NuVista Energy Ltd. ("NuVista") (TSX:NVA) is pleased to announce results for the
three and nine months ended September 30, 2013 and provide an update on its
business plan. During the third quarter of 2013 NuVista was able to advance its
Wapiti Montney drilling program delivering production growth and increased cash
flow, even during a quarter of lower natural gas prices. Development drilling
project areas have now been defined in each of our North and South Blocks of
Wapiti Montney lands. In addition, the independent resource evaluation of
NuVista's condensate-rich Wapiti Montney was recently updated showing a more
than doubling in resource while still only covering approximately half of
NuVista's landholdings in each of the B and C zones of the Middle Montney.
Highlights for, and subsequent to, the third quarter of 2013 are as follows:
-- Achieved an average production rate for the third quarter of 2013 of
18,532 Boe/d compared to 17,799 Boe/d in the second quarter of 2013 and
14,903 Boe/d in the first quarter of 2013. Production in the third
quarter was higher than originally anticipated due to stronger than
expected well performance;
-- Achieved funds from operations of $23.2 million in the third quarter of
2013 compared to $19.0 million in the second quarter of 2013 and $11.6
million in the first quarter of 2013;
-- Higher value condensate production continued to increase, averaging
2,210 Bbls/d in the third quarter of 2013 compared to 1,980 Bbls/d in
the second quarter. Condensate volumes generated 33% of total company
revenue, up from 31% in the second quarter;
-- Wapiti Montney production grew to 5,890 Boe/d in the third quarter of
2013 compared to 4,730 Boe/d in the second quarter and 1,830 Boe/d in
the first quarter of 2013 reflecting the strong results of the 2013
drilling program to date. Montney field netbacks averaged $26.61/Boe
down slightly from $28.90/Boe in the second quarter, primarily due to
lower natural gas prices. Wapiti Montney production has grown to 32% of
total production volumes and when combined with our Wapiti up-hole sweet
production, the Wapiti core operating area accounted for 58% of total
company production volumes in the third quarter;
-- Established IP30 (30 day) production rates for one more North and one
more South Block development well, brought on production an additional
South Block development well, and drilled two delineation/step-out
wells;
-- Set new horizontal well records with respect to cost and time,
continuing the improving trend by achieving spud-to-total depth in 24
days and a new drill cost of $4.0 million, which is 13% below the well's
cost estimate;
-- Set a new record for completion cost of $2.8 million for a large volume
18-stage slickwater fracture stimulation;
-- Completed an update of the evaluation of NuVista's Montney resource with
a 2.1x increase in Best Estimate Economic Contingent Resource to 2.6
Tcfe or 425 MMBoe including a 2.3x increase in the Best Estimate
condensate component of the Economic Contingent Resource to 102.7 MMBbl.
The update confirms $2.35 billion of net present value discounted at 10%
before tax, from 577 horizontal drilling locations and does not yet
include any discovered resources in the Lower Montney;
-- On October 29, 2013, announced the closing of a private placement and
public offering of an aggregate of 5,129,000 common shares issued on a
flow-through basis for gross proceeds of approximately $39.7 million;
and
-- Ended the third quarter with net long-term debt of $117.4 million or
just over 1.3x net debt as a ratio of annualized third quarter cash
flow.
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 own and industry's wells in the greater
Wapiti area. Industry is drilling several multi-well pads to the southeast and
the northwest, combining with NuVista's activity to boost the momentum of this
high value play.
In the South Block, we have increased our internal typecurve condensate yield
from 45 Bbls/MMcf to 75 Bbls/MMcf given the higher yield observed in our six
producers. This increased well performance and producing wellcount certainty has
enabled us to define a development project area between the six wells on
production and have planned approximately 75% of our 2014 activity to be
development wells in this area which can ultimately support well over 100
development wells in the Middle Montney zone alone. We look forward to the South
Block development project drilling in 2014 as we have now progressed into pad
drilling, and expect to see continued cost reduction progress with a number of
two to four well pads in late 2013 and through 2014.
Planning and construction for new South Block infrastructure is progressing
well. The first phase of this increase in capacity involves NuVista's
construction of a 100% owned South Block compressor station and Keyera's
construction of the new pipeline to Keyera's Simonette plant with additional
capacity starting at 35 MMcf/d of raw natural gas by mid-2014. Both our
compressor station and the Keyera pipeline are progressing well with all
regulatory licensing approved, site preparation beginning, and major long lead
equipment and materials ordered. The second phase of South Block growth involves
an expansion of our compressor station and some equipment installation at
Keyera's Simonette plant by the fourth quarter of 2014 adding additional
capacity of 30 MMcf/d at that time. As previously disclosed, this project allows
NuVista significant room for growth, reduced Montney operating and
transportation costs in the range of 25% to 33% by 2015, and firm access for
Montney C3+ volumes for fractionation and marketing at Keyera Fort Saskatchewan.
The NuVista South Block compressor station has been sized for 80 MMcf/d with 100
Bbls/MMcf total condensate yield, or a total of 8,000 Bbls/d of condensate
production - truly lifting our growth path to another level.
In the North Block, we are encouraged by the production performance of the seven
wells on stream to date, but plan to spend only approximately 10% of our 2014
capital there as we maintain our 2014 focus upon the South Block. With a
typecurve condensate yield of 45 Bbls/MMcf and the areal coverage and producing
certainty of the seven wells drilled, we have defined a North Block development
drilling project area across these wells which can ultimately support well over
100 wells in the Middle Montney zone alone.
On the land delineation front, we have tested two significant step-out wells in
the quarter. Both wells had encouraging tests with similar rates and recoveries
to other tested wells in the area and are anticipated to be placed on production
in the coming months. We are encouraged by the inclusion of these wells in the
contingent resource report.
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:
-- Raw gas in 2013 has and 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; and
-- For 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 at 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 concern about the corresponding impact on
AECO natural gas prices. For the fourth quarter of 2013, NuVista has fixed a
floor AECO price of $3.39/Mcf on approximately 50% of its net forecast
production, and has changed the floating price exposure through AECO/NYMEX basis
hedges on a further 44% of net production volumes from an AECO price to a NYMEX
price less US$0.58/MMbtu. Also for the fourth quarter of 2013, NuVista has fixed
a WTI crude oil floor price of $94.68/Bbl on 57% of its net forecast oil and
liquids production forecast. This strong price assurance continues through 2014.
For 2014, NuVista has fixed a floor AECO price of $3.41/Mcf on approximately 31%
of its net forecast production, and has changed the floating price exposure
through AECO/NYMEX basis hedges on a further 47% of net production volumes from
an AECO price to a NYMEX price less US$0.57/MMbtu. Also for 2014, NuVista has
fixed a WTI crude oil floor price of $94.72/Bbl on approximately 56% of its net
forecast oil and liquids production.
Update to Wapiti Montney Contingent Resource Evaluation
NuVista is also pleased to announce the results of the update to its independent
resource evaluation of NuVista's condensate-rich Wapiti Montney asset. GLJ
Petroleum Consultants Ltd. ("GLJ") has updated its evaluation of the Discovered
Petroleum Initially-In-Place ("DPIIP") and the Economic Contingent Resources
("ECR") associated with the in-place petroleum. The evaluation was performed in
accordance with National Instrument 51-101 - Standards of Disclosure for Oil and
Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook
("COGE Handbook") and is effective October 31, 2013.
This evaluation shows a large increase in the DPIIP and ECR of the Montney play,
in particular, new resource recognized as a result of our drilling activity in
the B zone of the Middle Montney formation. GLJ's Best Estimate of the total
DPIIP has more than doubled to 5.6 Tcf and GLJ's Best Estimate of the ECR is 2.6
Tcfe or 425 MMBoe. DPIIP and ECR has now been recognized on 55,000 net acres in
the Montney C and 64,000 net acres in the Montney B, leaving approximately half
of NuVista's total acreage yet to be assigned contingent resource in the Middle
Montney B and C zones. The evaluation does not yet include any discovered
resources in the Lower Montney zone. Step-out and delineation drilling will
continue in 2014.
GLJ's Best Estimate of the condensate component of the ECR has increased to
102.7 MMBoe or 24% of the ECR on a Boe basis. The total NGL component including
propane, butane, and condensate has now reached 140.4 MMBoe in the Best Estimate
case. Based on GLJ's October 1, 2013 forecast prices, the before-tax net present
value, discounted at 10%, associated with the Best Estimate of the ECR is $2.35
billion compared to $1.25 billion at September 1, 2012. It is expected that
significant value remains to be unlocked as NuVista continues to delineate its
landholdings and resources are converted to reserves and production.
DPIIP is typically broken down into four components including Cumulative
Production, Reserves, Contingent Resources and Unrecoverable DPIIP. The
following table presents a breakdown of the DPIIP associated with NuVista's
Montney properties into the component categories:
Discovered Petroleum Initially-In-Place(1)
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Cumulative Production(2) 1.2 MMBoe 0.007 Tcfe
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Reserves (Proved + Probable)(2,3) 29 MMBoe 0.174 Tcfe
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Economic Contingent Resources (Best
Estimate)(4,5) 425 MMBoe 2.550 Tcfe
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Unrecoverable DPIIP(6) 478 MMBoe 2.869 Tcf
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DPIIP (Best Estimate)(7) 934 MMBoe 5.603 Tcf
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Notes:
(1) All estimates of resources and reserves in the above table represent
NuVista's gross resources, reserves or production before the deduction
of any royalties and without including any royalty interests of
NuVista. There is no certainty that it will be commercially viable to
produce any portion of the resources. The resource estimates presented
above use the resource categories set out in the COGE Handbook. See
"Reserves and Resource Disclosure".
(2) The Cumulative Production numbers represent production to October 31,
2013 whereas the Proved plus Probable Reserves numbers are as of
December 31, 2012. From December 31, 2012 to October 31, 2013, total
Cumulative Production from NuVista's Montney properties in the reserve
report was approximately 0.003 Tcfe. For further information regarding
the previously reported reserves numbers, see NuVista's Annual
Information Form dated March 28, 2013.
(3) The Proved plus Probable Reserves estimate is effective as of December
31, 2012 and is based on an independent evaluation by GLJ using
January 1, 2013 forecast pricing. The Proved Reserves as of December
31, 2012 were estimated to be 0.094 Tcfe.
(4) All of NuVista's Contingent Resources from its Montney properties are
considered economic using GLJ's October 1, 2013 forecast prices.
(5) The primary contingency which prevents the classification of the ECR
as reserves is pace and availability of funding. In addition, more
drilling, completion, and testing data will be required before NuVista
can commit to the development of the ECR. Proved and Probable Reserves
are assigned to areas in proximity to proven producing Montney wells.
ECR's are assigned to areas that extend beyond the limits of Reserves.
As continued delineation drilling occurs, some resources currently
classified as ECR are expected to be re-classified as Reserves.
(6) All of the DPIIP that has not been classified as Cumulative
Production, Reserves or Contingent Resources may be considered
unrecoverable at this time. A portion of the Unrecoverable DPIIP may
in the future be determined to be recoverable and reclassified as
Contingent Resources or reserves as additional technical studies are
performed, commercial circumstances change or technological
developments occur; the remaining portion may never be recovered due
to the physical/chemical constraints represented by subsurface
interaction of fluids and reservoir rocks. The Unrecoverable DPIIP has
been calculated by subtracting Cumulative Production, Proved plus
Probable Reserves and Contingent Resources from DPIIP. Since the
Proved plus Probable Reserves are estimated as of December 31, 2012
and all other numbers are as of October 31, 2013 the Unrecoverable
DPIIP may be greater or less that the number in the above table due to
increases or decreases in Proved plus Probable Reserves between
December 31, 2012 and October 31, 2013.
(7) The sum of Cumulative Production, Reserves, Contingent Resources and
Unrecoverable DPIIP do not add to DPIIP as Cumulative Production,
Reserves and Contingent Resources have been reduced to marketable
sales volumes that have been shrunk to account for surface loss. DPIIP
and Unrecoverable DPIIP volumes are in-place volumes that have not
been reduced due to surface loss.
An update to NuVista's Proved and Probable Montney reserves, which will reflect
our active 2013 Montney drilling program, will be included within our regular
annual reserves disclosure in our 2014 Annual Information Form.
2013 and 2014 Guidance
We are pleased to provide an update to our guidance for 2013. Average production
forecast for the year is expected to be 17,000 Boe/d to 17,400 Boe/d, slightly
above the top of our previous guidance range of 16,250 Boe/d to 17,000 Boe/d.
Production for the fourth quarter is expected to be unchanged from prior
guidance at between 17,500 Boe/d and 18,500 Boe/d as first disclosed in our
March 6, 2013 press release. Our capital spending for 2013 is anticipated to be
between $215 million and $220 million. Funds from operations for the year are
forecast to be between $70 million and $75 million based on forecast fourth
quarter 2013 AECO and NYMEX natural gas prices of $3.29/Mcf and US$3.70/MMbtu,
respectively, and a WTI crude oil price of US$101.02/Bbl.
NuVista's Board of Directors has approved a 2014 capital budget range of $220
million to $240 million. NuVista's 2014 business plan will focus on South Block
development project drilling and timely completion of the two phases of
infrastructure that will facilitate 2014 and future growth while prudently
managing its debt levels throughout this period of facility expansion. NuVista
is targeting fourth quarter 2013 to fourth quarter 2014 production per share
growth of approximately 15%. We have a target to divest of noncore properties
for proceeds of $25 million to $50 million in each of 2013 and 2014. We will
provide more details of our 2014 business in the coming months as we finalize
our detailed capital plan and budget for 2014.
With a similar capital program in 2015, we have line of sight to reaching 25,000
Boe/d of company production in that year. Ultimately the South and North Block
development drilling project areas alone are expected to support more than 200
profitable horizontal wells in the Middle Montney zone, a proven resource base
which is expected to support 15% to 30% annual production growth rates
(depending on spending pace) in the defined development project areas through
2020 and beyond. In addition, there is significant room to expand beyond the
defined project areas when one looks at the 577 total locations assigned in the
Contingent Resources report and the many NuVista lands where we expect to
continue delineation drilling in the Middle and Lower Montney.
With every well drilled, we are learning more about our Wapiti Montney area and
growing increasingly confident and excited about the impressive condensate-rich
potential of this play, the growth potential, and the exceptional value that is
and will be created as we increase scale and benefit from the efficiencies that
come with it. We have moved into defined development project area and pad
drilling. We have the people, the assets, the processing capacity, and the will
to continue to deliver significant results for our shareholders. We look forward
to providing our fourth quarter results and annual reserves data in March 2014.
----------------------------------------------------------------------------
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Corporate Highlights
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Three months ended Nine months ended
September 30, September 30,
($ thousands, except per
share) 2013 2012 2013 2012
----------------------------------------------------------------------------
Financial
Oil and natural gas revenue 60,420 61,678 156,326 193,735
Funds from operations(1) 23,161 17,187 53,773 59,394
Per basic share 0.20 0.17 0.45 0.60
Per diluted share 0.20 0.17 0.45 0.60
Net earnings (loss) (2,295) (47,600) (13,739) (136,158)
Per basic share (0.02) (0.48) (0.12) (1.37)
Per diluted share (0.02) (0.48) (0.12) (1.37)
Adjusted net earnings
(loss)(1) (2,416) (19,692) (15,887) (42,257)
Per basic share (0.02) (0.20) (0.13) (0.45)
Per diluted share (0.02) (0.20) (0.13) (0.45)
Total assets 953,145 1,212,600
Long-term debt, net of
adjusted working capital(1) 117,425 314,242
Capital expenditures 44,626 15,776 144,378 86,428
Dispositions - 687 12,392 9,850
Weighted average common
shares outstanding
(thousands):
Basic 118,727 99,523 118,670 99,517
Diluted 118,727 99,523 118,670 99,517
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Operating
Production
Natural gas (MMcf/d) 76.7 101.8 71.0 101.8
Condensate (Bbls/d) 2,210 1,659 1,731 1,348
Butane (Bbls/d) 475 544 450 535
Propane (Bbls/d) 802 730 709 725
Ethane (Bbls/d) 715 608 820 681
Oil (Bbls/d) 1,550 3,435 1,545 3,967
Total oil equivalent 18,532 23,936 17,092 24,217
Average product prices (2)
Natural gas ($/Mcf) 3.04 2.24 3.23 2.24
Condensate ($/Bbl) 97.92 88.83 97.08 97.04
Butane ($/Bbl) 63.94 58.77 58.72 65.60
Propane ($/Bbl) 27.52 18.11 23.98 24.82
Ethane ($/Bbl) 11.59 3.14 8.97 7.12
Oil ($/Bbl) 94.45 74.43 80.44 73.22
Operating expenses
Natural gas and natural
gas liquids ($/Mcfe) 1.75 1.64 1.82 1.68
Oil ($/Bbl) 21.24 17.93 21.86 16.68
Total oil equivalent
($/Boe) 11.37 11.00 11.90 11.14
Operating netback ($/Boe) 17.28 11.96 16.01 13.00
Funds from operations
netback ($/Boe)(1) 13.59 7.80 11.52 8.95
----------------------------------------------------------------------------
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NOTES:
(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.
CONSOLIDATED FINANCIAL STATEMENTS AND MD&A
NuVista's third quarter 2013 interim consolidated financial statements and the
accompanying Management's Discussion and Analysis will be filed on SEDAR
(www.sedar.com) under NuVista Energy Ltd. and can also be accessed on NuVista's
website at www.nuvistaenergy.com.
RESERVES AND RESOURCE DISCLOSURE
The reserves and resources estimates prepared herein have been evaluated by an
independent qualified reserves evaluator in accordance with NI 51-101 and the
COGE Handbook. The reserves and resources have been categorized accordance with
the reserves and resource definitions as set out in the COGE Handbook, which are
set out below:
Discovered petroleum initially-in-place or DPIIP is that quantity of petroleum
that is estimated, as of a given date, to be contained in known accumulations
prior to production. The recoverable portion of discovered petroleum
initially-in-place includes Cumulative Production, Reserves, and Contingent
Resources; the remainder is categorized as unrecoverable.
Cumulative Production is the cumulative quantity of petroleum that has been
recovered at a given date.
Reserves are estimated remaining quantities of petroleum anticipated to be
recoverable from known accumulations, as of a given date, based on the analysis
of drilling, geological, geophysical, and engineering data; the use of
established technology; and specified economic conditions, which are generally
accepted as being reasonable. Reserves are further classified according to the
level of certainty associated with the estimates and may be sub-classified based
on development and production status.
Proved Reserves are those quantities of petroleum, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to
be economically producible from a given date forward, from known reservoirs and
under existing economic conditions, operating methods and government
regulations.
Probable Reserves are those additional quantities of petroleum that are less
certain to be recovered than Proved Reserves, but which, together with Proved
Reserves, are as likely as not to be recovered.
Contingent Resources are those quantities of petroleum estimated, as of a given
date, to be potentially recoverable from known accumulations using established
technology or technology under development, but which are not currently
considered to be commercially recoverable due to one or more contingencies.
Contingencies may include such factors as economic, legal, environmental,
political and regulatory matters or a lack of markets. It is also appropriate to
classify as Contingent Resources the estimated discovered recoverable quantities
associated with a project in the early evaluation stage.
There is no certainty that it will be commercially viable to produce any portion
of the Contingent Resources or that any portion of the volumes currently
classified as Contingent Resources will be produced. The recovery and resource
estimates provided herein are estimates. Actual Contingent Resources (and any
volumes that may be classified as Reserves) and future production from such
Contingent Resources may be greater than or less than the estimates provided
herein.
Economic Contingent Resources ("ECR\") are those Contingent Resources that are
currently economically recoverable based on specific forecasts of commodity
prices and costs.
Unrecoverable Discovered Petroleum Initially-In-Place or Unrecoverable DPIIP is
that portion of DPIIP which is estimated, as of a given date, not to be
recoverable by future development projects. A portion of these quantities may
become recoverable in the future as commercial circumstances change or
technological developments occur; the remaining portion may never be recovered
due to the physical/chemical constraints represented by subsurface interaction
of fluids and reservoir rocks.
Best Estimate of a resource represents the best estimate of the quantity that
will actually be recovered. It is equally likely that the actual remaining
quantities recovered will be greater or less than the best estimate. If
probabilistic methods are used, there should be at least a 50 percent
probability (P50) that quantities actually recovered will equal or exceed the
best estimate.
ADVISORY REGARDING OIL AND GAS INFORMATION
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.
ADVISORY REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
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, transportation and markets; expectations of future results,
including future production levels, typecurves, well economics, and operating
costs, future disposition plans, 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
NuVista's capital program; 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.
FOR FURTHER INFORMATION PLEASE CONTACT:
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
NuVista Energy (TSX:NVA)
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