NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE
UNITED STATES. ANY FAILURE TO COMPLY WITH THIS RESTRICTION MAY CONSTITUTE A
VIOLATION OF U.S. SECURITIES LAWS.
Seaview Energy Inc. ("Seaview" or the "Company") (TSX VENTURE:CVU.A) (TSX
VENTURE:CVU.B) is pleased to provide shareholders with an update on corporate
developments and the Company's 2009 financial and operational results.
----------------------------------------------------------------------------
SELECTED INFORMATION
----------------------------------------------------------------------------
Financial ($000's
except per share % %
amounts) Q4 2009 Q4 2008 Change 2009 2008 Change
----------------------------------------------------------------------------
Petroleum and
natural gas sales $ 10,377 $ 8,226 26% $ 33,504 $ 22,998 46%
Funds flow from
operations (1) 5,024 3,556 41% 15,120 10,854 39%
Basic per share(2) 0.08 0.07 14% 0.26 0.30 (13%)
Diluted per share(2) 0.08 0.06 33% 0.26 0.23 13%
Net loss (2,366) 375 (731%) (9,607) 2,296 (518%)
Basic per share(2) (0.04) 0.01 (500%) (0.16) 0.06 (367%)
Diluted per share(2) (0.04) 0.01 (500%) (0.16) 0.05 (420%)
Capital expenditures
(3) 9,208 6,669 38% 47,022 32,714 44%
Corporate
acquisitions (4) - - - - 60,927 -
Net debt 40,309 22,494 79% 40,309 22,494 79%
----------------------------------------------------------------------------
Shares Outstanding
at period end
(000's)
----------------------------------------------------------------------------
Class A 65,433 50,005 31% 65,433 50,005 31%
Class B 1,054 1,054 - 1,054 1,054 -
----------------------------------------------------------------------------
Operations
----------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 13,703 8,330 65% 11,422 5,221 119%
Light oil and NGLs
(bbl/d) 445 406 10% 417 207 101%
----------------------------------------------------------------------------
Total production
(boe/d) 2,729 1,794 52% 2,321 1,077 116%
----------------------------------------------------------------------------
Average realized sales
price (net of risk
management gains or
losses)
Natural gas (per
mcf) $ 6.06 $ 7.68 (21%) $ 5.88 $ 8.47 (31%)
Light oil and NGL
(per bbl) 66.92 62.82 7% 58.92 89.96 (35%)
----------------------------------------------------------------------------
Netback per boe (1)
Sales price $ 35.35 $ 46.98 (25%) $ 32.00 $ 57.41 (44%)
Realized risk
management gains 5.98 2.86 109% 7.55 0.93 712%
Sales price (net of
realized risk
management gains) 41.33 49.84 (17%) 39.55 58.34 (32%)
Royalties 4.52 8.77 (48%) 4.90 12.59 (61%)
Operating expenses 11.80 11.34 4% 11.57 10.08 15%
Transportation 1.27 1.14 11% 1.44 1.18 22%
----------------------------------------------------------------------------
Operating netback
(1) $ 23.74 $ 28.59 (17%) $ 21.64 $ 34.49 (37%)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company uses "funds flow from operations" and "funds flow from
operations per share" which do not have any standardized meaning
prescribed by Canadian GAAP. The term is used to analyze operating
performance and leverage. The Company uses "Netback per boe" and
"Operating Netback" which do not have any standardized meaning
prescribed by Canadian GAAP. The term is used to evaluate performance
and in capital allocation decisions.
(2) Weighted average diluted shares outstanding for all periods exclude the
granted options as these would have been anti-dilutive. The impact of
the conversion of the Class B shares has been included as dilutive for
Q4 2008 and 2008 while the impact has been excluded from Q4 2009 and
2009 as it would have been anti-dilutive.
(3) Capital expenditures include only the cash additions for the period and
capitalized G&A expense.
(4) Corporate acquisitions includes total consideration adjusted for net
debt assumed.
HIGHLIGHTS OF 2009 AND SUBSEQUENT EVENTS
- Average production for 2009 was 2,321 boe per day, an increase of 116%
relative to 2008 average production of 1,077 boe per day (32% per share
increase);
- Average production for Q4 2009 of 2,729 boe per day was an increase of 52%
relative to Q4 2008 production, and a 9% increase compared to Q3 2009 production
of 2,513 boe per day;
- Production per weighted average Class A share increased 9% in the fourth
quarter over third quarter 2009 results and 11% over the fourth quarter 2008
results;
- Since commencing operations on October 17, 2007, record production levels in
the fourth quarter of 2009 mark the Company's ninth consecutive quarter of
growth;
- Exceeded 2009 exit rate guidance of more than 3,000 boe per day with
production for January 2010 averaging 3,100 boe per day based on field
estimates. In addition, the Company has over 850 boe per day behind pipe to be
placed on production;
- 2009 Funds flow from operations increased 39% to $15.1 million from $10.9
million in 2008;
- Proven Producing reserves increased by 52% to 5,973 Mboe, compared to 3,941
Mboe at December 31, 2008;
- Total Proven reserves increased by 49%, to 7,141 Mboe compared to 4,786 Mboe
at December 31, 2008;
- Total Proven plus Probable reserves increased by 53% to 11,068 Mboe compared
to 7,256 Mboe at December 31, 2008;
- Reserve life index is 7.2 years on a Total Proven basis and 11.1 years on a
Total Proven plus Probable basis using December 31, 2009 reserves and fourth
quarter 2009 production of 2,729 boe/d;
- Achieved Proven finding, development and acquisition (FD&A) costs of
$14.99/boe and Proven plus Probable costs of $10.73/boe (including changes to
Future Development Costs "FDC" and technical revisions);
- Achieved Proven finding and development (F&D) costs of $9.97/boe and Proven
plus Probable costs of $7.75/boe (including changes to FDC and technical
revisions);
- The Company drilled eleven wells (9.0 net) in 2009 with a 73% success rate. In
the fourth quarter two wells (1.12 net) were drilled at a 100% success rate;
- Acquired approximately 730 boe per day of high quality, long life assets in
the Peace River Arch area for total consideration of $26.6 million on June 30,
2009. The 2009 results include cash flow and operational impact of this
acquisition from that date;
- Closed a bought deal financing for gross proceeds of approximately $15.7
million on June 16, 2009; and
- Expanded credit facility to $52 million, a 53% increase relative to December
31, 2008. Based on net debt of approximately $40 million at the end of Q4 2009,
Seaview has $12 million of available credit capacity to pursue strategic
opportunities.
Business Strategy
In 2009 Seaview continued to execute its balanced strategy of acquiring,
exploiting and exploring for high quality, long reserve life natural gas and
light oil assets in Western Canada. Despite the challenges of volatile commodity
prices and weak capital markets due the global economic crisis, Seaview's
business plan continued to deliver strong growth in 2009. Record production
levels for Q4-2009, of 2,729 boe/d, marks the Company's ninth consecutive
quarter of growth since inception in Q4-2007.
Seaview's management team continues to focus on consolidating high quality
assets within the Company's core areas, with significant exploration and
development opportunities. Operations highlights for 2009 include:
- Successfully closed five property acquisitions, further consolidating the
Company's core assets in the Peace River Arch.
-- Highlighted by the complimentary Peace River Arch assets acquired from a
senior producer for $26.6 million in June 2009 with a concurrent bought-deal
financing with gross proceeds of $15.7 million. This acquisition consolidated
Seaview's working interest in over 70% of the acquired assets focused in the
Balsam and Boundary Lake areas of northwest Alberta.
-- During the fourth quarter of 2009, Seaview purchased assets in four separate
acquisitions for total consideration of $3.8 million. Each of the minor property
acquisitions added high working interest follow-up drilling locations based on
the successful third quarter drilling program.
- Seaview drilled 11 wells (9.0 net) in 2009 at a 73% success rate.
-- In the Peace River Arch, Seaview drilled 7 wells (6.6 net) at a 71% success
rate. Results of the 2009 drilling program yielded 4 producing gas wells (3.6
net), 1 potential gas well (1.0 net), and 2 abandoned wells (2.0 net). One of
the abandoned wells encountered the target reservoir but was abandoned due to
operational problems and has subsequently been successfully re-drilled in the
first quarter of 2010.
-- As announced on November 19, 2009 the successful Q3-09 drilling program was
expected to add over 1,400 boe/d of new production capacity. Three of the four
successful wells were on online contributing a stable 1,500 boe/d net average
production for the month of December.
-- In southeast Saskatchewan, Seaview drilled 2 wells (1.8 net) with a 50%
success rate. Both wells were exploration projects targeting potential light oil
pools. The Company's exploration well in Rocanville (80% working interest) is
cased as a potential Birdbear oil well, various completion options are currently
being evaluated for this well.
-- In the first quarter of 2009, Seaview participated in one successful
exploration well (0.25 net) in the Harlech area of west-central Alberta. A total
of five prospective reservoir zones were successfully completed highlighting the
multi-zone nature of this resource style play. Further development activities in
Harlech will be deferred contingent on an improvement in natural gas prices;
-- In Wapiti, Seaview entered into a multi-well farm-in agreement where the
Company will drill a total of four wells in 2009-2010 targeting bath natural gas
and crude oil from the Cardium formation. In 2009, the Company participated in
one successful vertical exploration well (0.32 net) which has been successfully
completed and tested and is expected to be online in the second quarter.
Activity for the winter program to date in 2010 included drilling five wells
(4.0 net) at an 80% success rate. In the Peace River Arch, in Clayhurst, the
Company re-drilled one Montney well (1.0 net) which has been successfully
completed and tied in with initial rates expected to add over 80 boe/d net for
Q2-2010 and drilled one unsuccessful well (1.0 net) at Boundary Lake.
In Wapiti, Seaview drilled two wells (1.0 net) as part of the ongoing
exploration program targeting the Cardium formation. One vertical gas well (0.32
net) was drilled and completed testing Cardium gas similar to the vertical
exploration well drilled in late 2009. Seaview has now completed the earning
phase on the gas exploration portion of the program having earned 32% in three
sections of land on this Cardium natural gas resource play.
Finally, Seaview has successfully drilled and cased the Company's first
horizontal well in Wapiti targeting an early-stage light oil resource play in
the Cardium formation. The horizontal well has been completed with a 10-stage
multi-frac completion and is currently flowing on clean-up. Seaview has
assembled a sizable land position offsetting the horizontal well with exposure
to 11.5 sections of land (6.5 net) on this exciting new exploration play. The
Cardium formation in Wapiti is known to produce both oil and natural gas
regionally, however to date has not been developed using horizontal wells with
multi-frac completion technology.
Seaview estimates current behind pipe volumes of more than 850 boe/d from 7
wells (4.8 net). Of these volumes, it is anticipated that 5 wells (3.1 net) will
be brought on-stream during the second quarter adding more than 250 boe/d net of
new production. The remaining 2 wells (1.8 net) to be tied-in have initial
production of more than 600 boe/d which may be tied in before year-end
contingent on facility access and improved natural gas prices.
Capital Efficiency and Reserve Additions
The Company is pleased to report that a significant increase in reserves during
2009 as a result of its combined acquisitions and successful 2009 drilling
program. The independent reserves evaluation has been completed by Sproule and
Associates Limited "Sproule", with an effective date of December 31, 2009, in a
National Instrument 51-101 "NI 51-101" compliant report "Evaluation of the P&NG
Reserves of Seaview Energy Inc." Highlights of the report are summarized below:
- Proven Producing reserves increased by 52% to 5,973 Mboe compared to 3,941
Mboe at December 31, 2008;
- Total Proven reserves increased by 49% to 7,141 Mboe compared to 4,786 Mboe at
December 31, 2008;
- Total Proven plus Probable reserves increased by 53% to 11,068 Mboe compared
to 7,256 Mboe at December 31, 2008;
- Probable Developed Producing reserves assigned to Proved Producing assets are
2,286 Mboe, increasing developed Proven plus Probable producing reserves to
8,259 Mboe or 75% of the Total Proven plus Probable reserves. No future
development capital is required to convert the Probable Producing reserves to
Proven Producing over time;
- Reserve Life Index is 7.2 years on a Total Proven basis and 11.1 years on a
Total Proven plus Probable basis using December 31, 2009 reserves, and Q4-09
production of 2,729 boe/d;
- Total capital expenditures based on audited financial results were $46.9
million; including changes in FDC total capital costs for the purpose of
calculating FD&A costs are $47.4 million:
-- Achieved FD&A costs of $14.99/boe Proven and $10.73/boe Proven plus Probable
(Including changes in FDC);
-- Seaview completed five strategic property acquisitions in 2009, highlighted
by the complimentary PRA assets acquired from a senior producer for $26.6 mm in
June 2009. Overall the acquisition program added 2,158 Mboe of Total Proven plus
Probable reserves, or 47% of the Total Proven plus Probable reserve additions in
2009; and
-- Seaview's acquisitions and drilling success replaced production by 3.7 times
on a Proven basis and 5.4 times on a Proven plus Probable basis.
- Seaview completed an active drilling program in 2009 which included drilling
11 gross wells (9.0 net) with a 73% success rate. Capital expenditures based on
audited consolidated financial results were $16.5 million directed towards
drilling activity. Including changes to FDC, the total capital costs for the
purpose of calculating F&D costs are $19.1 million:
-- Achieved F&D costs of $9.97/boe Proven and $7.75/boe Proven plus Probable
(including FDC and after revisions);
-- Seaview enjoyed a very successful drilling program accounting for 2,458 Mboe
or 53% of the Total Proven and Probable reserve additions in 2009; and
-- Seaview's drilling success replaced production by 2.0 times on a Proven basis
and 2.5 times on a Proven plus Probable basis.
- Seaview continues to drive reserve addition costs down through successful
execution of the Company's balanced acquisition, exploration and development
strategy. Management has been able to steadily reduce finding costs as a result
of a strong prospect inventory and successful grass-roots exploration. Seaview's
three year average reserve costs are:
- Three year average Proven F&D costs of $14.10/boe Proven and Proven plus
Probable costs of $11.05/boe (including FDC and after revisions); and
- Three year average Proven FD&A costs of $21.69/boe Proven and Proven plus
Probable costs of $15.57/boe (including FDC and after revisions);
----------------------------------------------------------------------------
Historical Capital
Efficiency
Highlights 2009 2008 2007-2009
----------------------------------------------------------------------------
Total Total Total
Proved Proved Proved
Total plus Total plus Total plus
Proved Probable Proved Probable Proved Probable
----------------------------------------------------------------------------
Capital Costs
($thousands)
----------------------------------------------------------------------------
Exploration
and development
capital $16,484 $16,484 $20,907 $20,907 $41,027 $41,027
----------------------------------------------------------------------------
Acquisitions,
net of
dispositions $30,455 $30,455 $91,864 $91,864 $ 135,371 $135,371
----------------------------------------------------------------------------
Future
development
capital,
beginning
balance $5,219 $12,982 $843 $1,475 $0 $0
----------------------------------------------------------------------------
Future
development
capital, end
of period
balance $5,646 $15,551 $5,219 $12,982 $5,646 $15,551
----------------------------------------------------------------------------
Exploration
and
development
capital
including
change in
future
development
capital $16,911 $19,053 $25,283 $32,414 $46,673 $56,578
----------------------------------------------------------------------------
All-in
capital
including
change in
future
development
capital $47,366 $49,508 $117,147 $124,278 $ 182,044 $191,949
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reserve
additions
(including
technical
revisions)
----------------------------------------------------------------------------
Exploration
and
development
(Mboe) 1,696 2,458 1,393 2,321 3,309 5,118
----------------------------------------------------------------------------
Acquisitions,
net of
dispositions
(Mboe) 1,464 2,158 3,409 4,654 5,085 7,214
----------------------------------------------------------------------------
Total
reserve
additions
(Mboe) 3,160 4,616 4,802 6,976 8,395 12,332
----------------------------------------------------------------------------
Finding and
development
costs (F&D),
including
change in
future
development
capital
($/boe)(1) $9.97 $7.75 $18.15 $13.96 $14.10 $11.05
----------------------------------------------------------------------------
Finding,
development
and
acquisition
costs
(FD&A),
including
change in
future
development
capital
($/boe) $14.99 $10.73 $24.40 $17.82 $21.69 $15.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating
Efficiency
----------------------------------------------------------------------------
Operating
net-back
($/boe) $21.64 $21.64 $34.49 $34.49
----------------------------------------------------------------------------
Finding,
development
and
acquisition
costs
(FD&A),
excluding
change in
future
development
capital
($/boe) $14.85 $10.17 $23.48 $16.17
----------------------------------------------------------------------------
Recycle-Ratio 1.5 2.1 1.5 2.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reserve
Replacement
----------------------------------------------------------------------------
Reserve
additions,
including
revisions
(Mboe) 3,160 4,616 4,802 6,976
----------------------------------------------------------------------------
Annual
production
(Mboe) 847 847 427 427
----------------------------------------------------------------------------
Production
replacement
ratio 3.7 5.4 11.3 16.3
----------------------------------------------------------------------------
Notes:
(1) The aggregate of the exploration and development costs incurred in the
most recent financial year, and the change during that year in estimated
future development costs, generally will not reflect total finding and
development costs related to reserve additions for that year.
NI 51-101 Reserves Disclosure
Seaview has a Reserve Committee comprised of independent board members, which
reviews the qualifications and appointment of the independent reserve
evaluators. The committee also reviews the processes and technical data used to
determine the reserves booked.
The Company will file by April 30, 2010 its Annual Information Form which
includes Seaview's reserves data and other oil and gas information for the year
ended December 31, 2009 as mandated by "NI 51-101 - Standards for Disclosure for
Oil and Gas Activities of the Canadian Securities Administrators."
The December 31, 2009, evaluation was prepared by Sproule utilizing the
methodology and definitions as set out under NI 51-101. The reserves presented
herein include the total Company's working interest reserves before deduction of
royalties and exclude royalty interest reserves as at December 31, 2009.
Table 1 NI 51-101
Summary of Oil and Gas Reserves
as of December 31, 2009
Forecast Prices and Costs
Gross Reserves Net Reserves
----------------------------------------------------------------------------
Light
and Light and
Medium Natural Medium Natural
Crude Heavy Gas Natural Crude Heavy Gas Natural
Oil Crude Liquids Gas Oil Crude Liquids Gas
----------------------------------------------------------------------------
Mbbls Mbbls Mbbls Mmcf Mbbls Mbbls Mbbls Mmcf
----------------------------------------------------------------------------
Proved
Developed
Producing 1,210.4 0 127.7 27,812 1,065.9 0 77.4 20,607
Developed
Non-Producing 46.8 0 10.9 4,371 44.3 0 6.6 3,086
Undeveloped 20.4 0 15.4 2,074 16.2 0 11.4 1,853
Total
Proved 1,277.6 0 154.0 34,257 1,126.4 0 95.4 25,546
Probable 519.9 0 123.5 19,699 445.0 0 80.6 14,106
Total
Proved
plus
Probable 1,797.5 0 277.5 53,956 1,571.3 0 176.0 39,653
Table 2 NI 51-101
Summary of Net Present Values of Future Net Revenue
as of December 31, 2009
Forecast Prices and Costs
Unit Value
Before
Income Tax
Discounted
Before Future Income Tax Expenses and Discounted at at
----------------------------------------------------------------------------
0% 5% 10% 15% 20% 10%/yr
----------------------------------------------------------------------------
(M$) (M$) (M$) (M$) (M$) ($/boe)
----------------------------------------------------------------------------
Proved
Developed
Producing 181,089 125,766 98,253 81,755 70,676 21.46
Developed
Non-Producing 17,586 14,034 11,614 9,881 8,586 20.55
Undeveloped 8,418 6,387 5,124 4,269 3,654 15.23
Total Proved 207,093 146,186 114,992 95,905 82,916 20.99
Probable 123,676 68,343 46,006 34,124 26,746 15.99
Total Proved plus
Probable 330,769 214,530 160,997 130,029 109,661 19.27
After Future Income Tax Expenses and Discounted at
----------------------------------------------------------------------------
0% 5% 10% 15% 20%
----------------------------------------------------------------------------
(M$) (M$) (M$) (M$) (M$)
----------------------------------------------------------------------------
Proved
Developed Producing 151,858 107,378 84,894 71,260 62,029
Developed Non-Producing 13,012 10,353 8,542 7,246 6,278
Undeveloped 6,207 4,557 3,528 2,833 2,336
Total Proved 171,077 122,288 96,964 81,339 70,643
Probable 91,771 50,445 33,659 24,691 19,108
Total Proved plus
Probable 262,848 172,733 130,623 106,030 89,751
Table 3 NI 51-101
Total Future Net Revenue Undiscounted
as of December 31, 2009
Forecast Prices and Costs
Develop- Abandon-
Operating ment ment and
Revenue Royalties Costs Costs Other Costs
----------------------------------------------------------------------------
(M$) (M$) (M$) (M$) (M$)
----------------------------------------------------------------------------
Total Proved
Reserves 419,428 80,234 119,105 5,646 7,351
Total Proved plus
Probable 679,616 138,380 185,554 15,551 9,363
Future Net
Revenue
Before Future Net
Income Income Revenue After
Taxes Taxes Income Taxes
----------------------------------------------------------------------------
(M$) (M$) (M$)
----------------------------------------------------------------------------
Total Proved
Reserves 207,093 36,016 171,077
Total Proved plus Probable 330,769 67,922 262,848
Table 4 NI 51-101
Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2009
Forecast Prices and Costs
Future Net
Revenue Before Unit Value Before
Income Taxes Income Taxes
and (Discounted (Discounted at
at 10%/Year) 10%/Year)
-----------------------------------
(M$) ($/boe)
-----------------------------------
Proved
Light and Medium Crude Oil
(including solution gas and associated
by-products) 33,938 26.28
Heavy Crude Oil
(including solution gas and associated
by-products) 0 0
Natural Gas
(including associated by-products) 81,054 19.35
Proved plus Probable
Light and Medium Crude Oil
(including solution gas and associated
by-products) 43,723 24.45
Heavy Crude Oil
(including solution gas and associated
by-products) 0 0
Natural Gas
(including associated by-products) 117,274 17.86
Table 5 NI 51-101
Summary of Pricing and Inflation Rate Assumptions
As of December 31, 2009 Forecast Prices and Costs
NATURAL NATURAL GAS
CRUDE OIL GAS LIQUIDS
----------------------------------------------------------------------------
Edmonton Cromer
Par Price Medium Pentanes Butanes
WTI 40 degrees 29.3 degrees Alberta Plus FOB
Crude API API AECO Gas FOB Field Field
Year Oil Crude Oil Crude Oil Price Gate Gate
----------------------------------------------------------------------------
($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/mmbtu) ($Cdn/Bbl) ($Cdn/Bbl)
----------------------------------------------------------------------------
(1) (2) (3)
----------------------------------
Forecast
2010 79.17 84.25 80.04 5.36 86.28 59.65
2011 84.46 89.99 84.59 6.21 92.16 63.72
2012 86.89 92.61 85.20 6.44 94.84 65.57
2013 90.20 96.19 87.53 7.23 98.51 68.11
2014 92.01 98.13 88.32 7.98 100.50 69.48
US/CAN
Exchange
Year Inflation Rate
----------------------------------------------------------------------------
(%) ($US/Cdn)
-----------------------
Forecast
2010 2.0 0.920
2011 2.0 0.920
2012 2.0 0.920
2013 2.0 0.920
2014 2.0 0.920
Thereafter Escalation Rates of 2%
Notes:
(2) West Texas Intermediate at Cushing Oklahoma 40 degrees API, 0.4% sulphur
(3) Edmonton Light Sweet 40 degrees API, 0.3% sulphur
(4) Comer Medium (29.3 degrees API Heavy stream)
Net Asset Value per Class A Share
Information Based on Sproule Reserves Evaluation as at December 31, 2009
----------------------------------------------------------------------------
Before Tax 10% Discount
----------------------------------------------------------------------------
Proven
Developed Total Proven Total Proven
($M except share amounts) Producing Reserves plus Probable
----------------------------------------------------------------------------
Value of Reserves 98,253 114,992 160,997
Undeveloped Land (31,000 acres at
$200 per acre) 6,200 6,200 6,200
Estimated Net Debt as at December
31, 2009(1) (40,100) (40,100) (40,100)
----------------------------------------------------------------------------
Total Net Assets 64,353 81,092 127,097
Class A shares Outstanding (MM) as
at December 31, 2009 65.43 65.43 65.43
Estimated Net Asset Value per Class
A share $0.98 $1.24 $1.94
----------------------------------------------------------------------------
Notes:
(1) Estimated net debt excluding value of financial contracts.
Net Asset Value per Fully Diluted Share(1)
Information Based on Sproule Reserves Evaluation as at December 31, 2009
----------------------------------------------------------------------------
Before Tax 10% Discount
----------------------------------------------------------------------------
Proven
Developed Total Proven Total Proven
($M except share amounts) Producing Reserves plus Probable
----------------------------------------------------------------------------
Value of Reserves 98,253 114,992 160,997
Undeveloped Land (31,000 acres
at $200 per acre) 6,200 6,200 6,200
Estimated Net Debt as at
December 31, 2009(2) (38,560) (38,560) (38,560)
----------------------------------------------------------------------------
Total Net Assets 65,893 82,632 128,637
Fully Diluted shares Outstanding
(MM) as at December 31, 2009 (3) 77.34 77.34 77.34
Estimated Net Asset Value per
Fully Diluted share $0.85 $1.07 $1.66
----------------------------------------------------------------------------
Notes:
(2) Fully diluted shares including "in-the-money" options and converted
Class B shares based on closing price of $1.10 per Class A share as at
December 31, 2009.
(3) Estimated net debt excluding value of financial contracts, net of
proceeds from "in-the-money" options of $1,523,964
(4) Fully diluted shares outstanding based on 65,433,182 Class A shares,
Class B shares converted to 9,577,636 Class A shares based on conversion
price of $1.10 per Class A share as at December 31, 2009, and 2,328,500
"in-the-money" options as at December 31, 2009.
COMMODITY PRICE RISK MANAGEMENT
A key component to Seaview's balance sheet management is the Company's commodity
price risk program. The price risk management program is intended to reduce
price volatility in order to support cash flow, protect acquisition economics
and finance ongoing capital expenditures.
Subsequent to the end of the third quarter of 2009, Seaview entered into
additional financial contracts for 2010 and 2011 providing for increased
downside protection designed to minimize the impact of volatile commodity prices
on future capital expenditure plans. Seaview currently has approximately 1,545
boe/d (approximately 48% of estimated current production) hedged for the
remainder of 2010;
- 8,500 GJ/d of natural gas hedged in puts and fixed contracts providing for a
"net of cost" floor of $4.94/GJ;
- 200 bbl/d of crude oil hedged in put contracts for 2010 with a "net of cost"
floor of CDN$75.00/bbl;
- On a combined basis, Seaview has 9,255 mcfe/d, hedged at a "net of cost" floor
price of $6.16/mcfe, which will provide for a minimum revenue in 2010 of $20.8
million.
OUTLOOK; 2010 GUIDANCE
As a result of a continued success in 2009, Seaview remains well positioned to
continue its growth strategy in 2010 despite the current challenging economic
climate. Seaview now has the following characteristics:
- Total Proven reserves of 7,141 Mboe, and Total Proven plus Probable reserves
of 11,068 Mboe, effective December 31, 2009, as evaluated by Sproule and
Associates using National Instrument 51-101 reserve definitions;
- Reserve life index is 11.1 years based on Total Proven plus Probable reserves
and Q4 2009 production of 2,729 boe per day;
- Net asset value as at December 31, 2009 using Total Proven plus Probable
reserves and a before-tax 10-percent discount rate, including $6.2 million in
value for undeveloped land, is $1.66 per share;
- Forecast 2010 average daily production estimate of more than 3,200 boe per day
compared to 2009 annual average production of 2,321 boe per day resulting in an
estimated forecast production growth of 38% per share (based on 65.43 million
Class A shares outstanding);
- Forecasted 2010 capital budget of $11.5 million;
- Commodity hedging program providing for downside protection on 48% of 2010
forecasted average production generating a minimum $20.8 million gross revenue
for 2010; and
- 65.43 million Class A shares and 1.0 million Class B shares outstanding.
RELEASE OF 2009 FINANCIALS AND ANNUAL INFORMATION FORM
Seaview has filed its financial results for the year ended December 31, 2009
including the audited consolidated financial statements and related management's
discussion and analysis ("MD&A"). The Annual Information Form which includes
Seaview's reserves data and other oil and gas information for the year ended
December 31, 2009 as mandated by National Instrument 51-101 Standards for
Disclosure for Oil and Gas Activities of the Canadian Securities Administrators
will be filed by April 30, 2010. These filings will be available in their
entirety at www.seaviewenergy.com and www.sedar.com or by contacting the Company
directly.
Barrels of oil equivalent (boe) may be misleading, particularly if used in
isolation. A boe conversion ratio of six thousand cubic feet (mcf) of natural
gas to one barrel (bbl) of oil is based on an energy conversion method primarily
applicable at the burner tip and is not intended to represent a value
equivalency at the wellhead. All boe conversions in this press release are
derived by converting natural gas to oil in the ratio of six thousand cubic feet
of natural gas to one barrel of oil. Certain financial amounts are presented on
a per boe basis, such measurements may not be consistent with those used by
other companies.
Estimated values contained in this press release do not represent fair market value.
This press release may contain forward-looking statements within the meaning of
applicable securities laws. Forward-looking statements may include estimates,
plans, anticipations, expectations, opinions, forecasts, projections, guidance
or other similar statements that are not statements of fact. Although the
Company believes that the expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations will
prove to be correct. These statements are subject to certain risks and
uncertainties and may be based on assumptions that could cause actual results to
differ materially from those anticipated or implied in the forward-looking
statements. These risks include, but are not limited to: the risks associated
with the oil and gas industry (e.g. operational risks in development,
exploration and production; delays or changes in plans with respect to
exploration or development projects or capital expenditures; the uncertainty of
reserve estimates; the uncertainty of estimates and projections relating to
production, costs and expenses and health, safety and environmental risks),
commodity price and exchange rate fluctuation and uncertainties resulting from
potential delays or changes in plans with respect to exploration or development
projects or capital expenditures. The Company's forward-looking statements are
expressly qualified in their entirety by this cautionary statement. The
forward-looking statements contained in this press release are made as of the
date hereof and the Company undertakes no obligations to update publicly or
revise any forward-looking statements or information, whether as a result of new
information, future events or otherwise, unless so required by applicable
securities laws.
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