Oil & Gas Job Listings
CALGARY, May 9 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or "the Trust") announces the results for the first quarter ending March 31, 2006.
Three Months Ended
March 31
2006 2005
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FINANCIAL
($CDN thousands, except per unit and per boe amounts)
Revenue before royalties 318,931 238,054
Per unit(1) 1.58 1.26
Per boe 54.86 47.74
Cash flow(3) 191,200 141,965
Per unit(1) 0.94 0.75
Per boe 32.89 28.47
Net income(5) 104,071 38,646
Per unit(1) 0.52 0.20
Cash distributions 119,867 83,867
Per unit(1) 0.60 0.45
Payout ratio(5) 63% 59%
Net debt outstanding(4) 598,911 254,252
OPERATING
Production
Crude oil (bbl/d) 29,651 21,993
Natural gas (mcf/d) 184,974 176,073
Natural gas liquids (bbl/d) 4,120 4,072
Total (boe/d) 64,600 55,410
Average prices
Crude oil ($/bbl) 59.53 53.63
Natural gas ($/mcf) 8.40 7.20
Natural gas liquids ($/bbl) 52.91 46.57
Oil equivalent ($/boe)(6) 54.86 47.74
Operating netback ($/boe)
Commodity and other revenue (before hedging) 54.86 47.74
Transportation costs (0.61) (0.72)
Royalties (10.71) (8.99)
Operating costs (7.80) (6.10)
Netback (before hedging) 35.74 31.93
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TRUST UNITS
(thousands)
Units outstanding, end of period 200,194 186,623
Units issuable for exchangeable shares 2,896 2,986
Total units outstanding and issuable for
exchangeable shares, end of period 203,090 189,609
Weighted average units(2) 199,583 186,224
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TRUST UNIT TRADING STATISTICS
($CDN, except volumes) based on intra-day trading
High 27.51 20.40
Low 25.09 16.55
Close 27.36 18.15
Average daily volume 545,793 895,140
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(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average units plus units issuable for exchangeable
shares.
(2) Excludes trust units issuable for outstanding exchangeable shares at
period end.
(3) Management uses cash flow to analyze operating performance and
leverage. Cash flow 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. Cash flow as presented is not intended to represent
operating cash flow or operating profits for the period nor should it
be viewed as an alternative to cash flow from operating activities,
net earnings or other measures of financial performance calculated in
accordance with Canadian GAAP. All references to cash flow throughout
this report are based on cash flow from operating activities before
changes in non-cash working capital and expenditures on site
restoration and reclamation.
(4) Net debt excludes unrealized commodity and foreign exchange contracts
asset and liability.
(5) Cash distributions divided by cash flow from operations.
(6) Includes other revenue.
ACCOMPLISHMENTS/FINANCIAL UPDATE
--------------------------------
- Production averaged 64,600 boe per day in the first quarter of 2006,
17 per cent higher than the 55,410 boe per day production in the
first quarter of 2005. The increase in production is due to the
Redwater and NPCU acquisitions made in late 2005, other smaller
acquisitions and from the results of an active drilling program.
- The Trust spent $79 million on capital development and drilled 28 net
wells on operated properties in the first quarter. Successful
drilling programs at Ante Creek (five wells), Dawson (one well),
Prestville (two wells), Jenner (14 shallow gas wells) and southeast
Saskatchewan (five wells) contributed to the record production
levels. Other factors contributing to the record production levels
included well reactivations and optimization at Redwater and
favourable operating conditions in the field.
- Production per unit increased by 10 per cent to 0.32 boe per day per
thousand units in the first quarter of 2006 from 0.29 boe per day per
thousand units in the first quarter of 2005.
- ARC completed $33.8 million of acquisitions and $6.2 million of
dispositions during the quarter. On a net basis, ARC spent
$27.6 million to purchase 500 boe per day of production and
approximately 2 mmboe of proved plus probable reserves.
- ARC realized cash flow of $191 million ($0.94 per unit) in the first
quarter of 2006 compared to $142 million ($0.75 per unit) in the
first quarter of 2005. The 35 per cent increase in 2006 cash flow was
due to higher commodity prices and increased production volumes.
- Net income for the first quarter increased to $104 million from
$39 million in the first quarter of 2005, primarily due to the Trust
recording a hedging gain in the quarter of $4 million versus a loss
of $74 million in the first quarter of 2005.
- ARC's first quarter average oil price increased 11 per cent to $59.53
per boe from $53.63 per boe in the first quarter of 2005. West Texas
Intermediate ("WTI") increased 27 per cent in the first quarter of
2006 to US$63.53 compared to US$49.90 in the first quarter of 2005.
This increase was partially offset by a stronger Canadian dollar and
by wider differentials. ARC's average natural gas price increased to
$8.40 per mcf from $7.20 per mcf in the first quarter of 2005.
- The Trust realized an operating netback, before hedging, of $35.74
per boe in the first quarter of 2006 compared to $31.93 in the first
quarter of 2005.
- Operating costs increased to $7.80 per boe in the first quarter of
2006 compared to $6.10 per boe in the first quarter of 2005. This
increase in operating costs was primarily attributable to the
addition of higher cost properties at Redwater and NPCU and overall
industry operating cost increases.
- The Trust declared cash distributions of $120 million ($0.60 per
unit) in the first quarter of 2006, resulting in a payout ratio of
63 per cent. The remaining 37 per cent of cash flow ($71.3 million)
was used to fund 88 per cent of ARC's capital development program.
MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
Management's discussion and analysis ("MD&A") should be read in
conjunction with the audited consolidated financial statements for the year
ended December 31, 2005.
This MD&A was written on April 28, 2006.
Management uses cash flow to analyze operating performance and leverage.
Cash flow as presented does not have any standardized meaning prescribed by
Canadian generally accepted accounting principles, ("GAAP") and therefore it
may not be comparable with the calculation of similar measures for other
entities. Cash flow as presented is not intended to represent operating cash
flow or operating profits for the period nor should it be viewed as an
alternative to cash flow from operating activities, net earnings or other
measures of financial performance calculated in accordance with Canadian GAAP.
The following table reconciles the cash flow from operating activities to
cash flow from operations, which is a term used frequently in this MD&A:
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($ thousands) Q1 2006 Q1 2005
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Cash flow from operating activities 189,094 128,736
Changes in non-cash working capital 841 12,182
Expenditures on site reclamation and restoration 1,265 1,047
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Cash flow from operations 191,200 141,965
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Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as operating netbacks ("netbacks"), total capitalization and
payout ratios to analyze financial and operating performance. These KPI's 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.
This discussion and analysis contains forward-looking statements relating
to future events or future performance. In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions. 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 necessarily involve known and unknown risks and uncertainties,
including the business risks discussed in the MD&A as at and for the year
ended December 31, 2005, 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 results to differ materially from those predicted.
Highlights
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Three months ended
(CDN$ millions, except per unit March 31
and volume data) 2006 2005 % Change
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Cash flow from operations 191.2 142.0 35
Cash flow from operations per unit 0.94 0.75 25
Net income before taxes(1) 93.8 9.1 931
Net income 104.1 38.6 170
Distributions per unit 0.60 0.45 33
Payout ratio per cent(2) 63 59 7
Daily production (boe/d)(3) 64,600 55,410 17
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(1) Represents net income after non-controlling interest and before the
future income tax recovery.
(2) Based on cash distributions divided by cash flow from operations.
(3) Reported production amount is based on company interest before
royalty burdens.
Net Income
Net income in the first quarter of 2006 was $104.1 million, an increase
of $65.5 million from $38.6 million in the first quarter of 2005. The increase
was primarily due to the Trust recording a $4 million hedging gain in the
quarter versus a $74 million hedging loss in the first quarter of 2005.
Cash Flow from Operations
Cash flow from operations increased by 35 per cent in the first quarter
of 2006 to $191.2 million from $142 million in the first quarter of 2005. The
increase in 2006 cash flow was the result of a 17 per cent increase in
production volumes, reduced hedging losses and higher commodity prices,
partially offset by higher operating costs and royalties. Per unit cash flow
from operations increased 25 per cent to $0.94 per unit from $0.75 per unit in
the first quarter of 2005. The first quarter 2006 cash flow included a cash
loss of $1.4 million on commodity and foreign currency contracts compared to a
cash loss of $7.3 million in the first quarter of 2005.
Following is a summary of variances in cash flow from operations for the
first quarter of 2005 relative to the first quarter of 2006:
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%
$ Millions $ Per unit Variance(2)
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Q1 2005 Cash flow from operations $ 142.0 $ 0.75
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Volume variance 39.5 0.21 28
Price variance 41.4 0.22 29
Change in cash losses on commodity
and foreign currency contracts(1) 5.9 0.03 4
Royalties (17.4) (0.09) (12)
Expenses:
Operating (14.9) (0.08) (10)
Cash G&A (1.5) (0.01) (1)
Interest (4.5) (0.02) (3)
Other 0.7 - -
Weighted average trust units - (0.07) -
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Q1 2006 cash flow from operations $ 191.2 $ 0.94 35
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(1) Represents cash losses on commodity and foreign currency contracts
including cash settlements on termination of commodity and foreign
currency contracts.
(2) Variance is calculated based on $ millions column.
Production
Production volumes averaged 64,600 boe per day in the first quarter of
2006 compared to 55,410 boe per day in the first quarter of 2005. Production
from the Redwater and NPCU properties purchased late in December 2005
contributed over 5,300 boe per day in the first quarter, while other 2005
acquisitions including additional interest at Berrymoor, Buckcreek and the
Romulus acquisition, added 1,500 boe per day. An active drilling and
optimization program added the balance of the volumes. The Trust's annual
objective is to maintain 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.
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Three months ended
March 31
Production(1) 2006 2005 % Change
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Crude oil (bbl/d) 29,651 21,993 35
Natural gas (mcf/d) 184,974 176,073 5
NGL (bbl/d) 4,120 4,072 1
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Total production (boe/d) 64,600 55,410 17
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% Natural gas production 48 53 (9)
% Crude oil and liquids production 52 47 11
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(1) Reported production for a period may include minor adjustments from
previous production periods.
Oil production increased by thirty-five per cent to 29,651 boe per day in
the first quarter of 2006 from 21,993 boe per day in the first quarter of
2005. The increase in oil production was largely attributed to the Redwater
and NPCU acquisition in the fourth quarter of 2005. Natural gas production
declines at existing properties were more than offset by additional drilling
activities in the first quarter of 2006. The Trust's weighting of oil and
liquids production increased to 52 per cent in the first quarter of 2006 from
47 per cent in 2005 as a result of the incremental Redwater and NPCU oil
volumes.
Natural gas production increased to 185 mmcf per day in the first quarter
of 2006, a five per cent increase compared to first quarter 2005 natural gas
production of 176 mmcf per day. The majority of this increase was as a result
of ARC's active internal drilling program.
During the first quarter of 2006, the Trust drilled 31 gross wells (28
net wells) on operated properties; 12 gross oil wells and 19 gross natural gas
wells.
The following table summarizes the Trust's production by core area:
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Q1 2006 Q1 2005
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Core Total Oil Gas NGL Total Oil Gas NGL
Area(1) (boe/d)(bbls/d)(mmcf/d)(bbls/d)(boe/d)(bbls/d)(mmcf/d)(bbls/d)
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Central AB 8,588 1,656 32.2 1,561 8,505 1,511 31.2 1,800
Northern
AB & BC 19,557 6,527 69.5 1,454 18,223 5,595 67.6 1,350
Pembina &
Redwater 13,932 9,516 20.5 987 7,188 3,575 17.1 767
S.E. AB &
S.W. Sask. 11,219 1,087 60.8 6 11,262 1,513 58.4 18
S.E. Sask. 11,304 10,865 2.0 112 10,232 9,799 1.8 137
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Total 64,600 29,651 185.0 4,120 55,410 21,993 176.1 4,072
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(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, S.E. is Southeast, S.W. is Southwest.
The Trust expects 2006 annual production to average approximately 62,000
boe per day.
Commodity Prices Prior to Hedging
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Three months ended
March 31
Benchmark prices 2006 2005 % Change
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AECO gas (CDN$/mcf)(1) 9.30 6.69 39
WTI oil (US$/bbl)(2) 63.53 49.90 27
USD/CAD foreign exchange rate 0.87 0.82 6
WTI oil (CDN$/bbl) 73.36 61.21 20
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(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
The Canadian denominated oil price received by ARC and other Canadian
energy companies was negatively impacted by the continued strength of the
Canadian dollar with respect to the U.S. dollar during 2006. While crude oil
prices averaged US$63.53 per barrel in the first quarter of 2006, the Canadian
dollar also remained strong and closed the quarter at $0.87. Despite the
27 per cent increase in the US$ WTI oil price in the first quarter 2006
relative to 2005, the Canadian denominated oil price increased by only
20 per cent to $73.36 per barrel in the first quarter of 2006 compared to
$61.21 per barrel in the first quarter of 2005. The Trust's realized oil
price, before hedging, increased by only 11 per cent to $59.53 per barrel in
the first quarter of 2006 compared to $53.63 per barrel in 2005 due to a
widening of the differential between the Edmonton Posted price and the
benchmark WTI price. The Edmonton Posted price was CDN$5.31 per barrel lower
than Canadian equivalent WTI in the first quarter of 2006 versus CDN$0.41 per
barrel lower in the first quarter of 2005. The May 2006 differential has
narrowed to a more normal CDN$1.00 per barrel. The Trust's oil production
consists predominantly of light and medium crude oil while heavy oil accounts
for approximately five per cent of the Trust's liquids production.
Alberta AECO monthly Hub prices, which are commonly used as an industry
reference, averaged $9.30 per mcf in the first quarter of 2006 compared to
$6.69 per mcf in the first quarter of 2005. ARC's realized gas price, before
hedging, increased by 17 per cent in the first quarter of 2006 to $8.40 per
mcf compared to $7.20 per mcf in 2005. ARC's realized gas price is based on
prices received at the various markets where 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. ARC's realized prices are significantly
below AECO monthly average because AECO daily spot prices averaged only $7.53
per mcf in the first quarter.
Prior to hedging activities, ARC realized commodity revenue of $54.74 per
boe in the first quarter of 2006, a 15 per cent increase over the $47.59 per
boe received prior to hedging in 2005.
The following is a summary of realized prices:
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Three months ended
March 31
ARC realized prices(1) 2006 2005 % Change
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Oil ($/bbl) 59.53 53.63 11
Natural gas ($/mcf) 8.40 7.20 17
NGL's ($/bbl) 52.91 46.57 14
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Total commodity revenue before
hedging ($/boe) 54.74 47.59 15
Other revenue ($/boe) 0.12 0.15 (20)
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Total revenue before hedging ($/boe) 54.86 47.74 15
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(1) Prices as reported above are prior to gains and losses on commodity
and foreign currency contracts and are prior to transportation
charges. All gains and losses on commodity and foreign currency
contracts are included in "gain (loss) on commodity and foreign
currency contracts" in the statement of income.
Revenue
Revenue increased 34 per cent to $318.9 million in the first quarter of
2006 from first quarter 2005 revenue of $238.1 million. The increase in
revenue was primarily attributable to higher volumes and higher commodity
prices.
A breakdown of revenue is as follows:
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Three months ended
March 31
Revenue ($ thousands) 2006 2005 % Change
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Oil revenue 158,861 106,163 50
Natural gas revenue 139,765 114,093 23
NGL's revenue 19,625 17,063 15
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Total commodity revenue 318,251 237,319 34
Other revenue 680 735 (7)
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Total revenue 318,931 238,054 34
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Risk Management and Hedging Activities
The Trust's risk management activities are conducted by an internal Risk
Management Committee, based upon guidelines approved by the Board. The Risk
Management Committee has the following mandate:
- protect unitholder return on investment;
- provide for minimum monthly cash distributions to unitholders;
- employ a portfolio approach to risk management by entering into a
number of small positions that build upon each other;
- participate in commodity price upturns to the greatest extent
possible while limiting exposure to price downturns; and,
- ensure profitability of specific oil and gas properties that are more
sensitive to changes in market conditions.
The Trust realized cash hedging losses of $1.4 million for the quarter
were primarily due to the cost of premiums on bought protection for crude oil
prices. These losses were partially offset by gains in foreign exchange swaps
and natural gas put contracts.
At the date of this MD&A, the Trust had upside participation for 2006 on
all produced volumes, with the exception of the acquired volumes from Redwater
and NPCU as disclosed in the fourth quarter 2005 MD&A, with downside price
protection for the remainder of the year on 41 per cent of liquids production
and 31 per cent natural gas production (36 per cent of total production).
The Trust continues to execute a risk management strategy focused on put
and put spread structures to manage commodity prices and continues to use
fixed rate swaps to manage foreign exchange and interest rate exposures. The
purchase of a put involves paying a premium to limit the exposure to downturns
in commodity prices while participating in commodity price appreciation. At
quarter end the Trust had bought puts for the remainder of 2006 with an
average floor on oil production of US$54.99 per barrel and an average floor on
gas production of Cdn$7.73 per GJ. The Trust also entered into sold put
transactions that offset the cost of the bought put premiums. A total of
$12.6 million in premiums has been committed to protect a portion of the
remaining nine months of 2006 revenue.
In addition to the above contracts, the Trust has also taken the
following proactive measures to protect gas prices in light of record gas
storage levels throughout the winter of 2006 and the possibility of lower AECO
gas prices for the summer of 2006. ARC entered into an energy equivalent swap
transaction for April - August on 40,000 GJ per day whereby ARC receives a
fixed price on gas of Cdn$7.09 per GJ and receives the price upside on an
additional 3,870 barrels per day of oil above US$64.52 per barrel which was
facilitated though the combination of oil purchase and oil put contracts as
detailed in Note 4 of the financial statements. This transaction effectively
rebalances ARC's 48:52 gas-oil weighting to 40:60 for these months. Also, ARC
entered into a basis swap transaction whereby ARC reduces its exposure to gas
prices in Alberta by selling its gas at NYMEX gas prices less US$1.19 for
20,000 mmbtu per day from April - Oct, 2006.
For a complete summary of the Trust's oil and natural gas hedges, please
refer to "Hedging Program" under the "Investor Relations" section of the
Trust's website at www.arcenergytrust.com.
The Trust considers its risk management contracts to be effective
economic hedges as they meet the objectives of the Trust's risk management
mandate. In order to mitigate credit risk, the Trust executes commodity and
foreign currency hedging risk management with financially sound, credit worthy
counterparties. All contracts require approval of the Trust's Risk Management
Committee prior to execution. Deferred premiums payable will be recorded as a
realized cash hedging loss when payment is made in a future period. These
premiums may be partially offset if ARC sells any short-term options. The
Trust's oil contracts are based on the WTI index and the majority of the
Trust's natural gas contracts are based on the AECO monthly index.
Gain or Loss on Commodity and Foreign Currency Contracts
Gain or loss on commodity and foreign currency contracts comprise
realized and unrealized gains or losses on commodity and foreign currency
contracts that do not meet the requirements of an effective accounting hedge,
even though the Trust considers all commodity and foreign currency contracts
to be effective economic hedges. Accordingly, gains and losses on such
contracts are shown as a separate expense in the statement of income.
The Trust recorded a gain on commodity and foreign currency contracts of
$3.7 million in the first quarter of 2006, consisting of an unrealized fair
value gain of $5.1 million and a realized cash loss of $1.4 million.
The following is a summary of the gain (loss) on commodity and foreign
currency contracts:
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Commodity and foreign
currency contracts Crude oil Natural Foreign Q1 2006 Q1 2005
($ thousands) & liquids gas currency total total
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Realized cash (loss) gain
on contracts(1) (3,753) 868 1,501 (1,384) (7,314)
Unrealized (loss) gain on
contracts, change in
fair value(2) (7,793) 14,307 (1,424) 5,090 (66,687)
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Total gain (loss) on
commodity and foreign
currency contracts (11,546) 15,175 77 3,706 (74,001)
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(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized loss on contracts represents the change in fair value
of the contracts during the period.
Operating Netbacks
The Trust's operating netback, after realized hedging losses, increased
17 per cent to $35.50 per boe in the first quarter of 2006 compared to $30.46
per boe in the first quarter of 2005. The increase in netbacks in 2006 is
primarily due to higher commodity prices and lower hedging losses, which more
than offset increases in royalties, operating costs and cash general and
administrative costs.
The netbacks incorporate realized losses on commodity and foreign
currency contracts of $0.24 per boe for the first quarter of 2006, compared to
losses of $1.47 per boe in the first quarter of 2005.
The components of operating netbacks are shown below:
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Q1 2006 Q1 2005
Oil Gas NGL Total Total
Netback ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
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Weighted average sales price 59.53 8.40 52.92 54.74 47.59
Other revenue - - - 0.12 0.15
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Total revenue 59.53 8.40 52.92 54.86 47.74
Royalties (9.45) (1.93) (13.27) (10.71) (8.99)
Transportation (0.10) (0.20) - (0.61) (0.72)
Operating costs(1) (10.17) (0.96) (6.21) (7.80) (6.10)
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Netback prior to hedging 39.81 5.31 33.44 35.74 31.93
Realized gain (loss) on
commodity and foreign
currency contracts (0.84) 0.05 - (0.24) (1.47)
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Netback after hedging 38.97 5.36 33.44 35.50 30.46
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(1) Operating expenses are composed of direct costs incurred to operate
both oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, natural gas and natural gas
liquids production.
Royalties increased to $10.71 per boe in the first quarter of 2006
compared to $8.99 per boe in the first quarter of 2005. The increase in
royalties is the result of higher revenues in the first quarter of 2006
relative to 2005. Royalties as a percentage of pre-hedged commodity revenue
net of transportation costs increased slightly to 19.7 per cent compared to
19.1 per cent in the first quarter of 2005. Royalties are calculated and paid
based on commodity revenue net of associated transportation costs and before
any commodity hedging gains or losses.
Operating costs increased to $7.80 per boe compared to $6.10 per boe in
the first quarter of 2005. Operating costs (on properties other than Redwater
and NPCU) increased by 10 per cent in the past year. The acquisition of the
Redwater and NPCU properties with operating costs of approximately $20 per boe
contributed to a large portion of the 28 per cent increase in operating costs.
Higher costs for supplies, materials, electricity and labour accounted for the
remainder of the cost increase.
Transportation costs decreased 15 per cent to $0.61 per boe in the first
quarter of 2006 compared to $0.72 per boe in the first quarter of 2005. This
is a result of the increased percentage of oil in the Trust's production mix
as oil has a relatively lower transportation cost than gas. Transportation
costs are defined by the point of legal transfer of the product and are
dependent upon where the product is sold, the product split, location of
properties, and industry transportation rates.
General and Administrative Expenses and Trust Unit Incentive Compensation
Cash general and administrative expenses ("G&A"), net of overhead
recoveries on operated properties increased to $7.7 million ($1.32 per boe) in
the first quarter of 2006 from $6.2 million ($1.24 per boe) in 2005. Increases
in cash G&A expenses in total and per boe for 2006 were due to increased staff
levels and higher compensation costs. As a result of the unprecedented levels
of activity for ARC and for the industry as a whole, the costs associated with
hiring, compensating and retaining employees and consultants have risen.
The following is a breakdown of G&A and trust unit incentive compensation
expense:
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Three months ended
G&A and trust unit incentive compensation March 31
expense ($ thousands except per boe) 2006 2005 % Change
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G&A expenses 10,264 8,041 28
Operating recoveries (2,608) (1,875) 39
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Cash G&A expenses 7,656 6,166 24
Accrued compensation - Rights Plan 1,774 1,674
Accrued compensation - Whole Unit Plan 3,810 307
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Total G&A and trust unit incentive
compensation expense 13,240 8,147 63
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Cash G&A expenses per boe 1.32 1.24 6
Total G&A and trust unit incentive
compensation expense per boe 2.28 1.63 40
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A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $5.6 million ($0.96 per boe) was recorded in the
first quarter of 2006 compared to $2 million ($0.39 per boe) in the first
quarter of 2005. This non-cash amount relates to both the Trust Unit Incentive
Rights Plan ("Rights Plan") and the Whole Trust Unit Incentive Plan ("Whole
Unit Plan").
For the quarter ended March 31, 2006 the compensation expense for the
rights plan based on the fair value calculation resulted in an expense of
$1.8 million which is comparable to the $1.7 million from the first quarter
2005.
Under the Whole Unit Plan, $3.8 million was accrued during the first
quarter of 2006 versus $0.3 million in the first quarter of 2005 for G&A. The
increase in the accrued value of the Restricted Trust Units ("RTUs") and
Performance Trust Units ("PTUs") outstanding is attributed to the increase in
the Trust's unit value in the market, and the increase in the performance
multiplier on the PTUs after reflecting ARC's top quartile returns as compared
to other midsized oil and gas producers, as well as an increase in the number
of units expected to vest at maturity.
The Whole Unit Plan results in employees, officers and directors
receiving cash compensation in relation to the value and accumulated
distributions of a specified number of underlying units. The Whole Unit Plan
consists of RTUs for which the number of units is fixed and will vest over a
period of three years and PTUs for which the number of units is variable,
dependent upon the performance of the Trust compared to its peers, and will
vest at the end of three years. The number of units issued for the PTUs is
based upon a performance multiplier that calculates the percentile rank of the
Trust's total unitholder return, which is the sum of the increase in market
price of the units over the period plus the amount of distributions over the
period, compared to its peers. This performance multiplier can range from zero
to two.
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 units to be issued on vesting, and
distributions. Therefore, the expense recorded fluctuates over time.
The following table shows the changes during the first quarter of 2006 of
RTUs and PTUs outstanding:
-------------------------------------------------------------------------
Number Number
(in thousands of units) of RTUs of PTUs
-------------------------------------------------------------------------
Balance, beginning of period 479 391
Granted 3 2
Forfeited (10) -
-------------------------------------------------------------------------
Balance, end of period 472 393
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest Expense
Interest expense increased to $7.6 million in the first quarter of 2006
from $3.1 million in the first quarter of 2005 due to the higher debt balances
as a result of the 2005 acquisitions and an increase in short-term interest
rates. As at March 31, 2006, 90 per cent of the Trust's debt was denominated
in U.S. dollars.
The following is a summary of the debt balance and interest expense for
the first quarters of 2006 and 2005:
-------------------------------------------------------------------------
Three months ended
Interest expense March 31
($ thousands) 2006 2005 % Change
-------------------------------------------------------------------------
Period end debt balance(1) 549,025 226,656 142
Fixed rate debt 268,433 221,357
Floating rate debt 280,592 5,299
-------------------------------------------------------------------------
Interest expense before interest
rate swaps(2) 7,561 3,468
Loss (Gain) on interest rate hedge 41 (329)
-------------------------------------------------------------------------
Net interest expense 7,602 3,139 142
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes both long-term and current portions of debt.
(2) The interest rate swap was designated as an effective hedge for
accounting purposes whereby actual realized gains and losses are
netted against interest expense.
Foreign Exchange Gains and Losses
The Trust recorded a loss of $5.6 million ($0.96 per boe) on foreign
exchange transactions in the first quarter of 2006 compared to a loss of
$1 million ($0.21 per boe) in the first quarter of 2005. 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 as it is a non-cash amount. Realized foreign exchange gains or
losses arise from U.S. denominated transactions such as interest payments,
debt repayments and hedging settlements.
Taxes
Capital taxes paid or payable by ARC, based on debt and equity levels,
decreased slightly to $0.6 million in the first quarter of 2006 compared to
$0.7 million in the same period of 2005. On May 2, 2006 the Canadian
government tabled, in their budget, an elimination of capital taxes which
will, if passed, eliminate the capital taxes the Trust is currently paying by
monthly installments.
In the first quarter of 2006, a future income tax recovery of
$10.3 million was included in income compared to a $29.5 million recovery in
the first quarter of 2005.
ARC's expected future income tax rate is approximately 34 per cent
compared to the current rate of approximately 36 per cent applicable to the
2006 income tax year. In the Trust's structure, payments are made between ARC
Resources and the Trust, transferring both income and future tax liability to
the unitholders. At the current time, ARC does not anticipate any material
cash income taxes will be paid in fiscal 2006 by ARC Resources.
Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate increased to
$15.34 per boe in the first quarter of 2006 from $12.52 per boe in 2005. The
higher DD&A rate is due to the Redwater and NPCU acquisitions in late 2005 for
which the Trust recorded a higher proportionate cost per barrel of proved
reserves for the acquired properties compared to the existing ARC properties.
In addition, the higher asset retirement obligation recorded in 2005 has
resulted in higher accretion expense in 2006.
A breakdown of the DD&A rate is a follows:
-------------------------------------------------------------------------
Three months ended
DD&A rate March 31
($ thousands except per boe amounts) 2006 2005 % Change
-------------------------------------------------------------------------
Depletion of oil & gas assets(1) 86,547 61,215 41
Accretion of asset retirement obligation(2) 2,613 1,246 109
-------------------------------------------------------------------------
Total DD&A 89,160 62,461 43
DD&A rate per boe 15.34 12.52 23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
("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 period.
Goodwill
The goodwill balance of $157.6 million arose as a result of the
acquisition of Star Oil & Gas Ltd. ("Star") 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 an
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 March 31, 2006.
Capital Expenditures and Net Acquisitions
Total capital expenditures, excluding acquisitions and dispositions,
totaled $79 million in the first quarter of 2006 compared to $52.5 million in
the first quarter of 2005. This amount was incurred on drilling and
completions, land, geological, geophysical and facilities expenditures, as ARC
continues to develop its asset base. Due to favorable conditions in the field,
capital projects are ahead of schedule.
The Trust's strategy is to fully exploit its asset base and to increase
the recoverable portion of total oil and natural gas reserves in place on land
owned by the Trust.
In addition to the capital expenditures, the Trust completed minor
property acquisitions and property swaps of $33.8 million and $6.2 million of
dispositions for $27.6 million of net acquisitions, net of post closing
adjustments, in the first quarter of 2006. The execution of minor property
acquisitions and dispositions is part of the Trust's strategy to continually
high-grade its asset base by acquiring additional interests in properties
where ARC sees future upside potential and disposing of properties with
limited potential.
A breakdown of capital expenditures and net acquisitions is shown below:
-------------------------------------------------------------------------
Three months ended
March 31
Capital expenditures ($ thousands) 2006 2005 % Change
-------------------------------------------------------------------------
Geological and geophysical 2,718 1,262 115
Land 4,868 812 500
Drilling and completions 55,383 35,230 57
Plant and facilities 15,540 14,495 7
Other capital 536 721 (26)
-------------------------------------------------------------------------
Total capital expenditures 79,045 52,520 51
-------------------------------------------------------------------------
Producing property acquisitions(1) 33,825 3,844
Producing property dispositions(1) (6,212) (176)
-------------------------------------------------------------------------
Total capital expenditures and
net acquisitions 106,658 56,188 90
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital expenditures and net acquisitions
financed with cash flow 69,664 52,520
Capital expenditures and net acquisitions
financed with debt and equity 36,994 3,668
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
ARC expects to undertake significant development projects in 2006 to
fully execute the capital program of approximately $340 million.
Asset Retirement Obligation and Reclamation Fund
At March 31, 2006, the Trust has recorded an Asset Retirement Obligation
("ARO") of $167 million ($73.2 million at March 31, 2005) for future
abandonment and reclamation of the Trust's properties. The ARO increased by
$2.6 million for accretion expense, $0.6 million for development activities
and was reduced by $1.3 million for actual abandonment expenditures incurred
in the first quarter of 2006. The Trust did not record a gain or loss on
actual abandonment expenditures incurred to date in 2006 as the costs closely
approximated the liability value included in the ARO.
ARC contributed $1.5 million cash to its reclamation fund in the first
quarter of 2006 ($1.5 million in the first quarter of 2005) and earned
interest of $0.2 million ($0.2 million in 2005) on the fund balance. The fund
balance was reduced by $1.2 million for cash-funded abandonment expenditures
in the first quarter of 2006 ($1.1 million in the first quarter of 2005). This
fund, invested in money market instruments, is established to provide for
future abandonment and reclamation liabilities. Future contributions are
currently set at approximately $12 million per year and will vary over time in
order to provide for the total estimated future abandonment and reclamation
costs that are to be incurred upon the eventual abandonment of the Trust's
properties.
A breakdown of the Trust's capital structure is as follows:
-------------------------------------------------------------------------
Capitalization, financial resources and liquidity
($ thousands except per unit March 31, December 31,
and per cent amounts) 2006 2005
-------------------------------------------------------------------------
Revolving credit facilities 280,592 258,480
Senior secured notes 268,433 268,156
Working capital deficit(1) 49,886 51,450
-------------------------------------------------------------------------
Net debt obligations 598,911 578,086
Units outstanding and issuable for exchangeable
shares (thousands) 203,090 202,039
Market price per unit at end of period 27.36 26.49
Market value of units and exchangeable shares 5,556,542 5,352,013
Total capitalization(2) 6,155,453 5,930,099
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 9.7% 9.7%
Net debt obligations 598,911 578,086
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash flow from operations 191,200 639,511
Net debt to annualized cash flow 0.8 0.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The working capital deficit excludes the balances for commodity and
foreign currency contracts.
(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's bank facilities are consolidated into one syndicated credit
facility with a total base of $572 million. The debt is secured by all the
Trust's oil and gas properties.
As at March 31, 2006 net debt to total capitalization was 9.7 per cent
and net debt to annualized first quarter 2006 cash flow was approximately 0.8
times (0.9 times at December 31, 2005).
During the first quarter the Trust renewed and amended its syndicated
credit facilities. The renewed facility has a three year term, a credit limit
of $572 million and is governed by the following covenants:
- Long-term debt and letters of credit not to exceed three times net
income before non-cash items and interest expense.
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times net income before non-cash items and interest
expense.
- Long-term debt and letters of credit not to exceed 50 per cent of the
sum of unitholders' equity, 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. As at March 31, 2006, the Trust was in compliance
with all covenants, and had $4.4 million in letters of credit and no
subordinated debt.
The Trust funded 88 per cent of its first quarter capital development
program of $79 million with cash flow. The Trust intends to finance the
majority of the remaining $261 million portion of the $340 million 2006
capital development program with cash flow and proceeds from the distribution
reinvestment program ("DRIP") with the remainder financed with debt.
Unitholders' Equity
At March 31, 2006, there were 203.1 million units issued and issuable for
exchangeable shares, an increase of 1.1 million units from the 202 million
units at December 31, 2005. The increase in number of units outstanding is
mainly attributable to the 0.8 million units issued pursuant to the DRIP
during the quarter at an average price of $24.99 per unit.
The Trust had 1.2 million rights outstanding as of March 31, 2006 under
an employee plan discontinued in 2004. The rights have a five-year term and
vest equally over three years from the date of grant. The majority of rights
will be vested by May 6, 2006 and eligible to be purchased at an average
adjusted exercise price of $9.99 per unit as at March 31, 2006. Contractual
life of the rights varies by series but all series will expire on or before
March 22, 2009.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire 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.
Cash Distributions
ARC declared cash distributions of $119.9 million ($0.60 per unit),
representing 63 per cent of first quarter 2006 cash flow compared to cash
distributions of $83.9 million ($0.45 per unit), representing 59 per cent of
cash flow in the first quarter of 2005. The remaining 37 per cent of first
quarter 2006 cash flow ($71.3 million) was used to fund 88 per cent of ARC's
first quarter 2006 capital. The actual amount of cash flow withheld to fund
the Trust's capital expenditure program is dependent on the commodity price
environment and is at the discretion of the Board of Directors.
Cash flow and cash distributions in total and per unit for the first
quarters of 2006 and 2005 were as follows:
-------------------------------------------------------------------------
Three months Three months
ended ended
Cash flow and March 31 % March 31 %
distributions 2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
($ millions) ($ per unit)
Cash flow from operations 191.2 142.0 35 0.94 0.75 25
Reclamation fund
contributions(1) (1.7) (1.7) - (0.01) (0.01) -
Capital expenditures
funded with cash flow (69.6) (52.5) 33 (0.34) (0.27) 26
Discretionary debt
repayments - (3.9) - - - -
Other(2) - - 0.01 (0.02)
-------------------------------------------------------------------------
Cash distributions 119.9 83.9 43 0.60 0.45 33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balance that
is retained in the reclamation fund.
(2) Other represents the difference due to cash distributions paid being
based on actual units at each distribution date whereas per unit cash
flow, reclamation fund contributions and capital expenditures funded
with cash flow are based on weighted average units in the year.
Monthly cash distributions for the first quarter of 2006 were $0.20 per
unit and are 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.
The actual amount of future monthly cash distributions are proposed by
management and are subject to the approval and discretion of the Board of
Directors.
The Board reviews future cash distributions in conjunction with their
review of quarterly operating and financial results. The broad parameters used
in determining distributions include:
a) Setting a distribution level that will achieve a payout ratio not
exceeding 80 per cent, on an annual basis. This allows the Trust to
retain at least 20 per cent of cash flow to be utilized in funding
contributions to the reclamation fund and a portion of capital
expenditures;
b) Setting a payout ratio that allows for up to 100 per cent of capital
expenditures being funded from cash flow but that does not result in
the accumulation of cash within the Trust. The Trust's decision to
hold back cash flow to fund capital expenditures is predicated on the
Trust having attractive development opportunities on undeveloped
lands. The capital efficiency of development activities is
continuously monitored and subject to quarterly Board review in order
to ensure the appropriate balance between cash flow used to fund
development activities and distributions;
c) Setting a monthly distribution per unit that, in the opinion of
management and the Board, is sustainable for at least a six month
period.
Historical Cash Distributions by Calendar Year
The following table presents cash distributions paid in each calendar
period. Cash distributions for 2006 include distributions paid up to and
including April 15, 2006:
-------------------------------------------------------------------------
Calendar year Distributions(1) Taxable portion Return of capital
-------------------------------------------------------------------------
2006 YTD(2) 0.60(2) 0.59(2) 0.01(2)
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 $16.63 $9.93 $6.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on cash distributions paid in the calendar year.
(2) Based on cash distributions paid in 2006 up to and including
April 15, 2006 and estimated taxable portion of 2006 distributions of
98 per cent.
2006 Monthly Cash Distributions
Actual cash distributions paid for 2006 along with relevant payment dates
are as follows:
-------------------------------------------------------------------------
Ex-distribution Distribution Total
date Record date payment date distribution
-------------------------------------------------------------------------
December 28, 2005 December 31, 2005 January 16, 2006 0.20
January 27, 2006 January 31, 2006 February 15, 2006 0.20
February 24, 2006 February 28, 2006 March 15, 2006 0.20
March 29, 2006 March 31, 2006 April 17, 2006 0.20
April 26, 2006 April 30, 2006 May 15, 2006 0.20
May 29, 2006 May 31, 2006 June 15, 2006 (x)0.20
June 28, 2006 June 30, 2006 July 17, 2006 (x)0.20
July 27, 2006 July 31, 2006 August 15, 2006
August 29, 2006 August 31, 2006 September 15, 2006
September 27, 2006 September 30, 2006 October 16, 2006
October 27, 2006 October 31, 2006 November 15, 2006
November 28, 2006 November 30, 2006 December 15, 2006
-------------------------------------------------------------------------
(x) Estimated
Taxation of Cash Distributions
Cash distributions comprise a return of capital portion (tax deferred)
and a return on capital portion (taxable). The return of capital component
reduces the cost basis of the trust units held. For a more detailed breakdown,
please visit our website at www.arcenergytrust.com.
For 2006, it is estimated that cash distributions paid in the calendar
year will be approximately 98 per cent return on capital (taxable) and two per
cent return of capital (tax deferred). Actual taxable amounts may differ from
the estimated amount as they are dependent on commodity prices experienced
throughout the year. Changes in the estimated taxable and deferred portion of
the distributions will be announced quarterly.
The exchangeable shares of ARC Resources Limited (ARL) may provide a more
tax-effective basis for investment in the Trust. The ARL exchangeable shares
are traded on the TSX under the symbol "ARX" and are convertible into units,
at the option of the shareholder, based on the then current exchange ratio.
Exchangeable shareholders are not eligible to receive monthly cash
distributions, however the exchange ratio increases on a monthly basis by an
amount equal to the current month's unit distribution multiplied by the then
current exchange ratio and divided by the 10 day weighted average trading
price of the units at the end of each month. The gain realized as a result of
the monthly increase in the exchange ratio is taxed, in most circumstances, as
a capital gain rather than income and is therefore subject to a lower
effective tax rate. Tax on the exchangeable shares is deferred until the
exchangeable share is sold or converted into a trust unit.
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. These obligations are of a recurring and consistent nature
and impact cash flow in an ongoing manner. The following is a summary of the
Trust's contractual obligations and commitments as at March 31, 2006:
-------------------------------------------------------------------------
Payments due by period
-------------------------------------------------------------------------
2007 - 2009 - There-
($ millions) 2006 2008 2010 after Total
-------------------------------------------------------------------------
Debt repayments - 20.9 329.6 198.5 549.0
Reclamation fund
contributions(1) 6.1 11.8 10.2 80.9 109.0
Purchase commitments 2.4 3.4 3.2 8.0 17.0
Operating leases 3.3 8.4 8.5 - 20.2
Derivative contract
premiums(2) 12.6 4.2 1.7 - 18.5
Retention bonuses 1.0 1.0 - - 2.0
-------------------------------------------------------------------------
Total contractual
obligations 25.4 49.7 353.2 287.4 715.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Contribution commitments to a restricted reclamation fund associated
with the Redwater property acquired in the Redwater and NPCU
acquisition.
(2) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
In addition to the above, the Trust has commitments related to its risk
management program.
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.
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 2006 capital budget has
been approved by the Board at $340 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.
Off Balance Sheet Arrangements
The Trust has certain lease agreements that are entered into in the
normal course of operations. All leases are 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 March 31, 2006.
The Trust entered into agreements to pay premiums pursuant to certain
crude oil derivative put contracts. Premiums of approximately $18.5 million
will be paid in 2006 to 2009 for the put contracts in place at March 31, 2006.
As the premiums are part of the underlying derivative contract, they have been
recorded at fair market value at March 31, 2006 on the balance sheet.
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:
a) 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;
b) estimated capital expenditures on projects that are in progress;
c) estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves which the Trust expects to recover
in the future;
d) estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and
foreign exchange rates;
e) estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
f) estimated future recoverable value of property, plant and equipment
and goodwill.
The Trust has hired individuals and consultants who have the skill set to
make such estimates and ensures 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.
Objectives and 2006 Outlook
It is the Trust's objective to provide the highest possible long-term
returns to unitholders by focusing on the key strategic objectives of the
business plan.
To the end of the first quarter of 2006, the Trust has provided
cumulative cash distributions of $16.63 per unit and capital appreciation of
$17.36 per unit for a total return of $33.99 per unit (27.8 per cent
annualized total return) for unitholders who invested in the Trust at
inception in July of 1996. During the first quarter of 2006, the Trust
provided unitholders with a total return of 5.5 per cent.
During 2006, ARC will continue to be active with a robust drilling and
development program on its diverse asset base. The $340 million capital
expenditure budget for 2006 is the largest in the Trust's history excluding
acquisitions. The Trust will prudently deploy capital with a balanced drilling
program of low and moderate risk wells. The Trust continues to focus on major
properties with significant upside, with the objective to replace production
declines through internal development opportunities.
Current low debt levels and a strong working capital position provide the
Trust with the financial flexibility to fund the 2006 capital expenditure
program and be poised to take advantage of accretive acquisition
opportunities. The Trust continually reviews potential acquisitions of both
conventional oil and natural gas reserves and in the broader energy industry.
Acquisitions are evaluated internally and acquisitions in excess of
$25 million are subject to Board approval.
Following is a summary of the Trust's 2006 Guidance:
2006 2006
Revised Previous 2006 %
guidance guidance Actual Q1 Variance
-------------------------------------------------------------------------
Production (boe/d) 62,000 61,000 64,600 6
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 8.65 8.65 7.80 (10)
Transportation 0.70 0.70 0.61 (13)
G&A expenses - cash 1.70 1.70 1.32 (22)
G&A expenses - stock
compensation plans 0.65 0.65 0.96 47
Interest 1.40 1.40 1.31 (6)
Cash taxes - 0.15 0.11 (15)
-------------------------------------------------------------------------
Capital expenditures 340 over 4 340 over 4
($ millions) quarters quarters 79 7
-------------------------------------------------------------------------
Units (millions)(1) 205 205 202 (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Weighted average trust units and units issuable.
Due to the strong results from ARC's winter development program, first
quarter 2006 production was ahead of budget. As a result, ARC has increased
its production guidance for the full year 2006 to 62,000 boe per day.
The variance-to-date for operating costs on a boe basis is attributed to
the seasonality of operating costs and the strong production results achieved
in the first quarter. As workover and maintenance activities are undertaken in
the second and third quarters, the Trust expects that higher costs in those
quarters will result in annual operating costs that will more closely
approximate the guidance of $8.65 per boe.
Overall G&A expense at $2.28 per boe was down slightly from the guidance
of $2.35 per boe. This is due to higher production volumes versus guidance.
Cash G&A expense was lower than guidance and accrued stock compensation plan
expense was higher than guidance. These variances will offset one another when
actual cash payouts for stock compensation plan occur in the second quarter of
2006.
Interest expense in the first quarter of 2006 was lower than the guidance
target for 2006 as a result of strong cash flow in the quarter that resulted
in the Trust funding 88 per cent of its capital program with cash rather than
debt. Consequently, debt levels and the corresponding interest expense were
lower than anticipated during the first quarter of 2006. However, the Trust
expects interest to closely approximate the annual guidance of $1.40 per boe
for the full year.
Taxes for the first quarter of 2006 were below the guidance level as a
result of higher average production in the first quarter compared to the
annual average guidance. On May 2, 2006 the Canadian government tabled, in
their budget, an elimination of corporate capital taxes for 2006, which will,
if passed, eliminate capital taxes the Trust is currently paying in monthly
installments.
To the end of the first quarter, the Trust had incurred $79 million of
capital expenditures pursuant to the $340 million of the 2006 capital
development program. The Trust has significant capital development projects
planned for the remainder of 2006 whereby the Trust expects to meet the annual
2006 capital expenditure guidance target.
See "Outlook" in the Trust's Annual Report MD&A for additional discussion
of the Trust's key future objectives.
2006 Cash Flow
Below is a table that illustrates sensitivities to pre-hedged cash flow
with operational changes and changes to the business environment:
-------------------------------------------------------------------------
Impact on
annual
cash flow
Business environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/barrel)(1) $ 65.00 $ 1.00 $ 0.05
Natural gas price (CDN$AECO/mcf)(1) $ 7.50 $ 0.10 $ 0.03
USD/CAD exchange rate $ 0.87 $ 0.01 $ 0.05
Interest rate on debt 5.2% 1.0% $ 0.03
-------------------------------------------------------------------------
Operational
Liquids production volume (bbls/d) 31,700 1.0% $ 0.02
Gas production volumes (mmcf/d) 182.0 1.0% $ 0.02
Operating expenses per boe $ 8.50 1.0% $ 0.01
Cash G&A expenses per boe $ 1.70 10.0% $ 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Analysis does not include the effect of derivative contracts.
Assessment of Business Risks
The ARC management team is focused on long-term strategic planning and
has identified the key risks, uncertainties and opportunities associated with
the Trust's business that can impact the financial results. See "Assessment of
Business Risks" in the Trust's 2005 Annual Report MD&A for a detailed
assessment.
Additional Information
Additional information relating to ARC can be found on SEDAR at
www.sedar.com.
QUARTERLY REVIEW
(CDN$ thousands,
except per unit
amounts) 2006 2005
-------------------------------------------------------------------------
FINANCIAL Q1 Q4 Q3 Q2 Q1
Revenue before
royalties 318,931 365,298 310,249 251,596 238,054
Per unit(1) 1.58 1.89 1.62 1.32 1.26
Cash flow 191,200 207,621 168,117 121,808 141,965
Per unit - basic(1) 0.94 1.07 0.88 0.64 0.75
Per unit - diluted 0.94 1.07 0.87 0.63 0.74
Net income(5) 104,071 130,474 114,600 73,215 38,646
Per unit - basic(5) 0.52 0.68 0.61 0.39 0.21
Per unit - diluted 0.52 0.68 0.59 0.38 0.20
Cash distributions 119,867 115,671 92,559 84,468 83,867
Per unit(2) 0.60 0.60 0.49 0.45 0.45
Total assets 3,279,721 3,251,161 2,483,540 2,427,463 2,303,948
Total liabilities 1,434,090 1,415,519 912,160 895,179 785,776
Net debt outstanding(4) 598,911 578,086 357,560 366,216 254,252
Weighted average units
(thousands)(3) 202,479 193,445 191,709 190,315 189,210
Units outstanding and
issuable at period
end (thousands) 203,090 202,039 192,089 191,329 189,609
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
($ thousands)
Geological and
geophysical 2,718 3,040 2,258 2,659 1,262
Land 4,868 5,540 2,048 889 812
Drilling and
completions 55,383 60,150 63,628 32,576 35,230
Plant and facilities 15,540 17,031 14,803 8,703 14,495
Other capital 536 2,020 317 652 721
Total capital
expenditures 79,045 87,781 83,054 45,479 52,520
Property acquisitions
(dispositions) net 27,613 3,037 5,860 78,721 3,668
Corporate acquisitions(6) - 462,814 - 42,182 -
Total capital
expenditures and
net acquisitions 106,658 553,632 88,914 166,382 56,188
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,651 25,534 23,513 22,046 21,993
Natural gas (mmcf/d) 185.0 177.9 168.2 173.1 176.1
Natural gas liquids
(bbl/d) 4,120 3,943 4,047 3,962 4,072
Total (boe/d 6:1) 64,600 59,120 55,592 54,860 55,410
Average prices
Crude oil ($/bbl) 59.53 62.12 69.37 58.37 53.63
Natural gas ($/mcf) 8.40 12.05 9.08 7.42 7.20
Natural gas liquids
($/bbl) 52.91 57.14 50.43 46.13 46.57
Oil equivalent
($/boe)(7) 54.86 67.16 60.66 50.40 47.74
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading)
Unit prices
High 27.51 27.58 24.2 20.30 20.40
Low 25.09 20.45 19.94 16.88 16.55
Close 27.36 26.49 24.10 19.94 18.15
Average daily volume
(thousands) 546 653 599 605 895
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(CDN$ thousands,
except per unit
amounts) 2004
-----------------------------------------------------
FINANCIAL Q4 Q3 Q2
Revenue before
royalties 232,112 230,769 233,307
Per unit(1) 1.23 1.23 1.26
Cash flow 106,935 110,835 122,249
Per unit - basic(1) 0.57 0.59 0.66
Per unit - diluted 0.56 0.59 0.65
Net income(5) 112,995 38,897 50,338
Per unit - basic(5) 0.61 0.21 0.28
Per unit - diluted 0.60 0.21 0.27
Cash distributions 83,531 83,178 82,053
Per unit(2) 0.45 0.45 0.45
Total assets 2,304,998 2,316,297 2,309,599
Total liabilities 755,650 804,603 768,073
Net debt outstanding(4) 264,842 220,500 220,074
Weighted average units
(thousands)(3) 188,521 184,675 184,998
Units outstanding and
issuable at period
end (thousands) 188,804 187,629 187,296
-----------------------------------------------------
CAPITAL EXPENDITURES
($ thousands)
Geological and
geophysical 867 828 1,373
Land 2,484 798 584
Drilling and
completions 36,641 41,755 24,283
Plant and facilities 6,183 11,668 7,282
Other capital 1,480 394 605
Total capital
expenditures 47,655 55,443 34,127
Property acquisitions
(dispositions) net (1,036) (5,345) (53,412)
Corporate acquisitions(6) 41,449 - 30,560
Total capital
expenditures and
net acquisitions 88,068 50,098 11,275
-----------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 22,969 22,496 22,720
Natural gas (mmcf/d) 174.7 177.4 186.7
Natural gas liquids
(bbl/d) 4,097 4,034 4,313
Total (boe/d 6:1) 56,179 56,096 58,147
Average prices
Crude oil ($/bbl) 49.48 51.00 47.43
Natural gas ($/mcf) 6.82 6.65 6.99
Natural gas liquids
($/bbl) 43.72 42.30 38.22
Oil equivalent
($/boe)(7) 44.62 44.72 44.09
-----------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading)
Unit prices
High 17.98 17.38 15.74
Low 14.80 15.02 14.28
Close 17.90 16.85 15.35
Average daily volume
(thousands) 456 384 337
-----------------------------------------------------
-----------------------------------------------------
(1) Based on weighted average units plus units issuable for exchangeable
shares.
(2) Based on number of units outstanding at each cash distribution date.
(3) Includes units issuable for outstanding exchangeable shares.
(4) Total current and long-term debt net of working capital. Net debt
excludes commodity and foreign currency contracts, the deferred hedge
loss and deferred commodity and foreign currency contracts.
(5) Net income in the basic per unit calculation has been reduced by
interest in the convertible debentures.
(6) Represents total consideration for the corporate acquisition
including fees but prior to working capital asset retirement
obligations and future income tax liability assumed on acquisition.
(7) Includes other revenue
CONSOLIDATED BALANCE SHEETS
As at March 31 and December 31 (unaudited)
($CDN thousands) 2006 2005
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 8,737 $ -
Accounts receivable 105,590 122,956
Prepaid expenses 16,776 14,020
Commodity and foreign currency contracts
(Note 4) 16,467 3,125
-------------------------------------------------------------------------
147,570 140,101
Reclamation fund 23,922 23,491
Property, plant and equipment 2,950,637 2,929,977
Goodwill 157,592 157,592
-------------------------------------------------------------------------
Total assets $3,279,721 $3,251,161
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 140,924 $ 148,587
Cash distributions payable 40,066 39,839
Commodity and foreign currency contracts
(Note 4) 15,419 7,167
-------------------------------------------------------------------------
196,409 195,593
Long-term debt (Note 2) 549,025 526,636
Other long-term liabilities (Note 3) 16,101 12,360
Asset retirement obligations (Note 5) 166,951 165,053
Future income taxes 505,604 515,877
-------------------------------------------------------------------------
Total liabilities 1,434,090 1,415,519
-------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 12)
NON-CONTROLLING INTEREST
Exchangeable shares (Note 6) 37,644 37,494
UNITHOLDERS' EQUITY
Unitholders' capital (Note 7) 2,255,199 2,230,842
Contributed surplus (Note 8) 7,660 6,382
Accumulated earnings 1,339,813 1,235,742
Accumulated cash distributions (Note 10) (1,794,685) (1,674,818)
-------------------------------------------------------------------------
Total unitholders' equity 1,807,987 1,798,148
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $3,279,721 $3,251,161
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED EARNINGS
For the three months ended March 31 (unaudited)
($CDN thousands, except per unit amounts) 2006 2005
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and natural gas liquids $ 318,931 $ 238,054
Royalties (62,241) (44,839)
-------------------------------------------------------------------------
256,690 193,215
Gain (loss) on commodity and foreign
currency contracts (Note 4)
Realized (1,384) (7,314)
Unrealized 5,090 (66,687)
-------------------------------------------------------------------------
260,396 119,214
-------------------------------------------------------------------------
EXPENSES
Transportation 3,538 3,586
Operating 45,376 30,441
General and administrative 13,240 8,147
Interest on long-term debt (Note 2) 7,602 3,139
Depletion, depreciation and accretion 89,160 62,461
Loss on foreign exchange 5,564 1,027
-------------------------------------------------------------------------
164,480 108,801
-------------------------------------------------------------------------
Income before taxes 95,916 10,413
Capital taxes (622) (650)
Future income tax recovery 10,272 29,500
-------------------------------------------------------------------------
Net income before non-controlling interest 105,566 39,263
Non-controlling interest (Note 6) (1,495) (617)
-------------------------------------------------------------------------
Net income 104,071 38,646
-------------------------------------------------------------------------
Accumulated earnings, beginning of period 1,235,742 878,807
-------------------------------------------------------------------------
Accumulated earnings, end of period $1,339,813 $ 917,453
-------------------------------------------------------------------------
Net income per unit (Note 11)
Basic $ 0.52 $ 0.21
Diluted $ 0.52 $ 0.20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three months ended March 31 (unaudited)
($CDN thousands) 2006 2005
-------------------------------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 104,071 $ 38,646
Add items not involving cash:
Non-controlling interest 1,495 617
Future income tax recovery (10,272) (29,500)
Depletion, depreciation and accretion 89,160 62,461
Non-cash (gain) loss on commodity and
foreign currency contracts (Note 4) (5,090) 66,687
Non-cash loss on foreign exchange 5,584 1,073
Non-cash trust unit incentive compensation
(Notes 8 and 9) 6,252 1,981
Expenditures on site restoration and reclamation (1,265) (1,047)
Change in non-cash working capital (841) (12,182)
-------------------------------------------------------------------------
189,094 128,736
-------------------------------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES
Issuance of long-term debt, net 16,847 5,034
Issue of trust units 2,820 3,059
Trust unit issue costs (245) (2)
Cash distributions paid, net of distribution
reinvestment (99,699) (75,045)
Change in non-cash working capital 3,951 1,847
-------------------------------------------------------------------------
(76,326) (65,107)
-------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of petroleum and
natural gas properties (28,825) (3,844)
Proceeds on disposition of petroleum and
natural gas properties 1,212 176
Capital expenditures (78,604) (47,854)
Net reclamation fund contributions (431) (574)
Change in non-cash working capital 2,617 (15,946)
-------------------------------------------------------------------------
(104,031) (68,042)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 8,737 (4,413)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD - 4,413
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 8,737 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2006 and 2005 (unaudited)
(all tabular amounts in thousands, except per unit and volume amounts)
1. SUMMARY OF ACCOUNTING POLICIES
The unaudited interim consolidated financial statements follow the
same accounting policies as the most recent annual audited financial
statements. The interim consolidated financial statement note
disclosures do not include all of those required by Canadian
generally accepted accounting principles ("GAAP") applicable for
annual financial statements. Accordingly, these interim financial
statements should be read in conjunction with the audited
consolidated financial statements included in the Trust's 2005 annual
report.
2. LONG-TERM DEBT
March 31, December 31,
2006 2005
---------------------------------------------------------------------
Revolving credit facilities
Syndicated Credit Facility $ 280,592 $ 254,680
Working capital facility - 3,800
Senior secured notes
5.42% USD Note 87,532 87,443
4.94% USD Note 35,013 34,977
4.62% USD Note 72,944 72,868
5.10% USD Note 72,944 72,868
---------------------------------------------------------------------
Total long-term debt outstanding $ 549,025 $ 526,636
---------------------------------------------------------------------
---------------------------------------------------------------------
During the first quarter for 2006, the Trust entered into a
$572 million secured, extendible, financial covenant based three year
syndicated credit facility that expires in March 2009 and a
$25 million demand working capital facility. The credit facility is
extendible annually, security is in the form of floating charges on
all lands and assignments.
Various borrowing options exist under the credit facility including
prime rate advances, bankers' acceptances and LIBOR based loans
denominated in either Canadian or U.S. dollars. All drawings under
the facility are subject to stamping fees that vary between 65 bps
and 115 bps depending on certain consolidated financial ratios.
The following represents the significant financial covenants
governing the credit facility:
- Long-term debt and letters of credit not to exceed three times net
income before non-cash items and interest expense;
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times 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. As at March 31, 2006,
the Trust was in compliance with all covenants and had $4.4 million
in letters of credit and no subordinated debt.
During 2006, the weighted-average effective interest rate under the
credit facility was 4.4 per cent (2.5 per cent in the first three
months of 2005).
Amounts due under 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 the period did not differ significantly from
interest expense.
3. OTHER LONG-TERM LIABILITIES
March 31, December 31,
2006 2005
---------------------------------------------------------------------
Retention bonuses $ 1,000 $ 1,000
Accrued long-term incentive compensation 15,101 11,360
---------------------------------------------------------------------
Total other long-term liabilities $ 16,101 $ 12,360
---------------------------------------------------------------------
---------------------------------------------------------------------
The retention bonuses arose upon internalization of the management
contract in 2002. The long-term portion of retention bonuses will be
paid in August 2007.
The accrued long-term incentive compensation represents the long-term
portion of the Trust's estimated liability for the Whole Unit Plan as
at March 31, 2006 (see Note 9). This amount is payable in 2007 and
2008.
4. FINANCIAL INSTRUMENTS
The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices and foreign exchange
rates. 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 derivative contracts in place as at
March 31, 2006:
Financial WTI Crude Oil Sales Contracts
Bought Sold
Volume put Sold put call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
2006
Apr 06 - Jun 06 Put Spread 2,000 50.00 40.00 -
Apr 06 - Dec 06 Put Spread 1,000 55.00 45.00 -
Apr 06 - Dec 06 Bought Put 1,000 55.00 - -
Apr 06 - Jul 06 Bought Put 130 64.50 - -
Apr 06 - Sep 06 Put Spread 2,000 65.00 55.00 -
Apr 06 - Dec 06 Put Spread 2,000 55.00 45.00 -
Apr 06 - Dec 06 Bought Put 2,000 50.00 - -
Apr 06 - Dec 06 3-Way Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------
Remaining
2006 Weighted
Average 13,050 55.04 43.50 90.00
---------------------------------------------------------------------
2007
Jan 07 - Dec 07 3-Way Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------
2008
Jan 08 - Dec 08 3-Way Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------
2009
Jan 09 - Dec 09 3-Way Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------
Energy Equivalent Swap
Term Contract Volume Swap Bought Put
---------------------------------------------------------------------
Financial Cdn$ Crude Oil Purchase Contract
Apr 06 -
Jul 06 Swap 3,870 bbl/d 73.79 CDN$/bbl -
Financial WTI Crude Oil Sales Contract
Apr 06 -
Jul 06 Bought Put 3,870 bbl/d - 64.50 US$/bbl
Financial AECO Natural Gas Sales Contract
Apr 06 -
Aug 06 Swap 40,000 GJ/d 7.09 CDN$/GJ -
USD Sales Contracts
Apr 06 -
Jul 06 Swap 32.0 MM US$ 1.1618 CDN$/US$ -
---------------------------------------------------------------------
Financial AECO Natural Gas Sales Contracts
Volume Bought Put Sold Put
Term Contract GJ/d CDN$/GJ CDN$/GJ
---------------------------------------------------------------------
2006
Apr 06 - Aug 06 Put Spread 20,000 7.15 5.65
Apr 06 - Oct 06 Put Spread 20,000 7.50 5.50
Apr 06 - Oct 06 Put Spread 10,000 9.00 7.00
---------------------------------------------------------------------
Remaining
2006 Weighted Average 34,473 7.73 5.86
---------------------------------------------------------------------
Financial Natural Gas AECO Basis Contracts
Volume Swap
Term Contract GJ/d US$/mmbtu
---------------------------------------------------------------------
2006
Apr 06 - Oct 06 Swap 2,000 (1.19)
---------------------------------------------------------------------
Remaining
2006 Weighted Average 1,556 (1.19)
---------------------------------------------------------------------
Financial Foreign Exchange Contracts
Volume Swap