Canext Energy Ltd. ("Canext" or "the Company") (TSX VENTURE:CXZ) is pleased to
announce the results of its independent reserve report as at December 31, 2008.
Highlights:
- Proved reserves have increased 94% to 3,532,200 boe,
- Proved and Probable (P+P) reserves have increased 112% to 6,554,300 boe,
- Proved and P+P reserves per common share have increased 69% and 85% respectively,
- P + P reserve replacement was 988%,
- Finding and Development costs (F&D) including revisions and changes to future
capital were $17.66/boe Proved and $12.36/boe P + P based on un-audited capital
spending of 21.7 MM$,
- F&D including acquisitions and dispositions was $16.47/boe Proved and
$11.98/boe P + P on un-audited capital spending of 16.8 MM$,
- Production for the full year averaged 1,070 boepd based on field estimates up
39% from the previous year,
- Net Asset Value per share based on a 10% discount rate, increased 58% to
$1.16/share,
- Drilled 16 (9.5 net) wells resulting in 2.5 net oil wells, 6.3 net gas wells
and 0.7 net dry holes for a 93% success rate.
In 2008 the Company focused its exploration and development efforts on its two
core properties. The result was significant reserves growth on the Montney
natural gas resource play at Pouce Coupe and expansion of the Sweeney Triassic
oil play. The growth in reserves and production came despite a strategic
decision to sell non core properties including approximately 20% of the
Company's production representing 10% of December 31, 2007 P + P reserves. Last
year proved to be challenging environment for the junior oil and gas sector with
volatile commodity prices and reduced access to capital from equity and debt
markets. Despite this situation, the Company managed to strengthen its balance
sheet with an equity offering and non core property dispositions, reducing its
year end net debt by 20% from December 31, 2007 (based on unaudited management
estimate).
The following tables summarize the Company's reserve information as prepared in
accordance with National Instrument "NI" 51-101 by Trimble Engineering
Associates Ltd ("Trimble Report"). The Trimble Report contains several
cautionary statements that are required by NI 51-101. Additional information on
the Company's reserves as required by NI 51-101 will be filed prior to April 30,
2009 on SEDAR (www.sedar.com).
Reserves Summary - Company working interest before royalties using
forecasted prices as at December 31, 2008
Light and
Medium Oil Heavy Oil NGL's Gas BOE 6:1
mstb mstb mstb mmscf mstboe
----------------------------------------------------------------------------
Proven Developed
Producing 385 - 64 8,536 1,872
Proven Developed Non
Producing 28 - 19 2,616 483
-------------------------------------------------------
Total Proven Developed 413 - 83 11,152 2,354
Proven Undeveloped 153 - 52 5,839 1,178
-------------------------------------------------------
Total Proved 566 - 135 16,991 3,532
Probable 635 - 110 13,662 3,022
-------------------------------------------------------
Total Proved
+ Probable 1,201 - 245 30,653 6,554
-------------------------------------------------------
(Tables may not add due to rounding.)
Summary of Net Present Values of Future Net Revenue
Forecasted Prices and Costs
Before Income Taxes, Discounted at (%/year)
As at December 31, 2008
0% 10% 15%
M$ M$ M$
----------------------------------------------------------------------------
Proven Developed Producing 62,960 41,398 35,687
Proven Developed Non Producing 11,771 6,513 5,063
----------------------------------
Total Developed 74,731 47,911 40,750
Undeveloped 29,289 11,540 7,502
----------------------------------
Total Proved 104,020 59,451 48,253
Probable 110,423 42,441 29,840
----------------------------------
Total Proved + Probable 214,443 101,892 78,092
----------------------------------
Note: NI 51-101 disclosure requires Canext to provide the following
warning:
It should not be assumed that the present value of estimated future
net cash flows shown above are representative of the fair market
value of the reserves.
The Proved Developed Non Producing reserves are associated with the Company's
interest in 4.1 net wells which were not producing as of December 31, 2008. It
is expected that 51% of these reserves and 68% of NPV @10% will be reclassified
to Proved Producing by March 31, 2009. The on production date for the other
wells are scheduled over the next 12 - 18 months.
The following tables, prepared by management, summarize the reconciliation of
the Company's working interest reserves on a Proved and Proved plus Probable
basis using boe equivalents of 6:1.
Proved Working Interest Reserves
Oil & NGL's Gas Equivalents
mstb mmcf mstboe
December 31, 2007 323 8,994 1,822
Production (63) (1,967) (390)
Dispositions (62) (611) (164)
Acquisitions 1 170 30
Additions / Extensions 527 9,978 2,190
Revisions to previous (28) 428 44
------------------------------------
December 31, 2008 700 16,991 3,532
------------------------------------
------------------------------------
(Tables may not add due to rounding.)
Proved and Probable (P+P) Working Interest Reserves
Oil & NGL's Gas Equivalents
mstb mmcf mstboe
December 31, 2007 550 15,231 3,088
Production (63) (1,967) (390)
Dispositions (121) (1,155) (314)
Acquisitions 2 216 38
Additions / Extensions 1,191 18,401 4,257
Revisions to previous (113) (72) (125)
------------------------------------
December 31, 2008 1,445 30,653 6,554
------------------------------------
------------------------------------
The revisions to previous estimates for Proved reserves were positive 2.4% while
the revisions for P + P reserves were negative 4.0%. The revisions were a
summation of several small changes on both the Proved and P + P cases.
Based on the average production for 2008 the Company has a Proved Reserve Life
Index (RLI) of 9 years and a P + P RLI of 16.8 years. The long RLI is a function
of the undeveloped assets at Pouce Coupe and Sweeney.
Forecasted price assumptions used in the Trimble Report as at December 31,
2008
Exchange WTI Edmonton AECO
Rate @ Cushing Light Spot
YEAR US$/CDN$ US$/bbl CDN$/bbl $/MMbtu
2009 Forecast 0.85 60.25 70.00 7.25
2010 Forecast 0.90 73.00 80.00 7.75
2011 Forecast 0.95 86.50 90.00 8.25
2012 Forecast 0.95 91.25 95.00 8.75
2013 Forecast 1.00 101.00 100.00 9.00
Prices escalating at 2.0 percent annually thereafter.
Net Asset Value
The Net Asset Value increased 58% to $1.16/diluted share. The increase in NAV
was due mainly to drilling success at Pouce Coupe and Sweeney which was
partially offset by higher royalties due to the Alberta New Royalty Framework.
$ 000's except share and per December 31, December 31, 2008-07
share amounts 2008 2007 % change
-------------------------------------------
-------------------------------------------
P + P Btax Net Present Value
(NPV) @10% 101,892 51,124 99%
Undeveloped Land Value(1) 10,701 15,289 -30%
Seismic Value(2) - -
Net Debt(3) (8,100) (10,150) -20%
Cash proceeds on exercise of
options(4) 3,770 1,380 173%
Net Asset Value (NAV) 108,263 57,643 88%
Shares outstanding 87,981,493 76,478,293 15%
Diluted common shares(4) 93,554,993 78,569,293 19%
NAV per diluted common share(4)
($/share) 1.16 0.73 58%
1) Undeveloped land value for 2007 was based on management's estimate of an
average $140/acre. Undeveloped land value for 2008 is based on
management's estimate of $1,000/acre at Pouce Coupe, $300/acre at Clear
Prairie/Sweeney and $40/acre for the balance.
2) In presenting the NAV the Company typically does not assign value to its
seismic database. At the end of 2008 the Company had 187 square miles of
3D seismic of which 40 square miles was acquired in 2008.
3) Net Debt at December 31, 2008 is estimated by management and is
unaudited.
4) Includes only those shares and cash proceeds which would be dilutive to
the NAV.
Finding and Development (F&D) Costs
The following table summarizes the F&D for the year compared to prior periods
based on NI 51-101 methodology which includes changes to estimates of Future
Development Capital (FDC). For additional disclosure the Company also tracts the
total Finding, Development and Acquisition Costs (FD&A).
3 Year
Total Proved F&D 2008 2007 Total
Capital expenditures M$, excluding 21,700 15,657 45,028
Acquisitions and Dispositions (A&D)(1)
Net change in Future Development 17,760 1,013 21,960
Capital (FDC) - M$
---------------------------------------
Total Capital for reserve additions 39,460 16,670 66,988
---------------------------------------
Reserve additions excluding (A&D)
mstboe 2,234 915 3,389
Total Proved F&D $/boe $ 17.66 $ 18.22 $ 19.77
3 Year
Total Proved + Probable F&D 2008 2007 Total
Capital expenditures M$, excluding
(A&D)(1) 21,700 15,657 45,028
Net change in FDC - M$ 29,367 3,713 39,808
---------------------------------------
Total Capital for reserve additions 51,067 19,370 84,836
---------------------------------------
Reserve additions excluding (A&D)
mstboe 4,132 1,339 5,743
Total Proved + Probable F&D $/boe $ 12.36 $ 14.47 $ 14.77
3 Year
Total Proved FD&A 2008 2007 Total
Capital expenditures M$, including
A&D(1) 16,823 59,169 81,740
Net change in FDC - M$ 17,760 3,055 21,960
---------------------------------------
Total Capital for reserve additions 34,583 62,224 103,700
---------------------------------------
Reserve additions including (A&D)
mstboe 2,100 1,647 4,133
Total Proved FD&A $/boe $ 16.47 $ 37.78 $ 25.09
3 Year
Total Proved + Probable FD&A 2008 2007 Total
Capital expenditures M$, including
A&D(1) 16,823 59,169 81,740
Net change in FDC - M$ 29,367 6,985 39,808
---------------------------------------
Total Capital for reserve additions 46,190 66,154 121,548
---------------------------------------
Reserve additions including (A&D)
mstboe 3,857 2,522 7,092
Total Proved + Probable FD&A $/boe $ 11.98 $ 26.23 $ 17.14
1) Capital spending for 2008 based on unaudited estimates
Pouce Coupe Reserves and Resource Potential
Proved Non Producing reserves at Pouce Coupe were assigned to four (2.1 net)
wells which were not on production on December 31, 2008. It is expected that 54%
of these reserves will be converted to Proved Producing by March 31, 2009 and
another 43% may be brought on production later in 2009 pending gas price and
available processing capacity. The Trimble Report includes 2.9 net Proved
Undeveloped and 3.0 net Probable Undeveloped Horizontal multi frac wells in the
Montney formation. The undeveloped or infill locations have been booked as one
horizontal well per section for the Upper Montney or Lower Montney as the case
may be. In addition to the 5.9 net undeveloped locations in the Trimble Report,
the Company has identified 25.7 net potential horizontal wells assuming three
wells per section in the Lower Montney and two wells per section in the Upper
Montney.
The weighted average recovery factor based on P + P reserves is 15% for the
Lower Montney and 17% for the Upper Montney/Doig Phosphate. The current P + P
reserves represent a 9% recovery when compared to the Discovered Resource based
on the AJM Report released on September 15, 2008.
Sweeney / Clear Prairie Reserves and Resource Potential
As of December 31, 2008, the Company has drilled and proved reserves in six
separate quarter sections. The Trimble Report assigns Proved Undeveloped
reserves to 2.4 net wells and Probable Undeveloped Reserves to 1.8 net wells
based on 80 acre infill drilling. One of the Proved Undeveloped wells (0.6 net)
is a re-drill of a well which was a mechanical failure as disclosed on April 15,
2008. Current mapping, which is supported by 12 square miles of recently
acquired proprietary 3D seismic, has identified the potential for an additional
23 net locations on 80 acre spacing. Other large pools in the area are developed
on 40 acre spacing. If Sweeney were to be drilled up on 40 acre spacing, the
number of potential locations would increase to over 50 net wells.
Included in the Proved Developed Non Producing case is 3.5 MM$ (2.1 MM$ net) of
capital for the construction of a central battery and gathering system capable
of processing 2,000 bbls/d of fluid and having storage capacity for 4,000 bbls
of oil.
Production Operations Update
Based on field production estimates for the month of December, average daily
production for the fourth quarter was 1,118 boe/d. This represents a 13%
increase over the third quarter of 2008. Current production is 1,150 - 1,250
boe/d which is below the Company's target of 1,400 boe/d. Canext has
approximately 360 boe/d tested and shut-in waiting on tie-ins, commingle orders,
or processing capacity. In addition, the Company still has completion operations
for one (0.45 net) Pouce Coupe Montney horizontal well and one (0.25 net)
Sweeney oil well planned for the first quarter. These projects were delayed or
deferred from fourth quarter of 2008 to the first quarter of 2009 for strategic
reasons. The Company is expecting risked production adds of 170 boe/d net from
these wells, bringing the total behind pipe estimate to 530 boe/d.
Installation and start-up of two third-party field compressor projects at Pouce
Coupe is considerably behind schedule. Production outages resulting from these
delays continue to affect firm processing capacity and delay contracted
incremental capacity. As a result, the Company has experienced several shut
downs lasting up to four days and affecting up to 250 boepd while these projects
are proceeding. Canext now expects one compressor upgrade to be completed in
early February and the other in late March. The Company is timing the completion
of its horizontal well to coincide with the March install and has deferred the
tie-in of a vertical well until the summer. Final decision for this tie-in
affecting 110 boepd will be based on processing capacity and gas price.
Due to reduced corporate capital spending and corresponding deferral in
construction of a central battery at Sweeney, Canext will have an extended shut
down of Sweeney oil production during spring break-up. The Company will have 240
bopd shut-in for 8-10 weeks during the second quarter of 2009. A decision on
construction of the central battery has been deferred until the price of oil
recovers or access to capital improves.
Updates to Share Structure
Canext commenced a normal course issuer bid on October 24, 2008. To date the
Company has purchased and cancelled 504,000 shares at an average price of
$0.33/share. The issuer bid expires on October 23, 2009. At present, Canext has
87,981,493 common shares issued and outstanding.
2009 Budget
The Company has set a capital budget of 7 MM$ for 2009. The majority of the
spending (67%) is forecasted for the second half of the year when commodity
prices are expected to recover. If prices do not improve the Company may choose
to further delay its projects. The modest capital program and second quarter
shut down will moderate Canext's forecasted growth. The Company is expecting
2009 production to average 1,200 boepd which would be a 12% increase year over
year.
Outlook
With the global economic slowdown continuing to affect access to capital from
the debt and equity markets the Company is taking a cautious approach to its
business plan. With a strong balance sheet and significant inventory of lower
risk opportunities Canext is well positioned to manage through these challenging
times.
The management team believes that 2009 will present new opportunities to grow
the Company. The team has proven its ability in the past to consolidate public
and private companies. In 2009 there will be a renewed focus on mergers and
acquisition opportunities which complement the Company's inventory and help
accelerate the development of its Discovered Resources.
Reader advisory:
The term "BOE" may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio for natural gas of 6 mscf: 1
bbl has been used which is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Investors are cautioned that the preceding statement of the Company may include
certain estimates, assumptions and other forward-looking information. The actual
future performance, developments and/or results of the Company may differ
materially from any or all of the forward-looking statements, which include
current expectations, estimates and projections, in all or part attributable to
general economic conditions and other risks, uncertainties and circumstances
partly or totally outside the control of the Company, including natural gas/oil
prices, reserve estimates, drilling risks, future production of gas and oil,
rates of inflation, changes in future costs and expenses related to the
activities involving the exploration, development and production of gas and oil
hedging, financing availability and other risks related to financial activities.
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