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NuVista Energy Ltd. Announces Fourth Quarter and Year End 2013 Results

CALGARY, ALBERTA -- (Marketwired) -- 03/06/14 -- NuVista Energy Ltd. ("NuVista") (TSX: NVA) is pleased to announce results for the three and twelve months ended December 31, 2013 and provide an update on its future business plans. 2013 was a turning point year for NuVista, and one where all of our key business and strategic targets were met or exceeded. We have:

--  Transitioned the Bilbo (South) and Elmworth (North) sub-blocks of our
    Wapiti Montney play from delineation phase to full repeatable
--  Continued our successful delineation and land expiry management program
    in the Wapiti area;
--  Continued our rolling annual non-core divestiture program towards ever-
    enhanced focus;
--  Significantly increased natural gas and natural gas liquids reserves and
    contingent resources;
--  Substantially increased condensate yields in the Wapiti Montney play;
--  Reduced well costs and cycle times, using advanced technology to improve
    our drilling and completion execution;
--  Created a clearer than ever line-of-sight to increasing our Wapiti
    Montney typecurves and future growth initiatives; and
--  Improved corporate netbacks and prudently managed our balance sheet.

All of the above has placed NuVista in a position where our growth outlook and financial strength have never been brighter. Although we expect stronger gas pricing to prevail, we have now positioned the company to provide strong long-term profitable growth in a $3.00 to $3.50/GJ AECO natural gas price environment due to our significant and high value condensate production. The fiscal environment has improved significantly due to the recent gas price increase in late 2013 and early 2014. There is a high probability this strength will continue throughout 2014 due to very low gas storage levels in North America, driven by the cold winter experienced in most regions. As a result of the recent price strength, we have increased our hedge positions to ensure a strong baseline price underpinning our capital plans and economic threshold. Beyond 2014, we expect natural gas prices to moderate but retain a higher base compared to the environment of 2012 and 2013. In this environment NuVista is in an excellent position to grow and thrive.

As we kick off 2014, our key strategies are centered upon rapid profitable Wapiti Montney development, continued delineation drilling, the completion and startup of our South Bilbo block compressor station and the new Keyera Pipeline to the Simonette Plant late in the second quarter of 2014. We will continue to enhance our focus through our non-core asset divestiture program and improve profitability as our higher netback Montney production increases. We are very pleased to reach yet another turning point for the company - where increasing cash flow and profitability provides the ability to grow on a self-funding basis in a $3.00 to $3.50/GJ AECO gas price environment, with any dependency on outside funding being merely related to the optionality of choosing an accelerated pace of growth.

Significant highlights for the fourth quarter and full year of 2013 include:

--  Continued to reach IP30's on additional Montney wells since our last
    announcement on February 6, 2014 including another Bilbo (South) block
    test with excellent results as shown below. Well 17, a new record high
    result, is at the far Southwestern end of the Bilbo block resulting in
    strong encouragement as our two strongest Bilbo wells bracket the
    Northeast and Southwest edges of the block:

                          New Well IP30 Results(i)
Well                    Raw Gas     Condensate    Total Sales        C5+/Raw
                       (MMcf/d)       (Bbls/d)        (Boe/d)    (Bbls/MMcf)
Bilbo (South
 Blk) Typecurve             5.8            435          1,361             75
Well 17                     8.0            800          2,184            100

North Block
 Typecurve                  5.8            261          1,222             45
Well 18(ii)                 5.9            217          1,201             37
(i) Well numbering refers to the numbered wells in our corporate
presentation available on our website. They are effectively in chronological
order since our inception in the play. All numbers shown are based on field
estimate data.
(ii) This is an IP30 projection based on 21 days of production thus far.

--  Increased our Elmworth (North) block typecurve assumptions from an
    ultimate recovery of 4.4 Bcf/well to 6.0 Bcf/well;
--  Achieved the higher end of our annual guidance range. For the fourth
    quarter of 2013, NuVista's average production was 18,034 Boe/d compared
    to average production of 17,692 Boe/d for the fourth quarter of 2012 and
    18,532 Boe/d for the third quarter of 2013. The increase in production
    from the fourth quarter of 2012 is due to strong performance of new and
    existing Wapiti Montney wells offset by the sale of production as a
    result of 2012 and 2013 non-core dispositions;
--  Achieved funds from operations of $21.5 million ($0.17/share, basic) for
    the three months ended December 31, 2013, a 32% increase from $16.3
    million ($0.15/share, basic) for the three months ended December 31,
    2012 due to stronger pricing and an increased contribution of higher
    netback Wapiti Montney volumes. For the year ended December 31, 2013,
    NuVista's funds from operations were $75.3 million ($0.63/share, basic),
    a slight decrease from $75.7 million ($0.75/share, basic) in the same
    period of 2012 due to lower oil prices and divestitures offset by higher
    natural gas prices;
--  Achieved corporate netbacks for the twelvemonths ended December 31, 2013
    of $12.99/Boe and $11.91/Boe for the three months ended December 31,
    2013. Netbacks are expected to continue rising as the higher netback
    Wapiti Montney production increasingly dominates our corporate
--  Successfully executed an annual capital program of $224 million. Drilled
    16 wells (15.6 net) in our Montney condensate rich resource play for
    100% success rate while initiating spending on our Bilbo block
    compressor station and trunk lines;
--  Entered into significant firm processing contracts, strategically
    providing our Wapiti Montney play with space to grow to at least 2016,
    with reduced operating cost and guaranteed downstream liquids
    fractionation access;
--  Increased proved plus probable reserves ("2P") by 48% versus 2012, to
    129 MMBoe (up 64% excluding the effect of divested volumes) thereby
    increasing our proved plus probable reserves life index from 14.6 to
    22.2 years. Organic 2P reserves additions replaced 950% of production in
    the year;
--  Increased Montney 2P operating recycle ratio to 2.3x with full year
    Montney operating netbacks of $27.88/Boe and Montney 2P finding and
    development costs ("F&D") of $12.05/Boe;
--  Continued our trend of efficiency improvements, with average well
    drilling and completion costs, as well as well cycle times falling
--  Ensured our capital programs are funded through until at least 2015 or
    longer depending on the pace of capital spending, through a combination
    of rolling divestitures, improved cash flows, and equity issued in 2013;
--  Completed the disposition of certain gross overriding royalty volumes,
    undeveloped land, and non-core assets producing 1,800 Boe/d in our W3/W4
    operating areas for gross proceeds of $43.4 million; and
--  Exited 2013 with no bank debt. Net debt, including the working capital
    deficiency was $48 million and net debt to annualized fourth quarter
    funds from operations was 0.6x.

As noted above, on the strength of Elmworth (North) block out performance from wells drilled in 2011 to 2013 and even stronger IP30 production results from our recently drilled Elmworth block wells and nearby industry wells, we have increased our internal typecurve assumptions to 6 Bcf/well ultimate recovery compared to our original typecurve assumption of 4.4 Bcf/well. The condensate yield for this area remains unchanged at 45 Bbls/MMcf but the higher overall production results in very strong economics. This recovery applies to the Elmworth block only until more proof points are established on other blocks, and it corresponds to initial IP30 rates of 7.4 MMcf/d compared to our original typecurve assumption of 5.8 MMcf/d. We are very pleased to now have demonstrated proof of this trend which we believe is the natural evolution of a repeatable resource play where drilling and completions techniques can be optimized over time.

Corporate Highlights
                                     Three months ended     Year ended
                                        December 31,        December 31,
($ thousands, except per share)          2013      2012      2013      2012
Oil and natural gas revenue            57,143    48,277   213,469   242,012
Funds from operations(1)               21,533    16,278    75,306    75,672
  Per basic share                        0.17      0.15      0.63      0.75
  Per diluted share                      0.17      0.15      0.63      0.75
Net earnings (loss)                   (47,405)  (59,042)  (61,144) (195,200)
  Per basic share                       (0.38)    (0.56)    (0.51)    (1.93)
  Per diluted share                     (0.38)    (0.56)    (0.51)    (1.93)
Adjusted net earnings (loss)(1)        (4,245)  (10,920)  (20,133)  (52,462)
  Per basic share                       (0.03)    (0.10)    (0.17)    (0.52)
  Per diluted share                     (0.03)    (0.10)    (0.17)    (0.52)
Total assets                                              905,711   878,174
Long-term debt, net of adjusted
 working capital(1)                                        47,495    30,388
Capital expenditures                   80,011    29,194   226,572   116,638
Dispositions                           17,878   204,771    30,270   237,821
Weighted average common shares
 outstanding (thousands):
  Basic                               125,411   106,006   120,430   101,148
  Diluted                             125,411   106,006   120,430   101,148
  Natural gas (MMcf/d)                   73.9      74.9      71.8      95.0
  Condensate (Bbls/d)                   2,500       954     1,925     1,245
  Butane (Bbls/d)                         482       527       458       534
  Propane (Bbls/d)                        712       712       710       722
  Ethane (Bbls/d)                         744       746       801       700
  Oil (Bbls/d)                          1,280     2,278     1,478     3,542
    Total oil equivalent (Boe/d)       18,034    17,692    17,329    22,577
Average product prices(2)
  Natural gas ($/Mcf)                    3.40      2.79      3.28      2.35
  Condensate ($/Bbl)                    85.26    115.01     93.27     97.46
  Butane ($/Bbl)                        58.34     63.11     58.62     67.29
  Propane ($/Bbl)                       40.51     25.75     28.16     26.99
  Ethane ($/Bbl)                        10.91      4.30      9.42      7.60
  Oil ($/Bbl)                           71.46     66.35     78.48     72.11
Operating expenses
  Natural gas and natural gas
   liquids ($/Mcfe)                      1.67      1.78      1.78      1.87
  Oil ($/Bbl)                           26.31     15.53     22.65     11.00
    Total oil equivalent ($/Boe)        11.16     11.29     11.70     11.17
Operating netback ($/Boe)               17.99     14.82     16.54     13.36
Funds from operations netback
 ($/Boe)(1)                             12.99     10.00     11.91      9.16

(1) Funds from operations, revenue, funds from operations per share, funds
from operations netback, operating netback, adjusted net earnings, adjusted
net earnings per share 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, impairment reversals, goodwill 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, including reconciliation to GAAP measures refer to NuVista's
"Management's Discussion and Analysis".
(2) Product prices exclude realized gains/losses on commodity derivatives.

2014 Guidance

2014 is the year where NuVista will enter full development mode in the Wapiti Montney resource play. We have increased our capital budget in 2014 compared to 2013, to the range of $240 million to $260 million with a commensurate increase in rig count to three rigs for most of the year. The capital will be focused approximately 90% in the Wapiti area, with approximately 80% of that in the condensate rich Bilbo development block. We expect to drill and complete 16 to 18 horizontal wells in the year, complete and start up the Bilbo compressor station, and begin delivering to the Keyera Simonette plant late in the second quarter of 2014. This new infrastructure will provide the capacity for significant growth over the next few years.

Our entrance production rate in 2014 after the previously announced December divestitures was approximately 16,500 Boe/d. Production for 2014 is expected to be in the range of 17,500 to 18,500 Boe/d. Behind pipe capacity is continuing to build in order to accommodate the ramp in infrastructure capacity later in the year, with fourth quarter production expected in the range of 20,000 to 21,000 Boe/d. Cash flows for 2014 are expected in the range of $130 million to $140 million based on current strip prices of $4.50/GJ AECO for natural gas and US$98/Bbl for WTI.

Looking beyond 2014, we are excited about our ability to drive and internally fund significant growth with an increased pace of drilling and significant facility capacity. For 2015, we anticipate annual production of approximately 23,000 Boe/d which, at $3.50/GJ AECO gas and US$85/Bbl WTI oil prices, would drive cash flow to approximately $170 million.

With corporate netbacks and production rising quickly, and efficiencies continuing to be built into every aspect of our Wapiti Montney play, NuVista is confident to continue accelerating the pace of activity in the future. We will continue to work with area midstreamers to provide an ever-increasing facility capacity to underpin long-term profitable growth. We would like to thank our shareholders for their continued support, and our exceptionally dedicated and talented staff for their significant contributions to the bright future we are delivering together.

Please refer to the corporate presentation on our website which will be updated on or before the end of March 10, 2014 to include further details and context regarding the information in this press release.


December 31, 2013 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 (www.sedar.com) under NuVista Energy Ltd. and can also be accessed on NuVista's website at www.nuvistaenergy.com.


This news release contains the terms barrels of oil equivalent ("Boe"), millions of barrels of oil equivalent ("MMBoe") and thousand cubic feet equivalent ("Mcfe") and trillion cubic feet equivalent ("Tcfe"). 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, MMBoes, Mcfes and Tcfes 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. As well, given than the value ratio based on the current price of crude oil to natural gas is significantly different from the 6:1 energy equivalency ratio, using a conversion ratio on a 6:1 basis may be misleading as an indication of value.

Any references in this news release to initial or test production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for NuVista.


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, growth initiatives and operations; the expectations of creating significant shareholder value from NuVista's properties and opportunities; our ability to internally fund these opportunities and initiatives; forecast production; production mix; drilling, development, completion and tie-in plans and results; plans to reduce drilling times and costs and to optimize completions; plans relating to future access to processing facilities, transportation and markets; expectations of future results, including future production levels, typecurves, well economics, and operating costs, future disposition plans, targeted debt level; the amount, timing, allocation and efficiency of NuVista's capital program and the results therefrom; plans and expectations regarding facility construction and infrastructure development, the timing thereof and the benefits to be obtained therefrom; the anticipated potential of NuVista's asset base including expectations regarding repeatable development and improved drilling and completion techniques; forecast cash flow; the source of funding of NuVista's capital program; and plans to internally fund future growth and acceleration of our future opportunities;

NuVista's risk management strategy; expectations regarding future commodity prices and netbacks; industry conditions and the timing of release of future results. 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, access to infrastructure and markets, 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 has included the forward-looking statements in this press release in order to provide readers with a more complete perspective on NuVista's future operations and such information may not be appropriate for other purposes. 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.

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

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