cent qualified dividend tax rate.
2007 Review and 2008 Guidance
Following is a summary of the Trust's 2008 Guidance issued by way of news
release on November 7, 2007 (posted on www.sedar.com) and a review of 2007
actual results compared to 2007 Guidance:
<<
-------------------------------------------------------------------------
2007 Actual 2008
Guidance(1) 2007 % Change Guidance
-------------------------------------------------------------------------
Production (boe/d) 63,000 62,723 - 63,000
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 9.50 9.54 - 10.20
Transportation 0.70 0.72 3 0.80
G&A expenses(2) 2.25 2.15 (4) 2.55
Interest 1.70 1.61 (5) 1.90
Capital expenditures
($ millions)(3) 350 397 13 395
Weighted average trust
units and units issuable
(millions) 210 210 - 216
-------------------------------------------------------------------------
(1) 2007 Guidance shown is the revised amounts from the Trust's third
quarter MD&A.
(2) G&A expenses originally split out non-cash expenses with a guidance
estimate of $0.10 per boe compared to actual results of $0.14 per
boe.
(3) 2008 Capital Expenditure Guidance was revised on January 8, 2008. The
additional $40 million is earmarked for the Trust's Montney resource
play.
The 2008 Guidance is issued to provide unitholders with information as to
management's expectations for results of operations for 2008. Readers are
cautioned that the 2008 Guidance may not be appropriate for other purposes.
Actual 2007 results were in line with 2007 guidance with only minor
exceptions as follows:
- Transportation costs were higher than guidance due to additional
trucking costs incurred in the fourth quarter in the Saskatchewan
areas.
- Cash G&A expenses were lower than guidance due to higher operating
recoveries attributed to high levels of capital and operating
activity in the fourth quarter. This was offset by non-cash G&A
expenses that were higher than guidance as a result of an increase in
the Trust's performance multiplier at year-end.
- Interest expense was slightly lower than guidance due to the fact
that the majority of the Trust's debt is denominated in U.S. dollars.
With the strengthening of the Canadian dollar throughout 2007, the
Trust's Canadian equivalent of U.S. dollar interest payments was
reduced.
- Capital expenditures exceeded guidance by $47 million, which
comprised unbudgeted purchases of land in the Dawson area of British
Columbia in the third and fourth quarters of 2007 for $71.3 million
that were offset by cost savings of approximately $20 million on the
Trust's original 2007 capital budget amount.
2008 Operating Income Sensitivity
Below is a table that illustrates sensitivities to pre-hedged operating
income items with operational changes and changes to the business environment:
-------------------------------------------------------------------------
Impact on Annual
Cash flow from
operating
activities(2)
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 85.00 $ 1.00 $ 0.04
Natural gas price (CDN $AECO/mcf)(1) $ 6.50 $ 0.10 $ 0.03
USD/CAD exchange rate ` 1.03 $ 0.01 $ 0.05
Interest rate on debt 5.75% % 1.0 $ 0.02
Operational
Liquids production volume (bbl/d) 32,100 % 1.0 $ 0.03
Gas production volumes (mmcf/d) 185.0 % 1.0 $ 0.02
Operating expenses per boe $ 10.20 % 1.0 $ 0.01
Cash G&A expenses per boe $ 2.55 % 10.0 $ 0.03
-------------------------------------------------------------------------
(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.
>>
Forward-Looking Statements
This discussion and analysis contains forward-looking statements as to
the Trust's internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions and in
particular, includes the material under the heading "2007 Review and 2008
Guidance". These statements represent management's expectations or beliefs
concerning, among other things, future operating results and various
components thereof or the economic performance of ARC Energy Trust ("ARC" or
"the Trust"). The projections, estimates and beliefs contained in such
forward-looking statements are based on management's assumptions relating to
the production performance of ARC's oil and gas assets, the cost and
competition for services throughout the oil and gas industry in 2007, the
continuation of ARC's historical experience with expenses and production,
changes in the capital expenditure budgets relating to undeveloped land or
reserve acquisitions and the continuation of the current regulatory and tax
regime in Canada, and necessarily involve known and unknown risks and
uncertainties, including the business risks discussed in this MD&A and related
to management's assumptions set forth herein, which may cause actual
performance and financial results in future periods to differ materially from
any projections of future performance or results expressed or implied by such
forward-looking statements. Accordingly, readers are cautioned that events or
circumstances could cause actual results to differ materially from those
predicted. Other than the 2008 Guidance that is updated and discussed
quarterly, the Trust does not undertake to update any forward looking
information in this document whether as to new information, future events or
otherwise except as required by securities laws and regulations.
Additional Information
Additional information relating to ARC can be found on SEDAR at
www.sedar.com.
<<
ANNUAL HISTORICAL REVIEW
-------------------------------------------------------------------------
For the year ended
December 31
(CDN $ millions, except
per unit amounts) 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
FINANCIAL
Revenue before
royalties 1,251.6 1,230.5 1,165.2 901.8 743.2
Per unit(1) 5.95 6.02 6.10 4.85 4.80
Cash flow from
operating
activities(2) 704.9 734.0 616.7 446.4 405.3
Per unit - basic(1) 3.35 3.59 3.23 2.40 2.62
Per unit - diluted 3.35 3.58 3.20 2.38 2.54
Net income 495.3 460.1 356.9 241.7 284.6
Per unit - basic(3) 2.39 2.28 1.90 1.32 1.88
Per unit - diluted 2.39 2.27 1.88 1.31 1.82
Distributions 498.0 484.2 376.6 330.0 279.3
Per unit(4) 2.40 2.40 1.99 1.80 1.80
Total assets 3,533.0 3,479.0 3,251.2 2,305.0 2,281.8
Total liabilities 1,491.3 1,550.6 1,415.5 755.7 730.0
Net debt
outstanding(5) 752.7 739.1 578.1 264.8 262.1
Weighted average trust
units (millions)(6) 210.2 204.4 191.2 186.1 154.7
Trust units outstanding
and issuable
at period end
(millions)(6) 213.2 207.2 202.0 188.8 182.8
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 14.9 11.4 9.2 5.4 5.7
Land 77.5 32.4 9.1 4.1 4.0
Drilling and
completions 229.5 240.5 191.8 140.4 106.2
Plant and facilities 72.1 77.6 55.0 41.1 36.5
Other capital 3.2 2.6 3.7 2.8 3.4
Total capital
expenditures 397.2 364.5 268.8 193.8 155.8
Property
acquisitions
(dispositions), net 42.5 115.2 91.3 (58.2) (161.6)
Corporate
acquisitions(7) - 16.6 505.0 72.0 721.6
Total capital
expenditures and
net acquisitions 439.7 496.3 865.1 207.6 715.8
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,682 29,042 23,282 22,961 22,886
Natural gas
(mmcf/d) 180.1 179.1 173.8 178.3 164.2
Natural gas
liquids (bbl/d) 4,027 4,170 4,005 4,191 4,086
Total (boe per
day 6:1) 62,723 63,056 56,254 56,870 54,335
Average prices
Crude oil ($/bbl) 69.24 65.26 61.11 47.03 36.90
Natural gas ($/mcf) 6.75 6.97 8.96 6.78 6.40
Natural gas
liquids ($/bbl) 54.79 52.63 49.92 39.04 32.19
Oil equivalent
($/boe) 54.54 53.33 56.54 43.13 37.29
-------------------------------------------------------------------------
RESERVES
(company interest)(8)
Proved plus probable
reserves
Crude oil and NGL
(mbbl) 158,341 162,193 163,385 123,226 129,663
Natural gas (bcf) 768.2 743.6 741.7 724.5 720.2
Total (mboe) 286,370 286,125 286,997 243,974 249,704
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading)
Unit prices
High 23.86 30.74 27.58 17.98 14.87
Low 18.90 19.20 16.55 13.50 10.89
Close 20.40 22.30 26.49 17.90 14.74
Average daily volume
(thousands) 597 706 656 420 430
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure
reported in prior quarters. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.
(8) Company interest reserves are the gross interest reserves plus the
royalty interest prior to the deduction of royalty burdens.
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(CDN $ millions, except
per unit amounts) 2007
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 338.0 300.2 305.6 307.8
Per unit(1) 1.59 1.42 1.46 1.48
Cash flow from operating
activities(2) 173.7 179.6 179.4 172.3
Per unit - basic(1) 0.82 0.85 0.86 0.83
Per unit - diluted 0.82 0.85 0.86 0.83
Net income 106.3 120.8 184.9 83.3
Per unit - basic(3) 0.51 0.58 0.90 0.41
Per unit - diluted 0.51 0.58 0.89 0.41
Distributions 125.8 125.0 124.1 123.1
Per unit(4) 0.60 0.60 0.60 0.60
Total assets 3,533.0 3,460.8 3,432.8 3,540.1
Total liabilities 1,491.3 1,421.4 1,415.3 1,526.6
Net debt outstanding(5) 752.7 699.8 653.9 729.7
Weighted average trust units(6) 212.5 210.9 209.5 207.9
Trust units outstanding and
issuable(6) 213.2 211.7 210.2 208.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.0 2.9 4.1 4.9
Land 42.6 33.0 1.7 0.2
Drilling and completions 75.2 73.4 25.8 55.1
Plant and facilities 17.9 21.1 16.3 16.8
Other capital 0.6 1.5 0.6 0.5
Total capital expenditures 139.3 131.9 48.5 77.5
Property acquisitions
(dispositions) net 5.0 27.3 10.0 0.2
Corporate acquisitions(7) - - - -
Total capital expenditures
and net acquisitions 144.3 159.2 58.5 77.7
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,682 28,437 28,099 29,520
Natural gas (mmcf/d) 187.4 173.3 176.7 183.0
Natural gas liquids (bbl/d) 4,067 3,795 4,088 4,161
Total (boe per day 6:1) 63,989 61,108 61,637 64,175
Average prices
Crude oil ($/bbl) 77.53 73.40 65.21 60.79
Natural gas ($/mcf) 6.32 5.52 7.38 7.75
Natural gas liquids ($/bbl) 62.75 55.64 52.76 48.04
Oil equivalent ($/boe) 57.26 53.28 54.37 53.18
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 21.55 22.60 23.86 23.02
Low 18.90 19.00 20.78 20.05
Close 20.40 21.17 21.74 21.25
Average daily volume (thousands) 624 503 599 658
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 292.5 312.3 306.7 318.9
Per unit(1) 1.42 1.52 1.51 1.58
Cash flow from operating
activities(2) 159.4 203.4 182.2 189.0
Per unit - basic(1) 0.77 0.99 0.89 0.93
Per unit - diluted 0.77 0.98 0.89 0.93
Net income 56.6 116.9 182.5 104.1
Per unit - basic(3) 0.28 0.58 0.91 0.52
Per unit - diluted 0.28 0.58 0.91 0.52
Distributions 122.3 121.4 120.6 119.9
Per unit(4) 0.60 0.60 0.60 0.60
Total assets 3,479.0 3,335.8 3,277.8 3,279.7
Total liabilities 1,550.6 1,371.3 1,339.9 1,434.1
Net debt outstanding(5) 739.1 579.7 567.4 598.9
Weighted average trust units(6) 206.5 205.1 203.7 202.5
Trust units outstanding and
issuable(6) 207.2 205.7 204.4 203.1
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.7 2.2 2.8 2.7
Land 11.8 1.4 14.3 4.9
Drilling and completions 79.1 76.2 29.8 55.4
Plant and facilities 26.5 24.6 10.9 15.6
Other capital 0.8 0.5 0.8 0.5
Total capital expenditures 121.9 104.9 58.6 79.1
Property acquisitions
(dispositions) net 76.4 8.4 2.8 27.6
Corporate acquisitions(7) 16.6 - - -
Total capital expenditures
and net acquisitions 214.9 113.3 61.4 106.7
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,605 29,108 27,805 29,651
Natural gas (mmcf/d) 179.5 173.4 178.5 185.0
Natural gas liquids (bbl/d) 4,144 4,166 4,247 4,120
Total (boe per day 6:1) 63,663 62,178 61,803 64,600
Average prices
Crude oil ($/bbl) 58.26 71.84 71.86 59.53
Natural gas ($/mcf) 6.99 6.10 6.35 8.40
Natural gas liquids ($/bbl) 46.51 56.60 54.44 52.91
Oil equivalent ($/boe) 49.82 54.45 54.42 54.74
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 29.22 30.74 28.61 27.51
Low 19.20 25.25 24.35 25.09
Close 22.30 27.21 28.00 27.36
Average daily volume (thousands) 1,125 614 548 546
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure
reported in prior reports. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.
CONSOLIDATED BALANCE SHEETS
As at December 31
(CDN$ millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current assets
Cash $ 7.0 $ 2.8
Accounts receivable 162.5 129.8
Prepaid expenses 15.0 18.4
Risk management contracts (Note 11) 13.1 25.7
Future income taxes (Note 13) 4.0 -
-------------------------------------------------------------------------
201.6 176.7
Reclamation funds (Note 5) 26.1 30.9
Risk management contracts (Note 11) 4.7 -
Property, plant and equipment (Note 6) 3,143.0 3,093.8
Long-term investment (Note 7) - 20.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,533.0 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities (Note 8) $ 180.6 $ 162.1
Distributions payable 42.1 40.9
Risk management contracts (Note 11) 57.6 34.4
-------------------------------------------------------------------------
280.3 237.4
Risk management contracts (Note 11) 28.2 -
Long-term debt (Note 9) 714.5 687.1
Accrued long-term incentive compensation (Note 19) 12.1 14.6
Asset retirement obligations (Note 10) 140.0 177.3
Future income taxes (Note 13) 316.2 434.2
-------------------------------------------------------------------------
Total liabilities 1,491.3 1,550.6
-------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 21)
NON-CONTROLLING INTEREST
Exchangeable shares (Note 14) 43.1 40.0
UNITHOLDERS' EQUITY
Unitholders' capital (Note 15) 2,465.7 2,349.2
Contributed surplus (Note 18) 1.7 2.4
Deficit (Note 16) (465.9) (463.2)
Accumulated other comprehensive loss
(Notes 3 and 16) (2.9) -
-------------------------------------------------------------------------
Total unitholders' equity 1,998.6 1,888.4
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,533.0 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
For the three and twelve months ended December 31
Three months ended Twelve months ended
(CDN$ millions, except December 31 December 31
per unit amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
REVENUES
Oil, natural gas, and
natural gas liquids $ 338.0 $ 292.5 $ 1,251.6 $ 1,230.5
Royalties (61.6) (51.5) (219.4) (222.3)
-------------------------------------------------------------------------
276.4 241.0 1,032.2 1,008.2
(Loss) gain on risk
management contracts
(Note 11)
Realized (1.2) 9.8 14.1 29.3
Unrealized (47.9) 3.9 (55.9) (4.6)
-------------------------------------------------------------------------
227.3 254.7 990.4 1,032.9
-------------------------------------------------------------------------
EXPENSES
Transportation 4.0 3.8 16.4 14.5
Operating 56.7 53.5 218.4 195.4
General and administrative 15.0 10.1 49.1 47.1
Interest on long-term debt
(Note 9) 9.2 8.7 36.9 31.8
Depletion, depreciation and
accretion (Notes 6 and 10) 95.0 96.2 371.5 360.0
(Gain) loss on foreign
exchange (Note 12) (3.2) 21.2 (69.4) 4.2
-------------------------------------------------------------------------
176.7 193.5 622.9 653.0
-------------------------------------------------------------------------
Gain on sale of investment
(Note 7) - - 13.3 -
Capital and other taxes - - - (0.3)
Future income tax recovery
(expense) (Note 13) 57.2 (3.7) 121.3 87.1
-------------------------------------------------------------------------
Net income before non-
controlling interest 107.8 57.5 502.1 466.7
Non-controlling interest
(Note 14) (1.5) (0.9) (6.8) (6.6)
-------------------------------------------------------------------------
Net income $ 106.3 $ 56.6 $ 495.3 $ 460.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of period $ (446.4) $ (397.5) $ (463.2) $ (439.1)
Distributions paid or
declared (Note 17) (125.8) (122.3) (498.0) (484.2)
-------------------------------------------------------------------------
Deficit, end of period
(Note 16) $ (465.9) $ (463.2) $ (465.9) $ (463.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per unit (Note 20)
Basic $ 0.51 $ 0.28 $ 2.39 $ 2.28
Diluted $ 0.51 $ 0.27 $ 2.39 $ 2.27
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE LOSS
For the three and twelve months ended December 31
Three months ended Twelve months ended
December 31 December 31
($CDN millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
Net income $ 106.3 $ 56.6 $ 495.3 $ 460.1
Other comprehensive loss,
net of tax
Loss on financial
instruments designated
as cash flow hedges(1) (6.4) - (7.4) -
Gains and losses on
financial instruments
designated as cash flow
hedges in prior periods
realized in net income in
the current period(2) (0.5) - (0.3) -
Net unrealized gains
(losses) on available-
for-sale reclamation funds'
investments(3) 0.1 - (0.1) -
-------------------------------------------------------------------------
Other comprehensive loss (6.8) - (7.8) -
-------------------------------------------------------------------------
Comprehensive income $ 99.5 $ 56.6 $ 487.5 $ 460.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated other comprehensive
income, beginning of period 3.9 - - -
Application of initial adoption - - 4.9 -
Other comprehensive loss (6.8) - (7.8) -
-------------------------------------------------------------------------
Accumulated other comprehensive
loss, end of period (Note 16) $ (2.9) - $ (2.9) -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts are net of tax recovery of $2.4 million and $2.7 million,
respectively, for the three and twelve months ended December 31,
2007.
(2) Amounts are net of tax liability of $0.2 and $0.1 million,
respectively, for the three and twelve months ended December 31,
2007
(3) Nominal future income tax impact.
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and twelve months ended December 31
Three months ended Twelve months ended
December 31 December 31
($CDN millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 106.3 $ 56.6 $ 495.3 $ 460.1
Add items not involving cash:
Non-controlling interest
(Note 14) 1.5 0.9 6.8 6.6
Future income tax (recovery)
expense (Note 13) (57.2) 3.7 (121.3) (87.1)
Depletion, depreciation and
accretion (Notes 6 and 10) 95.0 96.2 371.5 360.0
Non-cash loss (gain) on risk
management contracts (Note 11) 47.9 (3.9) 55.9 4.6
Non-cash (gain) loss on foreign
exchange (Note 12) (3.1) 21.0 (69.6) 4.5
Non-cash trust unit incentive
compensation (Notes 18 and 19) 3.6 (0.1) 3.5 11.9
Gain on sale of investment
(Note 7) - - (13.3) -
Expenditures on site restoration
and reclamation (Note 10) (3.6) (4.0) (18.2) (10.6)
Change in non-cash working
capital (16.7) (11.1) (5.7) (16.0)
-------------------------------------------------------------------------
173.7 159.3 704.9 734.0
-------------------------------------------------------------------------
CASH FLOWS FROM FINANCING
ACTIVITIES
Issuance of long-term debt
under revolving credit
facilities, net 99.1 167.1 104.2 162.7
Repayment of senior
secured notes (5.8) (6.8) (5.8) (6.8)
Issue of trust units 0.8 2.2 3.7 14.4
Trust unit issue costs - (0.2) - (0.2)
Cash distributions paid
(Note 17) (99.1) (95.7) (388.4) (389.6)
Payment of retention bonuses - - (1.0) (1.0)
Change in non-cash
working capital (0.9) (2.7) 0.4 -
-------------------------------------------------------------------------
(5.9) 63.9 (286.9) (220.5)
-------------------------------------------------------------------------
CASH FLOWS FROM INVESTING
ACTIVITIES
Corporate acquisitions, net of
cash received (Note 4) - (16.6) - (16.6)
Acquisition of petroleum and
natural gas properties (5.1) (76.6) (43.7) (117.4)
Proceeds on disposition of
petroleum and natural gas
properties - - 1.2 2.1
Capital expenditures (138.9) (121.8) (396.5) (362.7)
Long-term investment (Note 7) - - 33.3 (20.0)
Net reclamation fund withdrawals
(contributions) (Note 5) 0.2 (1.9) 4.7 (7.4)
Change in non-cash working
capital (17.0) (3.9) (12.8) 11.3
-------------------------------------------------------------------------
(160.8) (220.8) (413.8) (510.7)
-------------------------------------------------------------------------
INCREASE IN CASH 7.0 2.4 4.2 2.8
CASH, BEGINNING OF PERIOD - 0.4 2.8 -
CASH, END OF PERIOD $ 7.0 $ 2.8 $ 7.0 $ 2.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007 and 2006
(all tabular amounts in CDN$ millions, except per unit and volume
amounts)
1. STRUCTURE OF THE TRUST
ARC Energy Trust (the "Trust") was formed on May 7, 1996 pursuant to
a Trust indenture (the "Trust Indenture") that has been amended from
time to time, most recently on May 15, 2006. Computershare Trust
Company of Canada was appointed as Trustee under the Trust Indenture.
The beneficiaries of the Trust are the holders of the Trust units.
The Trust was created for the purposes of issuing Trust units to the
public and investing the funds so raised to purchase a royalty in the
properties of ARC Resources Ltd. ("ARC Resources") and ARC Oil & Gas
Fund ("ARC Oil & Gas"). The Trust Indenture was amended on June 7,
1999 to convert the Trust from a closed-end to an open-ended
investment Trust. The current business of the Trust includes the
investment in all types of energy business-related assets including,
but not limited to, petroleum and natural gas-related assets,
gathering, processing and transportation assets. The operations of
the Trust consist of the acquisition, development, exploitation and
disposition of these assets and the distribution of the net cash
proceeds from these activities to the unitholders.
2. SUMMARY OF ACCOUNTING POLICIES
The consolidated financial statements have been prepared by
management following Canadian generally accepted accounting
principles ("GAAP"). The preparation of financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingencies
at the date of the financial statements, and revenues and expenses
during the reporting year. Actual results could differ from those
estimated.
In particular, the amounts recorded for depletion, depreciation and
accretion of the petroleum and natural gas properties and for asset
retirement obligations are based on estimates of reserves and future
costs. By their nature, these estimates, and those related to future
cash flows used to assess impairment, are subject to measurement
uncertainty and the impact on the financial statements of future
periods could be material.
Principles of Consolidation
The consolidated financial statements include the accounts of the
Trust and its subsidiaries. Any reference to "the Trust" throughout
these consolidated financial statements refers to the Trust and its
subsidiaries. All inter-entity transactions have been eliminated.
Revenue Recognition
Revenue associated with the sale of crude oil, natural gas, and
natural gas liquids (NGLs) owned by the Trust are recognized when
title passes from the Trust to its customers.
Transportation
Costs paid by the Trust for the transportation of natural gas, crude
oil and NGLs from the wellhead to the point of title transfer are
recognized when the transportation is provided.
Joint Venture
The Trust conducts many of its oil and gas production activities
through joint ventures and the financial statements reflect only the
Trust's proportionate interest in such activities.
Depletion and Depreciation
Depletion of petroleum and natural gas properties and depreciation of
production equipment are calculated on the unit-of-production basis
based on:
(a) total estimated proved reserves calculated in accordance
with National Instrument 51-101, Standards of Disclosure for
Oil and Gas Activities;
(b) total capitalized costs, excluding undeveloped lands, plus
estimated future development costs of proved undeveloped
reserves, including future estimated asset retirement costs;
and
(c) relative volumes of petroleum and natural gas reserves and
production, before royalties, converted at the energy
equivalent conversion ratio of six thousand cubic feet of
natural gas to one barrel of oil.
Unit Based Compensation
The Trust established a Trust Unit Incentive Rights Plan (the "Rights
Plan") for employees, independent directors and long-term consultants
who otherwise meet the definition of an employee of the Trust. The
exercise price of the rights granted under the Plan may be reduced in
future periods in accordance with the terms of the Plan. The Trust
accounts for the rights using the fair value method, whereby the fair
value of rights is determined on the date on which fair value can
initially be determined. The fair value is then recorded as
compensation expense over the period that the rights vest, with a
corresponding increase to contributed surplus. When rights are
exercised, the proceeds, together with the amount recorded in
contributed surplus, are recorded to unitholders' capital.
Whole Trust Unit Incentive Plan Compensation
The Trust has established a Whole Trust Unit Incentive Plan (the
"Whole Unit Plan") for employees, independent directors and long-term
consultants who otherwise meet the definition of an employee of the
Trust. Compensation expense associated with the Whole Unit Plan is
granted in the form of Restricted Trust Units ("RTUs") and
Performance Trust Units ("PTUs") and is determined based on the
intrinsic value of the Whole Trust Units at each period end. The
intrinsic valuation method is used as participants of the Whole Unit
Plan receive a cash payment on a fixed vesting date. This valuation
incorporates the period end Trust unit price, the number of RTUs and
PTUs outstanding at each period end, and certain management
estimates. As a result, large fluctuations, even recoveries, in
compensation expense may occur due to changes in the underlying Trust
unit price. In addition, compensation expense is amortized and
recognized in earnings over the vesting period of the Whole Unit Plan
with a corresponding increase or decrease in liabilities.
Classification between accrued liabilities and other long-term
liabilities is dependent on the expected payout date.
The Trust charges amounts relating to head office employees to
general and administrative expense, amounts relating to field
employees to operating expense and amounts relating to geologists and
geophysicists to property, plant and equipment.
The Trust has not incorporated an estimated forfeiture rate for RTUs
and PTUs that will not vest. Rather, the Trust accounts for actual
forfeitures as they occur.
Cash Equivalents
Cash equivalents include short-term investments, such as money market
deposits or similar type instruments, with an original maturity of
three months or less when purchased.
Reclamation Funds
Reclamation funds hold investment grade assets and cash and cash
equivalents. In accordance with Section 3855, investments are
categorized as either held-to-maturity or available-for-sale assets,
which are initially measured at fair value. Held-to-maturity
investments are subsequently measured at amortized cost using the
effective interest method. Available-for-sale investments are
subsequently measured at fair value with changes in fair value
recognized in other comprehensive income, net of tax. Section 3855
became effective January 1, 2007 as described in Note 3.
Investments carried at amortized cost are subject to impairment
losses in the event of a non-temporary decline in market value.
Property, Plant and Equipment ("PP&E")
The Trust follows the full cost method of accounting. All costs of
exploring, developing and acquiring petroleum and natural gas
properties, including asset retirement costs, are capitalized and
accumulated in one cost centre as all operations are in Canada.
Maintenance and repairs are charged against income, and renewals and
enhancements that extend the economic life of the PP&E are
capitalized. Gains and losses are not recognized upon disposition of
petroleum and natural gas properties unless such a disposition would
alter the rate of depletion by 20 per cent or more.
Impairment
The Trust places a limit on the aggregate carrying value of PP&E,
which may be amortized against revenues of future periods.
Impairment is recognized if the carrying amount of the PP&E exceeds
the sum of the undiscounted cash flows expected to result from the
Trust's proved reserves. Cash flows are calculated based on third
party quoted forward prices, adjusted for the Trust's contract prices
and quality differentials.
Upon recognition of impairment, the Trust would then measure the
amount of impairment by comparing the carrying amounts of the PP&E to
an amount equal to the estimated net present value of future cash
flows from proved plus risked probable reserves. The Trust's risk-
free interest rate is used to arrive at the net present value of the
future cash flows. Any excess carrying value above the net present
value of the Trust's future cash flows would be recorded as a
permanent impairment and charged against net income.
The cost of unproved properties is excluded from the impairment test
described above and subject to a separate impairment test. In the
case of impairment, the book value of the impaired properties is
moved to the petroleum and natural gas depletable base.
Goodwill
The Trust must record goodwill relating to a corporate acquisition
when the total purchase price exceeds the fair value for accounting
purposes of the net identifiable assets and liabilities of the
acquired company. The goodwill balance is assessed for impairment
annually at year-end or as events occur that could result in an
impairment. Impairment is recognized based on the fair value of the
reporting entity (consolidated Trust) compared to the book value of
the reporting entity. If the fair value of the consolidated Trust is
less than the book value, impairment is measured by allocating the
fair value of the consolidated Trust to the identifiable assets and
liabilities as if the Trust had been acquired in a business
combination for a purchase price equal to its fair value. The excess
of the fair value of the consolidated trust over the amounts assigned
to the identifiable assets and liabilities is the fair value of the
goodwill. Any excess of the book value of goodwill over this implied
fair value of goodwill is the impairment amount. Impairment is
charged to earnings in the period in which it occurs.
Goodwill is stated at cost less impairment and is not amortized.
Asset Retirement Obligations
The Trust recognizes an Asset Retirement Obligation ("ARO") in the
period in which it is incurred when a reasonable estimate of the fair
value can be made. On a periodic basis, management will review these
estimates and changes, if any, to the estimate will be applied on a
prospective basis. The fair value of the estimated ARO is recorded as
a long-term liability, with a corresponding increase in the carrying
amount of the related asset. The capitalized amount is depleted on a
unit-of-production basis over the life of the reserves. The liability
amount is increased each reporting period due to the passage of time
and the amount of accretion is charged to earnings in the period.
Revisions to the estimated timing of cash flows or to the original
estimated undiscounted cost would also result in an increase or
decrease to the ARO. Actual costs incurred upon settlement of the ARO
are charged against the ARO to the extent of the liability recorded.
Income Taxes
The Trust follows the liability method of accounting for income
taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial statements
of the Trust and the Trust's corporate subsidiaries and their
respective tax base, using substantively enacted future income tax
rates. The effect of a change in income tax rates on future tax
liabilities and assets is recognized in income in the period in which
the change occurs. Temporary differences arising on acquisitions
result in future income tax assets and liabilities.
Basic and Diluted per Trust Unit Calculations
Basic net income per unit is computed by dividing the net income by
the weighted average number of trust units outstanding during the
period. Diluted net income per unit amounts are calculated based on
net income before non-controlling interest divided by dilutive trust
units. Dilutive trust units are arrived at by taking weighted average
trust units and trust units issuable on conversion of exchangeable
shares, and giving effect to the potential dilution that would occur
if rights were exercised at the beginning of the period. The treasury
stock method assumes that proceeds received from the exercise of in-
the-money rights and the unrecognized trust unit incentive
compensation are used to repurchase units at the average market
price.
Derivative Financial Instruments
The Trust is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the
normal course of operations. A variety of derivative instruments are
used by the Trust to reduce its exposure to fluctuations in commodity
prices, foreign exchange rates, and interest rates. The fair values
of these derivative instruments are based on an estimate of the
amounts that would have been received or paid to settle these
instruments prior to maturity. The Trust considers all of these
transactions to be effective economic hedges, however, the majority
of the Trust's contracts do not qualify or have not been designated
as effective hedges for accounting purposes.
For transactions that do not qualify for hedge accounting, the Trust
applies the fair value method of accounting by recording an asset or
liability on the Consolidated Balance Sheet and recognizing changes
in the fair value of the instruments in the statement of income for
the current period.
For derivative instruments that do qualify as effective accounting
hedges, policies and procedures are in place to ensure that the
required documentation and approvals are in place. This documentation
specifically ties the derivative financial instruments to their use,
and in the case of commodities, to the mitigation of market price
risk associated with cash flows expected to be generated. When
applicable, the Trust also identifies all relationships between
hedging instruments and hedged items, as well as its risk management
objective and the strategy for undertaking hedge transactions. This
would include linking the particular derivative to specific assets
and liabilities on the Consolidated Balance Sheet or to specific firm
commitments or forecasted transactions. Where specific hedges are
executed, the Trust assesses, both at the inception of the hedge and
on an ongoing basis, whether the derivative used in the particular
hedging transaction is effective in offsetting changes in fair value
or cash flows of the hedged item. For accounting treatment of gains
on losses on derivative instruments that qualify as effective
accounting hedges refer to Note 3 - Hedges.
Foreign Currency Translation
Monetary assets and liabilities denominated in a foreign currency are
translated at the rate of exchange in effect at the Consolidated
Balance Sheet date. Revenues and expenses are translated at the
period average rates of exchange. Translation gains and losses are
included in income in the period in which they arise.
Non-Controlling Interest
The Trust must record non-controlling interest when exchangeable
shares issued by a subsidiary of the Trust are transferable to third
parties. Non-controlling interest on the Consolidated Balance Sheet
is recognized based on the fair value of the exchangeable shares upon
issuance plus the accumulated earnings attributable to the non-
controlling interest. Net income is reduced for the portion of
earnings attributable to the non-controlling interest. As the
exchangeable shares are converted to trust units, the non-controlling
interest on the Consolidated Balance Sheet is reduced by the
cumulative book value of the exchangeable shares and Unitholders'
capital is increased by the corresponding amount.
3. NEW ACCOUNTING POLICIES
Effective January 1, 2007, the Trust adopted six new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook Section 1530, Comprehensive Income,
Section 3855, Financial Instruments - Recognition and Measurement,
Section 3861, Financial Instruments - Disclosure and Presentation,
Section 3865, Hedges, Section 3251, Equity and Section 1506,
Accounting Changes. These new accounting standards have been adopted
prospectively and, accordingly, comparative amounts for prior periods
have not been restated. The standards provide requirements for the
recognition, measurement and disclosure of financial instruments, the
use of hedge accounting and the presentation of equity.
Comprehensive Income
Section 1530 introduces Comprehensive Income, which consists of Net
Income and Other Comprehensive Income (Loss) ("OCI"). Comprehensive
Income includes changes in Unitholders' Equity from transactions and
other events with non-owner sources, and OCI includes unrealized
gains and losses on financial assets classified as available-for-sale
and changes in the fair value of the effective portion of cash flow
hedging instruments that qualify for hedge accounting. These items
are excluded from Net Income calculated in accordance with GAAP. The
Consolidated Statements of Comprehensive Income includes Accumulated
Other Comprehensive Income (Loss) ("AOCI"), and the changes in these
items during the three and twelve month periods ended December 31,
2007. Cumulative changes in OCI are included in AOCI, which is
presented as a new category within Unitholders' Equity on the
Consolidated Balance Sheet.
Financial Instruments - Recognition and Measurement
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial
derivatives. Under this standard, all financial instruments are
required to be measured at fair value on initial recognition.
Measurement in subsequent periods depends on whether the financial
instrument has been classified as held-for-trading, available-for-
sale, held-to-maturity, loans and receivables, or other financial
liabilities.
a. Held-for-trading
Financial assets and liabilities designated as held-for-trading
are subsequently measured at fair value with changes in those fair
values recognized immediately in Net Income. With the exception of
risk management contracts that qualify for hedge accounting, the
Trust classifies all risk management contracts as held-for-
trading. Cash is also classified as held-for-trading.
b. Available-for-sale assets
Available-for-sale financial assets are subsequently measured at
fair value with changes in fair value recognized in OCI, net of
tax. Amounts recognized in OCI for available-for-sale financial
assets are transferred to net income when the asset is
derecognized or when there is an other than temporary asset
impairment. A portion of the Trust's reclamation fund is
classified as available-for-sale financial assets.
c. Held-to-maturity investments, loans and receivables and other
financial liabilities
Held-to-maturity investments, loans and receivables, and other
financial liabilities are subsequently measured at amortized cost
using the effective interest method. The Trust classifies a
portion of its reclamation fund investments to held-to-maturity,
accounts receivables to loans and receivables, and accounts
payable, distributions payable and long-term debt to other
financial liabilities.
The Section allows an entity to designate any financial instrument
as held-for-trading, which by characteristic and intended use may
be classified under another category. The Trust has chosen not to
make any such designations.
Transaction costs are expensed as incurred for financial instruments
excluding long-term debt. The Trust has elected to capitalize costs
incurred relating to debt issuances and to amortize these costs over
the term of the associated debt using the effective interest rate
method.
The Trust has elected January 1, 2003 as the effective date to
identify and measure embedded derivatives in financial and non-
financial contracts that are not closely related to the host
contracts. No adjustments were required for embedded derivatives on
adoption of this standard.
Financial Instruments - Disclosure and Presentation
Section 3861 establishes standards for enhancing financial statement
users' understanding of the significance of financial instruments to
an entity's financial position, performance and cash flows. It
establishes standards for presentation of financial instruments and
non-financial derivatives, and identifies the information that should
be disclosed about them. This section sets forth standards on the
presentation and classification of financial instruments between
liabilities and equity, the classification of related interest,
dividends, losses and gains, and the circumstances in which financial
assets and liabilities are offset. The standard outlines required
disclosures surrounding factors that affect the amount, timing and
certainty of an entity's future cash flows relating to financial
instruments. Disclosure of information about the nature and extent of
an entity's use of financial instruments, the business purposes they
serve, the risks associated with them and management's policies for
controlling those risks are also required.
Hedges
Section 3865 specifies the criteria that must be satisfied in order
for hedge accounting to be applied and the accounting for fair value
and cash flow hedges. Hedge accounting is discontinued prospectively
when the derivative no longer qualifies as an effective hedge, or the
derivative is terminated or sold, or upon the sale or early
termination of the hedged item. The Trust has currently designated
its financial electricity contracts and treasury rate lock contracts
as effective cash flow hedges. The Trust assesses, both at the
inception of the hedge and on an ongoing basis, whether the
derivative used in the particular hedging transaction is effective in
offsetting changes in cash flows of the hedged item.
In a cash flow hedging relationship, the effective portion of the
change in the fair value of the hedging derivative is recognized in
OCI while the ineffective portion is recognized in Net Income. When
hedge accounting is discontinued, the amounts previously recognized
in AOCI are reclassified to Net Income during the periods when the
variability in the cash flows of the hedged item affects Net Income.
Gains and losses on derivatives are reclassified immediately to Net
Income when the hedged item is sold or early terminated.
When hedge accounting is applied to a derivative used to hedge an
anticipated transaction and it is determined that the anticipated
transaction will not occur within the originally specified time
period, hedge accounting is discontinued and the unrealized gains and
losses are reclassified from AOCI to Net Income.
Equity
Section 3251 establishes standards for the presentation of equity and
changes in equity during the reporting period. This section specifies
that changes in equity for the period arising from Net Income, OCI,
other changes in deficit, changes in contributed surplus, and changes
in unitholders' capital must be presented separately.
Impact
As a result of these changes in accounting policies, on January 1,
2007 the Trust recorded $4.9 million to application of initial
adoption in AOCI to reflect the opening fair value of its cash flow
hedges, net of tax, which was previously not recorded on the
consolidated financial statements. The Trust has also recorded an
increase of $7 million to its risk management asset and an increase
of $2.1 million to its future income tax liability.
Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if
they result in financial statements that provide more reliable and
relevant information. Changes in policy are applied retrospectively
unless it is impractical to determine the period or cumulative impact
of the change. Corrections of prior period errors are applied
retrospectively and changes in accounting estimates are applied
prospectively by including these changes in Net Income. In addition,
disclosure is required for all future accounting changes when an
entity has not applied a new source of GAAP that has been issued but
is not yet effective.
Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards:
Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures, and Section 3863, Financial Instruments -
Presentation. These new standards will be effective on January 1,
2008.
Section 1535 specifies the disclosure of an entity's objectives,
policies and processes for managing capital, quantitative data about
what the entity regards as capital, whether the entity has complied
with any capital requirements, and if it has not complied, the
consequences of such non- compliance. This Section is expected to
have minimal impact on the Trust's financial statements.
Sections 3862 and 3863 specify standards of presentation and enhanced
disclosures on financial instruments. These Sections will require the
Trust to increase disclosure on the nature and extent of risks
arising from financial instruments and how the entity manages those
risks.
In February 2008, the CICA issued Section 3064, Goodwill and
Intangible Assets, replacing Section 3062, Goodwill and Other
Intangible Assets and Section 3450, Research and Development Costs.
The new Section will be effective on January 1, 2009. Section 3064
establishes standards for the recognition, measurement, presentation
and disclosure of goodwill and intangible assets subsequent to its
initial recognition. Standards concerning goodwill are unchanged from
the standards included in the previous Section 3062. The Trust is
currently evaluating the impact of the adoption of this new Section,
however does not expect a material impact on its consolidated
financial statements.
4. CORPORATE ACQUISITIONS
On December 6, 2006 the Trust completed a minor corporate acquisition
for net cash consideration of $16.6 million. There was no goodwill
recognized with this acquisition. Substantially all of the
consideration was applied against property, plant and equipment, with
a nominal amount applied against working capital items.
5. RECLAMATION FUNDS
December 31, 2007 December 31, 2006
-------------------------------------------------------------------------
Unrestricted Restricted Unrestricted Restricted
-------------------------------------------------------------------------
Balance, beginning
of period $ 24.8 $ 6.1 $ 23.5 $ -
Contributions 6.2 5.9 6.0 6.1
Reimbursed expendi-
tures(1) (17.5) (0.6) (5.7) -
Interest earned on
funds 1.1 0.3 1.0 -
Net unrealized losses
on available-for-sale
investments (0.2) - - -
-------------------------------------------------------------------------
Balance, end of
period(2) $ 14.4 $ 11.7 $ 24.8 $ 6.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.
(2) As at December 31, 2007 the unrestricted reclamation fund held
$1.5 million in cash and cash equivalents ($15 million at
December 31, 2006), with the balance held in investment grade
assets.
An unrestricted reclamation fund was established to fund future asset
retirement obligation costs. In addition, the Trust has created a
restricted reclamation fund associated with the Redwater property
acquired in 2005. Contributions to the restricted and unrestricted
reclamation funds and interest earned on the balances have been
deducted from the cash distributions to the unitholders. The Board of
Directors of ARC Resources has approved voluntary contributions to
the unrestricted reclamation fund over a 20-year period that
currently results in minimum annual contributions of $6 million
($6 million in 2006) based upon properties owned as at December 31,
2007. Contributions to the restricted reclamation fund will vary over
time and have been disclosed in Note 21. Contributions for both funds
are continually reassessed to ensure that the funds are sufficient to
finance the majority of future abandonment obligations. Interest
earned on the funds is retained within the funds.
For the 12 months ended December 31, 2007 no amounts relating to
available-for-sale reclamation fund assets were classified from
accumulated other comprehensive loss into the statement of income.
6. PROPERTY, PLANT AND EQUIPMENT
2007 2006
---------------------------------------------------------------------
Property, plant and equipment, at cost $ 5,065.0 $ 4,655.3
Accumulated depletion and depreciation (1,922.0) (1,561.5)
---------------------------------------------------------------------
Property, plant and equipment, net $ 3,143.0 $ 3,093.8
---------------------------------------------------------------------
---------------------------------------------------------------------
The calculation of 2007 depletion and depreciation included an
estimated $549 million ($547 million in 2006) for future development
costs associated with proved undeveloped reserves and excluded
$173.7 million ($108.9 million in 2006) for the book value of
unproved properties.
The Trust performed a ceiling test calculation at December 31, 2007
to assess the recoverable value of property plant and equipment
(PP&E). Based on the calculation, the value of future net revenues
from the Trust's reserves exceeded the carrying value of the Trust's
PP&E at December 31, 2007. The benchmark prices used in the
calculation were as follows:
WTI Oil AECO Gas USD/CAD
Year ($US/bbl) (CDN$/mmbtu) Exchange Rates
---------------------------------------------------------------------
2008 92.00 6.75 1.00
2009 88.00 7.55 1.00
2010 84.00 7.60 1.00
2011 82.00 7.60 1.00
2012 82.00 7.60 1.00
2013 82.00 7.60 1.00
2014 82.00 7.80 1.00
2015 82.00 7.97 1.00
2016 82.02 8.14 1.00
2017 83.66 8.31 1.00
2018 85.33 8.48 1.00
---------------------------------------------------------------------
Remainder(1) 2.0% 2.0% 1.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Percentage change represents the change in each year after 2018
to the end of the reserve life.
7. LONG-TERM INVESTMENT
During the year the Trust sold its equity investment in a private oil
sands company for proceeds of $33.3 million, resulting in a gain on
sale of investment of $13.3 million. The original investment was
purchased in 2006 for $20 million. The investment in the shares of
the private company was considered to be a related party transaction
due to common directorships of the Trust, the private company and the
manager of a private equity fund that held shares in the private
company. In addition, certain directors and officers of the Trust had
minor direct and indirect shareholdings in the private company.
8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
2007 2006
---------------------------------------------------------------------
Trade accounts payable $ 32.5 $ 39.0
Accrued liabilities 127.7 108.8
Current portion of accrued long-term
incentive compensation 18.2 11.5
Interest payable 2.2 1.8
Retention bonuses - 1.0
---------------------------------------------------------------------
Total accounts payable and accrued liabilities $ 180.6 $ 162.1
---------------------------------------------------------------------
---------------------------------------------------------------------
The current portion of accrued long-term incentive compensation
represents the current portion of the Trust's estimated liability for
the Whole Unit Plan as at December 31, 2007 (see Note 19). This
amount is payable in 2008.
9. LONG-TERM DEBT
2007 2006
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility - CDN denominated $ 344.9 $ 196.6
Syndicated credit facility - US denominated 154.1 228.4
Working capital facility - 1.1
Senior secured notes
5.42% USD Note 74.1 87.4
4.94% USD Note 17.8 28.0
4.62% USD Note 61.8 72.8
5.10% USD Note 61.8 72.8
---------------------------------------------------------------------
Total long-term debt outstanding $ 714.5 $ 687.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Revolving Credit Facilities
During 2007, the Trust renewed its $800 million secured, annually
extendible, financial covenant-based three year syndicated credit
facility. The revolving credit facility's security is in the form of
a floating charge on all lands and assignments and a negative pledge
on petroleum and natural gas properties. The Trust also has in place
a $25 million demand working capital facility.
Borrowings under the credit facility bear interest at bank prime (six
per cent at December 31, 2007 and December 31, 2006) or, at the
Trust's option, Canadian dollar bankers' acceptances or U.S. dollar
LIBOR loans, plus a stamping fee. At the option of the Trust, the
lenders will review the credit facility each year and determine
whether they will extend the revolving period for another year. In
the event that the credit facility is not extended at anytime before
the maturity date, the loan balance will become repayable on the
maturity date. The maturity date of the current credit facility is
April 15, 2010. All drawings under the facility are subject to
stamping fees that vary between 60 bps and 110 bps depending on
certain consolidated financial ratios.
The working capital facility allows for maximum borrowings of $25
million and is due and payable immediately upon demand by the bank.
The facility is secured and is subject to the same covenants as the
syndicated credit facility.
5.42 Per Cent and 4.94 Per Cent Senior Secured USD Notes
These senior secured notes were issued in two separate issues
pursuant to an Uncommitted Master Shelf Agreement. The US$18 million
senior secured notes were issued in 2002, bear interest at 4.94 per
cent, have a remaining final term of 2.8 years (remaining average
term of 1.8 years) and require equal principal repayments of
US$6 million over a three year period commencing in 2008. The
US$75 million senior secured notes were issued in 2005, bear interest
at 5.42 per cent, have a remaining final term of 10 years (remaining
weighted average term of 6.6 years) and require equal principal
repayments over an eight year period commencing in 2010.
4.62 Per Cent and 5.10 Per Cent Senior Secured USD Notes
These notes were issued on April 27, 2004 via a private placement in
two tranches of US$62.5 million each. The first tranche of
US$62.5 million bears interest at 4.62 per cent and has a remaining
final term of 6.3 years (remaining weighted average term of 3.9
years) and require equal principal repayments over a six year period
commencing 2009. Immediately following the issuance, the Trust
entered into interest rate swap contracts that effectively changed
the interest rate from fixed to floating (see Note 11). The second
tranche of US$62.5 million bears interest at 5.10 per cent and has a
remaining final term of 8.3 years (remaining weighted average term of
6.4 years). Repayments of the notes will occur over a five year
period commencing in 2012.
Debt Covenants
The following are the significant financial covenants governing the
revolving credit facilities:
- Long-term debt and letters of credit not to exceed three
times 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 unitholders' equity and long-term debt, letters of
credit, and subordinated debt.
In the event that the Trust enters into a material acquisition
whereby the purchase price exceeds 10 per cent of the book value of
the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times respectively, while the third covenant
is increased to 55 per cent for the subsequent six month period. As
at December 31, 2007, the Trust had $4.8 million in letters of credit
($4.7 million in 2006), no subordinated debt, and was in compliance
with all covenants.
The payment of principal and interest are allowable deductions in the
calculation of cash available for distribution to unitholders and
rank ahead of cash distributions payable to unitholders. Should the
properties securing this debt generate insufficient revenue to repay
the outstanding balances, the unitholders have no direct liability.
During 2007, the weighted-average effective interest rate under the
credit facility was 5.5 per cent (5.3 per cent in 2006).
Amounts due under the working capital facility and the senior secured
notes in the next 12 months have not been included in current
liabilities as management has the ability and intent to refinance
this amount through the syndicated credit facility.
Interest paid during 2007 was $1.8 million less than interest
expense. The difference between interest paid and interest expense in
2006 was nominal.
10. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligations were estimated by
management based on the Trust's net ownership interest in all wells
and facilities, estimated costs to reclaim and abandon the wells and
facilities and the estimated timing of the costs to be incurred in
future periods. The Trust has estimated the net present value of its
total asset retirement obligations to be $140 million as at
December 31, 2007 ($177.3 million in 2006) based on a total future
undiscounted liability of $1.29 billion ($1.04 billion in 2006). At
December 31, 2007 management estimates that these payments are
expected to be made over the next 51 years with the bulk of payments
being made in years 2048 to 2058. At December 31, 2006 management had
estimated that the expenditures would be made over 61 years with the
bulk of payments being made in years 2017 to 2021 and 2057 to 2067.
The Trust's weighted average credit adjusted risk free rate of 6.6
per cent (6.5 per cent in 2006) and an inflation rate of 2.0 per cent
(2.0 per cent in 2006) were used to calculate the present value of
the asset retirement obligations. During the year, no gains or losses
were recognized on settlements of asset retirement obligations.
The following table reconciles the Trust's asset retirement
obligations:
2007 2006
---------------------------------------------------------------------
Balance, beginning of year $ 177.3 $ 165.1
Increase in liabilities relating to corporate
acquisitions - 4.9
Increase in liabilities relating to
development activities 3.8 2.8
(Decrease) increase in liabilities relating to
change in estimate (34.4) 4.0
Settlement of liabilities during the year (18.2) (10.6)
Accretion expense 11.5 11.1
---------------------------------------------------------------------
Balance, end of year $ 140.0 $ 177.3
---------------------------------------------------------------------
---------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS
The Trust is exposed to a number of financial risks that are part of
its normal course of business. The Trust has a risk management
program in place that includes financial instruments as disclosed in
this note. ARC's risk management program is overseen by an
experienced risk management committee based on guidelines approved by
the board of directors. The objective of the risk management program
is to mitigate the Trust's exposure to the following financial risks:
Commodity Price Risks
The Trust's operational results and financial condition, and
therefore the amount of distributions paid to unitholders, are
dependent on the commodity prices received for oil and natural gas
production and the price paid for electricity. Commodity prices have
fluctuated widely during recent years and are determined by weather,
economic and, in the case of oil prices, geopolitical factors. Any
movement in commodity prices could have an effect on the Trust's
financial condition and therefore on the distributions to
unitholders. ARC manages the risks associated with changes in
commodity prices by entering into risk management contracts.
Variations in Interest Rates
The Trust has both fixed and variable interest debt. Changes in
interest rates could result in a significant increase or decrease in
the amount the Trust pays to service variable interest debt,
potentially impacting distributions to unitholders. Changes in
interest rates could also result in fair value risk on the Trust's
senior secured notes. This risk is mitigated due to the fact that the
Trust does not intend to settle its fixed rate debt prior to
maturity. ARC manages the risk associated with changes in interest
rates by entering into financial swaps in order to lock in favorable
fixed or floating rates.
Variations in Foreign Exchange Rates
World commodity prices are quoted in U.S. dollars, therefore the
price received by Canadian producers is affected by the Canadian/U.S.
dollar exchange rate that may fluctuate over time. Variations in the
exchange rate of the Canadian dollar could have significant positive
or negative impact on distributions to unitholders. ARC has initiated
certain risk management contracts to mitigate these risks.
Credit Risk
The Trust is exposed to credit risk with respect to its accounts
receivable and risk management contracts. Most of the Trust's
accounts receivable relate to oil and natural gas sales and are
exposed to typical industry credit risks. The Trust manages this
credit risk by entering into sales contracts with only established
entities and reviewing its exposure to individual entities on a
regular basis. The Trust minimizes credit risk on risk management
contracts by entering into agreements with counterparties that are of
investment grade.
The Trust has a legal right to offset asset and liability positions
with some of its counterparties. In situations where there is a legal
right to offset, balances are still shown gross on the Consolidated
Balance Sheet as it is not the Trust's intention to net settle. Only
in situations of credit default would these asset and liability
positions be shown net on the Consolidated Balance Sheet.
Maximum credit risk is calculated as the total positive value of
accounts receivable and risk management contracts at the balance
sheet date less any liability amounts where there is a legal right to
offset, to the extent that there are positive value accounts
receivable or risk management contracts with the same counterparty.
The following table details the Trust's maximum credit risk as at
December 31:
2007 2006
---------------------------------------------------------------------
Trade Accounts Receivable $ 159.5 $ 129.8
Risk Management Contracts 6.8 21.9
---------------------------------------------------------------------
Maximum Credit Exposure $ 166.3 $ 151.7
---------------------------------------------------------------------
---------------------------------------------------------------------
While the Trust is exposed to the above credit losses due to the
potential non-performance of its counterparties, the Trust considers
the risk of this remote.
Financial Instruments
Financial Instruments of the Trust carried on the Consolidated
Balance Sheet are carried at cost with the exception of reclamation
fund assets classified as available-for-sale and risk management
contracts, which are carried at fair value. Except for those items
noted in the table below there were no significant differences
between the carrying value of financial instruments and their
estimated fair values, at December 31:
Carrying Value Fair Value
2007 2006 2007 2006
---------------------------------------------------------------------
Reclamation Fund Assets
classified as available-
for-sale(1) $ 8.1 $ 5.2 $ 8.1 $ 5.2
Reclamation Fund Assets
classified as held-to-
maturity(1) 18.0 25.7 17.8 27.7
Senior secured notes(2) 215.5 261.0 226.1 257.0
---------------------------------------------------------------------
(1) Fair value obtained from third parties, determined directly by
reference to quoted market prices.
(2) Fair Value calculated as the present value of future principal
and interest payments discounted at the Trust's credit adjusted
risk free rate.
Risk Management Contracts
The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices, foreign exchange,
interest rates and power. The Trust considers all of these
transactions to be effective economic hedges, however, the majority
of the Trust's contracts do not qualify as effective hedges for
accounting purposes.
Following is a summary of all risk management contracts in place as
at December 31, 2007 that do not qualify for hedge accounting:
Financial WTI Crude Oil Contracts
Bought Sold Sold Bought
Volume Put Put Call Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
Jan 08 - Mar 08 Collar 2,000 92.50 - 110.00 -
Jan 08 - Mar 08 Collar 2,000 92.50 - 105.00 -
Jan 08 - Mar 08 Covered Collar 2,000 90.00 - 105.00 120.00
Jan 08 - Mar 08 Bought Put 500 84.00 - - -
Jan 08 - Mar 08 3 - Way Collar 1,000 84.00 69.00 105.00 -
Jan 08 - Mar 08 Put Spread 500 83.00 68.00 - -
Jan 08 - Mar 08 3 - Way Collar 1,000 79.00 66.00 105.00 -
Jan 08 - Jun 08 3 - Way Collar 1,000 65.00 52.50 82.50 -
Jan 08 - Jun 08 3 - Way Collar 1,000 65.00 52.50 85.00 -
Jan 08 - Jun 08 Collar 1,000 65.00 - 85.00 -
Jan 08 - Dec 08 3 - Way Collar 1,000 70.00 55.00 90.00 -
Jan 08 - Dec 08 3 - Way Collar 1,000 67.50 52.50 85.00 -
Jan 08 - Dec 08 Collar 1,000 67.50 - 85.00 -
Jan 08 - Dec 08 3 - Way Collar 2,000 61.50 50.00 85.00 -
Jan 08 - Dec 08 3 - Way Collar 1,000 61.30 50.00 85.00 -
Jan 08 - Dec 08 3 - Way Collar 2,000 61.00 50.00 85.00 -
Apr 08 - Jun 08 Collar 2,000 90.00 - 110.00 -
Apr 08 - Jun 08 Put Spread 500 85.00 70.00 - -
Apr 08 - Jun 08 Put Spread 500 85.00 69.00 - -
Apr 08 - Jun 08 Put Spread 500 84.00 68.00 - -
Apr 08 - Jun 08 Put Spread 1,000 79.00 66.00 - -
Jul 08 - Dec 08 Collar 2,000 85.00 - 107.50 -
Jan 09 - Dec 09 3 - Way Collar 5,000 55.00 40.00 90.00 -
-------------------------------------------------------------------------
Financial AECO Natural Gas Option Contracts
Bought Sold Sold
Volume Put Put Call
Term Contract GJ/d CDN$/GJ CDN$/GJ CDN$/GJ
-------------------------------------------------------------------------
Apr 08 - Oct 08 Collar 10,000 7.00 - 9.00
Apr 08 - Oct 08 3 - Way Collar 10,000 7.00 5.75 9.00
-------------------------------------------------------------------------
Financial NYMEX Natural Gas Contracts
Bought Sold Sold
Volume Put Put Call
mmbtu US$ US$ US$
Term Contract /d /mmbtu /mmbtu /mmbtu
-------------------------------------------------------------------------
Jan 08 - Mar 08 3 - Way Collar 10,000 9.25 6.25 10.00
Jan 08 - Mar 08 Collar 20,000 8.50 - 10.00
Jan 08 - Mar 08 Collar 5,000 7.85 - 9.40
Jan 08 - Mar 08 Collar 5,000 8.25 - 9.25
Jan 08 - Mar 08 Collar 5,000 8.00 - 9.00
Apr 08 - Oct 08 3 - Way Collar 10,000 8.00 6.00 9.60
Apr 08 - Oct 08 3 - Way Collar 10,000 7.80 6.20 9.50
Nov 08 - Mar 09 Collar 20,000 8.50 - 11.00
-------------------------------------------------------------------------
Financial Basis Swap Contract: receive NYMEX (Last 3 Day); pay AECO
(Monthly)
Basis
Volume Swap
mmbtu US$
Term Contract /d /mmbtu
-------------------------------------------------------------------------
Jan 08 - Oct 08 Basis Swap 50,000 (1.1930)
Nov 08 - Oct 10 Basis Swap 50,000 (1.0430)
-------------------------------------------------------------------------
Energy Equivalent Swap
Term Contract Volume Swap
-------------------------------------------------------------------------
Financial WTI Crude Oil Purchase Contract
Apr 08 - Oct 08 Swap 1,000 bbl/d 73.95 CDN$/bbl
Financial AECO Natural Gas Sales Contract
Apr 08 - Oct 08 Swap 10,000 GJ/d 7.10 CDN$/GJ
-------------------------------------------------------------------------
Financial Foreign Exchange Contracts
Noti- Bought Sold
onal Swap Swap Put Put
Volume CDN$ US$ CDN$ CDN$
Term Contract MM US$ /US$ /CDN$ /US$ /US$
-------------------------------------------------------------------------
USD Option Contracts
Jan 08 - Dec 08 Put Spread 12.0 - - 1.0750 1.0300
-------------------------------------------------------------------------
USD Long-term Principal Debt Repayment Contracts
Noti- Bought Sold
onal Swap Swap Put Put
Volume CDN$ US$ CDN$ CDN$
Settlement Date Contract MM US$ /US$ /CDN$ /US$ /US$
-------------------------------------------------------------------------
December 17, 2012 Forward 9.38 0.9324 (1.0725) - -
April 27, 2013 Forward 10.42 0.9454 (1.0578) - -
April 27, 2013 Forward 12.50 0.9430 (1.0604) - -
December 15, 2013 Forward 9.38 0.9520 (1.0504) - -
April 27, 2014 Forward 10.42 0.9743 (1.0264) - -
April 27, 2014 Forward 12.50 0.9615 (1.0400) - -
December 15, 2014 Forward 9.38 0.9825 (1.0178) - -
April 27, 2015 Forward 12.50 0.9825 (1.0178) - -
December 15, 2015 Forward 9.40 0.9980 (1.0020) - -
April 27, 2016 Forward 12.50 1.0180 (0.9823) - -
December 15, 2017 Forward 9.40 1.0184 (0.9819) - -
December 15, 2016 Collar 9.40 - - 1.0600 1.0000
-------------------------------------------------------------------------
Financial Interest Rate Contracts(1)(2)
Prin- Fixed
cipal Annual Spread on
Term Contract MM US$ Rate (%) 3 Mo. LIBOR
-------------------------------------------------------------------------
Jan 08 - Apr 14 Swap 30.5 4.62 38 bps
Jan 08 - Apr 14 Swap 32.0 4.62 (25.5 bps)
-------------------------------------------------------------------------
(1) Starting in 2009, the notional amount of the contracts decreases
annually until 2014. The Trust pays the floating interest rate based
on a three month LIBOR plus a spread and receives the fixed interest
rate.
(2) Starting in 2009 a mutual put exists where both parties have the
right to call on the other party to pay the then current mark-to-
market value of the contract.
Following is a summary of all risk management contracts in place as
at December 31, 2007 that qualify for hedge accounting:
Financial Electricity Contracts(3)(4)
Volume Swap
Term Contract MWh CDN$/MWh
-------------------------------------------------------------------------
Jan 08 - Dec 08 Swap 15.0 60.17
Jan 09 - Dec 09 Swap 15.0 59.33
Jan 10 - Dec 10 Swap 5.0 63.00
-------------------------------------------------------------------------
(3) Contracted volume is based on a 24/7 term.
(4) Includes margin provision on 5 MWh per year if contract value exceeds
$30M. If exercised a letter of credit would be issued for values in
excess of $30 million.
USD Note Treasury Rate Locks
Principal Interest
Settlement Date MM US$ Rate (%)
-------------------------------------------------------------------------
February 15, 2008 125.0 4.8082(5)
-------------------------------------------------------------------------
(5) Rate is based on 10 year US Treasury Bond
During the year the Trust entered into treasury rate lock contracts
in order to manage the Trust's interest rate exposure on future debt
issuances. These contracts have been designated as effective
accounting hedges on their respective contract dates and hedge
accounting has been applied. The unrealized fair value loss on these
contracts of $7.4 million has been recorded on the Consolidated
Balance Sheet at December 31, 2007 with the movement in the fair
value recorded in OCI, net of tax. Ineffectiveness as at December 31,
2007 is nominal and was calculated by considering the present value
of future cash flows on the original treasury rate lock contract and
the rate effective on the contract at December 31, 2007. The maximum
expected term for which the Trust is hedging its interest rate risk
exposure is 10 years, which is the expected term of the future debt
issuance. It is expected that a $0.8 million fair value loss will be
reclassified to Net Income within the next 12 months.
The Trust's fixed price electricity contracts are intended to manage
price risk on electricity consumption. All fixed price electricity
contracts were designated as effective accounting hedges on their
respective contract dates. A realized loss of $0.1 million and gain
of $0.4 million for the three months and twelve months ended
December 31, 2007 respectively (gain of $2.4 million and $3.4 million
respectively in 2006) on the electricity contracts has been included
in operating costs. The unrealized fair value gain on the electricity
contracts of $4 million has been recorded on the Consolidated Balance
Sheet at December 31, 2007 with the movement in fair value recorded
in OCI, net of tax. The fair value movement as at December 31, 2007
amounts to an unrealized loss of $3 million. $1.9 million of this
gain is expected to be recognized in income over the next 12 months.
The Trust has entered into interest rate swap contracts to manage the
Company's interest rate exposure on debt instruments. Prior to 2007,
these contracts were designated as effective accounting hedges on the
contract date. At January 1, 2007 the Trust elected to cease applying
hedge accounting to these contracts.
The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have not been
designated as effective accounting hedges:
December 31 December 31
2007 2006
---------------------------------------------------------------------
Fair value, beginning of year(1) $ (8.7) $ (4.1)
Fair value, end of year(1)(2) (64.6) (8.7)
---------------------------------------------------------------------
Change in fair value of contracts
in the year (55.9) (4.6)
Realized gains in the year 14.1 29.3
---------------------------------------------------------------------
(Loss) gain on risk management
contracts(1) $ (41.8) $ 24.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) For 2007 the fixed price electricity and treasury rate lock
contracts that were accounted for as effective accounting
hedges were excluded. For 2006 the fixed price electricity
contract and interest rate swap contracts that were accounted
for as effective accounting hedges were excluded.
(2) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $47.6 million at
December 31, 2007 ($5.3 million loss in 2006).
The following table reconciles the movement in the fair value of the
Trust's financial electricity and treasury rate lock contracts that
have been designated as effective accounting hedges:
December 31 December 31
2007 2006
---------------------------------------------------------------------
Fair value, beginning of year $ 7.0 $ (0.2)
Fair value, end of year (3.4) 7.0
---------------------------------------------------------------------
Change in fair value of contracts
in the year(3) $ (10.4) $ 7.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) In 2006 fair value amounts relating to risk management contracts
that qualified for hedge accounting were not recorded on the
Consolidated Balance Sheet.
At December 31, 2007, the fair value of the contracts that were not
designated as accounting hedges was a loss of $64.6 million. The
Trust recorded a loss on risk management contracts of $41.8 million
in the Statement of Income for the year ended 2007 ($24.7 million
gain in 2006). This amount includes the realized and unrealized gains
and losses on risk management contracts that do not qualify as
effective accounting hedges.
The fair values of all risk management contracts are determined using
published price quotations in an active market through a valuation
model. Significant inputs into this model include forward curves on
commodity prices, interest rates and foreign exchange rates.
12. GAIN (LOSS) ON FOREIGN EXCHANGE
The following is a summary of the total gain (loss) US$ denominated
transactions:
2007 2006
---------------------------------------------------------------------
Unrealized gain (loss) on US$ denominated debt $ 64.6 $ (7.1)
Realized gain on US$ denominated debt
repayments 5.0 2.6
---------------------------------------------------------------------
Total non-cash gain (loss) on US$ denominated
transactions 69.6 (4.5)
Realized cash (loss) gain on US$ denominated
transactions (0.2) 0.3
---------------------------------------------------------------------
Total foreign exchange gain (loss) $ 69.4 $ (4.2)
---------------------------------------------------------------------
---------------------------------------------------------------------
13. INCOME TAXES
In 2007, Income Trust tax legislation was passed resulting in a two-
tiered tax structure subjecting distributions to the federal
corporate income tax rate plus a deemed 13 per cent provincial income
tax at the Trust level commencing in 2011. Currently, distributions
paid to unitholders, other than returns of capital, are claimed as a
deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and is paid by the unitholders. As a
result, the future tax position of the Trust, the parent entity, is
now required to be reflected in the consolidated future income tax
calculation. The Trust recorded a $24.7 million one time increase in
earnings and a corresponding decrease to its future income tax
liability as a result of timing differences within the Trust that had
not been previously recognized.
On October 30, 2007, the Finance Minister announced a reduction of
the corporate income tax rate from 22.1 per cent to 15 percent by
2012. The reductions will be phased in between 2008 and 2012.
Legislation enacting the measures received Royal Assent on
December 14, 2007. The reduction in the general corporate tax rate
will also apply to the taxation of Income Trusts, reducing the
combined federal and deemed Provincial tax rate for distributions to
28 per cent in 2012.
The tax provision differs from the amount computed by applying the
combined Canadian federal and provincial statutory income tax rates
to income before future income tax recovery as follows:
2007 2006
---------------------------------------------------------------------
Income before future income tax
recovery $ 380.8 $ 379.6
Canadian statutory rate(1) 34.3% 34.5%
---------------------------------------------------------------------
Expected income tax expense at statutory rates 130.6 130.9
Effect on income tax of:
Net income of the Trust (163.6) (138.0)
Effect of change in corporate tax rate (41.3) (62.2)
Initial recognition of Trust tax pools (24.7) -
Unrealized (gain) loss on foreign exchange (10.4) 1.2
Change in estimated pool balances (7.0) (10.0)
Non-taxable portion of gains/losses (2.1) -
Resource allowance - (10.7)
Non-deductible crown charges - 1.2
Other non-deductible items (2.8) 0.5
---------------------------------------------------------------------
Future income tax recovery $ (121.3) $ (87.1)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The statutory rate consists of the combined Trust and Trust's
subsidiaries statutory tax rate
The net future income tax liability comprises the following:
2007 2006
---------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 371.6 $ 509.8
Long-term debt 11.9 4.0
Future tax assets:
Asset retirement obligations (36.1) (52.1)
Risk management contracts (16.7) (2.5)
Accrued long-term incentive compensation (7.8) (7.7)
Non-capital losses (3.8) (5.3)
Attributed Canadian royalty income (4.6) (10.4)
Cumulative eligible capital and deductible
share issue costs (1.6) (1.6)
Other comprehensive loss (0.7) -
---------------------------------------------------------------------
Net future income tax liability $ 312.2 $ 434.2
---------------------------------------------------------------------
Current portion of net future income tax
liability $ (4.0) $ -
Long-term portion of net future income tax
liability $ 316.2 $ 434.2
---------------------------------------------------------------------
---------------------------------------------------------------------
The petroleum and natural gas properties and facilities owned by the
Trust have an approximate tax basis of $1.84 billion
($1.58 billion in 2006) available for future use as deductions from
taxable income. Included in this tax basis are estimated non-capital
loss carry forwards of $13.8 million ($18.2 million in 2006) that
expire in the years 2010 through 2026. The following is a summary of
the estimated Trust's tax pools:
The 2006 comparative tax pools have been restated to include the tax
pools of the Trust and of the Trust's subsidiaries. The 2006 tax
pools disclosed in the prior year for the Trust's subsidiaries were
$1.03 billion. In addition, the Trust itself had an approximate tax
basis of $545.1 million as at December 31, 2006.
2007 2006
---------------------------------------------------------------------
Canadian oil and gas property expenses $ 816.5 $ 734.0
Canadian development expenses 326.1 285.9
Canadian exploration expenses 52.5 27.7
Undepreciated capital cost 460.2 389.0
Non-capital losses 13.8 18.2
Provincial tax pools 161.1 104.5
Other 10.3 16.8
---------------------------------------------------------------------
Estimated tax basis $ 1,840.5 $ 1,576.1
---------------------------------------------------------------------
---------------------------------------------------------------------
No current income taxes were paid or payable in both 2007 and 2006.
14. EXCHANGEABLE SHARES
The ARC Resources exchangeable shares ("ARL Exchangeable Shares")
were issued on January 31, 2001 at $11.36 per exchangeable share as
partial consideration for the Startech Energy Inc. acquisition. The
issue price of the exchangeable shares was determined based on the
weighted average trading price of Trust units preceding the date of
announcement of the acquisition. The ARL Exchangeable Shares had an
exchange ratio of 1:1 at the time of issuance.
The Trust is authorized to issue an unlimited number of ARL
Exchangeable Shares which can be converted (at the option of the
holder) into Trust units at any time. The number of Trust units
issuable upon conversion is based upon the exchange ratio in effect
at the conversion date. The exchange ratio is calculated monthly
based on the cash distribution paid divided by the ten day weighted
average unit price preceding the record date and multiplied by the
opening exchange ratio. The exchangeable shares are not eligible for
distributions and, in the event that they are not exchanged, any
outstanding shares are redeemable by the Trust for Trust units on
August 28, 2012. The ARL Exchangeable Shares are publicly traded.
ARL EXCHANGEABLE SHARES (thousands) 2007 2006
---------------------------------------------------------------------
Balance, beginning of year 1,433 1,595
Exchanged for Trust units (123) (162)
---------------------------------------------------------------------
Balance, end of year 1,310 1,433
Exchange ratio, end of year 2.24976 2.01251
---------------------------------------------------------------------
Trust units issuable upon conversion, end of year 2,947 2,884
---------------------------------------------------------------------
---------------------------------------------------------------------
The non-controlling interest on the Consolidated Balance Sheet
consists of the fair value of the exchangeable shares upon issuance
plus the accumulated earnings attributable to the non-controlling
interest. The net income attributable to the non-controlling interest
on the Consolidated Statement of Income represents the cumulative
share of net income attributable to the non-controlling interest
based on the Trust units issuable for exchangeable shares in
proportion to total Trust units issued and issuable at each period
end.
Following is a summary of the non-controlling interest for 2007 and
2006:
2007 2006
---------------------------------------------------------------------
Non-controlling interest, beginning of year $ 40.0 $ 37.5
Reduction of book value for conversion to
Trust units (3.7) (4.1)
Current year net income attributable to
non-controlling interest 6.8 6.6
---------------------------------------------------------------------
Non-controlling interest, end of year $ 43.1 $ 40.0
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 34.1 $ 27.3
---------------------------------------------------------------------
---------------------------------------------------------------------
15. UNITHOLDERS' CAPITAL
The Trust is authorized to issue 650 million Trust units of which
210.2 million units were issued and outstanding as at December 31,
2007 (204.3 million as at December 31, 2006).
The Trust has in place a Distribution Reinvestment and Optional Cash
Payment Program ("DRIP") in conjunction with the Trust's transfer
agent to provide the option for unitholders to reinvest cash
distributions into additional Trust units issued from treasury at a
five per cent discount to the prevailing market price with no
additional fees or commissions.
The Trust is an open ended mutual fund under which unitholders have
the right to request redemption directly from the Trust. Trust units
tendered by holders are subject to redemption under certain terms and
conditions including the determination of the redemption price at the
lower of the closing market price on the date units are tendered or
90 per cent of the weighted average trading price for the 10 day
trading period commencing on the tender date. Cash payments for units
tendered for redemption are limited to $100,000 per month with
redemption requests in excess of this amount eligible to receive a
note from ARC Resources Ltd. accruing interest at 4.5 per cent and
repayable within 20 years.
2007 2006
---------------------------------------------------------------------
Number of Number of
Trust Trust
Units Units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning of
year 204,289 2,349.2 199,104 2,230.8
Issued for cash - - 1 -
Issued on conversion of
ARL exchangeable shares
(Note 14) 261 3.7 310 4.1
Issued on exercise of
employee rights (Note 18) 131 2.1 978 18.4
Distribution reinvestment
program 5,551 110.7 3,896 96.1
Trust unit issue costs - - - (0.2)
---------------------------------------------------------------------
Balance, end of year 210,232 2,465.7 204,289 2,349.2
---------------------------------------------------------------------
---------------------------------------------------------------------
16. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE LOSS
The deficit balance is composed of the following items:
2007 2006
---------------------------------------------------------------------
Accumulated earnings $ 2,191.1 $ 1,695.8
Accumulated distributions (2,657.0) (2,159.0)
---------------------------------------------------------------------
Deficit $ (465.9) $ (463.2)
Accumulated other comprehensive loss (2.9) -
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive loss $ (468.8) $ (463.2)
---------------------------------------------------------------------
---------------------------------------------------------------------
The accumulated other comprehensive loss balance is composed of the
following items:
2007 2006
---------------------------------------------------------------------
Unrealized losses on financial
instruments designated as cash
flow hedges $ (2.8) -
Net unrealized losses on available-
for-sale reclamation funds'
investments (0.1) -
---------------------------------------------------------------------
Accumulated other comprehensive
loss, end of year $ (2.9) $ -
---------------------------------------------------------------------
17. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS
Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operating activities is
reduced by reclamation fund contributions including interest earned
on the funds, a portion of capital expenditures and, when applicable,
debt repayments. The portion of cash flow from operating activities
withheld to fund capital expenditures and to make debt repayments is
at the discretion of the Board of Directors.
Three months ended Twelve months ended
December 31 December 31
2007 2006 2007 2006
---------------------------------------------------------------------
Cash flow from operating
activities $ 173.7 $ 159.3 $ 704.9 $ 734.0
Deduct:
Cash withheld to fund
current period capital
expenditures (44.5) (33.6) (193.4) (236.7)
Reclamation fund
contributions and
interest earned on fund
balances (3.4) (3.4) (13.5) (13.1)
---------------------------------------------------------------------
Distributions(1) 125.8 122.3 498.0 484.2
Accumulated distributions,
beginning of period 2,531.2 2,036.7 2,159.0 1,674.8
---------------------------------------------------------------------
Accumulated distributions,
end of period $ 2,657.0 $ 2,159.0 $ 2,657.0 $ 2,159.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0.60 $ 0.60 $ 2.40 $ 2.40
Accumulated distributions
per unit, beginning of
period $ 20.43 $ 18.03 $ 18.63 $ 16.23
---------------------------------------------------------------------
Accumulated distributions
per unit, end of
period(3) $ 21.03 $ 18.63 $ 21.03 $ 18.63
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include non-cash amounts of $27 million and
$110 million for the three and twelve months ended December 31,
2007, respectively ($26 million and $94 million for the same
periods in 2006, respectively) relating to the distribution
reinvestment program.
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of the Trust in July 1996.
18. TRUST UNIT INCENTIVE RIGHTS PLAN
The Trust Unit Incentive Rights Plan (the "Rights Plan") was
established in 1999 and authorized the Trust to grant up to 8,000,000
rights to its employees, independent directors and long-term
consultants to purchase Trust units, of which 7,866,088 were granted
to December 31, 2007. The initial exercise price of rights granted
under the Rights Plan could not be less than the market price of the
Trust units as at the date of grant and the maximum term of each
right was not to exceed ten years. In general, the rights have a five
year term and vest equally over three years commencing on the first
anniversary date of the grant. In addition, the exercise price of the
rights is to be adjusted downwards from time to time by the amount,
if any, that distributions to unitholders in any calendar quarter
exceeds 2.5 per cent (ten per cent annually) of the Trust's net book
value of property, plant and equipment (the "Excess Distribution"),
as determined by the Trust.
During 2007, 2006 and 2005, the Trust did not grant any rights as the
Rights Plan was replaced with a Whole Unit Plan during 2004 (see Note
19). The existing Rights Plan will be in place until the remaining
0.2 million rights outstanding as at December 31, 2007 are exercised
or cancelled.
A summary of the changes in rights outstanding under the Rights Plan
is as follows:
2007 2006
---------------------------------------------------------------------
Weighted Weighted
Number Average Number Average
of Rights Exercise of Rights Exercise
(thousands) Price ($) (thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of year 369 9.47 1,349 10.22
Exercised (131) 10.77 (978) 12.19
Cancelled - - (2) 10.07
---------------------------------------------------------------------
Balance before reduction
of exercise price 238 9.41 369 10.40
Reduction of exercise
price(1) - (0.91) - (0.93)
---------------------------------------------------------------------
Balance, end of year 238 8.50 369 9.47
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held
at the original grant price or a reduced exercise price.
All rights outstanding are exercisable and have a remaining
contractual life of 0.4 years.
The Trust recorded a nominal amount of compensation expense for the
year ($2.5 million in 2006) for the cost associated with the rights.
Of the 3,013,569 rights issued on or after January 1, 2003 that were
subject to recording compensation expense, 357,999 rights have been
cancelled and 2,419,239 rights have been exercised to December 31,
2007.
The following table reconciles the movement in the contributed
surplus balance for 2007 and 2006:
---------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------
Balance, beginning of year $ 2.4 $ 6.4
Compensation expense - 2.5
Net benefit on rights exercised(1) (0.7) (6.5)
---------------------------------------------------------------------
Balance, end of year $ 1.7 $ 2.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to unitholders' capital.
19. WHOLE TRUST UNIT INCENTIVE PLAN
In March 2004, the Board of Directors, upon recommendation of the
Compensation Committee, approved a new Whole Trust Unit Incentive
Plan (the "Whole Unit Plan") to replace the existing Trust Unit
Incentive Rights Plan for new awards granted subsequent to March 31,
2004. The new Whole Unit Plan will result in employees, officers and
directors (the "plan participants") receiving cash compensation in
relation to the value of a specified number of underlying notional
trust units. The Whole Unit Plan consists of Restricted Trust Units
("RTUs") for which the number of trust units is fixed and will vest
over a period of three years and Performance Trust Units ("PTUs") for
which the number of trust units is variable and will vest at the end
of three years.
Upon vesting, the plan participant receives a cash payment based on
the fair value of the underlying trust units plus notional accrued
distributions. The cash compensation issued upon vesting of the PTUs
is dependent upon the future performance of the Trust compared to its
peers based on a performance multiplier. The performance multiplier
is based on the percentile rank of the Trust's Total Unitholder
Return. The cash compensation issued upon vesting of the PTUs may
range from zero to two times the value of the PTUs originally
granted.
The fair value associated with the RTUs and PTUs is expensed in the
statement of income over the vesting period. As the value of the RTUs
and PTUs is dependent upon the trust unit price, the expense recorded
in the statement of income may fluctuate over time.
The Trust recorded non-cash compensation expense of $3.2 million and
$0.3 million to general and administrative and operating expenses,
respectively, and capitalized $0.7 million to property, plant and
equipment in the twelve months ended December 31, 2007 for the
estimated cost of the plan ($8.2 million, $1.1 million, and
$1.8 million for the twelve months ended December 31, 2006). The non-
cash compensation expense was based on the December 31, 2007 unit
price of $20.40 ($22.30 in 2006), accrued distributions, a weighted
average performance multiplier of 1.7 (2.0 in 2006), and the number
of units to be issued on maturity.
The following table summarizes the RTU and PTU movement for the
twelve months ended December 31, 2007 and 2006:
2007 2006
---------------------------------------------------------------------
Number of Number of Number of Number of
RTUs PTUs RTUs PTUs
(thousands) (thousands) (thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning
of year 648 683 479 391
Vested (286) (110) (180) -
Granted 422 362 373 303
Forfeited (38) (32) (24) (11)
---------------------------------------------------------------------
Balance, end of year 746 903 648 683
---------------------------------------------------------------------
---------------------------------------------------------------------
The following table reconciles the change in total accrued
compensation liability relating to the Whole Unit Plan:
2007 2006
---------------------------------------------------------------------
Balance, beginning of year $ 26.1 $ 15.0
Change in liabilities in the year
General and administrative expense 3.2 8.2
Operating expense 0.3 1.1
Property, plant and equipment 0.7 1.8
---------------------------------------------------------------------
Balance, end of year $ 30.3 $ 26.1
---------------------------------------------------------------------
Current portion of liability (Note 8) 18.2 11.5
---------------------------------------------------------------------
Long-term liability $ 12.1 $ 14.6
---------------------------------------------------------------------
---------------------------------------------------------------------
During the year $12.7 million in cash payments were made to employees
relating to the Whole Unit Plan ($5.2 million in 2006).
20. BASIC AND DILUTED PER TRUST UNIT CALCULATIONS
Net income per trust unit has been determined based on the following:
Three months ended Twelve months ended
December 31 December 31
2007 2006 2007 2006
---------------------------------------------------------------------
Weighted average trust
units(1) 209,520 203,580 207,287 201,554
Trust units issuable on
conversion of exchangeable
shares(2) 2,947 2,884 2,947 2,884
Dilutive impact of
rights(3) 135 323 174 711
---------------------------------------------------------------------
Dilutive trust units and
exchangeable shares 212,602 206,787 210,408 205,149
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average trust units exclude trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for
outstanding exchangeable shares at the period end exchange
ratio.
(3) All outstanding rights were dilutive and therefore have been
included in the diluted unit calculation for both 2007 and
2006.
Basic net income per unit has been calculated based on net income
after non-controlling interest divided by weighted average trust
units. Diluted net income per unit has been calculated based on net
income before non-controlling interest divided by dilutive trust
units.
21. COMMITMENTS AND CONTINGENCIES
Following is a summary of the Trust's contractual obligations and
commitments as at December 31, 2007:
-------------------------------------------------------------------------
Payments Due by Period ($millions)
-------------------------------------------------------------------------
2008 2009-2010 2011-2012 Thereafter Total
Debt repayments(1) 5.9 540.8 51.5 116.3 714.5
Interest payments(2) 11.0 20.2 15.5 13.7 60.4
Reclamation fund
contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 10.1 4.1 4.0 6.0 24.2
Operating leases(4) 6.2 8.9 12.4 88.1 115.6
Risk management
contract premiums(5) 13.2 2.3 - - 15.5
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Total contractual
obligations 52.2 586.5 92.3 296.0 1,027.0
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(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property acquired in 2005.
(4) Includes an available option expiring February 2008 to reduce a
portion of office lease commitments.
(5) Fixed premiums to be paid in future periods on certain risk
management contracts.
The above noted risk management contract premiums are part of the
Trust's commitments related to its risk management program. In
addition to the above premiums, the Trust has commitments related to
its risk management program (see Note 11). As the premiums are part
of the underlying risk management contract, they have been recorded
at fair market value at December 31, 2007 on the balance sheet as
part of risk management contracts.
The Trust enters into commitments for capital expenditures in advance
of the expenditures being made. At a given point in time, it is
estimated that the Trust has committed to capital expenditures equal
to approximately one quarter of its capital budget by means of giving
the necessary authorizations to incur the capital in a future period.
The Trust's 2008 capital budget has been approved by the Board at
$395 million. This commitment has not been disclosed in the
commitment table as it is of a routine nature and is part of normal
course of operations for active oil and gas companies and trusts.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending
litigation will not have a material adverse impact on the Trust's
financial position or results of operations and therefore the
following table does not include any commitments for outstanding
litigation and claims.
The Trust has certain sales contracts with aggregators whereby the
price received by the Trust is dependent upon the contracts entered
into by the aggregator. This commitment has not been disclosed in the
commitment table as it is of a routine nature and is part of normal
course of operations.
>>
ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5.7 billion. The
Trust expects full year 2008 oil and gas production to average approximately
63,000 barrels of oil equivalent per day from six core areas in western
Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN and its
exchangeable shares trade under the symbol ARX.
ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 2008 and beyond; the
sources, deployment and allocation of expected capital in 2008; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.
ARC RESOURCES LTD.
John P. Dielwart,
President and Chief Executive Officer
For further information: about ARC Energy Trust, please visit our website www.arcresources.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9