News & Events


Press Release Navigation
Previous Headlines Next

FOR: NUVISTA ENERGY LTD.

TSX SYMBOL: NVA - |  View Quote |  View Chart |  View Financials | 

NuVista Energy Ltd.: Third Quarter Interim Report

Nov 10, 2010 - 21:14 ET

CALGARY, ALBERTA--(Marketwire - Nov. 10, 2010) - NuVista Energy Ltd. (TSX:NVA) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2010, as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corporate Highlights Three months Nine months
ended September 30, ended September 30,
---------------------------------------------------------
% %
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Financial
($ thousands,
except per share)
Production revenue 88,733 79,494 12 283,775 249,315 14
Funds from
operations(1) 42,482 41,198 3 134,336 139,639 (4)
Per share - basic 0.48 0.48 - 1.52 1.72 (12)
Per share - diluted 0.48 0.48 - 1.52 1.72 (12)
Net earnings
(loss) (5,025) (3,342) (50) (572) (8,022) 93
Per share
- basic (0.06) (0.04) (50) (0.01) (0.10) 90
Per share
- diluted (0.06) (0.04) (50) (0.01) (0.10) 90
Total assets 1,622,317 1,572,124 3
Long-term debt,
net of working
capital 447,924 386,167 16
Long-term debt,
net of adjusted
working capital(1) 446,961 387,060 15
Shareholders'
equity 914,644 906,993 1
Net capital
expenditures 79,629 189,508 (58) 196,515 279,054 (30)
Weighted average
common shares
outstanding
(thousands):
Basic 88,625 85,770 3 88,501 81,404 9
Diluted 88,625 85,770 3 88,501 81,404 9
Cash dividends
declared 4,432 - - 13,285 - -
Per share 0.05 - - 0.15 - -
----------------------------------------------------------------------------

Operating
(Boe conversion
- 6:1 basis)
Production
Natural gas
(MMcf/d) 124.0 121.0 2 124.7 114.3 9
Natural gas
liquids (Bbls/d) 2,840 3,181 (11) 3,062 3,153 (3)
Oil (Bbls/d) 4,731 4,153 14 4,550 4,289 6
Total oil
equivalent
(Boe/d) 28,244 27,505 3 28,403 26,490 7
Product prices(2)
Natural gas
($/Mcf) 4.34 3.99 9 4.70 4.99 (6)
Natural gas
liquids ($/Bbl) 48.92 39.58 24 51.05 36.86 38
Oil ($/Bbl) 61.20 66.17 (8) 63.40 61.78 3
Operating
expenses
Natural gas and
natural gas
liquids ($/Mcfe) 1.14 1.24 (8) 1.17 1.16 1
Oil ($/Bbl) 18.37 16.32 13 18.10 16.31 11
Total oil
equivalent
($/Boe) 8.77 8.79 - 8.78 8.46 4
General and
administrative
expenses ($/Boe) 1.87 1.49 26 1.82 1.45 26
Funds from
operations
netback ($/Boe)(1) 16.35 16.29 - 17.33 19.30 (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NOTES:
(1) Funds from operations, funds from operations per share, funds from
operations netback 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, general and administrative, restricted stock units,
interest expenses and cash taxes calculated on a Boe basis. Adjusted
working capital excludes the current portions of the commodity
derivative asset or liability and the future income tax asset or
liability. Total Boe is calculated by multiplying the daily production
by the number of days in the period. For more details on non-GAAP
measures, refer to "Management's Discussion and Analysis" section of
this press release.
(2) Product prices include realized gains/losses on commodity derivatives.


Trading Statistics

Three months ended Nine months ended
September 30, September 30,
(Cdn$, except volumes) based on -----------------------------------------
intra-day trading 2010 2009 2010 2009
----------------------------------------------------------------------------
High 12.51 12.50 14.56 12.50
Low 10.02 8.85 9.65 4.90
Close 10.43 12.49 10.43 12.49
Average daily volume 198,325 212,107 273,142 241,180
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


MESSAGE TO SHAREHOLDERS

NuVista Energy Ltd. ("NuVista") is pleased to report to its shareholders the financial and operating results for the three and nine months ended September 30, 2010. NuVista is in the second year of a three year transition as we shift our corporate emphasis from an acquire and develop business model to one where growth on a per share basis results from the successful implementation of repeatable development drilling projects on lands that we currently control. In our Wapiti operating area, successful test wells in the Montney and subsequently in the Cardium, have moved NuVista closer to validating our key resource plays. With extended production tests on our existing wells and new results from additional proof of concept wells drilled in our focus areas, the value of NuVista's strategy of positioning the company in high resource-in-place plays through significant land purchases in our Wapiti operating area, is becoming increasingly apparent. NuVista's portfolio of repeatable resource opportunities offers shareholders considerable upside on a per share basis.

While continuing to drill concept testing wells in our resource plays, NuVista and others have been experiencing the lowest natural gas prices in over a decade and the near term outlook is for these low prices to continue. Fortunately, NuVista remains in an enviable position of having many years of drilling opportunities where economics can be driven primarily from liquids. Our promising plays targeting oil in the Cardium and the 90-100 Bbls/MMcf liquid-rich Montney in Wapiti, are two examples of projects which remain economic in the current commodity price environment. Initial results in these plays are encouraging and given the size and scope of these resource opportunities, we believe it is appropriate for NuVista to devote up to two-thirds of its first half 2011 capital to these plays. Although these plays are expected to have a significant impact on NuVista's future growth, current weak natural gas prices will prolong full scale development of these concepts over a longer period of time.

In 2010, the vast majority of NuVista's capital was spent on testing resource concepts and de-risking plays. With the decline in natural gas prices and with the knowledge that our Montney project in Wapiti has the potential to transform the company over time, NuVista's 2011 capital plan will focus on increasing cash flow and netbacks by targeting light oil and heavy oil development projects, our two highest netback products. In the first half of 2011, over 80% of NuVista's operated capital expenditures will be directed towards oil projects and the only concept test well will be a second Wapiti Montney well on the northern block, approximately four miles from our existing 9-22 producer. In the first half of 2011, NuVista plans to spend available cash flow and maintain production at current levels by allowing our dry gas production to decline while increasing our liquids production by 15%. Based upon third quarter netbacks and an increase in our liquids ratio to 31% of production, cash flow at 28,000 Boe/d should be similar to 30,500 Boe/d at the current liquid ratio of 27%. 

In the third quarter of 2010, NuVista remained active in testing concept wells and completed a small tuck-in acquisition in our Ferrier operating area with Notikewan-Spirit River horizontal drilling opportunities. As experienced throughout the industry, efforts to complete and tie-in production during the third quarter were hampered by wet conditions in the field. Despite these conditions, NuVista was still able to achieve production of 28,244 Boe/d during the third quarter of 2010. NuVista's fourth quarter activities are being curtailed in an effort to continue to maintain financial flexibility in an uncertain natural gas price environment. We now forecast production between 28,000 - 28,500 Boe/d range for the fourth quarter along with capital expenditures of approximately $30 million. Our syndicated bank facility semi-annual review was recently completed and the commitment amount remains unchanged at $510 million. NuVista will prudently manage its financial flexibility during this period of low natural gas prices and adapt its business plan to changes in natural gas prices and global financial conditions. 

Update on Key Plays:

1. Wapiti Operating Area

Montney Formation

An extended production test was conducted on our first Wapiti Montney horizontal well in our northern block. This well encountered 1,400 meters of porous reservoir and was successfully completed over eleven intervals with 100 tonnes of sand per interval and tested at rates in excess of 10 MMcf/d. Of equal significance to the natural gas test rate is the discovery of significant associated liquids with the Montney production on the north block of our landholdings. This well has produced approximately 0.3 Bcf of liquid-rich raw gas and approximately 10,000 Bbls of free condensate to date. The well continues to produce at rates in excess of 3.0 MMcf/d and 100 Bbls/d of free condensate. In addition to the free condensate, the liquid content in the raw gas stream is estimated at 65 Bbls/MMcf if a deep cut facility was used to process the raw gas stream.

NuVista recently drilled its second planned Montney horizontal gas well to evaluate our southern Montney land block in Wapiti. This well is 20 miles southeast of NuVista's first well. Difficulties encountered during drilling limited the length of the horizontal section to 900 meters instead of the 1,300 meters originally planned. This well was completed over eleven intervals with approximately 1,000 tonnes of frac sand being placed in the well. A number of mechanical difficulties associated with the completion have prevented NuVista from adequately evaluating the interval to this point and operations to clean out the well are continuing.

NuVista anticipates the drilling of up to five additional Montney wells on our north and south blocks in 2011, however, only one well will be drilled on our northern block in the first half of 2011. NuVista will also monitor the results of Montney wells drilled in the area by other companies. Simultaneously with our drilling activity, NuVista is continuing with our preliminary evaluation of the construction of our own sour gas processing facility with acid gas re-injection in the Wapiti area by the end of 2012. NuVista has preliminary plans for a separate compression and dehydration facility with condensate stabilization in our northern block. This facility may be constructed in 2011. 

NuVista has approximately 170 gross sections of Montney acreage in Wapiti with an average working interest of 94%. Many of these sections contain significant lower Montney as well as upper Montney pay. Sections with both upper and lower Montney pay may ultimately yield more than six horizontal wells per section. NuVista continues to add acreage to our Cardium and Montney contiguous land blocks in the Wapiti area through farm-ins, swaps and land purchases.

Cardium Formation

NuVista has approximately 95 contiguous net sections of Cardium lands on this emerging oil resource play in Wapiti with similar log characteristics to those being successfully exploited using horizontal wells in the Pembina area. NuVista has farmed-out several low working interest sections to a third party who has drilled and completed a Cardium horizontal test well with multi-stage fractures, in which NuVista has a 22% carried working interest. The extended production test for this well expands the known "oil window" to the west proving up over 140 net locations. Six wells have now been drilled in the Cardium resource play and NuVista feels the Cardium in Wapiti is entering the development stage for 2011. NuVista has its first two operated Cardium horizontal wells in Wapiti on production with stabilized production rates meeting expectations. NuVista plans to participate in up to six Wapiti Cardium wells prior to the end of the first quarter and up to 20 Wapiti Cardium wells for all of 2011. The majority of NuVista's 2011 wells will be drilled on separate sections. The contiguous nature of NuVista's Cardium lands and the repeatability of the Cardium play should provide NuVista with attractive economic returns. In addition, each horizontal well drilled in 2011 provides the opportunity to book multiple infill opportunities in our reserves report.

Nikanassin Formation

With the completion of our land purchases in April 2010, we have increased our net Nikanassin land position in Wapiti to approximately 180 gross sections with an average working interest of 87%. NuVista now has a dominant Nikanassin land position within our Wapiti operating area and has participated in nine vertical wells during the last eighteen months, with initial production rates of between 0.5 - 2.0 MMcf/d per vertical well. Based upon the encouraging vertical production from this program, NuVista drilled one Nikanassin horizontal wells in the third quarter. Mechanical difficulties associated with the drilling of this well resulted in only 400 meters of open horizontal section and necessitated completing the well with cemented casing rather than the planned packer system. The completion of this well has been delayed while NuVista researches the best completion alternatives in cased horizontal wells. NuVista has considerable tenure on its lands and therefore, further de-risking and concept testing capital on the Nikanassin will be deferred in favour of the Montney which has higher liquid content yields and superior returns in the current natural gas price environment.

2. W3/W4 Operating Area 

Birdbear Formation

NuVista has drilled two Birdbear horizontal wells on our Zoller Lake oil property in West Central Saskatchewan, near our Hallum heavy oil play, and is currently drilling a third well with a view to setting up 17 additional development locations. NuVista plans to drill a minimum of twelve Birdbear horizontal wells in 2011 and will increase this program based upon results. Up to eight Birdbear horizontal wells are planned in the first quarter of 2011.

3. Pembina/Ferrier Operating Areas

Cardium Formation

NuVista has now participated in seven Cardium horizontal oil wells with multi-stage fractures in the Pembina operating area with an average working interest of 62%. All seven wells are on production and NuVista has operated four of these wells. During the third quarter, NuVista's 1-31-50-12W5M horizontal well (100% working interest) tested at a two week initial production rate of 420 Bbls/d of oil after recovering all load fluids. This well has produced over 10,000 Bbls of light oil to date. Current production from the well is approximately 250 Boe/d. NuVista plans to drill 1-2 development wells in section 31 prior to the end of the first quarter and participate in up to four additional wells during the first half of 2011.

Notikewin and Spirit River Formations

NuVista has over 180 net sections of rights in its Pembina and Ferrier operating areas which are prospective for Notikewin or Spirit River horizontal drilling. The Notikewin-Spirit River formations have become the primary focus for many operators in the area. These operators have press released successful drilling results in the Notikewan-Spirit River and continue to de-risk the play. Although NuVista will continue to monitor industry activity on this play, NuVista plans to focus on oil plays during the first half of 2011 which will result in Notikewin-Spirit River development capital being delayed until the second half of 2011. With the size and extent of NuVista's land base and successful testing of concept wells by other operators, this play could have significant development opportunities in the future. 

4. Kaybob Operating Area 

Montney Formation

In the third quarter, NuVista drilled two wells (100% working interest) at its Kaybob Montney property testing at 7.1 MMcf/d and 6.3 MMcf/d. In late September, NuVista completed the expansion of its Fir facility to 20 MMcf/d and current throughput is at approximately 17 MMcf/d. One additional well (100% working interest) is planned for the fourth quarter of 2010. 

Declaration of Dividend

On November 10, 2010, our Board of Directors declared a quarterly dividend of $0.05 per common share, payable in cash, to shareholders of record on December 31, 2010 with the dividend payment on January 17, 2011. 

Through challenging and at times difficult industry conditions, NuVista continues to maintain a disciplined approach to its business. The NuVista team has demonstrated its ability to protect and enhance the interests of our stakeholders over the long term by focusing on increasing our production and reserves on a per share basis while prudently managing our debt levels. We closely manage capital spending levels and we control the timing of all significant capital projects through our high level of operatorship. We pride ourselves on being able to make effective business decisions based on timely and accurate data. This approach has enabled us to adapt to rapidly changing economic and market conditions. We look forward to sharing our future successes with our shareholders. 




MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") of financial conditions and results of operations should be read in conjunction with NuVista's unaudited consolidated financial statements for the three and nine months ended September 30, 2010 and the audited consolidated financial statements for the year ended December 31, 2009. The following MD&A of financial condition and results of operations was prepared at and is dated November 10, 2010. Our audited consolidated financial statements, Annual Report, Annual Information Form and other disclosure documents for 2009 are available through our filings on SEDAR at www.sedar.com or can be obtained from our website at www.nuvistaenergy.com.

Basis of presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent ("Boe") using six thousand cubic feet of natural gas equal to one barrel of oil, unless otherwise stated. In certain circumstances natural gas liquid volumes have been converted to thousand cubic feet equivalent ("Mcfe") on the basis of one barrel of natural gas liquids to six thousand cubic feet. Boes and Mcfes may be misleading, particularly if used in isolation. A conversion ratio of one barrel to six thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 

Forward-looking statements - Certain information set forth in this document contains forward-looking statements, including management's assessment of NuVista's future strategy, plans, opportunities and operations, forecast production, production mix, reserves growth, resource opportunities, drilling, development, completion and tie-in plans and results, plans regarding new drilling and completion technology and the results therefrom, NuVista's planned capital budget, targeted debt level, the timing, allocation and efficiency of NuVista's capital program and the results therefrom, planned facility expansions the timing thereof and the results therefrom, plans to pursue and complete acquisition opportunities, forecast funds from operations, expectations regarding funds from operations being sufficient to fund NuVista's planned fourth quarter and 2011 capital program and the allocation thereof, targeted operating costs and other expenses, benefits from the Alberta Government's announcement of royalty incentives, expectations regarding the payment of future taxes, NuVista's dividend policy and the timing and payment of dividends, continuation and participation in NuVista's dividend re-investment plan, expectations regarding future commodity prices, netbacks and industry conditions and expectations regarding NuVista's IFRS conversion project which are provided to allow investors to better understand our business.

In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. 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 and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, competition from other industry participants, availability of qualified personnel or management services and drilling and related equipment, stock market volatility, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties and the ability to access sufficient capital from internal sources and bank and equity markets and including, without limitation, those risks considered under "Risk Factors" in our Annual Information Form. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. NuVista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP measurements - Within the MD&A, references are made to terms commonly used in the oil and natural gas industry. Management uses funds from operations to analyze operating performance and leverage. Funds from operations as presented, does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, per the statement of cash flows, net earnings (loss) or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities 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 netbacks equal total revenue including realized commodity derivative gains/losses less royalties, transportation, operating costs, general and administrative, restricted stock unit, interest expense and cash taxes. Management also uses field netbacks to analyze operating performance and adjusted working capital to analyze leverage. Field netbacks and adjusted working capital as presented, do not have any standardized meaning prescribed by Canadian GAAP and therefore, may not be comparable with the calculation of similar measures for other entities. Field netbacks equal the total of revenue including realized commodity derivative gains/losses less royalties, transportation and operating costs. Adjusted working capital equals working capital excluding the current portion of the commodity derivative asset or liability and the future income tax asset or liability. Total Boe is calculated by multiplying the daily production by the number of days in the period.



A reconciliation of funds from operations is presented in the following
table:

Three months ended Nine months ended
September 30, September 30,
----------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by operating activities 44,984 32,852 124,738 130,792
Add back:
Asset retirement expenditures 764 654 7,077 1,843
Change in non-cash working capital (3,266) 7,692 2,521 7,004
----------------------------------------------------------------------------
Funds from operations 42,482 41,198 134,336 139,639
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Operating activities - For the three months ended September 30, 2010, NuVista drilled 16 (13.2 net) wells resulting in nine oil wells, six natural gas wells, and a dry hole, for an overall success rate of 94%. NuVista operated 14 of the wells drilled. A total of 11 horizontal wells were drilled during the quarter, five oil wells and six natural gas wells. Five horizontal Cardium oil wells were drilled during the quarter, three wells at Wapiti and two wells at Pembina. In addition, four Montney horizontal gas wells were drilled, (three wells at Kaybob and one well at Wapiti), one Notikewin gas well at Pembina and one Cardium gas well at Ferrier. For the nine months ended September 30, 2010, NuVista drilled 57 (43.1 net) wells resulting in 28 oil wells, 28 natural gas wells and a dry hole, for an overall success rate of 98%. 

For the fourth quarter of 2010, NuVista plans to focus drilling activities primarily on oil targets but will continue to selectively drill liquid-rich natural gas prospects. NuVista plans to drill approximately 11 wells (eight oil wells and three natural gas wells), of which nine are planned to be horizontal wells. Of the oil wells, five wells are located in our Wapiti and Pembina operating areas primarily targeting Cardium oil and three wells are in West Central Saskatchewan targeting the Birdbear formation. In addition, our planned gas drilling will target the Montney, Gething and Nikanassin formations in our Kaybob and Wapiti operating areas.



Production

Three months ended September 30,
----------------------------------------
2010 2009 % Change
----------------------------------------------------------------------------
Natural gas (Mcf/d) 124,039 121,028 2
Liquids (Bbls/d) 2,840 3,181 (11)
Oil (Bbls/d) 4,731 4,153 14
----------------------------------------------------------------------------
Total oil equivalent (Boe/d) 28,244 27,505 3
----------------------------------------------------------------------------


Nine months ended September 30,
----------------------------------------
2010 2009 % Change
----------------------------------------------------------------------------
Natural gas (Mcf/d) 124,743 114,293 9
Liquids (Bbls/d) 3,062 3,153 (3)
Oil (Bbls/d) 4,550 4,289 6
----------------------------------------------------------------------------
Total oil equivalent (Boe/d) 28,403 26,490 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


For the three months ended September 30, 2010, NuVista's average production was 28,244 Boe/d, comprised of 124.0 Mcf/d of natural gas, 2,840 Bbls/d of associated natural gas liquids ("liquids") and 4,731 Bbls/d of oil, which represents an overall 3% average increase compared to the same period in 2009. The increase in NuVista's production during the three months ended September 30, 2010 compared to the same period in 2009 was primarily due to the property acquisitions in the third quarter of 2010 and new production from drilling activities at our Kaybob and Wapiti operating areas.

NuVista's production for the nine months ended September 30, 2010 averaged 28,403 Boe/d comprised of 124.7 Mcf/d of natural gas, 3,062 Bbls/d of liquids and 4,550 Boe/d of oil, which represents an overall 7% average increase over the same period in 2009. The increase in production for the nine months ended September 30, 2010 compared to the same period in 2009 is primarily due to the property acquisitions in the last half of 2009 and new production additions from our successful 2009/2010 drilling program. 



Revenues
Three months ended September 30,
------------------------------------------------------
($ thousands, except
per unit amounts) 2010 2009 % Change
----------------------------------------------------------------------------
Natural Gas $ $/Mcf $ $/Mcf $ $/Mcf
Production
revenue(1) 48,565 4.26 44,440 3.99 9 7
Realized gain (loss)
on commodity
derivatives 885 0.08 - - - -
----------------------------------------------------------------------------
Total Natural Gas 49,450 4.34 44,440 3.99 11 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liquids $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 12,785 48.92 11,583 39.58 10 24
Realized gain (loss)
on commodity
derivatives - - - - - -
----------------------------------------------------------------------------
Total Liquids 12,785 48.92 11,583 39.58 10 24
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 27,383 62.92 23,471 61.43 17 2
Realized gain (loss)
on commodity
derivatives (750) (1.72) 1,811 4.74 (141) (136)
----------------------------------------------------------------------------
Total Oil 26,633 61.20 25,282 66.17 5 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total $ $/Boe $ $/Boe $ $/Boe
Production revenue 88,733 34.15 79,494 31.41 12 9
Realized gain (loss)
on commodity
derivatives 135 0.05 1,811 0.72 (93) (93)
----------------------------------------------------------------------------
Total 88,868 34.20 81,305 32.13 9 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Natural gas revenue includes price risk management gains and losses on
physical sale contracts. For the three months ended September 30, 2010,
our physical sale contracts resulted in a gain of $3.8 million (2009 -
$9.3 million gain).


Nine months ended September 30,
------------------------------------------------------
($ thousands, except
per unit amounts) 2010 2009 % Change
----------------------------------------------------------------------------
Natural Gas $ $/Mcf $ $/Mcf $ $/Mcf
Production
revenue(1) 158,928 4.67 154,054 4.94 3 (5)
Realized gain (loss)
on commodity
derivatives 860 0.03 1,421 0.05 (39) (40)
----------------------------------------------------------------------------
Total Natural Gas 159,788 4.70 155,475 4.99 3 (6)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liquids $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 42,679 51.05 31,723 36.86 35 38
Realized gain (loss)
on commodity
derivatives - - - - - -
----------------------------------------------------------------------------
Total Liquids 42,679 51.05 31,723 36.86 35 38
----------------------------------------------------------------------------

Oil $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 82,168 66.15 63,538 54.27 29 22
Realized gain (loss)
on commodity
derivatives (3,414) (2.75) 8,797 7.51 (139) (137)
----------------------------------------------------------------------------
Total Oil 78,754 63.40 72,335 61.78 9 3
----------------------------------------------------------------------------

Total $ $/Boe $ $/Boe $ $/Boe
Production revenue 283,775 36.60 249,315 34.47 14 6
Realized gain (loss)
on commodity
derivatives (2,554) (0.33) 10,218 1.41 (125) (123)
----------------------------------------------------------------------------
Total 281,221 36.27 259,533 35.88 8 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Natural gas revenue includes price risk management gains and losses on
physical sale contracts. For the nine months ended September 30, 2010,
our physical sale contracts resulted in a gain of $7.3 million (2009 -
$27.3 million gain).

 


For the three months ended September 30, 2010, revenues including realized commodity derivative gains and losses were $88.9 million, a 9% increase from $81.3 million for the same period in 2009. The increase in revenues for the three months ended September 30, 2010 compared to the same period of 2009 is primarily due to the increase in realized prices for natural gas and liquids and a 3% increase in total production partially offset by the decrease in realized oil prices. Revenues were comprised of $49.5 million of natural gas revenue, $12.8 million of liquids revenue, and $26.6 million of oil revenue. The increase in average realized commodity prices is comprised of a 9% increase in the natural gas price to $4.34/Mcf from $3.99/Mcf, a 24% increase in the liquids price to $48.92/Bbl from $39.58/Bbl and a decrease of 8% in the oil price to $61.20/Bbl from $66.17/Bbl.

For the nine months ended September 30, 2010, revenues including realized commodity derivative gains and losses were $281.2 million, an 8% increase from $259.5 million for the same period in 2009. The increase in revenues for the first nine months of 2010 compared to the same period of 2009 is primarily due to the increase in liquids and oil prices and a 7% increase in total production partially offset by the decrease in natural gas pricing. These revenues were comprised of $159.8 million of natural gas revenue, $42.7 million of liquids revenue, and $78.8 million of oil revenue. The increase in average realized commodity prices is comprised of a 6% decrease in the natural gas price to $4.70/Mcf from $4.99/Mcf, a 38% increase in the liquids price to $51.05/Bbl from $36.86/Bbl, and an increase of 3% in the oil price to $63.40/Bbl from $61.78/Bbl.



Commodity price risk management

Three months ended September 30,
---------------------------------------------------------------
($ thousands) 2010 2009
----------------------------------------------------------------------------
Total Total
Realized Unrealized Gain Realized Unrealized Gain
Gain (Loss) Gain (Loss) (Loss) Gain (Loss) Gain (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas 885 (404) 481 - - -
Oil (750) (1,473) (2,223) 1,811 32 1,843
----------------------------------------------------------------------------
Total gain
(loss) 135 (1,877) (1,742) 1,811 32 1,843
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Nine months ended September 30,
---------------------------------------------------------------
($ thousands) 2010 2009
----------------------------------------------------------------------------
Total Total
Realized Unrealized Gain Realized Unrealized Gain
Gain (Loss) Gain (Loss) (Loss) Gain (Loss) Gain (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas 860 2,955 3,815 1,421 (1,093) 328
Oil (3,414) 374 (3,040) 8,797 (14,194) (5,397)
----------------------------------------------------------------------------
Total gain
(loss) (2,554) 3,329 775 10,218 (15,287) (5,069)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


As part of our financial risk management strategy, NuVista has adopted a disciplined commodity price risk management program. The purpose of this program is to reduce volatility in our financial results, protect acquisition economics and help stabilize cash flow against the unpredictable commodity price environment. NuVista's Board of Directors has approved a price risk management limit of up to 60% of forecast production, net of royalties, using fixed price, differential, put option and costless collar contracts. To achieve NuVista's price risk management objectives, we enter into both commodity derivative and physical sale contracts.

For the three months ended September 30, 2010, the commodity price risk management program resulted in a loss of $1.7 million, consisting of realized gains of $0.1 million and a $1.9 million unrealized loss on natural gas and oil contracts. For the nine months ended September 30, 2010, the commodity price risk management program resulted in a gain of $0.8 million, consisting of realized losses of $2.5 million and an unrealized gain of $3.3 million on natural gas and oil contracts. As at September 30, 2010, the mark-to-market value of our financial derivative commodity contracts was a net asset of $0.7 million.

For the three months ended September 30, 2010, price risk management gains on our physical sale contracts totaled $3.8 million. For the nine months ended September 30, 2010, price risk management gains on our physical sale contracts totaled $7.3 million. The physical sale contracts are purchase and sale transactions entered into the normal course of business. As at September 30, 2010, the mark-to-market value of our natural gas physical sale contracts was a gain of $1.5 million. No asset or liability value has been assigned to the physical sale contracts on the balance sheet at September 30, 2010.

The following is a summary of commodity price risk management contracts in place as at September 30, 2010: 

(a) Financial instruments

As at September 30, 2010, NuVista has the following crude oil put option contracts in place: 



Average Option
Strike Price Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
4,000 Bbls/d $87.60 - WTI $9.22 October 1, 2010 - December 31, 2010
2,000 Bbls/d $85.60 - WTI $8.43 January 1, 2011 - March 31, 2011
1,000 Bbls/d $87.00 - WTI $9.00 April 1, 2011 - December 31, 2011

 


As at September 30, 2010, NuVista has the following NYMEX natural gas basis differential contracts in place:



Differential
Volume (US$/MMbtu) Term
----------------------------------------------------------------------------
20,000 MMbtu/d ($0.34) October 1, 2010 - October 31, 2010
25,000 MMbtu/d ($0.32) November 1, 2010 - March 31, 2011
40,000 MMbtu/d ($0.46) April 1, 2011 - October 31, 2011
30,000 MMbtu/d ($0.51) November 1, 2011 - March 31, 2012

 


As at September 30, 2010, the mark-to-market value of the financial derivative commodity contracts was a net asset of $0.7 million (December 31, 2009 - a liability of $2.6 million). 

Subsequent to September 30, 2010, the following financial derivative crude oil put option contract has been entered into:



Average Option
Strike Price Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
2,000 Bbls/d $88.55 - WTI $9.43 January 1, 2011 - March 31, 2012

(b) Physical sale contracts

(i) As at September 30, 2010, NuVista has the following direct natural gas
sale contracts in place:

Average Price Premium
Volume (Cdn$/GJ) (Cdn$/GJ) Term
----------------------------------------------------------------------------
20,000 GJ/d $5.97 - AECO Floor $0.53 October 1, 2010 -
October 31, 2010
5,000 GJ/d $4.21 - Fixed Price AECO October 1, 2010 -
October 31, 2010

(ii) As at September 30, 2010, NuVista has the following fixed price
contract for the purchase of electricity in place:

Volume Price (Cdn$/Mwh) Term
----------------------------------------------------------------------------
4.0 Mwh $65.64 January 1, 2011 - December 31, 2013

 


These physical sale contracts are documented as normal purchase and sale transactions and as such are not considered financial instruments.



Royalties

Three months ended Nine months ended
September 30, September 30,
-----------------------------------------
Royalty rates (%) 2010 2009 2010 2009
----------------------------------------------------------------------------
Natural gas and liquids 11 7 15 12
Oil 17 15 18 13
----------------------------------------------------------------------------
Weighted average rate 13 9 16 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


For the three months ended September 30, 2010, royalties were $11.8 million, 57% higher than the $7.5 million for the same period of 2009. Royalties for the nine months ended September 30, 2010 were $44.7 million compared to $31.0 million reported for the nine months ended September 30, 2009. The increase in royalties is largely attributed to a significant increase in oil production volumes that attract higher royalty rates and gas cost allowance adjustments.

As a percentage of production revenue, the reported average royalty rate for the three months ended September 30, 2010 was 13% compared to 9% for the comparative period of 2009. Royalty rates by product for the three months ended September 30, 2010 were 11% for natural gas and liquids and 17% for oil compared to 7% for natural gas and liquids and 15% for oil for the same period in 2009. For the nine months ended September 30, 2010, the average royalty rate as a percentage of production revenue was 16% compared to 12% for the same period in 2009. Royalty rates by product were 15% for natural gas and liquids and 18% for oil compared to 12% for natural gas and liquids and 13% for oil for the same period in 2009. The increase in royalty rates is primarily due to the impact of lower realized gains on physical sale contracts, a 22% increase in oil pricing and prior period adjustments.

Our physical price risk management activities impact reported royalty rates as royalties are based on government market reference prices and not our average realized prices that include price risk management activities. As a result, the gains on our price risk management activities included in production revenue result in lower royalty rates as a percentage of production revenue than if no price risk management activities had taken place. Excluding the impact of price risk management activities, third party adjustments relating to prior periods and gas cost allowance adjustments, natural gas and liquids royalty rates for the three months ended September 30, 2010 were approximately 15% compared to 14% for the same period in 2009 and the oil royalty rates for the three months ended September 30, 2010 were approximately 15% compared to 14% for the same period in 2009.

On March 11, 2010, the Government of Alberta announced amendments to its royalty framework as a result of a competitiveness review. Effective January 1, 2011, the maximum royalty rate is expected to be reduced from the current levels of 50% for both oil and natural gas to 40% for oil and 36% for natural gas. Other changes include permanently instating a maximum 5% royalty rate on oil and natural gas with the existing time and volume limits.

On May 27, 2010, the Government of Alberta announced its proposed changes to the base royalty curves for oil and natural gas which are to take effect on January 1, 2011. The Government also announced further initiatives designed to spur investment in Alberta's unconventional and deep resource pools. NuVista continues to monitor the amendments and the impacts on NuVista's business.

Netbacks - The table below summarizes field netbacks by product for the three months ended September 30, 2010: 



Natural gas
and liquids Oil Total
-------------------------------------------------
($ thousands, except
per unit amounts) 141.1 MMcfe/d 4,731 Bbl/d 28,244 Boe/d
----------------------------------------------------------------------------
$ $/Mcfe $ $/Bbl $ $/Boe
Production revenue 61,350 4.73 27,383 62.92 88,733 34.15
Realized gain (loss) on
commodity derivatives 885 0.07 (750) (1.72) 135 0.05
----------------------------------------------------------------------------
62,235 4.80 26,633 61.20 88,868 34.20
Royalties (7,035) (0.54) (4,754) (10.92) (11,789) (4.54)
Transportation costs (1,822) (0.14) (442) (1.02) (2,264) (0.87)
Operating costs (14,787) (1.14) (7,993) (18.37) (22,780) (8.77)
----------------------------------------------------------------------------
Field netback 38,591 2.98 13,444 30.89 52,035 20.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The following table summarizes field netbacks by product for the nine months ended September 30, 2010:



Natural gas
and liquids Oil Total
-------------------------------------------------------
($ thousands, except
per unit amounts) 143.1 MMcfe/d 4,550 Bbl/d 28,403 Boe/d
----------------------------------------------------------------------------
$ $/Mcfe $ $/Bbl $ $/Boe
Production revenue 201,607 5.16 82,168 66.15 283,775 36.60
Realized gain (loss)
on commodity
derivatives 860 0.02 (3,414) (2.75) (2,554) (0.33)
----------------------------------------------------------------------------
202,467 5.18 78,754 63.40 281,221 36.27
Royalties (30,118) (0.77) (14,542) (11.71) (44,660) (5.76)
Transportation costs (5,315) (0.14) (1,427) (1.15) (6,742) (0.87)
Operating costs (45,603) (1.17) (22,479) (18.10) (68,082) (8.78)
----------------------------------------------------------------------------
Field netback 121,431 3.10 40,306 32.44 161,737 20.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The tables below summarize funds from operations netbacks for the three months ended September 30, 2010 compared to the three months ended September 30, 2009, and the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009:



Three months ended September 30,
------------------------------------------------------
($ thousands, except
per unit amounts) 2010 2009 % Change
----------------------------------------------------------------------------
$ $/Boe $ $/Boe $ $/Boe
Production revenue 88,733 34.15 79,494 31.41 12 9
Realized gain (loss)
on commodity
derivatives 135 0.05 1,811 0.72 (93) (93)
----------------------------------------------------------------------------
88,868 34.20 81,305 32.13 9 6
Royalties (11,789) (4.54) (7,493) (2.96) 57 53
Transportation (2,264) (0.87) (2,062) (0.81) 10 7
Operating costs (22,780) (8.77) (22,249) (8.79) 2 -
----------------------------------------------------------------------------
Field netback 52,035 20.02 49,501 19.57 5 2
General and
administrative (4,869) (1.87) (3,768) (1.49) 29 26
Restricted stock
units (371) (0.14) (617) (0.24) (40) (42)
Interest (4,313) (1.66) (3,918) (1.55) 10 7
----------------------------------------------------------------------------
Funds from
operations netback 42,482 16.35 41,198 16.29 3 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Nine months ended September 30,
------------------------------------------------------
($ thousands, except
per unit amounts) 2010 2009 % Change
----------------------------------------------------------------------------
$ $/Boe $ $/Boe $ $/Boe
Production revenue 283,775 36.60 249,315 34.47 14 6
Realized gain (loss)
on commodity
derivatives (2,554) (0.33) 10,218 1.41 (125) (123)
----------------------------------------------------------------------------
281,221 36.27 259,533 35.88 8 1
Royalties (44,660) (5.76) (30,954) (4.28) 44 35
Transportation (6,742) (0.87) (6,221) (0.86) 8 1
Operating costs (68,082) (8.78) (61,149) (8.46) 11 4
----------------------------------------------------------------------------
Field netback 161,737 20.86 161,209 22.28 - (6)
General and
administrative (14,125) (1.82) (10,496) (1.45) 35 26
Restricted stock
units (856) (0.11) (1,215) (0.17) (30) (35)
Interest (12,420) (1.60) (9,859) (1.36) 26 18
----------------------------------------------------------------------------
Funds from
operations netback 134,336 17.33 139,639 19.30 (4) (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Transportation - Transportation costs were $2.3 million ($0.87/Boe) for the three months ended September 30, 2010 as compared to $2.1 million ($0.81/Boe) for the same period of 2009. Transportation costs were $6.7 million ($0.87/Boe) for the nine months ended September 30, 2010 compared to $6.2 million ($0.86/Boe) for the same period in 2009. The increase in year to date transportation costs, on a total dollar basis, in 2010 compared to 2009 is primarily due to an increase in oil production volumes and their higher associated transportation costs.

Operating - Operating expenses were $22.8 million ($8.77/Boe) for the three months ended September 30, 2010 as compared to $22.2 million ($8.79/Boe) for the three months ended September 30, 2009. The increase, on a total dollar basis, resulted primarily from slightly higher production and higher power and field costs related to acquisitions completed in 2009. For the three months ended September 30, 2010, natural gas and liquids operating costs averaged $1.14/Mcfe and oil operating expenses were $18.37/Bbl as compared to $1.24/Mcfe and $16.32/Bbl respectively for the same period in 2009. The decrease in 2010 natural gas and liquids operating costs is primarily due to the timing of chemical purchases.

Operating expenses were $68.1 million ($8.78/Boe) for the nine months ended September 30, 2010 as compared to $61.1 million ($8.46/Boe) for the nine months ended September 30, 2009. This increase resulted from a 7% increase in production volumes and a 4% increase in per unit costs. The per unit operating costs were higher in 2010 compared to the same period in 2009, due to higher operating cost structure associated with the oil properties purchased in July 2009 located in northwest Alberta. For the nine months ended September 30, 2010, natural gas and liquids operating expenses averaged $1.17/Mcfe and oil operating expenses were $18.10/Bbl as compared to $1.16/Mcfe and $16.31/Bbl respectively for the same period of 2009. NuVista is forecasting operating expenses to average $8.75/Boe for the last quarter of 2010.

General and administrative - General and administrative expenses, net of overhead recoveries, for the three months ended September 30, 2010 were $4.9 million ($1.87/Boe) compared to $3.8 million ($1.49/Boe) in the same period of 2009. General and administrative expenses, net of overhead recoveries, for the nine months ended September 30, 2010 were $14.1 million ($1.82/Boe) as compared to $10.5 million ($1.45/Boe) for the nine months ended September 30, 2009. This increase in general and administrative costs in 2010 compared to 2009 is primarily a result of increased staffing costs to support future growth. NuVista is forecasting 2010 general and administrative costs for the remainder of the year to average approximately $1.80/Boe.



Three months ended Nine months ended
September 30, September 30,
-----------------------------------------
($ thousands, except per unit
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Gross general and administrative
expenses 6,277 4,934 18,627 14,293
Overhead recoveries (1,408) (1,166) (4,502) (3,797)
----------------------------------------------------------------------------
Net general and administrative
expenses 4,869 3,768 14,125 10,496
----------------------------------------------------------------------------
Per Boe 1.87 1.49 1.82 1.45
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation

Three months ended Nine months ended
September 30, September 30,
-----------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Stock-based compensation 1,569 1,316 4,677 4,670
Restricted stock units 371 617 856 1,215
----------------------------------------------------------------------------
Total 1,940 1,933 5,533 5,885
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


NuVista recorded a stock-based compensation charge of $1.9 million for the three months ended September 30, 2010 compared to $1.9 million for the same period in 2009. For the nine months ended September 30, 2010, NuVista recorded a stock-based compensation charge of $5.5 million compared to $5.9 million for the same period in 2009. The stock-based compensation charge relates to the amortization of the fair value of stock option awards and the accrual for future payments under the Restricted Stock Unit ("RSU") Incentive Plan. 

Interest - Interest expense for the three months ended September 30, 2010 was $4.3 million ($1.66/Boe) compared to $3.9 million ($1.55/Boe) for the same period of 2009. For the nine months ended September 30, 2010, interest expense was $12.4 million ($1.60/Boe) compared to $9.9 million ($1.36/Boe) in the same period of 2009. For the three months ended September 30, 2010, borrowing costs averaged 3.56% compared to 3.25% in the same period of 2009. Currently, NuVista's average borrowing rate is approximately 4.25%. Cash paid for interest for the three and nine months ended September 30, 2010 was $4.3 million (2009 - $4.0 million) and $12.6 million (2009 - $9.5 million) respectively.

Depreciation, depletion and accretion - Depreciation, depletion and accretion expenses were $45.3 million for the third quarter of 2010 as compared to $43.8 million for the same period in 2009. The average per unit cost was $17.42/Boe in the third quarter of 2010 as compared to $17.31/Boe for the same period in 2009. Depreciation, depletion and accretion expenses for the nine months ended September 30, 2010 were $132.1 million as compared to $128.7 million for the same period in 2009. The average per unit cost was $17.04/Boe in the first three quarters of 2010 as compared to $17.80/Boe in the same period in 2009. The decrease in per unit cost for the nine months ended September 30, 2010 compared to the same period in 2009 is primarily attributable to the low cost of reserves added from acquisitions in the last twelve months.

Income taxes - For the three months ended September 30, 2010, the provision for income and other taxes was a recovery of $1.2 million compared to a recovery of $0.5 million for the same period in 2009. The change is primarily a result of an increase in the net loss for the three months ended September 30, 2010. For the nine months ended September 30, 2010, the provision for income and other taxes was an expense of $1.4 million compared to a recovery of $1.0 million in the same period of 2009.

Capital expenditures - Capital expenditures were $79.6 million during the third quarter of 2010, consisting of $23.4 million of acquisitions and $56.2 million of exploration and development spending (net of drilling credits). This compares to $189.5 million incurred for the same period of 2009, consisting of $173.4 million of acquisitions and exploration and development spending (net of drilling credits) of $16.1 million. Capital expenditures for the nine months ended September 30, 2010 were $196.5 million, consisting of $23.4 million of acquisitions and $173.1 million of exploration and development spending (net of drilling credits). This compares to $279.1 million incurred for the same period of 2009, consisting of $227.5 million of acquisitions and exploration and development spending (net of drilling credits) of $51.6 million.



Three months ended Nine months ended
September 30, September 30,
($ thousands, except per unit -----------------------------------------
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Exploration and development
Land and retention costs 1,449 1,242 18,698 3,017
Seismic 1,574 2,300 10,307 6,790
Drilling and completion 48,231 12,473 125,252 30,001
Facilities and equipment 11,728 3,015 34,781 16,528
Corporate and other 30 316 87 807
----------------------------------------------------------------------------
Subtotal 63,012 19,346 189,125 57,143
----------------------------------------------------------------------------
Alberta drilling incentive credits (6,774) (3,209) (16,001) (5,535)
----------------------------------------------------------------------------
Subtotal 56,238 16,137 173,124 51,608
----------------------------------------------------------------------------
Property acquisitions 23,391 173,371 23,391 227,446
----------------------------------------------------------------------------
Net capital expenditures 79,629 189,508 196,515 279,054
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


On July 27, 2009, NuVista closed the acquisition of certain properties in northeast British Columbia and northwest Alberta for a cash purchase price of $172.3 million, net of final adjustments. The acquisition was financed through a combination of bank debt and net proceeds from two equity offerings. NuVista entered into an agreement to issue 7,500,000 subscription receipts at a price of $11.00 per subscription receipt on a bought deal basis for gross proceeds of $82.5 million. In addition, NuVista issued 1,500,000 subscription receipts at a price of $11.00 per subscription receipt, by way of a private placement, to Ontario Teachers' Pension Plan Board ("OTPP") for gross proceeds of $16.5 million. The subscription receipt offerings closed on July 7, 2009. Each subscription receipt was exchanged for one common share of NuVista for no additional consideration on July 27, 2009 in accordance with its terms.

Net earnings and funds from operations - For the three months ended September 30, 2010, the net loss increased to $5.0 million ($0.06/share, basic) from a net loss of $3.3 million ($0.04/share, basic) for the same period in 2009. NuVista's net loss for the nine months ended September 30, 2010 was $0.6 million ($0.01/share, basic) compared to a net loss of $8.0 million ($0.10/share, basic) in the same period in 2009. Net earnings for the nine months ended September 30, 2010 increased compared to the same period in 2009 primarily due to the impact of higher production revenues.

For the three months ended September 30, 2010, NuVista's funds from operations were $42.5 million ($0.48/share, basic), a 3% increase from $41.2 million ($0.48/share, basic) for the three months ended September 30, 2009. Funds from operations for the three months ended September 30, 2010 were higher than the same period in 2009 primarily due to higher natural gas and liquids prices and a 3% increase in total production offset by increased royalties. For the nine months ended September 30, 2010, NuVista's funds from operations were $134.3 million ($1.52/share, basic), a 4% decrease from $139.6 million ($1.72/share, basic) in the same period of 2009.


Liquidity and capital resources

September 30, December 31,
($ thousands) 2010 2009
----------------------------------------------------------------------------
Common shares outstanding 88,642 88,361
Share price(1) 10.43 12.48
----------------------------------------------------------------------------
Total market capitalization 924,536 1,102,745
----------------------------------------------------------------------------
Adjusted working capital (surplus)
deficit(2) 4,842 (16,876)
Bank debt 442,119 384,623
----------------------------------------------------------------------------
Debt, net of adjusted working capital
("Net Debt") 446,961 367,747
----------------------------------------------------------------------------
Funds from operations (annualized third
quarter)(2) 169,928 201,996
----------------------------------------------------------------------------
Net Debt to total funds from operations 2.6 1.8
----------------------------------------------------------------------------
Net Debt as a percentage of total
capitalization 48% 33%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Represents the closing price on the TSX on September 30 and December 31.
(2) Refer to the "non-GAAP measurements" disclosure in the MD&A.

 


As at September 30, 2010, debt net of adjusted working capital was $447.0 million, resulting in a net debt to annualized third quarter funds from operations ratio of 2.6:1. As at September 30, 2010, the net debt to the trailing twelve months funds from operations ratio was 2.4:1. At September 30, 2010, NuVista had an adjusted working capital deficit of $4.8 million. Adjusted working capital excludes the current portion of the fair value of the commodity derivative liability of $1.6 million and the current portion of future income tax asset of $0.6 million. We believe it is appropriate to exclude these amounts when assessing financial leverage. At September 30, 2010, NuVista had $67.9 million of unused bank borrowing capacity based on the current credit facility of $510 million. 

On April 29, 2010, NuVista completed the annual renewal of its credit facility. NuVista's lenders approved a request for a revolving extendible credit facility totaling $510 million. Borrowing under the credit facility may be made by prime loans, bankers' acceptances and/or US libor advances. These advances bear interest at the bank's prime rate and/or at money market rates plus a stamping fee. The credit facility is secured by a first floating charge debenture, general assignment of book debts and NuVista's oil and natural gas properties and equipment. The credit facility has a 364-day revolving period and is subject to an annual review by the lenders, at which time a lender can extend the revolving period or can request conversion to a one year term loan. During the revolving period, a determination of the maximum borrowing amount occurs semi-annually on or before October 31. NuVista has completed the semi-annual review of its borrowing base with its lenders and the lenders have approved the continuation of the maximum borrowing amount of $510 million. During the term period, no principal payments would be required until April 28, 2012. As such, this credit facility is classified as long-term. As at September 30, 2010, NuVista had drawn $442.1 million on the facility.

At September 30, 2010, NuVista's bank debt net of adjusted working capital increased to $447.0 million compared to $405.9 million at June 30, 2010. This increase is attributable to the capital expenditures incurred in the third quarter which were greater than third quarter cash flow. NuVista plans to closely monitor its 2010 business plan and adjust its capital program in the context of commodity prices and access to bank and equity capital.

As at September 30, 2010, there were 88.6 million common shares outstanding. In addition, there were 7.3 million stock options outstanding, with an average exercise price of $12.64 per share.

Contractual obligations and commitments - NuVista enters into contract obligations as part of conducting business. The following is a summary of NuVista's contractual obligations and commitments as at September 30, 2010:



Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Transportation $19,478 $1,544 $5,248 $4,011 $3,768 $3,288 $1,619
Office lease 4,318 519 2,076 1,723 - - -
Physical sale
contract premiums 329 329 - - - - -
Drilling rig
contract 1,498 567 931 - - - -
Physical power
contract 6,900 - 2,300 2,300 2,300 - -
Long-term debt 442,119 - - 442,119 - - -
----------------------------------------------------------------------------
Total commitments $474,642 $2,959 $10,555 $450,153 $6,068 $3,288 $1,619
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Off balance sheet arrangements - NuVista has no off balance sheet arrangements except for certain lease arrangements. NuVista has certain lease arrangements, all of which are reflected in the contractual obligations and commitments table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet at September 30, 2010. 

Dividends - In the third quarter of 2010, our Board of Directors declared a quarterly cash dividend of $0.05 per common share which was paid on October 15, 2010 to shareholders of record on September 30, 2010. Dividends paid to shareholders of common shares have been designated as "eligible dividends" for Canadian tax purposes. NuVista implemented a dividend re-investment plan ("DRIP") for Canadian shareholders in early June 2010, whereby common shareholders can elect to receive their dividends in shares. The number of shares issued is based on 97 percent of the average market price being the weighted average trading prices of the shares for the 10 consecutive days immediately prior to the dividend payment date. A complete copy of the DRIP is available by following the "Dividend Information" link on the "Investors" page of NuVista's website at www.nuvistaenergy.com or from Valiant Trust by calling 1-866-313-1872. On July 15, 2010, NuVista paid the quarterly cash dividend declared in the second quarter of 2010 for shareholders of record on June 30, 2010 and issued 70,688 common shares in payment of $0.8 million of dividends for shareholders that elected to participate in the DRIP.

On November 10, 2010, our Board of Directors declared a quarterly dividend of $0.05 per common share, payable in cash, to shareholders of record on December 31, 2010, with the dividend payment on January 17, 2011.

Relationship with Bonavista Petroleum Ltd. - NuVista and Bonavista Petroleum Ltd. ("Bonavista") are considered related as two directors of NuVista, one of whom is NuVista's chairman, are directors and officers of Bonavista and another director of NuVista is also an officer of Bonavista. For the three months ended September 30, 2010, overhead recoveries of $0.1 million were charged to Bonavista for our jointly owned partnership (2009 - $0.3 million) which are included as a reduction in general and administrative expenses. For the nine months ended September 30, 2010 overhead recoveries of $0.3 million were charged to Bonavista for our jointly owned partnership (2009 - $1.0 million). As at September 30, 2010, the amount receivable from Bonavista was $0.4 million (2009 - $0.4 million). These transactions are considered to be in the normal course of business and have been measured at their exchange amounts, being the amounts agreed to by both parties.

Quarterly financial information - The following table highlights NuVista's performance for the eight quarterly reporting periods from December 31, 2008 to September 30, 2010: 



($ thousands,
except per
share 2010 2009 2008
amounts) Sep 30 Jun 30 Mar 31 Dec 31 Sep 30 Jun 30 Mar 31 Dec 31
----------------------------------------------------------------------------
Production
(Boe/d) 28,244 28,512 28,455 28,345 27,505 25,777 26,175 25,688

Production
revenue 88,733 89,524 105,519 95,957 79,494 78,092 91,729 106,982
Net earnings
(loss) (5,025) (1,377) 5,830 10,498 (3,342) (7,312) 2,632 24,443
Net earnings
(loss)
Per share
- basic (0.06) (0.02) 0.07 0.12 (0.04) (0.09) 0.03 0.31
Per share
- diluted (0.06) (0.02) 0.07 0.12 (0.04) (0.09) 0.03 0.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


NuVista has seen production volumes in a range of 25,688 Boe/d to 28,512 Boe/d for the last eight quarters as incremental production from our exploration and development capital program and acquisitions have more than offset normal production declines. Over the prior eight quarters, quarterly revenue has been in a range of $78.1 million to $107.0 million with revenue primarily influenced by production volumes and commodity prices in the quarter. Net earnings have been in a range of a net loss of $7.3 million to net earnings of $24.4 million with earnings primarily influenced by production volumes, commodity prices and realized and unrealized gains and losses on commodity derivatives. 

Critical accounting estimates - The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. Certain accounting policies are critical to understanding the financial condition and results of operations of NuVista.

(a) Proved oil and natural gas reserves - Proved oil and natural gas reserves, as defined by the Canadian Securities Administrators in National Instrument 51-101 with reference to the Canadian Oil and Natural Gas Evaluation Handbook, are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

An independent reserve evaluator using all available geological and reservoir data as well as historical production data has prepared NuVista's oil and natural gas reserve estimates. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in NuVista's development plans. The effect of changes in proved oil and natural gas reserves on the financial results and position of NuVista is described below.

(b) Depreciation, depletion and accretion expense - NuVista uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproved properties, and estimated future development costs is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development costs have a direct impact on depreciation and depletion expense. 

Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion calculation, or for impairment, for which any write-down would be charged to depreciation and depletion expense. 

(c) Full cost accounting ceiling test - The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the asset is not recoverable by the future undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion and depreciation expense. 

(d) Asset retirement obligation - The asset retirement obligations are estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonments and reclamations discounted at a credit adjusted risk free rate. The costs are included in property, plant and equipment and amortized over its useful life. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings and for revisions to the estimated future cash flows. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

(e) Income taxes - The determination of income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.

(f) Financial Instruments - NuVista utilizes financial instruments to manage the exposure to market risks relating to commodity prices. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices and foreign currency exchange rates.

(g) Goodwill - Goodwill is recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance is not amortized, however, and must be assessed for impairment at least annually. Impairment is initially determined based on the fair value of a reporting unit compared to its book value. Any impairment must be charged to earnings in the period the impairment occurs. NuVista has one reporting unit, being the entity as a whole, and as at September 30, 2010, we have determined there was no goodwill impairment.

Update on regulatory matters 

Information regarding environmental and climate change regulations, the Government of Alberta's New Royalty Framework and other current provincial royalty and incentive programs are contained in our Annual Information Form for the year ended December 31, 2009 under the Industry Conditions Section.

Update on financial reporting matters

International Financial Reporting Standards ("IFRS") - On January 1, 2011, IFRS will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011, will require the restatement, for comparative purposes, of amounts reported by NuVista for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.

In order to meet the requirement to transition to IFRS, NuVista has appointed internal staff to lead the conversion project along with sponsorship from an executive steering committee. NuVista will continue to involve external auditors and external consultants, as required, during the conversion project. Regular progress reporting to the Audit Committee of the Board of Directors on the status of the IFRS conversion has been implemented. NuVista has held three special Audit Committee update meetings on IFRS in 2010 and anticipates a further meeting in the last quarter of 2010. NuVista is continuing the process of training key personnel within the accounting and finance functions as well as the management team. NuVista is on schedule with its conversion project and expects to be completed in time to meet its 2011 financial reporting requirements.

As of September 30, 2010, NuVista has made significant progress on its conversion project. NuVista has analyzed accounting policy alternatives and drafted the majority of our IFRS accounting policies. Process and system changes have been implemented for significant areas of impact, while adhering to existing internal control requirements. Information system changes have been tested and implemented to capture the required 2010 comparative data.

NuVista is in the process of completing its January 1, 2010, IFRS opening balance sheet. In addition, NuVista is preparing the March 31, 2010 and June 30, 2010 comparative IFRS financial information. NuVista's external auditors have reviewed its IFRS accounting policies and are in the process of completing audit procedures on the IFRS opening balance sheet. NuVista will continue to update its IFRS conversion project to reflect new and amended accounting standards issued by the International Accounting Standards Board ("IASB").

In July 2009, the IASB issued amendments to IFRS 1 - First-Time Adoption of International Financial Reporting Standards ("IFRS 1"). IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management continues to analyze the various accounting policy choices available and will implement those determined to be the most appropriate for NuVista which include:

- Business Combinations - IFRS 1 would allow NuVista to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations. The IFRS business combination rules converge with the new CICA Handbook section 1582 that is also effective for NuVista on January 1, 2011.

- Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option to value PP&E assets in the Exploration and Evaluation ("E&E") and development and production ("D&P") phases at their deemed cost, defined as carrying value assigned to these assets under Canadian GAAP at the date of transition, January 1, 2010. This amendment is permissible for entities, such as NuVista, who currently follow the full cost accounting guideline under Canadian GAAP that accumulates all oil and gas assets into one cost centre. Under IFRS, NuVista's PP&E assets in the D&P phases must be divided into cash generating units ("CGUs"). The deemed cost of NuVista's PP&E assets has been allocated to the CGUs based on proved plus probable reserve values. These values will be subject to an impairment test at transition.

The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect NuVista's reported financial position and results of operations. At this time, NuVista has identified key differences that will impact the financial statements as follows: 

- Re-classification of E&E expenditures from PP&E - Upon transition to IFRS, NuVista will re-classify all E&E expenditures that are currently included in the PP&E balance on the Consolidated Balance Sheet. This will consist of the book value of undeveloped land that relates to exploration properties and other exploration related activities. E&E assets will not be depleted and must initially be assessed for impairment when indicators suggest the possibility of impairment as well as upon transition. NuVista has currently determined approximately $130 million of PP&E will be classified as E&E in the opening balance sheet prepared under IFRS as at January 1, 2010.

- Impairment of PP&E assets - Under IFRS, impairment of PP&E must be calculated at a more detailed level than what is currently required under Canadian GAAP. Impairment calculations will be performed at the CGU level as opposed to one impairment test for the entire PP&E balance required under current Canadian GAAP. Under IFRS, NuVista is required to compare carrying values directly with the higher of fair value less cost of sales and value in use for impairment testing of PP&E. NuVista has determined its CGUs for the purpose of impairment testing and anticipates using discounted proved plus probable reserves values for impairment tests of PP&E. NuVista does not anticipate its PP&E assets to be impaired as at January 1, 2010 under IFRS.

- Impairment of goodwill - Under IFRS, goodwill that arises from a business combination is allocated to the specific CGUs that are expected to benefit from the business combination. To test for impairment of goodwill, the carrying value of the CGU including goodwill is compared to the fair value of the CGU. As the goodwill impairment test is performed at a more refined level under IFRS, NuVista anticipates recognizing an impairment of approximately $25 million of its goodwill on its opening balance sheet with the charge being reflected in opening retained earnings.

- Calculation of depletion expense for PP&E assets - Upon transition to IFRS, in addition to calculating depletion at a component level, NuVista has the option to calculate depletion using a reserve base of proved reserves or both proved and probable reserves, as compared to the Canadian GAAP method of calculating depletion using only proved reserves. NuVista plans to determine its depletion expense using proved plus probable reserves as its depletion base. As a result, NuVista's depletion cost may vary from the amount that would have been calculated under Canadian GAAP.

- Provisions for asset retirement obligations - IFRS requires that NuVista revalue its entire asset retirement obligation at each balance sheet date using a current liability specific discount rate. Under Canadian GAAP, once recorded, asset retirement obligations are not adjusted for future changes in discount rates. IAS 37 - Provisions, Contingent Liabilities and Contingent Assets and the Exposure Draft Measurement of Liabilities in IAS 37 are unclear as to whether the liability specific discount rate should include a credit adjustment for an entity's own credit risk. If the liability specific discount rate is defined as a risk free rate, NuVista's asset retirement obligation would increase under IFRS. If a credit-adjusted rate is used, the liability will approximate that recorded under Canadian GAAP. Management continues to monitor correspondence from the IASB regarding clarification of the appropriate discount rate to use in the measurement of the provisions.

- Interests in joint ventures - Under IFRS, interests in joint ventures must be accounted for by an entity either using the equity method or proportionate consolidation. The IASB is proposing to issue a final standard on Interests in Joint Ventures before the end of 2010. Management will continue to monitor correspondence from the IASB regarding the accounting treatment of joint ventures and the applicability to NuVista.

- Calculation of income taxes - In transitioning to IFRS, NuVista's future tax liability will be impacted by the tax effects resulting from the IFRS changes discussed above. Due to the withdrawal of the exposure draft on IAS 12 Income Taxes in November 2009 and the issuance of the exposure draft on IAS 37 - Provisions, Contingent Liabilities and Contingent Assets in January 2010, management is still determining the impact of these revised standards on its IFRS transition.

In addition to the accounting policy differences, NuVista's transition to IFRS will impact the internal controls over financial reporting, disclosure controls and procedures, certain of NuVista's business activities and information technology ("IT") systems as follows:

- Internal controls over financial reporting - As the review and analysis of NuVista's accounting policies is completed, an assessment will be made to determine changes required to internal controls over financial reporting. This will be an ongoing process in 2010 to ensure that changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.

- Disclosure controls and procedures - NuVista has assessed the impact of transition to IFRS on its disclosure controls and procedures and has not identified any material changes required in its control environment. It is expected that there will be increased note disclosure around certain financial statement items than what is currently required under Canadian GAAP. Management will draft its IFRS note disclosure in accordance with current IFRS standards and will continue to monitor requirements put forth by the IASB in discussion papers and exposure drafts for future disclosure requirements. Throughout the transition process, NuVista has been assessing its stakeholders' information requirements and will ensure that adequate and timely information is provided to meet these needs.

- Business activities - NuVista expects that IFRS will not have a major impact on our operations or strategic decisions. Management has been cognizant of the upcoming transition to IFRS and as such has worked with its lenders to ensure any references to Canadian GAAP financial statements in the lending agreement have been modified to allow for IFRS statements. Based on the expected changes to NuVista's accounting policies at this time, there are no foreseen issues with the existing wording of the agreement as a result of the conversion to IFRS. NuVista will continue to work with its other counterparties to ensure that any agreements that contain references to Canadian GAAP financial statements are modified to allow for IFRS statements.

- IT Systems - NuVista has completed most of the system updates required in order to prepare NuVista for IFRS reporting. The modifications while not significant, were deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as the modifications required to track PP&E costs and E&E costs in more detail for IFRS reporting. NuVista continues to assess other system modifications that may be required based on final accounting policy choices, in order to perform ongoing calculations and analysis under IFRS. These changes are not considered to be significant.

Internal control reporting

NuVista's President and Chief Executive Officer ("CEO") and Vice President, Finance and Chief Financial Officer ("CFO") are responsible for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting as defined in National Instrument 52-109. NuVista's CEO and CFO have designed disclosure controls and procedures, or caused them to be designed under their supervision, to provide reasonable assurance that information required to be disclosed by NuVista in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by NuVista in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to NuVista's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.

The CEO and CFO have also designed internal controls over financial reporting, or caused them to be designed under their supervision, to provide reasonable assurance regarding the reliability of NuVista's financial reporting and the preparation of financial statements for external purposes in accordance with NuVista's GAAP and includes those policies and procedures that: (a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of NuVista; (b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with NuVista's GAAP, and that receipts and expenditures of NuVista are being made only in accordance with authorizations of management and directors of NuVista; and (c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of NuVista's assets that could have a material effect on the annual financial statements or interim financial statements. NuVista has designed its internal controls over financial reporting based on the framework in "Internal Control Over Financial Reporting - Guidance for Smaller Public Companies" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). During the quarter ended September 30, 2010, there have been no changes to NuVista's internal control over financial reporting that have materially or are reasonably likely to materially affect the internal control over financial reporting. 

Because of their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, error or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance, that the objectives of the control system are met.

Assessment of business risks

Information regarding risk factors associated with the business of NuVista and how NuVista seeks to mitigate these risks are contained in our Annual Information Form under the Risk Factors Section and in our Annual Report for the year ended December 31, 2009.

OUTLOOK 

NuVista's 2010 and First Half 2011 Exploration and Development Capital Programs

Although the current natural gas price and financial markets create considerable uncertainty in the near term, NuVista is in a position to control and prudently manage its capital program. Our near term capital program is heavily weighted towards internally generated and operated capital projects with a higher liquid component leading to stronger cash flows. Returns for these projects remain highly attractive in the current commodity price environment. NuVista will continue to test concept plays that can deliver an attractive return on capital and have significant leverage to multi-year repeatable development projects on large contiguous blocks of land, while maintaining financial flexibility in an uncertain natural gas price environment. With weaker than initially forecast natural gas prices resulting in lower projected cash flow, NuVista is reducing its planned 2010 capital program to approximately $230 million with approximately 85% of this capital dedicated to exploration and development expenditures. Production for 2010 is now expected to average approximately 28,300 Boe/d.

NuVista's Board of Directors have approved a capital budget of $60 million for the first half of 2011. NuVista plans to spend less than forecast cash flow at strip prices, maintain production in the current range, and increase our liquids production by 15%. NuVista's focus in the first half of 2011 will be on increasing its cash flow and netbacks by focusing on light and heavy oil projects, our two highest netback products, rather than natural gas production growth. In the first half of 2011, over 80% of NuVista's operated capital expenditures are planned to be directed towards oil targets and the only concept test well is expected to be a second Wapiti Montney well on our northern block. 

With its extensive land base and its associated resource plays, NuVista continues to position the company for significant growth in future years. Given the uncertain outlook for natural gas prices, NuVista plans to limit spending to available cash flow until the outlook for natural gas pricing improves. In the second half of 2011, with the continued testing of concept wells and subject to the outlook for natural gas prices at the time, NuVista will adjust its capital program as required. All capital expenditures in 2011 are planned to be on internally generated exploration and development activities, with over 60% of planned capital expenditures targeting oil projects in our Deep Basin and W3M/W4M core regions and the remainder targeting liquid-rich natural gas opportunities in our Deep Basin core region. 

In 2011, the primary focus areas for the company are expected to include Cardium light oil (Wapiti/Pembina-Ferrier), Birdbear heavy oil development and exploration (West Central Saskatchewan) and Montney (Wapiti) delineation. In each of these areas, NuVista's drilling program is being designed to provide stronger cash flow and the potential to book multiple locations for each well drilled as part of a multi-year program targeting top quartile reserve addition costs. NuVista remains confident that despite a decrease in activity directed toward the concept testing of plays due to the current weak natural gas prices, prices will eventually improve to a level where de-risking can continue and the next five years of NuVista's future will become more defined.

Sincerely,



Alex G. Verge Robert F. Froese
President & CEO Vice-President, Finance & CFO
November 10, 2010


NUVISTA ENERGY LTD.

Consolidated Balance Sheets

($ thousands) September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
(unaudited)


Assets
Current assets
Cash and cash equivalents $ - $ -
Accounts receivable and prepaids 60,604 69,238
Future income taxes 627 1,336
----------------------------------------------------------------------------
61,231 70,574

Commodity derivative asset
(note 6) 2,326 -
Oil and natural gas properties and
equipment 1,475,044 1,401,453
Goodwill 83,716 83,716
----------------------------------------------------------------------------
1,622,317 1,555,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders'
Equity
Current liabilities
Accounts payable and accrued
liabilities 61,014 52,362
Dividends payable (note 5) 4,432 -
Commodity derivative liability
(note 6) 1,590 2,593
----------------------------------------------------------------------------
67,036 54,955

Long-term debt (note 4) 442,119 384,623
Compensation liability (note 5) 881 604
Asset retirement obligations
(note 3) 62,498 61,816
Future income taxes 135,139 134,052
Shareholders' equity
Share capital and contributed
surplus (note 5) 712,767 703,959
Retained earnings 201,877 215,734
----------------------------------------------------------------------------
914,644 919,693
----------------------------------------------------------------------------
$ 1,622,317 $ 1,555,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Contractual obligations and commitments (note 8)

See accompanying notes to consolidated financial statements.


NUVISTA ENERGY LTD.

Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss) and
Retained Earnings

Three months ended Nine months ended
September 30, September 30,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
(unaudited)

Revenues
Production $ 88,733 $ 79,494 $ 283,775 $ 249,315
Royalties (11,789) (7,493) (44,660) (30,954)
Realized gain (loss) on
commodity derivatives 135 1,811 (2,554) 10,218
Unrealized gain (loss) on
commodity derivatives (1,877) 32 3,329 (15,287)
----------------------------------------------------------------------------
75,202 73,844 239,890 213,292
----------------------------------------------------------------------------

Expenses
Operating 22,780 22,249 68,082 61,149
Transportation 2,264 2,062 6,742 6,221
General and administrative
(note 7) 4,869 3,768 14,125 10,496
Interest 4,313 3,918 12,420 9,859
Stock-based compensation
(note 5) 1,940 1,933 5,533 5,885
Depreciation, depletion and
accretion 45,269 43,796 132,122 128,714
----------------------------------------------------------------------------
81,435 77,726 239,024 222,324
----------------------------------------------------------------------------
Earnings (loss) before income
and other taxes (6,233) (3,882) 866 (9,032)
Future income tax expense
(recovery) (1,208) (540) 1,438 (1,010)
----------------------------------------------------------------------------

Net earnings (loss) and
Comprehensive income
(loss) (5,025) (3,342) (572) (8,022)

Retained earnings, beginning
of period 211,334 208,578 215,734 213,258
Dividends (note 5) (4,432) - (13,285) -
----------------------------------------------------------------------------
Retained earnings, end
of period $ 201,877 $ 205,236 $ 201,877 $ 205,236
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings (loss) per
share - basic $ (0.06) $ (0.04) $ (0.01) $ (0.10)
----------------------------------------------------------------------------
Net earnings (loss) per
share - diluted $ (0.06) $ (0.04) $ (0.01) $ (0.10)
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


NUVISTA ENERGY LTD.

Consolidated Statement of Cash Flows

Three months ended Nine months ended
September 30, September 30,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
(unaudited)

Cash provided by (used in)
Operating Activities
Net earnings (loss) $ (5,025) $ (3,342) $ (572) $ (8,022)
Items not requiring cash from
operations
Depreciation, depletion and
accretion 45,269 43,796 132,122 128,714
Stock-based compensation 1,569 1,316 4,677 4,670
Unrealized (gain) loss on
commodity derivatives 1,877 (32) (3,329) 15,287
Future income tax expense
(recovery) (1,208) (540) 1,438 (1,010)
Asset retirement expenditures (764) (654) (7,077) (1,843)
Change in non-cash working
capital items 3,266 (7,692) (2,521) (7,004)
----------------------------------------------------------------------------
44,984 32,852 124,738 130,792
----------------------------------------------------------------------------

Financing Activities
Issue of share capital, net of
share issuance costs 231 95,271 1,938 96,072
Increase in long-term debt 31,057 34,225 57,496 55,123
Cash dividends (3,664) - (8,090) -
----------------------------------------------------------------------------
27,624 129,496 51,344 151,195
----------------------------------------------------------------------------

Investing Activities
Oil and natural gas properties
and equipment (56,238) (16,137) (173,124) (51,608)
Property acquisition (23,391) (173,371) (23,391) (227,446)
Deposit on property acquisition
(note 2) - 18,084 - -
Change in non-cash working
capital items 7,021 9,076 20,433 (3,072)
----------------------------------------------------------------------------
(72,608) (162,348) (176,082) (282,126)
----------------------------------------------------------------------------
Change in cash and cash
equivalents - - - (139)
Cash and cash equivalents,
beginning of period - - - 139
----------------------------------------------------------------------------
Cash and cash equivalents, end
of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

 


NUVISTA ENERGY LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Three and nine months ended September 30, 2010. 

The unaudited consolidated financial statements of NuVista Energy Ltd. ("NuVista" or "the Company") have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"), using the same accounting policies as those set out in note 1 to the consolidated financial statements for the year ended December 31, 2009. The consolidated financial statements for the three and nine months ended September 30, 2010, should be read in conjunction with the annual audited consolidated financial statements for the year ended December 31, 2009. Certain amounts have been reclassified to conform with the current year's presentation. All tabular amounts are in thousands, except per share amounts, unless otherwise stated. 

1. Accounting changes

(a) Business Combinations

In January 2009, the CICA issued Section 1582, "Business Combinations". This section is effective January 1, 2011 and applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after January 1, 2011. Early adoption is permitted. This section replaces Section 1581, "Business Combinations" and harmonizes the Canadian standards with IFRS.

(b) Consolidated Financial Statements and Non-Controlling Interests

In January 2009, the AcSB issued Section 1601, "Consolidated Financial Statements", and Section 1602, "Non-Controlling Interests", which together replace Section 1600, "Consolidated Financial Statements", and harmonize the Canadian standards with IFRS. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These sections are effective for the first reporting period beginning on or after January 1, 2011. Early adoption is permitted. 

2. Acquisitions

(a) Ferrier, Sunchild, Wapiti and Northwest Saskatchewan Properties

On January 29, 2009, the Company acquired certain natural gas properties and related facilities in the Ferrier/Sunchild, Wapiti and northwest Saskatchewan operating areas. The cash purchase price was $55.6 million, net of final adjustments. The results of operations of these properties have been included in the consolidated financial statements of the Company since the acquisition date.

(b) Northeast British Columbia and Northwest Alberta Properties

On July 27, 2009, the Company acquired certain natural gas properties and related facilities in the Martin Creek area of northeast British Columbia and northwest Alberta for a cash purchase price of $172.3 million, net of final adjustments. The results of operations of these properties have been included in the consolidated financial statements of the Company since the acquisition date.

3. Asset retirement obligations

Total asset retirement obligations are based on estimated costs to reclaim and abandon ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities. At September 30, 2010, the estimated total undiscounted amount of cash flows required to settle the Company's asset retirement obligations is $235 million (2009 - $262 million), which will be incurred over the next 51 years. The majority of the costs will be incurred between 2011 and 2030. A credit-adjusted risk-free rate of 8% (2009 - 8%) and an inflation rate of 2% (2009 - 2%) were used to calculate the fair value of the asset retirement obligations. The change in assumptions are primarily due to changes in the timing of abandonment expenditures.



A reconciliation of the asset retirement obligations is provided below:

September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of period 61,816 46,296
Accretion expense 3,484 4,100
Liabilities incurred 3,816 4,050
Liabilities acquired 378 9,985
Revisions 81 -
Liabilities settled (7,077) (2,615)
----------------------------------------------------------------------------
Balance, end of period 62,498 61,816
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


4. Long-term debt 

In April 2010, the Company completed the annual renewal of its credit facility. The Company's lenders approved a request for a revolving extendible credit facility totaling $510 million. Borrowing under the credit facility may be made by prime loans, bankers' acceptances and/or US libor advances. These advances bear interest at the bank's prime rate and/or at money market rates plus a stamping fee. The credit facility is secured by a first floating charge debenture, general assignment of book debts and the Company's oil and natural gas properties and equipment. The credit facility has a 364-day revolving period and is subject to an annual review by the lenders, at which time a lender can extend the revolving period or can request conversion to a one year term loan. During the revolving period, a determination of the maximum borrowing amount occurs semi-annually on or before October 31. NuVista has completed the semi-annual review of its borrowing base with its lenders and the lenders have approved the continuation of the maximum borrowing amount of $510 million. During the term period, no principal payments would be required until April 28, 2012. As such, this credit facility is classified as long-term. As at September 30, 2010, the Company had drawn $442.1 million (December 31, 2009 - $384.6 million) on the facility. Cash paid for interest expense for the three months ended September 30, 2010 was $4.3 million (2009 - $4.0 million) and for the nine months ended September 30, 2010 was $12.6 million (2009 - $9.5 million).



5. Shareholders' equity

(a) Share capital and contributed surplus

September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Share capital 688,584 685,269
Contributed surplus 24,183 18,690
----------------------------------------------------------------------------
Total 712,767 703,959
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(b) Authorized

Unlimited number of voting Common Shares and 1,200,000 Class B Performance
Shares.

(c) Common shares issued

September 30, 2010 December 31, 2009
------------------------------------------------
Number Amount Number Amount
----------------------------------------------------------------------------

Balance, beginning
of period 88,360,757 $ 685,269 79,164,582 $ 587,460
Issued for cash - - 9,000,000 99,016
Dividend Re-investment
Plan ("DRIP") 70,688 763 - -
Exercise of stock options 210,674 1,994 196,175 1,430
Stock-based compensation - 599 - 432
Cost associated with shares
issued, net of future tax
benefit of $0.01 million
(2009 - $1.1 million) - (41) - (3,069)
----------------------------------------------------------------------------

Balance, end of period 88,642,119 $ 688,584 88,360,757 $ 685,269
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


On June 15, 2009, the Company entered into an agreement to issue 7,500,000 subscription receipts at a price of $11.00 per subscription receipt on a bought deal basis for gross proceeds of $82.5 million. In addition, the Company issued 1,500,000 subscription receipts at a price of $11.00 per subscription receipt, by way of a private placement to Ontario Teachers' Pension Plan Board for gross proceeds of $16.5 million. The subscription receipt offerings closed on July 7, 2009. Each subscription receipt was exchanged for one common share of NuVista for no additional consideration on July 27, 2009.

On July 15, 2010, the Company issued 70,688 common shares in payment of $0.8 million of dividends for shareholders that elected to participate in the DRIP.

(d) Dividends 

In the third quarter of 2010, NuVista's Board of Directors declared a quarterly cash dividend of $0.05 per common share to shareholders of record on September 30, 2010. Dividends paid to shareholders of common shares have been designated as "eligible dividends" for Canadian tax purposes. 

On November 10, 2010, our Board of Directors declared a quarterly dividend of $0.05 per common share, payable in cash, to shareholders of record on December 31, 2010, with the dividend payment on January 17, 2011.



(e) Contributed surplus

September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of period 18,690 7,128
Stock-based compensation 6,092 8,540
Exercise of stock options (599) (432)
Expired warrants - 3,454
----------------------------------------------------------------------------
Balance, end of period 24,183 18,690
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


(f) Per share amounts

During the three months ended September 30, 2010, there were 88,625,346 (2009 - 85,770,428) weighted average shares outstanding. On a diluted basis, there were 88,625,346 (2009 - 85,770,428) weighted average shares outstanding after giving effect for dilutive stock options. For the nine months ended September 30, 2010, there were 88,501,158 (2009 - 81,404,296) weighted average shares outstanding and 88,501,158 (2009 - 81,404,296) weighted average shares outstanding on a dilutive basis. The number of anti-dilutive options totaled 4,757,007 at September 30, 2010 (2009 - 5,128,722). 

(g) Stock options

The Company has established a stock option plan whereby officers, directors, employees and service providers may be granted options to purchase common shares. Stock options are granted with an exercise price equal to the market price at the date of grant. Options granted prior to December 2008 vest at the rate of 1/4 per year and expire two years from the vest date. The terms of future stock option grants were amended in December 2008. Pursuant to the amendment, options subsequently granted will vest at the rate of 1/3 per year and expire 2.5 years after the vest date. The total stock options outstanding plus the Class B Performance Shares cannot exceed 10% of the outstanding common shares. The summary of stock option transactions is as follows:



September 30, 2010 December 31, 2009
--------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
----------------------------------------------------------------------------
Balance, beginning of period 6,574,823 13.16 6,111,945 13.69
Granted 1,779,720 11.02 1,600,953 11.01
Exercised (210,674) 9.46 (196,175) 7.29
Forfeited (413,241) 13.56 (566,950) 14.17
Expired (474,975) 14.27 (374,950) 14.29
----------------------------------------------------------------------------
Balance, end of period 7,255,653 12.64 6,574,823 13.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The Company uses the fair value based method for the determination of the stock-based compensation costs. The fair value of each option granted during the nine months ended September 30, 2010 was estimated on the date of grant using the Black-Scholes option pricing model. In the pricing model, the risk-free interest rate used was 2.3% (2009 - 2%); volatility of 40% (2009 - 52%); an average expected life of 4.4 years (2009 - 4.5 years); an estimated forfeiture rate of 10% (2009 - 10%); and dividends of $0.20 per share (2009 - nil). The weighted average fair value of stock options granted during the nine months ended September 30, 2010 was $3.46 per option (2009 - $4.75 per option). For the nine months ended September 30, 2010, the Company capitalized $1.4 million (2009 - $1.9 million) in stock based compensation.

(h) Restricted stock units

In January 2008, the Board of Directors approved a RSU Incentive Plan for employees and officers. Each RSU entitles participants to receive cash equal to the market value of the equivalent number of shares of the Company. Until November 2009, the RSUs became payable as they vested over three years. In November 2009, the Board of Directors amended the Plan. All RSUs granted subsequent to November 2009 vest two years after the date the RSUs are issued.



The following table summarizes the change in outstanding RSUs:

September 30, 2010 December 31, 2009
Number Number
----------------------------------------------------------------------------
Balance, beginning of period 414,791 351,543
Vested (195,294) (122,314)
Granted 163,210 204,154
Forfeited (16,822) (18,592)
----------------------------------------------------------------------------
Balance, end of period 365,885 414,791
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table summarizes the change in compensation liability relating
to the RSUs:

September 30, 2010 December 31, 2009
Amount Amount
----------------------------------------------------------------------------
Balance, beginning of period 2,744 1,461
Change in accrued compensation liability (1,233) 1,283
----------------------------------------------------------------------------
Balance, end of period 1,511 2,744
----------------------------------------------------------------------------
Compensation liability - current
(included in accounts payable) 630 2,140
----------------------------------------------------------------------------
Compensation liability - long-term 881 604
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The change in the liability at September 30, 2010 is primarily due to a reduction in the number of RSUs outstanding. For the nine months ended September 30, 2010, cash payments of $2.3 million (2009 - $0.8 million) were made relating to the RSU Incentive Plan, of which $0.5 million (2009 - $0.2 million) was capitalized to oil and natural gas properties and equipment.

6. Risk management activities

(a) Financial instruments

The Company's financial instruments recognized in the consolidated balance sheet consists of cash and cash equivalents, accounts receivable, commodity derivative contracts, dividend payable, accounts payable and accrued liabilities, and long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the Company's financial instruments due to their short-term maturities. The estimated fair values of recognized financial instruments have been determined based on the Company's assessment of available market information and appropriate methodologies, through comparisons to similar instruments, or third party quotes.

As at September 30, 2010, the Company has the following crude oil put option contracts in place:



Average Option
Strike Price Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
4,000 Bbls/d $87.60 - WTI $9.22 October 1, 2010 - December 31, 2010
2,000 Bbls/d $85.60 - WTI $8.43 January 1, 2011 - March 31, 2011
1,000 Bbls/d $87.00 - WTI $9.00 April 1, 2011 - December 31, 2011

 


As at September 30, 2010, the Company has the following NYMEX natural gas basis differential contracts in place:


Differential
Volume (US$/MMbtu) Term
----------------------------------------------------------------------------
20,000 MMbtu/d ($0.34) October 1, 2010 - October 31, 2010
25,000 MMbtu/d ($0.32) November 1, 2010 - March 31, 2011
40,000 MMbtu/d ($0.46) April 1, 2011 - October 31, 2011
30,000 MMbtu/d ($0.51) November 1, 2011 - March 31, 2012

 


As at September 30, 2010, the mark-to-market value of the financial derivative commodity contracts was a net asset of $0.7 million (December 31, 2009 - liability of $2.6 million). 

Subsequent to September 30, 2010, the following financial derivative crude oil put option contract has been entered into:



Average Option
Strike Price Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
2,000 Bbls/d $88.55 - WTI $9.43 January 1, 2011 - March 31, 2012

 


(b) Physical sale contracts

(i) As at September 30, 2010, the Company has the following direct natural gas sale contracts in place:



Average Price Premium
Volume (Cdn$/GJ) (Cdn$/GJ) Term
----------------------------------------------------------------------------
20,000 GJ/d $5.97 - AECO Floor $0.53 October 1, 2010 -
October 31, 2010
5,000 GJ/d $4.21 - Fixed Price AECO October 1, 2010 -
October 31, 2010

 


(ii) As at September 30, 2010, the Company has the following fixed price contract for the purchase of electricity in place:



Volume Price (Cdn$/Mwh) Term
----------------------------------------------------------------------------
4.0 Mwh $65.64 January 1, 2011 - December 31, 2013

 


These physical sale contracts are documented as normal purchase and sale transactions and as such are not considered financial instruments.

7. Relationship with Bonavista Petroleum Ltd.

NuVista and Bonavista Petroleum Ltd. ("Bonavista") are considered related as two directors of NuVista, one of whom is NuVista's chairman, are directors and officers of Bonavista and another director of NuVista is also an officer of Bonavista. For the three months ended September 30, 2010, overhead recoveries of $0.1 million were charged to Bonavista for our jointly owned partnership (2009 - $0.3 million) which are included as a reduction in general and administrative expenses. For the nine months ended September 30, 2010, overhead recoveries of $0.3 million were charged to Bonavista for our jointly owned partnership (2009 - $1.0 million). As at September 30, 2010, the amount receivable from Bonavista was $0.4 million (2009 - $0.4 million). These transactions are considered to be in the normal course of business and have been measured at their exchange amounts, being the amounts agreed to by both parties. 

8. Contractual obligations and commitments

The following is a summary of the Company's contractual obligations and commitments as at September 30, 2010:



Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Transportation $19,478 $1,544 $5,248 $4,011 $3,768 $3,288 $1,619
Office lease 4,318 519 2,076 1,723 - - -
Physical sale
contract premiums 329 329 - - - - -
Drilling rig
contract 1,498 567 931 - - - -
Physical power
contract 6,900 - 2,300 2,300 2,300 - -
Long-term debt 442,119 - - 442,119 - - -
----------------------------------------------------------------------------
Total commitments $474,642 $2,959 $10,555 $450,153 $6,068 $3,288 $1,619
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Corporate Information

Directors
Keith A. MacPhail, Chairman
W. Peter Comber, Barrantagh Investment Management Inc.
Pentti O. Karkkainen, KERN Partners
Ronald J. Poelzer, Bonavista Energy Trust
Alex G. Verge, President and CEO
Clayton H. Woitas, Range Royalty Management Ltd.
Grant A. Zawalsky, Burnet, Duckworth & Palmer LLP

Officers
Keith A. MacPhail, Chairman
Alex G. Verge, President and CEO
Robert F. Froese, Vice President, Finance and CFO and Corporate Secretary
Ross L. Andreachuk, Vice President and Controller
Kevin G. Asman, Vice President, Marketing
Kevin J. Christie, Vice President, Exploration
Steven J. Dalman, Vice President, Business Development
D. Chris McDavid, Vice President, Operations
Daniel B. McKinnon, Vice President, Engineering
Joshua T. Truba, Vice President, Land

Auditors Legal Counsel
KPMG LLP Burnet, Duckworth & Palmer LLP
Chartered Accountants Calgary, Alberta
Calgary, Alberta

Bankers Registrar and Transfer Agent
Canadian Imperial Bank of Commerce Valiant Trust Company
Bank of Montreal Calgary, Alberta
Royal Bank of Canada
Toronto Dominion Bank
Bank of Nova Scotia
Alberta Treasury Branches
Union Bank, Canada Branch

Engineering Consultants Stock Exchange Listing
GLJ Petroleum Consultants Ltd. Toronto Stock Exchange
Calgary, Alberta Trading Symbol "NVA"


FOR FURTHER INFORMATION PLEASE CONTACT:

NuVista Energy Ltd.
Alex G. Verge
President and CEO
(403) 538-8501

or

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

or

NuVista Energy Ltd.
Suite 3500, 700 - 2nd Street SW
Calgary, AB T2P 2W2
(403) 538-8500
(403) 538-8505 (FAX)
Email: inv_rel@nuvistaenergy.com
Website: www.nuvistaenergy.com