Seaview Energy Inc.
TSX VENTURE : CVU.A
TSX VENTURE : CVU.B

Seaview Energy Inc.

February 14, 2011 23:24 ET

Seaview Energy Inc. Provides an Update on Wapiti Operations Including 1,100 Boe/d Test, and Reports 2010 Year End Reserves

CALGARY, ALBERTA--(Marketwire - Feb. 14, 2011) -

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 operations and information on the Company's oil and natural gas reserves as at December 31, 2010, as evaluated by the Company's independent engineering firm, Sproule Associates Limited ("Sproule").

Highlights

Seaview continues to execute on its exploration program focused on the Wapiti Cardium light oil resource play. The Company has recently participated in the completion of 2 Cardium horizontal wells (1.1 net) in Wapiti successfully expanding the oil resource potential of the Company's Wapiti land base. In addition, Seaview has 3 Cardium horizontal wells (1.9 net) drilled, cased and awaiting completion:

- Seaview's fourth horizontal well 100/12-14-067-09-W6 (73.7% WI) (the "12-14" well) tested an average flow rate of 168 bbl/d of crude plus 675 mcf/d of solution gas (280 boe/d gross, 207 boe/d net) at a flowing tubing pressure of 480 psi during the last 72 hours of a 224 hour test;

- Seaview's fifth horizontal well at 100/14-28-067-08W6 (37% WI in Petroleum;18% WI in natural gas) ("the 14-28 well") tested over a 129 hour period, at an average flow rate of 249 bbl/d of crude plus 2,027 mcf/d of natural gas (587 boe/d gross, 153 boe/d net). Over the final 24 hours of the test, and after recovering 100% of the load fluid, the 14-28 well continued to clean-up and improved to 635 bbl/d of crude oil and 3,020 mcf of natural gas (1,138 boe/d gross, 326 boe/d net) at a flowing casing pressure of 510 psi;

- The 2010 drilling program in Wapiti added Total Proven plus Probable reserves of 3,165 Mboe, including 2,264 Mboe of crude oil and natural gas liquids with Net Present Value (BTAX 10% discount factor) of $41.8 million; and

- Increased Total Proven plus Probable reserves to 11,823 Mboe (26% light oil and natural gas liquids), 22% higher than year-end 2009 reserves after giving effect to the disposition of the southeast Saskatchewan assets.

Wapiti Results and Activity Plans

Seaview's strategy in 2010 focused on accumulating a large, contiguous land position targeting a potential light oil resource play in the Wapiti Cardium fairway. Over the course of 2010, Seaview successfully drilled 7 Cardium horizontal exploration wells (4.3 net) to evaluate the Company's lands. Subsequent to year-end, Seaview has drilled and cased one additional Cardium horizontal well (0.7 net) which is awaiting completion.

Industry activity in Wapiti has increased substantially since Q1-10 following Seaview's initial exploration success at 100/01-09-066-07W6 (The "1-9 well"). As at February 2011, industry has licensed 21 locations targeting the Cardium.

The Company's focus continues to be on the evaluation of the extensive land position in Wapiti through exploration drilling. In addition, Seaview continues to see improved test results with the evolution of the completion style and technology designed to optimize production and ultimate reserves potential of the Company's Wapiti property.

New Wapiti Completions

Seaview's fourth horizontal well at 12-14 (73.7% WI) and fifth horizontal well 14-28 (37% WI in Petroleum;18% WI in natural gas) have been successfully completed using multi-stage frac technology. Both wells have successfully extended the light oil resource potential to the north and west of the known oil accumulation in Wapiti.

The 12-14 well has been drilled and completed establishing crude oil production potential over 6 miles west of the Conventional Wapiti Cardium A pool. The 12-14 well was completed with a total of 320 tonnes of sand placed over 16 intervals. Following an initial clean-up period, the 12-14 well tested at an average flow rate of 168 bbl/d of crude plus 675 mcf/d of solution gas (280 boe/d gross, 207 boe/d net) at a flowing tubing pressure of 480 psi during the last 72 hours of a 224 hour test.

The 14-28 well has been drilled and successfully completed establishing crude oil production potential over 3 miles northwest of the known Wapiti conventional oil pool. The 14-28 was completed using new technology not previously deployed in Wapiti. The 14-28 well was fraced with a total of 150 tonnes of sand placed over 10 intervals. Over a 129 hour test period, the well flowed at an average rate of 249 bbl/d of crude plus 2,027 mcf/d of natural gas (587 boe/d gross, 153 boe/d net). Over the final 24 hours of the test, and after recovering 100% of the load fluid, the 14-28 well continued to clean-up and improved to 635 bbl/d of crude oil and 3,020 mcf of natural gas (1,138 boe/d gross, 326 boe/d net) at a flowing casing pressure of 510 psi.

Construction of surface facilities and pipeline tie-ins are currently underway and both wells are expected to be brought on production before the end of Q1-2011. While encouraged by the significant increase in test rates, Seaview cautions that these rates are preliminary test information only. Both the 14-28 and 12-14 wells are expected to follow similar decline profiles seen in the other wells drilled in the area. Both wells qualify for the Alberta Government's Horizontal Oil New Well Royalty Rate of 5% on initial production volumes. Under this program, the 12-14 qualifies for 24 months or 60,000 barrels of production while 14-28 qualifies for 18 months or 50,000 barrels of production.

Similar to most junior oil and gas operators, Seaview has experienced delays due to timely access to service companies providing hydraulic fracturing. Therefore the timing of future operations will remain a challenge to predict due to a shortage of available fracturing horsepower throughout the industry. Seaview continues to work closely with the service companies to maximize the Company's access to services in as timely a fashion as possible.

Wapiti Production Performance

Seaview's first Cardium horizontal well at 1-9 (68% working interest) was placed on production in August 2010 providing 6 months of production history. After an initial flush production period lasting 2-3 months, the 1-9 well has since stabilized over the past 3 months.

On a producing day basis, the 1-9 well averaged 133 boe/d (91 bbl/d liquids) for the first 90 days on production (August - October 2010). Over the last 90 days (November 2010 - February 2011), the 1-9 production averaged 119 boe/d (76 bbl/d liquids) on a producing day basis. Overall, management is encouraged by the stability of the production profile at 1-9, and believes that the thickness and quality of the Wapiti Cardium will support long-life reserves.

The 1-9 well continues to flow with the assistance of a plunger lift system. Seaview is planning to install a jet pump during February 2011 which is expected to improve production performance by improving wellbore drawdown and increasing operating run-time and efficiency.

Wapiti Exploration Program

Results to date in the Wapiti area continue to validate the Company's strategy of accumulating a large, contiguous position targeting light oil in the Wapiti Cardium fairway. With the recent success at 12-14 and 14-28, Seaview has successfully extended the potential Wapiti Cardium light oil resource fairway south, north and west of the existing Conventional Cardium A pool.

With 8 Cardium horizontal wells (5.0 net) drilled to date, Seaview has made significant progress towards evaluating the resource potential throughout the Company's land base in Wapiti. Management is encouraged by the initial oil rates and remains confident that the Wapiti Cardium light oil resource play offers a sizeable and repeatable opportunity.

Management also expects the economics of the play and initial production rates will continue to improve through the optimization of completion technology during this initial phase of exploration.

Seaview's opportunity base within the prospective Wapiti Cardium light oil resource fairway has the following characteristics:

- Exposure to earn up to 42.5 sections (22.8 net) of prospective Cardium rights;

- An extensive drilling inventory with over 170 horizontal development locations (91 net); and

- Excellent operational focus featuring a large contiguous land position directly offsetting the Company's recent successful Cardium exploration activities.

Seaview believes the Wapiti Cardium light oil resource play contains the essential elements of a profitable resource play including:

- Large areal extent, supported by numerous logs and tests validating the reservoir continuity;

- Contiguous resource potential including an average of 10 m of vertical pay exceeding 6% porosity providing for significant accumulation of light oil, and a high degree of repeatability;

- Ability to improve drilling and completion techniques leading to lower capital costs and higher productivity over time; and

- Scalable project targeting high quality light oil (41 degree API), and natural gas with high liquid recovery NGL's.

HIGHLIGHTS OF 2010

In 2010, Seaview recognized the challenges of weak natural gas prices and focused on transforming the Company's longer term strategic direction towards developing light oil resource exposure through focused exploration drilling. The Company's Peace River Arch assets feature long-life, low operating cost natural gas properties which provide an excellent source of cash flow and strong reserve base to support increased exploration spending.

Triggered by the initial success of the Company's first Wapiti Cardium light oil well at 1-9 in March 2010, management executed on several key strategic initiatives in support of the Company's new light oil resource strategy.

- Successfully closed the disposition of Seaview's assets in Southeast Saskatchewan for $33 million on April 29, 2010.

-- Sold approximately 200 bbl/d of conventional light oil production representing disposition metrics of $165,000 per flowing barrel;

-- Sold 1,332 Mboe on a Total Proven plus Probable basis (based on year-end 2009 reserves as evaluated by Sproule) representing disposition metrics of $24.77/boe;and

-- Reduced corporate debt levels to under $11 million at closing, providing available credit facilities of over $40 million to finance new exploration projects.

- Successfully executed a series of strategic farm-ins and acquisitions to assemble a large, contiguous land position in the emerging Wapiti Cardium light oil resource play.

-- Accumulated 42.5 sections (22.8 net) of prospective lands setting up an extensive drilling inventory with over 170 horizontal development locations (91 net) targeting high quality, high net-back light oil and associated natural gas production;

-- Drilled 8 Cardium horizontal wells (5.0 net) at 100% success rate establishing light oil resource potential over the majority of the Company's lands;

-- Demonstrated improved initial production rates while lowering capital costs through continuous improvement of both drilling and completion practices; and

-- Tested the application of new technologies to maximize the potential of the Wapiti Cardium light oil resource fairway.

- Established light oil resource potential of the Wapiti Cardium play demonstrated by strong reserve additions in 2010.

-- Added Total Proven reserves of 1,450 Mboe, including 1,032 Mbbbls of crude oil and natural gas liquids with Net Present Value (BTAX 10% discount factor) of $22.4 million;

-- Added Total Proven plus Probable reserves of 3,165 Mboe, including 2,264 Mbbls of crude oil and natural gas liquids with Net Present Value (BTAX 10% discount factor) of $41.8 million;

-- Sproule evaluation recognized reserves on 23 Cardium horizontal wells (13.3 net) representing 16% of Seaview's total Wapiti net well locations based on 4 wells per section; and

-- Continued success in developing the Wapiti Cardium light oil play could add significant incremental upside to Seaview's current reserves and net asset value.

- Increased average production for 2010 to 2,907 boe per day, an increase of 25% relative to 2009 average production of 2,321 boe per day. The estimated average production for the fourth quarter of 2010 is 2,641 boe per day;

- Due to operational challenges as a result of adverse weather conditions and delays in accessing fracturing equipment, new production volumes from the 12-14 and 14-28 wells have been delayed until Q1-2011 and therefore will impact Q4-2010 and Q1-2011 production volumes;

- In addition, the completions of the Company's 3 Cardium horizontal wells (1.9 net) may be impacted by the shortage of service capacity. Seaview continues to work closely with the service companies to maximize the Company's access to services in as timely a fashion as possible; and

- Reduced total corporate net debt 54% from $43.9 million at the end of Q1-2010 to estimated 2010 year-end net debt of $20.3 million (excluding impact of hedging contracts). Seaview's credit facility is currently $52 million providing for $32 million of available credit facilities.

Capital Efficiency and Reserve Additions

The independent reserves evaluation in respect of Seaview's assets has been completed by Sproule, with an effective date of December 31, 2010, in accordance with National Instrument 51-101 - Standards for Disclosure for Oil and Gas Activities of the Canadian Securities Administrators ("NI 51-101"). Highlights of the report are summarized below: "NI 51-101"

- Proven Producing reserves of 4,554 Mboe (14% light oil and natural gas liquids);

- Total Proven reserves increased of 6,578 Mboe (23% light oil and natural gas liquids);

- Total Proven plus Probable reserves of 11,823 Mboe (26% light oil and natural gas liquids);

- Probable Developed Producing reserves assigned to Proved Producing assets are 2,444 Mboe, increasing developed Proven plus Probable producing reserves to 6,998 Mboe or 59% 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 6.8 years on a Total Proven basis and 12.3 years on a Total Proven plus Probable basis using December 31, 2010 reserves, and Q4-10 production of 2,641 boe/d;

- Total capital expenditures based on unaudited financial results net of dispositions was negative $(1.6 million); including changes in FDC total capital costs for the purpose of calculating FD&A costs are $19.7 million Total Proven and $35.6 million Total Proven plus Possible basis:

-- Achieved FD&A costs of $45.19/boe Proven and $20.29/boe Proven plus Probable (Including changes in FDC); and

-- Seaview's 2010 capital program replaced production by 0.4 times on a Proven basis and 1.8 times on a Proven plus Probable basis, net of technical revisions.

- Seaview completed an active drilling program in 2010 which included drilling 11 gross wells (7.6 net) with a 91% success rate. Capital expenditures based on unaudited consolidated financial results were $29.1 million directed towards drilling activity. Including changes to FDC, the total capital costs for the purpose of calculating F&D costs are $50.4 million Total Proven and $66.3 million Total Proven plus Probable basis:

-- Achieved F&D costs of $39.59/boe Proven and $23.19/boe Proven plus Probable (including FDC and after revisions);

-- Proven F&D costs in 2010 reflect the high capital expenditures associated with earning commitments on farm-in lands in Wapiti plus the impact of more conservative reserve assignments for early stage resource plays;

-- Seaview's drilling program added 3,246 Mboe of Total Proven plus Probable reserves, including 2,160 Mboe of light crude oil and natural gas liquids; and

-- Reserve additions in Wapiti of 3,165 Mboe of Total Proven plus Probable reserves replaced the light oil reserves sold in the Saskatchewan disposition by 2.4 times.

- Over the past three years, Seaview has added over 13,347 Mboe through its balanced strategy of acquiring, exploiting and exploring for high-quality natural gas and light oil assets in Western Canada. 2010 marks the beginning of a successful transition for the Company towards exploration for light oil resource plays.

-- Three year average Proven F&D costs of $21.23/boe Proven and Proven plus Probable costs of $15.42/boe (including FDC and after revisions); and

-- Three year average Proven FD&A costs of $21.94/boe Proven and Proven plus Probable costs of $15.69/boe (including FDC and after revisions).



----------------------------------------------------------------------------
Historical Capital
Efficiency Highlights 2010 2009
----------------------------------------------------------------------------
Total Total Total Total
Proved Proved Proved Proved
plus plus
Probable Probable
----------------------------------------------------------------------------
Capital Costs ($thousands)
----------------------------------------------------------------------------
Exploration and
development capital $ 29,066 $ 29,066 $16,484 $16,484
----------------------------------------------------------------------------
Acquisitions, net of
dispositions $(30,704) $(30,704) $30,455 $30,455
----------------------------------------------------------------------------
Future development capital,
beginning balance $ 5,646 $ 15,551 $ 5,219 $12,982
----------------------------------------------------------------------------
Future development capital,
end of period balance $ 27,012 $ 52,821 $ 5,646 $15,551
----------------------------------------------------------------------------
Exploration and development
capital including change in
future development capital $ 19,728 $ 35,632 $16,911 $19,053
----------------------------------------------------------------------------
All-in capital including
change in future development
capital $ 50,432 $ 66,336 $47,366 $49,508
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Reserve additions (including
technical revisions)
----------------------------------------------------------------------------
Exploration and development
(Mboe) 1,274 2,860 1,696 2,458
----------------------------------------------------------------------------
Acquisitions, net of
dispositions (Mboe) (837) (1,104) 1,464 2,158
----------------------------------------------------------------------------
Total reserve additions (Mboe) 437 1,756 3,160 4,616
----------------------------------------------------------------------------
Finding and development costs
(F&D), including
change in future development
capital ($/boe)(1) $ 39.59 $ 23.19 $ 9.97 $ 7.75
----------------------------------------------------------------------------
Finding, development and
acquisition costs (FD&A),
including change in future
development capital ($/boe) $ 45.19 $ 20.29 $ 14.99 $ 10.73
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Reserve Replacement
----------------------------------------------------------------------------
Reserve additions, including
revisions (Mboe) 437 1,756 3,160 4,616
----------------------------------------------------------------------------
Annual production (Mboe) 1000 1000 847 847
----------------------------------------------------------------------------
Production replacement ratio 0.4 1.8 3.7 5.4
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Historical Capital Efficiency Highlights 2008 - 2010
----------------------------------------------------------------------------
Total Total
Proved Proved
plus
Probable
----------------------------------------------------------------------------
Capital Costs ($thousands)
----------------------------------------------------------------------------
Exploration and development capital $ 66,457 $ 66,457
----------------------------------------------------------------------------
Acquisitions, net of dispositions $ 91,615 $ 91,615
----------------------------------------------------------------------------
Future development capital, beginning balance $ 843 $ 1,475
----------------------------------------------------------------------------
Future development capital, end of period balance $ 27,012 $ 52,821
----------------------------------------------------------------------------
Exploration and development capital including
change in future development capital $ 92,626 $117,803
----------------------------------------------------------------------------
All-in capital including change in future
development capital $184,241 $209,418
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Reserve additions (including technical revisions)
----------------------------------------------------------------------------
Exploration and development (Mboe) 4,363 7,639
----------------------------------------------------------------------------
Acquisitions, net of dispositions (Mboe) 4,036 5,708
----------------------------------------------------------------------------
Total reserve additions (Mboe) 8,399 13,347
----------------------------------------------------------------------------
Finding and development costs (F&D), including
change in future development capital ($/boe)(1) $ 21.23 $ 15.42
----------------------------------------------------------------------------
Finding, development and acquisition costs (FD&A),
including change in future development capital ($/boe)$ 21.94 $ 15.69
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Reserve Replacement
----------------------------------------------------------------------------
Reserve additions, including revisions (Mboe)
----------------------------------------------------------------------------
Annual production (Mboe)
----------------------------------------------------------------------------
Production replacement ratio
----------------------------------------------------------------------------

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 on or before April 30, 2011 its Annual Information Form which includes Seaview's reserves data and other oil and gas information for the year ended December 31, 2010 as mandated by NI 51-101.

The December 31, 2010, 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, 2010.



Table 1 NI 51-101

Summary of Oil and Gas Reserves as of December 31, 2010
Forecast Prices and Costs

Gross Reserves
--------------------------------
Light
and Natural
Medium Heavy Gas Natural
Crude Crude Liquids Gas
Oil
--------------------------------
Mbbls Mbbls Mbbls Mmcf
--------------------------------
Proved
Developed Producing 460.9 0 176.0 23,500
Developed Non-Producing 94.2 0 32.0 1,650
Undeveloped 580.8 0 177.1 5,189
Total Proved 1,135.9 0 385.1 30,339
Probable 1,187.5 0 410.3 21,887
Total Proved plus Probable 2,323.3 0 795.4 52,226


Net Reserves
--------------------------------
Light
and Natural
Medium Heavy Gas Natural
Crude Crude Liquids Gas
Oil
--------------------------------
Mbbls Mbbls Mbbls Mmcf
--------------------------------
Proved
Developed Producing 394.0 0 114.3 18,953
Developed Non-Producing 80.1 0 21.7 1,401
Undeveloped 501.0 0 127.2 4,292
Total Proved 975.1 0 263.2 24,645
Probable 985.3 0 276.2 17,545
Total Proved plus Probable 1,960.4 0 539.4 42,191


Table 2 NI 51-101

Summary of Net Present Values of Future Net Revenue as of December 31, 2010
Forecast Prices and Costs

Unit Value
Before Income
Before Future Income Tax Expenses Tax Discounted
and Discounted at at
-------------------------------------------------------
0% 5% 10% 15% 20% 10%/yr
-------------------------------------------------------
(M$) (M$) (M$) (M$) (M$) ($/boe)
-------------------------------------------------------
Proved
Developed Producing 106,113 82,299 67,706 57,893 50,850 18.46
Developed Non-
Producing 11,234 8,949 7,472 6,453 5,710 22.29
Undeveloped 43,673 23,821 14,074 8,471 4,901 10.48
Total Proved 161,020 115,070 89,253 72,817 61,462 16.70
Probable 162,387 85,460 53,835 37,273 27,213 12.86
Total Proved plus
Probable 323,407 200,530 143,088 110,090 88,675 15.01


After Future Income Tax Expenses and
Discounted at
----------------------------------------
0% 5% 10% 15% 20%
----------------------------------------
(M$) (M$) (M$) (M$) (M$)
----------------------------------------
Proved
Developed Producing 91,387 71,654 59,526 51,336 45,431
Developed Non-Producing 8,383 6,629 5,495 4,713 4,143
Undeveloped 32,840 17,224 9,467 4,968 2,087
Total Proved 132,609 95,508 74,488 61,016 51,661
Probable 121,736 63,356 39,190 26,459 18,697
Total Proved plus Probable 254,345 158,864 113,678 87,476 70,358


Table 3 NI 51-101

Total Future Net Revenue Undiscounted as of December 31, 2010
Forecast Prices and Costs

Operating Development
Revenue Royalties Costs Costs
------------------------------------------------
(M$) (M$) (M$) (M$)
------------------------------------------------

Total Proved Reserves 323,712 53,748 79,567 27,012
Total Proved plus Probable 641,783 112,702 149,738 52,821

Future Net Future Net
Revenue Revenue
Abandonent Before After
and Other Income Income Income
Costs Taxes Taxes Taxes
------------------------------------------------
(M$) (M$) (M$) (M$)
------------------------------------------------

Total Proved Reserves 2,365 161,020 28,411 132,609
Total Proved plus Probable 3,114 323,407 69,062 254,345



Table 4 NI 51-101

Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2010
Forecast Prices and Costs

Future Net Unit Value
Revenue Before Before Income
Income Taxes 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) 30,924 19.67
Heavy Crude Oil
(including solution gas and associated by-
products) 0 0
Natural Gas
(including associated by-products) 58,329 15.46
Proved plus Probable
Light and Medium Crude Oil
(including solution gas and associated by-
products) 55,347 17.34
Heavy Crude Oil
(including solution gas and associated by-
products) 0 0
Natural Gas
(including associated by-products) 87,741 13.84


Table 5 NI 51-101

Summary of Pricing and Inflation Rate Assumptions
As of December 31, 2010 Forecast Prices and Costs


NATURAL GAS
CRUDE OIL (1)
------------------------------------------------
Edmonton Par
Price Cromer Alberta
Year WTI 40 degrees Medium 29.3 AECO Gas
Crude Oil API degrees API Price
Crude Oil Crude Oil
----------------------------------------------------------------------------
($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl)($Cdn/mmbtu)
------------------------------------------------

Forecast
2011 88.40 93.08 85.63 4.04
2012 89.14 93.85 86.34 4.66
2013 88.77 93.43 85.02 4.99
2014 88.88 93.54 84.18 6.58
2015 90.22 94.95 85.45 6.69

Thereafter Escalation Rates of 1.5%

NATURAL GAS
LIQUIDS
------------------------
Pentanes
Plus Butanes FOB US/CAN
Year FOB Field Field Gate Inflation(2) Exchange
Gate Rate(3)
----------------------------------------------------------------------------
($Cdn/Bbl) ($Cdn/Bbl) (%) ($US/Cdn)
------------------------------------------------

Forecast
2011 95.32 62.44 1.5 0.932
2012 96.11 62.95 1.5 0.932
2013 95.68 62.67 1.5 0.932
2014 95.79 62.75 1.5 0.932
2015 97.24 63.69 1.5 0.932

Thereafter Escalation Rates of 1.5%

Notes:

1. This summary table identifies benchmark reference pricing schedules
that might apply to a reporting issuer
2. Inflation rates for forecasting prices and costs
3. Exchange rates used to generate the benchmark reference prices in this
table


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.

Seaview currently has approximately 1,485 boe/d hedged for 2011, as follows:

-- 8,140 GJ/d of natural gas hedged in put contracts providing for a "net of cost" floor of $4.18/GJ ($4.42/mcf), which is a 25% premium to the current calendar AECO 2011 futures strip of $3.35/GJ, and a 27% premium to the current AECO strip price of $3.28/GJ;

-- 200 bbl/d of crude oil hedged in put contracts for 2011 with a "net of cost" floor of CDN$75.00/bbl; and

-- On a combined basis, Seaview has 8,913 mcfe/d, hedged at a "net of cost" floor price of $5.50/mcfe, which will provide for minimum revenue of $17.9 million for 2011.

OUTLOOK

Management successfully completed several strategic initiatives during 2010 to position the Company for long term sustainability and growth. The combined impacts of significantly reducing debt, high grading operations towards higher net back production and early exploration success in the Wapiti Cardium light oil resource play provides a solid platform for long term growth of reserves, production and cash flow on a per share basis.

The Company's focused long-life, low cost Peace River Arch asset and strong balance sheet provide a stable capital base to support development of the upside potential in the Wapiti Cardium play, and support ongoing exploration projects. Seaview now has the following characteristics:

- Total Proven reserves of 6,578 Mboe (23% light oil and natural gas liquids);

- Total Proven plus Probable reserves of 11,823 Mboe (26% light oil and natural gas liquids), effective December 31, 2010, as evaluated by Sproule Associates Ltd. using National Instrument 51-101 reserve definitions;

- Reserve life index is 12.3 years based on Total Proven plus Probable reserves and Q4 2010 production of 2,641 boe per day;

- Estimated year-end net debt of $20.3 milllion, with approximately $32 million of available credit capacity;

- Seaview has established significant positions in resource plays providing for longer-term growth potential in a diverse portfolio of assets targeting both light oil and natural gas plays, including:

-- In Wapiti, the Company has assembled a sizable land position targeting a Cardium light oil resource play:

--- Exposure to earn up to 42.5 sections (22.8 net) of prospective Cardium rights;

--- An extensive drilling inventory with over 170 horizontal development locations (91 net);

--- Scalable project targeting high quality light oil (41 degree API), and natural gas with high liquid recovery NGL's; and

--- Excellent operational focus featuring a large contiguous land position directly offsetting the Company's recent successful Cardium exploration activities.

-- In Pouce Coupe, the Company holds interests in 21 sections (4.5 net) of land targeting a Doig-Montney natural gas resource play. Seaview's land position is on trend with successful industry development activities further reducing the risk of full development when economics are more viable; and

-- In Harlech, Seaview holds a 25% working interest in 9 contiguous sections (2.25 net) of land targeting multi-zone Cretaceous and Nordegg gas resource potential. The Harlech area offers exposure to liquids rich natural gas reservoirs.

- Commodity hedging program providing for downside protection on 1,485 boe per day for 2011 a "net of cost" floor price of $5.50/mcfe, providing minimum 2011 revenue of $17.9 million; and

- 65.54 million Class A shares and 1.0 million Class B shares outstanding.

RELEASE OF 2010 FINANCIALS AND ANNUAL INFORMATION FORM

Seaview will file its financial results for the year ended December 31, 2010 including the audited consolidated financial statements and related management's discussion and analysis ("MD&A") on or before April 30, 2011. The Annual Information Form which will include Seaview's reserves data and other oil and gas information for the year ended December 31, 2010 as mandated by NI 51-101 will be filed on or before April 30, 2011.

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.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as the term is defined in the Policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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