CALGARY, ALBERTA–(Marketwired – Nov. 5, 2013) – 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-Place1|
|Cumulative Production2||1.2 MMBoe||0.007 Tcfe|
|Reserves (Proved + Probable)2,3||29 MMBoe||0.174 Tcfe|
|Economic Contingent Resources (Best Estimate)4,5||425 MMBoe||2.550 Tcfe|
|Unrecoverable DPIIP6||478 MMBoe||2.869 Tcf|
|DPIIP (Best Estimate)7||934 MMBoe||5.603 Tcf|
|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 $50 million in each of 2013 and 2014. We will provide more details of our 2014 business in the coming months as we finalize our detailed capital plan and budget for 2014.
With a similar capital program in 2015, we have line of sight to reaching 25,000 Boe/d of company production in that year. Ultimately the South and North Block development drilling project areas alone are expected to support more than 200 profitable horizontal wells in the Middle Montney zone, a proven resource base which is expected to support 15% to 30% annual production growth rates (depending on spending pace) in the defined development project areas through 2020 and beyond. In addition, there is significant room to expand beyond the defined project areas when one looks at the 577 total locations assigned in the Contingent Resources report and the many NuVista lands where we expect to continue delineation drilling in the Middle and Lower Montney.
With every well drilled, we are learning more about our Wapiti Montney area and growing increasingly confident and excited about the impressive condensate-rich potential of this play, the growth potential, and the exceptional value that is and will be created as we increase scale and benefit from the efficiencies that come with it. We have moved into defined development project area and pad drilling. We have the people, the assets, the processing capacity, and the will to continue to deliver significant results for our shareholders. We look forward to providing our fourth quarter results and annual reserves data in March 2014.
|Three months ended
|Nine months ended
|($ thousands, except per share)||2013||2012||2013||2012|
|Oil and natural gas revenue||60,420||61,678||156,326||193,735|
|Funds from operations1||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||)|
|Long-term debt, net of adjusted working capital1||117,425||314,242|
|Weighted average common shares outstanding (thousands):|
|Natural gas (MMcf/d)||76.7||101.8||71.0||101.8|
|Total oil equivalent||18,532||23,936||17,092||24,217|
|Average product prices 2|
|Natural gas ($/Mcf)||3.04||2.24||3.23||2.24|
|Natural gas and natural gas liquids ($/Mcfe)||1.75||1.64||1.82||1.68|
|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|
|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.
Jonathan A. Wright
President and CEO
NuVista Energy Ltd.
Robert F. Froese
VP, Finance and CFO