Contact Information: NuVista Energy Ltd. Robert F. Froese Vice President, Finance and CFO (403) 538-8530 or NuVista Energy Ltd. Suite 3500, 700 - 2nd Street SW Calgary, AB T2P 2W2 (403) 538-8500 (403) 538-8505 (FAX) inv_rel@nuvistaenergy.com www.nuvistaenergy.com
CALGARY, ALBERTA--(Marketwire - March 4, 2011) - NuVista Energy Ltd. (TSX:NVA) is pleased to announce its financial and operating results for the three months and year ended December 31, 2010, as follows:
/T/
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Corporate Highlights
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Three months Years ended
ended December 31, December 31,
------------------------------------------------------
% %
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Financial
($ thousands, except
per share)
Production revenue 89,552 95,957 (7) 373,327 345,272 8
Funds from
operations(1) 35,621 50,499 (29) 169,957 190,139 (11)
Per share - basic 0.40 0.57 (30) 1.92 2.29 (16)
Per share - diluted 0.40 0.56 (29) 1.92 2.28 (16)
Net earnings (loss) (13,417) 10,498 (228) (13,989) 2,476 (665)
Per share - basic (0.15) 0.12 (225) (0.16) 0.03 (633)
Per share - diluted (0.15) 0.12 (225) (0.16) 0.03 (633)
Total assets 1,597,068 1,555,743 3
Long-term debt, net
of working capital 444,756 369,004 21
Long-term debt, net
of adjusted working
capital(1) 444,093 367,747 21
Shareholders' equity 900,331 919,693 (2)
Net capital
expenditures 28,535 30,856 (8) 225,050 309,910 (27)
Weighted average
common shares
outstanding
(thousands):
Basic 88,719 88,335 - 88,583 83,152 7
Diluted 88,719 89,612 (1) 88,583 83,571 6
Cash dividends
declared 4,438 - - 17,723 - -
Per share 0.05 - - 0.20 - -
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Operating
(Boe conversion -
6:1 basis)
Production
Natural gas (MMcf/d) 121.2 123.5 (2) 123.9 116.6 6
Natural gas liquids
(Bbls/d) 3,024 3,312 (9) 3,053 3,193 (4)
Oil (Bbls/d) 4,935 4,454 11 4,647 4,330 7
Total oil equivalent
(Boe/d) 28,165 28,345 (1) 28,343 26,958 5
Product prices(2)
Natural gas ($/Mcf) 3.85 4.82 (20) 4.49 4.94 (9)
Natural gas liquids
($/Bbl) 52.76 43.43 21 51.48 38.58 33
Oil ($/Bbl) 64.38 67.33 (4) 63.66 63.22 1
Operating expenses
Natural gas and
natural gas liquids
($/Mcfe) 1.37 1.16 18 1.22 1.16 5
Oil ($/Bbl) 18.78 17.43 8 18.26 16.60 10
Total oil equivalent
($/Boe) 10.09 8.60 17 9.11 8.49 7
General and
administrative
expenses ($/Boe) 1.95 1.45 34 1.85 1.45 28
Funds from
operations netback
($/Boe)(1) 13.75 19.37 (29) 16.44 19.33 (15)
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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) Years ended December 31,
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2010 2009 % Change
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Undeveloped land, net acres
British Columbia/Northwest Alberta
core region 138,000 153,000 (10)
Alberta Deep Basin core region 251,000 251,000 -
Eastern Alberta/Saskatchewan core
region 471,000 488,000 (3)
Total Undeveloped land, net acres 860,000 892,000 (4)
Average working interest 81% 80% 1
Wells drilled gross (net)
Natural gas 31 (24.5) 33 (24.6) (6)
Oil 38 (25.6) 17 (12.7) 124
Dry holes 1 (1.0) 10 (9.3) (90)
Total wells drilled gross (net) 70 (51.1) 60 (46.6) 17
Company interest reserves(1)
Proved plus probable
Natural gas (Bcf) 488.9 438.7 11
Oil and liquids (Mbbls) 31,588 24,706 28
Total barrels of oil equivalent
(MBoe) 113,072 97,816 16
% proved producing 48% 56% (14)
% total proved 65% 70% (7)
% probable 35% 30% 17
Net present value of future cash
flows before tax ($ millions)(2)
@ 10% discount rate 1,402 1,586 (12)
@ 15% discount rate 1,110 1,307 (15)
Finding, development and
acquisition costs ($/Boe)(3) (5)
Total proved 22.04 14.15 56
Total proved plus probable 18.44 11.77 57
Reserve life index (years)(5)
Total proved 7.2 6.6 9
Total proved plus probable 11.0 9.5 16
Recycle ratio (4) (5)
Total proved 0.7 1.4 (50)
Total proved plus probable 0.9 1.6 (44)
Net asset value per share(2) (5) $ 12.19 $ 15.24 (20)
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NOTES:
(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 $135.3 million for proved reserves
and $247.0 million for proved plus probable reserves.
(4) Based on funds from operations netback per Boe divided by finding,
development and acquisition costs per Boe.
(5) For more details, refer to "Management's Discussion and Analysis"
section in this press release.
Trading Statistics
Three months ended Years ended
December 31, December 31,
-----------------------------------------
(Cdn$, except volumes) based on
intra-day trading 2010 2009 2010 2009
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High 10.60 14.00 14.56 14.00
Low 8.55 10.42 8.55 4.90
Close 9.25 12.48 9.25 12.48
Average daily volume 360,852 186,635 295,250 227,432
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/T/
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, 2010. During 2010, NuVista focused on value creation through the development of its existing asset base including the evaluation of various resource plays. This has resulted in NuVista now having the largest and most diverse inventory of drilling opportunities in its history. Our 2010 financial results were negatively impacted by lower natural gas prices however, as a result of executing our $225 million capital program, NuVista now has the flexibility to pursue light oil, heavy oil, liquids-rich natural gas or dry gas projects depending on the commodity price environment. In 2011, NuVista will continue to selectively evaluate oil and liquids-rich natural gas resource plays within its core regions where production and cash flow increases can be realized in the near term. In addition, we will continue to delineate our Wapiti Montney resource play. This liquids-rich natural gas play is at an early stage of evaluation but it has the potential to create significant long term growth and value for our shareholders, even in a low natural gas price environment.
On February 15, 2011, NuVista announced that it had entered into private placement agreements and a "bought deal" financing with a syndicate of underwriters for the issuance of in aggregate 10,500,000 common shares for gross proceeds of $99.8 million. NuVista also announced that it has decided to terminate its dividend in order to reallocate funds to its drilling program and growth opportunities. These events will significantly enhance our financial flexibility and NuVista's Board of Directors has approved a 2011 capital program of between $160 million and $180 million, including $35 million to further evaluate our Wapiti Montney resource play.
On November 23, 2010, NuVista announced the departure of Mr. Alex G. Verge, President and CEO. Mr. Verge became NuVista's President and CEO in July 2003 when NuVista was created from the reorganization of Bonavista Petroleum Ltd. NuVista would like to thank Mr. Verge for the key role he played in growing NuVista from an eastern Alberta focused company with production of approximately 3,500 barrels of oil equivalent per day ("Boe/d") to a company with significant properties in the Alberta deep basin and 2010 average production of 28,343 Boe/d. Mr. Robert F. Froese, Vice President, Finance and CFO, has been appointed as Interim President and CEO. NuVista's Board of Directors has formed an Executive Committee to assist Mr. Froese in the leadership of NuVista and to conduct an executive search for a President and CEO. Significant progress has been made in the search and the Executive Committee has begun interviewing candidates for this position. At this time, it is premature to predict the timing of the appointment of a President and CEO as this process is ongoing. In the interim, the Board of Directors has a high level of confidence in NuVista's management team to develop and execute NuVista's 2011 business plan and the Executive Committee will continue to assist management with key business decisions.
Significant operational highlights for the fourth quarter of 2010 and for the 2010 year include:
- Increased proved plus probable reserves by 16% to 113.1 million of barrels of oil equivalent ("Boe") in total and on a per share basis increased reserves by 15% to 1.27 Boe/share;
- Averaged 28,165 Boe/d of production for the three months ended December 31, 2010 compared with 28,345 Boe/d in the same period in 2009. In addition, 2010 average production increased by 5% to a record level of 28,343 Boe/d compared to 26,958 Boe/d in 2009;
- Evaluated six resource plays, including the Wapiti Montney liquids-rich natural gas play. NuVista's first horizontal well using multi-stage fracturing technology was brought on production in August with a 30 day initial production rate of 4.9 million cubic feet per day ("MMcf/d") of raw gas is currently producing 1.7 MMcf/d of raw gas. The raw gas is expected to produce a total of approximately 100 barrels per million cubic feet ("Bbls/MMcf") of liquids if the raw gas were processed through a deep-cut facility;
- In the fourth quarter, NuVista drilled 13 (8.1 net) wells resulting in 10 (6.1 net) oil wells and 3 (2.0 net) natural gas wells. For the year, NuVista drilled 70 (51.2 net) wells resulting in 38 (25.6 net) oil wells, 31 (24.5 net) natural gas wells and 1 (1.0 net) dry and abandoned well;
- Achieved finding, development and acquisition costs on a proved plus probable basis of $18.44/Boe (2009 - $11.77/Boe) (after revisions and including changes in future development capital and drilling credits); and
- Exited 2010 with debt, net of adjusted working capital, of $444 million. Following the closing of the private placements and public offerings currently scheduled for March 8, 2011, bank debt will be reduced to approximately $360 million.
NuVista's 2011 capital program of between $160 and $180 million will be allocated to a "core" capital program of high return oil and liquids-rich natural gas opportunities in its W3M/W4M and Deep Basin Core Regions. In addition, approximately $35 million of capital will be allocated to further advance the Wapiti Montney play.
2011 "Core" Capital Program
NuVista plans to drill heavy oil wells in west central Saskatchewan and eastern Alberta as part of its core 2011 capital program. These heavy oil wells have the most attractive economics of NuVista's opportunity inventory. Based on the strong results from four Zoller Lake Birdbear wells drilled in the fourth quarter of 2010, NuVista plans to drill up to 16 development wells. NuVista also plans to evaluate up to five new Birdbear heavy oil prospects which have been recently identified in west central Saskatchewan. In eastern Alberta, NuVista plans to drill follow-up wells to its successful heavy oil well drilled in the fourth quarter of 2010.
During the first quarter of 2011, NuVista has drilled and completed three follow-up wells to its West Pembina Cardium oil well in section 31-50-12W5M and a fourth follow-up well is planned for the second half of 2011. During 2011, NuVista also plans to drill additional evaluation and development wells at the Cardium oil play in its Wapiti operating area. NuVista plans to drill and complete three Wapiti Cardium oil wells in the first quarter of 2011 and plans to drill up to a six well program in the second half of 2011 to identify cost efficiencies and further evaluate the potential of this play. NuVista has a large contiguous Cardium land base in its Wapiti operating area and this high resource-in-place formation has consistent reservoir characteristics within this land base. NuVista also plans to drill and test the liquids-rich Notikewin and Spirit River formations in its Ferrier operating area where competitors have had success in offsetting lands.
2011 Wapiti Montney Capital Program
The results from the evaluation of NuVista's Wapiti Montney liquids-rich natural gas resource play in 2010 met NuVista's expectations. The Wapiti Montney play derives a significant portion of its cash flow from liquids and therefore exhibits good economics even at current natural gas prices. NuVista drilled its first Montney horizontal well (100%) in its north block of landholdings and completed this well in July 2010. This well was brought on production in August with a 30 day initial production rate of 4.9 MMcf/d of raw gas. The raw gas is expected to produce a total of approximately 100 barrels per million cubic feet ("Bbls/MMcf") of liquids if the raw gas were processed through a deep-cut facility. NuVista also drilled a Wapiti Montney horizontal well in its south block of landholdings. This well experienced mechanical issues but confirmed existence of liquids-rich natural gas. NuVista has extensive Montney landholdings of approximately 140 net sections.
There has been increased industry drilling activity in the liquids-rich Montney play at Wapiti and nearby Elmworth. Based on the results from NuVista and industry wells, NuVista believes this play has the potential to create significant value for shareholders over the next several years. NuVista's Board of Directors has approved a Wapiti Montney capital program for the next 15 months totaling $70 million. Up to five delineation wells are planned to be drilled and completed prior to spring break-up in 2012 in order to further evaluate the scope and economics of this play. NuVista is planning to drill three delineation wells at its north block and two wells at its south block to further delineate this play and secure crown licenses and leases. In addition, NuVista plans to construct a compressor and dehydration facility at its north block to accommodate increased production volumes. With continued success, NuVista expects to design and investigate gas processing alternatives in order to fully develop this property and maximize economic returns. Approximately $35 million of the approved capital program is expected to be spent in 2011 with the balance of this capital program to be spent in the first half of 2012.
2010 Year End Reserves Evaluation
The independent engineering evaluation of NuVista's reserves, effective December 31, 2010, was completed by GLJ Petroleum Consultants Ltd. Details of our reserves and finding and development costs were included in our press release dated February 15, 2011, 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, 2010. The following MD&A of financial condition and results of operations was prepared at and is dated March 4, 2011. Our audited consolidated financial statements, Annual Information Form and other disclosure documents for 2010 are 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, 2011.
Basis of presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent ("Boe") using six thousand cubic feet of natural gas equal to one barrel of oil, unless otherwise stated. In certain circumstances natural gas liquid volumes have been converted to thousand cubic feet equivalent ("Mcfe") on the basis of one barrel of natural gas liquids to six thousand cubic feet. Boes and Mcfes may be misleading, particularly if used in isolation. A conversion ratio of one barrel to six thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Forward-looking statements - Certain information set forth in this document contains forward-looking statements, including management's assessment of NuVista's future strategy, plans, opportunities and operations, forecast production, production mix, reserves growth, resource opportunities and potential, drilling, development, completion and tie-in plans and results, plans regarding new drilling and completion technology and the results therefrom, NuVista's planned capital budget, targeted debt level, the timing, allocation and efficiency of NuVista's capital program and the results therefrom, plans regarding facility construction and/or expansions, the timing thereof and the results therefrom, plans to pursue and complete acquisition opportunities, forecast funds from operations, the source of funding of capital expenditures and acquisitions, the objectives and focus of the 2011 capital program and the allocation thereof and results therefrom, anticipated operating costs and other expenses, benefits from the Alberta Government's announcement of royalty incentives, expectations regarding the payment of future taxes, estimated tax pools, estimated asset retirement obligations and expectations related to the timing of the incurrence of such costs, expectations regarding future commodity prices, netbacks and industry conditions, expectations regarding NuVista's IFRS conversion process and expectations regarding the completion of the Offerings, the timing of closing and the use of proceeds therefrom, estimated net debt following completion of the Offerings, and the timing of filing NuVista's 2010 Annual Information Form which are provided to allow investors to better understand our business.
In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. By their nature, forward-looking statements are based upon certain assumptions and are subject to numerous risks and uncertainties, some of which are beyond NuVista's control, including the impact of general economic conditions, industry conditions, current and future commodity prices, currency and interest rates, anticipated production rates, borrowing, operating and other costs and funds from operations, the timing and amount of capital expenditures and the results therefrom, anticipated reserves and the imprecision of reserve estimates, competition from other industry participants, availability of qualified personnel or management services and drilling and related equipment, stock market volatility, completion of the Offerings on the timing planned and the satisfaction of the conditions of closing, effects of regulation by governmental agencies including changes in environmental regulations, tax laws and royalties and the ability to access sufficient capital from internal sources and bank and equity markets and including, without limitation, those risks considered under "Risk Factors" in our Annual Information Form. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. NuVista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements, or if any of them do so, what benefits NuVista will derive therefrom. NuVista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP measurements - Within the MD&A, references are made to terms commonly used in the oil and natural gas industry. Management uses funds from operations to analyze operating performance and leverage. Funds from operations as presented, does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, per the statement of cash flows, net earnings (loss) or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures. Funds from operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net earnings (loss) per share. Funds from operations netbacks equal total revenue including realized commodity derivative gains/losses less royalties, transportation, operating costs, general and administrative, restricted stock unit, interest expense and cash taxes. Management also uses field netbacks to analyze operating performance and adjusted working capital to analyze leverage. Field netbacks and adjusted working capital as presented, do not have any standardized meaning prescribed by Canadian GAAP and therefore, may not be comparable with the calculation of similar measures for other entities. Field netbacks equal the total of revenue including realized commodity derivative gains/losses less royalties, transportation and operating costs. Adjusted working capital equals working capital excluding the current portion of the commodity derivative asset or liability and the future income tax asset or liability. Total Boe is calculated by multiplying the daily production by the number of days in the period.
Reserves - NuVista's 2010 year end total proved reserves were 74.0 MMBoe, a 9% increase over the closing balance at year end 2009. NuVista's proved plus probable reserves increased by 16% to 113.1 MMBoe compared to 97.8 MMBoe at year end 2009. Finding, development and acquisition costs in 2010, including an adjustment for the change in future development capital expenditures and after revisions, were $22.04/Boe on a proved basis and $18.44/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 $19.00/Boe in 2010. All future development capital expenditures are net of estimated drilling credits.
/T/
The following table outlines NuVista's finding, development and acquisition
costs:
3 Year-
Average (1) (2) 2010 (1) (2) 2009 (1) (2)
---------------------------------------------------
Proved Proved Proved
plus plus plus
Proved Probable Proved Probable Proved Probable
----------------------------------------------------------------------------
After reserve revisions
and including
changes in future
development capital
Finding, development
and acquisition
cost 20.41 16.52 22.04 18.44 14.15 11.77
Finding and development
costs 21.72 18.82 22.60 19.00 16.57 16.69
Acquisition costs 19.56 14.89 15.10 10.66 13.27 10.51
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(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 $17.6 million were recorded during 2010 and $10.7
million were recorded in 2009.
/T/
The capital program for 2010 resulted in a funds from operations netback recycle ratio of 0.9 on a proved plus probable basis. NuVista's reserve life index, based upon 2010 fourth quarter average production of 28,165 Boe/d, was 7.2 years for total proved reserves and 11.0 years for proved plus probable reserves. This compares with 6.6 years and 9.5 years respectively at December 31, 2009. All of NuVista's reserves, as at December 31, 2010, were evaluated by NuVista's independent engineering consultants, GLJ Petroleum Consultants Ltd.
Additional reserve disclosure tables, as required under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), will be contained in the Annual Information Form to be filed on SEDAR on or before March 31, 2011. 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" 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.
/T/
The following table is a reconciliation of the 2010 year end reserves with
the reserves reported in the 2009 year end report:
Total oil
Natural gas Liquids Oil equivalent
Reconciliation items (1) (Bcf) (Mbbls) (Mbbls) (MBoe)
----------------------------------------------------------------------------
Total Proved
Balance, December 31, 2009 305.2 7,530 9,595 67,984
Exploration and development 46.5 2,039 3,763 13,547
Revisions (including
improved recovery) 6.7 54 416 1,588
Acquisitions 6.1 254 - 1,269
Dispositions (0.3) (4) - (54)
Production (45.2) (1,115) (1,697) (10,347)
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Balance, December 31, 2010 319.0 8,758 12,077 73,988
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Total Proved plus Probable
Balance, December 31, 2009 438.7 11,099 13,607 97,816
Exploration and development 89.5 3,917 5,896 24,731
Revisions (including
improved recovery) (2.2) (274) (205) (852)
Acquisitions 8.9 388 - 1,878
Dispositions (0.8) (29) - (155)
Production (45.2) (1,115) (1,697) (10,347)
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Balance, December 31, 2010 488.9 13,986 17,602 113,071
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(1) Numbers may not add due to rounding.
Net Asset Value Per Share
($ thousands) 2010 2009
----------------------------------------------------------------------------
Net present value of oil and gas reserves,
discounted at 10%, before tax (1) $ 1,402,478 $ 1,585,998
Undeveloped land (2) 123,575 128,175
Cash, accounts receivable and prepaids 55,144 69,238
Accounts payable and accrued liabilities (56,233) (52,362)
Dividends payable (4,438) -
Long-term debt (438,566) (384,623)
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Net asset value $ 1,081,960 $ 1,346,426
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Shares outstanding (000's) 88,760 88,361
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Net asset value ($/share) $ 12.19 $ 15.24
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(1) Proved plus probable company interest reserves, as at December 31,
2010, as evaluated by GLJ Petroleum Consultants Ltd.
(2) Undeveloped land value has been calculated based on management's
internal estimates of $250/acre for deep basin lands and $100/acre for
all other acreage.
/T/
Operating activities - For the three months ended December 31, 2010, NuVista drilled 13 (8.1 net) wells resulting in 10 (6.1 net) oil wells and 3 (2.0 net) natural gas wells. NuVista drilled 4 (3.0 net) heavy oil wells at Zoller Lake in west central Saskatchewan, 3 (0.8 net) Wapiti Cardium oil wells, 2 (1.3 net) Pembina Cardium oil wells, and 1 (1.0 net) heavy oil well in eastern Alberta. NuVista drilled 3 (2.0 net) natural gas wells in its Wapiti and Kaybob operating areas.
For the year ended December 31, 2010, NuVista drilled 70 (51.1 net) wells resulting in 38 (25.6 net) oil wells, 31 (24.5 net) natural gas wells and 1 (1.0 net) dry and abandoned well. NuVista operated 56 of the wells and a total of 41 horizontal wells were drilled during the year.
/T/
Production
Three months ended December 31,
--------------------------------
2010 2009 % Change
----------------------------------------------------------------------------
Natural gas (Mcf/d) 121,238 123,476 (2)
Liquids (Bbls/d) 3,024 3,312 (9)
Oil (Bbls/d) 4,935 4,454 11
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Total oil equivalent (Boe/d) 28,165 28,345 (1)
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Years ended December 31,
--------------------------------
2010 2009 % Change
----------------------------------------------------------------------------
Natural gas (Mcf/d) 123,860 116,608 6
Liquids (Bbls/d) 3,053 3,193 (4)
Oil (Bbls/d) 4,647 4,330 7
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Total oil equivalent (Boe/d) 28,343 26,958 5
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/T/
For the three months ended December 31, 2010, NuVista's average production was 28,165 Boe/d, comprised of 121.2 MMcf/d of natural gas, 3,024 Bbls/d of associated natural gas liquids ("liquids") and 4,935 Bbls/d of oil, which represents an overall 1% average decrease compared to the same period in 2009. The slight decrease in NuVista's production during the three months ended December 31, 2010 compared to the same period in 2009 was primarily due to natural production declines in natural gas and liquids offset by increased oil production generated by increased drilling activity in oil wells in 2010.
NuVista's production for the year ended December 31, 2010 averaged 28,343 Boe/d comprised of 123.9 MMcf/d of natural gas, 3,053 Bbls/d of liquids and 4,647 Bbls/d of oil, which represents an overall 5% average increase over the same period in 2009. The increase in production for the year ended December 31, 2010 compared to the same period in 2009 is primarily due to production additions from acquisitions completed in 2009 and 2010 and increased drilling activity in oil wells.
/T/
Revenues
Three months ended December 31,
($ thousands, except ----------------------------------------------
per unit amounts) 2010 2009 % Change
----------------------------------------------------------------------------
Natural Gas $ $/Mcf $ $/Mcf $ $/Mcf
Production
revenue (1) 43,040 3.86 54,796 4.82 (21) (20)
Realized gain (loss)
on commodity
derivatives (80) (0.01) - - - -
----------------------------------------------------------------------------
Total Natural Gas 42,960 3.85 54,796 4.82 (22) (20)
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----------------------------------------------------------------------------
Liquids $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 14,678 52.76 13,233 43.43 11 21
Realized gain (loss)
on commodity
derivatives - - - - - -
----------------------------------------------------------------------------
Total Liquids 14,678 52.76 13,233 43.43 11 21
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Oil $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 31,834 70.12 27,928 68.15 14 3
Realized gain (loss)
on commodity
derivatives (2,605) (5.74) (336) (0.82) 675 600
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Total Oil 29,229 64.38 27,592 67.33 6 (4)
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Total $ $/Boe $ $/Boe $ $/Boe
Production revenue 89,552 34.56 95,957 36.80 (7) (6)
Realized gain (loss)
on commodity
derivatives (2,685) (1.04) (336) (0.13) 699 700
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Total Revenue 86,867 33.52 95,621 36.67 (9) (9)
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(1) Natural gas revenue includes price risk management gains and losses on
physical sale contracts. For the three months ended December 31, 2010,
our physical sale contracts resulted in a gain of $1.4 million (2009 -
$3.8 million gain).
Years ended December 31,
($ thousands, except ----------------------------------------------
per unit amounts) 2010 2009 % Change
----------------------------------------------------------------------------
Natural Gas $ $/Mcf $ $/Mcf $ $/Mcf
Production
revenue(1) 201,969 4.47 208,849 4.91 (3) (9)
Realized gain (loss)
on commodity
derivatives 779 0.02 1,421 0.03 (45) (33)
----------------------------------------------------------------------------
Total Natural Gas 202,748 4.49 210,270 4.94 (4) (9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liquids $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 57,357 51.48 44,957 38.58 28 33
Realized gain (loss)
on commodity
derivatives - - - - - -
----------------------------------------------------------------------------
Total Liquids 57,357 51.48 44,957 38.58 28 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil $ $/Bbl $ $/Bbl $ $/Bbl
Production revenue 114,001 67.21 91,466 57.87 25 16
Realized gain (loss)
on commodity
derivatives (6,018) (3.55) 8,461 5.35 (171) (166)
----------------------------------------------------------------------------
Total Oil 107,983 63.66 99,927 63.22 8 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total $ $/Boe $ $/Boe $ $/Boe
Production revenue 373,327 36.09 345,272 35.09 8 3
Realized gain (loss)
on commodity
derivatives (5,239) (0.51) 9,882 1.00 (153) (151)
----------------------------------------------------------------------------
Total Revenue 368,088 35.58 355,154 36.09 4 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Natural gas revenue includes price risk management gains and losses on
physical sale contracts. For the year ended December 31, 2010, our
physical sale contracts resulted in a gain of $8.7 million (2009 -
$31.1 million gain).
/T/
For the three months ended December 31, 2010, revenues including realized commodity derivative gains and losses were $86.9 million, a 9% decrease from $95.6 million for the same period in 2009. The decrease in revenues for the three months ended December 31, 2010 compared to the same period of 2009 is primarily due to a 9% decrease in realized prices. Revenues were comprised of $43.0 million of natural gas revenue, $14.7 million of liquids revenue, and $29.2 million of oil revenue. The decrease in average realized commodity prices is comprised of a 20% decrease in the natural gas price to $3.85/Mcf from $4.82/Mcf, a 21% increase in the liquids price to $52.76/Bbl from $43.43/Bbl and a 4% decrease in the oil price to $64.38/Bbl from $67.33/Bbl.
For the year ended December 31, 2010, revenues including realized commodity derivative gains and losses were $368.1 million, a 4% increase from $355.2 million for the same period in 2009. The increase in revenues for 2010 compared to the same period of 2009 is primarily due to a 1% decrease in realized prices offset by a 5% increase in production volumes. These revenues were comprised of $202.7 million of natural gas revenue, $57.4 million of liquids revenue, and $108.0 million of oil revenue. The decrease in average realized commodity prices is comprised of a 9% decrease in the natural gas price to $4.49/Mcf from $4.94/Mcf, a 33% increase in the liquids price to $51.48/Bbl from $38.58/Bbl, and a 1% increase in the oil price to $63.66/Bbl from $63.22/Bbl.
/T/
Commodity price risk management
Three months ended December 31,
----------------------------------------------------------------
($ thousands) 2010 2009
----------------------------------------------------------------------------
Realized Unrealized Total Realized Unrealized Total
Gain Gain Gain Gain Gain Gain
(Loss) (Loss) (Loss) (Loss) (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas (80) (1,048) (1,128) - - -
Oil (2,605) (5,028) (7,633) (336) (3,818) (4,154)
----------------------------------------------------------------------------
Total gain
(loss) (2,685) (6,076) (8,761) (336) (3,818) (4,154)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Years ended December 31,
----------------------------------------------------------------
($ thousands) 2010 2009
----------------------------------------------------------------------------
Realized Unrealized Total Realized Unrealized Total
Gain Gain Gain Gain Gain Gain
(Loss) (Loss) (Loss) (Loss) (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas 779 1,906 2,685 1,421 (1,094) 327
Oil (6,018) (4,653)(10,671) 8,461 (18,012) (9,551)
----------------------------------------------------------------------------
Total gain
(loss) (5,239) (2,747) (7,986) 9,882 (19,106) (9,224)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
As part of our financial risk management strategy, NuVista has adopted a disciplined commodity price risk management program. The purpose of this program is to reduce volatility in our financial results, protect acquisition economics and help stabilize cash flow against the unpredictable commodity price environment. NuVista's Board of Directors has approved a price risk management limit of up to 60% of forecast production, net of royalties, using fixed price, differential, put option and costless collar contracts. To achieve NuVista's price risk management objectives, we enter into both commodity derivative and physical sale contracts.
For the three months ended December 31, 2010, the commodity price risk management program resulted in a loss of $8.8 million, consisting of realized losses of $2.7 million and a $6.1 million unrealized loss on natural gas and oil contracts. For the year ended December 31, 2010, the commodity price risk management program resulted in a loss of $8.0 million, consisting of realized losses of $5.2 million and an unrealized loss of $2.8 million on natural gas and oil contracts. As at December 31, 2010, the mark-to-market value of our financial derivative commodity contracts was a liability of $5.3 million.
For the three months ended December 31, 2010, price risk management gains on our physical sale contracts totaled $1.4 million. For the year ended December 31, 2010, price risk management gains on our physical sale contracts totaled $8.7 million. The physical sale contracts are purchase and sale transactions entered into the normal course of business.
The following is a summary of commodity price risk management contracts in place as at December 31, 2010:
/T/
(a) Financial instruments
As at December 31, 2010, NuVista has the following crude oil put option
contracts in place:
Average
Strike Option
Price Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
----------------------------------------------------------------------------
4,000 Bbls/d $87.52 - WTI $8.93 January 1, 2011 - March 31, 2011
3,000 Bbls/d $88.03 - WTI $9.29 April 1, 2011 - December 31, 2011
2,000 Bbls/d $88.55 - WTI $9.43 January 1, 2012 - March 31, 2012
As at December 31, 2010, NuVista has the following NYMEX natural gas basis
differential contracts in place:
Volume Differential (US$/MMbtu) Term
----------------------------------------------------------------------------
25,000 MMbtu/d ($0.34) January 1, 2011 - March 31, 2011
40,000 MMbtu/d ($0.46) April 1, 2011 - October 31, 2011
30,000 MMbtu/d ($0.51) November 1, 2011 - March 31, 2012
/T/
As at December 31, 2010, the mark-to-market value of the above derivative commodity contracts was a liability of $5.3 million (December 31, 2009 - a liability of $2.6 million).
As at December 31, 2010, NuVista has the following non-financial fixed price contract for the purchase of electricity in place:
/T/
Volume Price (Cdn$/Mwh) Term
----------------------------------------------------------------------------
4.0 Mwh $65.64 January 1, 2011 - December 31, 2013
Subsequent to December 31, 2010, the following financial derivative crude
oil fixed price contract has been entered into:
Volume Strike Price (Cdn$/Bbl) Term
----------------------------------------------------------------------------
1,000 Bbls/d $97.50 - WTI April 1, 2011 - June 30, 2012
Royalties
Three months ended Years ended
December 31, December 31,
----------------------------------------
Royalty rates (%) 2010 2009 2010 2009
----------------------------------------------------------------------------
Natural gas and liquids 15 12 15 12
Oil 13 15 16 14
----------------------------------------------------------------------------
Weighted average rate 14 13 15 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
For the three months ended December 31, 2010, royalties were $12.7 million, 4% higher than the $12.2 million for the same period of 2009. Royalties for the year ended December 31, 2010 were $57.3 million compared to $43.1 million reported for the year ended December 31, 2009. The increase in royalties for the year ended December 31, 2010 compared to the same period in 2009 is largely due to an 8% increase in production revenues, an increase in royalty rates and one-time gas cost allowance adjustments.
Royalty rates by product for the three months ended December 31, 2010 were 15% for natural gas and liquids and 13% for oil compared to 12% for natural gas and liquids and 15% for oil for the same period in 2009. As a percentage of production revenue, the reported average royalty rate for the three months ended December 31, 2010 was 14% compared to 13% for the comparative period of 2009. Reported average royalty rates for the year ended December 31, 2010 by product were 15% for natural gas and liquids and 16% for oil compared to 12% for natural gas and liquids and 14% for oil for the same period in 2009. For the year ended December 31, 2010, the average royalty rate as a percentage of production revenue was 15% compared to 12% for the same period in 2009. The increase in royalty rates is primarily due to a decrease in physical price risk management gains included in production revenue, higher royalty rates attributed to properties acquired in 2009 and one-time gas cost allowance adjustments.
Our physical price risk management activities impact reported royalty rates as royalties are based on government market reference prices and not our average realized prices that include price risk management activities. As a result, the gains on our price risk management activities included in production revenue result in lower royalty rates as a percentage of production revenue than if no price risk management activities had taken place. Excluding the impact of price risk management activities natural gas and liquids royalty rates for the year ended December 31, 2010 were approximately 15% compared to 14% for the same period in 2009 and the oil royalty rates for the year ended December 31, 2010 were approximately 16% compared to 14% for the same period in 2009.
On March 11, 2010, the Government of Alberta announced amendments to its royalty framework as a result of a competitiveness review. Effective January 1, 2011, the maximum royalty rate was reduced from the 2010 levels of 50% for both oil and natural gas to 40% for oil and 36% for natural gas. Other changes include permanently instating a maximum 5% royalty rate on oil and natural gas with the existing time and volume limits effective May 2010.
On May 27, 2010, the Government of Alberta announced its changes to the base royalty curves for oil and natural gas which take effect on January 1, 2011. The Government also announced further initiatives designed to spur investment in Alberta's unconventional and deep resource pools. These initiatives were effective May 2010 and include a 5% royalty on shale gas, coalbed methane and horizontal oil and gas wells with time and volume limits.
Netbacks - The table below summarizes field netbacks by product for the three months ended December 31, 2010:
/T/
Natural gas and
liquids Oil Total
--------------------------------------------------
($ thousands, except per
unit amounts) 139.4 MMcfe/d 4,935 Bbls/d 28,165 Boe/d
----------------------------------------------------------------------------
$ $/Mcfe $ $/Bbl $ $/Boe
Production revenue 57,718 4.50 31,834 70.12 89,552 34.56
Realized gain (loss) on
commodity derivatives (80) (0.01) (2,605) (5.74) (2,685) (1.04)
----------------------------------------------------------------------------
57,638 4.49 29,229 64.38 86,867 33.52
Royalties (8,684) (0.68) (4,003) (8.82) (12,687) (4.90)
Transportation costs (1,490) (0.12) (358) (0.79) (1,848) (0.71)
Operating costs (17,626) (1.37) (8,528) (18.78) (26,154) (10.09)
----------------------------------------------------------------------------
Field netback(1) 29,838 2.32 16,340 35.99 46,178 17.82
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
The following table summarizes field netbacks by product for the year ended December 31, 2010:
/T/
Natural gas and
liquids Oil Total
--------------------------------------------------
($ thousands, except per
unit amounts) 142.2 MMcfe/d 4,647 Bbls/d 28,343 Boe/d
----------------------------------------------------------------------------
$ $/Mcfe $ $/Bbl $ $/Boe
Production revenue 259,326 5.00 114,001 67.21 373,327 36.09
Realized gain (loss) on
commodity derivatives 779 0.02 (6,018) (3.55) (5,239) (0.51)
----------------------------------------------------------------------------
260,105 5.02 107,983 63.66 368,088 35.58
Royalties (38,803) (0.75) (18,544) (10.93) (57,347) (5.54)
Transportation costs (6,803) (0.13) (1,785) (1.05) (8,588) (0.83)
Operating costs (63,271) (1.22) (30,966) (18.26) (94,237) (9.11)
----------------------------------------------------------------------------
Field netback(1) 151,228 2.92 56,688 33.42 207,916 20.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refer to "non-GAAP measurements" in the MD&A.
/T/
Funds from operations - The tables below summarize funds from operations netbacks for the three months ended December 31, 2010 compared to the three months ended December 31, 2009 and the year ended December 31, 2010 compared to the year ended December 31, 2009:
/T/
Three months ended December 31,
($ thousands, except per unit --------------------------------------------
amounts) 2010 2009 % Change
----------------------------------------------------------------------------
$ $/Boe $ $/Boe $ $/Boe
Production revenue 89,552 34.56 95,957 36.80 (7) (6)
Realized gain (loss) on
commodity derivatives (2,685) (1.04) (336) (0.13) 699 700
----------------------------------------------------------------------------
86,867 33.52 95,621 36.67 (9) (9)
Royalties (12,687) (4.90) (12,153) (4.66) 4 5
Transportation (1,848) (0.71) (2,087) (0.80) (11) (11)
Operating costs (26,154) (10.09) (22,435) (8.60) 17 17
----------------------------------------------------------------------------
Field netback 46,178 17.82 58,946 22.61 (22) (21)
General and administrative (5,047) (1.95) (3,784) (1.45) 33 34
Restricted stock units (217) (0.08) (461) (0.18) (53) (56)
Interest (5,293) (2.04) (4,202) (1.61) 26 27
----------------------------------------------------------------------------
Funds from operations
netback(1) 35,621 13.75 50,499 19.37 (29) (29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Years ended December 31,
($ thousands, except per unit ---------------------------------------------
amounts) 2010 2009 % Change
----------------------------------------------------------------------------
$ $/Boe $ $/Boe $ $/Boe
Production revenue 373,327 36.09 345,272 35.09 8 3
Realized gain (loss) on
commodity derivatives (5,239) (0.51) 9,882 1.00 (153) (151)
----------------------------------------------------------------------------
368,088 35.58 355,154 36.09 4 (1)
Royalties (57,347) (5.54) (43,107) (4.38) 33 26
Transportation (8,588) (0.83) (8,307) (0.84) 3 (1)
Operating costs (94,237) (9.11) (83,583) (8.49) 13 7
----------------------------------------------------------------------------
Field netback 207,916 20.10 220,157 22.38 (6) (10)
General and administrative (19,173) (1.85) (14,280) (1.45) 34 28
Restricted stock units (1,073) (0.10) (1,677) (0.17) (36) (41)
Interest (17,713) (1.71) (14,061) (1.43) 26 20
----------------------------------------------------------------------------
Funds from operations
netback(1) 169,957 16.44 190,139 19.33 (11) (15)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refer to "non-GAAP measurements" in the MD&A.
A reconciliation of funds from operations is presented in the following
table:
Three months ended Years ended
December 31, December 31,
---------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by operating activities 42,717 60,867 167,455 191,659
Add back:
Asset retirement expenditures 663 772 7,740 2,615
Change in non-cash working capital (7,759) (11,140) (5,238) (4,135)
----------------------------------------------------------------------------
Funds from operations(1) 35,621 50,499 169,957 190,139
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Refer to "non-GAAP measurements" in the MD&A.
/T/
For the three months ended December 31, 2010, NuVista's funds from operations were $35.6 million ($0.40/share, basic), a 29% decrease from $50.5 million ($0.57/share, basic) for the three months ended December 31, 2009. For the year ended December 31, 2010, NuVista's funds from operations were $170.0 million ($1.92/share, basic), a 11% decrease from $190.1 million ($2.29/share, basic) in the same period of 2009. Funds from operations for the three and twelve months ended December 31, 2010 were lower than the same period in 2009 primarily due to lower natural gas prices, higher operating costs and higher royalty rates.
Transportation - Transportation costs were $1.8 million ($0.71/Boe) for the three months ended December 31, 2010 as compared to $2.1 million ($0.80/Boe) for the same period of 2009. Transportation costs were $8.6 million ($0.83/Boe) for the year ended December 31, 2010 compared to $8.3 million ($0.84/Boe) for the same period in 2009. The decrease in transportation costs is due to year end rate corrections and lower pipeline costs experienced in the fourth quarter of 2010.
Operating - Operating expenses were $26.2 million ($10.09/Boe) for the three months ended December 31, 2010 as compared to $22.4 million ($8.60/Boe) for the three months ended December 31, 2009. This increase resulted from a 17% increase in per unit costs. The per unit operating costs were higher in 2010 compared to the same period in 2009 due to higher operating cost structure associated with the oil properties purchased in 2009 located in northwest Alberta and one-time third party charges for processing and power. For the three months ended December 31, 2010, natural gas and liquids operating expenses averaged $1.37/Mcfe and oil operating expenses were $18.78/Bbl as compared to $1.16/Mcfe and $17.43/Bbl respectively for the same period of 2009.
Operating expenses were $94.2 million ($9.11/Boe) for the year ended December 31, 2010 as compared to $83.6 million ($8.49/Boe) for the same period in 2009. For the year ended December 31, 2010, natural gas and liquids operating costs averaged $1.22/Mcfe and oil operating expenses were $18.26/Bbl as compared to $1.16/Mcfe and $16.60/Bbl respectively for the same period in 2009. The increase, on a total dollar basis, resulted primarily from third party charges related to gas processing adjustments and equalization payments.
/T/
General and administrative
Three months ended Years ended
December 31, December 31,
----------------------------------------
($ thousands, except per unit amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Gross general and administrative
expenses 7,013 5,183 25,640 19,476
Overhead recoveries (1,966) (1,399) (6,467) (5,196)
----------------------------------------------------------------------------
Net general and administrative
expenses 5,047 3,784 19,173 14,280
----------------------------------------------------------------------------
Per Boe 1.95 1.45 1.85 1.45
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
General and administrative expenses, net of overhead recoveries, for the three months ended December 31, 2010 were $5.0 million ($1.95/Boe) compared to $3.8 million ($1.45/Boe) in the same period of 2009. General and administrative expenses, net of overhead recoveries, for the year ended December 31, 2010 were $19.2 million ($1.85/Boe) as compared to $14.3 million ($1.45/Boe) for the year ended December 31, 2009. The increase in general and administrative costs in 2010 compared to 2009 is primarily due to an increase in staffing levels and one-time costs associated with the International Financial Reporting Standards ("IFRS") conversion, a partnership rationalization with Bonavista Energy Corporation and an executive severance payment.
/T/
Stock-based compensation
Three months ended Years ended
December 31, December 31,
-----------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Stock-based compensation 1,879 1,609 6,556 6,278
Restricted stock units 217 461 1,073 1,677
----------------------------------------------------------------------------
Total 2,096 2,070 7,629 7,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
NuVista recorded a stock-based compensation charge of $2.1 million for the three months ended December 31, 2010 compared to $2.1 million for the same period in 2009. For the year ended December 31, 2010, NuVista recorded a stock-based compensation charge of $7.6 million compared to $8.0 million for the same period in 2009. The stock-based compensation charge relates to the amortization of the fair value of stock option awards and the accrual for future payments under the Restricted Stock Unit ("RSU") Incentive Plan.
Interest - Interest expense for the three months ended December 31, 2010 was $5.3 million ($2.04/Boe) compared to $4.2 million ($1.61/Boe) for the same period of 2009. Interest expense for the year ended December 31, 2010 was $17.7 million ($1.71/Boe) compared to $14.1 million ($1.43/Boe) in the same period of 2009. For the three months ended December 31, 2010, borrowing costs averaged 4.4% compared to 3.2% in the same period of 2009. Interest expense for the year ended December 31, 2010 increased compared to the same period in 2009 due to higher debt levels in 2010 and an increase in the average borrowing rate. Currently, NuVista's average borrowing rate is approximately 4.5%. Cash paid for interest for the three months and year ended December 31, 2010 was $5.2 million (2009 - $4.3 million) and $17.9 million (2009 - $13.8 million) respectively.
/T/
Depreciation, depletion and accretion
Three months ended Years ended
December 31, December 31,
----------------------------------------
($ thousands except per Boe amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Depletion of oil and gas assets(1) 41,826 37,616 155,916 149,325
Depreciation of fixed assets 4,630 4,879 19,178 18,753
Accretion of asset retirement
obligation(2) 1,161 968 4,645 4,100
----------------------------------------------------------------------------
Total DD&A 47,617 43,463 179,739 172,178
DD&A rate per Boe 18.38 16.67 17.37 17.50
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
/T/
Depreciation, depletion and accretion expenses were $47.6 million for the fourth quarter of 2010 as compared to $43.5 million for the same period in 2009. The average per unit cost was $18.38/Boe in the fourth quarter of 2010 as compared to $16.67/Boe for the same period in 2009. Per unit costs in the fourth quarter of 2010 increased from the same period in 2009 due to higher finding and development costs recognized in the quarter. Depreciation, depletion and accretion expenses for the year ended December 31, 2010 were $179.7 million as compared to $172.2 million for the same period in 2009. The average per unit cost was $17.37/Boe for the year ended December 31, 2010 as compared to $17.50/Boe in the same period in 2009.
Asset retirement obligations - Asset retirement obligations ("ARO") 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, 2010 NuVista recorded an ARO of $62.7 million as compared to $61.8 million for the same period in 2009. At December 31, 2010, the estimated total undiscounted amount of cash flows required to settle NuVista's ARO is $235.9 million (2009 - $261.5 million), which will be incurred over the next 51 years. The majority of the costs are expected to be incurred between 2011 and 2030. A credit-adjusted risk-free rate of 8% and an inflation rate of 2% were used to calculate the fair value of the ARO.
There are uncertainties related to asset retirement obligations and the impact on the financial statements could be material as the eventual timing of and costs to settle these obligations could differ from our estimates. The main factors that could cause expected cash flows to differ are changes to laws, regulations, reserve estimates, costs and technology. Any reclamation or abandonment expenditures will generally be funded from cash flow from operating activities.
Income taxes - For the three months ended December 31, 2010, the provision for income and other taxes was a recovery of $6.5 million compared to a recovery of $8.7 million for the same period in 2009. For the year ended December 31, 2010, the provision for income and other taxes was a recovery of $5.1 million compared to a recovery of $9.7 million in the same period of 2009. The decrease in recovery for the year ended December 31, 2010 compared to the same period in 2009 is primarily attributable to the larger impact of the change in corporate tax rates and adjustments to the estimated tax pools in the 2009 fiscal period.
/T/
Capital expenditures
Three months ended Years ended
December 31, December 31,
---------------------------------------
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Exploration and development
Land and retention costs 420 2,950 19,118 5,980
Seismic 1,454 3,748 11,762 10,539
Drilling and completion 25,863 24,968 151,115 54,955
Facilities and equipment 7,241 3,075 42,022 19,603
Corporate and other 154 2,419 240 3,226
----------------------------------------------------------------------------
Subtotal 35,132 37,160 224,257 94,303
----------------------------------------------------------------------------
Alberta drilling incentive credits (1,563) (5,164) (17,564) (10,699)
----------------------------------------------------------------------------
Subtotal 33,569 31,996 206,693 83,604
----------------------------------------------------------------------------
Property acquisitions (dispositions) (5,034) (1,140) 18,357 226,306
----------------------------------------------------------------------------
Net capital expenditures 28,535 30,856 225,050 309,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Capital expenditures were $28.5 million during the fourth quarter of 2010, consisting of $33.6 million of exploration and development spending (net of drilling credits) and a $5.0 million undeveloped land disposition. This compares to $30.9 million incurred for the same period of 2009, consisting of exploration and development spending (net of drilling credits) of $32.0 million and credits of $1.1 million of final statement of adjustments for a property acquisition. Capital expenditures for the year ended December 31, 2010 were $225.1 million, consisting of $206.7 million of exploration and development spending (net of drilling credits) and $18.4 million of net acquisitions of producing and non-producing properties. This compares to $309.9 million incurred for the same period of 2009, consisting of $83.6 million of exploration and development spending (net of drilling credits) and two significant property acquisition totaling $226.3 million, the first acquisition was in natural gas properties and related facilities in the Ferrier/Sunchild, Wapiti and northwest Saskatchewan operating areas ($55.6 million) and the second acquisition was in northeast British Columbia and northwest Alberta ($172.3 million).
Net earnings - For the three months ended December 31, 2010, the net loss was $13.4 million (loss of $0.15/share, basic) compared to net earnings of $10.5 million ($0.12/share, basic) for the same period in 2009. NuVista's net loss for the year ended December 31, 2010 was $14.0 million (loss of $0.16/share, basic) compared to net earnings of $2.5 million ($0.03/share, basic) in the same period in 2009. Net earnings for the year ended December 31, 2010 decreased compared to the same period in 2009 primarily due to lower natural gas prices, higher operating costs and higher royalty rates.
/T/
Tax pools
Income Tax Pool Type Available Balance Maximum Annual Deduction
----------------------------------------------------------------------------
($ thousands) 2010 %
----------------------------------------------------------------------------
Canadian exploration expense 35,000 100%
Canadian development expense 185,000 30% declining balance
Canadian oil and natural gas
property expense 500,000 10% declining balance
Undepreciated capital cost 175,000 25% declining balance
Other 5,000 Various rates
----------------------------------------------------------------------------
Total tax pools 900,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
At December 31, 2010, NuVista had approximately $900 million (2009 - $990 million) of estimated tax pools available for deduction against future years' taxable income.
/T/
Liquidity and capital resources
($ thousands) 2010 2009
----------------------------------------------------------------------------
Common shares outstanding 88,760 88,361
Share price(1) 9.25 12.48
----------------------------------------------------------------------------
Total market capitalization 821,030 1,102,745
----------------------------------------------------------------------------
Adjusted working capital (surplus) deficit(2) 5,527 (16,876)
Bank debt 438,566 384,623
----------------------------------------------------------------------------
Debt, net of adjusted working capital ("Net Debt") 444,093 367,747
----------------------------------------------------------------------------
Funds from operations(2) 169,957 190,139
----------------------------------------------------------------------------
Net Debt to total funds from operations 2.6 1.9
----------------------------------------------------------------------------
Net Debt as a percentage of total capitalization 54% 33%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the closing price on the Toronto Stock Exchange on December
31.
(2) Refer to the "non-GAAP measurements" disclosure in the MD&A.
/T/
As at December 31, 2010, debt net of adjusted working capital was $444.1 million, resulting in a net debt to the trailing twelve months funds from operations ratio of 2.6:1. At December 31, 2010, NuVista had an adjusted working capital deficit of $5.5 million. Adjusted working capital excludes the current portion of the fair value of the commodity derivative liability of $1.3 million and the current portion of future income tax asset of $0.6 million. We believe it is appropriate to exclude these amounts when assessing financial leverage. At December 31, 2010, NuVista had $71.4 million of unused bank borrowing capacity based on the current credit facility of $510 million.
On April 29, 2010, NuVista completed the annual renewal of its credit facility. NuVista's lenders approved a request for a revolving extendible credit facility totaling $510 million. Borrowing under the credit facility may be made by prime loans, bankers' acceptances and/or US libor advances. These advances bear interest at the bank's prime rate and/or at money market rates plus a stamping fee. The credit facility is secured by a first floating charge debenture, general assignment of book debts and NuVista's oil and natural gas properties and equipment. The credit facility has a 364-day revolving period and is subject to an annual review by the lenders, at which time a lender can extend the revolving period or can request conversion to a one year term loan. During the revolving period, a determination of the maximum borrowing amount occurs semi-annually on or before October 31. NuVista completed the semi-annual review in November 2010 of its borrowing base with its lenders and the lenders approved the continuation of the maximum borrowing amount of $510 million. During the term period, no principal payments would be required until April 28, 2012. As such, this credit facility is classified as long-term. As at December 31, 2010, NuVista had drawn $438.6 million on the facility.
At December 31, 2010, NuVista's bank debt net of adjusted working capital decreased to $444.1 million compared to $447.0 million at September 30, 2010. This decrease is attributable to NuVista adjusting its capital program resulting in capital expenditures being less than funds from operations in the fourth quarter of 2010. NuVista plans to closely monitor its 2011 business plan and adjust its capital program in the context of commodity prices and access to bank and equity capital. NuVista plans to finance its 2011 capital program with funds from operating activities. If NuVista undertakes any major acquisitions, management would expect to finance transactions with a combination of debt and equity.
In February 2011, NuVista entered into private placement agreements and a "bought deal" agreement with a syndicate of underwriters for the issuance of an aggregate of 10,500,000 common shares for aggregate gross proceeds of $99.8 million (the "Offerings"). The proceeds from the Offerings will be initially used to reduce bank indebtedness. The Offerings are expected to close on March 8, 2011.
As at December 31, 2010, there were 88.8 million common shares outstanding. In addition, there were 7.5 million stock options outstanding, with an average exercise price of $12.29 per share. As at February 28, 2011, there were 88.9 million common shares outstanding.
Contractual obligations and commitments - NuVista enters into contract obligations as part of conducting business. The following is a summary of NuVista's contractual obligations and commitments as at December 31, 2010:
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($ thousands) Total 2011 2012 2013 2014 2015 Thereafter
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Transportation $14,851 $4,442 $3,305 $3,080 $2,647 $1,224 $153
Office lease 3,799 2,076 1,723 - - - -
Purchase
commitments 931 931 - - - - -
Physical power
contract 6,900 2,300 2,300 2,300 - - -
Long-term debt 438,566 - 438,566 - - - -
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Total
commitments $465,047 $9,749 $445,894 $5,380 $2,647 $1,224 $153
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/T/
Off balance sheet arrangements - NuVista has no off balance sheet arrangements except for certain lease arrangements. NuVista has certain lease arrangements, all of which are reflected in the contractual obligations and commitments table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet at December 31, 2010.
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, 2010.
Dividends - In the fourth quarter of 2010, our Board of Directors declared a quarterly cash dividend of $0.05 per common share which was paid on January 17, 2011 to shareholders of record on December 31, 2010. On October 15, 2010, NuVista paid the quarterly cash dividend declared in the third quarter of 2010 for shareholders of record on September 30, 2010 and issued 87,433 common shares in payment of $0.8 million of dividends for shareholders that elected to participate in the dividend re-investment plan. Dividends paid to shareholders of common shares have been designated as "eligible dividends" for Canadian tax purposes.
In February 2011, as part of managing NuVista's re-evaluation of its business plan and financial objectives, NuVista's Board of Directors has determined that NuVista will discontinue its dividends to shareholders and use this cash flow to fund its drilling program and growth opportunities.
Relationship with Bonavista Energy Corporation - NuVista and Bonavista Energy Corporation ("Bonavista") are considered related as two directors of NuVista, one of whom is NuVista's chairman, are directors and officers of Bonavista and another director of NuVista is also an officer of Bonavista. For the three months ended December 31, 2010, overhead recoveries of $0.2 million were charged to Bonavista for our jointly owned partnership (2009 - $0.2 million) which are included as a reduction in general and administrative expenses. For the year ended December 31, 2010 overhead recoveries of $0.6 million were charged to Bonavista for our jointly owned partnership (2009 - $1.2 million). As at December 31, 2010, the amount receivable to Bonavista was $0.1 million (2009 - receivable of $0.3 million). These transactions are considered to be in the normal course of business and have been measured at their exchange amounts, being the amounts agreed to by both parties.
In February 2011, Nuvista and Bonavista entered into a series of transactions that resulted in NuVista no longer having joint ownership in a partnership. The results of these transactions have no material impact on NuVista's total production, cash flow or reserves.
Annual financial information - The following table highlights selected annual financial information for the years ended December 31, 2010, 2009 and 2008:
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($ thousands, except per share amounts) 2010 2009 2008
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Production revenue 373,327 345,272 515,338
Net earnings (13,989) 2,476 88,195
Per share - basic (0.16) 0.03 1.18
Per share - diluted (0.16) 0.03 1.18
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Balance sheet information
Total assets 1,597,068 1,555,743 1,407,296
Long-term debt 438,566 384,623 355,407
Shareholders' equity 900,331 919,693 811,300
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/T/
Quarterly financial information - The following table highlights NuVista's performance for the eight quarterly reporting periods from March 31, 2009 to December 31, 2010:
/T/
2010 2009
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($ thousands,
except per share
amounts) Dec 31 Sep 30 Jun 30 Mar 31 Dec 31 Sep 30 Jun 30 Mar 31
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Production
(Boe/d) 28,165 28,244 28,512 28,455 28,345 27,505 25,777 26,175
Production
revenue 89,552 88,733 89,524 105,519 95,957 79,494 78,092 91,729
Net earnings
(loss) (13,417)(5,025)(1,377) 5,830 10,498 (3,342)(7,312) 2,632
Net earnings (loss)
Per share -
basic (0.15) (0.06) (0.02) 0.07 0.12 (0.04) (0.09) 0.03
Per share -
diluted (0.15) (0.06) (0.02) 0.07 0.12 (0.04) (0.09) 0.03
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/T/
NuVista has seen production volumes in a range of 25,577 Boe/d to 28,512 Boe/d for the last eight quarters as incremental production from our exploration and development capital program and acquisitions have more than offset normal production declines. Over the prior eight quarters, quarterly revenue has been in a range of $78.1 million to $105.5 million with revenue primarily influenced by production volumes and commodity prices in the quarter. Net earnings have been in a range of a net loss of $13.4 million to net earnings of $10.5 million with earnings primarily influenced by production volumes, commodity prices and realized and unrealized gains and losses on commodity derivatives.
Critical accounting estimates - The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. Certain accounting policies are critical to understanding the financial condition and results of operations of NuVista.
(a) Proved oil and natural gas reserves - Proved oil and natural gas reserves, as defined by the Canadian Securities Administrators in National Instrument 51-101 with reference to the Canadian Oil and Natural Gas Evaluation Handbook, are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
An independent reserve evaluator using all available geological and reservoir data as well as historical production data has prepared NuVista's oil and natural gas reserve estimates. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in NuVista's development plans. The effect of changes in proved oil and natural gas reserves on the financial results and position of NuVista is described below.
(b) Depreciation, depletion and accretion expense - NuVista uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproved properties, and estimated future development costs is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development costs have a direct impact on depreciation and depletion expense.
Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion calculation, or for impairment, for which any write-down would be charged to depreciation and depletion expense.
(c) Full cost accounting ceiling test - The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the asset is not recoverable by the future undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion and depreciation expense.
(d) Asset retirement obligation - The asset retirement obligations are estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonments and reclamations discounted at a credit adjusted risk free rate. The costs are included in property, plant and equipment and amortized over its useful life. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings and for revisions to the estimated future cash flows. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.
(e) Income taxes - The determination of income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.
(f) Financial Instruments - NuVista utilizes financial instruments to manage the exposure to market risks relating to commodity prices. Fair values of derivative contracts fluctuate depending on the underlying estimate of future commodity prices and foreign currency exchange rates.
(g) Goodwill - Goodwill is recorded on a business combination when the total purchase consideration exceeds the fair value of the net identifiable assets and liabilities of the acquired entity. The goodwill balance is not amortized, however, and must be assessed for impairment at least annually. Impairment is initially determined based on the fair value of a reporting unit compared to its book value. Any impairment must be charged to earnings in the period the impairment occurs. NuVista has one reporting unit, being the entity as a whole, and as at December 31, 2010, we have determined there was no goodwill impairment.
Update on regulatory matters
Environmental - The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of federal, provincial, and local laws and regulation. Environmental legislation provides for, among other things, restrictions and prohibitions on emissions, releases or spills of various substances produced in association with oil and natural gas operations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, as well as larger fines and environmental liability. No assurance can be given that the application of environmental laws to the business and operations of NuVista will not result in a limitation of production or a material increase in the costs of operating, development, or exploration activities or otherwise adversely affect NuVista's financial condition, results of operations, or prospects.
NuVista utilizes monitoring and reporting programs, as well as inspections and audits for environmental, health, and safety performance that are designed to provide assurance that environmental and regulatory standards are met. In the event of unknown or unforeseeable environmental impacts arising from its operations, NuVista may be subject to remedial and litigation costs. Contingency plans are in place for a timely response to environmental events and for the utilization of remediation/reclamation strategies to restore the environment in the event of such impacts.
Given the evolving nature of climate change discussion, the regulation of greenhouse gases (GHGs) and potential federal and provincial GHG commitments, NuVista is currently unable to predict the impact on its operations and financial condition at this time. It is possible that NuVista could face increases in operating and capital costs in order to comply with augmented greenhouse gas emissions legislation.
Further information regarding environmental and climate change regulations, current provincial royalty and incentive programs are contained in our Annual Information Form for the year ended December 31, 2010, to be filed on SEDAR by March 31, 2011, under the Industry Conditions Section.
Update on financial reporting matters
International Financial Reporting Standards ("IFRS") - On January 1, 2011, IFRS will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011, will require the restatement, for comparative purposes, of amounts reported by NuVista for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.
In order to meet the requirement to transition to IFRS, NuVista has appointed internal staff to lead the conversion project along with sponsorship from an executive steering committee. NuVista will continue to involve external auditors and external consultants, as required, during the conversion project. Regular progress reporting to the Audit Committee of the Board of Directors on the status of the IFRS conversion has been implemented. NuVista has held three special Audit Committee update meetings on IFRS in 2010 and a meeting in the first quarter of 2011. NuVista has trained key personnel within the accounting and finance functions as well as the management team. NuVista is on schedule with its conversion project and expects to be completed in time to meet its 2011 financial reporting requirements.
As of December 31, 2010, NuVista has made significant progress on its conversion project. NuVista has analyzed accounting policy alternatives and completed the majority of our IFRS accounting policies. Process and system changes have been implemented for significant areas of impact, while adhering to existing internal control requirements. Information system changes have been tested and implemented to capture the required 2010 comparative data.
NuVista has completed its January 1, 2010, IFRS opening balance sheet. In addition, NuVista is preparing the quarterly comparative IFRS financial information. NuVista's external auditors have reviewed its IFRS accounting policies and are finalizing audit procedures on the IFRS opening balance sheet. NuVista will continue to update its IFRS conversion project to reflect new and amended accounting standards issued by the International Accounting Standards Board ("IASB").
In July 2009, the IASB issued amendments to IFRS 1 - First-Time Adoption of International Financial Reporting Standards ("IFRS 1"). IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. NuVista will use the following exemptions:
- Business Combinations - IFRS 1 will allow NuVista to apply IFRS for business combinations on a prospective basis commencing January 1, 2010 rather than re-stating all past business combinations. The IFRS business combination rules converge with the new CICA Handbook section 1582 effective on January 1, 2011.
- Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option to value PP&E assets in the Exploration and Evaluation ("E&E") and Development and Production ("D&P") phases at their deemed cost, defined as carrying amount assigned to these assets under Canadian GAAP at the date of transition, January 1, 2010. This amendment is permissible for entities, such as NuVista, who currently follow the full cost accounting guideline under Canadian GAAP that accumulates all oil and gas assets into one cost centre. Under IFRS, NuVista's PP&E assets in the D&P phases must be divided into components and cash generating units ("CGUs"). The deemed cost of NuVista's PP&E assets has been allocated to the CGUs based on proved plus probable reserve values. These values will be subject to an impairment test at transition.
- Share Based Payments - IFRS 1 allows NuVista an exemption on IFRS 2 - "Share-Based Payments" to equity instruments which vested before NuVista's transition date to IFRS.
The transition from Canadian GAAP to IFRS is a significant undertaking that will materially affect NuVista's reported financial position and results of operations but NuVista expects the transition will not have a major impact on NuVista's operations, strategic decisions and cash flow. At this time, NuVista has identified key differences that will impact the financial statements as follows:
- Re-classification of E&E expenditures from PP&E - Upon transition to IFRS, NuVista will re-classify all E&E expenditures that are currently included in the PP&E balance on the consolidated balance sheet. This will consist of the book value of undeveloped land that relates to exploration properties and other exploration related activities. E&E assets will not be depleted and must initially be assessed for impairment upon transition, and subsequently when indicators suggest the possibility of impairment. NuVista has currently determined approximately $128 million of PP&E will be classified as E&E in the opening balance sheet prepared under IFRS as at January 1, 2010.
- Impairment of PP&E assets - Under IFRS, impairment calculations will be performed at the CGU level as opposed to one impairment test for the entire PP&E balance required under current Canadian GAAP. NuVista is required to compare carrying amounts directly with the higher of fair value less cost to sell and value in use for impairment testing of PP&E. NuVista has determined its CGUs for the purpose of impairment testing and anticipates using discounted proved plus probable reserves values for impairment tests of PP&E. NuVista does not anticipate its PP&E assets to be impaired as at January 1, 2010 under IFRS. As a result of continued decreases in natural gas prices through 2010 and their impact on the value of NuVista's reserves for certain CGU's, NuVista anticipates certain CGU's within PP&E will be impaired, the amount of which has not yet been determined.
- Impairment of goodwill - Under IFRS, goodwill that arises from a business combination is allocated to the specific CGUs that are expected to benefit from the business combination. To test for impairment of goodwill, the carrying amount of the CGU including goodwill is compared to the fair value of the CGU. As the goodwill impairment test is performed at a more refined level under IFRS, NuVista anticipates recognizing an impairment of approximately $19 million of goodwill on its opening balance sheet with the charge being reflected in opening retained earnings. As a result of continued decreases in natural gas prices through 2010 and their impact on the value of NuVista's reserves for certain CGU's, NuVista anticipates additional goodwill impairment in 2010, the amount of which has not yet been determined.
- Calculation of depletion expense for PP&E assets - Upon transition to IFRS, in addition to calculating depletion at a component level, NuVista has the option to calculate depletion using a reserve base of proved reserves or both proved and probable reserves, as compared to the Canadian GAAP method of calculating depletion using only proved reserves. NuVista plans to determine its depletion expense using proved plus probable reserves as its depletion base. As a result, NuVista's depletion cost will differ from the amount that would have been calculated under Canadian GAAP.
- Interests in joint ventures - Under IFRS, interests in joint ventures must be accounted for by an entity either using the equity method or proportionate consolidation. The IASB is proposing to issue a final standard on Interests in Joint Ventures before the end of 2011. Management will continue to monitor correspondence from the IASB regarding the accounting treatment of joint ventures and the applicability to NuVista.
- Calculation of income taxes - In transitioning to IFRS, NuVista's future tax liability will be impacted by the tax effects resulting from the IFRS changes discussed above.
- Decommissioning provisions for asset retirement obligations - Under IFRS, NuVista is required to revalue its entire asset retirement obligation at each balance sheet date using a current liability specific discount rate. There has been debate within the industry on the discount rate and whether there should be a risk component to it. Based on recent comments made by standard setters and positions within industry, NuVista believes a risk free rate is more appropriate. Under Canadian GAAP obligations are discounted using a risk-free rate adjusted for the entity's own credit risk. Once recorded, asset retirement obligations are not adjusted for future changes in discount rate. As a result, NuVista's asset retirement obligation will increase by approximately $57 million under IFRS.
The following is a summary of NuVista's balance sheet at January 1, 2010 under Canadian GAAP with transitional entries to arrive at the opening balance sheet under IFRS:
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Effect of
($ millions) Canadian Transition to
As at January 1, 2010 GAAP IFRS IFRS
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(unaudited)
Assets
Current assets $ 71 (2) $ 69
Intangible exploration asset - 128 128
Property, plant and equipment 1,401 (128) 1,273
Goodwill 84 (19) 65
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Total assets $ 1,556 (21) $ 1,535
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Liabilities and shareholders' equity
Current liabilities $ 55 - $ 55
Long-term debt 385 - 385
Compensation liability 1 - 1
Asset retirement obligations 62 57 119
Future income taxes 134 (17) 117
Shareholders' equity 919 (61) 858
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Total liabilities and shareholders'
equity $ 1,556 (21) $ 1,535
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/T/
In addition to the accounting policy differences, NuVista's transition to IFRS will impact the internal controls over financial reporting, disclosure controls and procedures, certain of NuVista's business activities and information technology ("IT") systems as follows:
- Internal controls over financial reporting - As the review and analysis of NuVista's accounting policies is completed, an assessment will be made to determine changes required to internal controls over financial reporting. This will be an ongoing process to ensure that changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.
- Disclosure controls and procedures - NuVista has assessed the impact of transition to IFRS on its disclosure controls and procedures and has not identified any material changes required in its control environment. It is expected that there will be increased note disclosure around certain financial statement items than what is currently required under Canadian GAAP. Management will draft its IFRS note disclosure in accordance with current IFRS standards and will continue to monitor requirements put forth by the IASB in discussion papers and exposure drafts for future disclosure requirements. Throughout the transition process, NuVista has been assessing its stakeholders' information requirements and will ensure that adequate and timely information is provided to meet these needs.
- Business activities - NuVista expects that IFRS will not have a major impact on our operations or strategic decisions. Management has been cognizant of the upcoming transition to IFRS and as such has worked with its lenders to ensure any references to Canadian GAAP financial statements in the lending agreement have been modified to allow for IFRS statements. Based on the expected changes to NuVista's accounting policies at this time, there are no foreseen issues with the existing wording of the agreement as a result of the conversion to IFRS. NuVista will continue to work with its other counterparties to ensure that any agreements that contain references to Canadian GAAP financial statements are modified to allow for IFRS statements.
- IT Systems - NuVista has completed most of the system updates required in order to prepare NuVista for IFRS reporting. The modifications while not significant, were deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as the modifications required to track PP&E costs and E&E costs in more detail for IFRS reporting. NuVista continues to assess other system modifications that may be required based on final accounting policy choices, in order to perform ongoing calculations and analysis under IFRS. These changes are not considered to be significant.
Internal control reporting
NuVista's President and Chief Executive Officer ("CEO") and Vice President, Finance and Chief Financial Officer ("CFO") are responsible for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting as defined in National Instrument 52-109. NuVista's CEO and CFO have designed disclosure controls and procedures, or caused them to be designed under their supervision, to provide reasonable assurance that information required to be disclosed by NuVista in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by NuVista in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to NuVista's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure. NuVista's Interim CEO and CFO have evaluated the effectiveness of the disclosure controls and procedures as at December 31, 2010 and have concluded that they are operating effectively.
The CEO and CFO have also designed internal controls over financial reporting, or caused them to be designed under their supervision, to provide reasonable assurance regarding the reliability of NuVista's financial reporting and the preparation of financial statements for external purposes in accordance with NuVista's GAAP and includes those policies and procedures that: (a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of NuVista; (b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with NuVista's GAAP, and that receipts and expenditures of NuVista are being made only in accordance with authorizations of management and directors of NuVista; and (c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of NuVista's assets that could have a material effect on the annual financial statements or interim financial statements. NuVista has designed its internal controls over financial reporting based on the framework in "Internal Control Over Financial Reporting - Guidance for Smaller Public Companies" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). NuVista's Interim CEO and CFO have evaluated NuVista's internal controls over financial reporting as at December 31, 2010 and have concluded they are operating effectively. During the year ended December 31, 2010, there have been no changes to NuVista's internal control over financial reporting that have materially or are reasonably likely to materially affect the internal control over financial reporting.
Because of their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, error or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance, that the objectives of the control system are met.
Assessment of business risks
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;
- 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; and
- Labour risks related to availability, productivity and retention of qualified personnel.
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.
Information regarding risk factors associated with the business of NuVista and how NuVista seeks to mitigate these risks are contained in our Annual Information Form under the Risk Factors Section for the year ended December 31, 2010.
OUTLOOK
NuVista's Board of Directors has approved a 2011 capital budget of between $160 and $180 million. The primary objective of the 2011 capital program is to balance near-term operating and financial results with the continued evaluation of resource play opportunities that have been assembled over the past couple of years. In 2011, the majority of NuVista's capital program will focus on oil and liquids-rich natural gas plays in its Deep Basin and W3/W4M Core Regions. In addition, approximately 20% or $35 million of the 2011 capital budget is expected to be allocated to the advancement of our Wapiti Montney liquids-rich natural gas resource play. While the Wapiti Montney play is at an early stage of evaluation, it has the potential to create significant long term growth and value for our shareholders, even in a low natural gas price environment.
During 2011, we expect to drill approximately 60 gross wells with approximately 20 wells drilled in the first half of 2011 and 40 wells drilled in the second half. Capital spending of $40 million has been allocated to the first quarter of 2011 and $20 million of capital spending has been allocated to the second quarter, however, an extended spring break up may result in the deferral of some activities to the third quarter. For the first six months our capital program primarily targets oil plays in Cardium light oil in our Pembina and Wapiti operating areas and heavy oil in our west central Saskatchewan operating area. During the second half of 2011, capital spending is planned to be focused on further evaluating our Wapiti Montney liquids-rich natural gas play, heavy oil in our W3/W4M Core Region, and light oil and liquids-rich natural gas in our Wapiti and Pembina operating areas.
In 2011, with this level of spending, production is expected to average between 26,000 Boe/d and 27,000 Boe/d. In response to low natural gas prices and lower spending levels in the first half of the year, NuVista's production volumes are expected to decline in the first half of 2011 from fourth quarter 2010 levels due to lower capital spending in the fourth quarter of 2010 and the first quarter of 2011. In addition, approximately 20% of the 2011 capital program will be used to advance the development of the Wapiti Montney play with the expectation that limited production will occur from this spending until late 2011. While average production volumes are expected to decline in 2011 from 2010 levels, NuVista is forecasting its oil and liquids weighting to increase which, based on current commodity prices, should have a positive impact on our netbacks. Based on NuVista's planned capital program, its oil and liquids weighting is expected to increase to approximately 35% of production at the end of 2011 compared our weighting of 27% in the fourth quarter of 2010. NuVista forecasts 2011 funds from operations of between $160 million and $180 million based on the forecasted production rate and current pricing assumptions of $4.00/Mcf for AECO natural gas, US$90/Bbl for WTI crude oil, a foreign exchange rate of 1.00, and including price risk management contracts currently in place.
For 2011, the natural gas supply/demand fundamentals continue to place downward pressure on natural gas prices and, as a result, we plan to carefully manage our business plan and financial flexibility to endure an extended period of weak prices. With a disciplined approach to adding value, and a talented, empowered, and accountable work force of highly motivated employees to achieve our targets, we are confident that our prudent strategy will result in superior performance over the long term and look forward to updating you on our progress and results throughout 2011.
Sincerely,
Robert F. Froese, Interim President and CEO, Vice-President, Finance and CFO
Keith A. MacPhail, Chairman
March 4, 2011
/T/
NUVISTA ENERGY LTD.
Consolidated Balance Sheets
($ thousands)
As at December 31, 2010 2009
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(unaudited)
Assets
Current assets
Cash and cash equivalents $ - $ -
Accounts receivable and prepaids 55,144 69,238
Future income taxes (note 9) 593 1,336
----------------------------------------------------------------------------
55,737 70,574
Oil and natural gas properties and equipment
(note 4) 1,457,615 1,401,453
Goodwill (note 5) 83,716 83,716
----------------------------------------------------------------------------
$ 1,597,068 $ 1,555,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and shareholders' equity
Current liabilities
Accounts payable and accrued liabilities $ 56,233 $ 52,362
Dividends payable (note 8) 4,438 -
Commodity derivative liability (note 11) 1,256 2,593
----------------------------------------------------------------------------
61,927 54,955
Long-term debt (note 7) 438,566 384,623
Compensation liability (note 8) 705 604
Long term commodity derivate liability
(note 11) 4,084 -
Asset retirement obligations (note 6) 62,673 61,816
Future income taxes (note 9) 128,782 134,052
Shareholders' equity
Share capital and contributed surplus (note 8) 716,309 703,959
Retained earnings 184,022 215,734
----------------------------------------------------------------------------
900,331 919,693
----------------------------------------------------------------------------
$ 1,597,068 $ 1,555,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual obligations and commitments (note 13)
Subsequent events (note 14)
See accompanying notes to consolidated financial statements.
NUVISTA ENERGY LTD.
Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss) and
Retained Earnings
Three months ended Years ended
December 31, December 31,
($ thousands except per share
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
(unaudited)
Revenues
Production $ 89,552 $ 95,957 $ 373,327 $ 345,272
Royalties (12,687) (12,153) (57,347) (43,107)
Realized gain (loss) on
commodity derivatives (2,685) (336) (5,239) 9,882
Unrealized gain (loss) on
commodity derivatives (6,076) (3,818) (2,747) (19,106)
----------------------------------------------------------------------------
68,104 79,650 307,994 292,941
----------------------------------------------------------------------------
Expenses
Operating 26,154 22,435 94,237 83,583
Transportation 1,848 2,087 8,588 8,307
General and administrative 5,047 3,784 19,173 14,280
Bad debt provision (recovery) - (182) - (182)
Interest 5,293 4,202 17,713 14,061
Stock-based compensation
(note 8) 2,096 2,070 7,629 7,955
Depreciation, depletion and
accretion 47,617 43,463 179,739 172,178
----------------------------------------------------------------------------
88,055 77,859 327,079 300,182
----------------------------------------------------------------------------
Earnings (loss) before income
and other taxes (19,951) 1,791 (19,085) (7,241)
Future income tax expense
(recovery) (note 9) (6,534) (8,707) (5,096) (9,717)
----------------------------------------------------------------------------
Net earnings (loss) and
comprehensive income (loss) (13,417) 10,498 (13,989) 2,476
Retained earnings, beginning
of period 201,877 205,236 215,734 213,258
Dividends (note 8) (4,438) - (17,723) -
----------------------------------------------------------------------------
Retained earnings, end
of period $ 184,022 $ 215,734 $ 184,022 $ 215,734
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings (loss) per share -
basic $ (0.15) $ 0.12 $ (0.16) $ 0.03
----------------------------------------------------------------------------
Net earnings (loss) per share -
diluted $ (0.15) $ 0.12 $ (0.16) $ 0.03
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
NUVISTA ENERGY LTD.
Consolidated Statement of Cash Flows
Three months ended Years ended
December 31, December 31,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in)
Operating Activities
Net earnings (loss) $ (13,417) $ 10,498 $ (13,989) $ 2,476
Items not requiring cash from
operations
Depreciation, depletion and
accretion 47,617 43,463 179,739 172,178
Bad debt provision (recovery) - (182) - (182)
Stock-based compensation 1,879 1,609 6,556 6,278
Unrealized (gain) loss on
commodity derivatives 6,076 3,818 2,747 19,106
Future income tax expense
(recovery) (6,534) (8,707) (5,096) (9,717)
Asset retirement expenditures (663) (772) (7,740) (2,615)
Change in non-cash working
capital items 7,759 11,140 5,238 4,135
----------------------------------------------------------------------------
42,717 60,867 167,455 191,659
----------------------------------------------------------------------------
Financing Activities
Issue of share capital, net of
share issuance costs 240 165 2,178 96,237
Increase (decrease) in
long-term debt (3,554) (25,908) 53,943 29,215
Cash dividends (3,577) - (11,667) -
----------------------------------------------------------------------------
(6,891) (25,743) 44,454 125,452
----------------------------------------------------------------------------
Investing Activities
Oil and natural gas
properties and equipment (33,569) (31,996) (206,693) (83,604)
Property (acquisition)
disposition (note 3) 5,034 1,140 (18,357) (226,306)
Change in non-cash working
capital items (7,291) (4,268) 13,141 (7,340)
----------------------------------------------------------------------------
(35,826) (35,124) (211,909) (317,250)
----------------------------------------------------------------------------
Change in cash and cash
equivalents - - - (139)
Cash and cash equivalents,
beginning of period - - - 139
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
/T/
NUVISTA ENERGY LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Years ended December 31, 2010 and 2009.
NuVista Energy Ltd. ("NuVista" or the "Company") is a publicly traded company incorporated under the laws of Alberta. The Company is engaged in the exploration of, and the acquisition, development and production of oil and natural gas reserves and assets related thereto in the Provinces of Alberta, British Columbia and Saskatchewan.
1. Significant accounting policies
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 Energy Corporation.
(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.
(h) Stock-based compensation
NuVista has equity incentive plans, which are described in note 8, 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. Accounting changes
(a) International Financial Reporting Standards
On January 1, 2011 International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB") will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011 will require the restatement of the Company's consolidated financial statements, for comparative purposes, for its year ended December 31, 2010, and of the opening balance sheet as at January 1, 2010.
(b) Business Combinations
In January 2009, the CICA issued Section 1582, "Business Combinations". This section is effective January 1, 2011 and applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after January 1, 2011. Early adoption is permitted. This section replaces Section 1581, "Business Combinations". The IFRS business combination rules converge with the new CICA Handbook section 1582 effective on January 1, 2011.
(c) Consolidated Financial Statements and Non-Controlling Interests
In January 2009, the AcSB issued Section 1601, "Consolidated Financial Statements", and Section 1602, "Non-Controlling Interests", which together replace Section 1600, "Consolidated Financial Statements", and harmonize the Canadian standards with IFRS. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These sections are effective for the first reporting period beginning on or after January 1, 2011. Early adoption is permitted.
3. Acquisitions
(a) Ferrier, Sunchild, Wapiti and Northwest Saskatchewan Properties
On January 29, 2009, the Company acquired certain natural gas properties and related facilities in the Ferrier/Sunchild, Wapiti and northwest Saskatchewan operating areas. The cash purchase price was $55.6 million, net of final adjustments. The results of operations of these properties have been included in the consolidated financial statements of the Company since the acquisition date.
(b) Northeast British Columbia and Northwest Alberta Properties
On July 27, 2009, the Company acquired certain natural gas properties and related facilities in the Martin Creek area of northeast British Columbia and northwest Alberta for a cash purchase price of $172.3 million, net of final adjustments. The results of operations of these properties have been included in the consolidated financial statements of the Company since the acquisition date.
/T/
4. Oil and natural gas properties and equipment
2010
-------------------------------------------
Accumulated Net
depreciation book
Cost and depletion value
----------------------------------------------------------------------------
Oil and gas properties $1,968,551 $827,376 $1,141,175
Facilities and office equipment 387,968 71,528 316,440
----------------------------------------------------------------------------
$2,356,519 $898,904 $1,457,615
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009
-------------------------------------------
Accumulated Net
depreciation 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Unproved property costs of $128.9 million were excluded from the depreciation and depletion calculation for the year ended December 31, 2010 (2009 - $128.2 million). Future development costs of $228.7 million (2009 - $93.3 million) were included in the depreciation and depletion calculation. For 2010, NuVista capitalized $4.6 million (2009 - $4.0 million) in general and administrative expenses, $2.0 million (2009 - $2.3 million) in stock compensation expense and $0.2 million (2009 - $0.5 million) in Restricted Stock Units ("RSU") expense related to exploration and development activities.
NuVista has performed the ceiling test as of December 31, 2010, and no impairment was required. The test was calculated using benchmark reference prices at January 1 for the years 2011 to 2016 and thereafter, adjusted for commodity differentials specific to NuVista, as determined by the Company's independent oil and natural gas reserves engineers.
/T/
Benchmark Reference Price Forecasts:
2011 2012 2013 2014 2015 2016 Thereafter
----------------------------------------------------------------------------
WTI (US$/Bbl) 88.00 89.00 90.00 92.00 95.17 97.55 +2%/yr
AECO (Cdn$/MMbtu) 4.16 4.74 5.31 5.77 6.22 6.53 +2%/yr
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
5. Goodwill
The Company completed its annual goodwill impairment test at December 31, 2010 and 2009 and has determined that there is no goodwill impairment as of December 31, 2010 and 2009.
6. 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, 2010, the estimated total undiscounted amount of cash flows required to settle the Company's asset retirement obligations is $235.9 million (2009 - $261.5 million), which will be incurred over the next 51 years. The majority of the costs will be incurred between 2011 and 2030. A credit-adjusted risk-free rate of 8% (2009 - 8%) and an inflation rate of 2% (2009 - 2%) were used to calculate the fair value of the asset retirement obligations. The change in assumptions are primarily due to changes in the timing of abandonment expenditures.
/T/
A reconciliation of the asset retirement obligations is provided below:
2010 2009
----------------------------------------------------------------------------
Balance, beginning of year $61,816 $46,296
Accretion expense 4,645 4,100
Liabilities incurred 3,493 4,050
Liabilities acquired 378 9,985
Revisions 81 -
Liabilities settled (7,740) (2,615)
----------------------------------------------------------------------------
Balance, end of year $62,673 $61,816
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
7. Long-term debt
In April 2010, the Company completed the annual renewal of its credit facility. The Company's lenders approved a request for a revolving extendible credit facility totaling $510 million. Borrowing under the credit facility may be made by prime loans, bankers' acceptances and/or US libor advances. These advances bear interest at the bank's prime rate and/or at money market rates plus a stamping fee. The credit facility is secured by a first floating charge debenture, general assignment of book debts and the Company's oil and natural gas properties and equipment. The credit facility has a 364-day revolving period and is subject to an annual review by the lenders, at which time a lender can extend the revolving period or can request conversion to a one year term loan. During the revolving period, a determination of the maximum borrowing amount occurs semi-annually on or before October 31. NuVista completed the semi-annual review in November 2010 of its borrowing base with its lenders and the lenders have approved the continuation of the maximum borrowing amount of $510 million. During the term period, no principal payments would be required until April 28, 2012. As such, this credit facility is classified as long-term. As at December 31, 2010, the Company had drawn $438.6 million (December 31, 2009 - $384.6 million) on the facility. Cash paid for interest expense for the three months ended December 31, 2010 was $5.2 million (2009 - $4.3 million) and for the year ended December 31, 2010 was $17.9 million (2009 - $13.8 million).
/T/
8. Shareholders' equity
(a) Share capital and contributed surplus
2010 2009
----------------------------------------------------------------------------
Share capital $689,757 $685,269
Contributed surplus 26,552 18,690
----------------------------------------------------------------------------
Total $716,309 $703,959
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(b) Authorized
Unlimited number of voting Common Shares and 1,200,000 Class B Performance
Shares.
(c) Common shares issued
2010 2009
------------------------------------------
Number Amount Number Amount
----------------------------------------------------------------------------
Balance, beginning of year 88,360,757 $685,269 79,164,582 $587,460
Issued for cash - - 9,000,000 99,016
Dividend Re-investment Plan
("DRIP") 158,121 1,618 - -
Exercise of stock options 240,924 2,233 196,175 1,430
Stock-based compensation - 678 - 432
Cost associated with shares
issued, net of future tax
benefit of $0.1 million
(2009 - $1.1 million) - (41) - (3,069)
----------------------------------------------------------------------------
Balance, end of year 88,759,802 $689,757 88,360,757 $685,269
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
During the year ended December 31, 2010, the Company issued 158,121 common shares in payment of $1.6 million of dividends for shareholders that elected to participate in the DRIP.
On June 15, 2009, the Company entered into an agreement to issue 7,500,000 subscription receipts at a price of $11.00 per subscription receipt on a bought deal basis for gross proceeds of $82.5 million. In addition, the Company issued 1,500,000 subscription receipts at a price of $11.00 per subscription receipt, by way of a private placement to Ontario Teachers' Pension Plan Board for gross proceeds of $16.5 million. The subscription receipt offerings closed on July 7, 2009. Each subscription receipt was exchanged for one common share of NuVista for no additional consideration on July 27, 2009.
(d) Dividends
In 2010, NuVista's Board of Directors declared cash dividends of $0.20 per common share to shareholders. In the fourth quarter of 2010, our Board of Directors declared a quarterly cash dividend of $0.05 per common share which was paid on January 17, 2011 to shareholders of record on December 31, 2010.
In February 2011, as part of managing NuVista's re-evaluation of its business plan and financial objectives, NuVista's Board of Directors has determined that NuVista will discontinue its dividends to shareholders.
/T/
(e) Contributed surplus
2010 2009
----------------------------------------------------------------------------
Balance, beginning of year $ 18,690 $ 7,128
Stock-based compensation 8,540 8,540
Exercise of stock options (678) (432)
Expired warrants - 3,454
----------------------------------------------------------------------------
Balance, end of year $ 26,552 $ 18,690
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
(f) Per share amounts
During the year ended December 31 2010, there were 88,582,672 (2009 - 83,152,386) weighted average shares outstanding. On a diluted basis, there were 88,582,672 (2009 - 83,571,055) weighted average shares outstanding after giving effect for dilutive stock options. The number of anti-dilutive options totaled 6,590,485 at December 31, 2010 (2009 - 4,681,719).
(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:
/T/
2010 2009
-----------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
----------------------------------------------------------------------------
Balance, beginning of year 6,574,823 $ 13.16 6,111,945 $ 13.69
Granted 2,449,840 10.46 1,600,953 11.01
Exercised (240,924) 9.27 (196,175) 7.29
Forfeited (705,391) 13.36 (566,950) 14.17
Expired (563,250) 14.42 (374,950) 14.29
----------------------------------------------------------------------------
Balance, end of year 7,515,098 $ 12.29 6,574,823 $ 13.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
The following table summarizes stock options outstanding and exercisable under the plan at December 31, 2010:
/T/
Options Outstanding Options Exercisable
----------------------------------------------------------------------------
Weighted
Average Weighted Weighted
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Price At Year-End Life Price at Year-End Price
----------------------------------------------------------------------------
$5.50 to $9.99 1,330,467 3.5 $ 8.42 373,158 $ 7.86
$10.00 to $14.99 4,561,981 2.8 11.99 1,596,328 13.00
$15.00 to $19.56 1,622,650 1.7 16.29 864,403 16.32
----------------------------------------------------------------------------
$5.50 to $19.56 7,515,098 2.7 $12.29 2,833,889 $13.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
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, 2010 was estimated on the date of grant using the Black-Scholes option pricing model. In the pricing model, the average risk-free interest rate used was 2.3% (2009 - 2%); volatility of 40% (2009 - 40% to 52%); an average expected life of 4.4 years (2009 - 4.5 years); an estimated forfeiture rate of 10% (2009 - 10%); and dividends of $0.20 per share (2009 - nil). The weighted average fair value of stock options granted during the year ended December 31, 2010 was $3.24 per option (2009 - $4.00 per option). For the year ended December 31, 2010, the Company capitalized $2.0 million (2009 - $2.3 million) in stock based compensation.
(h) Restricted stock units
In January 2008, the Board of Directors approved a RSU Incentive Plan for employees and officers. Each RSU entitles participants to receive cash equal to the market value of the equivalent number of shares of the Company. Until November 2009, the RSUs became payable as they vested over three years. In November 2009, the Board of Directors amended the Plan. All RSUs granted subsequent to November 2009 vest two years after the date the RSUs are issued.
For the year ended December 31, 2010, the Company recorded compensation expense related to RSU's of $1.1 million (2009 - $1.7 million) and capitalized $0.2 million (2009 - $0.5 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.
/T/
The following table summarizes the change in outstanding RSUs:
2010 2009
Number Number
----------------------------------------------------------------------------
Balance, beginning of year 414,791 351,543
Settled (210,704) (122,314)
Granted 270,505 204,154
Forfeited (21,661) (18,592)
----------------------------------------------------------------------------
Balance, end of year 452,931 414,791
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes the change in compensation liability relating
to the RSUs:
2010 2009
----------------------------------------------------------------------------
Balance, beginning of year $ 2,744 $ 1,461
Change in accrued compensation liability (1,076) 1,283
----------------------------------------------------------------------------
Balance, end of year $ 1,668 $ 2,744
----------------------------------------------------------------------------
Compensation liability - current (included in
accounts payable) $ 963 $ 2,140
----------------------------------------------------------------------------
Compensation liability - long-term $ 705 $ 604
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
For the year ended December 31, 2010, cash payments of $2.3 million (2009 - $0.9 million) were made relating to the RSU Incentive Plan.
9. 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:
/T/
2010 2009
----------------------------------------------------------------------------
Statutory tax rate 28.3% 29.2%
----------------------------------------------------------------------------
Expected tax expense (recovery) $ (5,401) $ (2,117)
Effect of change in tax rate (2,101) (6,390)
Stock-based compensation 1,855 1,835
Change in estimated pool balances 551 (3,045)
----------------------------------------------------------------------------
Future income tax expense (recovery) $ (5,096) $ (9,717)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The significant components of net future income tax liability are as
follows:
2010 2009
----------------------------------------------------------------------------
Future income tax liabilities
Oil and natural gas properties $ 106,545 $ 116,470
Facilities and well equipment 40,175 35,587
Future income tax assets
Asset retirement obligations (15,925) (16,010)
Share issue costs (775) (1,817)
Commodity derivative contracts (1,357) (732)
Other (474) (782)
----------------------------------------------------------------------------
Net future income tax liability $ 128,189 $ 132,716
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Future income tax liability (asset) - current $ (593) $ (1,336)
----------------------------------------------------------------------------
Future income tax liability - long-term $ 128,782 $ 134,052
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the year ended December 31, 2010, cash taxes paid was $nil (2009 -
$nil).
/T/
10. 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 annual funds from operations. As the ratio of net debt to annual 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 year. The Company's overall strategy is to maintain a net debt to annual funds from operations ratio of less than 2.0:1. At December 31, 2010, the Company had a ratio of net debt to funds from operations of 2.6:1 (2009 - 1.9:1). The actual ratio may fluctuate on a quarterly basis above or below our target due to a number of factors including timing of acquisitions and disposition and commodity prices.
In February 2011, the Company entered into private placement agreements and a "bought deal" agreement with a syndicate of underwriters for the issuance of an aggregate of 10,500,000 common shares for aggregate gross proceeds of $99.8 million (the "Offerings"). The proceeds from the Offerings will initially be used to reduce bank indebtedness. The Offerings are expected to close on March 8, 2011.
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, 2010, the Company was in compliance with all covenants. There were no changes to the Company's approach to capital management during the year.
11. Risk management activities
(a) Financial instruments
The Company's financial instruments recognized on the consolidated balance sheet consists of cash and cash equivalents, accounts receivable, commodity derivative contracts, dividend payable, accounts payable and accrued liabilities, compensation liability 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.
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, 2010, the Company has the following crude oil put option contracts in place:
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Average Strike Option
Price Premium
Volume (Cdn$/Bbl) (Cdn$/Bbl) Term
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4,000 Bbls/d $87.52 - WTI $8.93 January 1, 2011 - March 31, 2011
3,000 Bbls/d $88.03 - WTI $9.29 April 1, 2011 - December 31, 2011
2,000 Bbls/d $88.55 - WTI $9.43 January 1, 2012 - March 31, 2012
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As at December 31, 2010, the Company has the following NYMEX natural gas basis differential contracts in place:
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Differential
Volume (US$/MMbtu) Term
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25,000 MMbtu/d ($0.34) January 1, 2011 - March 31, 2011
40,000 MMbtu/d ($0.46) April 1, 2011 - October 31, 2011
30,000 MMbtu/d ($0.51) November 1, 2011 - March 31, 2012
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As at December 31, 2010, the mark-to-market value of the above derivative commodity contracts was a liability of $5.3 million (December 31, 2009 - liability of $2.6 million).
As at December 31, 2010, the Company has the following non-financial fixed price contract for the purchase of electricity in place:
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Volume Price (Cdn$/Mwh) Term
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4.0 Mwh $65.64 January 1, 2011 - December 31, 2013
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Subsequent to December 31, 2010, the following financial derivative crude oil fixed price contract has been entered into:
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Volume Strike Price (Cdn$/Bbl) Term
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1,000 Bbls/d $97.50 - WTI April 1, 2011 - June 30, 2012
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(b) 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, 2010, the accounts receivable balance was $42.3 million of which $1.0 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, 2010, the Company had an allowance for doubtful accounts of $0.4 million (2009 - $0.4 million).
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, 2010.
(c) 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, 2010, is as follows:
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Total 2011 2012 2013 2014 Thereafter
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Accounts payable and
accrued liabilities $ 56,233 $56,233 $ - $ - $ - $ -
Dividends payable 4,438 4,438 - - - -
Long-term debt 438,566 - 438,566 - - -
Compensation liability 705 - 705 - - -
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Total financial
liabilities $499,942 $60,671 $439,271 $ - $ - $ -
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(d) 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 derivatives to manage crude oil and natural gas commodity price risk as well as physical delivery natural gas sale contracts.
(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, 2010.
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, 2010, 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.
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Impact on net earnings
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Commodity price risk
Increase in Cdn$ WTI oil - $10/Bbl $ (2,400)
Decrease in Cdn$ WTI oil - $10/Bbl $ 5,900
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Interest rate risk
Increase in interest rate - 1% $ (3,700)
Decrease in interest rate - 1% $ 3,700
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12. Relationship with Bonavista Energy Corporation
NuVista and Bonavista Energy Corporation ("Bonavista") are considered related as two directors of NuVista, one of whom is NuVista's chairman, are directors and officers of Bonavista and another director of NuVista is also an officer of Bonavista. For the year ended December 31, 2010, overhead recoveries of $0.6 million were charged to Bonavista for our jointly owned partnership (2009 - $1.2 million). As at December 31, 2010, the amount receivable to Bonavista was $0.1 million (2009 - receivable of $0.3 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.
In February 2011, the Company and Bonavista entered into a series of transactions that resulted in NuVista no longer having joint ownership in a partnership. The results of these transactions have no material impact on the Company's total production, cash flow or reserves.
13. Contractual obligations and commitments
The following is a summary of the Company's contractual obligations and commitments as at December 31, 2010:
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Total 2011 2012 2013 2014 2015 Thereafter
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Transportation $ 14,851 $4,442 $ 3,305 $3,080 $2,647 $1,224 $153
Office lease 3,799 2,076 1,723 - - - -
Purchase commitments 931 931 - - - - -
Physical power
contract 6,900 2,300 2,300 2,300 - - -
Long-term debt 438,566 - 438,566 - - - -
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Total commitments $465,047 $9,749 $445,894 $5,380 $2,647 $1,224 $153
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14. Subsequent Events
(a) Partnership Rationalization
In February 2011, NuVista and Bonavista entered into a series of transactions that resulted in NuVista no longer having joint ownership in a partnership. The results of these transactions have no material impact on the Company's total production, cash flow or reserves.
(b) Equity issuance
In February 2011, the Company entered into private placement agreements and a "bought deal" agreement with a syndicate of underwriters for the issuance of an aggregate of 10,500,000 common shares for aggregate gross proceeds of $99.8 million (the "Offerings"). The Offerings are expected to close on March 8, 2011.
(c) Termination of dividend
In February 2011, as part of managing the Company's re-evaluation of its business plan and financial objectives, NuVista's Board of Directors decided to discontinue its dividends to shareholders.
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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
Clayton H. Woitas, Range Royalty Management Ltd.
Grant A. Zawalsky, Burnet, Duckworth & Palmer LLP
Officers
Keith A. MacPhail, Chairman
Robert F. Froese, Interim President and CEO, Vice President, Finance and CFO
and Corporate Secretary
Ross L. Andreachuk, Vice President and Controller
Kevin G. Asman, Vice President, Marketing
Kevin J. Christie, Vice President, Exploration
Steven J. Dalman, Vice President, Business Development
D. Chris McDavid, Vice President, Operations
Daniel B. McKinnon, Vice President, Engineering
Joshua T. Truba, Vice President, Land
Wayne M. Olmstead, Vice President, Human Resources and Office Administration
Auditors Legal Counsel
KPMG LLP Burnet, Duckworth & Palmer LLP
Chartered Accountants Calgary, Alberta
Calgary, Alberta
Bankers Registrar and Transfer Agent
Canadian Imperial Bank of Commerce Valiant Trust Company
Bank of Montreal Calgary, Alberta
Royal Bank of Canada
Toronto Dominion Bank
Bank of Nova Scotia
Alberta Treasury Branches
Union Bank, Canada Branch
Engineering Consultants Stock Exchange Listing
GLJ Petroleum Consultants Ltd. Toronto Stock Exchange
Calgary, Alberta Trading Symbol "NVA"
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