NuVista Energy Ltd. (TSX:NVA) is pleased to announce its financial and operating
results for the three and six months ended June 30, 2009, as follows:
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Corporate Highlights
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Three months Six months
ended June 30, % ended June 30, %
2009 2008 Change 2009 2008 Change
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Financial
($ thousands, except
per share)
Production revenue 78,092 161,712 (52) 169,821 258,760 (34)
Funds from operations
(1) 41,779 89,582 (53) 98,442 143,016 (31)
Per share - basic 0.53 1.14 (54) 1.24 2.05 (40)
Per share - diluted 0.53 1.11 (52) 1.24 2.02 (39)
Net earnings (loss) (7,312) 2,905 (352) (4,680) 10,054 (147)
Per share - basic (0.09) 0.04 (325) (0.06) 0.14 (143)
Per share - diluted (0.09) 0.04 (325) (0.06) 0.14 (143)
Total assets 1,429,854 1,356,172 5
Long-term debt, net
of working capital 350,580 365,282 (4)
Long-term debt, net
of adjusted working
capital (1) 351,451 338,900 4
Shareholders' equity 812,128 728,591 11
Total capital
expenditures 8,318 16,213 (49) 89,546 67,114 33
Corporate acquisition
(non-cash) - - - - 594,944 -
Weighted average common
shares outstanding
(thousands):
Basic 79,209 78,830 - 79,187 69,754 14
Diluted 79,209 80,368 (1) 79,187 70,753 12
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Operating
(boe conversion -
6:1 basis)
Production
Natural gas (mmcf/d) 109.6 113.0 (3) 110.9 99.2 12
Natural gas liquids
(bbls/d) 3,247 2,609 24 3,138 1,857 69
Oil (bbls/d) 4,269 4,714 (9) 4,358 4,349 -
Total oil equivalent
(boe/d) 25,777 26,153 (1) 25,974 22,746 14
Product prices (2)
Natural gas ($/mcf) 4.52 9.44 (52) 5.53 8.74 (37)
Natural gas liquids
($/bbl) 32.00 81.88 (61) 35.46 80.65 (56)
Oil ($/bbl) 64.14 91.82 (30) 59.66 84.95 (30)
Operating expenses
Natural gas and
natural gas liquids
($/mcfe) 1.05 1.16 (9) 1.11 1.15 (3)
Oil ($/bbl) 15.69 13.76 14 16.31 12.34 32
Total oil equivalent
($/boe) 7.84 8.19 (4) 8.27 7.95 4
General and
administrative
expenses ($/boe) 1.61 1.52 6 1.43 1.40 2
Funds from operations
netback ($/boe) (1) 17.81 37.64 (53) 20.95 34.56 (39)
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NOTES:
(1) Funds from operations, funds from operations per share, funds from
operations netback and adjusted working capital are not defined by GAAP
in Canada and are referred to as non-GAAP measures. Funds from
operations are based on cash flow from operating activities as per the
statement of cash flows before changes in non-cash working capital and
asset retirement expenditures. Funds from operations per share is
calculated based on the weighted average number of common shares
outstanding consistent with the calculation of net earnings (loss) per
share. Funds from operations netback equals the total of revenues
including realized commodity derivative gains/losses less royalties,
transportation, general and administrative, restricted stock units,
interest expenses and cash taxes calculated on a boe basis. Adjusted
working capital excludes the current portions of the commodity
derivative asset or liability and the future income tax asset or
liability. Total boe is calculated by multiplying the daily production
by the number of days in the period. For more details on non-GAAP
measures, refer to "Management's Discussion and Analysis" section of
this press release.
(2) Product prices include realized gains/losses on commodity derivatives.
MESSAGE TO SHAREHOLDERS
NuVista Energy Ltd. ("NuVista") is pleased to report to its shareholders the
financial and operating results for the three and six months ended June 30,
2009. During the second quarter of 2009, natural gas prices declined
significantly as continued weakness in the North American economy reduced demand
for natural gas and supply from United States production remained relatively
strong. We responded to lower natural gas prices by taking a disciplined
approach to our capital program, focusing on financial flexibility and
completing a strategic property acquisition. We believe that we have positioned
NuVista to create significant shareholder value when natural gas prices recover
by taking this time to build our drilling inventory and make strategic and
timely acquisitions.
During the second quarter of 2009, we achieved average production of 25,777
boe/d, approximately 600 boe/d less than expected due to unscheduled third party
plant outages but only slightly lower than production of 26,175 boe/d in the
first quarter of 2009. Lower natural gas prices had an impact on second quarter
funds from operations; however, this decline was partially mitigated by $9.2
million of gains realized from our financial and physical sale price risk
management program. During the second quarter, exploration and development
capital expenditures were $10.7 million as we focused on debt reduction
following the $54 million property acquisition in January 2009 and responded to
lower natural gas prices.
Significant highlights for NuVista in the second quarter:
- Implemented an $8.3 million exploration and development capital program that
was primarily directed toward our Oyen core area in order to maximize the
benefit of Alberta royalty drilling credits. In addition, our drilling program
benefited from lower drilling and completion costs resulting from reduced
industry activity levels. During the second quarter, we participated in 13 (11.8
net) wells with a 77% success factor;
- Entered into an agreement to purchase strategic properties located in the
Martin Creek area of British Columbia and in Northwest Alberta for cash
consideration of approximately $174 million. This acquisition closed on July 27,
2009;
- Entered into agreements to issue 9.0 million subscription receipts for gross
proceeds of $99 million in order to fund a significant portion of the
acquisition with equity. The subscription receipt offerings closed on July 7,
2009 and on July 27, 2009 the subscription receipts were exchanged into common
shares and the proceeds of the offerings were released from escrow; and
- Maintained financial flexibility by reducing net debt to approximately $334
million (after adjusting for the $18 million deposit relating to the recent
property acquisition) from a peak net debt level of approximately $390 million
following the property acquisition in January 2009.
Looking forward to the remainder of 2009, we will be focused on prudently
managing NuVista's business plan during a period of low natural gas prices,
integrating the recent property acquisition and continuing with our core capital
program focused on evaluating plays with potential for significant development
in 2010 and beyond.
Prudently Manage our Business Plan
We will continue to prudently manage NuVista's business during this period of
low natural gas prices. We will continue to invest capital on strategic projects
and pursue acquisition opportunities available in this environment, while
maintaining our financial flexibility. We believe natural gas prices will
increase as supply and demand fundamentals adjust but the timing of this
increase is uncertain. During the first half of 2009, we managed our capital
program in a disciplined manner spending less than cash flow on our drilling
program and achieving our debt reduction targets. Our recent property
acquisition was financed with a significant amount of equity in order to
maintain our financial flexibility and during the second half of 2009, we will
spend less than cash flow on our drilling program in order to further reduce
debt levels following this latest acquisition. Our drilling program for the
remainder of the year will be focused on evaluating resource gas plays with
potential for follow-up drilling, lease expiries and competitive drainage
situations. In response to low natural gas prices, NuVista plans to shut-in
approximately 400 boe/d of high operating costs natural gas production in August
and will consider shutting-in additional natural gas production if prices
decline further. In addition, TCPL has notified us of pipeline constraints in
our Northwest Alberta core area that are anticipated to continue until the first
quarter of 2010 that will result in shut-in production of approximately 500
boe/d.
Integrate our Recent Property Acquisition
With the closing of the recent property acquisition on July 27, 2009, we will
integrate these new properties into our business with a focus on optimizing
production, reducing operating costs, building an inventory of drilling
locations and evaluating small complementary acquisition opportunities. This
acquisition was strategic and creates a new core area characterized by longer
life reserves which lowers our overall corporate production decline rate and
adds over 140,000 net undeveloped acres. These properties were acquired at
attractive valuation metrics and are accretive to NuVista's production and
reserves per share. These properties also will provide opportunities for
continued growth over the long-term and they have significant leverage to rising
natural gas prices. We have identified over 30 drilling opportunities on the
acquired lands. These drilling opportunities are expected to be economically
robust and generate favourable rates of return even in a low natural gas price
environment and we are planning a nine well winter drilling program.
Evaluate Plays for Development in 2010
During the second half of 2009, our capital program will be focused on drilling
the remaining nine wells in our Oyen core area drilling program and implementing
horizontal drilling and multi-stage facing technology on several tight gas
projects. With the extension of the Alberta royalty drilling credit into 2011,
we have reallocated our capital program with less emphasis on the Oyen core area
for the remainder of the year and prioritized plays with larger resource
potential. During the second half of 2009, a horizontal Montney well will be
drilled in our Fir/Kaybob core area where we have 10 vertical Montney producing
wells on seven and one-half sections of land. This project may ultimately result
in 5 to 10 additional horizontal Montney wells, beginning in 2010. In our Wapiti
core area, we plan to investigate the thicker tight gas charged lower Dunvegan
sands by drilling one horizontal well and we will follow up on the success of
vertical wells in the upper Dunvegan zones by drilling two additional vertical
wells. Also in our Wapiti core area, we plan to complete one additional vertical
well in the Montney formation and monitor production from another vertical well
brought on during the second quarter, and monitor drilling and completion
results for horizontal Montney wells drilled by other companies in the greater
Wapiti area. Both the Dunvegan and Montney plays, if successful, possess the
size and scope to dramatically impact NuVista's capital program and financial
results over the next five years.
Through challenging and at times difficult industry conditions, we continue to
maintain a disciplined approach to our business. We will continue to employ an
"acquire and develop" business model focused on reserves per share and
production per share growth while maintaining our balance sheet strength. Due to
low commodity prices and an uncertain economic environment, prudent financial
management requires a responsive and flexible capital program in 2009 while
continuing to plan for our future. For the remainder of 2009, we will continue
to closely manage capital spending levels and focus on maintaining financial
flexibility. We pride ourselves on being able to make business decisions based
on timely and accurate data and this approach will continue to enable us to
adapt to rapidly changing economic and market conditions.
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 three and six months ended June 30,
2009 and the audited consolidated financial statements for the year ended
December 31, 2008. The following MD&A of financial condition and results of
operations was prepared at and is dated August 13, 2009. Our audited
consolidated financial statements, Annual Report, Annual Information Form and
other disclosure documents for 2008 are available through our filings on SEDAR
at www.sedar.com or can be obtained from our website at www.nuvistaenergy.com.
Basis of presentation - The financial data presented below has been prepared in
accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The
reporting and the measurement currency is the Canadian dollar. For the purpose
of calculating unit costs, natural gas is converted to a barrel of oil
equivalent ("boe") using six thousand cubic feet of natural gas equal to one
barrel of oil, unless otherwise stated. In certain circumstances natural gas
liquid volumes have been converted to thousand cubic feet equivalent ("mcfe") on
the basis of one barrel of natural gas liquids to six thousand cubic feet. Boe's
and mcfe's may be misleading, particularly if used in isolation. A conversion
ratio of one barrel to six thousand cubic feet of natural gas is based on an
energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead.
Forward-looking statements - Certain information set forth in this document
contain forward-looking statements, including management's assessment of
NuVista's future plans and operations, forecast production and growth and
production and reserves, drilling plans and results, NuVista's planned capital
budget, targeted debt level, the timing, allocation and efficiency of NuVista's
capital program and the results therefrom, forecast funds from operations and
targeted operating costs, benefits from the Alberta Government's announcement of
royalty incentives, expectations regarding the payment of future taxes,
expectations regarding future commodity prices, netbacks and industry conditions
which are provided to allow investors to better understand our business. By
their nature, forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond NuVista's control, including the impact
of general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability of
qualified personnel or management and services, stock market volatility, changes
in environmental regulations, tax laws and royalties and the ability to access
sufficient capital from internal sources and bank and equity markets. Readers
are cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. NuVista's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements, or if any of them do so, what benefits that NuVista will derive
therefrom. NuVista disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise, except as required by law.
Non-GAAP measurements - Within MD&A, references are made to terms commonly used
in the oil and natural gas industry. Management uses funds from operations to
analyze operating performance and leverage. Funds from operations as presented,
does not have any standardized meaning prescribed by Canadian GAAP and therefore
it may not be comparable with the calculation of similar measures for other
entities. Funds from operations as presented is not intended to represent
operating cash flow or operating profits for the period nor should it be viewed
as an alternative to cash flow from operating activities, per the statement of
cash flows, net earnings (loss) or other measures of financial performance
calculated in accordance with Canadian GAAP. All references to funds from
operations throughout this report are based on cash flow from operating
activities before changes in non-cash working capital and asset retirement
expenditures. Funds from operations per share is calculated based on the
weighted average number of common shares outstanding consistent with the
calculation of net earnings (loss) per share. Funds from operations netbacks
equal total revenue including realized commodity derivative gains/losses less
royalties, transportation, operating costs, general and administrative,
restricted stock unit, interest expense and cash taxes. Management also uses
field netbacks to analyze operating performance and adjusted working capital to
analyze leverage. Field netbacks and adjusted working capital as presented, do
not have any standardized meaning prescribed by Canadian GAAP and therefore may
not be comparable with the calculation of similar measures for other entities.
Field netbacks equal the total of revenue including realized commodity
derivative gains/losses less royalties, transportation and operating costs.
Adjusted working capital equals working capital excluding the current portion of
the commodity derivative asset or liability and the future income tax asset or
liability. Total boe is calculated by multiplying the daily production by the
number of days in the period.
A reconciliation of funds from operations is presented in the following table:
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Three months ended Six months ended
June 30, June 30,
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($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by operating activities 39,516 67,453 97,940 102,619
Add back:
Asset retirement expenditures 614 483 1,189 537
Change in non-cash working capital 1,649 21,646 (687) 39,860
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Funds from operations 41,779 89,582 98,442 143,016
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Plan of arrangement with Rider Resources Ltd. - On March 4, 2008, NuVista closed
a business combination with Rider Resources Ltd. ("Rider" or the "Rider
Acquisition") and a private placement financing with the Ontario Teachers'
Pension Plan Board ("OTPP"). The Rider Acquisition resulted in the combination
of NuVista and Rider, pursuant to which all of the issued and outstanding Rider
shares were exchanged for common shares of NuVista. Rider shareholders received,
for each Rider share held, 0.3540 of a NuVista share. The results of operations
from the Rider assets have been included effective March 4, 2008.
Operating activities - During the second quarter of 2009, NuVista participated
in 13 (11.8 net) wells, all of which were operated wells, with an average
working interest of 91%. Of these wells, 12 were drilled in the Oyen core area
and one in the West Central Saskatchewan core area. The success rate of 77% in
this drilling program resulted in nine natural gas wells, one oil well and three
dry holes. For the six months ended June 30, 2009, NuVista drilled 23 (17.4 net)
wells resulting in 13 natural gas wells, five oil wells and five dry holes.
NuVista has approximately 15 wells planned for the third quarter, primarily in
our Oyen, Wapiti and Pembina core areas.
Production
Three months ended June 30,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 109,564 112,979 (3)
Liquids (bbls/d) 3,247 2,609 24
Oil (bbls/d) 4,269 4,714 (9)
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Total oil equivalent (boe/d) 25,777 26,153 (1)
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----------------------------------------------------------------------------
Six months ended June 30,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Natural gas (mcf/d) 110,870 99,238 12
Liquids (bbls/d) 3,138 1,857 69
Oil (bbls/d) 4,358 4,349 -
----------------------------------------------------------------------------
Total oil equivalent (boe/d) 25,974 22,746 14
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For the three months ended June 30, 2009, NuVista's average production was
25,777 boe/d, comprised of 109.6 mmcf/d of natural gas, 3,247 bbls/d of
associated natural gas liquids ("liquids") and 4,269 bbls/d of oil, This is a 1%
decrease compared to the same period in 2008 and a 2% decrease compared to the
three months ended March 31, 2009. The slight decrease in NuVista's production
during the three months ended June 30, 2009 was primarily due to unscheduled
downtime experienced at third-party gas processing plants primarily in the
Wapiti and Pembina core areas.
NuVista's production for the six months ended June 30, 2009 averaged 25,974
boe/d comprised of 110.9 mmcf/d of natural gas, 3,138 bbls/d of liquids and
4,358 bbls/d of oil, which represents a 14% increase over the same period in
2008. Production increases for the six month period compared to the same period
in 2008 are primarily due to the full inclusion of six months of Rider
properties in 2009 compared to four months in 2008.
Revenues
Three months ended June 30,
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) 2009 2008 % Change
----------------- ----------------- --------------
Natural gas $ $/mcf $ $/mcf $ $/mcf
Production revenue 45,059 4.52 98,050 9.54 (54) (53)
Realized gain (loss) on
commodity derivatives (2) - (1,026) (0.10) (100) (100)
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Total 45,057 4.52 97,024 9.44 (54) (52)
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Liquids $ $/bbl $ $/bbl $ $/bbl
Production revenue 9,457 32.00 19,440 81.88 (51) (61)
Realized gain (loss) on
commodity derivatives - - - - - -
----------------------------------------------------------------------------
Total 9,457 32.00 19,440 81.88 (51) (61)
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Oil $ $/bbl $ $/bbl $ $/bbl
Production revenue 23,576 60.69 44,222 103.09 (47) (41)
Realized gain (loss) on
commodity derivatives 1,341 3.45 (4,835) (11.27) 128 131
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Total 24,917 64.14 39,387 91.82 (37) (30)
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----------------------------------------------------------------------------
Six months ended June 30,
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) 2009 2008 % Change
----------------- ----------------- --------------
Natural gas $ $/mcf $ $/mcf $ $/mcf
Production revenue 109,613 5.46 158,894 8.80 (31) (38)
Realized gain (loss) on
commodity derivatives 1,421 0.07 (1,026) (0.06) 238 217
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Total 111,034 5.53 157,868 8.74 (30) (37)
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Liquids $ $/bbl $ $/bbl $ $/bbl
Production revenue 20,141 35.46 27,256 80.65 (26) (56)
Realized gain (loss) on
commodity derivatives - - - - - -
----------------------------------------------------------------------------
Total 20,141 35.46 27,256 80.65 (26) (56)
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----------------------------------------------------------------------------
Oil $ $/bbl $ $/bbl $ $/bbl
Production revenue 40,067 50.80 72,610 91.73 (45) (45)
Realized gain (loss) on
commodity derivatives 6,986 8.86 (5,368) (6.78) 230 231
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Total 47,053 59.66 67,242 84.95 (30) (30)
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For the three months ended June 30, 2009, revenues including realized commodity
derivative gains and losses, were $79.4 million, a 49% decrease from $155.9
million for the same period in 2008. The decrease in revenues for the three
months ended June 30, 2009 compared to the same period of 2008 is primarily due
to the significant decrease in realized prices for all products. Revenues were
comprised of $45.1 million of natural gas revenue, $9.5 million of liquids
revenue, and $24.9 million of oil revenue. The decrease in average realized
commodity prices is comprised of a 52% decrease in the natural gas price to
$4.52/mcf from $9.44/mcf, a 61% decrease in the liquids price to $32.00/bbl from
$81.88/bbl and a decrease of 30% in the oil price to $64.14/bbl from $91.82/bbl.
For the six months ended June 30, 2009, revenues including realized commodity
derivative gains and losses were $178.2 million, a 29% decrease from $252.4
million, for the same period in 2008. The decrease in revenues for the first six
months of 2009 compared to the same period of 2008 is primarily due to the
decline in commodity prices offset by the 14% increase in production. These
revenues were comprised of $111.0 million of natural gas revenue, $47.1 million
of oil revenue, and $20.1 million of liquids revenue. The decrease in average
realized commodity prices is comprised of a 37% decrease in the natural gas
price to $5.53/mcf from $8.74/mcf, a 30% decrease in the oil price to $59.66/bbl
from $84.95/bbl, and a decrease of 56% in the liquids price to $35.46/bbl from
$80.65/bbl.
Commodity price risk management
Three months ended June 30,
----------------------------------------------------------------------------
2009 2008
------------------------------ -------------------------------
Realized Unrealized Total Realized Unrealized Total
Gain Gain Gain Gain Gain Gain
($ thousands) (Loss) (Loss) (Loss) (Loss) (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas (2) - (2) (1,026) (5,826) (6,852)
Oil 1,341 (7,478) (6,137) (4,835) (34,205) (39,040)
----------------------------------------------------------------------------
Total gain
(loss) 1,339 (7,478) (6,139) (5,861) (40,031) (45,892)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended June 30,
----------------------------------------------------------------------------
2009 2008
------------------------------ -------------------------------
Realized Unrealized Total Realized Unrealized Total
Gain Gain Gain Gain Gain Gain
($ thousands) (Loss) (Loss) (Loss) (Loss) (Loss) (Loss)
----------------------------------------------------------------------------
Natural gas 1,421 (1,094) 327 (1,026) (9,710) (10,736)
Oil 6,986 (14,226) (7,240) (5,368) (40,065) (45,433)
----------------------------------------------------------------------------
Total gain
(loss) 8,407 (15,320) (6,913) (6,394) (49,775) (56,169)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 stabilize cash flow against the unpredictable commodity price environment.
NuVista's Board of Directors has approved a price risk management limit of up to
60% of forecast production, net of royalties, using fixed price, put option and
costless collar contracts. To achieve NuVista's price risk management
objectives, we enter into both commodity derivative and physical sale contracts.
For the three months ended June 30, 2009, the commodity derivative price risk
management program resulted in a loss of $6.1 million consisting of realized
gains of $1.3 million on natural gas and oil hedges and a $7.5 million
unrealized loss on crude oil hedges. For the six months ended June 30, 2009, the
commodity derivative price risk management program resulted in a loss of $6.9
million consisting of realized gains of $8.4 million and an unrealized loss of
$15.3 million.
For the six months ended June 30, 2009, price risk management gains on our
physical sale contracts totaled $18.0 million. As at June 30, 2009, the
mark-to-market value of our financial commodity derivative contracts was a gain
of $1.2 million and the mark-to-market value of our physical sales contracts was
a gain of $7.9 million, net of the deferred put option costs of $5.6 million.
The following is a summary of commodity price risk management contracts in place
as at June 30, 2009:
(a) Financial contracts
Crude oil:
Volume Average Price (Cdn$/bbl) Term
----------------------------------------------------------------------------
1,000 bbls/d CDN. $64.00 - Bow River January 1, 2009 -
December 31, 2009
1,000 bbls/d CDN. $95.01 - $110.01 - WTI (1) January 1, 2009 -
December 31, 2009
(1) This is a US$ denominated crude oil contract with an associated fixed
price foreign exchange contract of 1.0262 US$/Cdn$.
(b) Physical sale contracts
Natural gas:
Volume Average Price (Cdn$/gj) Term
----------------------------------------------------------------------------
20,000 gj/d CDN. $7.45 - Fixed Price AECO April 1, 2009 -
October 31, 2009
5,000 gj/d CDN. $5.65 - AECO Floor (1), (4) April 1, 2009 -
October 31, 2009
20,000 gj/d CDN. $5.97 - $6.56 - AECO (2), (4) November 1, 2009 -
October 31, 2010
20,000 gj/d CDN. $5.55 - AECO Floor (3), (4) November 1, 2009 -
March 31, 2010
(1) The AECO put was purchased at a deferred cost of $0.82/gj for a total
cost of $0.9 million.
(2) The deferred cost associated with the funded collar was $0.30/gj for a
total cost of $2.2 million.
(3) The AECO put was purchased at a deferred cost of $0.97/gj for a total
cost of $2.9 million.
(4) The deferred costs are incurred monthly over the term of the contract
and will be offset against revenues.
Royalties
Three months ended Six months ended
June 30, June 30,
----------------------------------------
Royalty rates (%) 2009 2008 2009 2008
----------------------------------------------------------------------------
Natural gas and liquids 10 25 14 26
Oil 12 18 10 16
----------------------------------------------------------------------------
Weighted average rate 10 22 13 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties of $8.2 million for the three months ended June 30, 2009 were 77%
lower than the $35.9 million for the same period of 2008. Royalties for the six
months ended June 30, 2009 were $23.5 million as compared to $58.2 million
reported for the six months ended June 30, 2008. The decrease in royalties are
primarily due to lower revenues associated with low commodity prices in both the
second quarter and first half of 2009 compared to the same periods in 2008.
As a percentage of revenue, the average royalty rate for the second quarter of
2009 was 10% compared to 22% for the comparative period of 2008. Royalty rates
by product for the three months ended June 30, 2009, were 10% for natural gas
and liquids and 12% for oil compared to 25% for natural gas and liquids and 18%
for oil for the same period in 2008. For the six months ended June 30, 2009, the
average royalty rate as a percentage of revenue was 13% compared to 22% for the
same period in 2008. Royalty rates by product were 14% for natural gas and
liquids and 10% for oil compared to 26% for natural gas and liquids and 16% for
oil for the same period in 2008.
The lower royalty rates are primarily due to the impact of the New Alberta
Royalty Framework in a low commodity price environment and the impact of price
risk management activities on the reported royalty rates. Our price risk
management activities impact reported royalty rates as royalties are based on
government market reference prices and not our average realized prices that
include price risk management activities. As a result, the gains from our price
risk management activities included in revenue result in a lower royalty rate as
a percentage of revenue than if no price risk management activities had taken
place. Excluding the impact of price risk management activities, Alberta natural
gas royalty rates for the three months ended June 30, 2009 were approximately
12% compared to 21% for the same period in 2008 and Alberta oil royalty rates
for the three months ended June 30, 2009 were approximately 11% compared to 13%
for the same period in 2008.
Netbacks - The table below summarizes field netbacks by product for the
three months ended June 30, 2009:
Natural gas
and liquids Oil Total
----------------- ------------------ --------------
129.0 mmcfe/d 4,269 bbl/d 25,777 boe/d
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) $ $/mcfe $ $/bbl $ $/boe
Production revenue 54,516 4.64 23,576 60.69 78,092 33.29
Realized gain (loss) on
commodity derivatives (2) - 1,341 3.45 1,339 0.57
----------------------------------------------------------------------------
54,514 4.64 24,917 64.14 79,431 33.86
Royalties (5,236) (0.45) (3,001) (7.72) (8,237) (3.51)
Transportation costs (1,687) (0.14) (694) (1.79) (2,381) (1.02)
Operating costs (12,292) (1.05) (6,096) (15.69)(18,388) (7.84)
----------------------------------------------------------------------------
Field netback 35,299 3.00 15,126 38.94 50,425 21.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes field netbacks by product for the six months
ended June 30, 2009:
Natural gas
and liquids Oil Total
----------------- ------------------ --------------
129.7 mmcfe/d 4,358 bbl/d 25,974 boe/d
----------------------------------------------------------------------------
($ thousands, except per
unit amounts) $ $/mcfe $ $/bbl $ $/boe
Production revenue 129,754 5.53 40,067 50.80 169,821 36.12
Realized gain on
commodity derivatives 1,421 0.06 6,986 8.86 8,407 1.79
----------------------------------------------------------------------------
131,175 5.59 47,053 59.66 178,228 37.91
Royalties (18,857) (0.80) (4,604) (5.84)(23,461) (4.99)
Transportation costs (3,093) (0.13) (1,065) (1.35) (4,158) (0.88)
Operating costs (26,035) (1.11) (12,865) (16.31)(38,900) (8.27)
----------------------------------------------------------------------------
Field netback 83,190 3.55 28,519 36.16 111,709 23.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The tables below summarizes funds from operations netbacks for the three
months ended June 30, 2009 compared to the three months ended June 30, 2008,
and the six months ended June 30, 2009 compared to the six months ended June
30, 2008.
Three months ended June 30,
----------------------------------------------------------------------------
2009 2008 % Change
----------------- ------------------ --------------
($ thousands, except
per unit amounts) $ $/boe $ $/boe $ $/boe
Production revenue 78,092 33.29 161,712 67.95 (52) (51)
Realized gain (loss)
on commodity
derivatives 1,339 0.57 (5,861) (2.46) 123 123
----------------------------------------------------------------------------
79,431 33.86 155,851 65.49 (49) (48)
Royalties (8,237) (3.51) (35,926) (15.10) (77) (77)
Transportation (2,381) (1.02) (2,296) (0.96) 4 6
Operating costs (18,388) (7.84) (19,481) (8.19) (6) (4)
----------------------------------------------------------------------------
Field netback 50,425 21.49 98,148 41.24 (49) (48)
General and
administrative (3,777) (1.61) (3,606) (1.52) 5 6
Restricted stock
units (637) (0.27) (865) (0.36) (26) (25)
Interest (4,232) (1.80) (4,095) (1.72) 3 5
----------------------------------------------------------------------------
Funds from operations
netback 41,779 17.81 89,582 37.64 (53) (53)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended June 30,
2009 2008 % Change
----------------- ------------------ --------------
($ thousands, except per
unit amounts) $ $/boe $ $/boe $ $/boe
Production revenue 169,821 36.12 258,760 62.51 (34) (42)
Realized gain (loss) on
commodity derivatives 8,407 1.79 (6,394) (1.54) 231 216
----------------------------------------------------------------------------
178,228 37.91 252,366 60.97 (29) (38)
Royalties (23,461) (4.99) (58,153) (14.05) (60) (64)
Transportation (4,158) (0.88) (3,737) (0.90) 11 (2)
Operating costs (38,900) (8.27) (32,898) (7.95) 18 4
----------------------------------------------------------------------------
Field netback 111,709 23.77 157,578 38.07 (29) (38)
General and
administrative (6,728) (1.43) (5,811) (1.40) 16 2
Restricted stock units (598) (0.13) (1,118) (0.27) (47) (52)
Interest (5,941) (1.26) (7,633) (1.84) (22) (32)
----------------------------------------------------------------------------
Funds from operations
netback 98,442 20.95 143,016 34.56 (31) (39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Transportation - Transportation costs were $2.4 million ($1.02/boe) for the
three months ended June 30, 2009 as compared to $2.3 million ($0.96/boe) for the
same period of 2008. Transportation costs were $4.2 million ($0.88/boe) for the
six months ended June 30, 2009 compared to $3.7 million ($0.90/boe) for the same
period in 2008. The increase in transportation costs in 2009 compared to 2008 is
primarily due to an increase in oil and liquids production as a percentage of
overall production and their higher associated transportation costs.
Operating - Operating expenses were $18.4 million ($7.84/boe) for the three
months ended June 30, 2009 as compared to $19.5 million ($8.19/boe) for the
three months ended June 30, 2008 and $20.5 million ($8.71/boe) for the three
months ended March 31, 2009. The reduction in per unit costs resulted primarily
from lower electricity costs and cost savings initiatives completed by NuVista's
field staff during the second quarter. For the three months ended June 30, 2009,
natural gas and natural gas liquid operating costs averaged $1.05/mcfe and oil
operating expenses were $15.69/bbl as compared to $1.16/mcfe and $13.76/bbl
respectively for the same period in 2008.
Operating expenses were $38.9 million ($8.27/boe) for the six months ended June
30, 2009 as compared to $32.9 million ($7.95/boe) for the six months ended June
30, 2008. This increase resulted from the 14% increase in production volumes and
a 4% increase in per unit costs. For the six months ended June 30, 2009, natural
gas and natural gas liquid operating expenses averaged $1.11/mcfe and oil
operating expenses were 16.31/bbl as compared to $1.15/mcfe and $12.34/bbl
respectively for the same period of 2008.
NuVista is forecasting operating expenses to average $9.25/boe for the last half
of 2009 which increases our 2009 annual operating expense estimate to $8.75/boe.
The increase in projected costs (on a per boe basis) is due primarily to the
inclusion of the newly acquired northwest Alberta properties for the last five
months of 2009. These properties' cost structure is currently higher than
NuVista's average operating costs per boe for 2009.
General and administrative - General and administrative expenses, net of
overhead recoveries, for the three months ended June 30, 2009 were $3.8 million
($1.61/boe) compared to $3.6 million ($1.52/boe) in the same period of 2008.
General and administrative expenses, net of overhead recoveries, for the six
months ended June 30, 2009 were $6.7 million ($1.43/boe) as compared to $5.8
million ($1.40/boe) for the six months ended June 30, 2008. This increase in
general and administrative expenses is directly attributable to the higher
production base in NuVista associated with the Rider Acquisition. Higher per
unit costs reflect increased staffing costs and lower capital overhead
recoveries. NuVista is forecasting 2009 general and administrative costs for the
remainder of the year to average approximately $1.40/boe.
Three months ended Six months ended
June 30, June 30,
----------------------------------------
($ thousands, except per unit amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Gross general and administrative
expenses 4,889 5,384 9,359 8,947
Overhead recoveries (1,112) (1,778) (2,631) (3,136)
----------------------------------------------------------------------------
Net general and administrative
expenses 3,777 3,606 6,728 5,811
----------------------------------------------------------------------------
Per boe 1.61 1.52 1.43 1.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Stock-based compensation
Three months ended Six months ended
June 30, June 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Stock-based compensation 1,313 1,025 3,354 2,030
Restricted stock units 637 865 598 1,118
----------------------------------------------------------------------------
Total 1,950 1,890 3,952 3,148
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NuVista recorded a stock-based compensation charge of $2.0 million for the three
months ended June 30, 2009 compared to $1.9 million for the same period in 2008.
For the six months ended June 30, 2009, NuVista recorded a stock-based
compensation charge of $4.0 million compared to $3.1 million for the same period
in 2008. The stock-based compensation charge relates to the amortization of the
value of stock option awards and the accrual for future payments under the
Restricted Stock Unit ("RSU") Incentive Plan. The increase in the second quarter
of 2009 relates primarily to an increase in the number of stock options
outstanding. In January 2008, NuVista implemented an RSU Incentive Plan. Each
RSU entitles participants to receive cash equal to the market value of the
equivalent number of shares of NuVista. The RSUs become payable as they vest,
typically over three years. The decrease in RSU expense for the three and six
months ended 2009 was a result of the number of RSUs outstanding and movement in
NuVista's share price.
Interest - Interest expense for the three months ended June 30, 2009 was $4.2
million ($1.80/boe) compared to $4.1 million ($1.72 /boe) for the same period of
2008. For the six months ended June 30, 2009, interest expense was $5.9 million
($1.26/boe) compared to $7.6 million ($1.84/boe) in the same period of 2008. For
the three months ended June 30, 2009, borrowing costs averaged 3.25% compared to
4.0% in the same period of 2008. The revolving term of NuVista's credit facility
was extended on March 3, 2009, and as part of the terms of this extension
NuVista's borrowing margin was increased to current market rates. Currently,
NuVista's average borrowing rate is approximately 3.25%. Cash paid for interest
for the three and six months ended June 30, 2009 was $3.9 million (2008 - $5.0
million) and $5.5 million (2008 - $7.2 million) respectively.
Depreciation, depletion and accretion - Depreciation, depletion and accretion
expenses were $42.5 million for the second quarter of 2009 as compared to $43.1
million for the same period in 2008. The average per unit cost was $18.12/boe in
the second quarter of 2009 as compared to $18.11/boe for the same period in
2008. Depreciation, depletion and accretion expenses for the six months ended
June 30, 2009, were $84.9 million as compared to $75.8 million for the same
period in 2008. The average per unit cost was $18.06/boe in the first half of
2009 as compared to $18.31/boe in the same period in 2008.
Income taxes - For the three months ended June 30, 2009, the provision for
income and other taxes was a recovery of $2.2 million compared to an expense of
$1.9 million for the same period in 2008. For the six months ended June 30,
2009, the provision for income and other taxes was a recovery of $0.5 million
compared to an expense of $4.7 million in the same period of 2008. The effective
tax rate was 23% for the three months ended June 30, 2009.
Capital expenditures - Capital expenditures were $8.3 million during the second
quarter of 2009 compared to $16.2 million in the same period of 2008, with $10.6
million of exploration and development spending and $18.1 million spent on a
complementary property acquisition. Second quarter capital excludes $18.0
million for the deposit on the acquisition which closed on July 27, 2009 and is
net of an estimated $2.3 million credit on drilling costs resulting from the
Alberta government drilling incentive program. Capital expenditures for the six
months ended June 30, 2009 were $89.5 million, consisting of $37.8 million for
exploration and development spending, $54.1 million for acquisitions and $2.3
million in drilling credits. This compares to $67.1 million incurred for the
same period of 2008, consisting of $25.4 million of acquisitions and exploration
and development spending of $41.7 million.
Three months ended Six months ended
June 30, June 30,
----------------------------------------
($ thousands, except per unit amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Exploration and development
Land and retention costs 851 4,451 1,775 5,123
Seismic 1,906 2,385 4,490 4,986
Drilling and completion 5,538 6,176 17,528 17,881
Facilities and equipment 2,146 2,278 13,513 12,386
Corporate and other 203 1,188 491 1,340
----------------------------------------------------------------------------
Subtotal 10,644 16,478 37,797 41,716
Acquisitions
Property 4 (265) 54,075 25,398
----------------------------------------------------------------------------
Subtotal 4 (265) 54,075 25,398
----------------------------------------------------------------------------
Total capital expenditures 10,648 16,213 91,872 67,114
Alberta drilling incentive credits (2,326) - (2,326) -
----------------------------------------------------------------------------
Net capital expenditures 8,322 16,213 89,546 67,114
----------------------------------------------------------------------------
Corporate acquisition - non-cash - - - 594,944
----------------------------------------------------------------------------
Net earnings and funds from operations - For the three months ended June 30,
2009, net earnings decreased to a loss of $7.3 million (($0.09)/share, basic)
from $2.9 million ($0.04/share, basic) for the same period in 2008. Second
quarter 2009 net earnings were lower when compared to the same period in 2008
primarily due to the impact of lower oil and natural gas prices. For the three
months ended June 30, 2009, realized gains on our financial and physical sales
price risk management programs totaled $9.2 million, partially mitigating the
impact of lower oil and natural gas prices. Net earnings per share decreased due
to the decrease in net earnings and increase in number of shares outstanding
following the Rider Acquisition.
For the three months ended June 30, 2009, NuVista's funds from operations were
$41.8 million ($0.53/share, basic), a 53% decrease from $89.6 million
($1.14/share, basic) for the three months ended June 30, 2008. Funds from
operations for the three months ended June 30, 2009 were lower than the same
period in 2008 primarily due to lower commodity prices, partially offset by
higher production volumes, and increased operating and general and
administrative costs. Funds from operations per share decreased 54% due to the
decrease in funds from operations and an increase in number of shares
outstanding following the Rider Acquisition.
Liquidity and capital resources - As at June 30, 2009, debt net of adjusted
working capital was $351.5 million, resulting in a net debt to annualized second
quarter funds from operations ratio of 2.1:1. At June 30, 2009, NuVista had an
adjusted working capital surplus of $24.9 million. Adjusted working capital
excludes the current portion of the fair value of the commodity derivative asset
of $1.2 million and the related current portion of future income tax liability
of $0.3 million. We believe it is appropriate to exclude these amounts when
assessing financial leverage. At June 30, 2009, NuVista had $73.7 million of
unused bank borrowing capacity based on the current credit facility of $450.0
million. On July 27, 2009, NuVista's credit facility was increased to $510.0
million.
NuVista has a credit facility from a syndicate of primarily Canadian banks with
a maximum borrowing amount of $450.0 million. The credit facility is a 364-day
revolving facility subject to an annual review by the bank syndicate, at which
time a lender can provide an extension of the 364-day revolving period or
request conversion to a one year term loan. During the revolving period, a
determination of the maximum borrowing amount occurs semi-annually on or before
April 30 and October 31.
On March 3, 2009, NuVista and the bank syndicate agreed to an extension of the
revolving period from March 3, 2009 until April 30, 2009, in order for the bank
syndicate to complete their annual review of NuVista's reserves and financial
results. On April 3, 2009, NuVista's bank syndicate completed their annual
review and extended the revolving period of the credit facility to April 29,
2010, and the term period to April 29, 2011. Under the term period, no principal
payments would be required until April 29, 2011.
NuVista anticipates that funds from operations will provide the flexibility to
fund its planned 2009 capital program. In this period of lower commodity prices
and challenging economic environment, NuVista will place increased emphasis on
maintaining its financial flexibility. NuVista plans to closely monitor its 2009
business plan and adjust capital programs in the context of commodity prices and
access to bank and equity capital. It is NuVista's intent to have a reduced
capital program for the second half of 2009, which in turn is expected to reduce
net debt to the targeted level of approximately $365 million.
As at June 30, 2009, there were 79.3 million common shares outstanding. There
were 3.0 million of common share purchase warrants which expired on March 4,
2009. In addition, there were 6.3 million stock options outstanding, with an
average exercise price of $13.46 per share.
Subsequent events
(a) Property acquisition and equity financing - On June 15, 2009 NuVista
announced the acquisition of certain properties in the Martin Creek area of
Northeast British Columbia and in Northwest Alberta and two subscription receipt
financings. On July 27, 2009, NuVista closed the acquisition for a purchase
price of $174 million. The acquisition was financed through a combination of
bank debt and the net proceeds from two equity offerings. NuVista entered into
an agreement to issue 7,500,000 subscription receipts at a price of $11.00 per
subscription receipt on a bought deal basis for gross proceeds of $82.5 million.
In addition, NuVista issued 1,500,000 subscription receipts at a price of $11.00
per subscription receipt, by way of a private placement to Ontario Teachers'
Pension Plan 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.
(b) Long-term debt - On July 27, 2009, the Company's credit facility was
increased to a maximum borrowing amount of $510.0 million. Terms and conditions
remain the same as disclosed in note 5 of the financial statements.
Related party activities - In 2003, as part of the Plan of Arrangement with
Bonavista Petroleum Ltd. ("Bonavista"), NuVista entered into a Technical
Services Agreement ("TSA") with Bonavista for the provision of certain services
to NuVista. On August 31, 2007, the TSA was terminated and replaced with a new
services agreement that reflected the remaining ongoing services that will be
provided by Bonavista. On November 1, 2008, this services agreement was
terminated and Bonavista no longer provides any ongoing services to NuVista.
NuVista and Bonavista are considered related as two directors of NuVista, one of
whom is NuVista's chairman, are also directors and officers of Bonavista and a
director and an officer of NuVista are also officers of Bonavista. For the three
months ended June 30, 2009, NuVista paid Bonavista $nil (2008 - $0.4 million) in
fees relating to general and administrative services provided by Bonavista. In
2009, NuVista charged Bonavista management fees for jointly owned partnerships
totalling $0.3 million (2008 - $0.3 million). In addition, during the second
quarter of 2009, Bonavista charged NuVista $56,000 (2008 - $63,000) for costs
that are outside of the new services agreement relating to NuVista's share of
direct charges from third parties.
For the six months ended June 30, 2009, NuVista paid Bonavista $nil (2008 - $0.8
million) in fees relating to general and administrative services provided by
Bonavista, and NuVista charged Bonavista management fees for jointly owned
partnerships totaling $0.6 million (2008 - $0.6 million). In addition, Bonavista
charged NuVista $76,000 (2008 - $72,000) for costs that are outside of the new
services agreement relating to NuVista's share of direct charges from third
parties. As at June 30, 2009, the amount receivable from Bonavista was $0.2
million (2008 - $2.9 million).
Contractual obligations and commitments - NuVista enters into contract
obligations as part of conducting business. The following is a summary of
NuVista's contractual obligations and commitments as at June 30, 2009:
($ thousands) Total 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Transportation 13,817 2,426 3,368 2,668 2,004 3,351
Office lease 6,849 1,027 2,055 2,055 1,712 -
Physical sale contract
premiums 5,620 2,050 3,570 - - -
Physical power contract 6,900 - - 2,300 2,300 2,300
Long-term debt 376,305 - - 376,305 - -
----------------------------------------------------------------------------
Total commitments 409,491 5,503 8,993 383,328 6,016 5,651
----------------------------------------------------------------------------
Quarterly financial information - The following table highlights NuVista's
performance for the eight quarterly reporting periods from September 30, 2007 to
June 30, 2009:
2009 2008 2007
----------------------------------------------------------------
Jun 30 Mar 31 Dec 31 Sep 30 Jun 30 Mar 31 Dec 31 Sep 30
----------------------------------------------------------------------------
Production
(boe/d) 25,777 26,175 25,688 26,065 26,153 19,339 14,251 13,590
($ thousands,
except per
share amounts)
Production
revenue 78,092 91,729 106,982 149,648 161,794 97,064 53,790 48,166
Net earnings
(loss) (7,312) 2,632 24,443 53,699 2,905 7,150 11,063 754
Net earnings
(loss)
Per share
- basic (0.09) 0.03 0.31 0.68 0.04 0.12 0.21 0.01
Per share
- diluted (0.09) 0.03 0.31 0.68 0.04 0.12 0.21 0.01
----------------------------------------------------------------------------
NuVista has seen production volumes remain in a range of 25,688 boe/d to 26,175
boe/d for the last five quarters as NuVista reduced capital spending during this
period in order to allocate cash flow to debt reduction following the Rider
Acquisition and in response to lower commodity prices. The increases in
production during the first and second quarters of 2008 relate primarily to the
Rider Acquisition that closed on March 4, 2008. Over the prior eight quarters,
quarterly revenue has been in a range of $48.2 million to $161.8 million with
revenue primarily influenced by production volumes, and oil and natural gas
prices in the quarter. Net earnings (loss) have been in a range of $53.7 million
to $(7.3) million 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 the Company's development plans.
The effect of changes in proved oil and natural gas reserves on the financial
results and position of the Company 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) 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. The Company has one reporting unit, being the entity as a
whole, and as at June 30, 2009, we have determined there was no goodwill
impairment.
Update on regulatory matters
(a) New Alberta Royalty Framework - On October 25, 2007, the Government of
Alberta released a report entitled "The New Royalty Framework" (the "NRF")
containing the Government's proposals for Alberta's new royalty regime, which
was followed by the Mines and Minerals (New Royalty Framework) Amendment Act,
2008, which was given Royal Assent on December 2, 2008. The NRF and the
applicable new legislation became effective on January 1, 2009. The NRF
establishes new royalty rates for conventional oil, natural gas and oil sands.
On April 10, 2008, the Government of Alberta introduced two new royalty programs
that will encourage the development of deep oil and gas reserves, and these are:
(a) a five-year oil program for exploration wells over 2,000 metres that will
provide royalty adjustments to offset higher drilling costs and provide a
greater incentive for producers to continue to pursue new, deeper oil plays
(these oil wells will qualify for up to $1 million or 12 months of royalty
offsets, whichever comes first); and (b) a five-year natural gas deep drilling
program that will replace the existing program in order to encourage continued
deep gas exploration for wells deeper than 2,500 metres (the program will create
a sliding scale of royalty credit according to depth, of up to $3,750 per
metre). These new programs are to be implemented along with the NRF.
In response to the drop in commodity prices experienced during the second half
of 2008, the Government of Alberta announced on November 19, 2008, the
introduction of a five year program of transitional royalty rates with the
intent of promoting new drilling. Under this new program companies drilling new
natural gas or conventional oil deep wells (between 1,000 and 3,500 metres) will
be given a one-time option, on a well by well basis, to adopt either the new
transitional royalty rates or those outlined in the NRF. In order to qualify for
this program wells must be drilled during the period starting on November 19,
2008, and ending on December 31, 2013. Following this period all new wells
drilled will automatically be subject to the NRF.
On March 3, 2009, the Government of Alberta announced a three-point incentive
program to stimulate new and continued economic activity in Alberta which
included a drilling royalty credit for new conventional oil and natural gas
wells and a new well royalty incentive program. Under the drilling royalty
credit program a $200 per metre royalty credit will be available on new
conventional oil and natural gas wells drilled between April 1, 2009 and June
30, 2010, subject to certain maximum amounts. The maximum credits available will
be determined by the company's production level in 2008 and its drilling
activity between April 1, 2009 and March 31, 2010. Based on NuVista's 2008
production it will be entitled to a maximum credit of 40% of royalties payable
in the period April 1, 2009 to March 31, 2010. The new well incentive program
will apply to wells beginning production of conventional oil and natural gas
between April 1, 2009 and March 31, 2010 and provides for a maximum 5% royalty
rate for the first 12 months of production, up to a maximum of 50,000 barrels or
500 mmcf of natural gas. On June 25, 2009, the Government of Alberta extended
this incentive program to March 31, 2011.
As royalties under the NRF are sensitive to both commodity prices and production
levels, the estimated NRF Alberta and corporate royalty rates will fluctuate
with commodity prices, well production rates, production decline of existing
wells, and performance and location of new wells drilled.
(b) British Columbia Royalty Incentive Program - On August 6, 2009 the
Government of British Columbia introduced a new royalty incentive program that
provides for a 2% royalty rate for the first year of production from all wells
drilled between September 2009 and June 2010. In addition, the existing royalty
deductions available under the Deep Royalty Credit Program were increased by 15%
and horizontal wells drilled between 1,900 and 2,300 metres now qualify for the
Deep Royalty Credit Program.
Update on accounting policies and financial reporting matters
(a) Goodwill and intangible assets - Effective January 1, 2009, NuVista adopted
Section 3064, Goodwill and Intangible Assets issued by the Canadian Institute of
Chartered Accountants ("CICA"). Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and intangible
assets subsequent to its initial recognition. This new section has no current
impact on NuVista's consolidated financial statements.
(b) International Financial Reporting Standards - In February 2008, the Canadian
Accounting Standards Board confirmed January 1, 2011, as the effective date for
the requirement to report under International Financial Reporting Standards
("IFRS") with comparative 2010 periods converted as well. Canadian GAAP, as we
currently know them, will cease to exist for all public reporting entities.
In order to meet the requirement to transition to IFRS, NuVista has appointed
internal staff to lead the conversion project along with sponsorship from an
executive steering committee. NuVista involves external auditors and external
consultants, as required, during the conversion project. NuVista has provided
training to key employees, completed a preliminary analysis of the accounting
differences and is monitoring the impact of the transition on its business
practices, information systems and internal control over financial reporting.
During NuVista's preliminary analysis, accounting implementation for certain
areas was identified as having the greatest potential impact to NuVista's
consolidated financial statements in terms of complexity and effort. NuVista has
determined that accounting for property, plant and equipment, impairment
testing, asset retirement obligation, stock-based compensation and income taxes
will be impacted by the conversion to IFRS. In July 2009, the International
Accounting Standards Board issued amendments to IFRS 1 - First-Time Adoption of
International Financial Reporting Standards. This amendment allows first-time
adopters using full cost accounting to elect to measure oil and gas assets at
the date of transition to IFRS using amounts determined based on the entity's
previous GAAP. During the second quarter of 2009, NuVista performed an analysis
of IFRS in comparison with currently applied accounting principles on the key
areas previously identified as high priority. NuVista is currently analyzing the
various accounting policy choices available and will implement those determined
to be the most appropriate. The impact of IFRS on NuVista's consolidated
financial statements is not reasonably determinable at this time.
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 to be disclosed by NuVista is accumulated and communicated to
management as appropriate to allow timely decisions regarding the required
disclosure. The CEO and CFO have also designed internal controls over financial
reporting, or caused them to be designed under their supervision, to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. During the quarter ended June 30,
2009, 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 Canadian/US dollar exchange rate,
interest rates and debt service obligations;
- Risk associated with the current global financial crisis;
- Risk associated with the re-negotiation of NuVista's credit facility and the
continued participation of NuVista's lenders;
- Market risk relating to the availability of transportation systems to move the
product to market;
- Environmental and safety risk associated with well operations and production
facilities; and
- Changing government regulations relating to royalty legislation, income tax
laws, incentive programs, operating practices and environmental protection
relating to the oil and natural gas industry.
NuVista seeks to mitigate these risks by:
- Acquiring properties with established production trends to reduce technical
uncertainty as well as undeveloped land with development potential;
- Maintaining a low cost structure to maximize product netbacks and reduce
impact of commodity price cycles;
- Diversifying properties to mitigate individual property and well risk;
- Maintaining product mix to balance exposure to commodity prices;
- Conducting rigorous reviews of all property acquisitions;
- Monitoring pricing trends and developing a mix of contractual arrangements for
the marketing of products with creditworthy counterparties;
- Maintaining a price risk management program to manage commodity prices and
foreign exchange currency rates risk and transacting with creditworthy
counterparties;
- Ensuring strong third-party operators for non-operated properties;
- Adhering to NuVista's safety program and keeping abreast of current operating
best practices;
- Keeping informed of proposed changes in regulations and laws to properly
respond to and plan for the effects that these changes may have on our
operations;
- Carrying industry standard insurance to cover losses;
- Establishing and maintaining adequate cash resources to fund future
abandonment and site restoration costs;
- Closely monitoring commodity prices and capital programs to manage financial
leverage; and
- Monitoring the bank and equity markets to understand how changes in the
capital market may impact NuVista's business plan.
OUTLOOK
Although the current financial and commodity markets create considerable
uncertainty in the near term, NuVista will be responsive to economic conditions
and continue with its disciplined acquire and develop business model. The low
natural gas price environment presents challenges but with our disciplined
counter-cyclical approach to business and our financial flexibility, it can also
provide opportunities to create shareholder value. During this period of low
natural gas prices we will continue to evaluate opportunities for strategic or
smaller complementary acquisitions to position NuVista for future success.
Prudent management of our capital program and financial leverage should provide
us with the financial flexibility to take advantage of these opportunities. We
plan to spend less than forecast cash flow on our exploration and development
capital program for the second half of 2009 in order to reduce our debt levels
following the latest acquisition. In addition, concurrent with the closing of
the acquisition our credit facility was increased from $450 million to $510
million.
NuVista forecasts 2009 funds from operations of approximately $190 million based
on current pricing assumptions. These assumptions for 2009 include an AECO
natural gas price of $4.15/mcf, a WTI crude oil price of US$60.00, a foreign
exchange rate of 0.87 CDN/USD and include price risk management contracts
currently in place. Based on this forecast of funds from operations, our Board
of Directors has approved a 2009 capital budget of $320 million with capital
spending of approximately $50 million in the second half of 2009. This capital
program has the flexibility to either accelerate or defer capital expenditures
based upon market conditions. We expect to drill 20 to 30 wells during the
second half of the year. Our constrained 2009 capital program will result in a
high-grading of opportunities in 2009 and a growing prospect inventory heading
into 2010. Based on this capital budget, forecast funds from operations, and
closing of the recent acquisition and related equity financing, we are targeting
year end net debt of approximately $365 million.
We have revised our average 2009 production guidance to 27,000 boe/d to 27,500
boe/d due to the shut-in of up to 900 boe/d of natural gas production relating
to high operating cost production and constraints on the TCPL pipeline for the
remainder of 2009. The loss of this natural gas production has minimal impact
on our funds from operations.
For the remainder of the year, we will continue to invest human resources and
capital on our emerging tight gas resource plays in order to develop a thorough
understanding of recovery concepts. We will advance these projects in the
remainder of 2009 by drilling new wells to assess recovery from each of these
resource plays. During this period we will also pursue the benefits from
royalty incentive programs announced by the Alberta and British Columbia
governments and lower industry drilling and completion costs.
Over the long term we believe that supply and demand fundamentals should result
in significant upside for both oil and natural gas prices; however, we must be
prepared to endure an extended period of low prices before this recovery occurs.
We believe our counter-cyclical strategy of acquiring premium assets at
attractive prices over the next two to three years and optimizing production
from these assets will richly reward our stakeholders over the long term.
Throughout our six year history, NuVista has demonstrated a disciplined and
flexible approach to spending and allocating capital with a focus on profitable
per share growth while maintaining a strong balance sheet. NuVista will continue
with this approach in 2009 and beyond.
Sincerely,
Alex G. Verge, President & CEO
Robert F. Froese, Vice-President, Finance & CFO
NUVISTA ENERGY LTD.
Consolidated Balance Sheets
June 30, December 31,
($ thousands) 2009 2008
----------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ - $ 139
Accounts receivable and prepaids 69,008 64,712
Commodity derivative asset (note 7) 1,194 16,513
----------------------------------------------------------------------------
70,202 81,364
Oil and natural gas properties and equipment
(note 3) 1,275,936 1,242,216
Goodwill 83,716 83,716
----------------------------------------------------------------------------
$ 1,429,854 $ 1,407,296
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 44,154 $ 50,710
Future income taxes 323 4,954
----------------------------------------------------------------------------
44,477 55,664
Long-term debt (note 5) 376,305 355,407
Compensation liability (note 6) 274 850
Asset retirement obligations (note 4) 54,228 46,296
Future income taxes 142,442 137,779
Shareholders' equity
Share capital, warrants and contributed
surplus (note 6) 603,550 598,042
Retained earnings 208,578 213,258
----------------------------------------------------------------------------
812,128 811,300
----------------------------------------------------------------------------
$ 1,429,854 $ 1,407,296
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (note 9)
Subsequent events (note 10)
See accompanying notes to consolidated financial statements.
NUVISTA ENERGY LTD.
Consolidated Statements of Earnings (Loss), Comprehensive Income (Loss) and
Retained Earnings
Three months Six months
ended June 30, ended June 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)
Revenues
Production $ 78,092 $161,712 $169,821 $258,760
Royalties (8,237) (35,926) (23,461) (58,153)
Realized gain (loss) on commodity
derivatives 1,339 (5,861) 8,407 (6,394)
Unrealized loss on commodity
derivatives (7,478) (40,031) (15,320) (49,775)
----------------------------------------------------------------------------
63,716 79,894 139,447 144,438
----------------------------------------------------------------------------
Expenses
Operating 18,388 19,481 38,900 32,898
Transportation 2,381 2,296 4,158 3,737
General and administrative 3,777 3,606 6,728 5,811
Bad debt provision - 661 - 661
Interest 4,232 4,095 5,941 7,633
Stock-based compensation (note 6) 1,950 1,890 3,952 3,148
Depreciation, depletion and
accretion 42,495 43,091 84,918 75,792
----------------------------------------------------------------------------
73,223 75,120 144,597 129,680
----------------------------------------------------------------------------
Earnings (loss) before income and
other taxes (9,507) 4,774 (5,150) 14,758
Future income tax expense (recovery) (2,195) 1,869 (470) 4,704
----------------------------------------------------------------------------
Net earnings (loss) (7,312) 2,905 (4,680) 10,054
Other comprehensive income
Amortization of fair value of
financial instruments - - - (17)
----------------------------------------------------------------------------
Comprehensive income (loss) (7,312) 2,905 (4,680) 10,037
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, beginning of
period 215,890 132,212 213,258 125,063
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings, end of period $ 208,578 $135,117 $208,578 $135,117
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per share - basic $ (0.09) $ 0.04 $ (0.06) $ 0.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per share - diluted $ (0.09) $ 0.04 $ (0.06) $ 0.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Statement of Cash Flows
Three months Six months
ended June 30, ended June 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
(unaudited)
Cash provided by (used in)
Operating Activities
Net earnings (loss) $ (7,312) $ 2,905 $ (4,680) $ 10,054
Items not requiring cash from
operations
Depreciation, depletion and
accretion 42,495 43,091 84,918 75,792
Stock-based compensation 1,313 1,025 3,354 2,030
Bad debt provision - 661 - 661
Unrealized loss on commodity
derivatives 7,478 40,031 15,320 49,775
Future income tax expense
(recovery) (2,195) 1,869 (470) 4,704
Asset retirement expenditures (614) (483) (1,189) (537)
Decrease (increase) in non-cash
working capital items (1,649) (21,646) 687 (39,860)
----------------------------------------------------------------------------
39,516 67,453 97,940 102,619
----------------------------------------------------------------------------
Financing Activities
Issue of share capital and warrants,
net of share issuance costs 801 4,260 801 89,074
Increase in long-term debt - - 20,898 184,867
Repayment of long-term debt (15,202) (51,267) - (303,538)
----------------------------------------------------------------------------
(14,401) (47,007) 21,699 (29,597)
----------------------------------------------------------------------------
Investing Activities
Oil and natural gas properties and
equipment (8,318) (16,478) (35,471) (41,716)
Transaction costs on Rider acquisition - - - (4,130)
Property acquisition (4) 265 (54,075) (22,798)
Deposit on property acquisition
(note 3) (18,084) - (18,084) -
Decrease (increase) in non-cash
working capital items 1,115 475 (12,148) 1,215
----------------------------------------------------------------------------
(25,291) (15,738) (119,778) (67,429)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents (176) 4,708 (139) 5,593
Cash and cash equivalents, beginning
of period 176 885 139 -
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ - $ 5,593 $ - $ 5,593
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
NUVISTA ENERGY LTD.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three and six months ended June 30, 2009.
The unaudited consolidated financial statements of NuVista Energy Ltd.
("Nuvista" or "the Company") have been prepared by management in accordance with
Canadian Generally Accepted Accounting Principles ("GAAP"), using the same
accounting policies as those set out in note 1 to the consolidated financial
statements for the year ended December 31, 2008, except as noted below in note
1. The consolidated financial statements for the three and six months ended June
30, 2009, should be read in conjunction with the annual audited consolidated
financial statements for the year ended December 31, 2008. Certain amounts have
been reclassified to conform with the current year's presentation. All tabular
amounts are in thousands, except per share amounts, unless otherwise stated.
1. Adoption of new accounting policies
Goodwill and intangible assets
Effective January 1, 2009, the Company adopted Section 3064, Goodwill and
Intangible Assets issued by the Canadian Institute of Chartered Accountants
("CICA"). Section 3064 establishes standards for the recognition, measurement,
presentation and disclosure of goodwill and intangible assets subsequent to its
initial recognition. This new section has no current impact on the Company's
consolidated financial statements.
2. Future accounting changes
International Financial Reporting Standards
In February 2008, the Canadian Accounting Standards Board confirmed January 1,
2011, as the effective date for the requirement to report under International
Financial Reporting Standards ("IFRS") with comparative 2010 periods converted
as well. Canadian GAAP as we currently know them, will cease to exist for all
public reporting entities.
In order to meet the requirement to transition to IFRS, the Company has
appointed internal staff to lead the conversion project along with sponsorship
from an executive steering committee. The Company involves external auditors and
external consultants, as required, during the conversion project. The Company
has provided training to key employees, completed a preliminary analysis of the
accounting differences and is monitoring the impact of the transition on its
business practices, information systems and internal control over financial
reporting. During the Company's preliminary analysis, accounting implementation
for certain areas was identified as having the greatest potential impact to the
Company's consolidated financial statements in terms of complexity and effort.
The Company has determined that accounting for property, plant and equipment,
impairment testing, asset retirement obligation, stock-based compensation and
income taxes will be impacted by the conversion to IFRS. In July 2009, the
International Accounting Standards Board issued amendments to IFRS 1 -
First-Time Adoption of International Financial Reporting Standards. This
amendment allows first-time adopters using full cost accounting to elect to
measure oil and gas assets at the date of transition to IFRS using amounts
determined based on the entity's previous GAAP. During the second quarter of
2009, the Company performed an analysis of IFRS in comparison with currently
applied accounting principles on the key areas previously identified as high
priority. The Company is currently analyzing the various accounting policy
choices available and will implement those determined to be the most
appropriate. The impact of IFRS on the Company's consolidated financial
statements is not reasonably determinable at this time.
3. Property acquisitions
(a) Ferrier, Sunchild, Wapiti and Northwest Saskatchewan properties
On January 29, 2009, the Company acquired certain natural gas properties and
related facilities in the Ferrier/Sunchild, Wapiti and northwest Saskatchewan
core areas. The purchase price was approximately $54.1 million, net of asset
retirement obligations. The acquisition was financed through bank borrowings.
The results of operations of these properties have been included in the
consolidated financial statements of the Company since the acquisition date.
(b) Northeast British Columbia and Northwest Alberta properties
On June 15, 2009, the Company entered into an agreement to acquire certain
properties in the Martin Creek area of northeast British Columbia and in
northwest Alberta for a purchase price of $174 million, net of asset retirement
obligations. A cash deposit of $18.0 million was paid as part of the
transaction. The acquisition closed on July 27, 2009. See subsequent events,
note 10.
4. 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 June 30, 2009, the estimated
total undiscounted amount of cash flows required to settle the Company's asset
retirement obligations is $225.8 million (2008 - $187.9 million), which will be
incurred over the next 51 years. The majority of the costs will be incurred
between 2010 and 2036. A credit-adjusted risk-free rate of 8% (2008 - 8%) and an
inflation rate of 2% (2008 - 2%) were used to calculate the fair value of the
asset retirement obligations.
A reconciliation of the asset retirement obligations is provided below:
June 30, 2009 December 31, 2008
---------------------------------------------------------------------------
Balance, beginning of period $ 46,296 $ 26,574
Accretion expense 1,923 3,026
Liabilities incurred 5,870 7,203
Liabilities acquired 1,328 8,505
Change in assumptions - 3,504
Liabilities settled (1,189) (2,516)
---------------------------------------------------------------------------
Balance, end of period $ 54,228 $ 46,296
---------------------------------------------------------------------------
---------------------------------------------------------------------------
5. Long-term debt
On April 3, 2009, the Company received an extension of the revolving credit
facility until April 29, 2010. The maximum borrowing amount of the credit
facility remains unchanged at $450.0 million (2008 - $450.0 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 request conversion to a one year term
loan. During the revolving period, a determination of the maximum borrowing
amount occurs semi-annually on or before April 30 and October 31. During the
term period, no principal payments would be required until April 29, 2011. As
such, this credit facility is classified as long-term. Cash paid for interest
expense for the three months ended June 30, 2009 was $3.9 million (2008 - $5.0
million) and for the six months ended June 30, 2009 was $5.5 million (2008 -
$7.2 million).
6. Shareholders' equity
(a) Share capital, warrants and contributed surplus
June 30, 2009 December 31, 2008
---------------------------------------------------------------------------
Share capital $ 588,506 $ 587,460
Warrants - 3,454
Contributed surplus 15,044 7,128
---------------------------------------------------------------------------
Total $ 603,550 $ 598,042
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(b) Authorized
Unlimited number of voting Common Shares and 1,200,000 Class B Performance
Shares. Common shares issued
June 30, 2009 December 31, 2008
Number Amount Number Amount
---------------------------------------------------------------------------
Balance, beginning of period 79,164 $ 587,460 52,704 $ 240,245
Issued for cash - - 6,000 80,546
Issued on Rider acquisition - - 19,844 256,195
Exercise of stock options 116 801 616 6,545
Stock-based compensation - 245 - 4,144
Cost associated with shares
issued, net of future tax
benefit of $nil (2008 - $84) - - - (215)
---------------------------------------------------------------------------
Balance, end of period 79,280 $ 588,506 79,164 $ 587,460
---------------------------------------------------------------------------
---------------------------------------------------------------------------
On March 4, 2008, the Company issued 6.0 million units of NuVista ("Unit") at a
price of $14.00 per Unit for gross proceeds of $84.0 million by way of a private
placement. Each Unit consisted of one common share and one-half of a warrant.
(c) Warrants
June 30, 2009 December 31, 2008
Number Amount Number Amount
---------------------------------------------------------------------------
Balance, beginning of period 3,000 $ 3,454 - $ -
Issued - - 3,000 3,454
Transferred to contributed surplus
on expiry (3,000) (3,454) - -
---------------------------------------------------------------------------
Balance, end of period - $ - 3,000 $ 3,454
---------------------------------------------------------------------------
---------------------------------------------------------------------------
At December 31, 2008, there were 3.0 million common share purchase warrants
outstanding. Each warrant entitled the holder thereof to acquire, subject to
adjustment, one common share for $15.50, prior to March 4, 2009. As of March 5,
2009, these warrants expired unexercised.
(d) Contributed surplus
June 30, 2009 December 31, 2008
---------------------------------------------------------------------------
Balance, beginning of period $ 7,128 $ 4,967
Stock-based compensation 4,707 6,305
Exercise of stock options (245) (4,144)
Expired warrants 3,454 -
---------------------------------------------------------------------------
Balance, end of period $ 15,044 $ 7,128
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(e) Per share amounts
During the three months ended June 30, 2009, there were 79,209,242 (2008 -
78,829,785) weighted average shares outstanding. On a diluted basis, there were
79,209,242 (2008 - 80,368,214) weighted average shares outstanding after giving
effect for dilutive stock options. For the six months ended June 30, 2009, there
were 79,187,032 (2008 - 69,753,816) weighted average shares outstanding and
79,187,032 (2008 - 70,752,811) weighted average shares outstanding on a dilutive
basis. The number of anti-dilutive options totaled 5,462,467 at June 30, 2009
(2008 - 221,209).
(f) 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. Options granted prior to December 2008 vest at the rate of 25% 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 33% 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:
June 30, 2009 December 31, 2008
--------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
---------------------------------------------------------------------------
Balance, beginning of period 6,111,945 $ 13.69 4,046,400 $ 13.46
Granted 747,036 10.78 3,263,260 13.64
Exercised (115,750) 6.92 (615,675) 10.63
Forfeited (375,400) 14.24 (508,715) 14.63
Expired (95,950) 12.46 (73,325) 17.64
---------------------------------------------------------------------------
Balance, end of period 6,271,881 $ 13.46 6,111,945 $ 13.69
---------------------------------------------------------------------------
---------------------------------------------------------------------------
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
six months ended June 30, 2009, was estimated on the date of grant using the
Black-Scholes option pricing model. In the pricing model, the risk-free interest
rate used was 2% (2008 - 4.5%); volatility of 52% (2008 - 33%); an average
expected life of 4.5 years (2008 - 4.5 years); an estimated forfeiture rate of
10% (2008 - 10%); and dividends of nil (2008 - nil). The weighted average fair
value of stock options granted during the six months ended June 30, 2009 was
$4.73 per option (2008 - $5.26 per option). For the six months ended June 30,
2009, the Company capitalized $1.4 million (2008 - $0.8 million) in stock based
compensation.
(g) Restricted stock units
In January 2008, the Board of Directors approved a Restricted Stock Unit ("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. The RSUs become payable as they vest over their lives, typically three
years.
For the six months ended June 30, 2009, the Company recorded an RSU stock-based
compensation expense of $0.1 million (2008 - $1.1 million) and capitalized $nil
(2008 - $0.3 million) to property, plant and equipment with a corresponding
offset recorded in compensation liability. The stock-based compensation expense
was based on the trading price of the Company's shares on June 30, 2009.
The following table summarizes the change in RSUs:
June 30, 2009 December 31, 2008
---------------------------------------------------------------------------
Number Number
---------------------------------------------------------------------------
Balance, beginning of period 351,543 -
Vested (103,974) -
Granted 90,769 390,163
Forfeited (14,720) (38,620)
---------------------------------------------------------------------------
Balance, end of period 323,618 351,543
---------------------------------------------------------------------------
---------------------------------------------------------------------------
The following table summarizes the change in compensation liability
relating to the RSUs:
June 30, 2009 December 31, 2008
Amount Amount
---------------------------------------------------------------------------
Balance, beginning of period $ 1,461 $ -
Change in accrued compensation liability 821 1,461
Cash payments (740) -
---------------------------------------------------------------------------
Balance, end of period $ 1,542 $ 1,461
---------------------------------------------------------------------------
Compensation liability - current (included
in accounts payable and accrued
liabilities) $ 1,268 $ 611
---------------------------------------------------------------------------
Compensation liability - long-term $ 274 $ 850
---------------------------------------------------------------------------
---------------------------------------------------------------------------
For the six months ended June 30, 2009, cash payments of $0.7 million (2008 -
$nil) were made relating to the RSU Incentive Plan.
7. Risk management activities
(a) Financial instruments
The Company's financial instruments recognized in the consolidated balance sheet
consists of cash and cash equivalents, accounts receivable, commodity derivative
contracts, accounts payable and accrued liabilities, and long-term debt. Unless
otherwise noted, carrying values reflect the current fair value of the Company's
financial instruments due to their short-term maturities. The estimated fair
values of recognized financial instruments have been determined based on the
Company's assessment of available market information and appropriate
methodologies, through comparisons to similar instruments, or third party
quotes.
As at June 30, 2009, the Company has entered into the following crude oil
contracts:
Volume Average Price (Cdn$/bbl) Term
---------------------------------------------------------------------------
1,000 bbls/d CDN. $64.00 - Bow River January 1, 2009 - December 31, 2009
1,000 bbls/d CDN. $95.01 - $110.01 - January 1, 2009 - December 31, 2009
WTI (1)
(1) This is a US$ denominated crude oil contract with an associated fixed
price
As at June 30, 2009, the mark-to-market value of the financial commodity
contracts was an asset of $1.2 million.
(b) Physical sale contracts
As at June 30, 2009, the Company has entered into direct natural gas sale
contracts as follows:
Volume Average Price (Cdn$/gj) Term
---------------------------------------------------------------------------
20,000 gj/d CDN. $7.45 - Fixed Price April 1, 2009 - October 31, 2009
AECO
5,000 gj/d CDN. $5.65 - AECO Floor April 1, 2009 - October 31, 2009
(1),(4)
20,000 gj/d CDN. $5.97- $6.56 AECO November 1, 2009 - October 31, 2010
(2),(4)
20,000 gj/d CDN. $5.55 - AECO Floor November 1, 2009 - March 31, 2010
(3),(4)
(1) The AECO put was purchased at a deferred cost of $0.82/gj for a total
cost of $0.9 million.
(2) The deferred cost associated with the funded collar was $0.30/gj for a
total cost of $2.2 million.
(3) The AECO put was purchased at a deferred cost of $0.97/gj for a total
cost of $2.9 million.
(4) The deferred costs are incurred monthly over the term of the contract
and will be offset against revenues.
These physical sale contracts are normal purchase and sale transactions and as
such are not considered derivative financial instruments.
8. Relationship with Bonavista Petroleum Ltd.
In 2003, as part of the Plan of Arrangement with Bonavista Petroleum Ltd.
("Bonavista"), NuVista entered into a Technical Services Agreement ("TSA") with
Bonavista for the provision of certain services to NuVista. On August 31, 2007,
the TSA was terminated and replaced with a new services agreement that reflected
the remaining ongoing services that will be provided by Bonavista. On November
1, 2008, this services agreement was terminated and Bonavista no longer provides
any ongoing services to NuVista.
NuVista and Bonavista are considered related as two directors of NuVista, one of
whom is NuVista's chairman, are also directors and officers of Bonavista and a
director and an officer of NuVista are also officers of Bonavista. For the three
months ended June 30, 2009, NuVista paid Bonavista $ nil (2008 - $0.4 million)
in fees relating to general and administrative services provided by Bonavista.
In 2009, NuVista charged Bonavista management fees for jointly owned
partnerships totalling $0.3 million (2008 - $0.3 million). In addition, during
the second quarter of 2009, Bonavista charged NuVista $56,000 (2008 - $63,000)
for costs that are outside of the new services agreement relating to NuVista's
share of direct charges from third parties.
For the six months ended June 30, 2009, NuVista paid Bonavista $nil (2008 - $0.8
million) in fees relating to general and administrative services provided by
Bonavista, and NuVista charged Bonavista management fees for jointly owned
partnerships totaling $0.6 million (2008 - $0.6 million). In addition, Bonavista
charged NuVista $76,000 (2008 - $72,000) for costs that are outside of the new
services agreement relating to NuVista's share of direct charges from third
parties. As at June 30, 2009, the amount receivable from Bonavista was $0.2
million (2008 - $2.9 million).
The above 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 the parties.
9. Commitments
The following is a summary of the Company's contractual obligations and
commitments as at June 30, 2009:
Total 2009 2010 2011 2012 Thereafter
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Transportation $ 13,817 $2,426 $3,368 $ 2,668 $2,004 $ 3,351
Office lease 6,849 1,027 2,055 2,055 1,712 -
Physical sale contract
premiums 5,620 2,050 3,570 - - -
Physical power contract 6,900 - - 2,300 2,300 2,300
Long-term debt 376,305 - - 376,305 - -
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Total commitments $409,491 $5,503 $8,993 $383,328 $6,016 $ 5,651
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10. Subsequent events
(a) Property acquisition and equity financing
On July 27, 2009, the Company completed the acquisition of certain properties in
the Martin Creek area of Northeast British Columbia and in Northwest Alberta for
a purchase price of $174 million, net of asset retirement obligations. The
acquisition was financed through a combination of bank debt and the net proceeds
from two equity offerings. The Company entered into an agreement to issue
7,500,000 subscription receipts at a price of $11.00 per subscription receipt on
a bought deal basis for gross proceeds of $82.5 million. In addition, the
Company issued 1,500,000 subscription receipts at a price of $11.00 per
subscription receipt, by way of a private placement to Ontario Teachers' Pension
Plan 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.
(b) Long-term debt
On July 27, 2009, the Company's credit facility was increased to a maximum
borrowing amount of $510.0 million. Terms and conditions remain the same as
disclosed in note 5, long-term debt.
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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
Craig W. Stewart, RMP Energy Ltd.
Alex G. Verge, President and CEO
Clayton H. Woitas, Range Royalty Management Ltd.
Grant A. Zawalsky, Burnet, Duckworth & Palmer LLP
Officers
Keith A. MacPhail, Chairman
Alex G. Verge, President and CEO
Robert F. Froese, Vice President, Finance and CFO
Ross L. Andreachuk, Vice President and Controller
Kevin J. Christie, Vice President, Exploration
Steven J. Dalman, Vice President, Business Development
D. Chris McDavid, Vice President, Operations
Daniel B. McKinnon, Vice President, Engineering
Joshua T. Truba, Vice President, Land
Glenn A. Hamilton, Corporate Secretary
Auditors Legal Counsel
KPMG LLP Burnet, Duckworth & Palmer LLP
Chartered Accountants Calgary, Alberta
Calgary, Alberta
Bankers Registrar and Transfer Agent
Canadian Imperial Bank of Commerce Valiant Trust Company
Bank of Montreal Calgary, Alberta
Royal Bank of Canada
Toronto Dominion Bank
Bank of Nova Scotia
Alberta Treasury Branches
Union Bank of California, Canada Branch
Engineering Consultants Stock Exchange Listing
GLJ Petroleum Consultants Ltd. Toronto Stock Exchange
Calgary, Alberta Trading Symbol "NVA"
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