NuVista Energy Ltd. Announces Second Quarter 2013 Results

NuVista Energy Ltd. Announces Second Quarter 2013 Results 
CALGARY, ALBERTA -- (Marketwired) -- 08/12/13 -- NuVista Energy Ltd.
("NuVista") (TSX:NVA) is pleased to announce results for the three
and six months ended June 30, 2013 and provide an update on its
business plan. During the second quarter of 2013, our operating and
financial results began to reflect the tremendous growth potential
and strong economics of our condensate-rich Wapiti Montney play.
Included in this press release are the initial 30 day production
rates from two new wells brought on production in June which continue
to highlight the strong condensate yields and prolific nature of this
significant resource. The results of our drilling program together
with industry data continue to support our belief that the
condensate-rich Wapiti Montney is a top-decile North American natural
gas play. The current phase of production growth is well underway
through existing connected facilities, and progress continues to be
made towards the next phase of growth in mid 2014 with the
construction of a 65 MMcf/d compressor station in our South Wapiti
Block of land to connect with the egress arrangements secured and
previously announced with Keyera Corp. through the Simonette gas
Highlights for, and subsequent to, the second quarter of 2013 are as

--  Achieved an average production rate for the second quarter of 2013 of
    17,799 Boe/d, 19% higher than the 14,903 Boe/d recorded in the first
    quarter of 2013 and well above second quarter guidance. First half 2013
    production of 16,359 Boe/d is slightly above the high end of our
    guidance range of 15,250 Boe/d to 16,250 Boe/d provided in March 2013. 
--  Achieved funds from operations of $19.0 million compared to $11.6
    million in the first quarter of 2013 resulting in a quarter over quarter
    increase of 64%. Higher value condensate production doubled from 990
    Bbls/d in the first quarter to 1,980 Bbls/d in the second quarter. This
    increase corresponded to a marked shift in the distribution in NuVista's
    revenue stream quarter over quarter. Condensate volumes generated 31% of
    total revenue up from 22% in the first quarter. Total oil and liquids
    volumes accounted for 58% of NVA's second quarter revenue. 
--  Wapiti Montney production grew to 4,730 Boe/d in the second quarter from
    1,830 Boe/d in the first quarter of 2013 reflecting the strong results
    of the 2013 drilling program to date. Wapiti Montney production has
    grown to 27% of total production volumes with Montney field netbacks
    reaching $28.90/Boe. When combined with our up-hole sweet production,
    the Wapiti core operating area accounted for 57% of total company
    production volumes in the second quarter. 
--  Increased the number of Wapiti Montney wells on production to 11 with
    another strong well tracking the typecurve in our North Block and
    another exceptional well in our South Block. IP 30 condensate production
    from these wells based on field estimates are 254 Bbls/d (51 Bbls/MMcf)
    and 535 Bbls/d (103 Bbls/MMcf), respectively. Total IP30 production for
    these wells was 1,067 Boe/d and 1,383 Boe/d respectively. Please refer
    to the table below for details.  
--  Completed a third Montney delineation well in the second quarter that is
    currently in the process of being tied-in. 
--  Subsequent to the end of the second quarter we have begun drilling three
    additional wells spanning our North and South Blocks in pursuit of
    development step-out drilling near existing strong wells, delineation,
    and continued land expiry management. 
--  Achieved a new company record this month by reaching total depth (TD) on
    one of the above wells in 26 days spud-to-TD for $4.2 million drilling
    cost, four days and $0.4 million (9%) less than our prior record well.
    Drill times and costs continue to trend downwards in general.  
--  Continued strong results from our South Block well (#9 in the table
    below) originally disclosed in May 2013, with cumulative condensate
    production now up to 60,000 Bbls in just 84 days. Based on the current
    trend this well will reach payout in nine months. 

Strong Wapiti Montney Progress Continues 
We continue to be very pleased with the progress made in advancing
our Wapiti Montney play and the results from our and industry's wells
in the greater Wapiti area. With every well drilled we increase our
understanding and believe that we are still at the early stages of
fully maximizing the economic value from this play. We are currently
in the process of developing options for 2014 capital spending and
growth based on the evaluation of recent well results, commodity
prices and balance sheet flexibility. We continue to be encouraged by
our emerging well results defining the potential for proven
development pods, particularly in our highly condensate-rich South
Block. Please see below a table of well results including updated
cumulative production for wells drilled to date, and results from the
two new wells (#10 and #11). Due to continued positive results we
have determined it prudent to change our typecurve projections for
all future South Block wells from an average condensate recovery of
45 Bbls/MMcf raw to 75 Bbls/MMcf of condensate, with the raw gas
typecurve remaining as before at 4.4 Bcf raw. North Block well
forward projections will remain for now at the same as previous, 4.4
Bcf raw gas and 45 Bbls/MMcf condensate. 
Table of Well Results  

                                           IP30 Production(1)               
Well                             Raw Gas  Condensate Total Sales   Bbls/MMcf
                                (MMcf/d)    (Bbls/d)     (Boe/d)   (C5+/raw)
Original Typecurve                                                          
4.4 Bcf Raw Gas                      5.8         203       1,139          35
Average of 1st 6 wells               5.4         305       1,146          59
  Well 7 (North)(3)                  6.7         346       1,479          57
  Well 8 (South)(3)                  3.4         390         918         116
  Well 9 (South)(3)                  7.2         935       2,003         129
Average of next 3 wells              5.8         557       1,467         101
  New Well 10 (North)                5.0         254       1,067          51
  New Well 11 (South)                5.2         535       1,383         103
                              Cumulative Production to July 24, 2013        
                         Days on    CGR(3)                                  
Well                  Production  Bbls/MMcf Condensate  Sales Gas      Total
                                  (C5+/raw)     (Bbls)     (MMcf)     (MBoe)
Original Typecurve                                                          
4.4 Bcf Raw Gas         Ultimate         35    154,000      3,872        865
Well 1 (North)               812         34     39,000      1,000        221
Well 2 (South)               339         41     34,000        774        170
Well 3 (North)               334         40     46,000        948        223
Well 4 (North)               287         79     43,000        441        127
Well 5 (North)               241         54     47,000        762        193
Well 6 (South)               151         65     19,000        266         65
Well 7 (North)                97         52     25,000        428        108
Well 8 (South)                96        104     27,000        216         69
Well 9 (South)                84        113     60,000        422        141
Well 10 (North)               46         51     11,000        179         46
Well 11 (South)               26        105     14,000        111         36
(1) Excludes non-producing days and wells 10 and 11 are based on field      
(2) Condensate gas ratio                                                    
(3) Previously disclosed field estimates have been updated for actual       

After substantial cash flow and production growth from the first to
the second quarter, production for the third quarter of 2013 is
expected to be relatively flat to the second quarter. Production
growth is expected to resume again in the fourth quarter as a result
of an active third quarter drilling program. Faster cycle times for
wells drilled in the second quarter ahead of spring break-up and the
delay in the start-up of the third quarter drilling program due to
the extended Alberta spring rains effectively swapped some of our
third quarter production growth into the second quarter. The net
effect of this is that we expect to be right on track with the higher
end of original production guidance for 2013, but with phasing
changes quarter to quarter. We continue to focus on reducing drilling
times and costs in addition to optimizing completions and have
continued to meet or exceed cost reduction targets as outlined in the
highlights above and in our public Corporate Presentation. Our
average proved plus probable play recycle ratios are already well
over 2x and are expected to continue as previously forecast towards
3x as our optimizations continue. 
The significance of the Montney economics is beginning to flow
through to our quarterly results. Montney field netbacks have reached
$28.90/Boe in the second quarter despite being in the early stages of
development and the temporarily increased operating costs we have
incurred for additional condensate trucking and ramp-up transition
costs due to recent above-typecurve wells. These temporary issues
will be remedied in stages with resolution expected through 2014 when
the previously announced processing and transportation infrastructure
is in place. Corporate netbacks are expected to continue to grow
significantly as Wapiti Montney volumes increasingly take their place
as a dominant percentage of the company output and the benefits of
longer term transportation and processing arrangements are realized.
Overall, these short term issues and a one time annual Gas Cost
Allowance adjustment reduced quarterly cash flows by approximately $2
million in the quarter.  
We remain excited about the progress on our South Block compressor
station towards mid 2014 startup to feed the new Keyera pipeline and
Simonette plant firm processing contract. Major long lead equipment
has been ordered for the NuVista compressor station for early 2014
installation, and Keyera project plans also remain on schedule.
Production will begin mid 2014 with capacity of 35 MMcf/d raw,
ramping up to 65 MMcf/d by late 2014. As previously disclosed, this
project brings NuVista significant room for growth, reduced Montney
operating costs in the range of 25-33%, and firm access for all
Montney C3+ volumes for fractionation and market access at Keyera
Fort Saskatchewan. 
Access to markets and fractionation for natural gas liquids products
continues to be a challenge for our industry. It is critical that
volumes can move smoothly and efficiently to market to facilitate
play growth. In this regard, NuVista is very well positioned to meet
the industry challenges for the transportation, processing, and
marketing of Wapiti Montney products through a variety of firm
contracts which have been set in place including: 

--  All foreseeable raw gas in 2013 will access processing at SemCAMS K3 and
    CNRL Gold Creek plants; 
--  Significant growth volumes for 2014 and 2015 will access processing by
    adding the Keyera Simonette pipeline and gas plant processing, with
    facilities already under construction; 
--  All condensate volumes will be transported by pipeline and truck to the
    local Alberta market for 2013, with virtually all volumes expected to be
    pipeline delivered by late 2014; 
--  All 2013 and beyond propane and butane volumes are being transported on
    the Pembina Peace Pipeline with primarily firm commitments to Fort
    Saskatchewan, where they will be fractionated and delivered to market
    under firm service contracts with Keyera in Fort Saskatchewan. 

Commodity hedging is a key component of NuVista's financial risk
management initiatives. There has been much attention recently
directed to the TransCanada Eastern Mainline toll changes, and much
concern about the corresponding impact on AECO natural gas prices. In
anticipation of this change to tolls, NuVista stepped up its hedging
program several months ago. NuVista's Board of Directors has
increased the authorized hedging period from two years to three years
under specific circumstances and has formalized the inclusion in our
internal policy the hedging of natural gas basis risk. For the third
quarter of 2013, NuVista has fixed an AECO floor price on its natural
gas production of $3.19/Mcf on approximately 60% of forecast
production, net of royalties. For the fourth quarter of 2013, NuVista
has fixed a floor AECO price of $3.36/Mcf on approximately 40% of its
net forecast production, and has changed the floating price exposure
through AECO/NYMEX basis hedges on a further 30% of net production
volumes from an AECO price to a NYMEX price less US$0.56/MMbtu. This
strong AECO fixed and AECO/NYMEX basis protection continues through
2014. For the remainder of 2013, NuVista has also fixed a WTI crude
oil floor price of $93.38/Bbl on approximately 55% of its net
forecast oil and liquids production. 
A disciplined approach to financial risk management continues to be
one of our core principles and is key to our successful advancement
of the Wapiti Montney play and the creation of shareholder value.
During this period of significant opportunity, production growth, and
uncertain commodity prices, NuVista remains committed to maintaining
financial flexibility by keeping net debt at or below approximately
1.5x the most recent quarter's annualized cash flow. 
2013 Production Guidance Unchanged  
We are pleased to reiterate our full year 2013 guidance. Our capital
spending for the year is anticipated to be between $210 million and
$220 million. Average production forecast for the year is expected to
be 16,250 Boe/d to 17,000 Boe/d, trending towards the top half of the
guidance range. Production for the third quarter of 2013 is forecast
to be relatively flat with the second quarter with a range of 17,000
Boe/d to 17,750 Boe/d. Fourth quarter production is expected to
increase to between 17,500 Boe/d and 18,500 Boe/d as previously
disclosed. Funds from operations for the year are forecast to be
between $70 million and $75 million based on forecast second half of
2013 AECO and NYMEX natural gas prices of $3.15/Mcf and US$3.70/MMbtu
respectively, and a WTI crude oil price of US$103/Bbl. 
We continue to evaluate various scenarios pertaining to pace of
growth for our 2014 business plan, and we look forward to announcing
additional details in the fall. With every well drilled, we are
learning more about our Wapiti Montney play and growing increasingly
confident and excited about the impressive condensate-rich potential
of this play, the growth potential, and the exceptional value that is
and will be created from this play as we increase scale and benefit
from the efficiencies that come with it. We have the people, the
assets, and the processing capacity to continue to deliver strong
results for our shareholders. We look forward to providing an update
and 2014 spending details in early November with the release of our
third quarter results. 

Corporate Highlights                                                        
                                   Three months ended     Six months ended  
                                             June 30,              June 30, 
($ thousands, except per share)       2013       2012       2013       2012 
Oil and natural gas revenue         54,158     58,201     95,906    132,057 
Funds from operations(1)            18,983     18,083     30,612     42,207 
  Per basic share                     0.16       0.18       0.26       0.42 
  Per diluted share                   0.16       0.18       0.26       0.42 
Net earnings (loss)                 (7,383)   (85,411)   (11,444)   (88,558)
  Per basic share                    (0.06)     (0.86)     (0.10)     (0.89)
  Per diluted share                  (0.06)     (0.86)     (0.10)     (0.89)
Adjusted net earnings (loss)(1)     (4,850)   (14,668)   (13,471)   (25,566)
  Per basic share                    (0.04)     (0.15)     (0.11)     (0.26)
  Per diluted share                  (0.04)     (0.15)     (0.11)     (0.26)
Total assets                                             934,089  1,254,462 
Long-term debt, net of adjusted                                             
 working capital(1)                                       94,786    339,111 
Capital expenditures                30,963     18,805     99,752     70,652 
Dispositions                          (204)         -     12,392      9,163 
Weighted average common shares                                              
 outstanding (thousands):                                                   
  Basic                            118,665     99,513    118,643     99,513 
  Diluted                          118,665     99,513    118,643     99,513 
  Natural gas (MMcf/d)                73.5       98.1       68.2      101.8 
  Condensate (Bbls/d)                1,980      1,246      1,485      1,221 
  Butane (Bbls/d)                      502        529        437        539 
  Propane (Bbls/d)                     737        709        662        722 
  Ethane (Bbls/d)                      985        641        874        679 
  Oil (Bbls/d)                       1,354      3,994      1,542      4,236 
    Total oil equivalent            17,799     23,467     16,359     24,359 
Average product prices (2)                                                  
  Natural gas ($/Mcf)                 3.43       2.00       3.34       2.25 
  Condensate ($/Bbl)                 92.90      95.05      96.32     102.42 
  Butane ($/Bbl)                     50.57      60.75      56.10      69.02 
  Propane ($/Bbl)                    19.22      20.02      21.89      28.24 
  Ethane ($/Bbl)                      9.62       2.25       7.90       9.18 
  Oil ($/Bbl)                        81.67      69.35      73.28      72.73 
Operating expenses                                                          
  Natural gas and natural gas                                               
   liquids ($/Mcfe)                   1.86       1.66       1.86       1.69 
  Oil ($/Bbl)                        24.71      15.55      22.13      16.18 
    Total oil equivalent ($/Boe)     12.19      10.91      12.20      11.21 
Operating netback ($/Boe)            16.34      12.72      15.29      13.52 
Funds from operations netback                                               
 ($/Boe)(1)                          11.72       8.47      10.35       9.53 
(1) Funds from operations, 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 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.  

NuVista's second quarter 2013 interim consolidated financial
statements and the accompanying Management's Discussion and Analysis
will be 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. 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 and operations; the expectations of creating
significant shareholder value from NuVista's properties and
opportunities; 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 and markets; expectations
of future results, including future production levels, typecurves,
well economics, and operating costs, targeted debt level; the timing,
allocation and efficiency of NuVista's capital program and the
results therefrom; plans and expectations regarding facility
construction and/or expansions, the timing thereof and the benefits
to be obtained therefrom; the anticipated potential of NuVista's
asset base; forecast funds from operations; the source of funding of
capital expenditures; 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.
Jonathan A. Wright
President and CEO
(403) 538-8501 
Robert F. Froese
VP, Finance and CFO
(403) 538-8530
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