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FOR: NUVISTA ENERGY LTD.

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

NuVista Announces 2009 Year End Results

Mar 8, 2010 - 23:58 ET

CALGARY, ALBERTA--(Marketwire - March 8, 2010) - NuVista Energy Ltd. (TSX:NVA) is pleased to announce its financial and operating results for the three months and year ended December 31, 2009 as follows:



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Corporate Highlights
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Three months Years
ended ended
December 31, % December 31, %
2009 2008 Change 2009 2008 Change
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Financial
($ thousands, except
per share)
Production revenue 95,957 106,982 (10) 345,272 515,338 (33)
Funds from
operations(1) 50,499 58,878 (14) 190,139 281,029 (32)
Per share - basic 0.57 0.74 (23) 2.29 3.77 (39)
Per share - diluted 0.56 0.74 (24) 2.28 3.75 (39)
Net earnings 10,498 24,443 (57) 2,476 88,195 (97)
Per share - basic 0.12 0.31 (61) 0.03 1.18 (97)
Per share - diluted 0.12 0.31 (61) 0.03 1.18 (97)
Total assets 1,555,743 1,407,296 11
Long-term debt, net
of working capital 369,004 329,707 12
Long-term debt, net
of adjusted
working capital (1) 367,747 341,266 8
Shareholders' equity 919,693 811,300 13
Net capital
expenditures 30,856 49,166 (37) 309,910 200,737 54
Corporate acquisition
(non-cash) - - - - 594,944 -
Weighted average
common shares
outstanding
(thousands)
Basic 88,335 79,161 12 83,152 74,468 12
Diluted 89,612 79,197 13 83,571 75,021 11

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Operating
(Boe conversion -
6:1 basis)
Production
Natural gas (MMcf/d) 123.5 109.8 12 116.6 104.9 11
Natural gas liquids
(Bbls/d) 3,312 2,760 20 3,193 2,357 35
Oil (Bbls/d) 4,454 4,633 (4) 4,330 4,472 (3)
Total oil equivalent
(Boe/d) 28,345 25,688 10 26,958 24,320 11
Product prices (2)
Natural gas ($/Mcf) 4.82 7.80 (38) 4.94 8.39 (41)
Natural gas liquids
($/Bbl) 43.43 43.41 - 38.58 70.09 (45)
Oil ($/Bbl) 67.33 47.44 42 63.22 77.00 (18)
Operating expenses
Natural gas and
natural gas liquids
($/Mcfe) 1.16 1.21 (4) 1.16 1.18 (2)
Oil ($/Bbl) 17.43 16.95 3 16.60 14.16 17
Total oil equivalent
($/Boe) 8.60 8.98 (4) 8.49 8.37 1
General and
administrative
expenses ($/Boe) 1.45 1.29 12 1.45 1.35 7
Funds from operations
netback ($/Boe) (1) 19.37 24.93 (22) 19.33 31.58 (39)

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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.


Operating (continued)
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Undeveloped land, net acres
British Columbia/Northwest
Alberta core region 153,000 - -
Alberta Deep Basin core
region 251,000 251,000 -
Eastern Alberta/Saskatchewan
core region 488,000 517,000 (6)
Total 892,000 768,000 16
Average working interest 80% 79% 1
Wells drilled gross (net)
Natural gas 33 (24.6) 65 (45.7) (49)
Oil 17 (12.7) 37 (30.8) (54)
Dry holes 10 (9.3) 13 (9.5) (23)
Total 60 (46.6) 115 (86.0) (48)
Company interest reserves(1)
Proved plus probable
Natural gas (Bcf) 438.7 340.3 29
Oil and liquids (Mbbls) 24,706 20,962 18
Total barrels of oil
equivalent (MBoe) 97,816 77,680 26
% proved producing 56% 55% 2
% total proved 70% 68% 3
% probable 30% 32% (6)
Net present value of future
cash flows before tax
($ millions)(2)
@ 10% discount rate 1,586 1,351 17
@ 15% discount rate 1,307 1,110 18
Finding, development and
acquisition costs ($/Boe)(3)(5)
Total proved 14.15 24.28 (42)
Total proved plus probable 11.77 18.51 (36)
Reserve life index (years)(5)
Total proved 6.6 5.7 16
Total proved plus probable 9.5 8.3 14
Recycle ratio (4) (5)
Total proved 1.4 1.3 8
Total proved plus probable 1.6 1.7 6
Net asset value per share(2)(5) $ 15.24 $ 14.20 7
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(1) Company interest reserves are gross working interest reserves and
royalty interest reserves before the deduction of royalties.
(2) The estimated net present value of future cash flows disclosed do not
represent fair market value.
(3) Includes changes in future development capital expenditures net of
estimated drilling credits of $11.1 million for proved reserves and
$20.9 million for proved plus probable reserves.
(4) Based on funds from operations netback per Boe divided by finding,
development and acquisition costs per Boe.
(5) For more details, refer to "Management's Discussion and Analysis"
section in this press release.


Trading Statistics
(Cdn$, except volumes) based on intra-day trading


Three months ended Years ended
December 31, December 31,
----------------------------------------
2009 2008 2009 2008
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High 14.00 12.80 14.00 20.23
Low 10.42 6.25 4.90 6.25
Close 12.48 8.63 12.48 8.63
Average daily volume 186,635 270,677 227,432 264,447
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MESSAGE TO SHAREHOLDERS

NuVista Energy Ltd. ("NuVista") is pleased to report to its shareholders the company's financial and operating results for the three months and year ended December 31, 2009. In 2009, we continued with our disciplined approach to business and our focus on adding value on a per share basis. While our financial results and netbacks were impacted by lower commodity prices, this lower commodity price environment enabled us to act on our counter-cyclical business strategy of acquiring properties with stable production and future growth opportunities at attractive purchase price metrics. During 2009, approximately 73% of our $310 million capital program was allocated to acquisitions, including the addition of a new core area in Northeast British Columbia and Northwest Alberta. Despite lower netbacks, we achieved a proved plus probable operating recycle ratio of 1.9 times by driving down finding, development, and acquisition costs with the strategic shift in capital expenditures from drilling to lower cost acquisitions.

With the uncertain commodity price and economic environment in 2009, we carefully managed our financial flexibility by concentrating on improving operating efficiencies and adjusting our capital program throughout the year. Reduced drilling activity allowed our technical teams to focus on applying horizontal drilling and new multi-stage fracture completion technology in our high reserve-in-place plays, in order to develop an inventory of scalable and repeatable prospects. Over ten different horizons were selected based on the size of the reserve-in-place, repeatability, and NuVista's land position. Over the past six months, we have begun testing this technology with encouraging results.

Over the past six and one-half years, our asset base has changed significantly. NuVista has transitioned from a junior E&P company with a focus on shallow gas in Eastern Alberta to a strong intermediate company with a focus on longer life assets containing growth opportunities in the Deep Basin of central Alberta and northeast British Columbia. During this period our production has grown from 3,500 Boe/d to approximately 29,000 Boe/d. NuVista's oil properties and long life W5/W6M natural gas properties now represent more than 75% of our production base. This has led to an increase in our proved plus probable reserve life index to 9.5 years and has created a stable platform for future growth. In addition, about half of our production now resides in the Deep Basin where a significant portion of NuVista's land base, both developed and undeveloped, contains high reserve-in-place oil and natural gas deposits that are currently experiencing dramatic improvements in recovery from the application of new technology. NuVista's low cost structure results in significant free cash flow and in 2010 we are beginning to redeploy this stable cash flow into our large, scalable and repeatable prospect inventory.

Significant highlights for NuVista in 2009:

- Average production for the three months ended December 31, 2009, was 28,345 Boe/d compared with 25,688 Boe/d in the same period in 2008. In addition, 2009 average production increased by 11% to a record level of 26,958 Boe/d compared to 24,320 Boe/d in 2008. Current production is approximately 29,000 Boe/d;

- Acquired strategic properties in Northeast British Columbia and Northwest Alberta for approximately $174 million, and properties primarily in our Deep Basin core region for approximately $56 million, both at attractive purchase price metrics;

- Achieved finding, development and acquisition costs (after revisions and including changes in future development capital and drilling credits) on a proved plus probable basis of $11.77/Boe (2008 - $18.51/Boe). This resulted in a proved plus probable recycle ratio of 1.9:1 for 2009 based upon an operating netback of $22.38;

- Increased proved plus probable reserves by 26% to 97.8 million boe in total and on a per share basis increased reserves by 13% to 1.11 Boe/share;

- Proved developed producing reserves are 56% of total proved plus probable reserves and total proved reserves are 70% of total proved plus probable reserves, with the vast majority of NuVista's scalable high reserve-in-place opportunities remaining unbooked;

- Increased proved plus probable reserve life index, based on fourth quarter 2009 average production, to 9.5 years, an increase from 8.3 years at the end of 2008 and 5.3 years when we commenced operation in 2003;

- Drilled 24 (17.8 net) wells resulting in 10 (7.2 net) natural gas wells and 12 (8.9 net) oil wells in the fourth quarter of 2009. For the year ended December 2009, NuVista drilled 60 (46.6 net) wells, resulting in 33 (24.6 net) natural gas wells and 17 (12.7 net) oil wells, for an overall success rate of 83%;

- Ended 2009 with debt, net of adjusted working capital, of $368 million after peaking at approximately $400 million following the closing of our acquisition in July. 

For 2010, our base capital program is primarily focused on exploration and development activities however we will continue to pursue acquisition opportunities in what is expected to be an active mergers and acquisitions market. NuVista has recently embarked on the highest impact drilling program in our history, including the testing of repeatable high reserve-in-place plays using horizontal wells with multi-fracture completion technology. Our drilling activities in the first quarter of 2010 reached peak levels at the end of February with 10 rigs running in the field, five drilling horizontal wells and five drilling vertical wells. NuVista plans to drill approximately 30 wells in the first quarter. To date in 2010, 21 wells have been completed, resulting in 9 oil wells and 12 gas wells for a 100% success rate. This follows a successful fourth quarter 2009 drilling program of 24 wells, which resulted in 12 oil wells and 10 gas wells for a 92% success rate. Approximately 40% of NuVista's first quarter capital is being directed to horizontal drilling in areas where success could result in multiple low risk follow-up locations. 

Significant vertical and horizontal well drilling results over the past two quarters were described in our operational update press release issued on February 22, 2010. Additional activities since that time include the completion of NuVista's Dunvegan horizontal well (100% WI), in the Wapiti core area, which was drilled into a 20 m thick Dunvegan D channel sand. The well was completed over 11 intervals and had a final clean up flow rate of 4 MMcf/d. Also in our Wapiti core area, we are currently drilling our first Montney horizontal well (100% WI) and our first Cadomin horizontal well (70% WI). In our Pembina core area, our first horizontal Cardium well (30% WI) is now on production at 150-180 Bbls/d after recovering all of its load fluid. Our second horizontal well (45% WI) will be completed within the next week, weather permitting, and we are currently drilling our third Cardium horizontal well (100% WI) in this area. In our Kaybob core area, our second Montney horizontal well (100% WI) was successfully completed over 12 intervals this past weekend. The well flowed at an initial clean up rate of 11 MMcf/d. The third horizontal well (100% WI) is currently being drilled.

Unfortunately, at a time of record activity levels, early spring break-up due to unseasonably warm conditions in the field has resulted in the onset of daytime, and in some cases 24 hour, road bans. This may result in a deferral of capital expenditures and a corresponding delay in the completion and tie in of recently drilled wells. Even though this may have an impact on first quarter forecast exit rates and second quarter production volumes, the majority of planned completion and tie-in activities can be conducted in the summer as drier conditions return.

As part of the ongoing evolution of NuVista as an E&P growth company, we are adopting the hybrid 'growth and yield' business model. We plan to remain primarily focused on production and reserves growth but believe it is appropriate at this time to begin paying a small dividend. Our Board has declared a quarterly dividend of $0.05 per common share, payable in cash, with the first dividend payment on April 15, 2010, to shareholders of record on March 31, 2010. NuVista's initial plan is to maintain distribution levels between 5% and 15% of cash flow, preferably at the lower end of this range. NuVista expects to implement a dividend re-investment plan for Canadian shareholders in the next few months, subject to regulatory approval.

The independent engineering evaluation of NuVista's reserves, effective December 31, 2009, was completed by GLJ Petroleum Consultants Ltd. Details of our reserves and finding and development costs were included in our press release dated February 22, 2010, which are incorporated herein by reference.

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 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 March 8, 2010. Our audited consolidated financial statements, Annual Report, Annual Information Form and other disclosure documents for 2009 will be available through our filings on SEDAR at www.sedar.com or can be obtained from our website at www.nuvistaenergy.com prior to March 31, 2010.

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 contain forward-looking statements, including management's assessment of NuVista's future plans and operations, forecast production and reserves growth, drilling, 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, impact of early spring break-up on planned activities, plans to pursue acquisition opportunities, forecast funds from operations, expectations regarding funds from operations being sufficient to fund NuVista's planned 2010 capital program, targeted operating costs, 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, implementation of a dividend re-investment plan, expectations regarding future commodity prices, netbacks and industry conditions 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 subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management and services, stock market volatility, changes in environmental regulations, tax laws and royalties and the ability to access sufficient capital from internal sources and bank and equity markets. 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 that 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 Years ended
December 31, December 31,
----------------------------------------------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by operating activities 60,867 44,923 191,659 232,123
Add back:
Asset retirement expenditures 772 670 2,615 2,516
Change in non-cash working capital (11,140) 13,285 (4,135) 46,390
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Funds from operations 50,499 58,878 190,139 281,029
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Martin Creek and Northwest Alberta property acquisition - On July 27, 2009, NuVista closed the acquisition of certain properties in Northeast British Columbia and Northwest Alberta. 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.

Plan of arrangement with Rider Resources Ltd. - On March 4, 2008, NuVista closed a business combination with Rider Resources Ltd. ("Rider" or the "Rider Acquisition") and a private placement financing with the OTPP. The Rider Acquisition resulted in the combination of NuVista and Rider, pursuant to which all of the issued and outstanding Rider shares were exchanged for common shares of NuVista. Rider shareholders received, for each Rider share held, 0.3540 of a NuVista share. The results of operations from the Rider assets have been included, effective March 4, 2008.

Operating activities - For the year ended December 31, 2009, NuVista drilled 60 (46.6 net) wells, resulting in 33 (24.6 net) natural gas wells, 17 (12.7 net) oil wells and 10 (9.3 net) dry holes, for an overall success rate of 83%. NuVista operated 53 of the wells drilled. During the fourth quarter of 2009, NuVista participated in 24 (17.8 net) wells resulting in 10 (7.2 net) natural gas wells and 12 (8.9 net) oil wells and 2 (1.8 net) dry holes, for an overall success rate of 92%.

Reserves - NuVista's 2009 year end total proved reserves were 68.0 MMBoe, a 29% increase over the closing balance at year end 2008. NuVista's proved plus probable reserves increased by 26% to 97.8 MMBoe compared to 77.7 MMBoe at year end 2008. Finding, development and acquisition costs in 2009, including an adjustment for the change in future development capital expenditures and after revisions, were $14.15/Boe on a proved basis and $11.77/Boe on a proved plus probable basis. Excluding acquisitions, finding and development costs, on a proved plus probable basis after revisions and changes in future development capital expenditures were $16.69/Boe. In addition, NuVista's finding, development and acquisition costs on a proved plus probable basis were $11.26/Boe before revisions and including an adjustment for the change in future development costs. All future development capital expenditures are net of estimated drilling credits.



The following table outlines NuVista's finding, development and acquisition
costs:

3 Year-Average (1) (2) 2009 (1) (2) 2008 (1) (2)
Proved plus Proved plus Proved plus
Proved Probable Proved Probable Proved Probable
----------------------------------------------------------------------------
After reserve
revisions and
including
changes in
future
development
capital ($/Boe)
Finding,
development and
acquisition
cost 20.05 16.03 14.15 11.77 24.28 18.51
Finding and
development
costs 20.91 18.54 16.57 16.69 24.42 19.53
Acquisition
costs 19.66 14.96 13.27 10.51 24.24 18.14

(1) The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during the year in estimated
future development costs generally will not reflect total finding and
development costs related to reserve additions for the year.
(2) Drilling credits of $10.7 million were recorded during 2009.

 


The capital program for 2009 resulted in a funds from operations netback recycle ratio of 1.6x on a proved plus probable basis. NuVista's reserve life index, based upon 2009 fourth quarter average production of 28,345 Boe/d, was 6.6 years for total proved reserves and 9.5 years for proved plus probable reserves. This compares with 5.7 years and 8.3 years respectively at December 31, 2008. All of NuVista's reserves, as at December 31, 2009, were evaluated by NuVista's independent engineering consultants, GLJ Petroleum Consultants Ltd. NuVista has provided additional 2009 year end reserve information in a press release filed on SEDAR on February 22, 2010.

Additional reserve disclosure tables, as required under NI 51-101, will be contained in the Annual Information Form to be filed on SEDAR on or before March 31, 2010. The reserves information set forth in this MD&A are "company interest" reserves. "Company interest" means, in relation to NuVista's interest in reserves, its working interest (operating or non-operating) share before deduction of royalties, plus NuVista's royalty interests in production or reserves. "Company interest" is not a term defined or recognized under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 51-101") and does not have a standardized meaning under NI 51-101. Therefore, the "company interest" reserves of NuVista may not be comparable to similar measures presented by other issuers, and investors are cautioned that "company interest" reserves should not be construed as an alternative to "gross" or "net" reserves calculated in accordance with NI 51-101.

The following table is a reconciliation of the 2009 year end reserves with the reserves reported in the 2008 year end report:



Natural Total oil
gas Liquids Oil equivalent
----------------------------------------------------------------------------
Reconciliation items (1) (Bcf) (Mbbls) (Mbbls) (MBoe)
----------------------------------------------------------------------------
Total Proved
Balance, December 31, 2008 230.0 5,819 8,678 52,833
Exploration and development 23.7 838 713 5,505
Revisions (including improved
recovery) 3.7 653 (97) 1,172
Acquisitions 90.3 1,386 1,883 18,317
Dispositions - - - -
Production (42.6) (1,166) (1,581) (9,841)
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Balance, December 31, 2009 305.2 7,530 9,595 67,984
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Total Proved plus Probable
Balance, December 31, 2008 340.3 8,676 12,286 77,681
Exploration and development 32.4 1,202 873 7,472
Revisions (including improved
recovery) (7.4) 637 (759) (1,348)
Acquisitions 115.9 1,750 2,788 23,854
Dispositions - - - -
Production (42.6) (1,166) (1,581) (9,841)
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Balance, December 31, 2009 438.7 11,099 13,607 97,816
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(1) Numbers may not add due to rounding.


Net Asset Value Per Share

December 31,
----------------------------------------------------------------------------
($ thousands) 2009 2008
----------------------------------------------------------------------------
Net present value of oil and gas reserves,
discounted at 10%, before tax (1) $ 1,585,998 $ 1,350,700
Undeveloped land (2) 128,175 114,581
Cash, accounts receivable and prepaids 69,238 64,851
Accounts payable and accrued liabilities (52,362) (50,710)
Long-term debt (384,623) (355,407)
----------------------------------------------------------------------------
Net asset value $ 1,346,426 $ 1,124,015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Shares outstanding (000's) 88,361 79,164
----------------------------------------------------------------------------
Net asset value ($/share) $ 15.24 $ 14.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Proved plus probable company interest reserves, as at December 31, 2009,
as evaluated by GLJ Petroleum Consultants Ltd.
(2) Undeveloped land value has been calculated based on internal estimates
of $110/acre for our British Columbia/Northwest Alberta core region,
$250/acre for our Alberta Deep Basin core region and $100/acre for our
Eastern Alberta/Saskatchewan core region.


Production

Years ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Natural gas (Mcf/d) 116,608 104,946 11
Liquids (Bbls/d) 3,193 2,357 35
Oil (Bbls/d) 4,330 4,472 (3)
----------------------------------------------------------------------------
Total oil equivalent (Boe/d) 26,958 24,320 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Three months ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Natural gas (Mcf/d) 123,476 109,772 12
Liquids (Bbls/d) 3,312 2,760 20
Oil (Bbls/d) 4,454 4,633 (4)
----------------------------------------------------------------------------
Total oil equivalent (Boe/d) 28,345 25,688 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


For the year ended December 31, 2009, NuVista's average production was 26,958 Boe/d, comprised of 116,608 Mcf/d of natural gas, 3,193 Bbls/d of associated natural gas liquids ("liquids") and 4,330 Bbls/d of oil, which represents an 11% increase over the same period in 2008. This increase is primarily due to the acquisitions completed in 2009 and production additions resulting from the 2009 drilling program. For the fourth quarter of 2009, NuVista's average production was 28,345 Boe/d which was comprised of 123,476 Mcf/d of natural gas, 3,312 Bbls/d of liquids and 4,454 Bbls/d of oil and represents a 10% increase over the same period in 2008. The increase in production was primarily due to the Martin Creek and Northwest Alberta property acquisition completed in July 2009.



Revenues

Years ended December 31,
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) 2009 2008 % Change
--------------------------------------------------
Natural gas $ $/Mcf $ $/Mcf $ $/Mcf
Production revenue(1) 208,849 4.91 320,346 8.34 (35) (41)
Realized gain (loss) on
commodity derivatives 1,421 0.03 1,869 0.05 (24) (40)
----------------------------------------------------------------------------
Total 210,270 4.94 322,215 8.39 (35) (41)
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----------------------------------------------------------------------------

Liquids $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 44,957 38.58 60,463 70.09 (26) (45)
Realized gain (loss) on
commodity derivatives - - - - - -
----------------------------------------------------------------------------
Total 44,957 38.58 60,463 70.09 (26) (45)
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----------------------------------------------------------------------------

Oil $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 91,466 57.87 134,529 82.19 (32) (30)
Realized gain (loss) on
commodity derivatives 8,461 5.35 (8,497) (5.19) 200 203
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Total 99,927 63.22 126,032 77.00 (21) (18)
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Three months ended December 31,
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) 2009 2008 % Change
----------------------------------------------------
Natural gas $ $/Mcf $ $/Mcf $ $/Mcf
Production revenue(1) 54,796 4.82 76,856 7.61 (29) (37)
Realized gain (loss) on
commodity derivatives - - 1,908 0.19 (100) (100)
----------------------------------------------------------------------------
Total 54,796 4.82 78,764 7.80 (30) (38)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liquids $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 13,233 43.43 11,024 43.41 20 -
Realized gain (loss) on
commodity derivatives - - - - - -
----------------------------------------------------------------------------
Total 13,233 43.43 11,024 43.41 20 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 27,928 68.15 19,102 44.81 46 52
Realized gain (loss) on
commodity derivatives (336) (0.82) 1,119 2.63 (130) (131)
----------------------------------------------------------------------------
Total 27,592 67.33 20,221 47.44 36 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Natural gas revenue includes physical sale contracts. For the three
months ended December 31, 2009 our physical sale contracts resulted in a
gain of $3.8 million (2008 - $6.4 million gain). For the year ended
December 31, 2009, the gains on the physical sale contracts totaled
$31.1 million (2008 - $5.4 million loss).

 


For the year ended December 31, 2009, revenues including realized commodity derivative gains and losses were $355.2 million a 30% decrease from $508.7 million for the same period in 2008. The decrease in revenues for 2009 compared to the same period of 2008 is primarily due to a 37% decrease in realized prices offset by an 11% increase in production. These revenues were comprised of $210.3 million of natural gas revenue, $45.0 million of liquids revenue and $99.9 million of oil revenue. The decrease in average realized commodity prices is comprised of a 41% decrease in the natural gas price to $4.94/Mcf from $8.39/Mcf, a 45% decrease in the liquids price to $38.58/Bbl from $70.09/Bbl and a decrease of 18% in the oil price to $63.22/Bbl from $77.00/Bbl.

For the three months ended December 31, 2009, revenues including realized commodity derivative gains and losses were $95.6 million, a 13% decrease from $110.0 million for the same period in 2008. The decrease in revenues for the three months ended December 31, 2009 compared to the same period of 2008 is primarily due to a 21% decrease in realized prices offset by a 10% increase in production. These revenues were comprised of $54.8 million of natural gas revenue, $13.2 million of liquids revenue, and $27.6 million of oil revenue. The decrease in average realized commodity prices is comprised of a 38% decrease in the natural gas price to $4.82/Mcf from $7.80/Mcf, a slight increase in the liquids price to $43.43/Bbl from $43.41/Bbl and an increase of 42% in the oil price to $67.33/Bbl from $47.44/Bbl.



Commodity price risk management

Years ended December 31,
----------------------------------------------------------------------------
2009 2008
------------------------------------------------------------
Realized Total Realized Total
Gain Unrealized Gain Gain Unrealized Gain
($ thousands) (Loss) Gain (Loss) (Loss) (Loss) Gain (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas 1,421 (1,094) 327 1,869 1,094 2,963
Oil 8,461 (18,012) (9,551) (8,497) 17,148 8,651
----------------------------------------------------------------------------
Total gain (loss) 9,882 (19,106) (9,224) (6,628) 18,242 11,614
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three months ended December 31,
----------------------------------------------------------------------------
2009 2008
------------------------------------------------------------
Realized Total Realized Total
Gain Unrealized Gain Gain Unrealized Gain
($ thousands) (Loss) Gain (Loss) (Loss) (Loss) Gain (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas - - - 1,908 (784) 1,124
Oil (336) (3,818) (4,154) 1,119 26,601 27,720
----------------------------------------------------------------------------
Total gain (loss) (336) (3,818) (4,154) 3,027 25,817 28,844
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


As part of our financial 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 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, 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 year ended December 31, 2009, our commodity derivative price risk management program resulted in a loss of $9.2 million, consisting of realized gain of a $9.9 million and an unrealized loss of $19.1 million. The $19.1 million unrealized loss at December 31, 2009 is due to the change in NuVista's mark to market position which was a liability of $2.6 million at December 31, 2009 and an asset of $16.5 million at December 31, 2008. The loss of $9.2 million for 2009 consisted of a $0.3 million gain on natural gas contracts and a $9.5 million loss on crude oil contracts. In the fourth quarter of 2009, our commodity derivative price risk management program resulted in a loss of $4.1 million, consisting of a realized loss of $0.3 million and an unrealized loss of $3.8 million. 

For the three months ended December 31, 2009, the commodity physical price risk management program for natural gas resulted in a gain of $3.8 million compared to a $6.4 million gain for the same period in 2008. For the year ended December 31, 2009, price risk management gains on our physical sale contracts for natural gas totaled $31.1 million compared to a $5.4 million loss for the same period in 2008.

As at December 31, 2009, the mark to market value of our financial derivative contract was a loss of $2.6 million. The physical sale contracts are purchase and sales transactions entered into in the normal course of business. No asset or liability value has been assigned to the contracts on the balance sheet as of December 31, 2009. The mark to market value of our physical sale contracts was a gain of $7.2 million.

The following is a summary of commodity price risk management contracts in place as at December 31, 2009:



(a) Financial instruments

As at December 31, 2009, NuVista has entered into the following crude oil
put option contracts:

Average Strike Price Option Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
1,000 Bbls/d Cdn $80.30 - WTI $9.75(1) January 1, 2010 -
September 30, 2010
1,000 Bbls/d Cdn $77.50 - WTI $8.78(1) January 1, 2010 -
March 31, 2010
1,000 Bbls/d Cdn $87.40 - WTI $8.86(1) April 1, 2010 -
June 30, 2010
1,000 Bbls/d Cdn $89.40 - WTI $12.60(1) October 1, 2010 -
December 31, 2010

(1) The premiums are incurred monthly over the term of the contract and
will be offset against revenues.


As at December 31, 2009, NuVista has entered into NYMEX natural gas basis
differential contracts as follows:

Volume Differential (US$/MMbtu) Term
----------------------------------------------------------------------------
5,000 MMbtu/d ($0.105) March 1, 2010 - March 31, 2010
20,000 MMbtu/d ($0.34) April 1, 2010 - October 31, 2010
15,000 MMbtu/d ($0.30) November 1, 2010 - March 31, 2011


Subsequent to December 31, 2009, the following financial derivative crude
oil put option contract has been entered into:

Average Strike Price Option Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
1,000 Bbls/d Cdn $86.75 - WTI $5.65(1) February 1, 2010 -
June 30, 2010

(1) The premiums are incurred monthly over the term of the contract and will
be offset against revenues.


(b) Physical sale contracts

(i) As at December 31, 2009, NuVista has entered into direct natural gas
sale put option contracts as follows:

Premium
Volume Average Price (Cdn$/GJ) (Cdn$/GJ) Term
----------------------------------------------------------------------------
20,000 GJ/d Cdn $5.97 - $6.56 AECO Collar $0.30(1) January 1, 2010 -
March 31, 2010
20,000 GJ/d Cdn $5.55 - AECO Floor $0.97(1) January 1, 2010 -
March 31, 2010
20,000 GJ/d Cdn $5.97 - AECO Floor $0.53(1) April 1, 2010 -
October 31, 2010

(1) The premiums are incurred monthly over the term of the contract and will
be offset against revenues.


(ii) As at December 31, 2009, NuVista has entered into a fixed price
contract for the purchase of electricity as follows:

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 Years ended
December 31, December 31,
----------------------------------------
Royalty rates (%) 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas and liquids 12 20 12 25
Oil 15 19 14 17
----------------------------------------------------------------------------
Weighted average rate 13 20 12 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Royalties of $43.1 million for the year ended December 31, 2009, were 63% lower than the $116.9 million for the same period of 2008. Royalties for the three months ended December 31, 2009 were $12.2 million, a 44% decrease from the $21.7 million reported for the three months ended December 31, 2008. The decrease in royalties are primarily due to the lower revenues associated with lower commodity prices and lower average royalty rates in both the fourth quarter and for the year ended December 31, 2009 compared to the same period in 2008.

For the year ended December 31, 2009, the average royalty rate as a percentage of production revenue was 12% compared to 23% for the same period in 2008. Royalty rates by product for the year ended December 31, 2009, were 12% for natural gas and liquids and 14% for oil compared to 25% for natural gas and liquids and 17% for oil for the same period in 2008. As a percentage of production revenue, the average royalty rate for the fourth quarter of 2009 was 13% compared to 20% for the comparative period of 2008. Royalty rates by product for the fourth quarter of 2009 were 12% for natural gas and liquids and 15% for oil compared to 20% for natural gas and liquids and 19% for oil for the similar period in 2008. The lower royalty rates are primarily due to the impact of the New Alberta Royalty Framework in a low commodity price environment and the impact of our physical price risk management activities on the reported royalty rates. 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 from our physical price risk management activities included in revenue result in a lower reported royalty rate as a percentage of revenue than if no price risk management activities had taken place.



Netbacks - The following table summarizes field netback by product for the
year ended December 31, 2009:

Natural gas and
liquids Oil Total
-----------------------------------------------------
135.8 Mmcfe/d 4,330 Bbl/d 26,958 Boe/d
----------------------------------------------------------------------------
($ thousands, except
per unit amounts) $ $/Mcfe $ $/Bbl $ $/Boe
Production revenue 253,806 5.12 91,466 57.87 345,272 35.09
Realized gain on
commodity derivatives 1,421 0.03 8,461 5.35 9,882 1.00
----------------------------------------------------------------------------
255,227 5.15 99,927 63.22 355,154 36.09
Royalties (30,740) (0.62) (12,367) (7.82) (43,107) (4.38)
Transportation (6,315) (0.13) (1,992) (1.26) (8,307) (0.84)
Operating costs (57,342) (1.16) (26,241) (16.60) (83,583) (8.49)
----------------------------------------------------------------------------
Field netback 160,830 3.24 59,327 37.54 220,157 22.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The table below summarizes field netback by product for the three months
ended December 31, 2009:

Natural gas and
liquids Oil Total
----------------------------------------------------------------------------
143.3 MMcfe/d 4,454 Bbl/d 28,345 Boe/d
----------------------------------------------------------------------------
($ thousands, except
per unit amounts) $ $/Mcfe $ $/Bbl $ $/Boe
Production revenue 68,029 5.16 27,928 68.15 95,957 36.80
Realized gain on
commodity derivatives - - (336) (0.82) (336) (0.13)
----------------------------------------------------------------------------
68,029 5.16 27,592 67.33 95,621 36.67
Royalties (7,885) (0.60) (4,268) (10.42) (12,153) (4.66)
Transportation (1,731) (0.13) (356) (0.87) (2,087) (0.80)
Operating costs (15,294) (1.16) (7,141) (17.43) (22,435) (8.60)
----------------------------------------------------------------------------
Field netback 43,119 3.27 15,827 38.61 58,946 22.61
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The tables below summarize funds from operations netback for the year ended December 31, 2009, compared to the year ended December 31, 2008 and the three months ended December 31, 2009, compared to the three months ended December 31, 2008:



Years ended December 31,
----------------------------------------------------------------------------
($ thousands, except
per unit amounts) 2009 2008 % Change
-----------------------------------------------------
$ $/Boe $ $/Boe $ $/Boe
Production revenue 345,272 35.09 515,338 57.90 (33) (39)
Realized gain (loss)
on commodity
derivatives 9,882 1.00 (6,628) (0.74) 249 235
----------------------------------------------------------------------------
355,154 36.09 508,710 57.16 (30) (37)
Royalties (43,107) (4.38) (116,874) (13.13) (63) (67)
Transportation (8,307) (0.84) (7,632) (0.86) 9 (2)
Operating costs (83,583) (8.49) (74,504) (8.37) 12 1
----------------------------------------------------------------------------
Field netback 220,157 22.38 309,700 34.80 (29) (36)
General and
administrative (14,280) (1.45) (12,042) (1.35) 19 7
Restricted stock units (1,677) (0.17) (1,120) (0.13) 50 31
Interest (14,061) (1.43) (15,509) (1.74) (9) (18)
----------------------------------------------------------------------------
Funds from operations
netback 190,139 19.33 281,029 31.58 (32) (39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three months ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
-----------------------------------------------------
($ thousands, except
per unit amounts) $ $/Boe $ $/Boe $ $/Boe
Production revenue 95,957 36.80 106,982 45.27 (10) (19)
Realized gain (loss)
on commodity
derivatives (336) (0.13) 3,027 1.28 (111) (110)
----------------------------------------------------------------------------
95,621 36.67 110,009 46.55 (13) (21)
Royalties (12,153) (4.66) (21,669) (9.17) (44) (49)
Transportation (2,087) (0.80) (1,797) (0.76) 16 5
Operating costs (22,435) (8.60) (21,235) (8.98) 6 (4)
----------------------------------------------------------------------------
Field netback 58,946 22.61 65,308 27.64 (10) (18)
General and
administrative (3,784) (1.45) (3,053) (1.29) 24 12
Restricted stock units (461) (0.18) 109 0.05 523 460
Interest (4,202) (1.61) (3,486) (1.47) 21 10
----------------------------------------------------------------------------
Funds from operations
netback 50,499 19.37 58,878 24.93 (14) (22)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Transportation - For the year ended December 31, 2009, transportation costs were $8.3 million ($0.84/Boe) compared to $7.6 million ($0.86/Boe) for the same period in 2008. The increase in transportation costs in 2009 compared to 2008 is primarily due to the 11% increase in production volumes. Transportation costs were $2.1 million ($0.80/Boe) for the three months ended December 31, 2009 as compared to $1.8 million ($0.76/Boe) for the fourth quarter of 2008. The increase in transportation costs in the fourth quarter 2009 compared to the same period in 2008 is primarily due to the 10% increase in production volumes.

Operating - Operating expenses were $83.6 million for the year ended December 31, 2009, compared to $74.5 million for the same period in 2008, an increase of 12%. This increase resulted from significantly higher production volumes and a slight increase in per unit costs in 2009 compared to 2008. On a Boe basis, operating costs increased to $8.49/Boe for the year ended December 31, 2009, as compared to $8.37/Boe for the same period in 2008. For the year ended December 31, 2009, natural gas and liquids operating expenses averaged $1.16/Mcfe and oil operating expenses were $16.60/bbl compared to $1.18/Mcfe and $14.16/Bbl respectively for the same period of 2008.

For the three months ended December 2009, operating expenses were $22.4 million ($8.60/Boe), a 6% increase when compared to $21.2 million ($8.98/Boe) for the three months ended December 31, 2008. This increase is attributed to higher production volumes offset by a 4% decrease in per unit costs in the fourth quarter of 2009 compared to the same period in 2008. For the three months ended December 31, 2009, natural gas and liquids operating expenses averaged $1.16/Mcfe and oil operating expenses were $17.43/Bbl compared to $1.21/Mcfe and $16.95/Bbl respectively for the same period of 2008. The per unit oil operating costs for the three months ended December were higher in 2009 compared to the same period of 2008 primarily due to the higher operating cost structure associated with the oil properties purchased in July 2009 located in Northwest Alberta.

General and administrative - General and administrative expenses, net of overhead recoveries, for the year ended December 31, 2009 were $14.3 million ($1.45/Boe), an increase of 7% on a per Boe basis, over the $12.0 million ($1.35/Boe) for the year ended December 31, 2008. This increase is directly attributable to the higher production base in NuVista, the corresponding increase in staff levels and lower overhead recoveries associated with a reduction in drilling activity. In 2009, NuVista charged Bonavista Petroleum Ltd. ("Bonavista") management fees for jointly owned partnerships totalling $1.2 million (2008 - $1.4 million). General and administrative expenses were $3.8 million ($1.45/Boe) net of overhead recoveries for the three months ended December 31, 2009, as compared to the charge of $3.1 million ($1.29/Boe) for the same period in 2008. Higher general and administration expenses in the fourth quarter of 2009 were primarily due to increases in staff levels to support the increased operating activities and lower overhead recoveries.



Three months ended Years ended
December 31, December 31,
----------------------------------------
($ thousands, except per unit
amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Gross general and administrative
expenses 5,183 4,767 19,476 18,946
Overhead recoveries (1,399) (1,714) (5,196) (6,904)
----------------------------------------------------------------------------
Net general and administrative
expenses 3,784 3,053 14,280 12,042
----------------------------------------------------------------------------
Per Boe 1.45 1.29 1.45 1.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation

Three months ended Years ended
December 31, December 31,
----------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Stock options 1,609 1,321 6,278 4,471
Restricted stock units 461 (109) 1,677 1,120
----------------------------------------------------------------------------
Total 2,070 1,212 7,955 5,591
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


NuVista recorded a stock-based compensation charge of $8.0 million for the year ended December 31, 2009, compared to $5.6 million for the same period in 2008. The stock-based compensation charge relates to the amortization of the value of stock option awards and the change in accrual for future payments under the Restricted Share Unit ("RSU") incentive plan. The increase in the expense in 2009 relates primarily to an increase in the number of stock options and RSU's outstanding and an increase in NuVista's share price throughout the year. Each RSU entitles participants to receive cash equal to the market value of the equivalent number of shares of NuVista.

Interest - Interest expense for the year ended December 31, 2009 was $14.1 million ($1.43/Boe) versus $15.5 million ($1.74/Boe) for the same period of 2008 due primarily to lower average interest rates. For the three months ended December 31, 2009, interest expense was $4.2 million ($1.61/Boe), up 20% from $3.5 million ($1.47/Boe) in the same period of 2008. Currently NuVista's borrowing rate is approximately 3.75%. Cash paid for interest for the year ended December 31, 2009 was $13.8 million compared to $14.6 million for 2008.

Depreciation, depletion and accretion - Depreciation, depletion and accretion expenses for the year ended December 31, 2009 were $172.2 million, an increase of 5% over the $164.2 million for the year ended December 31, 2008. The average cost per unit was $17.50/Boe for the twelve months ended December 31, 2009, compared to $18.45/Boe in the same period in 2008. Per unit costs have decreased in 2009 compared to 2008 due to the cost of acquisitions completed and lower finding and development costs incurred in 2009. Depreciation, depletion and accretion expenses were $43.5 million for the fourth quarter of 2009 compared to $43.7 million for the same period in 2008. The average cost per unit was $16.67/Boe in the fourth quarter of 2009 compared to $18.48/Boe for the same period in 2008. The lower per unit cost is due primarily to the impact of the reserve additions recognized in NuVista's 2009 year end reserve report. 

Income taxes - For the year ended December 31, 2009, income taxes were a recovery of $9.7 million as compared to an expense of $37.6 million in 2008. For the fourth quarter of 2009, the provision for income tax was a recovery of $8.7 million, as compared to an expense of $11.6 million in the corresponding period in 2008. The change in income taxes from 2008 to 2009 is primarily due to lower earnings before income tax and a change in the expected future corporate income tax rate.

Capital expenditures - Capital expenditures for the year ended December 31, 2009 were $309.9 million, consisting of $83.6 million for exploration and development spending (net of $10.7 million in drilling credits) and $226.3 million for acquisitions. This compares to $200.7 million incurred for the same period of 2008, consisting of $29.2 million of acquisitions and exploration and development spending of $171.5 million. Capital expenditures were $30.9 million during the fourth quarter of 2009 compared to $49.2 million in the same period of 2008, with $32.0 million of exploration and development spending (net of $5.2 million in drilling credits), and credits of $1.1 million received on the final statement of adjustments for the property acquisitions completed in 2009. During 2009, NuVista increased the portion of its capital expenditures on acquisitions due to acquisition opportunities available and attractive purchase price metrics.



Three months ended Years ended
December 31, December 31,
----------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Exploration and development
Land and retention costs 2,950 9,507 5,980 37,015
Seismic 3,748 2,857 10,539 11,709
Drilling and completion 24,968 27,606 54,955 88,764
Facilities and equipment 3,075 5,449 19,603 32,117
Corporate and other 2,419 (111) 3,226 1,876
----------------------------------------------------------------------------
Subtotal 37,160 45,308 94,303 171,481
----------------------------------------------------------------------------
Alberta drilling incentive credits (5,164) - (10,699) -
----------------------------------------------------------------------------
Subtotal 31,996 45,308 83,604 171,481
----------------------------------------------------------------------------
Property acquisitions (1,140) 3,858 226,306 29,256
----------------------------------------------------------------------------
Net capital expenditures 30,856 49,166 309,910 200,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corporate acquisition - non-cash - - - 594,944
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Funds from operations and net earnings - For the year ended December 31, 2009, NuVista's funds from operations were $190.1 million ($2.29/share, basic), a 32% decrease from $281.0 million ($3.77/share, basic) for the year ended December 31, 2008. In the fourth quarter of 2009, funds from operations were $50.5 million ($0.57/share, basic), a 14% decrease from the $58.9 million ($0.74/share, basic) for the same period in 2008. Funds from operations for the three months and year ended 2009 were lower than the same periods in 2008 primarily due to lower commodity prices and higher operating costs, partially offset by higher production volumes and lower royalty rates. 

For the year ended December 31, 2009, net earnings decreased 97% to $2.5 million ($0.03/share, basic) from $88.2 million ($1.18/share, basic) for the same period in 2008. 2009 net earnings were lower when compared against 2008 net earnings due to the same factors impacting funds from operations as well as the impact of a larger unrealized loss on commodity derivatives and higher depletion, depreciation and accretion costs. Net earnings decreased during the fourth quarter of 2009 to $10.5 million ($0.12/share, basic) from the $24.4 million ($0.31/share, basic) for the same period in 2008. Fourth quarter 2009 net earnings were lower compared to the same period in 2008, for the same factors impacting the decrease in annual net earnings. 

Tax pools - At December 31, 2009, NuVista had approximately $990 million (2008 - $925 million) of estimated tax pools available for deduction against future years' taxable income. The following table summarizes the estimated tax pool balances:



Income Tax Pool Type Available Balance Maximum Annual Deduction
----------------------------------------------------------------------------
($ thousands) 2009 %
----------------------------------------------------------------------------
Canadian exploration expense 55,000 100%
Canadian development expense 155,000 30% declining balance
Canadian oil and natural gas 10% declining balance
property expense 570,000
Undepreciated capital cost 200,000 25% declining balance
Other 10,000 Various rates
----------------------------------------------------------------------------
Total tax pools 990,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Based on our current 2010 forecast of funds flow from operations and capital
expenditures, NuVista does not expect to be cash taxable in 2010.


Liquidity and capital resources

($ thousands) 2009 2008
----------------------------------------------------------------------------
Common shares outstanding 88,361 79,164
Share price (1) 12.48 8.63
----------------------------------------------------------------------------
Total market capitalization 1,102,745 683,185
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted working capital surplus 16,876 14,141
Bank debt 384,623 355,407
----------------------------------------------------------------------------
Debt, net of adjusted working capital
("Net Debt")(2) 367,747 341,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Funds from operations (annualized fourth
quarter) (2) 201,996 235,512
----------------------------------------------------------------------------
Net Debt to total funds from operations 1.8 1.5
----------------------------------------------------------------------------
Net Debt as a percentage of total
capitalization 33% 50%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

 


As at December 31, 2009, debt net of adjusted working capital was $367.7 million, resulting in a net debt to annualized fourth quarter funds from operations ratio of 1.8:1. Adjusted working capital excludes the current portion of the fair value of the commodity derivatives liability of $2.6 million and the current portion of future income tax asset of $1.3 million. At December 31, 2009, NuVista had an adjusted working capital surplus of $16.9 million. NuVista believes it is appropriate to exclude these amounts when assessing financial leverage. At December 31, 2009, NuVista had $125.4 million of unused bank borrowing capacity, $30 million of which is solely reserved for acquisitions, based on the current credit facility of $510.0 million.

In November, NuVista completed the semi-annual review of its borrowing base with its lenders. NuVista's lenders approved a request for a credit facility totaling $510 million, comprised of a $480 million extendible revolving facility and a $30 million non-extendible, non-revolving acquisition facility. The acquisition facility is available subject to mutual approval of the lenders and NuVista. NuVista's credit facility annual renewal date is April 30, 2010.

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 April 30 and October 31. During the term period, no principal payments would be required until April 29, 2011. As such, this credit facility is classified as long-term. As at December 31, 2009, NuVista had drawn $384.6 million (2008 - $355.4 million) on the facility. 

NuVista anticipates that funds from operations will provide the flexibility to fund its planned 2010 capital program. In this period of uncertain commodity prices, NuVista will continue to place emphasis on maintaining its financial flexibility. NuVista plans to closely monitor its 2010 business plan and adjust capital programs in the context of commodity prices and access to bank and equity capital.

As at December 31, 2009, there were 88.4 million common shares outstanding. In addition, there were 6.6 million stock options outstanding, with an average exercise price of $13.16 per share. As of February 28, 2010 there were 88.5 million common shares and 6.4 million stock options outstanding.

Contractual obligations and commitments - NuVista enters into contractual obligations as part of conducting business. The following is a summary of NuVista's contractual obligations and commitments as at December 31, 2009:



($ thousands) Total 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------
Transportation 20,329 5,851 4,470 3,489 3,121 3,398
Office lease 5,901 2,102 2,076 1,723 - -
Physical sale contract
premiums 5,838 5,838 - - - -
Financial contract premiums 5,417 5,417 - - - -
Physical power contract 6,900 - 2,300 2,300 2,300 -
Long-term debt 384,623 - 384,623 - - -
----------------------------------------------------------------------------
Total commitments 429,008 19,208 393,469 7,512 5,421 3,398
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet at December 31, 2009. 

Goodwill - Goodwill of $83.7 million arose from various business acquisitions and was determined based on the excess of total consideration paid less the fair value of the assets and liabilities acquired. Accounting standards require that the goodwill balance be assessed for impairment at least annually or more frequently if events or changes in circumstances indicate that the balance might be impaired. If such impairment exists, it would be charged to income in the period in which the impairment occurs. NuVista has determined that there was no goodwill impairment as of December 31, 2009.

Related party activities - NuVista and Bonavista are considered related. Two of NuVista directors, one whom is NuVista's chairman, are also directors and officers of Bonavista. A director and an officer of NuVista are also officers of Bonavista. In 2009, NuVista charged Bonavista management fees for jointly owned partnerships totaling $1.2 million (2008 - $1.4 million) which is included as a reduction in general and administrative expenses. As at December 31, 2009, the amount receivable from Bonavista was $0.3 million (2008 - $1.2 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.



Annual financial information - The following table highlights selected
annual financial information for the years ended December 31, 2009, 2008
and 2007:

December 31, 2009 2008 2007
----------------------------------------------------------------------------
($ thousands, except per share
amounts)
Production revenue 345,272 515,338 212,386
Net earnings 2,476 88,195 26,327
Per share - basic 0.03 1.18 0.51
Per share - diluted 0.03 1.18 0.51
----------------------------------------------------------------------------
Balance sheet information
Total assets 1,555,743 1,407,296 683,165
Long-term debt 384,623 355,407 177,109
Shareholders' equity 919,693 811,300 370,292
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Quarterly financial information - The following table highlights NuVista's
performance for the eight quarterly reporting periods from March 31, 2008 to
December 31, 2009:

($ thousands,
except per 2009 2008
share --------------------------------------------------------------
amounts) Dec 31 Sep 30 Jun 30 Mar 31 Dec 31 Sep 30 Jun 30 Mar 31
----------------------------------------------------------------------------
Production
(Boe/d) 28,345 27,505 25,777 26,175 25,688 26,065 26,153 19,339

Production
revenue 95,957 79,494 78,092 91,729 106,982 149,596 161,794 97,064
Net earnings
(loss) 10,498 (3,342) (7,312) 2,632 24,443 53,699 2,905 7,150
Per share
- basic 0.12 (0.04) (0.09) 0.03 0.31 0.68 0.04 0.12
Per share
- diluted 0.12 (0.04) (0.09) 0.03 0.31 0.68 0.04 0.12

 


NuVista's average quarterly production has increased from 19,339 Boe/d in the first quarter of 2008, to an average of 28,345 Boe/d in the fourth quarter of 2009. This increase in production is due primarily to the acquisitions completed during these periods and incremental production from our drilling program which have more than offset natural production declines. The 2009 second quarter's average production was negatively impacted by third party facility outages. Over the prior eight quarters, quarterly revenue has been in a range of $78.1 million to $161.8 million with revenue primarily influenced by production volumes, and oil and natural gas prices in the quarter. Net earnings (loss) have been in a range of a net loss of $7.3 million to net earnings of $53.7 million primarily influenced by production volumes, commodity prices and realized and unrealized gains and losses on commodity derivatives.

Subsequent event - On March 8, 2010, NuVista's Board of Directors declared a quarterly dividend of $0.05 per common share. The first dividend payment will be on April 15, 2010 payable in cash, to shareholders of record on March 31, 2010. NuVista expects to implement a dividend re-investment plan for Canadian shareholders in the coming months, subject to regulatory approval. In the future, NuVista intends to pay quarterly dividends, however these dividends are not guaranteed.

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 the 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) 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.

(f) 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.

(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 December 31, 2009, we have determined there was no goodwill impairment.

Update on regulatory matters 

(a) Climate Change Regulation - The Government of Canada ratified the Kyoto Protocol in 2002, calling for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business as usual" levels by 2012. In December 2009, representatives of approximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol. The Copenhagen negotiations resulted in the Copenhagen Accord, a non-binding political accord which reinforced the Kyoto Protocol's commitment to reducing greenhouse gas emissions. In response to the Copenhagen Accord, the government of Canada revised its emissions reduction goals and now aims to achieve a 17% reduction in greenhouse gas emissions from 2005 levels by 2020. Despite the commitments made under the Kyoto Protocol and the Copenhagen Accord, no federal legislation has been implemented to regulate the emission of greenhouse gases and the Government of Canada has indicated that it will delay the implementation of climate change legislation and regulations in order to ensure consistency with the approach ultimately taken by the United States with respect to greenhouse gas emissions.

There has been much public debate with respect to Canada's ability to meet these targets and the Government of Canada's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. The implementation of strategies for reducing greenhouse gases, whether to meet the goals of the Kyoto Protocol, the Copenhagen Accord or otherwise could have a material impact on the nature of oil and natural gas operations, including those of NuVista. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact of those requirements on NuVista and our operations and financial condition. 

Further information regarding environmental and climate change regulation is contained in our Annual Information Form for the year ended December 31, 2009 under the Industry Conditions Section.

(b) New Royalty Framework - On October 25, 2007, the Alberta government announced the "New Royalty Framework" ("NRF"), which introduced the following changes to Alberta's royalty regime effective January 1, 2009:

- Conventional oil - overall royalty rates increased from the pre-NRF maximum of 30% and 35% for old and new tiers. The NRF rates vary on a sliding scale basis up to 50%, and rate caps have been raised to $120 per barrel for West Texas Intermediate crude.

- Natural gas - the Government eliminated "old" and "new" tiers. Royalty rates, pre-NRF at 5% to 35% increased to 5% to 50%, based on a sliding rate formula sensitive to price and production volume, with rate caps at $17.75/GJ.

- Oil Sands - before NRF, the pre-payout royalty rate was 1%. Under the NRF, this rate increased for prices above $55 per barrel, to a maximum of 9% when oil is priced at $120 or higher. Under the previous regime, once an oil sands project reached payout, the 1% royalty converted to a 25% net profits interest. Under the NRF, the net profits interest applies at the rate of 25% when oil is less than $55 per bbl of WTI, and increases for every dollar oil is priced above $55 per barrel to a maximum of 40% when oil is priced at $120 or higher.

On November 19, 2008, in response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced the introduction of a five-year program of transitional royalty rates with the intent of promoting new drilling. Companies drilling new natural gas or conventional oil deep wells between 1,000 and 3,500 m are given a one-time option, on a well-by-well basis, to adopt either the new transitional royalty rates or those outlined in the NRF. In order to qualify for this program wells must be drilled during the period starting on November 19, 2008 and ending on December 31, 2013. Following this period all new wells drilled will automatically be subject to the NRF and wells that operated under the transitional royalty rates will revert to royalty rates determined by the NRF.

On March 3, 2009, the Alberta Government announced a new well incentive program intended to stimulate conventional drilling activity. The incentive program offers a one-year royalty credit for conventional oil and gas wells drilled between April 1, 2009 and March 31, 2010 of $200 per metre and also provides for a maximum 5% royalty for all new wells that begin producing conventional oil and gas during the same period. In June 2009 the Government of Alberta announced the extension of these incentive programs until March 31, 2011.

(c) British Columbia Royalty Incentive Program - On August 6, 2009, the British Columbia ("B.C.") government announced a stimulus package to boost the current economy by introducing changes to the B.C. royalty program. These changes include a one-year, two per cent royalty rate for the first year of production on wells drilled in a 10 month window from September 1, 2009 to June 30, 2010 and brought on production by December 31, 2010; a permanent increase of 15 per cent in the existing Deep Royalty Credit Program for both vertical and horizontal wells; and a permanent change in the Deep Royalty Credit Program to include horizontal wells drilled between 1,900 and 2,300 metres, which is shallower than the previous cut-off of 2,300 metres.

Further information regarding NRF and current provincial royalties and incentive programs is contained in our Annual Information Form for the year ended December 31, 2009 under the Industry Conditions Section.

Update on accounting policies and financial reporting matters

Current Accounting Changes

Goodwill and intangible assets - Effective January 1, 2009, NuVista adopted Section 3064, Goodwill and Intangible Assets issued by the Canadian Institute of Chartered Accountants ("CICA"). Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. This standard has no current impact on NuVista's consolidated financial statements and was adopted prospectively.

Financial instruments - disclosures - Effective December 31, 2009, NuVista adopted CICA issued amendments to Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments now require that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 12 in NuVista's consolidated financial statements on risk management activities for enhanced fair value disclosures and liquidity risk disclosures. The amendments are consistent with recent amendments to financial instrument disclosure standards in International Financial Reporting Standards ("IFRS").

Future Accounting Changes

Business Combinations - The CICA issued Handbook Section 1582 "Business Combinations" that replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the market price of shares exchanged at the acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of first deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. NuVista is currently assessing the impact of the standard.

Consolidated Financial Statements and Non-controlling Interest - The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". 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 standards will be effective for NuVista for business combinations occurring on or after January 1, 2011, with early application permitted. NuVista is currently assessing the impact of the standard.

International Financial Reporting Standards ("IFRS") - In October 2009, the Accounting Standards Board ("AcSB") issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accounting enterprises will be required to apply IFRS for financial periods beginning on January 1, 2011 along with IFRS compliant comparative periods.

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 involves 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 is continuing the process of training key personnel within the accounting and finance functions as well as the management team.

NuVista's project consists of three key phases:

- Assessment phase - this phase involved performing a high level preliminary analysis of the differences between Canadian GAAP and IFRS. Areas with the greatest potential impact to NuVista's consolidated financial statements, in terms of complexity and effort, were identified.

- Evaluation phase - during this phase, items identified in the assessment phase are addressed according to the priority levels assigned to them. This phase involves analysis of policy choices allowed under IFRS and their impact on the financial statements. The results obtained through the evaluation phase will require the Audit Committee of the Board of Directors to review and approve all accounting policy choices as recommended by management.

- Implementation phase - involves implementation of all changes approved in the evaluation phase and will include changes to information systems, business processes, assessment of internal controls and training of all staff who are impacted by the conversion.

NuVista has completed the assessment phase and has prepared draft analysis for the evaluation phase. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on its financial statements. 

First-Time Adoption of IFRS

In July 2009, the International Accounting Standards Board 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 is analyzing 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 the PP&E assets at their deemed cost being the Canadian GAAP net book value assigned to these assets as at the date of transition, January 1, 2010 rather than retroactively restating these balances from inception. 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, the NuVista's PP&E assets must be divided into smaller cost centers. The net book value of the assets on the date of transition will be allocated to the new cost centers on the basis of the NuVista's reserve values at that point in time. 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 Exploration and Evaluation ("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 for NuVista's undeveloped land that relates to exploration properties and other exploration related activities. E&E assets will not be depleted and must be assessed for impairment when indicators suggest the possibility of impairment.

- Calculation of depletion expense for PP&E assets - Upon transition to IFRS, in addition to calculating depletion at a more detailed 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 has not concluded at this time which method for calculating depletion will be used.

- 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 cash generating unit level using either total proved or proved plus probable reserves.

In addition to accounting policy differences, NuVista's transition to IFRS will impact the internal controls over financial reporting, the disclosure controls and procedures and IT systems as follows: 

- Internal controls over financial reporting - As the review of the NuVista's accounting policies is completed, an assessment will be made to determine changes required for internal controls over financial reporting. For example, additional controls will be implemented for the determination of exploration activities and their potential reclassification to PP&E. This will be an ongoing process through 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.

- Disclosure controls and procedures - Throughout the transition process, NuVista will be assessing stakeholders' information requirements and will ensure that adequate and timely information is provided so that all stakeholders are kept apprised.

- IT systems - NuVista has completed most of the system updates required in order to ready the company for IFRS reporting. The modifications were not significant, however, 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 at a more detailed level for IFRS reporting. Additional system modifications may be required based on final policy choices. 

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 NI 52-109.

Disclosure controls and procedures have been designed to ensure that information to be disclosed by NuVista is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. NuVista's CEO and CFO have evaluated the effectiveness of the disclosure controls and procedures as at December 31, 2009 and have concluded that they provide reasonable assurance that all material information relating to NuVista is disclosed in a timely manner.

Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of the NuVista's financial reporting and compliance with generally accepted accounting principles. The CEO and CFO have evaluated NuVista's internal controls over financial reporting as at December 31, 2009 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") and have concluded they are designed and operating effectively to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with GAAP. During the year ended December 31, 2009, there have been no changes to NuVista's internal controls over financial reporting that have materially, or are reasonably likely to, materially affect the internal controls over financial reporting. 

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

Assessment of business risks

The following are the primary risks associated with the business of NuVista. Most of these risks are similar to those affecting others in the conventional oil and natural gas sector. NuVista's financial position and results of operations are directly impacted by these factors:

- Operational risk associated with the production of oil and natural gas;

- Reserves risk with respect to the quantity and quality of recoverable reserves;

- Commodity risk as crude oil and natural gas prices fluctuate due to market forces;

- Financial risk such as volatility of the CDN/US dollar exchange rate, interest rates and debt service obligations;

- Risk associated with the re-negotiation of NuVista's credit facility and the continued participation of NuVista's lenders;

- Market risk relating to the availability of transportation systems to move the product to market;

- Environmental and safety risk associated with well operations and production facilities; and

- Changing government regulations relating to royalty legislation, income tax laws, incentive programs, operating practices and environmental protection relating to the oil and natural gas industry.

NuVista seeks to mitigate these risks by:

- Acquiring properties with established production trends to reduce technical uncertainty as well as undeveloped land with development potential;

- Maintaining a low cost structure to maximize product netbacks and reduce impact of commodity price cycles;

- Diversifying properties to mitigate individual property and well risk;

- Maintaining product mix to balance exposure to commodity prices;

- Conducting rigorous reviews of all property acquisitions;

- Monitoring pricing trends and developing a mix of contractual arrangements for the marketing of products with creditworthy counterparties;

- Maintaining a price risk management program to manage commodity prices and foreign exchange currency rates risk and transacting with creditworthy counterparties;

- Ensuring strong third-party operators for non-operated properties;

- Adhering to NuVista's safety program and keeping abreast of current operating best practices;

- Keeping informed of proposed changes in regulations and laws to properly respond to and plan for the effects that these changes may have on our operations;

- Carrying industry standard insurance to cover losses; 

- Establishing and maintaining adequate cash resources to fund future abandonment and site restoration costs; 

- Closely monitoring commodity prices and capital programs to manage financial leverage; and 

- Monitoring the bank and equity markets to understand how changes in the capital market may impact NuVista's business plan.

OUTLOOK 

NuVista's Board of Directors has approved a 2010 capital budget of $240 million to $280 million. Over 70% of capital expenditures will be directed to exploration and development activities with the balance allocated to complementary acquisitions. Given the nature of our drilling program and the discretionary nature of acquisitions, we will carefully monitor our spending in the context of commodity prices and cash flow in order to maintain our financial flexibility. Any large strategic acquisitions would be incremental to this capital budget and our 2010 operational and financial guidance.

NuVista forecasts 2010 funds from operations of approximately $255 million based on current pricing assumptions of $5.50/Mcf for AECO natural gas, US$80/Bbl for WTI crude oil, a foreign exchange rate of 0.96, and including price risk management contracts currently in place. We expect to drill approximately 110 gross wells in 2010 and this should result in production averaging between 30,000 Boe/d and 31,000 Boe/d depending on the timing of exploration and development activities, downtime and the impact of the early spring break-up on first quarter activity levels. We are currently forecasting a 2010 exit production rate of between 32,000 Boe/d and 33,000 Boe/d based on our current capital program. 

For the first half of 2010, we are forecasting capital spending to be less than our forecast funds from operations. Capital spending during the first quarter of 2010 is expected to total approximately $80 million, however, early spring break up may result in the deferral of some activities to the third quarter. Capital expenditures in the second quarter of 2010 will be significantly reduced due to spring break-up. 

Since NuVista's formation almost seven years ago, we have demonstrated an unwavering commitment to enhancing stakeholder value. Our leadership team has remained disciplined, successfully guiding NuVista through several rapid increases and contractions in commodity prices, changes in regulatory and tax regimes, and the most significant financial crisis in recent history. In 2010, we will test applications of new drilling and completion technology that has the potential to add certainty and predictability to our rapidly expanding inventory of scalable and repeatable prospects. If market conditions permit, we may expand our business plan with accretive acquisitions that focus on reserves and production per share growth over time while maintaining our financial flexibility and increasing future development potential of our asset base. 

The outlook for natural gas prices remains uncertain and we plan to prudently manage our business plan and financial flexibility to endure an extended period of lower prices. However, we believe our counter-cyclical strategy of acquiring premium assets at lower prices and optimizing production from these assets, will richly reward our stakeholders over the long term. With a disciplined, countercyclical approach to adding value, and a talented, empowered, and accountable work force of highly motivated employees to achieve our targets, we believe our stakeholders have never been in better hands. As we continue to implement the highest impact drilling program in our history, we look forward to updating you on our progress.



Sincerely,

Alex G. Verge Robert F. Froese
President & CEO Vice President, Finance & CFO
March 8, 2010


NUVISTA ENERGY LTD.

Consolidated Balance Sheets

($ thousands)
As at December 31, 2009 2008
----------------------------------------------------------------------------
(unaudited)

Assets
Current assets
Cash and cash equivalents $ - $ 139
Accounts receivable and prepaids
(notes 12 and 13) 69,238 64,712
Commodity derivative asset (note 12) - 16,513
Future income taxes (note 10) 1,336 -
----------------------------------------------------------------------------
70,574 81,364
Oil and natural gas properties and
equipment (note 5) 1,401,453 1,242,216
Goodwill (note 6) 83,716 83,716
----------------------------------------------------------------------------
$ 1,555,743 $ 1,407,296
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 52,362 $ 50,710
Future income taxes (note 10) - 4,954
Commodity derivative liability (note 12) 2,593 -
----------------------------------------------------------------------------
54,955 55,664
Long-term debt (note 8) 384,623 355,407
Compensation liability (note 9) 604 850
Asset retirement obligations (note 7) 61,816 46,296
Future income taxes (note 10) 134,052 137,779
Shareholders' equity
Share capital, warrants and contributed
surplus (note 9) 703,959 598,042
Retained earnings 215,734 213,258
----------------------------------------------------------------------------
919,693 811,300
----------------------------------------------------------------------------
$ 1,555,743 $ 1,407,296
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commitments (note 14)
Subsequent Event (note 15)
See accompanying notes to consolidated financial statements.


NUVISTA ENERGY LTD.

Consolidated Statements of Earnings, Comprehensive Income and Retained
Earnings

Three months Years
($ thousands, except ended December 31, ended December 31,
per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)

Revenues
Production $ 95,957 $ 106,982 $ 345,272 $ 515,338
Royalties (12,153) (21,669) (43,107) (116,874)
Realized gain (loss) on
commodity derivatives (336) 3,027 9,882 (6,628)
Unrealized gain (loss) on
commodity derivatives (3,818) 25,817 (19,106) 18,242
----------------------------------------------------------------------------
79,650 114,157 292,941 410,078
----------------------------------------------------------------------------

Expenses
Operating 22,435 21,235 83,583 74,504
Transportation 2,087 1,797 8,307 7,632
General and administrative
(note 13) 3,784 3,053 14,280 12,042
Bad debt provision (recovery)
(note 12(c)) (182) 3,631 (182) 4,758
Interest 4,202 3,486 14,061 15,509
Stock-based compensation
(note 9) 2,070 1,212 7,955 5,591
Depreciation, depletion
and accretion 43,463 43,685 172,178 164,211
----------------------------------------------------------------------------
77,859 78,099 300,182 284,247
----------------------------------------------------------------------------
Earnings (loss) before
income taxes 1,791 36,058 (7,241) 125,831
Future income tax expense
(recovery) (note 10) (8,707) 11,615 (9,717) 37,636
----------------------------------------------------------------------------
Net earnings 10,498 24,443 2,476 88,195
Other comprehensive income
Amortization of fair value
of financial instruments - - - (17)
----------------------------------------------------------------------------
Comprehensive income 10,498 24,443 2,476 88,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, beginning
of period 205,236 188,815 213,258 125,063
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, end
of period $ 215,734 $ 213,258 $ 215,734 $ 213,258
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per
share - basic $ 0.12 $ 0.31 $ 0.03 $ 1.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per
share - diluted $ 0.12 $ 0.31 $ 0.03 $ 1.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


NUVISTA ENERGY LTD.

Consolidated Statement of Cash Flows

Three months Years
ended December 31, ended December 31,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)

Cash provided by (used in)
Operating Activities
Net earnings $ 10,498 $ 24,443 $ 2,476 $ 88,195
Items not requiring cash
from operations
Depreciation, depletion
and accretion 43,463 43,685 172,178 164,211
Stock-based compensation
(note 9) 1,609 1,321 6,278 4,471
Bad debt provision (recovery)
(note 12 (c)) (182) 3,631 (182) 4,758
Unrealized loss (gain) on
commodity derivatives 3,818 (25,817) 19,106 (18,242)
Future income tax expense
(recovery) (note 10) (8,707) 11,615 (9,717) 37,636
Asset retirement expenditures
(note 7) (772) (670) (2,615) (2,516)
Decrease (increase) in non-cash
working capital items 11,140 (13,285) 4,135 (46,390)
----------------------------------------------------------------------------
60,867 44,923 191,659 232,123
----------------------------------------------------------------------------

Financing Activities
Issue of share capital and
warrants, net of share
issuance costs 165 461 96,237 90,246
Increase (decrease) in
long-term debt (25,908) 10,262 29,215 178,298
Repayment of long-term debt - - - (305,584)
----------------------------------------------------------------------------
(25,743) 10,723 125,452 (37,040)
----------------------------------------------------------------------------

Investing Activities
Oil and natural gas
properties and equipment (31,996) (45,308) (83,604) (169,936)
Transaction costs on Rider
acquisition - - - (4,146)
Property acquisition (note 4) 1,140 (3,858) (226,306) (26,656)
Decrease (increase) in
non-cash working capital
items (4,268) (11,716) (7,340) 5,794
----------------------------------------------------------------------------
(35,124) (60,882) (317,250) (194,944)
----------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents - (5,236) (139) 139
Cash and cash equivalents,
beginning of period - 5,375 139 -
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ - $ 139 $ - $ 139
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.

 


NUVISTA ENERGY LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Years ended December 31, 2009 and 2008. 

1. Significant accounting policies

NuVista Energy Ltd. ("NuVista" or the "Company") was established with an effective date of July 2, 2003 under a Plan of Arrangement entered into by Bonavista Energy Trust (the "Trust"), Bonavista Petroleum Ltd. ("Bonavista") and NuVista. Under the Plan of Arrangement, various assets of Bonavista comprising of certain producing and exploration assets were transferred to NuVista.

Management has prepared its consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles. As the determination of many assets, liabilities, revenue and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions, which have been made using careful judgment. In particular, the amounts recorded for depreciation and depletion of oil and natural gas properties and equipment, the provision for asset retirement obligations, the provision for income taxes, financial instruments and stock-based compensation are based on estimates. The ceiling test is based on estimates of proved reserves, production rates, future oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant. All tabular amounts are in thousands of Canadian dollars, except per share amounts, unless otherwise stated. 

(a) Principles of consolidation

The consolidated financial statements include the accounts of NuVista and its wholly owned subsidiaries and proportionate share of its partnerships, which are jointly owned with Bonavista.

(b) Oil and natural gas properties and equipment 

NuVista follows the full cost method of accounting, whereby all costs associated with the exploration for and development of oil and natural gas reserves are capitalized in cost centres on a country-by-country basis. Such costs include land acquisitions, drilling, well equipment and geological and geophysical activities. Gains or losses are not recognized upon disposition of oil and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion by 20% or more.

Costs capitalized in the cost centres, including well equipment, together with estimated future capital costs associated with proved reserves, are depreciated and depleted using the unit-of-production method which is based on gross production and estimated proved oil and natural gas reserves as determined by independent engineers. The cost of unproven properties is excluded from the depreciation and depletion base. For purposes of the depreciation and depletion calculations, oil and natural gas reserves are converted to a common unit of measure on the basis of their relative energy content, being six thousand cubic feet of natural gas for one barrel of oil. Facilities are depreciated using the declining balance method over their useful lives, which range from 12 to 15 years. Costs associated with office furniture, fixtures, leasehold improvements and information technology are carried at cost and depreciated on a 20% declining balance.

Oil and natural gas properties and equipment are evaluated in each reporting period to determine whether the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves and the cost less any impairment of unproved properties and major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved plus probable reserves and the cost less any impairment of unproved properties and major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs, and are discounted using a risk-free interest rate.

(c) Joint interest operations

A portion of NuVista's oil and natural gas operations is conducted jointly with others. Accordingly, the consolidated financial statements reflect only NuVista's proportionate interest in such activities.

(d) Goodwill

Goodwill represents the excess of purchase price over the fair value of net assets acquired in a business combination. Goodwill is tested for impairment on an annual basis at the year-end balance sheet date, or as events occur that could result in impairment. Impairment is recognized based on the fair value of the reporting unit compared to the carrying amount of the reporting unit. If the fair value is less than the carrying amount, impairment is measured by allocating the fair value of the identifiable assets and liabilities as if the reporting unit has been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value over the amounts assigned to the identifiable assets and liabilities is the fair value of goodwill. Any excess of the carrying amount of goodwill over the implied fair value of goodwill is recognized as an impairment loss in the period in which it occurs. 

(e) Asset retirement obligations

NuVista records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability, there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the reserves. 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. Actual costs incurred upon settlement of the obligations are charged against the liability.

(f) Revenue recognition

Revenues from the sale of oil and natural gas are recorded when title passes to an external party.

(g) Financial instruments

(i) Financial instruments - recognition and measurement

All financial instruments, including all derivatives, are to be recognized on the consolidated balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in other comprehensive income and reclassified to earnings when derecognized or impaired. NuVista has classified its accounts receivable as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities and long-term debt are classified as other financial liabilities which are measured at amortized cost. Financial commodity derivatives are designated as held for trading which are measured at fair value. The Company immediately expenses all transaction costs incurred in relation to the acquisition of a financial asset or liability.

(ii) Derivatives

NuVista continues to utilize financial derivatives and non-financial derivatives, such as commodity sales contracts requiring physical delivery, to manage the price risk attributable to anticipated sale of oil and natural gas production. 

NuVista has elected to account for its commodity sales contracts which were entered into and continue to be held for the purpose of delivery of non-financial items in accordance with its expected sales as executory contracts rather than as non-financial derivatives.

(iii) Embedded derivatives

Embedded derivatives are derivatives embedded in a host contract. NuVista has not identified any material embedded derivatives which require separate recognition and measurement.

(iv) Other comprehensive income

The Comprehensive Income standard, Section 1530, requires a statement of comprehensive income, which is comprised of net earnings and other comprehensive income which, for NuVista, to date relate to changes in gains or losses on derivatives designated as cash flow hedges.

(h) Stock-based compensation

NuVista has equity incentive plans, which are described in note 9, Shareholders' equity. These stock-based compensation plans for employees do not involve the direct award of stock, or call for the settlement in cash or other assets. NuVista uses the fair value method for valuing stock option grants. Under this method, the compensation cost attributable to all stock options granted is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of stock options, consideration received together with the amount previously recognized in contributed surplus is recorded as an increase to share capital.

(i) Income taxes

NuVista follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the consolidated financial statements of NuVista and its respective tax base using substantively enacted future income tax rates. The effective change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs.

(j) Per share amounts

Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments.

(k) Cash and cash equivalents

Cash and cash equivalents are comprised of cash and short-term investments that are highly liquid in nature and have an original maturity date of three months or less.

(l) Comparative figures

Certain prior period amounts have been reclassified to conform with current year's presentation.

2. Adoption of new accounting policies

(a) Goodwill and intangible assets

Effective January 1, 2009, the Company adopted Section 3064, Goodwill and Intangible Assets issued by the Canadian Institute of Chartered Accountants ("CICA"). Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. This standard has no current impact on the Company's consolidated financial statements and was adopted prospectively.

(b) Financial instruments - disclosures

Effective December 31, 2009, the Company adopted CICA issued amendments to Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments now require that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 12 on risk management activities for enhanced fair value disclosures and liquidity risk disclosures. The amendments are consistent with recent amendments to financial instrument disclosure standards in International Financial Reporting Standards ("IFRS").

3. Future accounting changes

(a) Business Combinations

The CICA issued Handbook Section 1582 "Business Combinations" that replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the market price of shares exchanged at the acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of first deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. The Company is currently assessing the impact of the standard.

(b) Consolidated Financial Statements and Non-controlling Interest

The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". 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 standards will be effective for the Company for business combinations occurring on or after January 1, 2011 with early application permitted. The Company is currently assessing the impact of the standard.

(c) International Financial Reporting Standards

Canadian publicly accountable entities will be required to report under IFRS, which will replace Canadian generally accepted accounting principles ("GAAP") for years beginning on or after January 1, 2011. In July 2009, the International Accounting Standards Board ("IASB") approved additional IFRS transitional exemptions that will allow entities to allocate their oil and gas asset balance as determined under full cost accounting to the IFRS categories of exploration and evaluation assets and development and producing properties. Under the exemption, exploration and evaluation assets are measured at the amount determined under an entity's previous GAAP. For assets in the development or production phases, the amount is also measured at the amount determined under an entity's previous GAAP; however, such values must be allocated to the underlying balances at the IFRS transition date. This exemption will relieve entities from significant adjustments resulting from retrospective adoption of IFRS. The Company intends to utilize this exemption. NuVista is also evaluating other first-time adoption exemptions and elections available upon initial transition that provide relief from retrospective application of IFRS.

The Company has completed the assessment phase by performing comparisons of the differences between Canadian GAAP and IFRS and is continuing assessment of the effects of adoption and finalizing its conversion plan. The Company has determined that primarily the accounting for property, plant and equipment will be impacted by the conversion to IFRS. The Company currently follows full cost accounting as prescribed in Accounting Guideline ("AcG") 16, "Oil and Gas Accounting - Full Cost." Conversion from Canadian GAAP to IFRS may have an impact on how the Company accounts for costs pertaining to oil and gas activities, in particular those related to the pre-exploration, exploration and development phases. The conversion to IFRS will also result in other impacts, some of which may be significant in nature.

Assessments of other impacts completed to date include foreign exchange, revenue recognition, provisions and asset retirement obligations. The Company continues to perform assessments on less critical IFRS transition issues and has commenced analysis of IFRS financial statement presentation and disclosure requirements. These assessments will need to be further analyzed and evaluated throughout the implementation phase of the Company's project. At this time, the impact on NuVista's financial position and results of operations is not reliably determinable or estimable.

In 2009, the Company progressed work on information systems in preparation for the conversion of its balance sheet as at December 31, 2009 and the requirement to report 2010 comparative results in compliance with IFRS when reporting in 2011.

The Company will continue to monitor any changes in the adoption of IFRS and will update its plan as necessary.

4. 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 core areas. The cash purchase price was $55.6 million, net of final adjustments. The acquisition was financed through bank borrowings. 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 $174 million, net of asset retirement obligations. The purchase price is subject to change as a result of any final closing adjustments. The results of operations of these properties have been included in the consolidated financial statements of the Company since the acquisition date.

(c) Rider Resources Ltd. Business Combination

In March 2008, the Company completed the acquisition of all of the issued and outstanding common shares of Rider Resources Ltd. ("Rider") for net consideration of $260.3 million. The purchase price was based on Rider shareholders receiving 0.3540 common shares of the Company for each Rider share owned. The Company issued approximately 19.8 million common shares in exchange for 56.0 million common shares of Rider. The acquisition was accounted for using the purchase method. Operating results for Rider have been consolidated with the results of the Company effective from March 4, 2008, the date of acquisition. The allocation of the net purchase price to assets acquired and liabilities assumed based on their fair values was as follows:




Amount
----------------------------------------------------------------------------
Purchase Price
19.8 million NuVista common shares issued $ 256,195
Transaction costs 4,146
----------------------------------------------------------------------------
260,341
----------------------------------------------------------------------------
Allocation of purchase price
Property, plant and equipment 594,944
Working capital (deficiency) (18,261)
Bank loan (288,901)
Financial instrument (19,251)
Asset retirement obligations (8,505)
Future income taxes (28,962)
Goodwill 29,277
----------------------------------------------------------------------------
$ 260,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------

5. Oil and natural gas properties and equipment

2009
-------------------------------------------
Accumulated
Depreciation Net book
Cost and depletion value
----------------------------------------------------------------------------
Oil and gas properties $ 1,764,222 $ 671,966 $ 1,092,256
Facilities and office equipment 361,041 51,844 309,197
----------------------------------------------------------------------------
$ 2,125,263 $ 723,810 $ 1,401,453
----------------------------------------------------------------------------
----------------------------------------------------------------------------

2008
-------------------------------------------
Accumulated
Depreciation Net book
Cost and depletion value
----------------------------------------------------------------------------
Oil and gas properties $ 1,496,120 $ 522,641 $ 973,479
Facilities and office equipment 301,828 33,091 268,737
----------------------------------------------------------------------------
$ 1,797,948 $ 555,732 $ 1,242,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Unproved property costs of $128.2 million were excluded from the depreciation and depletion calculation for the year ended December 31, 2009 (2008 - $108.8 million). Future development costs of $93.3 million (2008 - $49.6 million) were included in the depreciation and depletion calculation. For 2009, NuVista capitalized $4.0 million (2008 - $3.7 million) in general and administrative expenses, $2.3 million (2008 - $1.8 million) in stock compensation expense and $0.5 million (2008 - $0.3 million) in Restricted Stock Units ("RSU") expense related to exploration and development activities.

NuVista has performed the ceiling test as of December 31, 2009, and no impairment was required. The test was calculated using benchmark reference prices at January 1 for the years 2010 to 2015 and thereafter, adjusted for commodity differentials specific to NuVista, as determined by the Company's independent oil and natural gas reserves engineers.



Benchmark Reference Price Forecasts:

2010 2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
WTI (US$/Bbl) (1) 80.00 83.00 86.00 89.00 92.00 93.84 95.72
AECO (Cdn$/MMbtu) (2) 5.96 6.79 6.89 6.95 7.05 7.16 7.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Escalated at 2% per year thereafter.
(2) For the period 2016 - 2018 AECO escalated at 7%. Thereafter, AECO
escalated at 2% per year.

 


6. Goodwill

The Company completed its annual goodwill impairment test at December 31, 2009 and 2008 and has determined that there is no goodwill impairment as of December 31, 2009 and 2008.

7. 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 December 31, 2009, the estimated total undiscounted amount of cash flows required to settle the Company's asset retirement obligations is $261.5 million (2008 - $187.9 million), which will be incurred over the next 51 years. The majority of the costs will be incurred between 2011 and 2037. A credit-adjusted risk-free rate of 8% (2008 - 8%) and an inflation rate of 2% (2008 - 2%) were used to calculate the fair value of the asset retirement obligations. In 2008, the change in assumptions was due to changes in per well cost estimates.



A reconciliation of the asset retirement obligations is provided below:

2009 2008
----------------------------------------------------------------------------
Balance, beginning of year $ 46,296 $ 26,574
Accretion expense 4,100 3,026
Liabilities incurred 4,050 7,203
Liabilities acquired 9,985 8,505
Change in assumptions - 3,504
Liabilities settled (2,615) (2,516)
----------------------------------------------------------------------------
Balance, end of year $ 61,816 $ 46,296
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


8. Long-term debt 

In November 2009, the Company completed the semi-annual review of its borrowing base with its lenders. The Company's lenders approved a request for a credit facility totaling $510 million, comprised of a $480 million extendible revolving facility and a $30 million non-extendible, non-revolving acquisition facility. The acquisition facility is available subject to mutual approval of the lenders and the Company.

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 April 30 and October 31. During the term period, no principal payments would be required until April 29, 2011. As such, this credit facility is classified as long-term. As at December 31, 2009, the Company had drawn $384.6 million (2008 - $355.4 million) on the facility. Cash paid for interest expense for the year ended December 31, 2009 was $13.8 million (2008 - $14.6 million).



9. Shareholders' equity

(a) Share capital, warrants and contributed surplus


2009 2008
----------------------------------------------------------------------------
Share capital $ 685,269 $ 587,460
Warrants - 3,454
Contributed surplus 18,690 7,128
----------------------------------------------------------------------------
Total $ 703,959 $ 598,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(b) Authorized

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

(c) Common shares issued

2009 2008
-----------------------------------------------
Number Amount Number Amount
----------------------------------------------------------------------------
Balance, beginning of year 79,164,582 $ 587,460 52,703,887 $ 240,245
Issued for cash 9,000,000 99,016 6,000,000 80,546
Issued on Rider acquisition - - 19,844,718 256,195
Exercise of stock options 196,175 1,430 615,977 6,545
Stock-based compensation - 432 - 4,144
Cost associated with shares
issued, net of future tax
benefit of $1.1 million
(2008 - $84) - (3,069) - (215)
----------------------------------------------------------------------------
Balance, end of year 88,360,757 $ 685,269 79,164,582 $ 587,460
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


On July 27, 2009, the Company closed the acquisition of certain properties in the Martin Creek area of Northeast British Columbia and Northwest Alberta. The acquisition was financed through a combination of bank debt and net proceeds from two equity offerings. 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 March 4, 2008, the Company issued 6.0 million units of NuVista ("Unit") at a price of $14.00 per Unit for gross proceeds of $84.0 million by way of a private placement. Each Unit consists of one common share and one-half of a warrant.



(d) Warrants

2009 2008
----------------------------------------------
Number Amount Number Amount
----------------------------------------------------------------------------
Balance, beginning of year 3,000,000 $ 3,454 - $ -
Issued - - 3,000,000 3,454
Transferred to contributed
surplus on expiry (3,000,000) (3,454) - -
----------------------------------------------------------------------------
Balance, end of year - $ - 3,000,000 $ 3,454
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


At December 31, 2008, there were 3.0 million common share purchase warrants outstanding. Each warrant entitled the holder thereof to acquire, subject to adjustment, one common share for $15.50 prior to March 4, 2009. As of March 5, 2009, these warrants expired unexercised.



(e) Contributed surplus

2009 2008
----------------------------------------------------------------------------
Balance, beginning of year $ 7,128 $ 4,967
Stock-based compensation 8,540 6,305
Exercise of stock options (432) (4,144)
Expired warrants 3,454 -
----------------------------------------------------------------------------
Balance, end of year $ 18,690 $ 7,128
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


(f) Per share amounts

During the year ended December 31, 2009, there were 83,152,386 (2008 - 74,468,270) weighted average shares outstanding. On a diluted basis, there were 83,571,055 (2008 - 75,021,409) weighted average shares outstanding after giving effect for dilutive stock options. The number of anti-dilutive options totaled 4,681,719 at December 31, 2009 (2008 - 5,890,266).

(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:



2009 2008
----------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
----------------------------------------------------------------------------
Balance, beginning of year 6,111,945 $ 13.69 4,046,400 $ 13.46
Granted 1,600,953 11.01 3,263,260 13.64
Exercised (196,175) 7.29 (615,675) 10.63
Forfeited (566,950) 14.17 (508,715) 14.63
Expired (374,950) 14.29 (73,325) 17.64
----------------------------------------------------------------------------
Balance, end of year 6,574,823 $ 13.16 6,111,945 $ 13.69
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes stock options outstanding and exercisable
under the plan at December 31, 2009:

Options Outstanding Options Exercisable
----------------------------------------------------------------------------
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Exercise Outstanding Contractual Exercise Exercisable Exercise
Price At Year-End Life Price at Year-End Price
----------------------------------------------------------------------------
$5.50 to $9.99 878,780 3.4 $ 7.98 282,325 $ 8.06
$10.00 to $14.99 3,748,298 2.8 12.74 1,214,750 13.77
$15.00 to $19.56 1,947,745 2.6 16.28 661,057 16.46
----------------------------------------------------------------------------
$5.50 to $19.56 6,574,823 2.8 $ 13.16 2,158,132 $ 13.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 year ended December 31, 2009 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% (2008 2% to 4%); volatility ranged between 40% to 52% (2008 29% to 41%); an average expected life of 4.5 years (2008 - 4.5 years); an estimated forfeiture rate of 10% (2008 - 10%); and dividends of nil (2008 - nil). The weighted average fair value of stock options granted during the year ended December 31, 2009 was $4.00 per option (2008 - $4.67 per option). For the year ended December 31, 2009, the Company recorded stock-based compensation expense of $6.3 million (2008 - $4.5 million) and capitalized $2.3 million (2008 - $1.8 million) in stock-based compensation related to exploration and development activities.

(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 RSU's granted subsequent to November 2009, vest two years after the date the RSUs are issued.

For the year ended December 31, 2009, the Company recorded compensation expense related to RSU's of $1.7 million (2008 - $1.1 million) and capitalized $0.5 million (2008 - $0.3 million) to property, plant and equipment with a corresponding offset recorded in compensation liability. The compensation expense was calculated using the intrinsic value method based on the trading price of the Company's shares at the balance sheet date.



The following table summarizes the change in RSUs:

2009 2008
----------------------------------------------------------------------------
Number Number
----------------------------------------------------------------------------
Balance, beginning of year 351,543 -
Vested (122,314) -
Granted 204,154 390,163
Forfeited (18,592) (38,620)
----------------------------------------------------------------------------
Balance, end of year 414,791 351,543
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

2009 2008
----------------------------------------------------------------------------
Amount Amount
----------------------------------------------------------------------------
Balance, beginning of period $ 1,461 $ -
Change in accrued compensation liability 2,204 1,461
Cash payments (921) -
----------------------------------------------------------------------------
Balance, end of period $ 2,744 $ 1,461
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Compensation liability - current (included in
accounts payable
and accrued liabilities) $ 2,140 $ 611
----------------------------------------------------------------------------
Compensation liability - long-term $ 604 $ 850
----------------------------------------------------------------------------

 


For the year ended December 31, 2009, cash payments of $0.9 million (2008 - $nil) were made relating to the RSU Incentive Plan.

10. Income and other taxes

The provision for income tax differs from the result of which would have been obtained by applying the combined Federal and Provincial statutory income tax rate to the income before taxes. This difference results from the following items:



2009 2008
----------------------------------------------------------------------------
Statutory tax rate 29.2% 30.8%
----------------------------------------------------------------------------
Expected tax expense (recovery) $ (2,117) $ 38,693
Effect of change in tax rate (6,390) (7,691)
Stock-based compensation 1,835 1,375
Change in estimated pool balances (3,045) 5,259
----------------------------------------------------------------------------
Future income tax expense (recovery) $ (9,717) $ 37,636
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The significant components of net future income tax liability are as
follows:

2009 2008
----------------------------------------------------------------------------
Future income tax liabilities
Oil and natural gas properties $ 116,470 $ 115,060
Facilities and well equipment 35,587 36,921
Commodity derivative contracts - 4,954
Future income tax assets
Asset retirement obligations (16,010) (12,537)
Share issue costs (1,817) (1,633)
Commodity derivative contracts (732) -
Other (782) (32)
----------------------------------------------------------------------------
Net future income tax liability $ 132,716 $ 142,733
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Future income tax liability (asset) - current $ (1,336) $ 4,954
----------------------------------------------------------------------------
Future income tax liability - long-term $ 134,052 $ 137,779
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


For the year ended December 31, 2009, cash taxes paid was $nil (2008 - $nil).

11. Capital risk management

The Company's objectives when managing capital are: (i) to deploy capital to provide an appropriate return on investment to its shareholders; (ii) to maintain financial flexibility in order to preserve its ability to meet financial obligations; and (iii) to maintain a capital structure that provides financial flexibility to execute on strategic opportunities throughout the business cycle.

The Company's strategy is designed and formulated to maintain a flexible capital structure consistent with the objectives as stated above and to respond to changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include share capital, long-term debt, and working capital. In order to maintain or adjust its capital structure, the Company may issue new shares, raise debt, refinance existing debt and adjust capital spending.

A key measure the Company utilizes in evaluating its capital structure is the ratio of net debt to annualized funds from operations. Readers are cautioned that as the ratio of net debt to annualized funds from operations has no defined meaning under GAAP, this financial measure may not be comparable to similar measures provided by other reporting entities. The ratio is calculated as net debt, defined as outstanding long-term debt plus or minus working capital adjusted for the current portion of commodity derivative asset or liability and current portion of future income tax asset or liability, divided by cash flow from operations before asset retirement expenditures and changes in non-cash working capital for the most recent calendar quarter. The Company's strategy is to maintain a net debt to annualized funds from operations ratio of less than 2.0:1. At December 31, 2009, the Company had a ratio of net debt to annualized fourth quarter funds from operations of 1.8:1 (2008 - 1.5:1).

The Company's share capital is not subject to external restrictions; however the credit facility borrowing commitment is based on the lender's semi-annual review of the Company's petroleum and natural gas reserves. The Company is subject to various covenants under its credit facility. Compliance with these covenants is monitored on a regular basis and as at December 31, 2009, the Company was in compliance with all covenants. There were no changes to the Company's approach to capital management during the year.

12. Risk management activities

(a) Financial instruments

The Company's financial instruments recognized in the consolidated balance sheet consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, commodity derivative contracts 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.

All of the Company's cash and cash equivalents and commodity derivative contracts are transacted in active markets. The Company classifies fair value measurements according to the following hierarchy based on the amount of observable inputs used to value the instrument.

- Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

- Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

- Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The Company's cash and cash equivalents and commodity derivative contracts have been assessed on the fair value hierarchy described above. The Company's cash and cash equivalents are classified as Level 1 and commodity derivative contracts as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level.

As at December 31, 2009, the Company has entered into the following crude oil put option contracts: 



Option
Average Strike Premium
Volume Price (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
January 1, 2010 -
1,000 Bbls/d Cdn $80.30 - WTI $9.75(1) September 30, 2010
January 1, 2010 -
1,000 Bbls/d Cdn $77.50 - WTI $8.78(1) March 31, 2010
April 1, 2010 -
1,000 Bbls/d Cdn $87.40 - WTI $8.86(1) June 30, 2010
October 1, 2010 -
1,000 Bbls/d Cdn $89.40 - WTI $12.60(1) December 31, 2010

(1) The premiums are incurred monthly over the term of the contract and will
be offset against revenues.

As at December 31, 2009, the Company has entered into NYMEX natural gas
basis differential contracts as follows:

Volume Differential (US$/MMbtu) Term
----------------------------------------------------------------------------
5,000 MMbtu/d ($0.105) March 1, 2010 - March 31, 2010
20,000 MMbtu/d ($0.34) April 1, 2010 - October 31, 2010
15,000 MMbtu/d ($0.30) November 1, 2010 - March 31, 2011

 


As at December 31, 2009, the mark to market value of the financial derivative commodity contracts was a liability of $2.6 million (2008 - asset of $16.5 million). 

Subsequent to December 31, 2009, the following financial derivative crude oil put option contract has been entered into:



Option
Average Strike Premium
Volume Price (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
February 1, 2010 -
1,000 Bbls/d Cdn $86.75 - WTI $5.65(1) June 30, 2010

(1) The premiums are incurred monthly over the term of the contract and will
be offset against revenues.

(b) Physical sale contracts

(i) As at December 31, 2009, the Company has entered into direct natural gas
sale put option contracts as follows:

Average Price Premium
Volume (Cdn$/GJ) (Cdn$/GJ) Term
----------------------------------------------------------------------------
January 1, 2010 -
20,000 GJ/d Cdn $5.97 - $6.56 AECO Collar $0.30(1) March 31, 2010
January 1, 2010 -
20,000 GJ/d Cdn $5.55 - AECO Floor $0.97(1) March 31, 2010
April 1, 2010 -
20,000 GJ/d Cdn $5.97 - AECO Floor $0.53(1) October 31, 2010

(1) The premiums are incurred monthly over the term of the contract and will
be offset against revenues.

(ii) As at December 31, 2009, the Company has entered into a fixed price
contract for the purchase of electricity as follows:


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.

 


(c) Credit risk

Credit risk is the risk of financial loss to the Company if a counterparty to a financial instrument fails to meet its contractual obligation. The Company is exposed to credit risk with respect to its accounts receivables. Most of the Company's accounts receivable arise from transactions with joint venture partners and oil and natural gas sales with petroleum and natural gas marketers. The Company mitigates its credit risk by entering into contracts with established counterparties that have strong credit ratings and reviewing its exposure to individual counterparties on a regular basis. 

As at December 31, 2009, the accounts receivable balance was $51.4 million of which $6.7 million of accounts receivable were past due. The Company considers all amounts greater than 90 days past due. These past due accounts receivable are considered to be collectible. When determining whether past due accounts are uncollectible, the Company factors in the past credit history of the counterparties. As at December 31, 2009, the Company had an allowance for doubtful accounts of $0.4 million. 

At December 31, 2008, NuVista had an outstanding balance owing of $4.5 million from SemCAMS ULC and SemCanada Crude Company. In 2008, SemGroup LP filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code and two of SemGroup LP's Canadian subsidiaries, SemCAMS ULC and SemCanada Crude Company, filed for creditor protection under the Companies' Creditors Arrangement Act in Canada. At December 31, 2008 NuVista provided for the full $4.5 million balance owing in the Company's allowance for doubtful accounts. In 2009, NuVista recovered $0.2 million of the outstanding balance.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum credit exposure risk to the Company. The Company did not have accounts receivable balances owing from counterparties that constituted more than 10% of the total revenue during the year ended December 31, 2009. 

(d) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company manages its liquidity through continuously monitoring cash flows from operating activities, review of actual capital expenditure program, managing maturity profiles of financial assets and financial liabilities, maintaining a revolving credit facility with sufficient capacity, and managing its commodity price risk management program. These activities ensure that the Company has sufficient funds to meet its financial obligations when due. 



The timing of cash flows relating to financial liabilities as at December
31, 2009, is as follows:

Total 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------
Accounts payable
and accrued
liabilities $ 52,362 $ 52,362 $ - $ - $ - $ -
Long-term debt 384,623 - 384,623 - - -
Compensation
liability 2,744 2,140 454 150 - -
----------------------------------------------------------------------------
Total financial
liabilities $ 439,729 $ 54,502 $ 385,077 $ 150 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


(e) Market risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in commodity price risk, currency risk, and interest rate risk. The Company is engaged in oil and gas exploration, development and production activities in Canada and as a result has significant exposure to commodity price risk. The Company has adopted a disciplined commodity price risk management program as part of its overall financial management strategy. The Board of Directors has a commodity price risk management limit of up to a maximum of 60% of forecast production volumes, net of royalties. The company considers all of these transactions to be economic hedges but does not designate them as hedges for accounting purposes.

(i) Commodity price risk

Commodity price risk is the risk that the fair value of financial instruments will fluctuate as a result of changes in commodity prices. The Company manages the risks associated with changes in commodity prices through the use of various financial derivative and physical delivery sales contracts. The financial derivative contracts are considered financial instruments but the physical delivery sales contracts are excluded from the definition of financial instruments as discussed in note 1(g)(ii). Currently the Company uses financial instruments to manage crude oil and liquids commodity price risk and physical delivery sales contracts to manage natural gas price risk.

(ii) Currency risk

Currency risk is the risk that the fair value of a financial instrument will fluctuate as a result of changes in foreign exchange rates. The Company's financial instruments are only indirectly exposed to currency risk as the underlying commodity prices in Canada for petroleum and natural gas are impacted by changes in exchange rate between the Canadian and United States dollars. 

(iii) Interest rate risk

Interest rate risk is the risk that the fair value of a financial instrument will fluctuate because of changes in market interest rates. The Company's bank loan which bears a floating rate of interest is considered a financial instrument and is exposed to interest rate fluctuations. The Company had no interest rate financial derivative contracts in place as at or during the year ended December 31, 2009.

Financial instrument sensitivities

The following table summarizes the annualized sensitivities of the Company's net earnings to changes in the fair value of financial instruments outstanding at December 31, 2009, resulting in changes from the specified variable, with all other variables held constant. Changes in the fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear.



Impact on net earnings
----------------------------------------------------------------------------
Commodity price risk
Increase in Cdn$ WTI oil - $10/Bbl -
Decrease in Cdn$ WTI oil - $10/Bbl $2.0 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest rate risk
Increase in interest rate - 1% ($2.7 million)
Decrease in interest rate - 1% $2.7 million
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


13. Relationship with Bonavista Petroleum Ltd.

NuVista and Bonavista are considered related. Two of NuVista directors, one whom is NuVista's chairman, are also directors and officers of Bonavista. A director and an officer of NuVista are also officers of Bonavista. In 2009, NuVista charged Bonavista management fees totaling $1.2 million (2008 - $1.4 million) which is included in general and administrative expenses. As at December 31, 2009, the amount receivable from Bonavista was $0.3 million (2008 - $1.2 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.



14. Commitments

The following is a summary of the Company's contractual obligations and
commitments as at December 31, 2009:

Total 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------
Transportation $ 20,329 $ 5,851 $ 4,470 $ 3,489 $ 3,121 $ 3,398
Office lease 5,901 2,102 2,076 1,723 - -
Physical sale
contract
premiums 5,838 5,838 - - - -
Financial
contract
premiums 5,417 5,417 - - - -
Physical power
contract 6,900 - 2,300 2,300 2,300 -
Long-term debt 384,623 - 384,623 - - -
----------------------------------------------------------------------------
Total
commitments $ 429,008 $ 19,208 $ 393,469 $ 7,512 $ 5,421 $ 3,398
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


15. Subsequent Event

On March 8, 2010, NuVista's Board of Directors declared a quarterly dividend of $0.05 per common share. The first dividend payment will be on April 15, 2010, payable in cash, to shareholders of record on March 31, 2010. NuVista expects to implement a dividend re-investment plan for Canadian shareholders in the coming months, subject to regulatory approval.




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
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
Glenn A. Hamilton, Corporate Secretary

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 of California, 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, Alberta T2P 2W2
(403) 538-8500
(403) 538-8505 (FAX)
inv_rel@nuvistaenergy.com
www.nuvistaenergy.com