Crescent Point Energy Trust Announces Fourth Quarter 2008 Results and Year End Reserves
CALGARY, March 16, 2009 /CNW/ - Crescent Point Energy Trust ("Crescent
Point" or the "Trust") (TSX: CPG.UN) is pleased to announce its unaudited
operating and financial results for the fourth quarter and year ended December
31, 2008.FINANCIAL AND OPERATING HIGHLIGHTS
-------------------------------------------------------------------------
Three months ended
($000, except trust December 31 Year ended December 31
units, per trust -------------------------------------------------------
unit and per % %
boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Financial
Funds flow from
operations(1)(8) 109,635 112,572 (3) 592,132 355,910 66
Per
unit(1)(2)(8) 0.87 0.99 (12) 4.73 3.51 35
Net income
(loss)(3)(8) 361,411 (90,348) 500 464,102 (32,167) 1,543
Per
unit(2)(3)(8) 2.84 (0.80) 455 3.71 (0.32) 1,259
Cash
distributions 86,314 67,971 27 324,821 245,108 33
Per unit 0.69 0.60 15 2.61 2.40 9
Payout
ratio (%)(1)(8) 79 60 19 55 69 (14)
Per unit
(%)(1)(2)(8) 79 61 18 55 68 (13)
Net debt(1)(4) 730,932 650,088 12 730,932 650,088 12
Capital
acquisitions
(net)(5) (705) 408,377 (100) 140,851 1,068,406 (87)
Development
capital
expenditures 92,855 95,385 (3) 454,533 227,923 99
Weighted average
trust units
outstanding (mm)
Basic 125.1 113.1 11 124.0 100.7 23
Diluted 127.4 114.6 11 125.9 102.1 23
-------------------------------------------------------------------------
Operating
Average daily
production
Crude oil and
NGLs (bbls/d) 34,897 28,601 22 32,583 24,349 34
Natural gas
(mcf/d) 27,941 28,500 (2) 28,883 22,610 28
-------------------------------------------------------------------------
Total (boe/d) 39,554 33,351 19 37,397 28,117 33
-------------------------------------------------------------------------
Average selling
prices(6)
Crude oil and
NGLs ($/bbl) 60.02 75.31 (20) 94.36 67.33 40
Natural gas
($/mcf) 7.23 6.32 14 8.36 6.52 28
-------------------------------------------------------------------------
Total ($/boe) 58.06 69.99 (17) 88.67 63.55 40
-------------------------------------------------------------------------
Netback ($/boe)
Oil and gas
sales 58.06 69.99 (17) 88.67 63.55 40
Royalties (9.53) (12.81) (26) (16.09) (11.59) 39
Operating
expenses (9.23) (9.19) - (9.01) (9.25) (3)
Transportation (1.60) (1.83) (13) (1.87) (1.73) 8
-------------------------------------------------------------------------
Netback prior
to realized
derivatives 37.70 46.16 (18) 61.70 40.98 51
Realized gain
(loss) on
derivatives(7) 2.72 (3.68) 174 (8.77) (0.96) 814
-------------------------------------------------------------------------
Operating
netback 40.42 42.48 (5) 52.93 40.02 32
-------------------------------------------------------------------------
The Crescent Point financial and operating results do not reflect the
production or cash flows of Shelter Bay Energy Inc. ("Shelter Bay") other
than the production and cash flows associated with the Trust's interests
in the wells farmed out to Shelter Bay by the Trust. Crescent Point
accounts for its investment in Shelter Bay using the equity method of
accounting. Accordingly, the Trust records its share of Shelter Bay net
income or loss in the "equity and other income" caption on the
consolidated statements of operations, comprehensive income and deficit.
(1) Funds flow from operations, payout ratio and net debt as presented do
not have any standardized meaning prescribed by Canadian generally
accepted accounting principles and, therefore, may not be comparable
with the calculation of similar measures presented by other entities.
(2) The per unit amounts (with the exception of per unit distributions)
are the per unit - diluted amounts. The net income and funds flow per
unit - diluted amounts exclude the cash portion of unit-based
compensation.
(3) The net income of $361.4 million for the fourth quarter of 2008
includes unrealized derivative gains of $416.8 million and net income
of $464.1 million for the year ended December 31, 2008 includes
unrealized derivative gains of $294.3 million.
(4) Net debt includes bank indebtedness, working capital and long term
investments, but excludes the risk management liabilities and assets.
(5) Capital acquisitions represent total consideration for the
transactions including bank debt and working capital assumed.
(6) The average selling prices reported are before realized derivatives
and transportation charges.
(7) The realized derivative loss for the year ended December 31, 2008
excludes a $34.5 million loss on the derivative crystallization of
various oil contracts completed in the second quarter of 2008.
(8) Fourth quarter 2008 funds flow from operations of $109.6 million
includes a $19.4 million bad debt provision for SemCanada. Funds flow
from operations and the net income for the year ended December 31,
2008 include the $34.5 million loss on the derivative crystallization
and $19.4 million bad debt provision for SemCanada. Excluding these
funds flow from operations for the year ended December 31, 2008 would
be $646.0 million or $5.16 per unit - diluted, net income would be
$518.0 million or $4.14 per unit - diluted and the payout ratio would
be 50 percent and 51 percent per unit - diluted.
HIGHLIGHTS
In the fourth quarter of 2008, Crescent Point continued to execute its
integrated business strategy of acquiring, exploiting and developing high
quality, long life light and medium oil and natural gas properties.
- Crescent Point grew fourth quarter 2008 average daily production by 5
percent over third quarter 2008 and exceeded guidance by more than
2,800 boe/d. The Trust produced 39,554 boe/d for the quarter, up from
37,630 boe/d in the third quarter and up 19 percent from 33,351 boe/d
in the fourth quarter of 2007.
- Crescent Point exceeded its original 2008 production guidance by more
than 4,000 boe/d, or 13 percent, due to its expanded and successful
drilling program. Including acquisitions, the Trust exceeded original
guidance by more than 6,000 boe/d. Production averaged 37,397 boe/d
in 2008.
- The Trust increased proved plus probable reserves by 14 percent to
191.0 million boe ("mmboe") at year end 2008, increasing its reserve
life index to 13.7 years from 13.3 years. Proved reserves also
increased by 14 percent to 132.1 mmboe at year end 2008.
- Including the acquisition of Villanova Energy Corporation
("Villanova"), which closed January 15, 2009, the Trust's reserves
increased to 196.5 mmboe proved plus probable, and its reserve life
index to 14.1 years.
- Crescent Point replaced 226 percent of 2008 production on a proved
plus probable basis, excluding reserves added through acquisitions.
This is the seventh straight year of strong positive technical
reserve revisions.
- The Trust grew year end Bakken reserves by 35 percent over 2007 to
94.8 mmboe proved plus probable, which included 27.0 mmboe of
technical revisions in 2008.
- Crescent Point achieved 2008 finding and development ("F&D") costs of
$9.37 per proved plus probable boe and $11.07 per proved boe of
reserves, excluding capital expenditures on facilities, land and
seismic. The Trust spent $164.4 million in 2008 on facilities, land
and seismic, approximately 36 percent of capital spending, in
preparation for the long term growth of the Bakken resource play.
- Including facilities, land and seismic expenditures, F&D costs were
$14.67 per proved plus probable boe and $17.33 per proved boe of
reserves. This represents recycle ratios of 4.2 and 3.6 for proved
plus probable and proved, respectively.
- Crescent Point achieved 2008 finding, development and acquisition
("FD&A") costs of $15.97 per proved plus probable boe and $19.69 per
proved boe, including expenditures on facilities, land and seismic.
Recycle ratios were 3.9 and 3.1 for proved plus probable and proved,
respectively.
-------------------------------------------------------------------------
Proved plus
Per boe, except Recycle Ratios Probable Proved
-------------------------------------------------------------------------
F&D
-------------------------------------------------------------------------
2008 cost, excluding change in FDC(1) $14.67 $17.33
-------------------------------------------------------------------------
2008 average recycle ratio(2) 4.2 3.6
-------------------------------------------------------------------------
2008 cost, including change in FDC $20.91 $24.29
-------------------------------------------------------------------------
7-yr weighted avg cost, excluding change in FDC $9.49 $12.85
-------------------------------------------------------------------------
-------------------------------------------------------------------------
FD&A
-------------------------------------------------------------------------
2008 cost, excluding change in FDC $15.97 $19.69
-------------------------------------------------------------------------
2008 average recycle ratio(2) 3.9 3.1
-------------------------------------------------------------------------
2008 cost, including change in FDC $21.17 $25.75
-------------------------------------------------------------------------
7-yr weighted avg cost, excluding change in FDC $13.85 $18.47
-------------------------------------------------------------------------
(1) Future Development Capital.
(2) Based on 2008 average operating netback (excluding realized hedging
losses) of $61.70/boe.
- Crescent Point increased its net asset value ("NAV") per unit by 16
percent to $34.97 at year end 2008 from $30.05 at year end 2007,
based on independent engineering evaluations of reserves and
escalated price assumptions discounted at 10 percent.
- The Trust spent $92.9 million on development capital activities in
the fourth quarter, including $30.7 million on facilities, land and
seismic. The Trust spent $62.2 million on drilling and completions
activities, including the drilling of 49 (33.7 net) wells with a 98
percent success rate.
- Crescent Point's funds flow from operations decreased by 3 percent to
$109.6 million ($0.87 per unit - diluted) in the fourth quarter of
2008, compared to $112.6 million ($0.99 per unit - diluted) in the
fourth quarter of 2007. During the fourth quarter of 2008, the Trust
recorded a provision of $19.4 million in respect of its previously
announced exposure to SemCanada Crude Company ("SemCanada").
Excluding this provision, Crescent Point's funds flow from operations
was $129.0 million ($1.02 per unit - diluted).
- The Trust's netback decreased to $40.42 per boe in the fourth quarter
from $42.48 in the fourth quarter of 2007. During the quarter, the
Trust realized an operating netback of $48.21 per boe on its Bakken
production.
- Crescent Point maintained consistent monthly distributions of $0.23
per unit, totaling $0.69 per unit for the fourth quarter of 2008.
This is up from $0.60 per unit paid in the fourth quarter of 2007 and
resulted in a payout ratio of 79 percent on a per unit - diluted
basis, up from 61 percent in 2007. Excluding the SemCanada provision,
Crescent Point's payout ratio was 68 percent on a per unit - diluted
basis.
- On January 15, 2009, the Trust closed the previously announced
acquisition of Villanova, adding approximately 1,750 boe/d of
focused, high netback oil production, 95 percent of which is in the
Bakken play. The acquisition added 26 net sections of undeveloped
Bakken land and 47 net low risk Bakken drilling locations to the
Trust's inventory.
- In January of 2009, Crescent Point increased its calendar 2009
hedging position to provide increased certainty over cash flow and
distributions for the year and to take advantage of rising prices in
the forward market for crude oil. As at March 3, 2009, the Trust had
hedged 57 percent, 42 percent, 27 percent and 14 percent of
production, net of royalty interest, for the balance of 2009, 2010,
2011 and the first six months of 2012, respectively. Average
quarterly hedge prices range from Cdn$74 per boe to Cdn$108 per boe.
- On January 9, 2009, Crescent Point closed a previously announced
bought deal equity financing of 5.2 million trust units at $22.00 per
trust unit for gross proceeds of approximately $115 million.
- During the fourth quarter, Crescent Point invested $78.7 million in a
private financing by Shelter Bay Energy Inc. ("Shelter Bay") and
$20.0 million in a private financing by Wild River Resources Ltd.
("Wild River"). The $78.7 investment in Shelter Bay brings the
Trust's total investment in Shelter Bay to approximately $200 million
or 21 percent ownership. The $20.0 million investment in Wild River
represents a 17 percent ownership of the private Bakken and Lower
Shaunavon producer.
- During 2008, Crescent Point's borrowing base was increased to $1.15
billion from $800 million. The Trust's balance sheet remains strong
with projected 2009 net debt to 12 month cash flow of 1.1 times.OPERATIONS REVIEW
Forward-Looking Statements
Certain statements contained in this report constitute forward-looking
statements. All forward-looking statements are based on Crescent Point's
beliefs and assumptions based on information available at the time the
assumption was made. The use of any of the words "anticipate", "continue",
"estimate", "expect", "may", "will", "project", "should", "believe" and
similar expressions are intended to identify forward-looking statements. By
their nature, such forward-looking statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking statements.
Crescent Point believes that the expectations reflected in those forward-
looking statements are reasonable but no assurance can be given that these
expectations will prove to be correct and such forward-looking statements
included in this report should not be unduly relied upon. These statements
speak only as of the date of this report or, if applicable, as of the date
specified in those documents specifically referenced herein.
In particular, this report contains forward-looking statements pertaining
to the following: the performance characteristics of Crescent Point's oil and
natural gas properties; oil and natural gas production levels; capital
expenditure programs; the quantity of Crescent Point's oil and natural gas
reserves and anticipated future cash flows from such reserves; projections of
commodity prices and costs; supply and demand for oil and natural gas;
expectations regarding the ability to raise capital and to continually add to
reserves through acquisitions and development; and treatment under
governmental regulatory regimes.
By their nature, such forward-looking statements are subject to a number
of risks, uncertainties and assumptions, which could cause actual results or
other expectations to differ materially from those anticipated, including
those material risks discussed in our annual information form under "Risk
Factors" and in our Managements Discussion and Analysis for the year ended
December 31, 2007 under the "Business Risks and Prospects". The material
assumptions are disclosed in the Results of Operations section of this press
release under the headings "Cash Distributions", "Taxation of Cash
Distributions", "Capital Expenditures", "Asset Retirement Obligation",
"Liquidity and Capital Resources", "Critical Accounting Estimates", "New
Accounting Pronouncements" and "Business Risks and Prospects". The actual
results could differ materially from those anticipated in these forward-
looking statements as a result of the material risks set forth under the noted
headings, which include, but are not limited to: volatility in market prices
for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions and exploration and development programs;
geological, technical, drilling and processing problems; fluctuations in
foreign exchange or interest rates and stock market volatility; failure to
realize the anticipated benefits of acquisitions; general business and market
conditions; changes in income tax laws or changes in tax laws and incentive
programs relating to the oil and gas industry.
Additional information on these and other factors that could affect
Crescent Point's operations or financial results are included in Crescent
Point's reports on file with Canadian securities regulatory authorities.
Readers are cautioned not to place undue reliance on this forward-looking
information, which is given as of the date it is expressed herein or otherwise
and Crescent Point undertakes no obligation to update publicly or revise any
forward-looking information, whether as a result of new information, future
events or otherwise, unless required to do so pursuant to applicable law.
Fourth Quarter Operations Summary
During the fourth quarter of 2008, Crescent Point continued to
aggressively implement management's business strategy of creating sustainable,
value added growth in reserves, production and cash flow through acquiring,
exploiting and developing high quality, long life light and medium oil and
natural gas properties.
Crescent Point achieved another record quarter for production in the
fourth quarter, averaging 39,554 boe/d, a 5 percent increase over the third
quarter. The Trust participated in the drilling of 49 (33.7 net) oil wells,
achieving a 98 percent success rate, and fracture stimulated a total of 30
(28.8 net) Bakken horizontal wells. The Trust's development activities in the
quarter added in excess of 3,600 boe/d of initial interest production, not
including approximately 1,000 boe/d of Crescent Point's share of initial
production from Bakken wells drilled in the quarter by Shelter Bay on lands
farmed in on the Trust.Drilling Results
-------------------------------------------------------------------------
Three months ended Ser- Stan- % Suc-
December 31, 2008 Gas Oil D&A vice ding Total Net cess
-------------------------------------------------------------------------
Southeast
Saskatchewan - 31 - - - 31 26.3 100
Southwest
Saskatchewan - 13 - - - 13 5.8 100
South/Central
Alberta - 4 - - - 4 0.8 100
Northeast BC and
West Peace
River Arch,
Alberta - - - - 1 1 0.8 -
-------------------------------------------------------------------------
Total - 48 - - 1 49 33.7 98
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year ended Ser- Stan- % Suc-
December 31, 2008 Gas Oil D&A vice ding Total Net cess
-------------------------------------------------------------------------
Southeast
Saskatchewan - 147 - 5 - 152 124.7 100
Southwest
Saskatchewan - 25 - - - 25 11.2 100
South/Central
Alberta - 7 - - - 7 3.5 100
Northeast BC
and West Peace
River Arch,
Alberta 1 4 - - 1 6 5.0 84
-------------------------------------------------------------------------
Total 1 183 - 5 1 190 144.4 99
-------------------------------------------------------------------------
-------------------------------------------------------------------------Southeast Saskatchewan
In the fourth quarter of 2008, Crescent Point participated in the
drilling of 31 (26.3 net) oil wells in southeast Saskatchewan, including 28
(23.3 net) horizontal wells in the southeast Saskatchewan Bakken light oil
resource play and 3 (3.0 net) horizontal wells in the Frobisher zone above the
Bakken play. Crescent Point also fracture stimulated a total of 30 (28.8 net)
horizontal wells in the Bakken play. The Trust achieved a 100 percent success
rate on its drilling and completion activities in southeast Saskatchewan and
added initial interest production in excess of 3,300 boe/d, not including
volumes added from wells drilled by Shelter Bay on lands farmed out by
Crescent Point.
During the quarter, Shelter Bay drilled 21 Bakken horizontal wells on
lands farmed out by the Trust. Crescent Point's share of initial production
from these wells exceeded 1,000 boe/d. These wells are not included in the
above totals.
Crescent Point successfully drilled and completed 3 (3.0 net) horizontal
oil wells in the Frobisher zone above the Bakken play in the fourth quarter,
adding nearly 1,000 boe/d of initial interest production. These wells, along
with a fourth well drilled in the third quarter, prove up four new light oil
pool discoveries in the shallower Frobisher zone above the Bakken. Three
dimensional seismic and numerous oil shows in the zones above the Bakken
suggest the potential for several additional new pool or pool extension
discoveries. Crescent Point anticipates drilling up to 7 Frobisher wells above
the Bakken play in 2009 in anticipation of extending and proving up additional
light oil pool discoveries.
The Trust continued expansion activities in the fourth quarter at the
Viewfield gas plant to accommodate the Trust's growing Bakken production. The
expansion was subsequently completed and commissioned in early 2009,
increasing the plant's inlet capacity from 9 mmcf/d to 18 mmcf/d. Crescent
Point continues to work on design plans for a further expansion to 30 mmcf/d,
construction of which is planned for 2010 and which will accommodate Bakken
production growth from Crescent Point as well as Shelter Bay and other
potential third parties. The Trust will earn processing revenues on any
natural gas volumes processed on behalf of Shelter Bay or other third party
producers.
The Trust commenced integration of the operations of Villanova late in
the quarter in anticipation of the January closing of the acquisition. As of
late February, the integration was largely complete.
Southwest Saskatchewan
At Battrum in the fourth quarter, Crescent Point drilled 13 (5.8 net)
wells with a 100 percent success rate and added nearly 300 boe/d of initial
interest production. Through operational efficiencies and innovations, the
Trust reduced the average drilling cost by $65,000 per well or approximately
20 percent.
South/Central Alberta
The Trust participated in the drilling of 1 (0.4 net) well in the Chip
Lake area targeting the Rock Creek formation and added initial interest
production of 90 boe/d. The Trust is working with the operator to identify
possible follow up locations, of which at least one is planned for the first
quarter of 2009. The Trust also participated in 3 (0.4 net) wells in the
Wildmere area of central Alberta.
The Trust received regulatory approval to down space the Sparky formation
and commence a water flood at Sounding Lake. Water injection into four wells
commenced late in the fourth quarter of 2008 and initial expectations for
incremental recoveries are greater than 10 percent within the flood area.
Northeast British Columbia and Peace River Arch, Alberta
The Trust drilled 1 (0.8 net) well targeting the Doig formation in the
TeePee Creek area. The well is currently standing pending further evaluation
of initial inflow rates.
Acquisitions
On January 15, 2009, the Trust closed the previously announced
acquisition of Villanova, adding approximately 1,750 boe/d of focused, high
netback oil production, 95 percent of which is in the Bakken play. The
acquisition added 26 net sections of undeveloped Bakken land and 47 low risk
Bakken drilling locations to the Trust's inventory.
RESERVES
In 2008, Crescent Point replaced 226 percent of production on a proved
plus probable basis, not including reserves added through acquisitions.
Including acquisitions, the Trust increased its year end proved plus probable
reserves by 14 percent to 191.0 mmboe and its proved reserves by 14 percent to
132.1 mmboe. Year end 2007 reserves were 167.5 mmboe proved plus probable and
115.7 mmboe proved.- The Trust achieved F&D costs, excluding $164.4 million of
expenditures on facilities, land and seismic, of $9.37 per proved
plus probable boe and $11.07 per proved boe. Including expenditures
on facilities, land and seismic, F&D costs were $14.67 per proved
plus probable boe and $17.33 per proved boe, generating proved plus
probable and proved recycle ratios of 4.2 times and 3.6 times,
respectively.
- Crescent Point's three year average F&D cost, including expenditures
on facilities, land and seismic, is $9.41 per proved plus probable
boe and $12.77 per proved boe. This highlights the Trust's technical
ability to efficiently add value to its large resource in place asset
base and accurately reflects the full cycle nature of investments in
facilities, land and seismic.
- Crescent Point achieved FD&A costs of $15.97 per proved plus probable
boe and $19.69 per proved boe, including expenditures on facilities,
land and seismic. Recycle ratios were 3.9 and 3.1 times for proved
plus probable and proved, respectively.
- Crescent Point achieved technical revisions on its core Viewfield
Bakken assets of 27.0 mmboe proved plus probable and 22.2 mmboe
proved. At year end 2008, the Trust had Bakken reserves of 94.8 mmboe
proved plus probable and 64.7 mmboe proved.
- The Trust increased its net asset value ("NAV") per unit to $34.97 at
year end 2008 from $30.05 at year end 2007, based on independent
engineering evaluations of reserves and escalated price assumptions
discounted at 10 percent. The Trust has increased NAV per unit every
year since inception.
- Including the acquisition of Villanova, the Trust's reserves are
expected to increase to 196.5 mmboe proved plus probable and its
reserve life index to 14.1 years.
The Trust's year end reserves were independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Ltd. as at December 31,
2008.
Summary of Reserves
(Escalated Pricing)
As at December 31, 2008(1)
----------------------------------------------
RESERVES(2)
----------------------------------------------
Oil (mbbls) Gas (mmscf)
-------------------------------------------------------------------------
Description Gross Net Gross Net
-------------------------------------------------------------------------
Proved producing 67,998 55,910 42,466 37,190
Proved non-producing 47,336 43,078 26,195 23,213
-------------------------------------------------------------------------
Total proved 115,333 98,989 68,661 60,403
Probable 51,780 44,316 27,881 24,238
-------------------------------------------------------------------------
Total proved plus probable(3) 167,113 143,305 96,542 84,641
-------------------------------------------------------------------------
----------------------------------------------
RESERVES(2)
----------------------------------------------
NGL (mbbls) Total (mboe)
-------------------------------------------------------------------------
Description Gross Net Gross Net
-------------------------------------------------------------------------
Proved producing 2,122 1,884 77,197 63,991
Proved non-producing 3,251 3,028 54,952 49,979
-------------------------------------------------------------------------
Total proved 5,373 4,913 132,149 113,969
Probable 2,377 2,194 58,805 50,549
-------------------------------------------------------------------------
Total proved plus probable(3) 7,750 7,106 190,954 164,518
-------------------------------------------------------------------------
(1) Based on GLJ's January 1, 2009 escalated price forecast.
(2) "Gross Reserves" are the total Trust's interest share before the
deduction of any royalties and without including any royalty interest
of the Trust. "Net Reserves" are the total Trust's interest share
after deducting royalties and including any royalty interest.
(3) Numbers may not add due to rounding.
Summary of Before and After Tax Net Present Values
(Escalated Pricing)
As at December 31, 2008(1)
---------------------------------------------------------
BEFORE TAX NET PRESENT VALUE ($000)
---------------------------------------------------------
Discount Rate
-------------------------------------------------------------------------
Description Undiscounted 5% 10% 15% 20%
-------------------------------------------------------------------------
Proved producing 3,712,718 2,591,223 2,025,553 1,681,908 1,449,281
Proved
non-producing 145,635 102,859 78,442 62,930 52,330
Undeveloped 2,603,920 1,754,199 1,270,837 966,927 761,291
-------------------------------------------------------------------------
Total proved 6,462,273 4,448,281 3,374,832 2,711,765 2,262,902
Probable 3,899,632 1,923,706 1,175,382 808,934 597,825
-------------------------------------------------------------------------
Total proved
plus probable 10,361,905 6,371,987 4,550,214 3,520,699 2,860,727
-------------------------------------------------------------------------
---------------------------------------------------------
AFTER TAX NET PRESENT VALUE ($000)
---------------------------------------------------------
Discount Rate
-------------------------------------------------------------------------
Description Undiscounted 5% 10% 15% 20%
-------------------------------------------------------------------------
Proved producing 3,285,618 2,355,386 1,874,022 1,575,680 1,370,495
Proved
non-producing 112,847 81,042 62,778 51,086 43,033
Undeveloped 2,020,422 1,368,239 992,956 754,992 593,057
-------------------------------------------------------------------------
Total proved 5,418,887 3,804,667 2,929,756 2,381,758 2,006,585
Probable 2,836,042 1,405,237 861,626 594,799 440,893
-------------------------------------------------------------------------
Total proved
plus probable 8,254,929 5,209,904 3,791,382 2,976,557 2,447,478
-------------------------------------------------------------------------
(1) Based on GLJ's January 1, 2009 escalated price forecast.
Before Tax Net Asset Value Per Unit, Fully Diluted, Utilizing Independent
Engineering Escalated Pricing
-------------------------------------------------------------------------
2008 2007 2006 2005 2004 2003
-------------------------------------------------------------------------
PV 0% $80.66 $61.03 $34.08 $21.99 $16.19 $12.72
PV 5% $49.30 $40.21 $21.61 $15.12 $11.22 $9.15
PV 10% $34.97 $30.05 $15.70 $11.45 $8.56 $7.14
PV 15% $26.85 $24.04 $12.27 $9.10 $6.85 $5.83
-------------------------------------------------------------------------
Reserves Reconciliation
(Escalated Pricing)
Gross Reserves(1)
For the year ended December 31, 2008
--------------------------------
CRUDE OIL AND NGL (mbbl)
--------------------------------
Proved Probable Total
-------------------------------------------------------------------------
Opening balance January 1, 2008 104,282 47,164 151,446
Acquired 4,834 2,711 7,545
Disposed (431) (125) (555)
Production (11,925) - (11,925)
Development 19,114 9,233 28,347
Technical revisions 4,832 (4,827) 5
-------------------------------------------------------------------------
Closing balance December 31, 2008(2) 120,706 54,157 174,863
-------------------------------------------------------------------------
--------------------------------
NATURAL GAS (mmscf)
--------------------------------
Proved Probable Total
-------------------------------------------------------------------------
Opening balance January 1, 2008 68,526 27,649 96,175
Acquired 2,888 1,493 4,381
Disposed (5,840) (3,346) (9,186)
Production (10,571) - (10,571)
Development 6,245 4,066 10,311
Technical revisions 7,413 (1,981) 5,432
-------------------------------------------------------------------------
Closing balance December 31, 2008(2) 68,661 27,881 96,542
-------------------------------------------------------------------------
--------------------------------
BOE (mboe)
--------------------------------
Proved Probable Total
-------------------------------------------------------------------------
Opening balance January 1, 2008 115,703 51,773 167,476
Acquired 5,315 2,960 8,275
Disposed (1,404) (682) (2,086)
Production (13,687) - (13,687)
Development 20,155 9,911 30,066
Technical revisions 6,066 (5,156) 910
-------------------------------------------------------------------------
Closing balance December 31, 2008(2) 132,149 58,805 190,954
-------------------------------------------------------------------------
(1) Based on GLJ's January 1, 2009 escalated price forecast. "Gross
reserves" are the Trust's working-interest share before deduction of
any royalties and without including any royalty interests of the
Trust.
(2) Numbers may not add due to rounding.
Finding, Development and Acquisition Costs
(excluding future development costs)
For the year ended December 31, 2008
------------------------------------------------------------
FINDING,
CAPITAL DEVELOPMENT
EXPENDITURES AND ACQUISITION
(1)(4) RESERVES(3) COSTS(1)(2)
------------------------------------------------------------
Proved Proved
Plus Plus
Total Proved Probable Proved Probable
-------------------------------------------------------------------------
$000 % mboe % mboe % $/boe $/boe
-------------------------------------------------------------------------
Exploration
development
and
revisions $454,533 77% 26,221 87% 30,976 83% $17.33 $14.67
Acquisitions,
net of
dispo-
sitions $138,911 23% 3,911 13% 6,189 17% $35.52 $22.44
-------------------------------------------------------------------------
Total $593,444 100% 30,132 100% 37,165 100% $19.69 $15.97
-------------------------------------------------------------------------
(1) Exploration, Development and Revisions exclude the change during the
most recent financial year in estimated future development costs
relating to proved and proved plus probable reserves, respectively.
These costs would add $182.5 million and $193.3 million,
respectively, to the proved and proved plus probable reserves
categories. Including these changes, the proved and proved plus
probable finding and development costs are $24.29 and $20.91 per boe,
respectively.
(2) Including change in future development costs, finding, development
and acquisition costs are $25.75 per proved boe and $21.17 per proved
plus probable boe.
(3) Gross Trust interest reserves are used in this calculation (interest
reserves, before deduction of any royalties and without including any
royalty interests of the Trust).
(4) The capital expenditures include the purchase price of corporate
acquisitions rather than the amounts allocated to property, plant and
equipment for accounting purposes. The capital expenditures also
exclude capitalized administration costs and acquisition costs.
Summary of Reserves, Including First Quarter 2009 Acquisitions
(Villanova)
(Escalated Pricing)
As at January 1, 2009(1)(2)
----------------------------------------------
RESERVES(3)
----------------------------------------------
Oil (mbbls) Gas (mmscf)
-------------------------------------------------------------------------
Description Gross Net Gross Net
-------------------------------------------------------------------------
Proved producing 69,676 57,338 42,487 37,207
Proved non-producing 48,904 44,453 27,480 24,343
-------------------------------------------------------------------------
Total proved 118,581 101,791 69,967 61,550
Probable 53,424 45,740 28,584 24,858
-------------------------------------------------------------------------
Total proved plus probable(4) 172,004 147,531 98,551 86,408
-------------------------------------------------------------------------
----------------------------------------------
RESERVES(3)
----------------------------------------------
NGL (mbbls) Total (mboe)
-------------------------------------------------------------------------
Description Gross Net Gross Net
-------------------------------------------------------------------------
Proved producing 2,125 1,887 78,883 65,426
Proved non-producing 3,471 3,222 56,956 51,732
-------------------------------------------------------------------------
Total proved 5,597 5,109 135,838 117,158
Probable 2,497 2,300 60,685 52,183
-------------------------------------------------------------------------
Total proved plus probable(4) 8,094 7,409 196,523 169,342
-------------------------------------------------------------------------
(1) Includes independent engineers' evaluations of Crescent Point 2008
year end and Villanova Energy Corporation 2008 year end.
(2) Based on GLJ's January 1, 2009 escalated price forecast.
(3) "Gross Reserves" are the total Trust's interest share before the
deduction of any royalties and without including any royalty
interests of the Trust. "Net Reserves" are the total Trust's interest
share after deducting royalties and including any royalty interests.
(4) Numbers may not add due to rounding.
---------------------------------------------------------
BEFORE TAX NET PRESENT VALUE ($000)
---------------------------------------------------------
Discount Rate
-------------------------------------------------------------------------
Description Undiscounted 5% 10% 15% 20%
-------------------------------------------------------------------------
Proved producing 3,810,915 2,667,278 2,088,311 1,735,894 1,497,056
Proved
non-producing 2,822,518 1,905,093 1,382,493 1,053,473 830,608
-------------------------------------------------------------------------
Total proved 6,633,433 4,572,371 3,470,804 2,789,367 2,327,664
Probable 4,019,399 1,988,921 1,216,788 837,908 619,382
-------------------------------------------------------------------------
Total proved
plus probable 10,652,832 6,561,292 4,687,592 3,627,275 2,947,046
-------------------------------------------------------------------------SUBSEQUENT EVENTS
On March 4, 2009, Crescent Point announced that it had entered into an
agreement with affiliates of Talisman Energy Inc. ("Talisman") and TriStar Oil
& Gas Ltd. ("TriStar") wherein Crescent Point and TriStar will jointly acquire
all of Talisman's assets in southeast Saskatchewan and Montana for cash
consideration of approximately $720 million. The assets include more than
8,500 boe/d of high quality, high netback, long life, low decline crude oil
and natural gas production in southeast Saskatchewan, including approximately
1,900 boe/d of production from the southeast Saskatchewan Bakken light oil
resource play.
Crescent Point and TriStar agreed to sell a portion of the assets
acquired to Shelter Bay for consideration of approximately $71 million.
On a net basis, Crescent Point expects to acquire approximately 4,000
boe/d of high quality southeast Saskatchewan production, approximately 700
boe/d of which is in the Bakken resource play, for cash consideration of
approximately $325 million. Crescent Point anticipates funding the acquisition
with proceeds from a $230 million bought deal financing also announced on
March 4, 2009, and the Trust's existing credit facilities. The bought deal
financing, which is expected to close on or about March 24, 2009, is for 10.8
million trust units at $21.25 per trust unit. The acquisition is expected to
close on June 1, 2009.Key attributes of the assets to be acquired by Crescent Point:
- 312 net sections of undeveloped Saskatchewan land, 25 of which are in
the Bakken light oil resource play;
- 70 net low risk drilling locations, 37 of which are in the southeast
Saskatchewan Bakken light oil resource play;
- Ownership of freehold mineral rights on 217 net sections of land,
resulting in overall royalties of less than 16 percent;
- Tax pools estimated at more than $324 million; and
- Approximately 21.1 mmboe of proved plus probable and 14.6 mmboe of
proved reserves, independently evaluated as of March 31, 2009.Including the assets acquired from Talisman and the first quarter 2009
acquisition of Villanova, Crescent Point's reserves are expected to increase
to 217.6 mmboe proved plus probable and 150.4 mmboe proved. Crescent Point's
reserve life index is expected to increase to 14.2 years on a proved plus
probable basis and to 9.8 years on a proved basis.
Crescent Point also announced on March 4, 2009, that its Board of
Directors had unanimously agreed to a strategic conversion (the "Conversion")
to a dividend paying corporation. The Conversion, which the Trust expects to
complete on or before May 31, 2009, will allow Crescent Point to continue to
implement its proven business plan of growing value through its integrated
strategy of acquiring, exploiting and developing high quality, long life
reserves and will allow Crescent Point improved access to capital markets
without the constraints of the Safe Harbour growth limitations placed on
income trusts.
With the planned Conversion, Crescent Point's business model is expected
to remain unchanged, with Crescent Point paying a monthly dividend instead of
the current monthly distribution. The initial dividend is expected to be set
at $0.23 per share, which equals Crescent Point's current monthly distribution
of $0.23 per unit. Crescent Point's dividend policy is intended to be similar
to the distribution policy currently in use by the Trust. It is Crescent
Point's understanding that dividends paid in respect of shares held by
Canadians outside of a Registered Retirement Savings Plan ("RRSP"), Registered
Retirement Income Fund ("RRIF"), or Deferred Profit Sharing Plan ("DPSP") will
be eligible for the Canadian Dividend Tax Credit. In such circumstances, under
the intended monthly dividend of $0.23 per share, Canadians holding shares
outside of a RRSP, RRIF or DPSP will receive an increase on an after tax basis
when they receive the intended dividend instead of the current distribution.
Under the planned Conversion, Crescent Point unitholders will receive one
share in a dividend paying corporation for each Crescent Point trust unit they
hold. The Conversion is intended to be tax deferred for Canadian and U.S.
income tax purposes.
The planned Conversion requires the approval of Crescent Point
unitholders, as well as customary court and regulatory approvals. To be
implemented, the Conversion must be approved by not less than two-thirds of
the votes cast by unitholders voting at the related unitholder meeting, which
is expected to be scheduled on or before May 27, 2009. Closing of the
Conversion is anticipated on or before May 31, 2009.
SHELTER BAY FOURTH QUARTER UPDATE
On October 1, 2008, Shelter Bay closed a $300 million private placement
equity financing, of which Crescent Point contributed $78.7 million. The
private placement financing, along with a $60 million third quarter increase
in Shelter Bay's credit facilities, position Shelter Bay well for significant
growth in core Crescent Point areas, including the southeast Saskatchewan
Bakken light oil resource play. In total, Shelter Bay raised more than $1.0
billion of debt and equity from inception in the first quarter of 2008 to year
end.
During the fourth quarter of 2008, Shelter Bay continued to aggressively
pursue its business strategy of growth in core Crescent Point areas. Shelter
Bay drilled 38 Bakken horizontal wells, including 21 on lands farmed out by
the Trust. Crescent Point's share of production from all farmout wells
averaged more than 1,000 boe/d for the quarter. In the Lower Shaunavon,
Shelter Bay fracture stimulated three horizontal wells that were drilled in
the third quarter. Shelter Bay also drilled and fracture stimulated 2
additional horizontal wells in the Lower Shaunavon in the fourth quarter, one
of which was completed in the first quarter of 2009. Excluding the 2009 well,
Shelter Bay added nearly 500 boe/d of initial interest production in the Lower
Shaunavon in the fourth quarter. Shelter Bay's production averaged 4,376 boe/d
for the fourth quarter.
Shelter Bay's credit facilities are expected to be increased from the
current $100 million upon renewal in March as a result of the successful
drilling program and reserves growth during the year, with the potential for a
further increase related to the acquisition from Crescent Point and TriStar.
Shelter Bay is poised for growth with its strong balance sheet and
available cash and credit facilities of more than $210 million, including the
$71 million acquisition of assets from Crescent Point and TriStar, to fund
future expansion opportunities within Crescent Point's core areas. Shelter Bay
currently has a development drilling inventory of more than 425 Bakken and
Lower Shaunavon drilling locations. Exit 2009 production is forecast greater
than 7,200 boe/d.
Including the October 2008 investment of $78.7 million, Crescent Point's
total investment in Shelter Bay is approximately $200 million, which equates
to a 21 percent interest. The Crescent Point financial and operating results
do not reflect the production or cash flows of Shelter Bay other than the
production and cash flows associated with the Trust's interests in the wells
farmed out to Shelter Bay by the Trust. Crescent Point accounts for its
investment in Shelter Bay using the equity method of accounting. Accordingly,
the Trust records its share of Shelter Bay net income or loss in the "equity
and other income" caption on the consolidated statements of operations,
comprehensive income and deficit.
OUTLOOK
Crescent Point continues to execute its proven business plan of creating
value added growth in reserves, production and cash flow through management's
integrated strategy of acquiring, exploiting and developing high quality, long
life, light and medium oil and natural gas properties. Crescent Point's strong
balance sheet, 3 1/2 year risk management program and high quality asset base
position the Trust well to maintain production and distributions through
volatile commodity price cycles.
Pro forma with the assets acquired from Talisman, Crescent Point will
have increased its low risk development drilling inventory to more than 1,600
net locations, representing more than 16 years of low risk drilling inventory
to maintain production levels. Through infill drilling, production
optimization and water flood implementation, management believes the Trust has
the potential to more than double its proved plus probable reserves over time.
Since the third quarter of 2008, global financial markets have been
trapped in a period of significant uncertainty marked by downward pressure on
equities, overall tightening of credit markets and global economic recession.
Prices for commodities, including crude oil and natural gas, have
deteriorated.
During this period, Crescent Point was successful in entering into an
agreement to acquire assets from Talisman, in raising $115 million of equity
in a bought deal financing and in entering into a bought deal arrangement in
respect of a further $230 million. The Trust's credit facilities were
increased by $150 million with an additional increase expected in conjunction
with the acquisition of the Talisman assets. Shelter Bay raised $300 million
of equity in a private placement in October 2008. The combined $795 million of
financing highlights the high quality nature of the asset bases and the robust
economics of the opportunities that lie ahead for both Crescent Point and
Shelter Bay.
Crescent Point's development capital budget for 2009 was set in December
2008 at $225 million, with average production forecast at 38,250 boe/d.
Assuming the successful completion of the acquisition of the Talisman assets,
Crescent Point has upwardly revised its average 2009 production guidance to
40,500 boe/d, while maintaining its $225 million capital program for the year.
Exit production is forecast greater than 42,000 boe/d.
With low benchmark oil prices early in 2009, the Trust has reduced first
quarter drilling plans and focused on achieving significant cost reductions
and increasing the number of expected fracture stimulation projects. The
capital expenditure reduction in the first quarter has led to an expected 20
percent reduction in Bakken drilling and completions costs to approximately
$1.6 million per Bakken well. With these capital cost reductions, a typical
Bakken horizontal well generates a 140 percent before tax rate of return at
benchmark WTI oil prices of US$45 per barrel and pays out in 10 months. These
robust economics position the Trust well for potential capital budget and
production increases in the second half of 2009 should benchmark WTI oil
prices stabilize above US$45 per barrel.
Crescent Point continues to implement its balanced 3 1/2 year price risk
management program, using a combination of swaps, collars and purchased put
options with investment grade counter parties all within the Trust's banking
syndicate. Effective March 3, 2009, pro forma with the Talisman assets, the
Trust had hedged 54 percent of production volumes net of royalty interests for
the balance of 2009, 38 percent for 2010, 24 percent for 2011 and 12 percent
for the first half of 2012. Quarterly floor prices range from Cdn$74 per boe
to Cdn$108 per boe, with upside potential if prices strengthen above current
levels. The Trust's hedge position is significantly in the money, with a mark
to market value of $234 million as of March 3, 2009, including $98 million for
the balance of 2009.
Crescent Point intends to crystallize up to $75 million of its 2011 and
2012 mark to market hedge value in the first quarter of 2009 and intends to
reset those hedges at current market prices, expected to be in the Cdn$75 per
boe to Cdn$80 per boe range. This capitalizes on the Trust's strong 2011 and
2012 hedges while continuing to provide cash flow stability to Crescent Point
over the next 3 1/2 years. Assuming the completion of the crystallization and
reset, Crescent Point expects that its 3 1/2 year average hedge price would be
in the range of Cdn$75 to Cdn$80 per boe while increasing 2009 cash flows by
up to $75 million.
Crescent Point is well positioned to withstand the current market
uncertainty and to take advantage of acquisition opportunities. The Trust's
balance sheet is strong with projected 2009 net debt to 12 month cash flow of
1.1 times and its 3 1/2 year risk management program provides cash flow
stability. The Trust's 16 year drilling inventory and current 100 well
fracture stimulation inventory provide long term sustainability and capital
investment flexibility even at low oil prices.
Crescent Point's management believes that with the high quality reserve
base and development inventory, excellent balance sheet and solid hedging
program, the Trust is well positioned to continue generating strong operating
and financial results and delivering sustainable distributions through 2009
and beyond.2009 Guidance
Crescent Point's 2009 guidance is as follows:
-------------------------------------------------------------------------
Production 2009
Oil and NGL (bbls/d) 36,200
Natural gas (mcf/d) 25,800
-------------------------------------------------------------------------
Total (boe/d) 40,500
-------------------------------------------------------------------------
Funds flow from operations ($000) 593,000
Combined funds flow per unit - diluted and per share -
diluted ($) 3.91
Combined cash distributions per unit and dividends per share ($) 2.76
Payout ratio - per unit/share - diluted (%) 71
-------------------------------------------------------------------------
Capital expenditures ($000)(1) 225,000
Wells drilled, net 82
-------------------------------------------------------------------------
Pricing
Crude oil - WTI (US$/bbl) 46.50
Crude oil - WTI (Cdn$/bbl) 58.86
Natural gas - Corporate (Cdn$/mcf) 5.00
Exchange rate (US$/Cdn$) 0.79
-------------------------------------------------------------------------
(1) The projection of capital expenditures excludes acquisitions, which
are separately considered and evaluated.
ON BEHALF OF THE BOARD OF DIRECTORS
(signed)
Scott Saxberg
President and Chief Executive Officer
March 16, 2009RESULTS OF OPERATIONS
STRUCTURE OF THE TRUST
Crescent Point Energy Trust ("the Trust") is an open-ended unincorporated
investment trust created on September 5, 2003 pursuant to a Declaration of
Trust and Plan of Arrangement operating under the laws of the Province of
Alberta. Olympia Trust Company is the trustee, Crescent Point Resources Inc.
("CPRI") is the administrator of the Trust and the beneficiaries of the Trust
are the unitholders.
On March 1, 2007, the Trust completed a reorganization of the Trust and
its subsidiaries. The reorganization resulted in the existing business of the
Trust, which was carried on through a limited partnership and corporations,
being carried on through a limited partnership, directly and indirectly owned
by the Trust.
The principal undertaking of the Trust's operating entities, Crescent
Point Resources Limited Partnership along with its general partner, Crescent
Point General Partner Corp. is to acquire, hold directly or indirectly,
interests in oil and gas properties. The administrator of the Trust's business
is CPRI.
Non-GAAP Financial Measures
Throughout this discussion and analysis, the Trust uses the terms "funds
flow from operations", "funds flow from operations per unit", "funds flow from
operations per unit-diluted", "net debt", "market capitalization" and "total
capitalization". These terms do not have any standardized meaning as
prescribed by Canadian generally accepted accounting principles ("GAAP") and,
therefore, may not be comparable with the calculation of similar measures
presented by other issuers.
Funds flow from operations is calculated based on cash flow from
operating activities before changes in non-cash working capital and asset
retirement obligation expenditures. Funds flow from operations per unit-
diluted is calculated based on cash flow from operating activities before
changes in non-cash working capital and asset retirement obligation
expenditures excluding the cash portion of unit-based compensation. Management
utilizes funds flow from operations as a key measure to assess the ability of
the Trust to finance distributions, operating activities, capital expenditures
and debt repayments. Funds flow from operations as presented is not intended
to represent 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
funds flow from operations:-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
% %
($000) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from
operating
activities 125,625 99,070 27 584,955 332,605 76
Changes in
non-cash working
capital (16,364) 12,623 (230) 4,860 21,450 (77)
Asset retirement
expenditures 374 879 (57) 2,317 1,855 25
-------------------------------------------------------------------------
Funds flow from
operations 109,635 112,572 (3) 592,132 355,910 66
-------------------------------------------------------------------------Net debt is calculated as current liabilities plus bank indebtedness less
current assets and long term investments but excludes risk management assets
and liabilities. Management utilizes net debt as a key measure to assess the
liquidity of the Trust. Market capitalization is calculated by applying the
period end closing unit trading price to the number of trust units
outstanding. Market capitalization is an indication of the enterprise value.
Total capitalization is calculated as market capitalization and current
liabilities plus bank indebtedness, less current assets, and long term
investments, excluding the risk management assets and liabilities. Total
capitalization is used by management to measure the proportion of net debt in
the Trust's capital structure to assess the amount of debt leverage used in
the Trust's capital structure.
Forward-Looking Information
Cautionary Statement Regarding Forward-Looking Information and Statements
Certain statements contained in this report constitute forward-looking
statements and are based on the Trust's beliefs and assumptions based on
information available at the time the assumption was made. By its nature, such
forward-looking information involves known and unknown risks, uncertainties
and other factors that may cause actual results or events to differ materially
from those anticipated in such forward-looking statements. The Trust and CPRI,
the administrator of the Trust, believe the expectations reflected in those
forward-looking statements are reasonable but no assurance can be given that
these expectations will prove to be correct and such forward-looking
statements should not be unduly relied upon. These statements are effective
only as of the date of this report.
The material assumptions in making these forward-looking statements are
disclosed in this analysis under the headings "Cash Distributions", "Capital
Expenditures", "Asset Retirement Obligation", "Liquidity and Capital
Resources", "Critical Accounting Estimates", "New Accounting Pronouncements"
and "Outlook".
Certain statements contained in this report, including statements related
to Crescent Point's capital expenditures, projected asset growth, view and
outlook toward future commodity prices, drilling activity and statements that
contain words such as "could", "should", "can", "anticipate", "expect",
"believe", "will", "may", "projected", "sustain", "continues", "strategy",
"potential", "projects", "grow", "take advantage", "estimate", "well
positioned" and similar expressions and statements relating to matters that
are not historical facts constitute "forward-looking information" within the
meaning of applicable Canadian securities legislation. The material
assumptions in making these forward-looking statements are disclosed in this
analysis under the headings "Cash Distributions", "Capital Expenditures",
"Asset Retirement Obligation", "Liquidity and Capital Resources", "Critical
Accounting Estimates", "New Accounting Pronouncements" and "Outlook".The following are examples of references to forward-looking information:
- Volumes and estimated value of the Trust's oil and gas reserves;
- The life of the Trust's reserves;
- Volume and product mix of the Trust's oil and gas production;
- Future oil and gas prices and interest rates in respect of the
Trust's commodity risk management programs;
- The amount and timing of future asset retirement obligations;
- Future liquidity and financial capacity;
- Future interest rates;
- Future results from operations and operating metrics;
- Future development, exploration and other expenditures;
- Future costs, expenses and royalty rates;
- Future tax treatment of income trusts; and
- The Trust's tax pools.This disclosure contains certain forward-looking estimates that involve
substantial known and unknown risks and uncertainties, certain of which are
beyond Crescent Point's control. Therefore, Crescent Point's actual results,
performance or achievement could differ materially from those expressed in, or
implied by, these forward-looking estimates and if such actual results,
performance or achievements transpire or occur, or if any of them do so, there
can be no certainty as to what benefits Crescent Point will derive therefrom.
Crescent Point is exposed to several operational risks inherent in
exploiting, developing, producing and marketing crude oil and natural gas.
These risks include but are not limited to:- Economic risk of finding and producing reserves at a reasonable cost;
- Reliance on reserve estimates for the year as well as on
acquisitions;
- Financial risk of marketing reserves at an acceptable price given
market conditions;
- Fluctuations in commodity prices, foreign exchange and interest
rates;
- Operational matters related to non-operated properties;
- Delays in business operations, pipeline restrictions, blowouts;
- Debt service, indebtedness may limit timing or amount of
distributions as well as market price of trust units;
- The continued availability of adequate debt and equity financing and
cash flow to fund planned expenditures;
- Sufficient liquidity for future operations;
- Cost of capital risk to carry out the Trust's operations;
- Unforeseen title defects;
- Aboriginal land claims;
- Increased competition and the lack of availability of qualified
personnel or management;
- Loss of key personnel;
- Uncertainty of government policy changes;
- The risk of carrying out operations with minimal environmental
impact;
- Operational hazards and availability of insurance;
- Industry conditions including changes in laws and regulations
including the adoption of new environmental laws and regulations and
changes in how they are interpreted and enforced;
- General economic, market and business conditions;
- Competitive action by other companies;
- The ability of suppliers to meet commitments;
- Stock market volatility;
- Obtaining required approvals of regulatory authorities;
- Financing the purchase of Shelter Bay in the event certain
shareholders exercise their right to require the Trust to purchase
the remaining Shelter Bay shares not owned by the Trust; and
- Creditworthiness of counterparties.
Crescent Point strives to manage or minimize these risks in a number of
ways, including:
- Employing qualified professional and technical staff;
- Concentrating in a limited number of areas with low cost exploitation
and development objectives;
- Utilizing the latest technology for finding and developing reserves;
- Constructing quality, environmentally sensitive, safe production
facilities;
- Maximizing operational control of drilling and producing operations;
- Mitigating price risk through strategic hedging;
- Adhering to conservative borrowing guidelines;
- Monitoring counterparty creditworthiness; and
- Obtaining counterparty credit insurance
In particular, forward-looking information and statements include, but are
not limited to:
- The Trust's 2009 guidance as outlined in the Outlook section;
- Addition of new pool or pool extension discoveries in the Bakken
play;
- Expansion of the Viewfield gas plant capacity to 18 mmcf/d and design
work for further expansion to 30 mmcf/d;
- Earning of processing revenues on natural gas volumes processed at
the Viewfield gas plant;
- Integration of Villanova operations and reserve base;
- Identification of possible follow up locations in the Chip Lake area;
- Incremental recoveries in excess of 10 percent within the flood area
at Sounding Lake;
- Evaluation of initial inflow rates in the TeePee Creek area;
- Drilling inventory of 16 years and 100 well fracture stimulation
inventory;
- Bakken horizontal well before tax rate of return;
- Stabilization of benchmark WTI oil prices above US$45.00 per barrel;
- Pro forma statements related to the acquisition of Talisman assets
and;
- Projected 2009 net debt to 12 month cash flow of 1.1 times.All of which are stated under the headings "Results of Operations" and
"Outlook" of this report.
A barrel of oil equivalent ("boe") is based on a conversion rate of six
thousand cubic feet of natural gas to one barrel of oil.
Results of Operations
Production
Crescent Point grew fourth quarter 2008 average daily production by five
percent over third quarter 2008 and exceeded guidance by more than 2,800
boe/d. The Trust produced 39,554 boe/d for the quarter, up from 37,630 boe/d
in the third quarter and up 19 percent from 33,351 boe/d in the fourth quarter
of 2007.
On October 22, 2007, the Trust closed the acquisition of Innova
Exploration Ltd. ("Innova"), which added over 4,300 boe/d of light and natural
gas assets, including more than 2,800 boe/d from the Viewfield Bakken resource
play. On January 16, 2008, the Trust closed the acquisition of Pilot Energy
Ltd. ("Pilot"), which added over 1,000 boe/d of high netback oil, 50 percent
of which was in the Viewfield Bakken resource play. Lastly on March 26, 2008,
the Trust closed the acquisition of light oil assets from Shelter Bay Energy
Inc. ("Shelter Bay") in connection with the Shelter Bay's corporate
acquisition of Landex Petroleum Corp. ("Landex"). This property acquisition
added over 1,500 boe/d in the Trust's core area of southeast Saskatchewan.
Further contributing to the significant increase in production was the
Trust's successful drilling program. During 2008 the Trust drilled 190 (144.4
net) wells primarily in southeast Saskatchewan and the Viewfield Bakken
resource play. The Trust exceeded its original 2008 production guidance by
more than 13 percent due to its expanded and successful drilling programs.
The Trust's weighting to oil during 2008 remained consistent with the
comparative period.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
% %
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Crude oil and NGL
(bbls/d) 34,897 28,601 22 32,583 24,349 34
Natural gas (mcf/d) 27,941 28,500 (2) 28,883 22,610 28
-------------------------------------------------------------------------
Total (boe/d) 39,554 33,351 19 37,397 28,117 33
-------------------------------------------------------------------------
Crude oil and
NGL (%) 88 86 2 87 87 -
Natural gas (%) 12 14 (2) 13 13 -
-------------------------------------------------------------------------
Total (%) 100 100 - 100 100 -
-------------------------------------------------------------------------Marketing and Prices
The Trust's selling price for oil for the three months ended December 31,
2008, decreased 20 percent compared to the same period in the prior year. This
decrease is primarily the result of a 35 percent decrease in the US$WTI
benchmark price. The Trust's differential was $11.63 per barrel during the
fourth quarter of 2008 compared to $13.54 per barrel during the fourth quarter
of 2007. The Trust's differential as a percentage of Cdn$ WTI was 16% percent
compared to 15% 2007. This widening differential was due to temporary
transportation issues on the Enbridge Pipeline (Saskatchewan) system that
caused benchmark differentials between light crude oil in Western Canada and
WTI to increase. These issues have been addressed and benchmark differentials
have improved to date in the first quarter of 2009.
For the twelve months ended December 31, 2008, the Trust's selling price
for oil increased 40 percent, from $67.33 per bbl during 2007 to $94.36 per
bbl during the current year, primarily as a result of 38 percent increase in
the US$WTI benchmark price. The Trust's oil differential was $11.65 per barrel
during 2008 compared to $10.52 per barrel in 2007. The Trust's differential as
a percentage of Cdn$ WTI was 11% in 2008 compared to 14% during 2007. This
improvement is the result of the growth of high quality Bakken crude
production from the Trust's successful acquisition and drilling programs
partially offset by the fourth quarter 2008 temporary transportation issues
discussed above.
During the three months ended December 31, 2008, the Trust's selling
price for gas increased 14 percent from $6.32 per mcf to $7.23 during 2008.
This is comparable to a nine percent increase in the AECO daily gas price for
the three months ended December 31, 2008 compared to the same period in 2007.
The differential in the Trust's gas price compared to the AECO daily price is
the result of the Trust's portfolio of gas marketing contracts and the high
heat content gas production associated with the Viewfield Bakken area.
The Trust's average selling price for gas increased 28 percent to $8.36
per mcf in 2008 compared to $6.52 per mcf in 2007. This is comparable to a 27
percent increase year-over-year in the AECO daily gas price. The differential
in the Trust's gas price compared to the AECO daily price is consistent with
the three months ended December 31, 2008.-------------------------------------------------------------------------
Average Selling Three months ended
Prices(1) December 31 Year ended December 31
% %
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Crude oil and NGL
($/bbl) 60.02 75.31 (20) 94.36 67.33 40
Natural gas ($/mcf) 7.23 6.32 14 8.36 6.52 28
-------------------------------------------------------------------------
Total ($/boe) 58.06 69.99 (17) 88.67 63.55 40
-------------------------------------------------------------------------
(1) The average selling prices reported are before realized derivative
losses and transportation charges.
-------------------------------------------------------------------------
Benchmark Pricing Three months ended
December 31 Year ended December 31
% %
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
WTI crude oil
(US$/bbl) 58.75 90.63 (35) 99.65 72.40 38
WTI crude oil
(Cdn$/bbl) 71.65 88.85 (19) 106.01 77.85 36
AECO natural gas(1)
(Cdn$/mcf) 6.70 6.15 9 8.15 6.44 27
Exchange rate -
US$/Cdn$ 0.82 1.02 (20) 0.94 0.93 1
-------------------------------------------------------------------------
(1) The AECO natural gas price reported is the average daily spot price.Derivatives and Risk Management
Management of cash flow variability is an integral component of Crescent
Point's business strategy. Changing business conditions are monitored
regularly and reviewed with the Board of Directors of CPRI, the administrators
of the Trust, to establish risk management guidelines used by management in
carrying out the Trust's strategic risk management program. The risk exposure
inherent in movements in the price of crude oil and natural gas, fluctuations
in the US/Cdn dollar exchange rate, changes in the price of power and interest
rate movements on long-term debt are all proactively managed by Crescent Point
through the use of derivatives with investment grade counterparties. The Trust
considers these contracts to be an effective means to manage cash flow.
The Trust's crude oil and natural gas financial instruments are
referenced to WTI and AECO, unless otherwise noted. Crescent Point utilizes a
variety of financial instruments including swaps, collars and puts to protect
against downward commodity price movements while providing the opportunity for
some participation during periods of rising prices.
During the three months ended December 31, 2008, the Trust realized a
hedging gain of $9.9 million compared to a loss of $11.3 million in the same
period during 2007. This fluctuation is the result of a 19 percent decrease in
the Cdn$ WTI benchmark price during the three months ended December 31, 2008
compared to the same period in the previous year.
The Trust incurred total realized derivative losses of $154.6 million
during the twelve months ended December 31, 2008 compared to a loss of $9.9
million during 2007. The total derivative losses consists of an operating
realized derivative loss of $120.1 million plus a $34.5 million realized
derivative loss relating to the Trust's derivative crystallization and reset
program (discussed below).
Crescent Point's operating realized derivative loss for oil was $119.7
million in 2008 compared to a loss of $10.8 million during 2007. The increase
in the loss is attributable to the significant increase in the Cdn$ WTI
benchmark price, a year-over-year increase of 36 percent. This increase is
partially offset by an increase in the oil derivative prices. The Trust's
effective financial instrument oil price increased 15 percent or $10.99 per
barrel, from $75.22 per barrel in 2007 to $86.21 per barrel in 2008.
Crescent Point's loss pursuant to its derivative crystallization and
reset program ("derivative crystallization") announced June 16, 2008 was $34.5
million. The Trust crystallized a portion of its forward mark-to-market losses
on swaps for 2009 and 2010 and reset the derivatives using a combination of
swaps and costless collars at market prices at the end of the second quarter,
which were significantly higher than the Trust's average derivative price. The
impact of resetting the 2009 and 2010 derivatives will increase the Trust's
2009 and 2010 funds flow from operations for derivative transactions.
The following is a summary of the realized derivative gains (losses) on
oil and gas contracts:-------------------------------------------------------------------------
Three months ended
($000, except per December 31 Year ended December 31
boe and volume % %
amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Average crude oil
volumes hedged
(bbls/d) 16,750 12,250 37 16,520 11,190 48
Crude oil realized
derivative gain
(loss) 9,864 (11,594) 185 (119,745) (10,752) 1,014
per bbl 3.07 (4.41) 170 (10.04) (1.21) 730
-------------------------------------------------------------------------
Average natural
gas volumes
hedged (GJ/d) 674 2,674 (75) 1,667 3,173 (47)
Natural gas realized
derivative gain
(loss) 52 305 (83) (342) 853 (140)
per mcf 0.02 0.12 (83) (0.03) 0.10 (130)
-------------------------------------------------------------------------
Average barrels
of oil equivalent
hedged (boe/d) 16,857 12,672 33 16,783 11,691 44
Realized derivative
gain (loss) 9,916 (11,289) 188 (120,087) (9,899) 1,113
per boe 2.72 (3.68) 174 (8.77) (0.96) 814
-------------------------------------------------------------------------
Derivative
crystallization
loss - - - (34,483) - -
per boe - - - (2.52) - -
-------------------------------------------------------------------------
Total realized
derivative gain
(loss) 9,916 (11,289) 188 (154,570) (9,899) 1,461
per boe 2.72 (3.68) 174 (11.29) (0.96) 1,076
-------------------------------------------------------------------------The Trust has not designated any of its risk management activities as
accounting hedges under the Canadian Institute of Chartered Accountants (the
"CICA") section 3855 and, accordingly, has marked-to-market its derivatives.
The Trust's risk management policy allows for hedging a forward profile
of three and a half years, and up to 65 percent of net royalty interest
production. As at March 3, 2009, the Trust had hedged 57 percent, 42 percent,
27 percent, and 14 percent of production, net of royalty interest, for the
balance of 2009, 2010, 2011 and the first six months of 2012, respectively.
Crescent Point has the following derivative contracts in place as at
March 3, 2009:-------------------------------------------------------------------------
Financial WTI Crude Oil Contracts - Canadian Dollar(1)
Average Average
Collar Collar Average
Average Sold Bought Bought Average
Swap Call Put Put Put
Average Price Price Price Price Premium
Volume ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/
Term Contract (bbls/d) bbl) bbl) bbl) bbl) bbl)
-------------------------------------------------------------------------
2009 Swap 9,297 80.01
2009 Collar 5,250 95.47 76.19
2009 Put 3,250 70.46 (6.03)
2010 Swap 6,313 85.17
2010 Collar 3,937 96.35 79.74
2010 Put 2,500 72.90 (4.51)
2011 Swap 4,748 105.74
2011 Collar 3,626 123.19 95.00
2012
January
- June Swap 3,250 90.07
2012
January
- June Collar 1,000 105.38 75.00
-------------------------------------------------------------------------
(1) The volumes and prices reported are the weighted average volumes and
prices for the period.
-------------------------------------------------------------------------
Financial AECO Natural Gas Contracts - Canadian Dollar
Average
Average Swap
Volume Price
Term Contract (GJ/d) ($Cdn/GJ)
-------------------------------------------------------------------------
2009 March - December Swap 3,595 6.02
2010 January - October Swap 2,592 6.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Financial Interest Rate Contracts - Canadian Dollar
Notional Fixed
Principal Annual
Term Contract ($Cdn) Rate (%)
-------------------------------------------------------------------------
January 2009 - February 2009 Swap 50,000,000 4.37
January 2009 - May 2009 Swap 75,000,000 3.16
January 2009 - November 2010 Swap 75,000,000 4.35
January 2009 - November 2010 Swap 50,000,000 1.97
January 2009 - June 2011 Swap 75,000,000 3.89
January 2009 - November 2011 Swap 25,000,000 2.54
February 2009 - February 2011 Swap 25,000,000 1.25
February 2009 - February 2011 Swap 50,000,000 1.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Physical Power Contracts - Canadian Dollar
Fixed
Rate
Volume ($Cdn/
Term (MW/h) MW/h)
-------------------------------------------------------------------------
January 2009 - December 2009 1.0 82.45
January 2009 - December 2009 3.0 81.25
January 2010 - December 2010 3.0 80.75
-------------------------------------------------------------------------Revenues
During the three months ended December 31, 2008, oil revenues decreased
three percent compared to the same period in 2007. This decrease is primarily
the result of a 35 percent decrease in US$ WTI benchmark price during the last
quarter of 2008 compared to the same period in 2007, partially offset by a 22
percent increase in production volumes as a result of the 2008 acquisition of
Pilot Energy Ltd. and non-Bakken assets of Landex Petroleum Corp. ("Landex")
as well as successful drilling results.
Oil revenues were $1.1 billion for the twelve months ended December 31,
2008 compared to $598.4 million in 2007. The 88 percent increase relates
primarily to 38 percent increase in the US$ WTI benchmark price for 2008
compared to 2007 and a 34 percent increase in production volumes as a result
of the 2008 acquisition of Pilot Energy Ltd. and non-Bakken assets of Landex
as well as the Trust's successful drilling program.
During the three months ended December 31, 2008, natural gas revenues
increased 12 percent compared to the same period in 2007. This increase is the
result of nine percent increase in the AECO daily gas price, partially offset
by a two percent decline in production volumes.
Natural gas sales increased 64 percent in 2008 compared to 2007. The
increase is the result of a 27 percent increase in the AECO daily gas price
and a 28 percent increase in production volumes as a result of acquisitions
and the Trust's successful drilling program.
On July 23, 2008, the Trust announced that it has a potential exposure to
SemCanada Crude Company ("SemCanada"), a Canadian subsidiary of SemGroup, L.P.
("SemGroup"), relating to the marketing of a portion of the Trust's crude oil
and liquids production. The contract pertaining to the majority of the
production volumes purchased by SemCanada was previously terminated and does
not represent an ongoing exposure for the Trust. SemGroup filed a voluntary
petition for reorganization under Chapter 11 of the Bankruptcy Code in the
United States Bankruptcy Court for the District of Delaware and SemCanada also
filed for creditor protection in Canada under The Companies' Creditors
Arrangement Act. The Trust's actual exposure is approximately $31.1 million
based on confirmed production volumes and contract prices.
During the fourth quarter of 2008, the Trust recorded a $19.4 million bad
debt provision based on the Trust's estimate of uncollectible amounts from
SemCanada at December 31, 2008.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
% %
($000)(1) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Crude oil and NGL
sales 192,684 198,174 (3) 1,125,300 598,364 88
Natural gas sales 18,580 16,574 12 88,376 53,811 64
-------------------------------------------------------------------------
Revenues 211,264 214,748 (2) 1,213,676 652,175 86
-------------------------------------------------------------------------
(1) Revenue is reported before transportation charges and realized
derivatives.Transportation Expense
During the three months ended December 31, 2008, transportation expenses
were $1.60 per boe compared to $1.83 in the previous year. This decrease is
the result of a reduction in pipeline capacity constraints in southeast
Saskatchewan as described below.
For the twelve months ended December 31, 2008, transportation expense per
boe increased eight percent compared to 2007. The increase relates to pipeline
constraint issues in southeast Saskatchewan which began in the fourth quarter
of 2006 and continued through until mid-2008. Growing production volumes in
southeast Saskatchewan and incremental imports from other areas had exceeded
capacity of the area's major oil gathering system, Enbridge Pipelines
(Saskatchewan). Efforts to maintain crude sales led to incremental trucking
costs throughout 2007 and most of 2008.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except per % %
boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Transportation
expenses 5,813 5,626 3 25,608 17,725 44
Per boe 1.60 1.83 (13) 1.87 1.73 8
-------------------------------------------------------------------------Royalty Expenses
During the three months ended December 31, 2008, royalties as a
percentage of sales were 16 percent compared to 18 percent in the same period
in 2007. This decrease is the result of the significant decrease in oil
selling prices during the quarter combined with the impact of the royalty
incentives associated with the Trust's drilling program in Saskatchewan.
Royalties as a percentage of sales were 18 percent during the twelve
months ended December 31, 2008, consistent with the same period in 2007.
Royalties per boe increased 39 percent during 2008 compared to 2007. This
increase is primarily the result of the 40 percent increase in realized sales
prices in 2008 compared to 2007.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except per % %
boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Total royalties 34,672 39,295 (12) 220,225 118,915 85
As a % of oil and
gas sales 16% 18% (2) 18% 18% -
Per boe 9.53 12.81 (26) 16.09 11.59 39
-------------------------------------------------------------------------Operating Expenses
Operating expenses per boe during the three months ended December 31,
2008 were consistent with the same period in 2007.
Operating expense per boe decreased by three percent from $9.25 per boe
in 2007 to $9.01 per boe in 2008. This decrease in operating costs relates
primarily to the growth of the high quality Bakken crude production which has
lower average operating costs due to its geographical concentration,
relatively new production and benefit of significant Trust infrastructure
including an 18 mmcf/d gas processing plant and several batteries.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except per % %
boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Operating expenses 33,584 28,192 19 123,316 94,918 30
Per boe 9.23 9.19 - 9.01 9.25 (3)
-------------------------------------------------------------------------Netbacks
During the three months ended December 31, 2008, Crescent Point's
operating netback decreased five percent from $42.48 per boe in 2007 to $40.42
per boe in 2008. This decrease is primarily the result of the decrease in the
average selling price as a result of a decrease in the US$ WTI benchmark
price, partially offset by a realized gain on derivatives during 2008 compared
to a loss in the same period in 2007.
For the twelve months ended December 31, 2008, Crescent Point's operating
netback, after realized loss on derivatives, increased 32 percent from $40.02
per boe to $52.93 per boe. This increase is primarily the result of the
increase in the average selling price as a result of the increase in the US$
WTI benchmark price, partially offset by realized derivative losses during
2008. The realized derivative losses did not completely offset the benefits of
the increased average selling price due to the increase in average derivative
prices for contracts maturing in 2008 and the Trust's policy to hedge up to a
maximum of 65% of its after royalty production.
After adjusting for the Trust's derivative crystallization, the Trust's
netback for the year was further reduced by $2.52 per boe to $50.41 per boe.
As discussed earlier, this realized derivative crystallization loss will be
recovered through higher reset derivative prices entered into in 2009 and
2010.-------------------------------------------------------------------------
Three months ended December 31
2008 2007
-------------------------------------------------------------------------
Crude Oil Natural
and NGL Gas Total Total %
($/bbl) ($/mcf) ($/boe) ($/boe) Change
-------------------------------------------------------------------------
Average selling
price 60.02 7.23 58.06 69.99 (17)
Royalties (9.54) (1.57) (9.53) (12.81) (26)
Operating expenses (8.30) (2.69) (9.23) (9.19) -
Transportation (1.65) (0.20) (1.60) (1.83) (13)
-------------------------------------------------------------------------
Netback prior to
realized
derivatives 40.53 2.77 37.70 46.16 (18)
-------------------------------------------------------------------------
Realized gain
(loss) on
derivatives 3.07 0.02 2.72 (3.68) 174
-------------------------------------------------------------------------
Operating netback 43.60 2.79 40.42 42.48 (5)
-------------------------------------------------------------------------
Realized loss on
derivative
crystallization - - - - -
-------------------------------------------------------------------------
Netback 43.60 2.79 40.42 42.48 (5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Year ended December 31
2008 2007
-------------------------------------------------------------------------
Crude Oil Natural
and NGL Gas Total Total %
($/bbl) ($/mcf) ($/boe) ($/boe) Change
-------------------------------------------------------------------------
Average selling
price 94.36 8.36 88.67 63.55 40
Royalties (17.13) (1.51) (16.09) (11.59) 39
Operating expenses (8.78) (1.76) (9.01) (9.25) (3)
Transportation (1.96) (0.22) (1.87) (1.73) 8
-------------------------------------------------------------------------
Netback prior to
realized
derivatives 66.49 4.87 61.70 40.98 51
-------------------------------------------------------------------------
Realized gain
(loss) on
derivatives (10.04) (0.03) (8.77) (0.96) 814
-------------------------------------------------------------------------
Operating netback 56.45 4.84 52.93 40.02 32
-------------------------------------------------------------------------
Realized loss on
derivative
crystallization(1) (2.89) - (2.52) - -
-------------------------------------------------------------------------
Netback 53.56 4.84 50.41 40.02 26
-------------------------------------------------------------------------
(1) The Trust realized a $34.5 million loss in the second quarter of
2008 resulting from the crystallization of various oil contracts.General and Administrative Expenses
General and administrative expenses increased 502 percent for the three
months ended December 31, 2008 compared to the same period in 2007. This
increase is the result of a $19.4 million provision for uncollectible amounts
from SemCanada as discussed above. Excluding this one time write-down, general
and administrative expenses were $1.14 per boe during the fourth quarter of
2008.
General and administrative expenses increased 167 percent for the twelve
months ended December 31, 2008 compared to 2007. In addition to the fourth
quarter bad debt provision, the year ended December 31, 2008 also has the
special bonus award paid to employees of the Trust in the second quarter of
2008. Excluding the bad debt provision and special bonus award, general and
administrative expenses were $1.12 per boe for the year ended December 31,
2008.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
General and
administrative
costs 26,328 5,402 387 52,148 19,965 161
Capitalized (2,785) (1,488) 87 (11,181) (4,607) 143
-------------------------------------------------------------------------
General and
administrative
expenses 23,543 3,914 502 40,967 15,358 167
Provision for
uncollectible
amounts from
SemCanada (19,380) - - (19,380) - -
-------------------------------------------------------------------------
General and
administrative
expenses,
excluding
provision for
uncollectible
amounts from
SemCanada 4,163 3,914 6 21,587 15,358 41
Per boe 1.14 1.28 (11) 1.58 1.50 5
-------------------------------------------------------------------------Restricted Unit Bonus Plan
The Trust has a Restricted Unit Bonus Plan and under the terms of this
plan, the Trust may grant restricted units to directors, officers, employees
and consultants. Restricted units vest at 33 1/3 percent on each of the first,
second and third anniversaries of the grant date or at a date approved by the
Board of Directors. Restricted unitholders are eligible for monthly
distributions, immediately upon grant.
On May 30, 2008, at the annual general meeting, the unitholders approved
an increase in the maximum number of trust units issuable under the Restricted
Unit Bonus Plan from 5,000,000 units to 11,000,000 units. The Trust had
2,325,302 restricted units outstanding at December 31, 2008 compared with
1,486,050 units outstanding at December 31, 2007.
During the three months ended December 31, 2008, the Trust recorded
compensation expense and contributed surplus of $9.7 million, based on fair
value of units on the date of grant, an increase of 156 percent over 2007. The
cash distributions on restricted units increased from $0.6 million for the
three months ended December 31, 2007 to $1.0 million for the same period in
2008. The total cash and non-cash unit based compensation recorded in the
fourth quarter of 2008 was $10.7 million compared to $4.3 million during 2007.
This increase is the result of an increase in the number of restricted units
granted (see below) and an increase in the fair value at the time of grant.
During the twelve months ended December 31, 2008, the Trust recorded
compensation expense and contributed surplus of $27.4 million in 2008, based
on fair value of units on the date of grant, an increase of 91 percent over
2007. The cash distributions on restricted units increased from $2.0 million
for the 2007 year to $3.3 million for the 2008 year. The total cash and non-
cash unit based compensation recorded in the year 2008 was $30.8 million, as
compared to $16.4 million in 2007, an increase of 88 percent. This increase is
due to the issuance approved by the Board of Directors effective July 1, 2008
of 551,622 restricted units to employees of the Trust in conjunction with the
special bonus award, an increase in the fair value per unit at the time of
grant and the growth in the Trust's operations combined with industry
pressures to retain and attract high quality employees.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash unit-based
compensation
expense 1,000 559 79 3,343 1,997 67
Non-cash
unit-based
compensation
expense 9,683 3,786 156 27,435 14,378 91
-------------------------------------------------------------------------
Total 10,683 4,345 146 30,778 16,375 88
Per boe 2.94 1.42 107 2.25 1.60 41
-------------------------------------------------------------------------Interest Expense
Interest expense increased 20 percent and 54 percent for the three and
twelve months ended December 31, 2008. This increase is attributable to
increased amounts drawn on credit facilities throughout the year reflecting
the growth of the Trust. This increase was partially offset by a decrease in
the prime rate through the majority of the year. Crescent Point actively
manages exposure to fluctuations in interest rates through interest rate swaps
and short term banker's acceptances (refer to Derivatives and Risk Management
section above).-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Interest expense 9,700 8,107 20 33,484 21,805 54
Per boe 2.67 2.64 1 2.45 2.12 16
-------------------------------------------------------------------------
Depletion, Depreciation and Amortization
The depletion, depreciation and amortization expense per boe were $22.70
and $23.05 for the three and twelve months ended December 31, 2008,
respectively, and were consistent with the same periods in 2007. During 2008,
the net capital acquisitions did not have a significant impact on the Trust's
depletion rate.
-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Depletion,
depreciation
and amortization 82,594 68,017 21 315,483 242,923 30
Per boe 22.70 22.17 2 23.05 23.67 (3)
-------------------------------------------------------------------------Taxes
Capital Tax and Other Expense
Capital and other tax expense consists of Saskatchewan Corporation
Capital Tax Resource Surcharge. Capital and other tax expense for the fourth
quarter of 2008 decreased 34 percent over 2007 due to a decrease in the
Trust's realized oil price reflecting the lower market prices, partially
offset by an increase in the Trust's Saskatchewan based production, primarily
as a result of the acquisitions of Innova, Pilot and the non-Bakken assets of
Landex completed over the past year and the Trust's development drilling
program.
The Trust's capital and other tax expense for the year ended December 31,
2008 increased 30 percent over the comparable 2007 period due to higher
realized oil prices and an increase in production levels.
Future Income Tax Expense
Future income tax expense increased from $18.0 million in the fourth
quarter of 2007 to $73.9 million in the fourth quarter of 2008. The expense in
the fourth quarter of 2008 relates primarily to a larger amount of temporary
differences expected to reverse in 2011 and beyond and a larger distribution
of income and temporary differences to corporate entities during the period,
which are taxed at higher rates than the trust entities. In addition, the
significant unrealized gain on derivatives of $416.8 million also contributed
to the increase in the future tax expense in the fourth quarter of 2008.
The future income tax expense for the year ended December 31, 2008 was
$77.3 million as compared to $21.2 million in 2007. The expense in 2008
relates primarily to a larger amount of temporary differences expected to
reverse in 2011 and beyond and a larger distribution of income and temporary
differences to corporate entities during the period, which are taxed at higher
rates than the trust entities. In addition, the significant unrealized gain on
derivatives of $294.3 million also contributed to the increase in the future
tax expense in 2008.
At December 31, 2008, the Trust had tax pools of approximately $1.3
billion (2007 - $1.0 billion) consisting of intangible resource pools,
tangible pools and trust unit issue costs.
Enactment of Tax on Income Trusts
On June 22, 2007, income trust tax legislation was passed resulting in
tax on the distributions of publicly traded income trusts and limited
partnerships, referred to as "Specified Investment Flow-Through" ("SIFT")
entities, commencing in 2011 (the "SIFT Tax Rules"). The tax on distributions
includes tax at the federal corporate income tax rate plus a deemed 13 percent
provincial income tax at the Trust level. 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 is not expected to impact
the Trust until 2011, provided that the Trust does not exceed the normal
growth guidelines announced by the Department of Finance.
On February 26, 2008, the federal government announced that beginning
with the 2009 taxation year, the provincial component of the trust tax will be
based on the general provincial corporate tax rate in each province in which
the trust has a permanent establishment instead of the deemed 13 percent
provincial tax rate. As the proposed rules were not substantively enacted as
of December 31, 2008, the Trust has not reflected a reduced tax rate in the
calculation of future income taxes in 2008.
On November 28, 2008, the Department of Finance released draft
legislation to allow the conversion of SIFT trusts into corporations. The
legislation has two main elements. The first allows unitholders to sell their
units to a taxable Canadian corporation on a tax-deferred basis. The second
element provides two alternatives for the tax-deferred elimination of trusts.
The draft legislation provides that trusts will have a limited period of time,
until December 31, 2012, to convert to corporations on a tax-deferred basis.
The draft legislation also included draft income tax regulations regarding the
calculation of the provincial tax rate which will apply as part of the SIFT
tax. A Notice of Ways and Means that includes the proposed legislation to
facilitate the conversion of income trusts into corporations was tabled by the
Minister of Finance on February 1, 2009.
The Explanatory Notes released on December 4, 2008 in respect of the
November 28, 2008 draft legislation, announced the elimination to the staging
of the Safe Harbour limits for 2009 and 2010. Income trusts are now permitted
to accelerate the utilization of their annual Safe Harbour limits for 2009 and
2010, without penalty. With the acquisition from Talisman, the Trust is close
to its Safe Harbour limit.
The Board has agreed to a strategic conversion to a dividend paying
corporation. The conversion, which the Trust expects to complete on or before
May 31, 2009, will be subject to unitholder approval as well as customary
court and regulatory approvals.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
% %
($000) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Capital and
other tax
expense 3,233 4,874 (34) 20,031 15,394 30
Future income tax
expense 73,850 17,965 311 77,308 21,173 265
-------------------------------------------------------------------------Funds Flow, Cash Flow and Net Income
Funds flow from operations decreased to $109.6 million in the fourth
quarter of 2008 from $112.6 million in the fourth quarter of 2007 and
decreased to $0.87 per unit - diluted from $0.99 per unit - diluted,
respectively. The decrease in funds flow from operations and funds flow from
operations per unit - diluted is primarily the result of the $19.4 million bad
debt provision and the decrease in the operating netback, partially offset by
increased production volumes. The Trust's operating netback decreased five
percent primarily as a result of the decline in the Cdn$ WTI benchmark
pricing, partially offset by realized gains on derivatives and lower royalty
costs.
In the twelve months ended December 31, 2008, funds flow from operations
increased 66 percent to $592.1 million compared to $355.9 million in the same
period during 2007. This increase is primarily the result of higher operating
netbacks and increased production volumes. The operating netback increased 32
percent primarily the result of increases in the Cdn$ WTI benchmark pricing,
partially offset by increased losses on derivative contracts.
Cash flow from operating activities in the fourth quarter of 2008
increased to $125.6 million from $99.1 million during the fourth quarter 2008.
Cash flow from operating activities per unit - diluted increased 14 percent to
$0.99 per unit - diluted in the fourth quarter of 2008 from $0.87 per unit -
diluted for the same period in 2007. The increase in cash flow from operating
activities and cash flow from operating activities per unit - diluted is a
result of the same factors above and further increased by fluctuations in
operating working capital.
Cash flow from operating activities in the twelve months ended December
31, 2008 increased to $585.0 million from $332.6 million during 2007. Cash
flow from operating activities per unit - diluted increased 42 percent to
$4.67 per unit - diluted during 2008 from $3.28 per unit - diluted during
2007. The increase in cash flow from operating activities and cash flow from
operating activities per unit - diluted is a result of the same factors above
and further increased by fluctuations in operating working capital.
Net income for the fourth quarter of 2008 increased to $361.4 million
from a loss of $90.3 million during the fourth quarter of 2007. The increase
is primarily the result of realized derivative gains of $9.9 million and
unrealized derivative gains of $416.8 million during 2008 compared to realized
derivative losses of $11.3 million and unrealized derivative losses of $112.2
million during the fourth quarter of 2008. The trend in net income per unit -
diluted was also driven by the same factors.
The Trust recorded net income of $464.1 million during the twelve months
ended December 31, 2008 compared to a loss of $32.2 million during 2007. This
increase is the result of higher operating netbacks, increased production and
unrealized derivative gains of $294.3 million, partially offset by realized
derivative losses of $154.6 million during 2008. The trend in net income per
unit - diluted was also driven by the same factors.
Excluding the derivative crystallization of $34.5 million and $19.4
million bad debt provision for SemCanada: funds flow from operations for the
twelve months ended December 31, 2008 would have been $646.0 million or $5.16
per unit - diluted; cash flow from operations for 2008, would have been $638.9
million or $5.10 per unit - diluted; and net income would have been $518.0
million or $4.14 per unit - diluted. Lastly, excluding the $34.5 million
derivative crystallization, the realized derivative loss would have been
$120.1 million.
As noted in the Derivatives and Risk Management section, the Trust has
not designated any of its risk management activities as accounting hedges
under the CICA Handbook section 3855 and, accordingly, has marked-to-market
its derivatives.
Crescent Point uses financial derivatives, including swaps, costless
collars and put options, to reduce the volatility of the selling price of its
crude oil and natural gas production. This provides a measure of stability to
the Trust's cash flows and distributions over time.
The Trust's derivatives portfolio extends out 3 1/2 years from the
current quarter.
The CICA Handbook section 3855 "Financial Instruments - Recognition and
Measurement", gives guidelines for mark to market accounting for financial
derivatives. Financial derivatives that have not settled during the current
quarter are marked to market each quarter. The change in mark to market from
the previous quarter represents a gain or loss that is recorded on the income
statement. As such, if benchmark oil and natural gas prices rise during the
quarter, the Trust records a loss based on the change in price multiplied by
the volume of oil and natural gas hedged. If prices fall during the quarter,
the Trust records a gain. The prices used to record the actual gain or loss
are subject to an adjustment for volatility, then the resulting gain (asset)
or loss (liability) is discounted to a present value using a risk-free rate
adjusted for counterparty risk.
The Trust's underlying physical reserves are not marked to market each
quarter, hence no gain or loss associated with price changes is recorded; the
Trust realizes the benefit/detriment of any price increase/decrease in the
period which the physical sales occur.
The Trust's financial results should be viewed with the understanding
that the future gain or loss on financial derivatives is recorded in the
current period's results, while the future value of the underlying physical
sales is not.-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Funds flow from
operations 109,635 112,572 (3) 592,132 355,910 66
Funds flow from
operations per
unit
- diluted(1) 0.87 0.99 (12) 4.73 3.51 35
Cash flow from
operating
activities 125,625 99,070 27 584,955 332,605 76
Cash flow from
operating
activities per
unit-diluted(1) 0.99 0.87 14 4.67 3.28 42
Net income 361,411 (90,348) 500 464,102 (32,167) 1,543
Net income per
unit
- diluted(1) 2.84 (0.80) 455 3.71 (0.32) 1,259
-------------------------------------------------------------------------
(1) Per unit - diluted is calculated by excluding the cash portion of
unit based compensation.Cash Distributions
In June 2008, the Trust increased its monthly distribution from $0.20 per
unit to $0.23 per unit.
Distributions for the year ending December 31, 2008 were $2.61 per unit,
compared to $2.40 per unit during 2007. The distribution increase is the
result of Crescent Point's growing cash flow per unit, which was due to higher
than expected commodity prices throughout the majority of 2008, increased
production levels and higher netbacks resulting from the Trust's successful
Bakken drilling program. Crescent Point believes it is well positioned to
maintain its current monthly distribution over time as the Trust continues to
exploit and develop its current base. The Trust's risk management strategy
minimized corporate price volatility and provides a measure of sustainability
to distributions through periods of fluctuating market prices.
The Trust's derivative crystallization and reset program, discussed
above, will provide further certainty to 2009 and 2010 cash flows and
distributions. The impact of resetting the 2009 and 2010 derivatives will
increase the Trust's 2009 and 2010 average hedge prices. The cash outflow from
the derivative crystallization and reset program during the year ended
December 31, 2008 was $34.5 million.
Cash distributions increased 27 percent and 33 percent, respectively, for
the three and twelve months ended December 31, 2008 compared to 2007. The rise
in distributions is the result of increases in the distribution rate and the
number of units outstanding, resulting from the Pilot acquisition in the first
quarter of 2008 along with bought deal financings which closed in September
2007 and January 2008.The following table provides a reconciliation of cash distributions:
-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000, except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Accumulated cash
distributions,
beginning of
period 774,057 467,579 66 535,550 290,442 84
Cash
distributions
declared to
unitholders(1) 86,314 67,971 27 324,821 245,108 33
-------------------------------------------------------------------------
Accumulated cash
distributions,
end of period 860,371 535,550 61 860,371 535,550 61
-------------------------------------------------------------------------
Accumulated cash
distributions
per unit,
beginning of
period 11.58 9.06 28 9.66 7.26 33
Cash
distributions
declared to
unitholders per
unit(1) 0.69 0.60 15 2.61 2.40 9
-------------------------------------------------------------------------
Accumulated cash
distributions
per unit, end
of period 12.27 9.66 27 12.27 9.66 27
-------------------------------------------------------------------------
(1) Cash distributions reflect the sum of the amounts declared monthly to
unitholders, including distributions under the DRIP and Premium DRIP
plans.For the three and twelve months ended December 31, 2008, cash flow from
operating activities of $125.6 million and $585.0 million, respectively,
exceeded cash distributions of $86.3 million and $324.8 million, respectively.
This trend was consistent for 2007 and 2006.
Net income for the three month period ended December 31, 2008 of $361.4
million exceeded cash distributions of $86.3 million, primarily due to the
significant unrealized gain on derivatives of $416.8 million.
Net income for the twelve months ended December 31, 2008 of $464.1
million exceeded cash distributions of $324.8 million, primarily due to the
significant unrealized gain on derivatives of $294.3 million. Net income
includes significant non-cash income or charges that do not impact the cash
flow which in the fourth quarter were a net $251.8 million of non-cash income
and net $128.0 million of non-cash charges for the twelve months ended
December 31, 2008. The non-cash fluctuations include changes in future income
taxes due to changes in the tax rates and tax rules, unrealized gains on
derivatives, depletion and unit based compensation.
Crescent Point does not anticipate cash distributions will exceed cash
flow from operating activities however it is likely they will exceed net
income as noted above given the significant non-cash items that are recorded
such as future income taxes, depletion, unit-based compensation and unrealized
gains (losses) on derivatives. Further, the cash flow from operating
activities can be significantly impacted by large fluctuations in working
capital that may vary quarter-to-quarter but level out over the period.
An objective of the Trust's distribution policy is to provide unitholders
with relatively stable and predictable monthly distributions. An additional
objective is to retain a portion of funds flow from operations to fund ongoing
development and optimization projects designed to enhance the sustainability
of the Trust's funds flow from operations.
Although the Trust strives to provide unitholders with stable and
predictable funds flow from operations, the percentage of funds flow from
operations paid to unitholders each month may vary according to a number of
factors, including fluctuations in resource prices, exchange rates and
production rates, reserves growth, the size of development drilling programs
and the portion thereof funded from funds flow from operations and the overall
level of debt of the Trust. The actual amounts of the distributions are at the
discretion of the Board of Directors. In the event that commodity prices are
higher than anticipated and a cash surplus develops, such surplus may be used
to increase distributions, reduce debt and/or increase the capital program.
The Trust has a strong balance sheet and a balanced three and a half year
derivative profile and is, therefore, well positioned to sustain distributions
over time as Crescent Point continues to exploit and develop its asset base
and actively identify and evaluate acquisition opportunities. As discussed
above, there are many factors impacting the Trust's ability to sustain
distributions. The Trust continues to monitor these factors in connection with
setting long term sustainable distribution levels.The following table provides a reconciliation of distributable cash:
-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
($000) 2008 2007 2008 2007 2006
-------------------------------------------------------------------------
Cash flow from
operating
activities 125,625 99,070 584,955 332,605 177,426
Net income (loss) 361,411 (90,348) 464,102 (32,167) 68,947
Cash distributions
paid or payable 86,314 67,971 324,821 245,108 150,277
-------------------------------------------------------------------------
Excess of cash
flows from
operating
activities over
cash distributions
paid 39,311 31,099 260,134 87,497 27,149
-------------------------------------------------------------------------
Excess (shortfall)
of net income
(loss) over cash
distributions paid 275,097 (158,319) 139,281 (277,275) (81,330)
-------------------------------------------------------------------------Taxation of Cash Distributions
Cash distributions are comprised of a return on capital portion (taxable)
and a return of capital portion (tax deferred). For cash distributions
received by Canadian residents outside of a registered pension or retirement
plan in the 2008 taxation year, the distributions are 100 percent taxable.
The following table outlines the breakdown of the cash distributions per
unit paid or payable by the Trust with respect to the record dates from
January 31, 2008 to December 31, 2008 for Canadian income tax purposes:-------------------------------------------------------------------------
Tax
Taxable Deferred
Amount Amount Total
(Box 26 (Box 42 Cash
Other Return of Distri-
Record Date Payment Date Income) Capital) bution
-------------------------------------------------------------------------
January 31, 2008 February 15, 2008 $0.20 - $0.20
February 29, 2008 March 17, 2008 $0.20 - $0.20
March 31, 2008 April 15, 2008 $0.20 - $0.20
April 30, 2008 May 15, 2008 $0.20 - $0.20
May 31, 2008 June 16, 2008 $0.20 - $0.20
June 30, 2008 July 15, 2008 $0.23 - $0.23
July 31, 2008 August 15, 2008 $0.23 - $0.23
August 31, 2008 September 15, 2008 $0.23 - $0.23
September 30, 2008 October 15, 2008 $0.23 - $0.23
October 31, 2008 November 17, 2008 $0.23 - $0.23
November 30, 2008 December 15, 2008 $0.23 - $0.23
December 31, 2008 January 15, 2009 $0.23 - $0.23
-------------------------------------------------------------------------
TOTAL PER UNIT $2.61 - $2.61
-------------------------------------------------------------------------Investments in Marketable Securities
During the year ended December 31, 2007, the Trust owned shares of
publicly traded exploration and production companies. In accordance with new
accounting standards for financial instruments, the Trust marked-to-market its
investment in marketable securities in the first quarter of 2007. The carrying
amount of $0.1 million at December 31, 2006 was increased to $1.6 million at
January 1, 2007 to reflect the fair value of the investment. The unrealized
gain of $1.5 million at January 1, 2007 was recorded through retained
earnings. In the second quarter of 2007, the Trust sold the securities for a
realized gain of $1.4 million.
In the fourth quarter of 2007, the Trust received 1.5 million shares of a
publicly traded exploration and production company for $1.00 per share or $1.5
million in connection with a disposition of properties. The fair value at
December 31, 2007 was $1.4 million, resulting in an unrealized loss on
investment of $0.1 million recorded through the income statement. Throughout
2008, the Trust continued to hold these shares and recorded an unrealized loss
of $1.4 million and $0.8 million, for the three months and twelve months ended
Dec 31, 2008, respectively.
Long-Term Investments
a) Wild River Resources Ltd.
On December 15, 2008, the Trust announced that it had acquired a 17
percent ownership of Wild River Resources Ltd., a private oil and gas producer
with assets in the southeast Saskatchewan Bakken light oil resource play and
in the emerging southwest Saskatchewan Lower Shaunavon resource play. The
total investment of $20.0 million was acquired through a private placement
financing.
b) Shelter Bay Energy Inc.
During the first quarter of 2008, the Trust invested in Shelter Bay, a
private Bakken light oil growth company. At that time, the Trust also entered
into a Call Obligation Agreement with Shelter Bay in exchange for Special
Voting Shares. Pursuant to the agreement, the Trust committed to subscribe for
additional Class A Common Shares of Shelter Bay if so requested by Shelter Bay
for approximately $45.4 million. In connection with this capital commitment,
the Trust received 45.4 million Special Voting Shares. Other major investors
of Shelter Bay also entered into similar Call Obligation Agreements with
Shelter Bay. As a result, the Trust's equity interest would not change
significantly in connection with the Call Obligation Agreement.
The Trust accounts for its investment in Shelter Bay using the equity
method.
The Trust's initial investment of $76.3 million was comprised of 72.6
million Class A Common Shares and 3.5 million Non-Voting Common Shares, issued
for $1.00 per share.
During the second quarter of 2008, the Trust, pursuant to the Call
Obligation Agreement, invested a further $20.0 million in Shelter Bay in
return for an additional 20.0 million Class A Common Shares.
During the third quarter of 2008, Shelter Bay exercised its remaining
call rights under the Call Obligation Agreements. As a result the Trust
subscribed for approximately 25.4 million Class A Common Shares for $25.4
million in July 2008. This subscription satisfied in full the Trust's
commitment under the Call Obligation Agreement. On September 5, 2008, the
Trust exchanged with Shelter Bay 3.5 million Non-Voting Common Shares of
Shelter Bay for 3.5 million Class A Common Shares of Shelter Bay.
In the fourth quarter of 2008, the Trust invested a further $78.7 million
in Shelter Bay through participation in private placement financing for an
additional 52.4 million Class A Common Shares.
At December 31, 2008, the Trust's investment of $200.4 million consists
of 173.9 million Class A Common Shares, which represents an interest of 21
percent.
Under the terms of the unanimous shareholders' agreement governing
Shelter Bay (the "Shelter Bay USA"), the Trust has a right to purchase all,
but not less than all, of the shares of Shelter Bay not already owned by the
Trust (the "Call Right") at a price equal to the market value of the shares,
as defined in the Shelter Bay USA. The Call Right is exercisable at (i) any
time before April 1, 2011, provided that the proceeds from such a transaction
(including cumulative distributions) would result in the initial investors in
Shelter Bay receiving realized proceeds equal to at least two times the amount
of the aggregate capital invested by the initial investors and the Trust in
Shelter Bay, or (ii) any time on or after April 1, 2011 and on or before March
31, 2013.
Upon exercise of the Call Right, and acceptance by 66 2/3% or greater of
the shares held by Shelter Bay shareholders (excluding the Trust), the Trust
will have the right to acquire all of the Shelter Bay shares it does not own.
In the event of acceptance by less than 66 2/3% of the shares held by Shelter
Bay shareholders (excluding the Trust), the Trust shall have the right to
purchase all of the assets (the "Asset Call Right") of Shelter Bay for 105% of
the market value of the assets, as defined in the Shelter Bay USA.
In the event Crescent Point exercises its Call Right or Asset Call Right,
Class B and C Common Share shareholders will be entitled to receive 100
percent of all proceeds from the sale transaction up to their original
investment in Shelter Bay plus a 10 percent return on investment. Class A
Common Share shareholders would then receive 100 percent of their original
investment in the Company plus a 10 percent return on investment. Subsequent
proceeds up to and until a 25 percent return on investment to all Common
Shareholders, would be shared on a pro rata basis by shareholders in
accordance with the number of shares held by each shareholder. Following
receipt of a 25 percent return on investment by all Common Shareholders, the
remaining proceeds would be shared 50 percent by Crescent Point and 50 percent
by all Common Shareholders on a pro rata basis.
As at December 31, 2008, no conditions exist which would require the
Trust to record a liability pursuant to the Shelter Bay USA.
Also under the Shelter Bay USA, between April 1, 2013 and September 30,
2013, certain Shelter Bay shareholders shall have a separate right to require
that the Trust acquire all of the shares of Shelter Bay then owned by such
shareholder for a purchase price equal to 85% of the market value of such
shares, as defined in the Shelter Bay USA (the "Put Right"). If the Put Right
is exercised, the Trust will be obligated to provide all of the other
shareholders in Shelter Bay with a similar right to put their shares to the
Trust on the same terms.
The purchase price for the Shelter Bay shares may be settled, at the
Trust's election, in cash or the issuance of Trust Units; however, the Shelter
Bay shareholders shall have certain rights to receive their consideration for
their Shelter Bay shares in the form of Trust Units.
Notwithstanding the foregoing, the Trust shall have no obligation to
cause to be issued Trust Units under the Shelter Bay USA in an amount that
would cause the Trust to lose its grandfathered status under the SIFT Rules by
violating the "normal growth" guidelines. Given the terms of the Shelter Bay
USA, there can be no assurance that the Trust will not be required to, or will
not elect to purchase the shares of Shelter Bay not already owned by the Trust
or the assets of Shelter Bay and further, there can be no assurance that the
Trust will have the capital resources to satisfy such Call Right or Put Right
or that it will be able to issue Trust Units to Shelter Bay shareholders in
association with the exercise of the Call Right or Put Right described herein,
which number of Trust Units may be material to the Trust at the time of
issuance and which issuance may be dilutive to existing holders of Trust Units
at such time.
Related Party Transactions
At December 31, 2008, the Trust's investment of $200.4 million consisted
of 173.9 million Class A Common Shares, which represents an interest of 21
percent, plus the equity earnings of $4.5 million.The following related party transactions occurred between Crescent Point
and Shelter Bay during 2008;
- Management and Technical Services Agreement - The Trust entered into
a Management and Technical Services Agreement with Shelter Bay,
effective January 11, 2008. The purpose of this agreement is to
reimburse Crescent Point for costs incurred while overseeing the
responsibilities relating to the managing, administering and
operating the assets and business of Shelter Bay. The services are
provided in exchange for a monthly management fee. Crescent Point
billed management fees of $2.5 million to Shelter Bay for the year
ended December 31, 2008.
- Farm-Out Agreement - Effective January 11, 2008, the Trust entered
into a farm-out agreement with Shelter Bay. Under the agreement,
Shelter Bay has the right to farm-in on 22 net sections of Viewfield
Bakken lands owned by the Trust. Shelter Bay is responsible for
paying 100 percent of the capital costs and earns a 50 percent
interest in production from the property, while the Trust retains the
other 50 percent production interest. This agreement gives Crescent
Point the means to drill this undeveloped land and receive 50% of the
production for no capital cost or risk.
- Farm-Out Note - During the first quarter of 2008, as Shelter Bay
commenced operations, the Trust entered into a farm-out note with
Shelter Bay to finance Shelter Bay's capital activities. The
principal amount of the note was $23.5 million and interest on the
note was equivalent to the Canadian Chartered Bank Prime Rate plus 2
percent. The principal amount of the note was re-paid on March 26,
2008, subsequent to Shelter Bay's closing of a private placement.
Interest of $0.2 million was charged by Crescent Point during the
first quarter and collected at the end of April 2008.
- Capital Commitment - Pursuant to Shelter Bay's private placement, the
Trust entered into a Call Obligation Agreement with Shelter Bay in
association with its subscription for Special Voting Shares. Pursuant
to the agreement, the Trust committed to subscribe for additional
Class A Common Shares of Shelter Bay for approximately $45.4 million.
In exchange for this capital commitment, the Trust received 45.4
million Special Voting Shares. Other major investors of Shelter Bay
also entered into similar Call Obligation Agreements with Shelter Bay
and may, at Shelter Bay's discretion be required to subscribe for
additional shares of Shelter Bay. As a result, the Trust's equity
interest would not change significantly in connection with the Call
Obligation Agreement. On May 15, 2008 and July 31, 2008, the Trust
subscribed for approximately, 20.0 million Class A Common shares for
$20.0 million and 25.4 million Class A Common Shares for $25.4
million, respectively. These subscriptions satisfied in full the
Trust's commitment under the Call Obligation Agreement.
- Property Acquisition and Trust Unit Issuance - In conjunction with
the closing of Shelter Bay's acquisition of Landex Petroleum Corp.
("Landex") on March 26, 2008, the Trust issued 3.1 million trust
units valued at $75 million and cash of $5 million to Shelter Bay in
exchange for an $80 million note. The Trust subsequently completed a
Saskatchewan property acquisition from Shelter Bay for total
consideration of $80 million, in exchange for settlement of the note.
The trust unit issuance was recorded at $75 million as this was
equivalent to the fair value of the consideration received. The
property acquisition was recorded at the exchange amount of $80
million. The Saskatchewan properties are within Crescent Point's core
operating area and a strategic fit to the Trust's operations.
- Property Disposition - On March 26, 2008, the Trust disposed of
undeveloped land to Shelter Bay for cash consideration of $31.3
million. The transaction was recorded at the exchange amount. Certain
Bakken undeveloped land acquired by the Trust was sold to Shelter Bay
to enable Shelter Bay to further drill and exploit the resource play.
- Property Acquisition - On December 11, 2008, Crescent Point purchased
undeveloped land from the Shelter Bay for cash consideration of $12.3
million. The transaction was recorded at the exchange amount. This
land was purchased by the Trust to align with strategic investment in
core assets.
- Amounts Owing From / Due To - At December 31, 2008, the Trust had
$3.6 million receivable from Shelter Bay for management fees and
operating activity paid for by the Trust on Shelter Bay's behalf.
These receivables were collected by the Trust at the end of January
2009.
- Painted Pony Petroleum Ltd. ("Painted Pony") Share Disposition - The
Trust entered into an agreement with Shelter Bay to dispose of the
Painted Pony shares for $17.8 million. The transaction was recorded
at the exchange amount. The Trust received shares of Painted Pony as
consideration for an asset disposal and sold these shares to Shelter
Bay which further increased Shelter Bay's investment in Painted Pony.Capital Expenditures
Major Capital Acquisitions
There were no major acquisitions in the fourth quarter of 2008.
Major acquisitions for the year ended December 31, 2008 included Pilot
Energy Ltd. and the non-Bakken assets of Landex Petroleum Corp.
Pilot Energy Ltd.
On January 16, 2008, the Trust purchased all the issued and outstanding
shares of Pilot Energy Ltd., a publicly traded company with properties in the
Viewfield area of southeast Saskatchewan for total consideration of
approximately $78.5 million, including assumed bank debt and working capital
($93.3 million was allocated to property, plant and equipment). The purchase
was paid for through the issuance of approximately 2.6 million trust units and
was accounted for as a business combination using the purchase method of
accounting. The Trust owned 2.0 million shares of Pilot Energy Ltd. prior to
the closing which it purchased for $2.90 per share or $5.9 million in November
2007.
Non-Bakken Assets of Landex Petroleum Corp.
On March 26, 2008, the Trust closed the acquisition of the non-Bakken
assets of Landex Petroleum Corp. from Shelter Bay for consideration of
approximately $80.0 million ($81.4 million was allocated to property, plant
and equipment). The purchase was paid for with approximately 3.1 million trust
units and $5.0 million of cash from the Trust's existing bank line.
Minor Property Acquisitions and Dispositions
During the three months ended December 31, 2008, the Trust closed three
property acquisitions for consideration of approximately $1.5 million ($1.9
was allocated to property plant and equipment) and also closed five property
dispositions for consideration of approximately $1.3 million ($1.4 was
recorded as reduction to property, plant and equipment). Purchase price
adjustments recorded were recoveries of $0.9 million on previously closed
acquisitions for the three months ended December 31, 2008.
During the year ended December 31, 2008, the Trust closed five minor
property acquisitions for $10.8 million ($11.9 million was allocated to
property, plant and equipment), and several property dispositions for a net
consideration of approximately $30.0 million ($31.8 million was recorded as
reduction to property, plant and equipment). The Trust also recorded purchase
price adjustments of $1.6 million on previously closed acquisitions.
Subsequent Events
On January 9, 2009, the Trust and a syndicate of underwriters closed a
bought deal equity financing pursuant to which the syndicate sold 5,227,325
trust units for gross proceeds of $115.0 million ($22.00 per trust unit).
On January 15, 2009, the Trust closed the acquisition of Villanova Energy
Corporation, a private company with properties in the Bakken area of southeast
Saskatchewan by way of a Plan of Arrangement for total consideration of 4.625
million trust units plus the assumption of approximately $23.6 million of
Villanova debt. Total consideration was approximately $123.1 million based on
a value of $21.51 per trust unit.
On March 4, 2009, the Trust announced the acquisition of the Talisman
Energy Inc. ("Talisman") assets in southeast Saskatchewan and Montana for cash
consideration of approximately $720 million effective April 1, 2009. Under the
terms of the agreement, Crescent Point and TriStar Oil & Gas Ltd. ("TriStar")
will jointly and severally acquire the assets. Crescent Point and TriStar have
agreed that each party will acquire 50 percent working interests in the assets
for approximately $360 million. The Trust's share of the acquisition will be
financed with existing credit facilities and through a $230 million bought
deal financing (10,825,000 trust units at $21.25 per trust unit).
Crescent Point and TriStar have also entered into an agreement with
Shelter Bay, under which Crescent Point and TriStar will sell to Shelter Bay a
portion of the Bakken assets (the "Bakken Assets"). Consideration to be
received for the Bakken Assets is approximately $71 million, of which Crescent
Point and TriStar will each receive approximately $35.5 million.
In addition, the Trust announced an intention to convert to a corporation
with a $0.23 monthly dividend.Development Capital
-------------------------------------------------------------------------
Three months ended
December 31 Year ended December 31
% %
($000) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Capital
acquisitions
(net)(1) (705) 408,377 (100) 140,851 1,068,406 (87)
Development
capital
expenditures 92,855 95,385 (3) 454,533 227,923 99
Capitalized
administration 2,785 1,488 87 11,181 4,607 143
Office equipment 180 981 (82) 1,181 3,258 (64)
-------------------------------------------------------------------------
Total 95,115 506,231 (81) 607,746 1,304,194 (53)
-------------------------------------------------------------------------
(1) Capital acquisitions represent total consideration for the
transactions including bank debt and working capital assumed.The Trust's budgeted capital program for 2009 is approximately $225
million, not including acquisitions. The Trust searches for opportunities that
align with strategic parameters and evaluates each prospect on a case-by-case
basis. The Trust's acquisitions are expected to be financed through bank debt
and new equity issuances where applicable within the federal government's Safe
Harbour Limits on equity issuance.
Goodwill
The goodwill balance of $68.4 million as at December 31, 2008 is
attributable to the corporate acquisitions of Tappit Resources Ltd., Capio
Petroleum Corporation and Bulldog Energy Inc. during the period 2003 through
2005. The Trust performed a goodwill impairment test at December 31, 2008 and
no impairment of goodwill exists.
Asset Retirement Obligation
The asset retirement obligation increased by $1.2 million during the
fourth quarter of 2008. This increase relates to liabilities of $0.2 million
recorded in respect of acquisitions and drilling, partially offset by
liabilities disposed of $0.1 million. Accretion expense of $1.4 million was
also recognized, however was partially offset by $0.3 million of liabilities
settled.
The asset retirement obligation increased by $2.7 million during 2008.
The increase relates to liabilities of $7.3 million recorded in respect of
acquisitions and drilling, partially offset by dispositions of $1.8 million.
Accretion expense of $5.4 million was also recognized, however was partially
offset by actual expenditures incurred in the year of $2.3 million. In
addition, there was a reduction of $5.9 million relating to changes in prior
year estimates as a result of the increased reserve lives in the Viewfield
area due to new technology enhancing recoverability.
The reclamation fund increased by $0.2 million during the fourth quarter
of 2008, this increase is the result of contributions of $1.1 million offset
by expenditures of $0.9 million.
The reclamation fund increased $1.6 million during 2008. This increase
relates to an increase in contributions of $5.1 million offset by expenditures
of $3.5 million. Contributions to the fund were $0.30 per barrel of production
throughout the year. The Board of Directors and Management review the adequacy
of the fund annually and adjust contributions as necessary.
Liquidity and Capital Resources
At December 31, 2008, the Trust had a syndicated credit facility with ten
banks and an operating credit facility with one Canadian chartered bank. As at
December 31, 2008, the Trust had bank debt of $918.6 million, leaving
unutilized borrowing capacity of $231.4 million. The credit facility matures
in May 2010, however, the Trust anticipates renegotiating the terms of this
facility in May 2009.
As at December 31, 2008, Crescent Point was capitalized with 19 percent
net debt and 81 percent equity, consistent with the capitalization at December
31, 2007. The Trust's net debt to funds flow from operations ratio at December
31, 2008 was 1.2 times (December 31, 2007 - 1.8 times).
Since the third quarter of 2008, global financial markets have been
trapped in a period of significant uncertainty marked by downward pressure on
equities, overall tightening of credit markets and global economic recession.
Prices for commodities, including crude oil and natural gas, have
deteriorated.
During this period, Crescent Point was successful in entering into an
agreement to acquire assets from Talisman, in raising $115 million of equity
in a bought deal financing and in entering into a bought deal arrangement in
respect of a further $230 million. The Trust's credit facilities were
increased by $150 million with an additional increase expected in conjunction
with the acquisition of the Talisman assets. Shelter Bay raised $300 million
of equity in a private placement in October 2008. The combined $795 million of
financing highlights the high quality nature of the asset bases and the robust
economics of the opportunities that lie ahead for both Crescent Point and
Shelter Bay.
Crescent Point's development capital budget for 2009 was set in December
2008 at $225 million, with average production forecast at 38,250 boe/d.
Assuming the successful completion of the acquisition of the Talisman assets,
Crescent Point has upwardly revised its average 2009 production guidance to
40,500 boe/d, while maintaining its $225 million capital program for the year.
Exit production is forecast greater than 42,000 boe/d.
With low benchmark oil prices early in 2009, the Trust has reduced first
quarter drilling plans and focused on achieving significant cost reductions
and increasing the number of expected fracture stimulation projects. The
capital expenditure reduction in the first quarter has led to an expected 20
percent reduction in Bakken drilling and completions costs to approximately
$1.6 million per Bakken well. With these capital cost reductions, a typical
Bakken horizontal well generates a 140 percent before tax rate of return at
benchmark WTI oil prices of US$45 per barrel and pays out in 10 months. These
robust economics position the Trust well for potential capital budget and
production increases in the second half of 2009 should benchmark WTI oil
prices stabilize above US$45 per barrel.
Crescent Point continues to implement its balanced 3 1/2 year price risk
management program, using a combination of swaps, collars and purchased put
options with investment grade counter parties all within the Trust's banking
syndicate. Effective March 3, 2009, pro forma with the Talisman assets, the
Trust had hedged 54 percent of production volumes net of royalty interests for
the balance of 2009, 38 percent for 2010, 24 percent for 2011 and 12 percent
for the first half of 2012. Quarterly floor prices ranged from Cdn$74 per boe
to Cdn$108 per boe, with upside potential if prices strengthen above current
levels. The Trust's hedge position is significantly in the money, with a mark
to market value of $234 million as of March 3, 2009, including $98 million for
the balance of 2009.
Crescent Point intends to crystallize up to $75 million of its 2011 and
2012 mark to market hedge value in the first quarter of 2009 and intends to
reset those hedges at current market prices, expected to be in the Cdn$75 per
boe to Cdn$80 per boe range. This capitalizes on the Trust's strong 2011 and
2012 hedges while continuing to provide cash flow stability to Crescent Point
over the next 3 1/2 years. Assuming the completion of the crystallization and
reset, Crescent Point's 3 1/2 year average hedge price would be in the range
of Cdn$75 to Cdn$80 per boe while increasing 2009 cash flows by up to $75
million.
Crescent Point is well positioned to withstand the current market
uncertainty and to take advantage of acquisition opportunities. The Trust's
balance sheet is strong with projected 2009 net debt to 12 month cash flow of
1.1 times and its 3 1/2 year risk management program provides cash flow
stability. The Trust's 16 year drilling inventory and current 100 well
fracture stimulation inventory provide long term sustainability and capital
investment flexibility even at low oil prices.
Crescent Point's management believes that with the high quality reserve
base and development inventory, excellent balance sheet and solid hedging
program, the Trust is well positioned to continue generating strong operating
and financial results and delivering sustainable distributions through 2009
and beyond.-------------------------------------------------------------------------
Capitalization Table ($000, except unit, December 31, December 31,
per unit and percent amounts) 2008 2007
-------------------------------------------------------------------------
Bank debt 918,626 595,984
Working capital(1) (187,694) 54,104
-------------------------------------------------------------------------
Net debt(1) 730,932 650,088
Trust units outstanding(2) 125,678,681 113,760,732
Market price at end of period (per unit) 24.09 24.81
Market capitalization 3,027,599 2,822,404
-------------------------------------------------------------------------
Total capitalization 3,758,531 3,472,492
-------------------------------------------------------------------------
Net debt as a percentage of total
capitalization (%) 19 19
-------------------------------------------------------------------------
Annual funds flow from operations 592,132 355,910
-------------------------------------------------------------------------
Net debt to funds flow from operations(3) 1.2 1.8
-------------------------------------------------------------------------
(1) Working capital and net debt include long-term investments and bank
indebtedness, but exclude the risk management liabilities and assets.
(2) The trust units outstanding balance at December 31, 2008 includes
586,881 of units to be issued on January 15, 2009 pursuant to the
DRIP program reinstated in December 2008.
(3) The net debt reflects the financing of acquisitions, however the
funds flow from operations only reflects funds flow from operations
generated from the acquired properties since the closing dates of the
acquisitions.
Unitholders' Equity
At December 31, 2008, Crescent Point had 125.7 million trust units issued
and outstanding compared to 113.8 million trust units at December 31, 2007.
The increase by 11.9 million trust units relates primarily to the bought deal
financing and the acquisition of Pilot in January 2008, combined with the
issuance of units for a property acquisition in March 2008:
- The Trust and a syndicate of underwriters closed a bought deal equity
financing on January 8, 2008 pursuant to which the syndicate sold
5.2 million trust units at $24.25 per trust unit for gross proceeds
of $125.0 million.
- The Trust issued 2.6 million trust units to Pilot shareholders at a
price of $23.12 per trust unit on closing of the acquisition on
January 16, 2008.
- On March 26, 2008, the Trust issued 3.1 million trust units at $24.08
per unit in respect of the southeast Saskatchewan property
acquisition from Shelter Bay, which was completed in conjunction with
Shelter Bay's closing of the Landex acquisition.In December 2007, the Trust announced that as a result of the federal
government Safe Harbour Limits on equity issuances for income trusts, the
DRIP, Premium DRIP and Optional Unit Purchase programs would be suspended
until further notice beginning the month of December 2007.
On December 15, 2008, the Trust announced that the DRIP, Premium DRIP and
Optional Unit Purchase programs would be reinstated for unitholders of record
on December 31, 2008 with payments commencing January 15, 2009.
Crescent Point's total capitalization increased to $3.8 billion at
December 31, 2008 compared to $3.5 billion at December 31, 2007, with the
market value of the trust units representing 81 percent of the total
capitalization. The increase in capitalization is attributable to the increase
in the number of units outstanding partially offset by a three percent decline
in the unit trading price.
Contractual Obligations and Commitments
The Trust has assumed various contractual obligations and commitments in
the normal course of operations. The following table summarizes the Trust's
contractual obligations and commitments as at December 31, 2008:-------------------------------------------------------------------------
Contractual Obligations
Summary ($000) Expected Payout Date
-------------------------------------------------------------------------
Total 2009 2010-2011 2012-2013 After 2013
-------------------------------------------------------------------------
Operating
Leases(1)(2) 104,225 8,398 19,266 16,466 60,095
Premiums on Put
Contracts 13,059 7,176 5,883 - -
-------------------------------------------------------------------------
(1) Operating leases includes leases for office space, equipment and
vehicles.
(2) Included in operating leases are recoveries of rent expense on office
space the Trust has acquired through various acquisitions and has
subleased out to other tenants.Off Balance Sheet Arrangements
The Trust has off-balance sheet financing arrangements consisting of
various lease agreements. All leases have been treated as operating leases
whereby the lease payments are included in operating expenses or general and
administrative 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, 2008. All of the lease agreement amounts have been reflected in
the Contractual Obligations and Commitments table above, which were entered
into in the normal course of operations.
Critical Accounting Estimates
The preparation of the Trust's financial statements requires management
to adopt accounting policies that involve the use of significant estimates and
assumptions. These estimates and assumptions are developed based on the best
available information and are believed by management to be reasonable under
the existing circumstances. New events or additional information may result in
the revision of these estimates over time. A summary of the significant
accounting policies used by Crescent Point can be found in Note 2 to the
December 31, 2008 consolidated financial statements. The following discussion
outlines what management believes to be the most critical accounting policies
involving the use of estimates and assumptions.
Depletion, Depreciation and Amortization ("DD&A")
Crescent Point follows the CICA accounting guideline AcG-16 on full cost
accounting in the oil and gas industry to account for oil and gas properties.
Under this method, all costs associated with the acquisition of, exploration
for and the development of natural gas and crude oil reserves are capitalized
and costs associated with production are expensed. The capitalized costs are
depleted using the unit-of-production method based on estimated proved
reserves using management's best estimate of future prices (see Oil and Gas
Reserves discussion below).
Reserve estimates can have a significant impact on earnings, as they are
a key component in the calculation of depletion. A downward revision in a
reserve estimate could result in a higher DD&A charge to earnings. In
addition, if net capitalized costs are determined to be in excess of the
calculated ceiling, which is based largely on reserve estimates (see Asset
Impairment discussion below), the excess must be written off as an expense
charged against earnings. In the event of a property disposition, proceeds are
normally deducted from the full cost pool without recognition of a gain or
loss unless there is a change in the DD&A rate of 20 percent or greater.
Asset Retirement Obligation
Upon retirement of its oil and gas assets, the Trust anticipates
incurring substantial costs associated with asset retirement activities.
Estimates of the associated costs are subject to uncertainty associated with
the method, timing and extent of future retirement activities. A liability for
these costs and a related asset are recorded using the discounted asset
retirement costs and the capitalized costs are depleted on a unit-of-
production basis over the associated reserve life. Accordingly, the liability,
the related asset and the expense are impacted by changes in the estimates and
timing of the expected costs and reserves (see Oil and Gas Reserves discussion
below).
Asset Impairment
Producing properties and unproved properties are assessed annually, or as
economic events dictate, for potential impairment. Impairment is assessed by
comparing the estimated undiscounted future cash flows to the carrying value
of the asset. The cash flows used in the impairment assessment require
management to make assumptions and estimates about recoverable reserves (see
Oil and Gas Reserves discussion below), future commodity prices and operating
costs. Changes in any of the assumptions, such as a downward revision in
reserves, a decrease in anticipated future commodity prices, or an increase in
operating costs could result in an impairment of an asset's carrying value.
Purchase Price Allocation
Business acquisitions are accounted for by the purchase method of
accounting. Under this method, the purchase price is allocated to the assets
acquired and the liabilities assumed based on the fair value at the time of
acquisition. The excess purchase price over the fair value of identifiable
assets and liabilities acquired is goodwill. The determination of fair value
often requires management to make assumptions and estimates about future
events. The assumptions and estimates with respect to determining the fair
value of property, plant and equipment acquired generally requires the most
judgment and include estimates of reserves acquired (see Oil and Gas Reserves
discussion below), future commodity prices, and discount rates. Changes in any
of the assumptions or estimates used in determining the fair value of acquired
assets and liabilities could impact the amounts assigned to assets,
liabilities, and goodwill in the purchase price allocation. Future net
earnings can be affected as a result of changes in future depletion and
depreciation, asset impairment or goodwill impairment.
Goodwill Impairment
Goodwill is subject to impairment tests annually, or as economic events
dictate, by comparing the fair value of the reporting entity to its carrying
value, including goodwill. If the fair value of the reporting entity is less
than its carrying value, a goodwill impairment loss is recognized as the
excess of the carrying value of the goodwill over the implied value of the
goodwill. The determination of fair value requires management to make
assumptions and estimates about recoverable reserves (see Oil and Gas Reserves
discussion below), future commodity prices, operating costs, production
profiles, and discount rates. Changes in any of these assumptions, such as a
downward revision in reserves, a decrease in future commodity prices, an
increase in operating costs or an increase in discount rates could result in
an impairment of all or a portion of the goodwill carrying value in future
periods.
Oil and Gas Reserves
Reserves estimates, although not reported as part of the Trust's
financial statements, can have a significant effect on net earnings as a
result of their impact on depletion and depreciation rates, asset retirement
provisions, asset impairments, purchase price allocations, and goodwill
impairment (see discussion of these items above). Independent petroleum
reservoir engineering consultants perform evaluations of the Trust's oil and
gas reserves on an annual basis. However, the estimation of reserves is an
inherently complex process requiring significant judgment. Estimates of
economically recoverable oil and gas reserves are based upon a number of
variables and assumptions such as geoscientific interpretation, commodity
prices, operating and capital costs and production forecasts, all of which may
vary considerably from actual results. These estimates are expected to be
revised upward or downward over time, as additional information such as
reservoir performance becomes available, or as economic conditions change.
Future Income Taxes
The determination of the Trust's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the actual
income tax liability may differ significantly from that estimated and
recorded.
The Trust Tax Legislation results in a tax applicable at the trust level
on certain income from publicly traded mutual fund trusts at rates of tax
comparable to the combined federal and provincial corporate tax and treats
distributions as dividends to the Unitholders. Existing trusts will have a
transition period and the new tax will apply in January 2011.New Accounting Pronouncements
Accounting Changes in the Current Period
Financial Instruments
On January 1, 2008, the Trust adopted the following CICA Handbook
sections:
- Section 3862 "Financial Instruments - Disclosures" and Section 3863
"Financial Instruments - Presentation". The new disclosure standards
increase the Trust's disclosure regarding the nature and extent of
the risks associated with financial instruments and how those risks
are managed (see Note 17 to the unaudited interim consolidated
financial statements for the quarter ended December 31, 2008).
- Section 1535 "Capital Disclosures". The new standard requires the
Trust to disclose objectives, policies and processes for managing its
capital structure (see Note 12 to the unaudited interim consolidated
financial statements for the quarter ended December 31, 2008).Future Accounting Pronouncements
The CICA issued Section 3064, "Goodwill and Other Intangible Assets",
replacing Section 3062, "Goodwill and Other Intangible Assets" and Section
3450, "Research and Development Costs". Section 3064 establishes standards for
the recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition and is effective on
January 1, 2009. The Trust does not expect these new standards to have a
material impact on its financial statements.
International Financial Reporting Standards (IFRS)
On February 13, 2008, the Accounting Standards Board confirmed that the
transition date to International Financial Reporting Standards ("IFRS") from
Canadian GAAP will be January 1, 2011 for publicly accountable enterprises.
Therefore the Trust will be required to report its results in accordance with
IFRS starting in 2011, with comparative IFRS information for the 2010 fiscal
year.
The Trust is assessing the potential impacts of this changeover and is
developing its implementation plan accordingly, however, at this time, the
impact on our future financial position and results of operations is not
reasonably determinable.
The Trust has commenced the conversion project and will establish a
functional steering committee consisting of managers from accounting, land,
engineering, information technology, investor relations, among others. Regular
reporting is provided to our executive management team and to the Audit
Committee of our Board of Directors.
Our project consists of four phases: impact assessment, planning &
solution development, implementation and post implementation review.
We have completed the impact assessment which included a diagnostic of
the major differences between current Canadian GAAP and IFRS. The area which
will have the highest impact on the financial statements and require the
highest implementation effort will be accounting for and assessing depletion
and impairment of property, plant and equipment.
We are currently in the planning & solution development phase which has
included working on the definition of cash generating units and depletion
components, examining the elective exemptions from retroactive restatement
offered in IFRS 1 and defining changes required to accounting and operations
information systems.
During the implementation phase, activities will include executing the
required changes to accounting and operational information systems as well as
to disclosure controls and internal controls over financial reporting, writing
accounting policies and training employees.
The post implementation review will include the compilation of IFRS
compliant financial statements and make any required process changes.
The Trust will also continue to monitor the IFRS conversion efforts of
many of its peers and will participate in any related industry initiatives, as
appropriate.Outstanding Trust Unit Data
As at March 10, 2009, the Trust had 136,690,984 trust units outstanding.
Selected Annual Information
-------------------------------------------------------------------------
($000 except per unit amounts) 2008 2007 2006
-------------------------------------------------------------------------
Total oil and gas sales 1,213,676 652,175 427,491
Net income (loss)(1) 464,102 (32,167) 68,947
Net income (loss) per unit(1) 3.74 (0.32) 1.12
Net income (loss) per unit - diluted(1)(4) 3.71 (0.32) 1.05
Cash flow from operating activities 584,955 332,605 177,426
Cash flow from operating activities
per unit 4.72 3.30 2.88
Cash flow from operating activities per
unit - diluted(4) 4.67 3.28 2.79
Funds flow from operations 592,132 355,910 189,135
Funds flow from operations per unit 4.78 3.54 3.07
Funds flow from operations per unit -
diluted(4) 4.73 3.51 2.98
Working capital(2) 187,694 (54,104) 26,533
Total assets 3,307,688 2,613,432 1,373,466
Total liabilities 1,462,876 1,196,429 467,086
Net debt(2) 730,932 650,088 227,905
Total long-term risk management
liabilities 5,216 59,652 11,697
Weighted average trust units
(thousands)(3) 125,944 102,059 63,569
Cash distributions 324,821 245,108 150,277
Cash distributions per unit 2.61 2.40 2.40
-------------------------------------------------------------------------
(1) Net income and net income before discontinued operations and
extraordinary items are the same.
(2) Working capital and net debt include long-term investments, but
exclude the risk management liabilities and assets.
(3) The trust units issuable on conversion of the exchangeable shares
reflect the weighted average exchangeable shares outstanding
converted at the exchange ratio in effect at the end of the period.
For the 2006 amounts, the exchangeable share ratio applied is the one
in effect for the October 27, 2006 redemption.
(4) Per unit - diluted is calculated excluding the cash portion of unit-
based compensation.Crescent Point's revenue, cash flow from operations and assets have
increased significantly from the year ended December 31, 2006 through the year
December 31, 2008 due to numerous corporate and property acquisitions and the
Trust's successful drilling program, which have resulted in higher production
volumes. This factor combined with favourable commodity prices resulting from
higher market prices and narrower corporate oil differentials have produced
the increases realized in the table noted above. Net income through 2006 to
2008 has fluctuated primarily due to unrealized financial instrument gains and
losses on oil and gas contracts, which fluctuate with changes in market
conditions along with fluctuations in the future income tax expense and
recovery.Summary of Quarterly Results
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
($000, except per unit amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Oil and gas sales 211,264 365,748 360,685 275,979
Net income (loss)(1)(4)(5) 361,411 497,815 (353,660) (41,464)
Net income (loss) per
unit(1)(4) 2.89 3.98 (2.83) (0.34)
Net income (loss) per unit -
diluted(1)(4) 2.84 3.92 (2.83) (0.34)
Cash flow from operating
activities(1)(5) 125,625 153,875 140,181 165,274
Cash flow from operating
activities per unit 1.00 1.23 1.12 1.37
Cash flow from operating
activities per unit -
diluted 0.99 1.22 1.11 1.35
Funds flow from
operations(1)(5) 109,635 183,843 142,990 155,664
Funds flow from operations
per unit 0.88 1.47 1.15 1.29
Funds flow from operations
per unit - diluted 0.87 1.45 1.13 1.28
Working capital(2) 187,694 50,766 14,973 20,157
Total assets 3,307,688 3,083,978 2,987,069 2,918,199
Total liabilities 1,462,876 1,535,646 1,856,144 1,358,676
Net debt(2) 730,932 672,812 635,731 565,475
Total long-term risk
management liabilities 5,216 129,370 377,580 124,351
Weighted average trust units
- diluted (thousands) 127,417 127,286 126,426 122,615
Capital expenditures(3) 95,115 131,839 131,135 249,657
Cash distributions 86,314 86,247 78,635 73,625
Cash distributions per unit 0.69 0.69 0.63 0.60
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007
-------------------------------------------------------------------------
($000, except per unit amounts) Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Oil and gas sales 214,748 164,368 144,179 128,880
Net income (loss)(1)(4)(5) (90,348) 18,410 (117,773) 157,544
Net income (loss) per
unit(1)(4) (0.80) 0.18 (1.17) 1.83
Net income (loss) per unit -
diluted(1)(4) (0.80) 0.18 (1.17) 1.80
Cash flow from operating
activities(1)(5) 99,070 80,722 102,637 50,176
Cash flow from operating
activities per unit 0.88 0.79 1.02 0.58
Cash flow from operating
activities per unit -
diluted 0.87 0.78 1.01 0.58
Funds flow from
operations(1)(5) 112,572 92,215 78,248 72,875
Funds flow from operations
per unit 1.00 0.90 0.78 0.84
Funds flow from operations
per unit - diluted 0.99 0.89 0.77 0.84
Working capital(2) (54,104) (9,908) (23,346) 13,044
Total assets 2,613,432 2,106,227 2,051,979 2,076,521
Total liabilities 1,196,429 555,233 656,693 534,299
Net debt(2) 650,088 208,554 353,416 340,612
Total long-term risk
management liabilities 59,652 - 7,286 16,107
Weighted average trust units
- diluted (thousands) 114,623 104,074 101,681 87,537
Capital expenditures(3) 506,231 80,488 58,835 658,640
Cash distributions 67,971 63,206 60,320 53,611
Cash distributions per unit 0.60 0.60 0.60 0.60
-------------------------------------------------------------------------
(1) Per unit - diluted is calculated excluding the cash portion of unit -
based compensation. Net income per unit diluted is calculated using
the net income before non-controlling interest.
(2) Working capital and net debt include bank indebtedness and long-term
investments, but exclude the risk management liabilities and assets.
(3) Capital expenditures include capital acquisitions. Capital
acquisitions represent total consideration for the transactions
including bank debt and working capital assumed. Prior period results
have been restated to conform to current period presentation.
(4) Net income for the first quarter of 2007 includes the $158.8 million
future income tax recovery resulting from the March 1, 2007
reorganization. Net income for the second quarter of 2007 includes
the $152.3 million future income tax expense resulting from the June
12, 2007 Bill C-52 Budget Implementation Act that was substantively
enacted.
(5) The second quarter of 2008's net loss, cash flow from operating
activities and funds flow from operations include a realized
derivative loss of $34.5 million for the crystallization of various
oil derivative contracts. The fourth quarter of 2008 net income, cash
flow from operating activities and funds flow from operations include
a bad debt provision of $19.4 million.Crescent Point's revenue has increased due to several corporate and
property acquisitions completed over the past two years and the Trust's
successful drilling program. Significant increases in the Cdn$ WTI benchmark
price and narrower corporate oil differentials also contributed to the
increase in revenues.
The overall growth of the Trust's asset base also contributed to the
general increase in funds flow from operations and cash flow from operating
activities. Higher market oil prices and narrower corporate oil differentials
also contributed to this trend.
Net income through 2007 and 2008 has fluctuated primarily due to
unrealized derivative gains and losses on oil and gas contracts, which
fluctuate with the changes in forward market conditions along with
fluctuations in the future income tax expense (recovery). The March 1, 2007
internal reorganization resulted in a $158.8 million future tax recovery in
the first quarter of 2007. Bill C-52 became substantively enacted on June 12,
2007, resulting in the future tax expense of $152.3 million in the second
quarter of 2007.
Capital expenditures fluctuated through this period as a result of timing
of acquisitions and the development drilling program. The general increase in
funds flow from operations and cash flow from operating activities throughout
the last eight quarters has allowed the Trust to maintain stable monthly cash
distributions over the past two years.
Fourth Quarter ReviewThe following are the main highlights for the fourth quarter of 2008:
- The Trust spent $92.9 million on development capital activities in
the fourth quarter, including the drilling of 49 (33.7 net) wells
with a 98 percent success rate.
- Crescent Point grew fourth quarter 2008 average daily production by
five percent over third quarter 2008 and exceeded guidance by more
than 2,800 boe/d. The Trust produced 39,554 boe/d for the quarter, up
from 37,630 boe/d in the third quarter and up 19 percent from
33,351 boe/d in the fourth quarter of 2007.
- Crescent Point's funds flow from operations decreased by three
percent to $109.6 million in the fourth quarter of 2008, compared to
$112.6 million in the fourth quarter of 2007. The decrease is
primarily the result of the $19.4 million bad debt provision, the
decrease in the operating netback, partially offset by increased
production volumes.
- Crescent Point maintained consistent monthly distributions of
$0.23 per unit, totaling $0.69 per unit for the fourth quarter of
2008.
- The Trust continued to execute its core strategy of managing
commodity price risk using a combination of fixed price swaps,
costless collars, and put option instruments. As at March 3, 2009,
the Trust had hedged 57 percent, 42 percent, 27 percent and 14
percent production, net of royalty interest, for 2009, 2010, 2011 and
the first six months of 2012, respectively.
- During the fourth quarter, Crescent Point invested $78.7 million in a
private financing by Shelter Bay Energy Inc. ("Shelter Bay") and
$20.0 million in a private financing by Wild River Resources Ltd.
("Wild River"). The $78.7 investment in Shelter Bay brings the
Trust's total investment in Shelter Bay to approximately $200 million
or 21 percent ownership. The $20.0 million investment in Wild River
represents a 17 percent ownership of the private Bakken and Lower
Shaunavon producer.
- In October 2008, the amount available under the Trust's credit
facility was increased from $1.0 billion to $1.15 billion.Disclosure Controls and Procedures
Disclosure controls and procedures ("DC&P"), as defined in National
Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim
Filings, are designed to provide reasonable assurance that information
required to be disclosed in reports filed with, or submitted to, securities
regulatory authorities is recorded, processed, summarized and reported within
the time periods specified under Canadian securities law. The Chief Executive
Officer and the Chief Financial Officer of Crescent Point evaluated the
effectiveness of the Trust's DC&P. Based on that evaluation, the executive and
financial officers concluded that Crescent Point's DC&P were effective as of
December 31, 2008.
Internal Controls over Financial Reporting
Internal control over financial reporting ("ICFR"), as defined in
National Instrument 52-109, includes policies and procedures that:1. pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect transactions and dispositions of assets
of Crescent Point;
2. provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles; and
3. provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the Trust's
assets that could have a material effect on the financial statements.The Chief Executive Officer and the Chief Financial Officer are
responsible for establishing and maintaining internal ICFR for Crescent Point.
They have, as at the financial year ended December 31, 2008, designed ICFR, or
caused it to be designed under their supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with Canadian
GAAP. The control framework Crescent Point's officers used to design the
Trust's ICFR is the Internal Control -- Integrated Framework ("COSO
Framework") published by The Committee of Sponsoring Organizations of the
Treadway Commission ("COSO").
Under the supervision of the Chief Executive Officer and the Chief
Financial Officer, Crescent Point conducted an evaluation of the effectiveness
of the Trust's ICFR as at December 31, 2008 based on the COSO Framework. Based
on this evaluation, the officers concluded that as of December 31, 2008,
Crescent Point's ICFR does provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with Canadian GAAP.
It should be noted that while Crescent Point's officers believe that the
Trust's controls provide a reasonable level of assurance with regard to their
effectiveness, they do not expect that the DC&P and ICFR will prevent all
errors and fraud. A control system, no matter how well conceived or operated,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system are met.
There were no changes in Crescent Point's ICFR during the year ended
December 31, 2008 that materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
Health, Safety and Environment Policy
The health and safety of employees, contractors, visitors and the public,
as well as the protection of the environment, is of utmost importance to
Crescent Point. The Trust endeavours to conduct its operations in a manner
that will minimize both adverse effects and consequences of emergency
situations by:- Complying with government regulations and standards;
- Conducting operations consistent with industry codes, practices and
guidelines;
- Ensuring prompt, effective response and repair to emergency
situations and environmental incidents;
- Providing training to employees and contractors to ensure compliance
with Trust safety and environmental rules and procedures;
- Promoting the aspects of careful planning, good judgment,
implementation of the Trust's procedures, and monitoring Trust
activities;
- Communicating openly with members of the public regarding our
activities; and
- Amending the Trust's policies and procedures as may be required from
time to time.Crescent Point believes that all employees have a vital role in achieving
excellence in environmental, health and safety performance. This is best
achieved through careful planning and the support and active participation of
everyone involved.
As part of Crescent Point's ongoing commitment to reduce greenhouse gas
emissions, the Trust established an Environmental Emissions Reduction Fund in
2007. Currently $0.15 per produced boe is directed into this fund. To date,
$3.1 million has been contributed to the fund and $2.2 million has been
expended in order to reduce greenhouse gas emissions and to meet and exceed
provincial and federal targets. These targets relate to the Government of
Canada's April 26, 2007 "Turning the Corner: An Action Plan to Reduce
Greenhouse Gases and Air Pollution" and to the Government of Alberta's March
8, 2007 Bill 3: Climate Change and Emissions Management Amendment Act and its
accompanying Gas Emitters Regulation.
OutlookCrescent Point's 2009 guidance is as follows:
-------------------------------------------------------------------------
2009
-------------------------------------------------------------------------
Production
Oil and NGL (bbls/d) 36,200
Natural gas (mcf/d) 25,800
-------------------------------------------------------------------------
Total (boe/d) 40,500
-------------------------------------------------------------------------
Funds flow from operations ($000) 593,000
Combined funds flow per unit - diluted and per share -
diluted ($) 3.91
Combined cash distributions per unit and dividends per
share ($) 2.76
Payout ratio - per unit/share - diluted (%) 71
-------------------------------------------------------------------------
Capital expenditures ($000)(1) 225,000
Wells drilled, net 82
-------------------------------------------------------------------------
Pricing
Crude oil - WTI (US$/bbl) 46.50
Crude oil - WTI (Cdn$/bbl) 58.86
Natural gas - Corporate (Cdn$/mcf) 5.00
Exchange rate (US$/Cdn$) 0.79
-------------------------------------------------------------------------
(1) The projection of capital expenditures excludes acquisitions, which
are separately considered and evaluated.
Additional information relating to Crescent Point, including the Trust's
annual information form, is available on SEDAR at www.sedar.com.
CONSOLIDATED BALANCE SHEETS
-------------------------------------------------------------------------
As at December 31
(UNAUDITED) ($000) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current assets
Accounts receivable (Note 17) 91,994 102,800
Investments in marketable securities (Note 17) 538 1,385
Prepaids and deposits 3,419 2,218
Risk management asset (Note 17) 82,782 451
-------------------------------------------------------------------------
178,733 106,854
Long-term investment (Note 5) 224,989 6,386
Reclamation fund (Note 8) 3,996 2,436
Risk management asset (Note 17) 99,153 -
Property, plant and equipment (Notes 6 & 7) 2,732,467 2,429,406
Goodwill 68,350 68,350
-------------------------------------------------------------------------
Total assets 3,307,688 2,613,432
-------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 17) 118,038 144,141
Cash distributions payable 15,208 22,752
Bank indebtedness (Note 9) - 595,984
Risk management liability (Note 17) 5,395 63,819
-------------------------------------------------------------------------
138,641 826,696
Bank indebtedness (Note 9) 918,626 -
Asset retirement obligation (Note 10) 68,754 66,074
Risk management liability (Note 17) 5,216 59,652
Future income taxes (Note 15) 331,639 244,007
-------------------------------------------------------------------------
Total liabilities 1,462,876 1,196,429
-------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (Notes 11 & 12) 2,100,297 1,826,423
Contributed surplus (Note 13) 29,740 15,086
Deficit (Note 14) (285,225) (424,506)
-------------------------------------------------------------------------
Total unitholders' equity 1,844,812 1,417,003
-------------------------------------------------------------------------
Total liabilities and unitholders' equity 3,307,688 2,613,432
-------------------------------------------------------------------------
Commitments (Note 18)
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS)
AND DEFICIT
-------------------------------------------------------------------------
Three months ended Year ended
(UNAUDITED) ($000, except December 31 December 31
per unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
REVENUE
Oil and gas sales 211,264 214,748 1,213,676 652,175
Royalties (34,672) (39,295) (220,225) (118,915)
Derivatives
Realized gains (losses) 9,916 (11,289) (154,570) (9,899)
Unrealized gains (losses)
(Note 17) 416,754 (112,236) 294,344 (105,426)
Equity and other income
(Note 5) 2,508 - 3,226 -
-------------------------------------------------------------------------
605,770 51,928 1,136,451 417,935
EXPENSES
Operating 33,584 28,192 123,316 94,918
Transportation 5,813 5,626 25,608 17,725
General and administrative 23,543 3,914 40,967 15,358
Unit-based compensation
(Note 13) 10,683 4,345 30,778 16,375
Interest on bank indebtedness
(Note 9) 9,700 8,107 33,484 21,805
Depletion, depreciation and
amortization 82,594 68,017 315,483 242,923
Accretion on asset retirement
obligation (Note 10) 1,359 1,236 5,374 4,431
-------------------------------------------------------------------------
167,276 119,437 575,010 413,535
-------------------------------------------------------------------------
Income (loss) before taxes 438,494 (67,509) 561,441 4,400
Capital and other taxes 3,233 4,874 20,031 15,394
Future income tax expense
(Note 15) 73,850 17,965 77,308 21,173
-------------------------------------------------------------------------
Net income (loss) and
comprehensive income (loss)
for the period 361,411 (90,348) 464,102 (32,167)
-------------------------------------------------------------------------
Deficit, beginning of period (560,322) (266,187) (424,506) (148,699)
Change in accounting policy
(Note 3) - - - 1,468
Cash distributions paid or
declared (86,314) (67,971) (324,821) (245,108)
-------------------------------------------------------------------------
Deficit, end of the period
(Note 14) (285,225) (424,506) (285,225) (424,506)
-------------------------------------------------------------------------
Net income (loss) per unit
(Note 16)
Basic 2.89 (0.80) 3.74 (0.32)
Diluted 2.84 (0.80) 3.71 (0.32)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
(UNAUDITED) ($000) 2008 2007 2008 2007
-------------------------------------------------------------------------
CASH PROVIDED BY (USED IN)
OPERATING ACTIVITIES
Net income (loss) for the
period 361,411 (90,348) 464,102 (32,167)
Items not affecting cash
Equity and other income
(Note 5) (2,508) - (3,226) -
Future income tax expense
(Note 15) 73,850 17,965 77,308 21,173
Unit-based compensation
(Note 13) 9,683 3,786 27,435 14,378
Depletion, depreciation
and amortization 82,594 68,017 315,483 242,923
Accretion on asset
retirement obligation
(Note 10) 1,359 1,236 5,374 4,431
Realized gain on sale
of investment - - - (1,402)
Unrealized (gains) losses
on derivatives (Note 17) (416,754) 112,236 (294,344) 105,426
Unrealized (gains)
losses on investment - (320) - 1,148
Asset retirement expenditures
(Note 10) (374) (879) (2,317) (1,855)
Change in non-cash working
capital
Accounts receivable 60,995 14,062 11,709 19,753
Prepaids and deposits 417 363 (1,201) 2,291
Accounts payable and
accrued liabilities (45,048) (27,048) (15,368) (43,494)
-------------------------------------------------------------------------
125,625 99,070 584,955 332,605
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Development capital and
other expenditures (95,819) (97,854) (463,394) (235,788)
Capital acquisitions, net
(Note 6) 705 (343,791) (9,123) (401,034)
Proceeds on sale of
marketable securities - - 17,796 1,573
Reclamation fund net
contributions (Note 8) (159) 112 (1,560) (711)
Long-term investment (Note 5) (98,810) 10,694 (220,443) (5,912)
Change in non-cash working
capital
Accounts receivable 10,530 (4,022) 3,650 (11,667)
Accounts payable and
accrued liabilities (48,964) 10,645 (13,610) 48,417
-------------------------------------------------------------------------
(232,517) (424,216) (686,684) (605,122)
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Issue of trust units, net
of issue costs 11,699 20,542 124,477 253,926
Restricted unit vests - - - (833)
Increase in bank indebtedness 195,048 359,983 309,617 250,173
Cash distributions (86,314) (67,971) (324,821) (245,108)
Change in non-cash working
capital
Cash distributions payable (13,541) 10,840 (7,544) 14,154
-------------------------------------------------------------------------
106,892 323,394 101,729 272,312
-------------------------------------------------------------------------
INCREASE IN CASH - (1,752) - (205)
CASH AT BEGINNING OF PERIOD - 1,752 - 205
-------------------------------------------------------------------------
CASH AT END OF PERIOD - - - -
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Supplementary Information:
Cash capital taxes paid 4,807 2,600 25,426 13,960
Cash interest paid 9,525 12,314 31,648 25,386
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2008 and 2007 (UNAUDITED)
1. STRUCTURE OF THE TRUST
Crescent Point Energy Trust ("the Trust") is an open-ended unincorporated
investment trust created on September 5, 2003 pursuant to a Declaration
of Trust and Plan of Arrangement operating under the laws of the Province
of Alberta. Olympia Trust Company is the trustee, Crescent Point
Resources Inc. ("CPRI") is the administrator of the Trust and the
beneficiaries of the Trust are the unitholders.
On March 1, 2007, the Trust completed a reorganization of the Trust and
its subsidiaries. The reorganization resulted in the existing business of
the Trust, which was carried on through a limited partnership and
corporations, being carried on through a limited partnership, directly
and indirectly owned by the Trust.
The principal undertaking of the Trust's operating entities, Crescent
Point Resources Limited Partnership along with its general partner,
Crescent Point General Partner Corp. is to acquire, hold directly or
indirectly, interests in oil and gas properties. The administrator of the
Trust's business is CPRI.
2. SIGNIFICANT ACCOUNTING POLICIES
a) Principles of Consolidation
The consolidated financial statements have been prepared by
management in accordance with generally accepted accounting
principles in Canada and they 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 transactions between the Trusts and its
subsidiaries have been eliminated.
b) Joint Ventures
Certain of the Trust's development and production activities are
conducted jointly with others through unincorporated joint ventures.
The accounts of the Trust reflect its proportionate interest in such
activities.
c) Property, Plant and Equipment
The Trust follows the full cost method of accounting for petroleum
and natural gas properties and equipment, whereby all costs of
acquiring petroleum and natural gas properties and related
development costs are capitalized and accumulated in one cost centre.
Such costs include lease acquisition costs, geological and
geophysical expenditures, costs of drilling both productive and non-
productive wells, related plant and production equipment costs and
related overhead charges. Maintenance and repairs are charged against
income, whereas renewals and enhancements which extend the economic
life of the properties and equipment 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 percent or more.
Depletion, Depreciation and Amortization
Depletion of petroleum and natural gas properties is calculated using
the unit-of-production method based on the estimated proved reserves
before royalties, as determined by independent engineers. Natural gas
reserves and production are converted to equivalent barrels of oil
based upon the relevant energy content (6:1). The depletion base
includes capitalized costs, plus future costs to be incurred in
developing proven reserves and excludes the unimpaired cost of
unproved land. Costs associated with unproved properties are not
subject to depletion and are assessed periodically to ascertain
whether impairment has occurred. When proved reserves are assigned or
the value of the unproved property is considered to be impaired, the
cost of the unproved property or the amount of impairment is added to
costs subject to depletion.
Tangible production equipment is depreciated on a straight-line basis
over its estimated useful life of 15 years. Office furniture,
equipment and motor vehicles are depreciated on a declining balance
basis at rates ranging from 10 percent to 30 percent.
Ceiling Test
A limit is placed on the aggregate carrying value of property, plant
and equipment that may be amortized against revenues of future
periods (the "ceiling test"). The ceiling test is an impairment test
whereby the carrying amount of the PP&E is compared to the sum of the
undiscounted cash flows expected to result from the Trust's proved
reserves. 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 measures the amount of impairment by comparing the carrying
amounts of PP&E to an amount equal to the estimated net present value
of future cash flows from proved and probable reserves. The Trust's
risk-free interest rate is used to determine the net present value of
the future cash flows. Any excess carrying value above the net
present value of 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.
d) Reclamation Fund
The Trust established a reclamation fund effective July 1, 2004 to
fund future asset retirement obligation costs and environmental
emissions reduction costs. The Board of Directors has approved
contributions of $0.30 per barrel of production beginning January 1,
2008. Prior to January 1, 2008, contributions ranged from $0.15 to
$0.25 per barrel of production. Additional contributions are made at
the discretion of management.
e) Asset Retirement Obligation
The Trust recognizes the fair value of an asset retirement obligation
in the period in which it is incurred. The obligation is recorded as
a liability on a discounted basis when incurred using the Trust's
average credit-adjusted risk-free rate, with a corresponding increase
to the carrying amount of the related asset. Over time the
liabilities are accreted for the change in their present value and
the capitalized costs are depleted on a unit-of-production basis over
the life of the reserves. Revisions to the estimated timing of cash
flows or the original estimated undiscounted cost would also result
in an increase or decrease to the obligation and related asset.
f) 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 has 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 implied value of
the goodwill. Any excess of the book value of goodwill over the
implied value of goodwill is the impairment amount. Impairment is
charged to earnings and is not tax affected, in the period in which
it occurs. Goodwill is stated at cost less impairment and is not
amortized.
g) Unit-based Compensation
The fair value based method of accounting is used to account for the
restricted units granted under the Restricted Unit Bonus Plan.
Compensation expense is determined based on the estimated fair value
of trust units on the date of grant. The compensation expense is
recognized over the vesting period, with a corresponding increase to
contributed surplus. At the time the restricted units vest, the
issuance of units is recorded with a corresponding decrease to
contributed surplus and increase to unitholders' equity.
h) 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 its corporate subsidiaries and their respective tax
base, using enacted or 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. Currently, the Trust is a
taxable entity under the Income Tax Act (Canada) and is taxable only
on income that is not distributed or distributable to the
unitholders. Effective in 2011, the Trust's distributions are
taxable. Accordingly, income tax liabilities and assets have been
recognized on the Trust's temporary differences at the substantively
enacted rate applicable to the periods in which the temporary
differences reverse.
i) Financial Instruments
The Trust uses financial instruments and physical delivery commodity
contracts from time to time to reduce its exposure to fluctuations in
commodity prices, foreign exchange rates and interest rates. The
Trust also makes investments in corporations from time to time in
connection with the Trust's acquisition and divesture activities.
All financial assets must be classified as held-for-trading,
available-for-sale, held-to-maturity, or loans and receivables and
all financial liabilities must be classified as held-for-trading or
other. Financial assets and financial liabilities classified as
held-for-trading are measured at fair value with changes in those
fair values recognized in earnings. Financial assets held-to-
maturity, loans and receivables, and other financial liabilities are
measured at amortized cost using the effective interest method of
amortization. Available-for-sale financial assets are measured at
fair value with unrealized gains and losses, including changes in
foreign exchange rates, being recognized in other comprehensive
income. Investments in equity instruments classified as
available-for-sale that do not have a quoted market price in an
active market are measured at cost.
Derivative instruments are always carried at fair value and reported
as assets where they have a positive fair value and as liabilities
where they have a negative fair value. Derivatives may be embedded in
other financial instruments or contractual arrangements. Derivatives
embedded in other instruments are valued as separate derivatives when
their economic characteristics and risks are not clearly and closely
related to those of the host contract; the terms of the embedded
derivative are the same as those of a free standing derivative and
the combined contract is not held-for-trading. When an entity is
unable to measure the fair value of the embedded derivative
separately, the combined contract is treated as a financial asset or
liability that is held-for-trading and measured at fair value with
changes therein recognized in earnings.
The fair value of a financial instrument on initial recognition is
normally the transaction price, i.e. the fair value of the
consideration given or received. Subsequent to initial recognition,
the fair values are based on quoted market price where available from
active markets, otherwise fair values are estimated based upon market
prices at reporting date for other similar assets or liabilities with
similar terms and conditions, or by discounting future payments of
interest and principal at estimated interest rates that would be
available to the Trust at the reporting date.
The Trust has not designated any of its risk management activities as
accounting hedges and accordingly marks-to-market its financial
instruments with the resulting gains and losses recorded in the
statement of operations.
The Trust has elected to classify its investments in marketable
securities and long term investments as held for trading, and
accordingly, marks-to-market the investments with the resulting gain
or loss being recorded in the statement of operations.
j) Revenue Recognition
Revenues associated with sales of crude oil, natural gas and natural
gas liquids are recognized when title passes to the purchaser.
k) Cash and Cash Equivalents
Cash and cash equivalents include short-term investments with a
maturity of three months or less when purchased.
l) Measurement Uncertainty
Certain items recognized in the financial statements are subject to
measurement uncertainty. The recognized amounts of such items are
based on the Trust's best information and judgment. Such amounts are
not expected to change materially in the near term. They include the
amounts recorded for future income taxes, depletion, depreciation,
amortization and asset retirement costs which depend on estimates of
oil and gas reserves or the economic lives and future cash flows from
related assets.
3. CHANGES IN ACCOUNTING POLICIES
On January 1, 2008, the Trust adopted the following Canadian Institute of
Chartered Accountants ("CICA") Handbook sections:
- Section 3862 "Financial Instruments - Disclosures" and Section 3863
"Financial Instruments - Presentation". The new disclosure standards
increase the Trust's disclosure regarding the nature and extent of
the risks associated with financial instruments and how those risks
are managed (see Note 17).
- Section 1535 "Capital Disclosures". The new standard requires the
Trust to disclose objectives, policies and processes for managing its
capital structure (see Note 12).
On January 1, 2007, the Trust adopted the CICA Handbook sections 3855
"Financial Instruments Recognition and Measurement", 3865 "Hedges", 3861
"Financial Instruments - Disclosure and Presentation", 1530
"Comprehensive Income," and 3251 "Equity". Other than the effect on the
Investment in Marketable Securities as described in the section below,
the adoption of the financial instruments standards has not affected the
current or comparative period balances on the consolidated financial
statements as all financial instruments identified have been fair valued.
In 2007, the Trust elected to classify the investment in marketable
securities as held-for-trading. Accordingly, the investment in marketable
securities balance of $0.1 million at January 1, 2007 consisting of an
investment in a publicly traded exploration and production company, was
fair valued at January 1, 2007 to $1.6 million. Under prospective
application, the $1.5 million gain was recorded as an adjustment to
opening retained earnings.
4. FUTURE ACCOUNTING PRONOUNCEMENTS
The CICA issued Section 3064, "Goodwill and Other Intangible Assets",
replacing Section 3062, "Goodwill and Other Intangible Assets" and
Section 3450, "Research and Development Costs". Section 3064 establishes
standards for the recognition, measurement, presentation and disclosure
of goodwill and intangible assets subsequent to its initial recognition
and is effective on January 1, 2009. The Trust does not expect these new
standards to have a material impact on its financial statements.
On February 13, 2008, the Accounting Standards Board confirmed that the
transition date to International Financial Reporting Standards ("IFRS")
from Canadian GAAP will be January 1, 2011 for publicly accountable
enterprises. Therefore the Trust will be required to report its results
in accordance with IFRS starting in 2011, with comparative IFRS
information for the 2010 fiscal year.
The Trust is assessing the potential impacts of this changeover and is
developing its implementation plan accordingly, however, at this time,
the impact on our future financial position and results of operations is
not reasonably determinable.
The Trust has commenced the conversion project and will establish a
functional steering committee consisting of managers from accounting,
land, engineering, information technology, investor relations, among
others. Regular reporting is provided to our executive management team
and to the Audit Committee of our Board of Directors.
Our project consists of four phases: impact assessment, planning &
solution development, implementation and post implementation review.
We have completed the impact assessment which included a diagnostic of
the major differences between current Canadian GAAP and IFRS. The area
which will have the highest impact on the financial statements and
require the highest implementation effort will be accounting for and
assessing depletion and impairment of property, plant and equipment.
We are currently in the planning & solution development phase which has
included working on the definition of cash generating units and depletion
components, examining the elective exemptions from retroactive
restatement offered in IFRS 1 and defining changes required to accounting
and operations information systems.
During the implementation phase, activities will include executing the
required changes to accounting and operational information systems as
well as to disclosure controls and internal controls over financial
reporting, writing accounting policies and training employees.
The post implementation review will include the compilation of IFRS
compliant financial statements and make any required process changes. The
Trust will also continue to monitor the IFRS conversion efforts of many
of its peers and will participate in any related industry initiatives, as
appropriate.
5. LONG TERM INVESTMENT
a) Wild River Resources Ltd.
On December 15, 2008, the Trust announced that it had acquired a
17 percent ownership of Wild River Resources Ltd., a private oil and gas
producer with assets in the southeast Saskatchewan Bakken light oil
resource play and in the emerging southwest Saskatchewan Lower Shaunavon
resource play. The total investment of $20.0 million was acquired through
a private placement financing.
b) Shelter Bay Energy Inc.
During the first quarter of 2008, the Trust invested in Shelter Bay
Energy Inc. ("Shelter Bay"), a private light oil company. The Trust's
initial $76.3 million investment was comprised of 72.6 million Class A
Common Shares and 3.5 million Non-Voting Common Shares issued for $1.00
per share and representing an interest of 17 percent.
During the second quarter of 2008, the Trust invested a further
$20.0 million in Shelter Bay in return for an additional 20.0 million
Class A Common Shares.
In the third quarter of 2008, the Trust invested an additional
$25.4 million in Shelter Bay for a further 25.4 million Class A Common
Shares. On September 5, 2008, the Trust exchanged with Shelter Bay
3.5 million Non-Voting Common Shares of Shelter Bay for 3.5 million Class
A Common Shares of Shelter Bay.
In the fourth quarter of 2008, the Trust invested a further $78.7 million
in Shelter Bay through participation in private placement financing for
an additional 52.4 million Class A Common Shares.
At December 31, 2008, the Trust's investment of $200.4 million consisted
of 173.9 million Class A Common Shares, that represents an interest of
21 percent, plus the equity earnings of $4.5 million.
Under the terms of the unanimous shareholders' agreement governing
Shelter Bay (the "Shelter Bay USA"), the Trust has a right to purchase
all, but not less than all, of the shares of Shelter Bay not already
owned by the Trust (the "Call Right") at a price equal to the market
value of the shares, as defined in the Shelter Bay USA. The Call Right is
exercisable at (i) any time before April 1, 2011, provided that the
proceeds from such a transaction (including cumulative distributions)
would result in the initial investors in Shelter Bay receiving realized
proceeds equal to at least two times the amount of the aggregate capital
invested by the initial investors in Shelter Bay, or (ii) any time on or
after April 1, 2011 and on or before March 31, 2013.
Upon exercise of the Call Right, and acceptance by 66 2/3% or greater of
the shares held by Shelter Bay shareholders (excluding the Trust), the
Trust will have the right to acquire all of the Shelter Bay shares it
does not own. In the event of acceptance by less than 66 2/3% of the
shares held by Shelter Bay shareholders (excluding the Trust), the Trust
shall have the right to purchase all of the assets (the "Asset Call
Right") of Shelter Bay for 105% of the market value of the assets, as
defined in the Shelter Bay USA.
In the event Crescent Point exercises its Call Right or Asset Call Right,
Class B and C Common Share shareholders will be entitled to receive 100
percent of all proceeds from the sale transaction up to their original
investment in the Company plus a 10 percent return on investment. Class A
Common Share shareholders would then receive 100 percent of their
original investment in Shelter Bay plus a 10 percent return on
investment. Subsequent proceeds up to and until a 25 percent return on
investment to all Common Shareholders, would be shared on a pro rata
basis by shareholders in accordance with the number of shares held by
each shareholder. Following receipt of a 25 percent return on investment
by all Common Shareholders, the remaining proceeds would be shared 50
percent by Crescent Point and 50 percent by all Common Shareholders on a
pro rata basis.
As at December 31, 2008, no conditions exist which would require the
Trust to record a liability pursuant to the Shelter Bay USA.
Also under the Shelter Bay USA, between April 1, 2013 and September 30,
2013, certain Shelter Bay shareholders shall have a separate right to
require that the Trust acquire all of the shares of Shelter Bay then
owned by such shareholder for a purchase price equal to 85% of the market
value of such shares, as defined in the Shelter Bay USA (the "Put
Right"). If the Put Right is exercised, the Trust will be obligated to
provide all of the other shareholders in Shelter Bay with a similar right
to put their shares to the Trust on the same terms.
The purchase price for the Shelter Bay shares may be settled, at the
Trust's election, in cash or the issuance of Trust Units; however, the
Shelter Bay shareholders shall have certain rights to receive their
consideration for their Shelter Bay shares in the form of Trust Units.
Notwithstanding the foregoing, the Trust shall have no obligation to
cause to be issued Trust Units under the Shelter Bay USA in an amount
that would cause the Trust to lose its grandfathered status under the
SIFT Rules by violating the "normal growth" guidelines. Given the terms
of the Shelter Bay USA, there can be no assurance that the Trust will not
be required to, or will not elect to purchase the shares of Shelter Bay
not already owned by the Trust or the assets of Shelter Bay and further,
there can be no assurance that the Trust will have the capital resources
to satisfy such Call Right or Put Right or that it will be able to issue
Trust Units to Shelter Bay shareholders in association with the exercise
of the Call Right or Put Right described herein, which number of Trust
Units may be material to the Trust at the time of issuance and which
issuance may be dilutive to existing holders of Trust Units at such time.
Variable Interest Entity
Shelter Bay is considered a variable interest entity under Accounting
Guideline 15. However, the Trust is not the primary beneficiary of this
variable interest entity, and, accordingly, the Trust accounts for its
investment in Shelter Bay using the equity accounting method. Therefore,
the Trust has recorded its share of Shelter Bay's net income (loss) as an
increase (decrease) to the Trust's net income and as an increase
(decrease) to the cost of its investment. The Trust's maximum exposure to
loss as a result of its involvement in Shelter Bay is approximately
$200.4 million, which includes the carrying value of the Trust's
investment.
Related Party Transactions
Management and Technical Services Agreement - The Trust entered into a
Management and Technical Services Agreement with Shelter Bay, effective
January 11, 2008. Crescent Point is responsible for managing,
administering and operating the assets and business of Shelter Bay. The
services are provided in exchange for a monthly management fee. Crescent
Point billed management fees to Shelter Bay of $2.5 million for the year
ended December 31, 2008.
Farm-Out Agreement - Effective January 11, 2008, the Trust entered into a
farm-out agreement with Shelter Bay. Under the agreement, Shelter Bay has
the right to farm-in on 22 net sections of Viewfield Bakken lands owned
by the Trust. Shelter Bay is responsible for paying 100 percent of the
capital costs and earns a 50 percent interest in production from the
property, while the Trust retains the other 50 percent production
interest.
In the first quarter of 2008, there were two wells drilled by Crescent
Point immediately prior to the effective date of the farm-out agreement,
and pursuant to the agreement, these wells were sold by Crescent Point to
Shelter Bay in exchange for a reimbursement of capital costs, which
totaled $3.6 million. As this transaction was not in the normal course of
operations, the disposition of the wells was recorded at the carrying
amount.
Farm-Out Note - During the first quarter of 2008, as Shelter Bay
commenced operations, the Trust entered into a farm-out note with Shelter
Bay to finance Shelter Bay's capital activities. The principal amount of
the note was $23.5 million and interest on the note was equivalent to the
Canadian Chartered Bank Prime Rate plus 2 percent. The principal amount
of the note was re-paid on March 26, 2008, subsequent to Shelter Bay's
closing of a private placement. Interest of $0.2 million was charged by
Crescent Point during the first quarter and collected at the end of April
2008.
Capital Commitment - Pursuant to Shelter Bay's private placement, the
Trust entered into a Call Obligation Agreement with Shelter Bay in
association with its subscription for Special Voting Shares. Pursuant to
the agreement, the Trust committed to subscribe for additional Class A
Common Shares of Shelter Bay for approximately $45.4 million. In exchange
for this capital commitment, the Trust received 45.4 million Special
Voting Shares. Other major investors of Shelter Bay also entered into
similar Call Obligation Agreements with Shelter Bay and may, at Shelter
Bay's discretion be required to subscribe for additional shares of
Shelter Bay. As a result, the Trust's equity interest would not change
significantly in connection with the Call Obligation Agreement.
On May 15, 2008 Shelter Bay exercised in part its call rights under the
Call Obligation Agreements. As a result the Trust subscribed for
20.0 million Class A Common Shares of Shelter Bay for $20.0 million.
On July 31, 2008 Shelter Bay exercised its remaining call rights under
the Call Obligation Agreements. As a result the Trust subscribed for
approximately 25.4 million Class A Common Shares for $25.4 million. This
subscription satisfied in full the Trust's commitment under the Call
Obligation Agreement.
On September 5, 2008 the Trust exchanged with Shelter Bay 3.5 million
Non-Voting Common Shares of Shelter Bay for 3.5 million Class A Common
Shares of Shelter Bay.
On October 1, 2008, the Trust and Shelter Bay announced the closing of a
$300.0 million private placement financing for Shelter Bay. Crescent
Point's participation in the private placement was $78.7 million. With
the closing of this private placement, Crescent Point's aggregate
investment in Shelter Bay is approximately $200.4 million which equates
to a 21 percent interest.
Property Acquisition and Trust Unit Issuance - In conjunction with the
closing of Shelter Bay's acquisition of Landex Petroleum Corp. ("Landex")
on March 26, 2008, the Trust issued 3.1 million trust units valued at $75
million and cash of $5 million to Shelter Bay in exchange for an $80
million note. The Trust subsequently completed a Saskatchewan property
acquisition from Shelter Bay for total consideration of $80 million, in
exchange for settlement of the note.
The trust unit issuance was recorded at $75 million as this was
equivalent to the fair value of the consideration received. The property
acquisition was recorded at the exchange amount of $80 million.
Property Disposition - On March 26, 2008, the Trust disposed of
undeveloped land to Shelter Bay for cash consideration of $31.3 million.
The transaction was recorded at the exchange amount.
Property Acquisition - On December 11, 2008, Crescent Point purchased
undeveloped land from the Shelter Bay for cash consideration of $12.3
million. The transaction was recorded at the exchange amount.
Amounts Owing From/Due To - At December 31, 2008, the Trust had $3.6
million receivable from Shelter Bay for management fees and operating
activity paid for by the Trust on Shelter Bay's behalf. These receivables
were collected by the Trust at the end of January 2009.
Painted Pony Petroleum Ltd. ("Painted Pony") Share Disposition - The
Trust entered into an agreement with Shelter Bay to dispose of the
Painted Pony shares for $17.8 million. The transaction was recorded at
the exchange amount.
6. CAPITAL ACQUISITIONS AND DISPOSITIONS
a) Major acquisitions
There were no major acquisitions in the fourth quarter of 2008.
Major acquisitions in the year ended December 31, 2008 included Pilot
Energy Ltd. and the non-Bakken assets of Landex.
Pilot Energy Ltd.
On January 16, 2008, the Trust purchased all the issued and outstanding
shares of Pilot Energy Ltd., a publicly traded company with properties in
the Viewfield area of southeast Saskatchewan for total consideration of
approximately $78.5 million, including assumed bank debt and working
capital ($93.3 million was allocated to property, plant and equipment).
The purchase was paid for through the issuance of approximately 2.6
million trust units and was accounted for as a business combination using
the purchase method of accounting. The Trust owned 2.0 million shares of
Pilot Energy Ltd. prior to the closing which it purchased for $2.90 per
share or $5.9 million in November 2007.
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Net assets acquired
Working capital 1,678
Property, plant and equipment 93,310
Bank debt (13,025)
Asset retirement obligation (3,341)
Future income taxes (11,494)
-------------------------------------------------------------------------
Total net assets acquired 67,128
-------------------------------------------------------------------------
Consideration
Cash 5,912
Trust units issued (2,628,269 trust units) 60,766
Acquisition costs 450
-------------------------------------------------------------------------
Total purchase price 67,128
-------------------------------------------------------------------------
Non-Bakken Assets of Landex Petroleum Corp.
On March 26, 2008, the Trust closed the acquisition of the non-Bakken
assets of Landex from Shelter Bay Energy Inc. for consideration of
approximately $80.0 million ($81.4 million was allocated to property,
plant and equipment). The purchase was paid for with approximately 3.1
million trust units and $5.0 million of cash from the Trust's existing
bank line. See Note 5 for further disclosures regarding the property
acquisition.
b) Minor Property Acquisitions and Dispositions
During the year ended December 31, 2008, the Trust closed five property
acquisitions for $10.8 million ($11.9 million was allocated to property,
plant and equipment), and several property dispositions for a net
consideration of approximately $30.0 million ($31.8 million was recorded
as reduction to property, plant and equipment). The Trust also recorded
purchase price adjustments of $1.6 million on previously closed
acquisitions.
7. PROPERTY, PLANT AND EQUIPMENT
-------------------------------------------------------------------------
Accumulated
depletion,
depreciation
December 31, 2008 and
($000) Cost amortization Net
-------------------------------------------------------------------------
Petroleum and natural
gas properties 2,782,298 715,642 2,066,656
Production equipment 772,096 110,800 661,296
Office furniture and equipment 8,418 3,903 4,515
-------------------------------------------------------------------------
3,562,812 830,345 2,732,467
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated
depletion,
depreciation
December 31, 2007 and
($000) Cost amortization Net
-------------------------------------------------------------------------
Petroleum and natural
gas properties 2,330,613 448,101 1,882,512
Production equipment 606,418 63,878 542,540
Office furniture and equipment 7,237 2,883 4,354
-------------------------------------------------------------------------
2,944,268 514,862 2,429,406
-------------------------------------------------------------------------
At December 31, 2008, unproved land costs of $333.9 million (2007 -
$312.7 million) have been excluded from costs subject to depletion.
Future development costs of $918.9 million (2007 - $719.6 million) are
included in costs subject to depletion.
Direct general and administrative expenses capitalized by the Trust
during the year were $11.2 million (2007 - $4.6 million). The capitalized
administration costs do not include any related unit-based compensation
costs.
The ceiling test calculation at December 31, 2008 indicated that the net
recoverable amount from proved reserves exceeded the net carrying value
of the petroleum and natural gas properties and equipment. The following
are the prices that were used in the December 31, 2008 ceiling test:
-------------------------------------------------------------------------
Average Price Forecast(1)
-------------------------------------------------------------------------
2009 2010 2011 2012 2013 2014
-------------------------------------------------------------------------
WTI ($US/bbl) 57.50 68.00 74.00 85.00 92.01 93.85
Exchange rate 0.83 0.85 0.88 0.93 0.95 0.95
-------------------------------------------------------------------------
WTI ($Cdn/bbl) 68.61 78.94 83.54 90.92 95.91 97.84
AECO ($Cdn/mcf) 7.58 7.94 8.34 8.70 8.95 9.14
-------------------------------------------------------------------------
------------------------------------------------------------------
Average Price Forecast(1)
------------------------------------------------------------------
2015 2016 2017 2018 2019+(2)
------------------------------------------------------------------
WTI ($US/bbl) 95.73 97.64 99.59 101.59 2%
Exchange rate 0.95 0.95 0.95 0.95 0.95
------------------------------------------------------------------
WTI ($Cdn/bbl) 99.82 101.83 103.89 105.99 2%
AECO ($Cdn/mcf) 9.34 9.54 9.75 9.95 2%
------------------------------------------------------------------
(1) The benchmark prices listed above are adjusted for quality
differentials, heat content, distance to market and other factors in
performing our ceiling test.
(2) Percentage change represents the change in each year after 2018 to
the end of the reserve life.
8. RECLAMATION FUND
The following table reconciles the reclamation fund:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Balance, beginning of year 2,436 1,725
Contributions 3,877 2,566
Actual expenditures (2,317) (1,855)
-------------------------------------------------------------------------
Balance, end of year 3,996 2,436
-------------------------------------------------------------------------
9. BANK INDEBTEDNESS
The Trust has a syndicated credit facility with ten banks and an
operating credit facility with one Canadian chartered bank. During the
year ended December 31, 2008, the amount available under the combined
credit facilities was increased from $800.0 million to $1.15 billion. The
Trust has letters of credit in the amount of $0.9 million outstanding at
December 31, 2008.
The credit facilities bear interest at the prime rate plus a margin based
on a sliding scale ratio of the Trust's debt to cash flows. The Trust
also manages its debt facilities through a combination of bankers'
acceptance loans and interest rate swaps. The credit facilities are
secured by a $1.5 billion floating charge demand debenture, a general
security agreement and a subordination agreement from the Trust covering
all assets and cash flows.
The credit facilities mature in May 2010 and are subject to a review on
annual basis. The credit facilities constitute a revolving facility for a
364 day term which is extendible annually for a further 364 day revolving
period, subject to a one year term maturity as to lenders not agreeing to
such annual extension.
Revolving credit borrowings include bankers' acceptance loans, operating
credit facility and prime loan maturing at various dates with a weighted
average interest rate of 3.48 percent.
10. ASSET RETIREMENT OBLIGATION
The total future asset retirement obligation was estimated by management
based on the Trust's net ownership in all wells and facilities. This
includes all 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 obligation to be $68.8 million at December 31, 2008 (December
31, 2007 - $66.1 million) based on total estimated undiscounted cash
flows to settle the obligation $167.2 million (December 31, 2007 $153.3
million). These obligations are expected to be settled during the period
from 2009 through 2060. The estimated cash flows have been discounted
using an average credit-adjusted risk-free rate of return of eight
percent and an inflation rate of two percent.
The following table reconciles the asset retirement obligation:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Asset retirement obligation, beginning of year 66,074 45,829
Liabilities incurred 1,569 2,101
Liabilities acquired through capital acquisitions 5,820 16,533
Liabilities disposed through capital dispositions (1,819) (965)
Liabilities settled (2,317) (1,855)
Changes in prior year estimates (5,947) -
Accretion expense 5,374 4,431
-------------------------------------------------------------------------
Asset retirement obligation, end of year 68,754 66,074
-------------------------------------------------------------------------
11. UNITHOLDERS' CAPITAL
a) Authorized
An unlimited number of voting trust units has been authorized.
b) Issued and outstanding
The Trust has a distribution reinvestment plan (the "Regular DRIP") and a
premium distribution reinvestment plan (the "Premium DRIP"). The Regular
DRIP permits eligible unitholders to direct their distributions to the
purchase of additional units at 95 percent of the average market price,
as defined in the plan. The Premium DRIP permits eligible unitholders to
elect to receive 102 percent of the cash the unitholder would otherwise
have received on the distribution date. The additional cash distributed
to the Premium DRIP unitholders is funded through the issuance of
additional trust units in the open market. Participation in the Regular
and Premium DRIP is subject to proration by the Trust. Unitholders who
participate in either the Regular DRIP or the Premium DRIP are also
eligible to participate in the Optional Unit Purchase Plan as defined in
the plan.
In December 2007, the Trust announced that as a result of the federal
government Safe Harbour Limits on equity issuances for income trusts, the
DRIP, Premium DRIP, and Optional Unit Purchase programs would be
suspended until further notice beginning with the month of December 2007.
The Trust reinstated its DRIP, Premium DRIP and Optional Unit Purchase
programs for unitholders of record on December 31, 2008 with payments
beginning January 15, 2009.
On January 8, 2008, the Trust and a syndicate of underwriters closed a
bought deal equity financing pursuant to which the syndicate sold
5,155,000 trust units for gross proceeds of $125.0 million ($24.25 per
trust unit).
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Number of Amount Number of Amount
trust units ($000) trust units ($000)
Trust units,
beginning of year 113,760,732 1,873,523 69,531,952 1,083,948
Issued for cash 5,155,000 125,009 8,900,000 165,095
Issued on capital
acquisitions 5,742,887 135,766 29,784,377 518,961
Issued on vesting
of restricted units(1) 433,181 5,619 236,127 4,859
Issued pursuant to
the distribution
reinvestment plans - - 5,308,276 100,660
-------------------------------------------------------------------------
Trust units,
end of year 125,091,800 2,139,917 113,760,732 1,873,523
-------------------------------------------------------------------------
Cumulative unit
issue costs - (53,199) - (47,100)
To be issued pursuant
to distribution
reinvestment plans 586,881 13,579 - -
-------------------------------------------------------------------------
Total unitholders'
capital, end of year 125,678,681 2,100,297 113,760,732 1,826,423
-------------------------------------------------------------------------
(1) The amount of trust units issued on vesting of restricted units is
net of employee withholding taxes.
12. CAPITAL MANAGEMENT
The Trust's capital structure is comprised of unitholders' equity, bank
debt and working capital. The balance of each of these items is as
follows:
-------------------------------------------------------------------------
December 31, December 31,
($000) 2008 2007
-------------------------------------------------------------------------
Bank debt 918,626 595,984
Working capital(1) (187,694) 54,104
-------------------------------------------------------------------------
Net debt 730,932 650,088
Unitholders' equity 1,884,812 1,417,003
-------------------------------------------------------------------------
Total capitalization 2,615,744 2,067,091
-------------------------------------------------------------------------
(1) Working capital is calculated as current assets less current
liabilities, including long term investments and excluding risk
management liabilities and assets.
The Trust's objective for managing capital is to maintain a strong
balance sheet and capital base to provide financial flexibility,
stability to distributions and to position the Trust for future
development of the business. Ultimately, the Trust strives to maximize
long-term unitholder value by ensuring the Trust has the financing
capacity to fund projects that are expected to add value to unitholders
and distribute any excess cash to unitholders that is not required for
financing projects.
The Trust manages and monitors its capital structure and short term
financing requirements using a non-GAAP measure, the ratio of net debt to
funds flow from operations. Net debt is calculated as current liabilities
plus bank indebtedness less current assets, including long term
investments and excluding risk management liabilities and assets. Funds
flow from operations is calculated as cash flow from operating activities
before changes in non-cash working capital and asset retirement
expenditures. The Trust's objective is to maintain a net debt to funds
flow from operations ratio of approximately 1.0 times. This metric is
used to measure the Trust's overall debt position and measure the
strength of the Trust's balance sheet. The Trust monitors this ratio and
uses this as a key measure in making decisions regarding financing,
capital spending and distribution levels.
The Trust strives to provide stability to its distributions over time by
managing risks associated with the oil and gas industry. To accomplish
this, the Trust maintains a conservative balance sheet with significant
unutilized lines of credit and actively hedges commodity prices using a
three and a half year risk management program and hedging up to 65
percent of after royalty volumes using a portfolio of swaps, collars and
put option instruments.
Crescent Point is subject to certain financial covenants in its credit
facility agreements and is in compliance with all financial covenants as
of December 31, 2008.
The Trust's ability to raise new equity will be limited by the Safe
Harbour Limit guidelines as announced by the Federal Government. The
Federal Government's decision to tax income trusts has created
uncertainty in the capital markets regarding the future of the trust
sector. However, Crescent Point believes that it has sufficient capital
resources to meet its obligations given the Trust's significant
unutilized borrowing capacity available and its prior success raising new
equity within the guidelines as demonstrated from 2006 through 2008.
13. RESTRICTED UNIT BONUS PLAN
The Trust has a Restricted Unit Bonus Plan. Under the terms of the
Restricted Unit Bonus Plan, the Trust may grant restricted units to
directors, officers, employees and consultants. Restricted units vest at
33 1/3 percent on each of the first, second and third anniversaries of
the grant date. Restricted unitholders are eligible for monthly
distributions on their restricted units, immediately upon grant.
On May 30, 2008, at the annual general meeting, the unitholders approved
an increase in the maximum number of trust units outstanding under the
Restricted Unit Plan from 5,000,000 to 11,000,000 units.
A summary of the changes in the restricted units outstanding under the
plan is as follows:
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Restricted units, beginning of year 1,486,050 1,043,628
Granted 1,505,844 898,476
Exercised (649,000) (434,557)
Forfeited (17,592) (21,497)
-------------------------------------------------------------------------
Restricted units, end of year 2,325,302 1,486,050
-------------------------------------------------------------------------
The Trust recorded compensation expense and contributed surplus of $27.4
million in the year ended December 31, 2008 (2007 - $14.4 million), based
on the amortization of the fair value of the units on the date of grant.
Additionally, the Trust recorded $3.4 million (2007 - $2.0 million) of
cash distributions on restricted units. The total cash and non-cash unit
based compensation recorded in the year was $30.8 million (2007 - $16.4
million).
A summary of the changes in the contributed surplus is as follows:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Contributed surplus, beginning of year 15,086 9,150
Unit-based compensation 27,554 14,516
Exercised restricted units (12,781) (8,442)
Forfeited restricted units (119) (138)
-------------------------------------------------------------------------
Contributed surplus, end of year 29,740 15,086
-------------------------------------------------------------------------
On June 23, 2008, the Board of Directors approved the issuance effective
July 1, 2008 of 551,622 restricted units to employees of the Trust in
conjunction with a special bonus award to recognize their efforts
contributing to the successful growth and net asset value appreciation of
the Trust in the past two and a half years.
14. DEFICIT
The deficit balance is composed of the following items:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Accumulated earnings 575,146 111,044
Accumulated cash distributions (860,371) (535,550)
-------------------------------------------------------------------------
Deficit, end of year (285,225) (424,506)
-------------------------------------------------------------------------
The Trust has historically paid cash distributions in excess of
accumulated earnings as cash distributions are based on cash flow from
operating activities before changes in non-cash working capital generated
in the current period while accumulated earnings are based on net income.
15. INCOME TAXES
On June 22, 2007, income trust tax legislation was passed resulting in
tax on distributions at the federal corporate income tax rate plus a
deemed 13 percent 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 of this new legislation, the future tax position
of the Trust, the parent entity, is now required to be reflected in the
consolidated future income tax calculation.
On February 26, 2008, the Federal Government announced as part of their
budget, that the provincial component of trust tax will be based on the
general provincial corporate tax rate in each province in which the trust
has a permanent establishment instead of the deemed 13 percent provincial
tax rate. As the proposed rules were not substantively enacted as of
December 31, 2008, the Trust has not reflected a reduced tax rate in the
calculation of future income taxes in 2008.
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 as follows:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Income before income taxes 561,441 4,400
Capital and other tax expense (20,031) (15,394)
-------------------------------------------------------------------------
541,410 (10,994)
Statutory income tax rate 30.81% 33.72%
-------------------------------------------------------------------------
Expected provision for income taxes 166,808 (3,707)
Internal reorganization - (158,817)
Initial recognition of tax liability - 152,346
Effect of change in corporate tax rates (7,419) (23,337)
Income of the Trust not subject to
current tax and other (82,081) 54,688
-------------------------------------------------------------------------
Future income tax expense 77,308 21,173
-------------------------------------------------------------------------
The net future income tax liability is comprised of the following:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Future income tax assets:
Asset retirement obligations 19,210 18,600
Trust unit issue costs 2,586 679
Risk management contracts 298 -
-------------------------------------------------------------------------
22,094 19,279
Future income tax liabilities:
Property, plant and equipment (335,060) (263,286)
Risk management contracts (18,673) -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(353,733) (263,286)
Net future income tax liability (331,639) (244,007)
-------------------------------------------------------------------------
At December 31, 2008, the Trust had tax pools of approximately $1.3
billion (2007 - $1.0 billion) consisting of intangible resource pools,
tangible pools and trust unit issue costs.
16. PER TRUST UNIT AMOUNTS
The following table summarizes the weighted average trust units used in
calculating net income per trust unit:
-------------------------------------------------------------------------
Three months ended December 31 Year ended December 31
2008 2007 2008 2007
-------------------------------------------------------------------------
Weighted average
trust units 125,091,800 113,136,424 123,993,078 100,670,407
Dilutive impact
of restricted
units 2,325,663 1,486,714 1,950,679 1,388,254
-------------------------------------------------------------------------
Dilutive trust units 127,417,463 114,623,138 125,943,757 102,058,661
-------------------------------------------------------------------------
17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Trust's financial assets and liabilities are comprised of accounts
receivable, investments in marketable securities, the reclamation fund,
risk management assets and liabilities, accounts payable and accrued
liabilities, cash distributions payable and bank indebtedness. Risk
management assets and liabilities arise from the use of derivatives.
Discussions of risks associated with financial assets and liabilities,
fair values of financial assets and liabilities and summarized
information related to risk management positions are detailed below:
a) Risks Associated with Financial Assets and Liabilities
The Trust is exposed to financial risks from its financial assets and
liabilities. The financial risks include market risk relating to
commodity prices, interest rates and foreign exchange rates as well as
credit and liquidity risk.
Market Risk
Market risk is the risk that the fair value or future cash flows of a
derivative will fluctuate because of changes in market prices. Market
risk comprised of commodity price risk, interest rate risk and foreign
exchange risk is discussed below.
Commodity Price Risk
The Trust is exposed to commodity price risk on crude oil and natural gas
revenues as well as power on electricity consumption. As a means to
mitigate the exposure to commodity price volatility, the Trust has
entered into various derivative agreements. The use of derivative
instruments is governed under formal policies and is subject to limits
established by the Board of Directors of Crescent Point Resources Inc.,
the administrator of the Trust.
Crude Oil - To partially mitigate exposure to the crude oil commodity
price risk, the Trust enters into option contracts and swaps, which
manage the Cdn$ WTI price fluctuations.
Natural gas - The Trust has partially mitigated the natural gas commodity
price risk by entering into AECO natural gas collars, which manage the
AECO natural gas price fluctuations.
Power - To manage the Trust's exposure to electricity price changes, the
Trust has entered into swaps and fixed price physical delivery contracts
which fix the power price.
Interest Rate Risk
The Trust is exposed to interest rate risk on bank indebtedness to the
extent of changes in the prime interest rate. Crescent Point partially
mitigates its exposure to interest rate changes by entering into both
interest rate swap and bankers acceptance transactions as a means of
managing the debt portfolio.
At December 31, 2008, a one percent increase or decrease in the interest
rate on floating rate debt and interest rate swaps would have amounted to
a $5.7 million impact to net income for the year ended December 31, 2008.
At December 31 2008, the Trust's outstanding derivative instruments
utilized for interest rate management activities were in an unrealized
loss position of $10.6 million.
Foreign Exchange Risk
Fluctuations in the exchange rates between the U.S. and Canadian dollar
can affect the Trust's reported results. Crescent Point's functional and
reporting currency is Canadian dollars. To partially mitigate this risk
the Trust has fixed crude oil contracts to settle in Cdn$ WTI.
Credit Risk
Credit risk is the risk that one party to a financial instrument will
cause a financial loss for the other party by failing to discharge an
obligation. A substantial portion of the Trust's accounts receivable are
with customers in the oil and gas industry and are subject to normal
industry credit risks. The Trust monitors the creditworthiness and
concentration of credit with customers of its physical oil and gas sales.
The Trust is authorized to transact derivative contracts with
counterparties rated A (or equivalent) or better, based on the lowest
rating of the three ratings providers. Should one of the Trust's
financial counter parties be downgraded below the A rating limit, the
Chief Financial Officer will advise the Audit Committee and provide
recommendations to minimize the Trust's credit risk to that counterparty.
The maximum credit exposure associated with accounts receivable and risk
management assets is the total carrying value and the maximum exposure
associated with the derivative instruments approximates their fair value.
On July 23, 2008, the Trust announced that it has a potential exposure to
SemCanada Crude Company ("SemCanada"), a Canadian subsidiary of SemGroup,
L.P. ("SemGroup"), relating to the marketing of a portion of the Trust's
physical crude oil and liquids production. The contract pertaining to the
majority of the production volumes purchased by SemCanada was previously
terminated and does not represent an ongoing exposure for the Trust.
SemGroup filed a voluntary petition for reorganization under Chapter 11
of the Bankruptcy Code in the United States Bankruptcy Court for the
District of Delaware and SemCanada also filed for creditor protection in
Canada under The Companies' Creditors Arrangement Act. SemGroup listed
assets of $6.14 billion and liabilities of $7.53 billion in its US
bankruptcy filing.
Crescent Point's exposure is listed in SemGroup's US bankruptcy filing as
$42.5 million based on SemGroup's forecasts of prices and production
volumes. The Trust's actual exposure is closer to $31.1 million based on
confirmed production volumes and contract prices. During the fourth
quarter of 2008, a provision of $19.4 million was recorded for amounts
considered to be uncollectible relating to this receivable.
The Trust has purchased trade credit insurance to protect the Trust
against credit risk with financial counterparties.
Liquidity Risk
Liquidity risk is the risk that the Trust will encounter difficulty in
meeting obligations associated with financial liabilities. The Trust
manages its liquidity risk through cash and debt management. As disclosed
in Note 12, Crescent Point targets a net debt to funds flow from
operations ratio of approximately 1.0 times.
In managing liquidity risk, the Trust has access to a wide range of
funding at competitive rates through capital markets and banks. At
December 31, 2008, the Trust had available unused borrowing capacity of
$231.4 million. The Trust believes it has sufficient funding to meet
foreseeable borrowing requirements.
The timing of cash outflows relating to financial liabilities is outlined
in the table below:
-------------------------------------------------------------------------
($000) 1 year 2 years 3 years Total
-------------------------------------------------------------------------
Accounts payable and accrued
liabilities 118,038 - - 118,038
Cash distribution payable 15,208 - - 15,208
Risk management liabilities 5,395 4,205 1,011 10,611
Bank indebtedness - 918,626 - 918,626
-------------------------------------------------------------------------
Included in Crescent Point's bank indebtedness of $918.6 million at
December 31, 2008 are obligations of $750.0 million of bankers'
acceptances, obligations of $172.3 million for borrowings under the
operating and syndicated prime loans, partially offset by prepaid
interest on banker's acceptances of $3.7 million. These amounts are fully
supported and management expects that they will continue to be supported
by revolving credit and loan facilities that have no repayment
requirements other than interest.
Throughout the latter part of 2008, global financial markets entered into
a period of significant uncertainty marked by high profile bankruptcies
of major financial institutions, large increases in stock market
volatility, significant downward pressure on equities and overall
tightening of credit markets. At December 31, 2008 there was $231.4
million of credit facilities available.
During this year, Crescent Point was successful in increasing its credit
facilities by $350 million. The financing highlights the high quality
nature of the asset base and the robust economics of the opportunities
that lie ahead for Crescent Point. Subsequent to December 31, 2008
Crescent Point successfully completed $115 million offering of trust
units (see note 19). The Trust has significant cash available to meet its
short and medium term needs.
Crescent Point is well positioned to withstand the current market
uncertainty and to take advantage of acquisition opportunities. Crescent
Point's balance sheet is strong and its 31/2 year risk management program
provides cash flow stability.
b) Fair Value of Financial Assets and Liabilities
The fair values of cash, accounts receivable, the reclamation fund,
accounts payable and accrued liabilities, cash distributions payable and
bank indebtedness approximates their carrying amounts due to their short-
term nature and floating interest rate on debt.
Risk management assets and liabilities and investments in marketable
securities are recorded at their estimated fair value based on the mark-
to- market method of accounting, using third-party market forecasts. The
Trust incorporates the credit risk associated with counterparty default,
as well as the Trust's own credit risk, into the estimates of fair value.
The following is a summary of the fair value of financial assets and
liabilities:
-------------------------------------------------------------------------
($000) As at December 31, As at December 31,
2008 2007
Fair Value Fair Value
-------------------------------------------------------------------------
Financial Assets
Held-for-Trading
Risk management assets(1) 181,935 451
Investments in marketable securities 538 1,385
Long term investments(2) - 6,386
Loans and Receivables
Accounts receivable 91,994 102,800
Available for Sale
Long term investments 20,160 -
Financial Liabilities
Held-for-Trading
Risk management liabilities(1) 10,611 123,471
Other Financial Liabilities
Accounts payable and accrued
liabilities 118,038 144,141
Cash distribution payable 15,208 22,752
Bank debt 918,626 595,984
-------------------------------------------------------------------------
(1) Including current portion.
(2) Excluding equity investment.
c) Risk Management Assets and Liabilities
The Trust entered into fixed price oil, gas, power and interest rate
contracts to manage its exposure to fluctuations in the price of crude
oil, gas, power, and interest on debt.
The following is a summary of the derivative contracts in place as at
December 31, 2008:
-------------------------------------------------------------------------
Financial WTI Crude Oil Contracts - Canadian Dollar(1)
Average Average
Collar Collar Average
Average Sold Bought Bought Average
Swap Call Put Put Put
Price Price Price Price Premium
Volume ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/
Term Contract (bbls/d) bbl) bbl) bbl) bbl) bbl)
-------------------------------------------------------------------------
2009 Swap 7,500 83.82
2009 Collar 5,250 95.48 76.24
2009 Put 3,250 70.46 (6.03)
2010 Swap 6,313 85.17
2010 Collar 3,937 96.35 79.74
2010 Put 2,500 72.90 (4.51)
2011 Swap 4,748 105.74
2011 Collar 3,626 123.19 95.00
2012
January
- March Swap 3,000 101.11
2012
January
- March Collar 500 123.00 90.00
-------------------------------------------------------------------------
(1) The volumes and prices reported are the weighted average volumes and
prices for the period.
-------------------------------------------------------------------------
Financial Interest Rate Contracts - Canadian Dollar
Notional Fixed
Principal Annual
Term Contract ($Cdn) Rate (%)
-------------------------------------------------------------------------
January 2009 - February 2009 Swap 50,000,000 4.37
January 2009 - May 2009 Swap 75,000,000 3.16
January 2009 - November 2010 Swap 75,000,000 4.35
January 2009 - November 2010 Swap 50,000,000 1.97
January 2009 - June 2011 Swap 75,000,000 3.89
January 2009 - November 2011 Swap 25,000,000 2.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Physical Power Contracts - Canadian Dollar
Fixed
Rate
Volume ($Cdn/
Term Contract (MW/h) MW/h)
-------------------------------------------------------------------------
January 2009 - December 2009 Swap 1.0 82.45
January 2009 - December 2009 Swap 3.0 81.25
January 2010 - December 2010 Swap 3.0 80.75
-------------------------------------------------------------------------
The physical contracts have not been marked-to-market as the power
acquired is for the Trust's own use. The unrealized loss on the physical
contracts at December 31, 2008 is $0.1 million.
The following table reconciles the movement in the fair value of the
Trust's commodity, power and interest rate contracts:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Risk management asset, beginning of year 451 1,052
Acquired through capital acquisitions - 2,063
Unrealized mark-to-market gain (loss) 181,484 (2,664)
-------------------------------------------------------------------------
Risk management asset, end of year 181,935 451
Less: current risk management asset, end of year (82,782) (451)
-------------------------------------------------------------------------
Long term risk management asset, end of year 99,153 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Risk management liability, beginning of year 123,471 19,278
Acquired through capital acquisitions - 1,431
Unrealized mark-to-market loss (gain) (112,860) 102,762
-------------------------------------------------------------------------
Risk management liability, end of year 10,611 123,471
Less: current risk management liability, end of year (5,395) (63,819)
-------------------------------------------------------------------------
Long term risk management liability, end of year 5,216 59,652
-------------------------------------------------------------------------
Commodity Price Sensitivities on Derivatives
The following table summarizes the sensitivity of the fair value of the
Trust's risk management positions as at December 31, 2008 to fluctuations
in commodity prices, with all other variables held constant. When
assessing the potential impact of these commodity price changes, the
Trust believes 10 percent volatility is a reasonable measure.
Fluctuations in commodity prices potentially could have resulted in
unrealized gains (losses) impacting net income as follows:
-------------------------------------------------------------------------
($000) Impact on Net Income
Year Ended December 31, 2008
-------------------------------------------------------------------------
Increase 10% Decrease 10%
-------------------------------------------------------------------------
Crude oil price (83,455) 85,014
-------------------------------------------------------------------------
18. COMMITMENTS
At December 31, 2008, the Trust had contractual obligations and
commitments for office space, equipment, vehicles and premiums on put
contracts:
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
2009 15,574
2010 15,731
2011 9,418
2012 7,784
2013 8,682
-------------------------------------------------------------------------
(1) Included in the above commitments are recoveries of rent expense on
office space the Trust has acquired through various acquisitions and
has subleased out to other tenants.
19. SUBSEQUENT EVENTS
a) Equity financing
On January 9, 2009, the Trust and a syndicate of underwriters closed a
bought deal equity financing pursuant to which the syndicate sold
5,227,325 trust units for gross proceeds of $115.0 million ($22.00 per
trust unit).
b) Acquisition of Villanova Energy Corporation
On January 15, 2009, the Trust closed the acquisition of Villanova Energy
Corporation, a private company with properties in the Bakken area of
southeast Saskatchewan by way of a Plan of Arrangement for total
consideration of 4.625 million trust units plus the assumption of
approximately $23.6 million of Villanova debt. Total consideration was
approximately $123.1 million based on a value of $21.51 per trust unit.
c) Acquisition of Bakken southeast Saskatchewan Assets
On March 4, 2009, the Trust announced the acquisition of the Talisman
Energy Inc. assets in southeast Saskatchewan and Montana for cash
consideration of approximately $720 million effective April 1, 2009.
Under the terms of the agreement, Crescent Point and TriStar Oil & Gas
Ltd. ("TriStar") will jointly and severally acquire the assets. Crescent
Point and TriStar have agreed that each party will acquire 50 percent
working interests in the assets for approximately $360 million. The
Trust's share of the acquisition will be financed with existing credit
facilities and through a $230 million bought deal financing (10,825,000
trust units at $21.25 per trust unit).
Crescent Point and TriStar have also entered into an agreement with
Shelter Bay, under which Crescent Point and TriStar will sell to Shelter
Bay a portion of the Bakken assets (the "Bakken Assets"). Consideration
to be received for the Bakken Assets is approximately $71 million, of
which Crescent Point and TriStar will each receive approximately $35.5
million.
In addition, the Trust announced an intention to convert to a corporation
with a $0.23 monthly dividend.
20. COMPARATIVE INFORMATION
Certain information provided for the previous period has been restated to
conform to the current period presentation.
Directors
Peter Bannister, Chairman(1)(3)
Paul Colborne(2)(4)
Ken Cugnet(3)(4)(5)
Hugh Gillard(1)(2)(5)
Gerald Romanzin(1)(3)
Scott Saxberg(4)
Greg Turnbull(2)(5)
(1) Member of the Audit Committee of the Board of Directors
(2) Member of the Compensation Committee of the Board of Directors
(3) Member of the Reserves Committee of the Board of Directors
(4) Member of the Health, Safety and Environment Committee of the Board
of Directors
(5) Member of the Corporate Governance Committee
Officers
Scott Saxberg
President and Chief Executive Officer
C. Neil Smith
Vice President, Engineering and
Business Development
Greg Tisdale
Chief Financial Officer
Dave Balutis
Vice President, Geosciences
Tamara MacDonald
Vice President, Land
Trent Stangl
Vice President, Marketing and Investor Relations
Ken Lamont
Controller and Treasurer
Head Office
Suite 2800, 111 - 5th Avenue S.W.
Calgary, Alberta T2P 3Y6
Tel: (403) 693-0020
Fax: (403) 693-0070
Toll Free: (888) 693-0020
Banker
The Bank of Nova Scotia
Calgary, Alberta
Auditor
PricewaterhouseCoopers LLP
Calgary, Alberta
Legal Counsel
McCarthy Tétrault LLP
Calgary, Alberta
Evaluation Engineers
GLJ Petroleum Consultants Ltd.
Calgary, Alberta
Sproule Associates Ltd.
Calgary, Alberta
Registrar and Transfer Agent
Investors are encouraged to contact Crescent Point's Registrar and
Transfer Agent for information regarding their security holdings:
Olympia Trust Company
2300, 125 - 9th Avenue S.E.
Calgary, Alberta T2G 0P6
Tel: (403) 261-0900
Stock Exchange
Toronto Stock Exchange - TSX
Stock Symbol
CPG.UN
For further information:
For further information: Investor Contacts: Scott Saxberg, President and Chief Executive Officer, (403) 693-0020; Greg Tisdale, Chief Financial Officer, (403) 693-0020; Trent Stangl, Vice President, Marketing and Investor Relations, (403) 693-0020