CALGARY, ALBERTA--(Marketwire - March 5, 2012) - NuVista Energy Ltd. ("NuVista") (TSX:NVA) is pleased to announce results for the three and twelve months ended December 31, 2011 and provide an update on its business plans. NuVista delivered strong fourth quarter operating and financial results despite a weak natural gas price environment. Full year 2011 operating guidance provided in its May 2011 press release was achieved due to excellent drilling results and efficient execution of the capital program. NuVista will continue to prudently manage its business and balance sheet in 2012 while building on recent drilling successes and creating a solid foundation for future growth.

Significant highlights for the fourth quarter of 2011 and year to date 2012 

--  Achieved funds from operations of $48.5 million for the three months
    ended December 31, 2011 compared to $35.6 million for the same period in
    2010 and $41.3 million for the three months ended September 30, 2011, an
    increase of 17%; 

--  Exited 2011 with net debt of $307 million and a trailing 12 month debt
    to funds from operations of 1.9x, a significant improvement compared to
    $443 million and 2.6x at the end of 2010; 

--  Achieved budget targets with an average production rate of 25,306 Boe/d
    for the three months ended December 31, 2011 and 25,556 Boe/d for the
    year ended December 31, 2011; 

--  Significantly increased oil and liquids production as a percentage of
    total production to 33% for the three months ended December 31, 2011
    and 32% for the full year 2011 compared to 28% and 27%, respectively,
    for the same periods in 2010; 

--  Drilled 16 (11.9 net) wells during the fourth quarter and 56 (42.1 net)
    wells for the year ended December 31, 2011. NuVista operated 47 of these
    wells and 50 of the 56 wells were drilled horizontally; 

--  In February 2012, the third of our five well highly liquids-rich Wapiti
    Montney program was completed (100% working interest) in the North block
    of our lands with excellent results. Test rates after cleanup averaged
    9.5 MMcf/d for the final 5 hours of a 30 hour test at 2,233 psi flowing 
    surface pressure. Free condensate production over the 5 hour test period
    averaged 370 Bbls/d. At this rate, we estimate total C2+ production to 
    range between 640 Bbls/d processed through existing shallow cut
    facilities and 975 Bbls/d if processed through deep cut facilities.
    This test rate reinforces our confidence in this play, signifying a
    well which we expect will exceed our economic type curve for this play.
    This well is being tied-in for production startup early in the second
    quarter. As previously announced on December 21, 2011, we drilled and
    completed the second of the five well program in the South Block of our
    lands with strong results. This well is on track for tie-in and
    production startup early in the second quarter of 2012 at an expected
    restricted production rate of 5 MMcf/d and 250 Bbls/d of natural gas
    liquids. This well represents a significant step-out and validation
    point for the South block of our lands; 

--  The fourth of the five well program has now been rig released and is
    awaiting completion. The drilling results have demonstrated remarkable
    progress with pacesetter results for the entire Wapiti Montney trend.
    Drilling days for this well were 44 days compared to a 57 day average
    for all nearby wells, a reduction of 23%. This is a strong early
    demonstration of the cost efficiencies possible as we move towards full
    development on this repeatable play. A new compressor station, which is
    part of the $70 million five well program, is due for startup early in
    the second quarter of 2012 as planned. As a result of continued success
    on the part of NuVista and other industry players, land sale prices and
    industry activity in the area continue to heat up. NuVista owns 164
    gross sections (92% working interest) of land in the Wapiti Montney play
    with the potential for over 400 future drilling locations; 

--  Subsequent to year end, NuVista participated in a second sweet liquids-
    rich Falher horizontal natural gas well (50% working interest) in the
    Wapiti operating area with very strong test results. Maximum test rates
    were 9.5 MMcf/d at 2,500 psi during a 6 hour period at the end of a 59
    hour flow test. Free condensate production over this period averaged 380
    Bbls/d. At this rate, we estimate total C2+ production of 950 Bbls/d
    using deep cut recoveries at the nearby third party plant to which the
    well will be tied into. A third well has also been drilled and recently
    completed (51% working interest) with very successful results to be
    released at a later date. We are reviewing additional Falher locations
    and are currently developing drilling plans to exploit this play further
    in the coming months; 

--  Drilled three highly successful liquids-rich natural gas wells through
    the fourth quarter of 2011 in the W5 Alder Flats operating area with
    detailed results announced previously. All wells have been placed on
    production at very strong rates. Subsequent to year end, the most recent
    well at Alder Flats (75% working interest) has now been completed and is
    also showing excellent results. This well tested at 9 MMcf/d at 2,345
    psi flowing surface pressure over 43 hours. Liquids yields are expected
    to average 25 - 30 Bbls/MMcf or the equivalent of 230 - 280 Bbls/day at
    the test rate. This well has been tied-in and is on production as of
    mid-January at over 9 MMcf/d; 

--  Expanded our proven geographic footprint in our W5 Spirit
    River/Notikewin play, west of the Alder Flats area, with a successful
    horizontal multi-frac test well (100% working interest). NuVista has
    accumulated significant land and access to infrastructure in the area
    and, based on our current interpretation of the play, should provide for
    significant volume growth in the future. Overall, NuVista's momentum
    and positive results continue in W5 with exceptional strength. Combined
    with heritage W5 lands, NuVista now holds 251 gross sections
    (67% working interest) in this play area; and 

--  During 2011, NuVista proceeded with the development of its Zoller Lake
    Birdbear heavy oil play and delivered exceptional economic returns and
    record oil production in the area. Success in the south step-out tests
    from the Hallam Birdbear pool has resulted in development and
    delineation drilling which continues in 2012. 

Non-Core Asset Dispositions

NuVista has made significant progress on its non-core divestiture program with proceeds from dispositions of $5 million in the fourth quarter of 2011 and a total of $14 million, including first quarter 2012 dispositions to date. Most dispositions were undeveloped or minor production lands with total production of only approximately 200 Boe/d and an attractive average sales multiple of $70,000 per flowing Boe/d. This non-core divestiture program will continue as we prudently manage our balance sheet in this low gas price environment and move towards second half 2012 funding catalysts of a larger nature.

2011 Year End Reserves and Finding and Development Costs

2011 year end proved reserves were 69.8 MMBoe compared to 74.0 MMBoe at year end 2010. Proved plus probable year end reserves were 110.1 MMBoe compared to 113.1 MMBoe at year end 2010. The difference is primarily due to economic revisions of -2.7 MMBoe in dry gas production properties based on reduced natural gas price forecasts and -1.7 MMBoe of net divestitures, on a proved plus probable basis. Significant momentum is building in NuVista's W6 Montney and W5 Spirit River/Notikewin plays which are expected to result in material increases to proved and proved plus probable reserves bookings, however, year end cut-off phasing has pushed much of this benefit to 2012. In the Wapiti Montney alone, NuVista has only five proved drilling locations and eight probable drilling locations booked to date while resource estimates and well results continue to indicate the potential for over 400 future horizontal locations.

Net Loss for the Year Ended December 31, 2011 - Impairment in Value of Oil and Gas Properties

In the fourth quarter of 2011, NuVista recognized an impairment to the financial statement value of Property, Plant and Equipment and Goodwill in the amounts of $147.7 million and $25.8 million, respectively. These impairments relate to the reduction in the fair value of four natural gas Cash Generating Units in northern and eastern Alberta and in Saskatchewan due to a continuing forecast for lower natural gas prices compared to the forecast at December 31, 2010. The impairments are described in more detail in NuVista's audited financial statements and management's discussion and analysis for the year ended December 31, 2011, available through NuVista's filings on SEDAR at

2011 Summary and 2012 Guidance

In 2011, NuVista continued its successful transition towards a business model of internal generation of large resource plays with repeatable liquids-rich natural gas and crude oil opportunities and away from an acquire and develop model. NuVista's first priority in 2011 was reducing its debt levels and this occurred in the first quarter with a $99.8 million equity offering and the disposition of $37.2 million of Pembina Cardium assets. Following the reduction of its debt, NuVista targeted capital spending approximately equal to funds from operations. With funds from operations reduced due to lower natural gas prices, NuVista prudently managed capital and maintained production volumes at second quarter levels for the remainder of the year. The focus of NuVista's 2011 capital program was on drilling a balance of high return oil wells, combined with drilling strategic wells in its two liquids-rich natural gas plays to advance the significant inventory of repeatable multi-frac horizontal drilling locations.

In May 2011, Jonathan Wright joined NuVista as President and Chief Executive Officer. Mr. Wright has a proven track record of successful leadership at a larger oil and gas producer, both domestically and internationally. Mr. Wright brought a business philosophy to NuVista that ensures focus on a limited number of repeatable plays, improving drilling and completion execution, and a disciplined approach to managing all aspects of the business. Based on a review of NuVista's assets, a decision was made to focus on the following three key plays:

--  W3/W4 heavy oil with the company's best economic returns and a 1-2 year
    inventory of prospects; 
--  W5 Pembina/Ferrier liquids-rich natural gas in the Spirit River and
    Notikewin formations with the potential to develop into a repeatable
    play with over 75 locations representing economic investment of over
    $350MM; and 
--  W6 Wapiti Montney liquids-rich natural gas resource play with the
    potential for a repeatable inventory of over 400 drilling locations and
    several billion dollars of economic investment. 

With breakeven gas prices of $2.00 - $3.00/Mcf, the above two liquids-rich natural gas plays are highly competitive.

Also, as part of this review of assets, certain assets were identified as non-strategic with the potential to be rationalized at the appropriate time for the purpose of redeploying the capital in NuVista's three key plays.

In early 2012, we have seen natural gas prices continue to decline due to a warm winter and an oversupply of natural gas in North America. With the outlook for continued low natural gas prices over the near term, NuVista is carefully evaluating its business to preserve value and ensure a sustainable model without jeopardizing its financial flexibility and its advancement of long term growth opportunities in the W5 Spirit River/Notikewin and W6 Wapiti Montney plays. NuVista expects to limit 2012 capital spending to funds from operations and proceeds from non-core divestitures, however second half 2012 spending levels will be determined at the end of the second quarter of 2012 after reviewing the results of our Montney program and divestiture proceeds. As of the date of this press release, NuVista has disposed of non-core Pembina Cardium and other assets for approximately $14 million since December 2011 so this process is well advanced. NuVista will be pursuing additional non-core dispositions of assets throughout 2012 where retention values can be realized, creating additional financial flexibility to fund the areas of key focus for the company. NuVista will remain flexible to accelerate spending in areas where recent success has been realized subject to some of the various funding catalysts being contemplated.

For now, NuVista's operating and financial guidance for the first half of 2012 remains unchanged with a capital budget of between $70 million and $80 million and average production within the previous guidance range of 24,500 Boe/d to 25,500 Boe/d. Given the tremendous drilling results experienced over the past several months, NuVista expects that this range of production can be achieved. Funds from operations for the first half of 2012 are forecast at between $45 million and $50 million based on a forecast AECO natural gas price of $2.40/Mcf and WTI oil price of US$103/Bbl. The capital budget is planned to modestly exceed funds from operations in the first half of 2012 due to the busy winter drilling season however, as mentioned earlier, proceeds of asset dispositions are expected to make up any cash flow shortfall with $14 million already achieved to date.

Despite the weak natural gas price environment, NuVista is confident that its disciplined deployment of capital on its material key plays, while maintaining a prudent focus on the balance sheet, will result in shareholder value creation over the long term. With a talented and motivated workforce and a revised business strategy focused on discipline, execution and profitability, we look forward to updating you on the progress in this value creation process as we move through 2012.

Corporate Highlights                                                        

                                   Three months ended            Year ended 
                                          December 31,          December 31,
                                       2011      2010       2011       2010 
($ thousands, except per share)                                             
Oil and natural gas revenue          96,578    89,552    369,234    373,327 
Funds from operations(1)             48,467    35,618    164,019    169,991 
  Per basic share                      0.49      0.40       1.68       1.92 
  Per diluted share                    0.49      0.40       1.68       1.92 
Net earnings (loss)                (158,462)  (20,965)  (143,800)   (59,655)
  Per basic share                     (1.59)    (0.24)     (1.47)     (0.67)
  Per diluted share                   (1.59)    (0.24)     (1.47)     (0.67)
Adjusted net earnings (loss) (1)    (19,965)    2,431    (33,366)   (22,931)
Per basic share                       (0.20)     0.03      (0.34)     (0.26)
Per diluted share                     (0.20)     0.03      (0.34)     (0.26)
Total assets                                           1,373,705  1,533,824 
Long-term debt, net of adjusted                                             
 working capital(1)                                      306,791    443,043 
Capital expenditures                 57,784    28,535    161,830    225,050 
Dispositions                          5,250         -     42,444          - 
Weighted average common shares                                              
 outstanding (thousands):                                                   
  Basic                              99,513    88,719     97,557     88,583 
  Diluted                            99,513    88,719     97,557     88,583 
  Natural gas (MMcf/d)                101.3     121.2      104.3      123.9 
  Natural gas liquids (Bbls/d)        2,912     3,024      2,974      3,053 
  Oil (Bbls/d)                        5,506     4,935      5,206      4,647 
    Total oil equivalent (Boe/d)     25,306    28,165     25,556     28,343 
Average product prices(2)                                                   
  Natural gas ($/Mcf)                  3.63      3.85       3.87       4.49 
  Natural gas liquids ($/Bbl)         68.82     52.76      64.31      51.48 
  Oil ($/Bbl)                         80.92     64.38      74.42      63.66 
Operating expenses                                                          
  Natural gas and natural gas                                               
   liquids ($/Mcfe)                    1.69      1.37       1.70       1.22 
  Oil ($/Bbl)                         14.41     18.78      14.63      18.26 
    Total oil equivalent ($/Boe)      11.06     10.09      11.12       9.11 
Operating netback ($/Boe)             24.88     17.82      21.56      20.10 
Funds from operations netback                                               
 ($/Boe)(1)                           20.81     13.75      17.58      16.44 


1.  Funds from operations, funds from operations per share, funds from
    operations netback, operating netback, adjusted net earnings and
    adjusted working capital are not defined by GAAP in Canada and are
    referred to as non-GAAP measures. Funds from operations are based on
    cash flow from operating activities as per the statement of cash flows
    before changes in non-cash working capital and asset retirement
    expenditures. Funds from operations per share is calculated based on the
    weighted average number of common shares outstanding consistent with the
    calculation of net earnings (loss) per share. Funds from operations
    netback equals the total of revenues including realized commodity
    derivative gains/losses less royalties, transportation, operating,
    general and administrative, restricted stock units, interest expenses
    and cash taxes calculated on a Boe basis. Adjusted net earnings equals
    net earnings excluding after tax unrealized gains (losses) on commodity
    derivatives, impairments and gains (losses) on property divestments.
    Operating netback equals the total of revenues including realized
    commodity derivative gains/losses less royalties, transportation and
    operating expenses calculated on a Boe basis. Adjusted working capital
    excludes the current portions of the commodity derivative asset or
    liability. Total Boe is calculated by multiplying the daily production
    by the number of days in the period. For more details on non-GAAP
    measures, refer to NuVista's "Management's Discussion and Analysis". 
2.  Product prices include realized gains/losses on commodity derivatives. 

Supplemental 2011 Year End Reserves Data

Our 2011 independent engineering evaluation has been completed by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2011 (the "GLJ Report").

Unless otherwise indicated, the reserves information set forth in this press release are "company interest" reserves. "Company interest" means, in relation to NuVista's interest in reserves, its working interest (operating or non-operating) share before deduction of royalties, plus NuVista's royalty interests in production or reserves. Investors are cautioned that "company interest" reserves should not be construed as an alternative to "gross" or "net" reserves calculated in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and does not have a standardized meaning under NI 51-101.

Overall finding and development costs, including revisions and future development capital, were $30.29/Boe for proved reserves and $27.89/Boe for proved plus probable reserves. Excluding revisions, the proved plus probable finding and development costs including future development capital was $20.37/Boe. This resulted in a corporate proved plus probable operating netback recycle ratio of 0.8x or 1.1x excluding revisions. One-time factors affecting these results include the phasing and economic revisions noted above and our corporate netback having a natural gas weighting while our new capital program focuses on oil and liquids-rich natural gas. 2011 play specific recycle ratios for all three key plays range from 1.8x to 2.4x despite the challenging natural gas price environment, illustrating our confidence in their finding and development costs and recycle ratio strength as we move through 2012 and beyond.

The following table outlines NuVista's finding, development and acquisition costs in more detail:

                       3 Year-Average                                       
                                (1)(2)       2011 (1) (2)       2010 (1) (2)
                               Proved             Proved             Proved 
                                 plus               plus               plus 
                     Proved  probable   Proved  probable   Proved  probable 
After reserve                                                               
 revisions and                                                              
 including changes                                                          
 in future                                                                  
 capital ($/Boe)                                                            
   development and                                                          
   cost(3)            18.43     16.27    27.80     28.79    22.04     18.44 
  Finding and                                                               
   costs              22.84     20.51    30.29     27.89    22.60     19.00 
   costs              11.79      9.52   (43.01)   (24.53)   15.10     10.66 

1.  The aggregate of the exploration and development costs incurred in the
    most recent financial year and the change during the year in estimated
    future development costs generally will not reflect total finding and
    development costs related to reserve additions for the year. 
2.  Drilling credits of $1.3 million were recorded during 2011 and $17.6
    million were recorded in 2010. 
3.  Finding, development and acquisition costs have been included in
    addition to finding and development costs, future acquisition costs can
    have a significant impact on reserves replacement costs. 

The following table summarizes the future development capital included in   
the GLJ Report:                                                             

 ($ thousands, undiscounted)                                    Proved plus 
                                                      Proved       probable 
Balance, December 31, 2010                           228,687        410,555 
  Exploration and development changes in the                                
   year                                               22,838         63,088 
Balance, December 31, 2011                           251,525        473,643 

The following table provides summary reserve information based upon the GLJ 
Report using the published GLJ January 1, 2012 price forecast set forth     

                                            Natural gas             Liquids 
                                      Company             Company           
                                     interest       Net  Interest       Net 
Reserves category (1)                   (MMcf)    (MMcf)   (MBbls)   (MBbls)
  Developed producing                 211,627   186,627     5,914     4,290 
  Developed non-producing              34,276    30,238     1,280       996 
  Undeveloped                          52,202    48,196     1,904     1,538 
Total proved                          298,104   265,062     9,097     6,823 
Probable                              173,910   155,490     5,886     4,371 
Total proved plus probable            472,014   420,552    14,983    11,194 

                                                    Oil               Total 
                                      Company             Company           
                                     Interest       Net  Interest       Net 
Reserves category (1)                  (MBbls)   (MBbls)    (Mboe)    (Mboe)
  Developed producing                   7,754     6,811    48,939    42,205 
  Developed non-producing                 431       351     7,423     6,387 
  Undeveloped                           2,813     2,494    13,417    12,065 
Total proved                           10,997     9,657    69,779    60,657 
Probable                                5,435     4,547    40,306    34,834 
Total proved plus probable             16,432    14,204   110,085    95,491 

1.  Numbers may not add due to rounding. 

The following table is a summary reconciliation of the 2011 year end        
reserves with the reserves reported in the 2010 year end reserves report:   

                                 Natural                          Total oil 
                                   gas(1) Liquids(1)    Oil(1) equivalent(1)
                                    (Bcf)    (MBbls)   (MBbls)        (MBoe)
Total proved                                                                
  Balance, December 31, 2010       319.0      8,758    12,077        73,989 
    Exploration and development     25.4      1,329     1,449         7,014 
    Technical revisions              8.2        469         2         1,843 
    Economic revisions             (15.0)      (243)        3        (2,739)
    Acquisitions                    10.9         29       155         1,999 
    Dispositions                   (12.3)      (159)     (789)       (2,999)
    Production                     (38.1)    (1,086)   (1,900)       (9,328)
  Balance, December 31, 2011       298.1      9,097    10,997        69,779 
Total proved plus probable                                                  
  Balance, December 31, 2010       488.9     13,986    17,602       113,073 
    Exploration and development     40.1      2,272     2,034        10,995 
    Technical revisions             (0.6)       227      (365)         (250)
    Economic revisions             (14.7)      (248)      (13)       (2,713)
    Acquisitions                    15.2         35       230         2,795 
    Dispositions                   (18.8)      (203)   (1,156)       (4,487)
    Production                     (38.1)    (1,086)   (1,900)       (9,328)
  Balance, December 31, 2011       472.0     14,983    16,432       110,085 

1.  Numbers may not add due to rounding. 

The estimated net present values of future net revenue before income taxes associated with NuVista's reserves effective December 31, 2011 and based on published GLJ future price forecast are summarized in the following table.

The estimated future net revenue contained in the following table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ 2011 Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.

                                            Discount factor (%/year)        
Reserves category (1)(2) ($                                                 
 millions)                                  0%        5%       10%       15%
  Developed producing                   1,116       868       714       609 
  Developed non-producing                 166       109        81        64 
  Undeveloped                             265       163       106        72 
Total proved                            1,547     1,140       901       745 
Probable                                1,054       592       383       269 
Total proved plus probable              2,601     1,732     1,284     1,014 

1.  Numbers may not add due to rounding. 
2.  Estimate future net reserves do not represent the fair market value of

The following table is a summary of pricing and inflation rate assumptions  
based on published GLJ forecast prices and costs as at January 1, 2012:     

                           Gas           Liquids                 Oil        
                         AECO Gas                             WTI Par Price 
                            Price   Edmonton   Edmonton   Cushing    40 API 
                           ($Cdn/    Propane     Butane  Oklahoma    ($Cdn/ 
Year                        MMbtu) ($Cdn/Bbl) ($Cdn/Bbl) ($US/Bbl)      Bbl)
  2012                       3.49      58.78      76.41     97.00     97.96 
  2013                       4.13      60.61      78.80    100.00    101.02 
  2014                       4.59      60.61      78.80    100.00    101.02 
  2015                       5.05      60.61      78.80    100.00    101.02 
  2016                       5.51      60.61      78.80    100.00    101.02 
  2017                       5.97      60.61      78.80    100.00    101.02 
  2018                       6.21      61.44      79.87    101.35    102.40 
  2019                       6.33      62.68      81.49    103.38    104.47 
  2020                       6.46      63.95      83.13    105.45    106.58 
  2021                       6.58      65.24      84.81    107.56    108.73 
  2022                     +2%/yr     +2%/yr     +2%/yr    +2%/yr    +2%/yr 

                                    Hardisty   Cromer                       
                                       Heavy   Medium                       
                                      12 API   29 API  Inflation   Exchange 
                                      ($Cdn/   ($Cdn/      Rates   Rate(2)  
Year                                     Bbl)     Bbl) %/ Year(1) ($US/$Cdn)
  2012                                 72.37    90.12        2.0       0.98 
  2013                                 73.60    92.94        2.0       0.98 
  2014                                 74.51    91.93        2.0       0.98 
  2015                                 74.51    91.93        2.0       0.98 
  2016                                 74.51    91.93        2.0       0.98 
  2017                                 74.51    91.93        2.0       0.98 
  2018                                 75.54    93.18        2.0       0.98 
  2019                                 77.09    95.07        2.0       0.98 
  2020                                 78.67    96.99        2.0       0.98 
  2021                                 80.28    98.85        2.0       0.98 
  2022                                +2%/yr   +2%/yr        2.0       0.98 

1.  Inflation rate for costs. 
2.  Exchange rate used to generate the benchmark reference prices in this

Net Asset Value Per Share, as at December 31, 2011                          

($ thousands)                                                          2011 
Net present value of oil and gas reserves, discounted at 10%,               
 before tax (1)(2)                                               $1,284,023 
Undeveloped land (3)                                                120,414 
Cash, accounts receivable and prepaids                               50,350 
Accounts payable and accrued liabilities                            (67,710)
Long-term debt                                                     (289,431)
Net asset value                                                 $ 1,097,646 
Shares outstanding (000's)                                           99,513 
Net asset value ($/share)                                           $ 11.03 

1.  Proved plus probable company interest reserves, as at December 31, 2011,
    as evaluated by GLJ Petroleum Consultants Ltd. 
2.  Estimated future net reserves do not represent the fair market value of
3.  Undeveloped land value is recorded at the carrying value. 

In addition to the reserves information disclosed in this press release, more detailed reserves information will be included in NuVista's Annual Information Form in addition to the full NI 51-101 disclosure for the year ended December 31, 2011, which is expected to be filed on SEDAR on or before March 30, 2012.


December 31, 2011 audited consolidated financial statements and notes to the consolidated financial statements and Management's Discussion and Analysis for NuVista Energy Ltd. have been filed on SEDAR ( under NuVista Energy Ltd. and can also be accessed on NuVista's website at


This news release contains the terms barrels of oil equivalent ("Boe") and thousand cubic feet equivalent ("Mcfe"). Natural gas is converted to a Boe using six thousand cubic feet of gas to one barrel of oil. In certain circumstances natural gas liquid volumes have been converted to a Mcfe on the basis of one barrel of natural gas liquids to six thousand cubic feet of gas. Boes and Mcfes may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.


This press release contains forward-looking statements and forward-looking information (collectively, "forward-looking statements") within the meaning of applicable securities laws. The use of any of the words "will", "expects", "believe", "plans", "potential" and similar expressions are intended to identify forward-looking statements. More particularly and without limitation, this press release contains forward looking statements, including management's assessment of: NuVista's future strategy, plans, opportunities and operations; forecast production; production mix; drilling, development, completion and tie-in plans and results; NuVista's planned capital budget; targeted debt level; the timing, allocation and efficiency of NuVista's capital program and the results therefrom; plans regarding facility construction and/or expansions, the timing thereof and the results therefrom; the anticipated potential of NuVista's asset base; forecast funds from operations; the source of funding of capital expenditures; the objectives and focus of NuVista's capital program and the allocation thereof and results therefrom; NuVista's risk management strategy; expectations regarding future commodity prices and netbacks; and industry conditions. By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, current and future commodity prices, currency and interest rates, anticipated production rates, borrowing, operating and other costs and funds from operations, the timing, allocation and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, the performance of existing wells, the success obtained in drilling new wells, the sufficiency of budgeted capital expenditures in carrying out planned activities, competition from other industry participants, availability of qualified personnel or services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties; the ability to access sufficient capital from internal sources and bank and equity markets; and including, without limitation, those risks considered under "Risk Factors" in our Annual Information Form.

Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. NuVista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Contact Information:

NuVista Energy Ltd.
Jonathan A. Wright
President and CEO
(403) 538-8501

NuVista Energy Ltd.
Robert F. Froese
VP, Finance and CFO
(403) 538-8530