NAL Energy Corporation ("NAL" or the "Corporation") (TSX:NAE) today announced
its financial and operational results for the first quarter of 2011. All amounts
are in Canadian dollars unless otherwise stated.
2011 YEAR TO DATE ACTIVITY
- Executed NAL's largest drilling program to date, with 52 (29 net) wells
drilled of which 24 were Mississippian oil wells in SE Saskatchewan, 26 were in
Alberta and two were Doig wells at Fireweed in NE British Columbia. Total
capital expenditures were $83 million with $69 million directed to drilling,
completion and tie-in activity, a 23 percent increase over a year ago;
- NAL's 12 well Cardium program at Garrington continues to deliver positive
results. Recent changes to completion techniques that utilize water based fracs
and increased frac density appear to be improving initial production
performance;
- In the Hoffer area of SE Saskatchewan, NAL has successfully expanded the
Ratcliffe play with new discoveries in the Beaubier, Neptune and Oungre blocks.
The majority of drilling was centered on the greater Hoffer area with 13 of 24
wells drilled in this emerging Mississippian play;
- NAL's liquids rich natural gas programs included a significant Wilrich well in
the Edson area which had a stabilized test rate of approximately 1,400 boe/d
with production expected to commence in July, 2011. At Fireweed in NE B.C., NAL
successfully drilled two high impact Doig horizontal wells that tested at rates
of 1,475 boe/d and 1,600 boe/d. Production from these two wells will be rate
limited by facility capacity but should hold production at Fireweed flat for
several months at 2,500 - 3,000 boe/d. The wells will be tied-in after break
up;
- Production volumes of 28,024 boe/d in the quarter were impacted by higher than
anticipated decline in certain properties and uncontrollable factors related to
timing and delay caused by third party facility outages, access to equipment and
frac services and extreme weather. NAL currently has approximately 3,500 boe/d
ready for tie-in post spring break-up and expects production to average over
30,000 boe/d in Q3 and Q4;
- The Corporation had its credit facility review in April and the facility has
been renewed at $550 million of which $295 million remains available to the
Corporation as at March 31, 2011
-Successfully completed the transition to International Financial Reporting
Standards ("IFRS"). The implementation of IFRS has not had an impact on the
Corporation's operations and strategic decisions.
UPDATED 2011 GUIDANCE
First quarter 2011 production of 28,024 boe/d was internally forecast to be
29,000 - 29,500 boe/d based on declines from new horizontal wells coming off
high initial production rates in Q4, 2010. The 2011 drilling program commenced
in January, as planned, and our internal forecast assumed new volumes would
offset declines by the end of the second quarter. However, tie-ins of new
production from first quarter drills have been impacted by extreme weather, road
bans and frac services which delayed the program by approximately three months.
Additional unforecasted down time and restrictions through third party
facilities (Kaybob - Sem/Cams and Spectra McMahon) are also contributing to this
short fall.
Second quarter 2011 production is expected to be impacted by a total of 2,000 -
2,500 boe/d through continued down time, delay and facility outages. Severe wet
weather in southeast Saskatchewan is causing down time, and in extreme cases,
shutting down entire fields where single well battery leases are under water
making truck access impossible during periods in April and May.
As shown in the table entitled "Currently Drilled and Tested Wells Awaiting
Tie-in", significant production (estimated at 3,500 boe/d) is behind pipe
waiting for ground conditions to improve allowing tie-ins to be completed,
pipelines to be built and single well batteries to come on stream. Adding these
volumes is expected to increase second half 2011 production as shown in the
Production Forecast table below.
CURRENTLY DRILLED AND TESTED WELLS AWAITING TIE-IN
Forecast
Working
Interest
Production
Estimated on (Average first
Wells Stream Date month boe/d)
----------------------------------------------------------------------------
Crude Oil
----------
8 Cardium wells in Garrington May - July 1,000
5 wells in Hoffer/Oungre/Beaubier July 200
14-36-35-7W5M (Caroline - Viking) June 1 300
Liquids Rich Gas
-----------------
13-07-56-19W5M (Wilrich - Edson) June 15 - facility
restricted 500
b-96-I / 94-A-12 (Doig - Fireweed) July - facility
restricted 500
d-94-I / 94-A-12 (Doig - Fireweed) July - facility
restricted 500
4-11-43-4W5M (Glauc.- Wilson Ck) July 1 Non Op 500
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Total 3,500e
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2011 PRODUCTION FORECAST RANGES BY QUARTER (BOE/D)
Q1 Q2 Q3 Q4 Full Year
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28,024
(actual) 26,800 - 27,600 29,500 - 30,500 30,300 - 31,300 28,500 - 29,500
----------------------------------------------------------------------------
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NAL's revised 2011 guidance is currently 28,500 - 29,500 boe/d, an adjustment of
-1,200 boe/d, from our January, 2011 guidance. Capital and operating cost
guidance remains unchanged.
UPDATED 2011 GUIDANCE
May 2011 January 2011
Guidance Guidance
----------------------------------------------------------------------------
Production (boe/d) 28,500 - 29,500 29,700 - 30,700
Net capital expenditures ($MM) 200 - 230 200 - 230
Operating costs ($/boe) 10.50-10.90 10.50 - 10.90
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OUTLOOK
- In the first quarter, NAL completed its most active drilling program to date
and remains on track to complete the planned 139 well drilling program for 2011.
The focus of drilling continues to be balanced between the Corporation's
significant light oil resources in southeast Saskatchewan and central Alberta;
- As a result of success in the first quarter capital program, the Corporation
currently forecasts production to exit the year above 30,000 boe/d;
- Given NAL's broad opportunities and financial flexibility Management is
evaluating the potential for an increase in the capital program in the fourth
quarter depending on market conditions. The Corporation's balance sheet provides
flexibility to pursue internally generated opportunities or acquisition
opportunities with approximately $295 million in available credit lines;
- NAL has commitments on approximately $30 million of a $40 million target in
non-core divestments as at May 15, with the balance expected to be completed in
the last half of the year;
- NAL continues to possess a strong inventory of over 1,300 risked drilling
locations and an extensive land base to sustain activity in future years in each
of its core Cardium oil, Mississippian oil and liquids rich gas resources of
Alberta, SE Saskatchewan and NE British Columbia;
- The Board of Directors reviews its dividend policy quarterly based upon
corporate and market conditions. Currently, the Corporation has no plans to
change the monthly dividend of $0.07 per share.
FORWARD-LOOKING INFORMATION
Please refer to the disclaimer on forward-looking information set forth under
the Management's Discussion and Analysis in this document. The disclaimer is
applicable to all forward-looking information in this document, including the
2011 full year guidance set forth above.
CHANGES IN ACCOUNTING POLICIES
NAL adopted IFRS for financial reporting purposes, using a transition date of
January 1, 2010.
NON-IFRS MEASURES
Please refer to the discussion of non-IFRS measures set forth under the
Management's Discussion and Analysis regarding the use of the following terms:
"funds from operations", "payout ratio" and "operating netbacks".
NOTE
When converting natural gas to barrels of oil equivalent (boe) within this press
release, NAL uses the widely recognized standard of six thousand cubic feet
(Mcf) to one barrel of oil. However, boes may be misleading, particularly if
used in isolation. A conversion ratio of 6 Mcf:1 boe is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended
(thousands of dollars, except per share and boe data)
(unaudited)
March 31, March 31, December 31,
2011 2010 2010
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FINANCIAL
Revenue(1) $121,752 $136,883 $116,888
Cash flow from operating activities 60,983 68,248 72,152
Cash flow per share - basic 0.41 0.50 0.49
Cash flow per share - diluted 0.40 0.47 0.47
Funds from operations 62,997 79,481 67,645
Funds from operations per share
- basic 0.43 0.58 0.46
Funds from operations per share
- diluted 0.41 0.55 0.44
Net income (loss) (1,510) 50,169 (22,017)
Dividends declared 31,001 37,185 39,702
Dividends per share 0.21 0.27 0.27
Basic payout ratio:
based on cash flow from operating
activities 51% 54% 55%
based on funds from operations 49% 47% 59%
Basic payout ratio including capital
expenditures:
based on cash flow from operating
activities 186% 169% 90%
based on funds from operations 180% 145% 96%
Basic payout ratio including
capital expenditures and proceeds
from disposition:
based on cash flow from operating
activities 142% 148% 80%
based on funds from operations 137% 127% 86%
Shares outstanding (000's)
Period end 147,781 137,881 147,248
Weighted average 147,534 137,660 146,948
Capital expenditures(2) 82,587 78,298 25,524
Property acquisitions
(dispositions), net(3) (26,107) (13,191) 15,963
Corporate acquisitions, net(4) - 309 -
Net debt, excluding convertible
debentures(5) 334,003 308,455 310,302
Convertible debentures (at face
value) 194,744 194,744 194,744
OPERATING
Daily production prior to
Reorganization(6)
Crude oil (bbl/d) 10,411 11,788 11,469
Natural gas (Mcf/d) 89,581 93,328 93,314
Natural gas liquids (bbl/d) 2,683 2,777 2,635
Oil equivalent (boe/d) 28,024 30,120 29,657
Daily production after
Reorganization (6)(7) 28,024 29,819 28,596
OPERATING NETBACK ($/boe)
Revenue before hedging gains
(losses) 48.27 50.49 44.43
Royalties (7.85) (8.34) (7.53)
Operating costs (10.81) (10.35) (9.72)
Other income 0.11 0.16 0.20
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Operating netback before hedging 29.72 31.96 27.38
Hedging gains (losses) (0.34) 0.63 2.49
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Operating netback 29.38 32.59 29.87
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(1) Oil, natural gas and liquid sales less transportation costs and prior
to royalties and hedging.
(2) Excludes corporate acquisitions, and is net of drilling incentive
credits of $2.7 million for the quarter ended March 31, 2011 (March 31,
2010 - $2.4 million)
(3) Represents costs to acquire properties less proceeds from dispositions.
(4) Represents total consideration for corporate acquisitions including
fees.
(5) Bank debt plus working capital and other liabilities, excluding
derivative contracts, notes payable and deferred income tax balances.
(6) Production prior to conversion includes 100 percent of the volumes
attributable to a jointly held partnership with Manulife Financial
Corporation, see MD&A disclosure for details; all volumes include
royalty interest volumes.
(7) Excludes 50 percent of volumes attributable to a jointly held
partnership of NAL and Manulife dissolved as part of the Reorganization
for 2010, see MD&A.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in conjunction
with the interim unaudited consolidated financial statements for the three
months ended March 31, 2011 and the audited consolidated financial statements
and MD&A for the year ended December 31, 2010 of NAL Energy Corporation ("NAL"
or the "Corporation"). It contains information and opinions on the Corporation's
future outlook based on currently available information. All amounts are
reported in Canadian dollars, unless otherwise stated. Where applicable, natural
gas has been converted to barrels of oil equivalent ("boe") based on a ratio of
six thousand cubic feet of natural gas to one barrel of oil. The boe rate is
based on an energy equivalent conversion method primarily applicable at the
burner tip and does not represent a value equivalent at the wellhead. Use of boe
in isolation may be misleading.
Unless otherwise specifically stated, all financial information included and
incorporated by reference in this MD&A is determined, for all periods prior to
January 1, 2010, using Canadian generally accepted accounting principles in
effect prior to January 1, 2010 and, for all periods beginning on and after
January 1, 2010, using International Financing Reporting Standards as adopted by
the Canadian Accounting Standards Board ("IFRS").
NAL is engaged in the exploration for, and the development and production of
natural gas, natural gas liquids and crude oil in Western Canada. The
Corporation resulted from a reorganization effective December 31, 2010 as part
of the Plan of Arrangement involving, among others, NAL Oil & Gas Trust (the
"Trust"), the Corporation, and the security holders of the Trust (the
"Reorganization").
Pursuant to the Reorganization, the Trust was restructured from an open-end
unincorporated trust to NAL Energy Corporation, a publicly traded exploration
and development corporation. Unitholders of the Trust received one common share
of the Corporation for each trust unit held. The Corporation and its
subsidiaries now carry on the business formerly carried on by the Trust and its
subsidiaries.
The Reorganization to a corporation has been accounted for on a continuity of
interest basis and accordingly, the consolidated financial statements for 2010
reflect the financial position, results of operations and cash flows as if the
Corporation had carried on the business formerly carried on by the Trust.
References to NAL or the Corporation in this MD&A for periods prior to December
31, 2010 are references to the Trust and for periods after December 30, 2010 are
references to NAL Energy Corporation. Additionally, NAL or the Corporation
refers to shares, shareholders, and dividends which are comparable to units,
unitholders and distributions previously under the Trust.
CHANGES IN ACCOUNTING POLICIES
On January 1, 2011, NAL adopted IFRS for financial reporting purposes, using a
transition date of January 1, 2010. The financial statements for the three
months ended March 31, 2011, including required comparative information, have
been prepared in accordance with International Financial Reporting Standards 1,
First-time Adoption of International Financial Reporting Standards, and with
International Accounting Standard ("IAS") 34, Interim Financial Reporting, as
issued by the International Accounting Standards Board ("IASB"). Previously, the
Corporation prepared its interim and annual consolidated financial statements in
accordance with Canadian generally accepted accounting principles ("previous
CGAAP" or "CGAAP"). Unless otherwise noted, 2010 comparative information has
been prepared in accordance with IFRS.
The adoption of IFRS has not had an impact on the Corporation's operations and
strategic decisions. The most significant area of impact was to property, plant
and equipment. Further information on the IFRS impacts is provided in the
Accounting Policies of this MD&A, including reconciliations between previous
CGAAP and IFRS Net Income, funds from operations and other financial metrics.
NON-IFRS FINANCIAL MEASURES
Throughout this MD&A, Management uses the terms funds from operations, funds
from operations per share, payout ratio, cash flow from operations per share,
net debt to trailing 12 month cash flow, operating netback and cash flow
netback. These are considered useful supplemental measures as they provide an
indication of the results generated by the Corporation's principal business
activities. Management uses the terms to facilitate the understanding of the
results of its operations. However, these terms do not have any standardized
meaning as prescribed by Canadian Generally Accepted Accounting Principles for
publicly accountable enterprises, being IFRS. Investors should be cautioned that
these measures should not be construed as an alternative to net income
determined in accordance with IFRS as an indication of NAL's performance. NAL's
method of calculating these measures may differ from other income funds and
companies and, accordingly, they may not be comparable to measures used by other
income funds and companies.
Funds from operations is calculated as cash flow from operating activities
before changes in non-cash working capital. Funds from operations does not
represent operating cash flows or operating profits for the period and should
not be viewed as an alternative to cash flow from operating activities
calculated in accordance with IFRS. Funds from operations is considered by
Management to be a more meaningful key performance indicator of NAL's ability to
generate cash to finance operations and to pay monthly dividends. Funds from
operations per share and cash flow from operations per share are calculated
using the weighted average shares outstanding for the period.
Payout ratio is calculated as dividends declared for a period as a percentage of
either cash flow from operating activities or funds from operations; both
measures are stated.
Net debt to trailing 12 months cash flow is calculated as net debt as a
proportion of funds from operations for the previous 12 months. Net debt is
defined as bank debt, plus convertible debentures at face value, plus working
capital and other liabilities, excluding derivative contracts, notes
payable/receivable and deferred income tax balances.
The following table reconciles cash flows from operating activities to funds
from operations:
Three months ended March 31
------------------------------
$(000s) 2011 2010
----------------------------------------------------------------------------
Cash flow from operating activities $60,983 $68,248
Add back change in non-cash working capital 2,014 11,233
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Funds from operations $62,997 $79,481
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FORWARD-LOOKING INFORMATION
This MD&A contains forward-looking information as to the Corporation's internal
projections, expectations and beliefs relating to future events or future
performance. Forward looking information is typically identified by words such
as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will",
"could", "plan", "intend", "should", "believe", "outlook", "project",
"potential", "target", and similar words suggesting future events or future
performance. In addition, statements relating to "reserves" are forward-looking
statements as they involve the implied assessment, based on certain estimates
and assumptions, that the reserves described exist in the quantities estimated
and can be profitably produced in the future.
In particular, this MD&A contains forward-looking information pertaining to the
following, without limitation: the amount and timing of cash flows and dividends
to shareholders; reserves and reserves values; 2011 production; future tax
treatment of the Corporation; the Corporation's tax pools; future oil and gas
prices; operating, drilling and completion costs; the amount of future asset
retirement obligations; future liquidity and future financial capacity; the
initiation of an "at-the-market" financing program; future results from
operations; payout ratios; cost estimates and royalty rates; drilling plans;
tie-in of wells; future development, exploration, and acquisition and
development activities and related expenditures; and rates of return.
With respect to forward-looking statements contained in this MD&A and the press
release through which it was disseminated, we have made assumptions regarding,
among other things: future oil and natural gas prices; future capital
expenditure levels; future oil and natural gas production levels; future
exchange rates; the amount of future cash dividends that we intend to pay; the
cost of expanding our property holdings; our ability to obtain equipment in a
timely manner to carry out exploration and development activities; our ability
to market our oil and natural gas successfully to current and new customers; the
impact of increasing competition; our ability to obtain financing on acceptable
terms; and our ability to add production and reserves through our development
and exploitation activities.
Although NAL believes that the expectations reflected in the forward-looking
information contained in the MD&A and the press release through which it was
disseminated, and the assumptions on which such forward-looking information are
made, are reasonable, readers are cautioned not to place undue reliance on such
forward looking statements as there can be no assurance that the plans,
intentions or expectations upon which the forward-looking information are based
will occur. Such information involves known and unknown risks, uncertainties and
other factors that may cause actual results or events to differ materially from
those anticipated and which may cause NAL's actual performance and financial
results in future periods to differ materially from any estimates or projections
of future performance. These risks and uncertainties include, without
limitation: changes in commodity prices; unanticipated operating results or
production declines; the impact of weather conditions on seasonal demand and
NAL's ability to execute its capital program; risks inherent in oil and gas
operations; the imprecision of reserve estimates; limited, unfavorable or no
access to capital or credit markets; the impact of competitors; the lack of
availability of qualified operating or management personnel; the inability to
obtain industry partner and other third party consents and approvals, when
required; failure to realize the anticipated benefits of acquisitions; general
economic conditions in Canada, the United States and globally; fluctuations in
foreign exchange or interest rates; changes in government regulation of the oil
and gas industry, including environmental regulation; changes in royalty rates;
changes in tax laws; stock market volatility and market valuations; OPEC's
ability to control production and balance global supply and demand for crude oil
at desired price levels; political uncertainty, including the risk of
hostilities in the petroleum producing regions of the world; and other risk
factors discussed in other public filings of the Corporation including the
Corporation's current Annual Information Form.
NAL cautions that the foregoing list of factors that may affect future results
is not exhaustive. The forward-looking information contained in this MD&A is
made as of the date of this MD&A. The forward-looking information contained in
this MD&A is expressly qualified by this cautionary statement.
STRUCTURE OF THE BUSINESS
On December 31, 2010, NAL Oil & Gas Trust completed a plan of arrangement
whereby the Trust unitholders exchanged their trust units for common shares of
NAL Energy Corporation on a one-to-one basis thereby effectively converting the
Trust into a corporation ("Reorganization"). As a result of the Reorganization,
the Trust was dissolved and NAL Energy Corporation received all the assets and
assumed all the liabilities of the Trust.
In conjunction with the Reorganization, a partnership ("Partnership") that was
indirectly owned jointly by the Corporation and Manulife Financial Corporation
("MFC") was dissolved on December 31, 2010. This Partnership held the assets
acquired from the acquisitions of Tiberius and Spear in February 2008.
Prior to December 31, 2010 the Corporation, by virtue of being the owner of the
general partner of the Partnership, was required to consolidate the results of
the Partnership into its financial statements on the basis that the Corporation
had control over the Partnership. The March 31, 2010 MD&A and financial
information of the Corporation therefore reflects all the assets, liabilities,
revenues and expenses of the Partnership, of which 50 percent are effectively
removed through the minority interest. As a result of the Partnership
dissolution on December 31, 2010, the Corporation only reflects its
proportionate share of the Partnership's assets, liabilities, revenues and
expenses in the March 31, 2011 MD&A and financial information.
NAL's conversion from a trust to a corporation had no effect on its strategic or
operational objectives.
EXPLORATION & DEVELOPMENT ACTIVITIES
The Corporation spent $68.8 million on drilling, completion and tie-in
operations during the first quarter of 2011 compared to $56.0 million during the
first quarter of 2010. There were 52 (29.3 net) wells drilled in the first
quarter compared to 48 (21.1 net) wells during the same period in 2010 which is
consistent with an expanded capital program year-over-year. Operations were
conducted across NAL's operations with 24 wells drilled in Saskatchewan, two in
British Columbia and 26 in Alberta.
The Corporation participated in 49 (28 net) horizontal wells with 85 percent of
the activity focused on oil projects across Saskatchewan and Alberta. The
Corporation will continue to focus on horizontal oil drilling for the remainder
of the year with significant programs in the Cardium drilling 18 (12 net)
additional wells and in the Mississippian throughout southeast Saskatchewan
drilling 35 (16 net) wells.
First Quarter Drilling Activity
Dry &
Crude Oil Natural Gas Service Wells Abandoned Total
----------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 41 24 6 4.4 0 0 0 0 47 28.4
Non-operated wells 2 0.1 2 0.3 0 0 1 0.5 5 0.9
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Total wells drilled 43 24.1 8 4.7 0 0 1 0.5 52 29.3
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Southeast Saskatchewan
In Saskatchewan, there were 24 (11.6 net) horizontal oil wells drilled during
the first quarter with activity focused on the Mississippian in the greater
Hoffer area (13), Steelman (2), Alida (2), Bryant (3), Hardy (1) and overall
results are meeting internal expectations.
Extreme cold weather and high winter storm frequency translated into 12 lost
drilling days and five fewer wells being drilled than planned in the quarter.
Greater than normal snowfall has also amplified the impact of break up as very
wet conditions have shut in many new areas where trucking from single well oil
batteries is restricted and has curtailed production. This limited access has
delayed new well tie-ins toward the end of the second quarter. NAL expects to
have its base production back to full capacity in June.
New wells in Beaubier and Oungreare currently producing at initial production
rates of 150 boe/d (50 percent WI), confirming additional accumulations in the
Ratcliffe and Oungre directly offsetting Hoffer. Construction on a central
battery at Hoffer is now expected to commence in the summer with facility start
up scheduled by year end. The first Hardy Bakken drill at 13-32-5-21W2 is
awaiting stimulation and tie-in which was delayed at the end of the quarter and
is now scheduled for the end of June.
Drilling operations are expected to resume in June with four rigs drilling 35
gross wells (17.5 net) over the balance of the year.
Alberta
In Alberta, NAL participated in drilling 26 (15.7 net) locations including 12 (7
net) Cardium wells, eight (5.5 net) oil wells in Millard Lake, Irricana and
Hussar and five (2.1 net) gas wells. Generally, equipment was available and
NAL's drilling programs were executed as planned with some delay, especially in
completion and tie-in activities.
NAL management continues to be encouraged by the performance of its Cardium
programs and in aggregate, results continue to be in line with our internal type
curve. Of the 12 Cardium wells drilled in the quarter, four are on stream, three
wells are tied in recovering load fluid and waiting on infrastructure capacity,
three wells are waiting on completion and two wells are waiting on tie-in with
all remaining activities to be completed by the end of the second quarter. The
Corporation has changed its completion process executing water-based fracs
instead of oil in eight Cardium wells, using higher density 75 meter inter-frac
spacing (14-18 stages per well) and lower (10-15)tonnes per stage. The
2-21-34-4W5M Cardium well came on production in early May with current
production of over 500 boe/d (60 percent WI),which is above the Corporation's
type curve. It is expected that an increased density of fracs will have a
positive impact on reserves and initial production rates. NAL expects cost
savings from using water versus oil based fracs will be offset by an increase in
stages pumped and general cost escalation due to increased activity.
NAL has successfully drilled two (1.2 net) horizontal Viking oil wells at
Caroline as part of a program to test the significant potential of the Viking on
the Corporation's extensive land base in central Alberta. The first well
14-36-35-07W5M was completed with limited frac placement due to extremely high
treating pressures but subsequently tested at greater than 1,000 boe/d.
Production is expected to be on stream by June 1st and the Corporation will
continue to assess performance as there is no analogous horizontal production in
the area. The second well will be completed in the third quarter.
Infill oil drilling in Millard Lake, Hussar and Irricana has added 250 boe/d of
production from four (3.4 net) wells.
The Corporation's liquids rich gas projects in the Edson area continue to drive
strong capital efficiencies. In the quarter there were two (1.1 net) gas wells
drilled and completed including the 13-07-56-19W5M (70 percent WI) Wilrich well
which had a test rate of 1,400 boe/d (7.8 mmcf/d + 15 bbl/mmcf of free
condensate) at 700 psi flowing wellhead pressure. Line looping and compression
projects are coming on stream in the area in June and will increase Wilrich
production from NAL's four wells, including 13-07, from 11 to 15 mmcf/d with
well deliverability expected to hold production flat for several months. NAL
also drilled a development Bluesky gas well at 1-32-54-17W5M which is tied in
and flowed at 2 mmcf/d initial production.
The Corporation is planning 18 (12 net) Cardium wells for the remainder of the
year with 12 in the greater Garrington area and six wells at Lochend/North
Cochrane following up on successful operated and industry activity. Drilling is
expected to commence in June.
Northeast British Columbia
There were two wells drilled in Fireweed (100 percent WI) during the first
quarter. Access to frac services in this region proved challenging and the on
stream forecast for these wells was delayed three months from original plans.
The Doig horizontal b-96-I/94-A-12 was tested at final clean up rates of 1,600
boe/d (5 mmcf/d + 150 bbls/mmcf of free condensate) at a flowing tubing pressure
of 500 psi and is expected to be on stream by June 1st. A second well at
d-94-I/94-A-12 was tested at final clean up rates of 1,475 boe/d (6 mmcf/d + 80
bbls/mmcf of free condensate) at a flowing tubing pressure of 600 psi and has
commenced production in May. Production from these two wells will be rate
limited by facility capacity but should hold production flat for several months
at 2,500 - 3,000 boe/d.
CAPITAL EXPENDITURES
Capital expenditures, before property acquisitions and dispositions, for the
quarter ended March 31, 2011 totaled $82.6 million compared with $78.3 million
for the quarter ended March 31, 2010. The year-over-year increase is tied to the
corresponding increase in wells drilled as well as a continued shift towards
horizontal drilling and multi stage frac completions which significantly
increases per well costs. Spending was slightly below expectations ($6 million)
as some drilling and completions late in the quarter were delayed and subsequent
tie-ins were moved into the second and third quarter. First quarter land and
seismic expenditures of $11.3 million represent a combination of Crown and
private land purchases in and around established core areas and proprietary 3D
seismic to help delineate play concepts on significant land blocks acquired in
2010.
Capital Expenditures ($000s)
Three months ended March 31
------------------------------
2011 2010
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Drilling, completion and production equipment 68,793 55,993
Plant and facilities 2,121 427
Seismic 4,536 1,660
Land 6,719 19,931
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Total exploitation and development 82,169 78,011
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Office equipment 418 287
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Total capitalized expenditures before acquisitions 82,587 78,298
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Property acquisitions 983 1,485
Proceeds on disposition (27,090) (14,676)
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Total property acquisitions (dispositions), net (26,107) (13,191)
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Total capitalized expenditures 56,480 65,107
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PRODUCTION
First quarter 2011 production of 28,024 boe/d was six percent below production
of 29,819 boe/d in the comparable period of 2010. One of the primary
contributing factors to this year-over-year decline is that the first quarter of
2010 contained significant peak flush production from high impact horizontal
wells at Irricana and Fireweed from the recently completed Breaker acquisition.
Flush production was forecast to decline at rates of 70 percent through the
remainder of 2010. Consequently, the first quarter of 2011 was negatively
impacted higher than anticipated declines but the production profile on whole,
is consistent with a typical front end loaded capital program where production
peaks in the fourth quarter and is in decline during the first quarter. NAL also
completed approximately 650 boe/d of dispositions in the first quarter of 2011
that impacts year-over-year performance.
Average Daily Production Volumes
Three months ended March 31
------------------------------
2011 2010
----------------------------------------------------------------------------
Oil (bbl/d) 10,411 11,788
Natural gas (Mcf/d) 89,581 93,328
NGLs (bbl/d) 2,683 2,777
----------------------------------------------------------------------------
Oil equivalent (boe/d) 28,024 30,120
Less 50% of oil equivalent production relating to
the non-controlling interest (boe/d)(1) - (301)
----------------------------------------------------------------------------
Oil equivalent (boe/d) 28,024 29,819
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) See Structure of the Business
For the quarter ended March 31, 2011, oil and natural gas liquids production
represented 47 percent of total production volume with natural gas representing
53 percent of total production volume.
Production Weighting
Three months ended March 31
------------------------------
2011 2010
----------------------------------------------------------------------------
Oil 37% 39%
Natural gas 53% 52%
NGLs 10% 9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales, after
transportation costs and prior to hedging, totaled $121.8 million for the three
months ended March 31, 2011, 11 percent lower than the first quarter of 2010.
The decrease is due to a six percent decrease in production and a four percent
decrease in the average realized price per boe, driven by a 27 percent decrease
in the realized natural gas price offset by an eight percent increase in the
realized crude oil price and a 12 percent increase in the realized price for
natural gas liquids.
Revenue
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Revenue(1) ($000s)
Oil 77,007 81,085
Gas 29,692 42,064
NGLs 14,878 13,752
Sulphur 175 (18)
----------------------------------------------------------------------------
Total revenue 121,752 136,883
$/boe 48.27 50.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties and hedging.
OIL MARKETING
NAL markets its crude oil based on refiners' posted prices at Edmonton, Alberta
and Cromer, Manitoba adjusted for transportation and the quality of crude oil at
each field battery. The refiners' posted prices are influenced by the WTI
benchmark price, transportation costs, exchange rates and the supply/demand
situation of particular crude oil quality streams during the year.
NAL's first quarter average realized Canadian crude oil price per barrel, net of
transportation costs excluding hedging, was $82.19, as compared to $76.43 for
the comparable quarter of 2010. The increase in realized price
quarter-over-quarter of eight percent, or $5.76/bbl, was primarily driven by a
20 percent increase in the WTI price (U.S.$/bbl) over the comparable period,
partially offset by a five percent increase in the value of the Canadian dollar.
For the first quarter of 2011, NAL's crude oil price differential was 89
percent, a decrease of four percentage points from the comparable period in
2010. The differential is calculated as realized price as a percentage of the
WTI price stated in Canadian dollars. The differentials in the first quarter of
2010 were higher than NAL's historical average. In the first quarter of 2011,
high inventory levels across North America combined with pipeline constraints
resulted in lower NAL differentials at the start of the quarter, which started
improving later in the quarter.
Natural gas liquids averaged $61.61/bbl in the first quarter of 2011, a 12
percent increase from the $55.02/bbl realized in 2010.
NATURAL GAS MARKETING
Approximately 72 percent of NAL's current gas production is sold under marketing
arrangements tied to the Alberta monthly or daily spot price ("AECO"), with the
remaining 28 percent tied to NYMEX or other indexed reference prices.
For the three months ended March 31, 2011, the Corporation's natural gas sales
averaged $3.68/Mcf compared to $5.01/Mcf in the comparable period of 2010, a
decrease of 27 percent. The quarter-over-quarter decrease in gas price was
largely attributable to the AECO daily spot price decreasing 24 percent
quarter-over-quarter.
Price for Lake Erie natural gas was $4.71/Mcf in the first quarter of 2011, a
decrease of 17 percent compared to $5.70/Mcf in 2010. Lake Erie production of
3.0 mmcf/d accounted for three percent of the Corporation's natural gas
production in the first quarter of 2011, consistent with the comparable period
of 2010. Natural gas sales from the Lake Erie property generally receive a
higher price due to the close proximity of the Ontario and Northeastern U.S.
markets.
Average Pricing
(net of transportation charges)
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 94.10 78.69
NAL average oil (Cdn$/bbl) 82.19 76.43
NAL natural gas liquids (Cdn$/bbl) 61.61 55.02
Natural Gas (Cdn$/mcf)
AECO - daily spot 3.77 4.96
AECO - monthly 3.77 5.36
NAL Western Canada natural gas 3.65 4.98
NAL Lake Erie natural gas 4.71 5.70
NAL average natural gas 3.68 5.01
NAL Oil Equivalent before hedging (Cdn$/boe - 6:1) 48.27 50.49
Average Foreign Exchange Rate (Cdn$/US$) 0.986 1.041
----------------------------------------------------------------------------
----------------------------------------------------------------------------
RISK MANAGEMENT
NAL employs risk management practices to assist in managing cash flows and to
support capital programs and distributions. NAL currently has derivative
contracts in place to assist in managing the risks associated with commodity
prices, interest rates and foreign exchange rates.
NAL's commodity hedging policy currently provides authorization for management
to hedge up to 60 percent of forecasted total production, net of royalties.
Management's practice is to layer in hedges such that more volumes are hedged in
the current 12 month forward period with lesser volumes hedged in the 13 - 24
months forward time period. The execution of NAL's commodity hedging program is
layered in using a combination of swaps and collars. As at March 31, 2011, NAL
had several financial WTI oil contracts and AECO natural gas contracts in place.
NAL's interest rate hedging policy currently provides authorization to hedge up
to 50 percent of outstanding bank debt for periods of up to five years. As at
March 31, 2011, NAL had several interest rate swaps outstanding with a total
notional value of US$139 million.
NAL's foreign exchange hedging policy currently provides authorization to hedge
up to 50 percent of the Corporation's US dollar exposure for up to 24 months. As
at March 31, 2011, NAL had several foreign exchange rate swaps outstanding with
a total notional value of US$111 million.
All derivative contract counterparties are Canadian chartered banks in the
Corporation's lending syndicate.
Realized losses on derivative contracts were $1.0 million for the first quarter
of 2011, compared to a gain of $1.4 million in the comparable quarter of 2010.
The losses in 2011 are due primarily to higher oil prices versus contracted
positions and lower gains on gas positions due to reduced hedged positions. Oil
losses are somewhat offset by foreign exchange gains related to a rising
Canadian dollar.
All derivative contracts are recorded on the balance sheet at fair value based
upon forward curves at March 31, 2011. Changes in the fair value of the
derivative contracts are recognized in net income for the period.
Fair value is calculated at a point in time based on an approximation of the
amounts that would be received or paid to settle these instruments, with
reference to forward prices at March 31, 2011. Accordingly, the magnitude of the
unrealized gain or loss will continue to fluctuate with changes in forward
commodity prices, interest rates and foreign exchange rates.
The fair value of the derivatives at March 31, 2011 was a net liability of $30.2
million, comprised of a $36.7 million liability on oil contracts, offset by a
$1.7 million asset on gas contracts, a $3.8 million asset on foreign exchange
contracts and a $1.0 million asset on interest rate swaps.
First quarter income for 2011 includes a $20.3 million unrealized loss on
derivatives resulting from the change in the fair value of the derivative
contracts during the quarter from an unrealized loss of $9.9 million at December
31, 2010 to an unrealized loss of $30.2 million at March 31, 2011. The $20.3
million unrealized loss was comprised of a $21.3 million unrealized loss on
crude oil contracts, a $0.3 million unrealized gain on interest rate swaps, a
$0.1 million unrealized gain on natural gas contracts and a $0.6 million
unrealized gain on foreign exchange contracts.
The gain/loss on all forward derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts ($000s)
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts (21,318) 1,546
Natural gas contracts 56 15,021
Interest rate swaps 306 191
Exchange rate swaps 678 1,751
----------------------------------------------------------------------------
Unrealized gain (loss) (20,278) 18,509
Realized gain (loss):
Crude oil contracts (3,127) (2,082)
Natural gas contracts 916 2,497
Interest rate swaps (129) (257)
Exchange rate swaps 1,342 1,290
----------------------------------------------------------------------------
Realized gain (loss) (998) 1,448
----------------------------------------------------------------------------
Gain (loss) on derivative contracts (21,276) 19,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following is a summary of the realized gains and losses on risk
management contracts:
Realized Gain (Loss) on Derivative Contracts
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Commodity contracts:
Average crude volumes hedged (bbl/d) 5,700 6,366
Crude oil realized gain (loss) ($000s) (3,127) (2,082)
Gain (loss) per bbl hedged ($) (6.09) (3.63)
Average natural gas volumes hedged (GJ/d) 5,000 37,967
Natural gas realized gain ($000s) 916 2,497
Gain per GJ hedged ($) 2.04 0.73
Average BOE hedged (boe/d) 6,490 12,363
Total realized commodity contracts gain (loss)
($000s) (2,211) 415
Gain (loss) per boe hedged ($) (3.78) 0.37
Gain (loss) per boe ($) (0.88) 0.15
Exchange rate swaps realized gain ($000s) 1,342 1,290
Gain per boe ($) 0.53 0.48
Interest rate swaps realized loss ($000s) (129) (257)
Loss per boe ($) (0.05) (0.09)
Total realized gain (loss) ($000s) (998) 1,448
Gain (loss) per boe ($) (0.40) 0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average hedged boes for the first quarter of 2011 were 6,490 as compared to
11,049 for the fourth quarter of 2010.
NAL has the following interest rate risk management contracts outstanding:
Counterparty
INTEREST RATE Remaining Amount Corporation Floating
CONTRACT Term (millions)(1) Fixed Rate Rate
----------------------------------------------------------------------------
Swaps-floating to Apr 2011 - CAD-BA-CDOR
fixed Dec 2011 $ 39.0 1.5864% (3 months)
Swaps-floating to Apr 2011 - CAD-BA-CDOR
fixed Jan 2013 $ 22.0 1.3850% (3 months)
Swaps-floating to Apr 2011 - CAD-BA-CDOR
fixed Jan 2014 $ 22.0 1.5100% (3 months)
Swaps-floating to Apr 2011 - CAD-BA-CDOR
fixed Mar 2013 $ 14.0 1.8750% (3 months)
Swaps-floating to Apr 2011 - CAD-BA-CDOR
fixed Mar 2014 $ 14.0 1.9850% (3 months)
Swaps-floating to Apr 2011 - CAD-BA-CDOR
fixed Mar 2013 $ 14.0 1.8500% (3 months)
Swaps-floating to Apr 2011 - $ 14.0 1.9300% CAD-BA-CDOR
fixed Mar 2014 (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount
NAL has the following Canadian dollar / U.S. dollar foreign exchange option
contracts outstanding.
Fixed Rate Notional (US)
(CAD/USD) per month Term Counterparty Floating Rate
----------------------------------------------------------------------------
1.05 $ 2.0 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
1.0608 $ 0.5 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL has a monthly commitment to settle the above fixed rates against the
Bank of Canada monthly average noon rate.
Option Monthly
Payout Range Notional Premium
(CAD/USD) (US) per Counterparty Received
month Term Floating Rate (CAD)
----------------------------------------------------------------------------
May 1, 2011 to BofC Monthly Average
$0.93 - $1.01 $ 3.0 MM Dec 31, 2011 Noon Rate $ 60K
Jan 1, 2012 to BofC Monthly Average
$0.93 - $1.01 $ 2.0 MM Jun 30, 2012 Noon Rate $ 40K
----------------------------------------------------------------------------
----------------------------------------------------------------------------
When the monthly average noon spot foreign exchange rate is outside the
payout range, the monthly premium is forfeited. NAL is committed to selling
the above listed USD at the upper payout range value for that month when the
average noon spot foreign exchange rate exceeds the payout range.
Notional
Option Fixing Rate (US) per Counterparty
(CAD/USD) month Term Floating Rate
----------------------------------------------------------------------------
$0.94 - $1.06 Apr 1, 2011 to BofC Monthly Average
$ 0.5 MM Dec 31, 2011 Noon Rate
$0.95 - $1.07 Apr 1, 2011 to BofC Monthly Average
$ 0.5 MM Dec 31, 2011 Noon Rate
$0.94 - $1.08 Apr 1, 2011 to BofC Monthly Average
$ 0.5 MM Dec 31, 2011 Noon Rate
$0.95 - $1.04 Apr 1, 2011 to BofC Monthly Average
$ 0.5 MM Dec 31, 2011 Noon Rate
$0.95 - $1.0125 Apr 1, 2011 to BofC Monthly Average
$ 0.5 MM Jun 30, 2012 Noon Rate
$0.95 - $1.0138 Apr 1, 2011 to BofC Monthly Average
$ 1.0 MM Jun 30, 2012 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
When the monthly average noon spot foreign exchange rate exceeds the lower
fixing rate, NAL is committed to selling the above listed USD at the upper
fixing rate for that month. To the extent the monthly average noon spot
foreign exchange rate is below the lower fixing rate, NAL has no commitment
to sell USD.
Notional
Option Fixing Range (US) per Counterparty
(CAD/USD) month Term Floating Rate
----------------------------------------------------------------------------
$1.05 - $1.15 $ 1.0 MM Apr 1, 2011 to Dec BofC Monthly
31, 2011 Average Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
When the monthly average noon spot foreign exchange rate exceeds the fixing
range, NAL is committed to selling the above listed USD at the lower fixing
rate for that month. To the extent the monthly average spot foreign exchange
rate is below the lower fixing rate, NAL has a commitment to sell the above
listed USD at the lower fixing rate. When the monthly average noon spot
foreign exchange rate falls within the fixing range, NAL has no commitment
to sell USD.
NAL has the following commodity risk management contracts outstanding:
CRUDE OIL Q2-11 Q3-11 Q4-11 Q1-12 Q2-12 Q3-12 Q4-12
----------------------------------------------------------------------------
US$ Collar Contracts
----------------------
$US WTI Collar Volume
(bbl/d) 1,000 200 200 800 800 700 700
Bought Puts - Average
Strike Price
($US/bbl) 83.00 90.00 90.00 101.25 101.25 101.43 101.43
Sold Calls - Average
Strike Price
($US/bbl) 95.68 100.50 100.50 117.95 117.95 117.66 117.66
US$ Swap Contracts
----------------------
$US WTI Swap Volume
(bbl/d) 4,900 5,700 5,700 500 500 500 500
Average WTI Swap
Price ($US/bbl) 87.39 88.10 88.10 109.60 109.60 109.60 109.60
Total Oil Volume
(bbl/d) 5,900 5,900 5,900 1,300 1,300 1,200 1,200
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Two calendar 2011 500 bbl/day swap contracts with an average price of $95.00
contain extendable call options. The extendible call option provides the
counterparty with the option to extend the contract into calendar 2012 under
the same price and volumetric terms. The counterparty can exercise this
option any time before December 31, 2011.
NATURAL GAS Q2-11 Q3-11 Q4-11 Q1-12 Q2-12 Q3-12 Q4-12
----------------------------------------------------------------------------
Swap Contracts
------------------------
AECO Swap Volume (GJ/d) 20,000 21,000 21,000 24,000 5,000 5,000 3,674
AECO Average Price
($Cdn/GJ) 4.32 3.95 3.95 3.98 4.15 4.15 4.15
Total Natural Gas
Volume (GJ/d) 20,000 21,000 21,000 24,000 5,000 5,000 3,674
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the remainder of 2011, the Corporation has outstanding contracts
representing approximately 38 percent of its net crude oil, liquids and natural
gas production after royalties. In 2012, the Corporation has outstanding
contracts representing approximately 11 percent of its net liquids and natural
gas production after royalties.
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $19.8 million for the three months
ended March 31, 2011. Expressed as a percentage of gross sales net of
transportation costs, before gain/loss on derivative contracts, the net royalty
rate was 16.3 percent for the quarter ended March 31, 2011, a decrease from the
16.5 percent experienced in the same period of the previous year.
Royalties decreased to $7.85 per boe for the first quarter of 2011, a decrease
of six percent compared to the first quarter of 2010. The decrease is
attributable to lower commodity prices on a quarter-over-quarter basis.
On March 11, 2010, the Alberta Government announced measures to improve the
Province of Alberta's competitive position in the oil and gas industry. The
current royalty framework for natural gas and conventional oil will be modified
for all production effective January 1, 2011 and the new royalty curves were
announced on May 31, 2010. The current incentive program rate of five percent on
new natural gas and conventional oil wells is a permanent feature of the royalty
systems. The maximum royalty rate for conventional oil wells is a permanent
feature of the royalty system. The maximum royalty rate for conventional oil is
reduced at higher price levels from 50 percent to 36 percent.
For the quarter ended March 31, 2011, 43 percent of crude oil and 69 percent of
natural gas production was from Alberta.
Royalty Expenses
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Royalties ($000s) 19,789 22,599
As % of revenue 16.3 16.5
$/boe 7.85 8.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING COSTS
Operating costs averaged $10.81 per boe for the quarter ended March 31,
2011, up four percent from $10.35 per boe for the quarter ended March 31,
2010 and is attributed to lower volumes. Operating costs are expected to
remain within the guidance range of $10.50 - 10.90 per boe for full year
2011.
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Operating costs ($000s) 27,257 28,070
As a % of revenue 22.4 20.5
$/boe 10.81 10.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OTHER INCOME
Other income was $0.11 per boe for the first quarter of 2011 compared to
$0.12 per boe in the comparable quarter of 2010. Other income includes gas
processing fees and other miscellaneous income and fees.
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Other Income 281 331
As a % of revenue - -
$/boe 0.11 0.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended March 31, 2011, NAL's operating netback, before hedging
gains, was $29.38 per boe, a decrease of 10 percent from $32.59 per boe for the
quarter ended March 31, 2010. The decrease was due to lower revenues, a result
of lower production and lower gas prices, increased operating costs, partially
offset by decreased royalty expense. Hedging losses, related to commodity and
exchange rate derivative contracts, were $0.34 per boe in the first quarter of
2011, as compared to a gain of $0.63 per boe in 2010, the decrease in 2011
attributable mainly to higher realized crude oil prices.
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
Oil (bbl/d) 10,411 11,788
Gas (Mcf/d) 89,581 93,328
NGLs (bbl/d) 2,683 2,777
----------------------------------------------------------------------------
Total (boe/d) 28,024 30,120
REVENUE(1)
Oil ($/bbl) 82.19 76.43
Gas ($/Mcf) 3.68 5.01
NGLs ($/bbl) 61.61 55.02
----------------------------------------------------------------------------
Total ($/boe) 48.27 50.49
ROYALTIES
Oil ($/bbl) 16.16 15.06
Gas ($/Mcf) 0.13 0.42
NGLs ($/bbl) 14.92 12.23
----------------------------------------------------------------------------
Total ($/boe) 7.85 8.34
OPERATING EXPENSES
Oil ($/bbl) 16.83 12.79
Gas ($/Mcf) 1.05 1.41
NGLs ($/bbl) 12.71 10.85
----------------------------------------------------------------------------
Total ($/boe) 10.81 10.35
OTHER INCOME(2)
Oil ($/bbl) 0.19 0.25
Gas ($/Mcf) 0.01 0.02
NGLs ($/bbl) 0.14 0.18
----------------------------------------------------------------------------
Total ($/boe) 0.11 0.16
OPERATING NETBACK, BEFORE HEDGING
Oil ($/bbl) 49.39 48.83
Gas ($/Mcf) 2.51 3.20
NGLs ($/bbl) 34.12 32.12
----------------------------------------------------------------------------
Total ($/boe) 29.72 31.96
HEDGING GAINS/(LOSSES)(3)
Oil ($/bbl) (1.90) (0.75)
Gas ($/Mcf) 0.11 0.30
NGLs ($/bbl) - -
----------------------------------------------------------------------------
Total ($/boe) (0.34) 0.63
OPERATING NETBACK, AFTER HEDGING
Oil ($/bbl) 47.49 48.08
Gas ($/Mcf) 2.62 3.50
NGLs ($/bbl) 34.12 32.12
----------------------------------------------------------------------------
Total ($/boe) 29.38 32.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation charges.
(2) Excludes interest on notes with MFC and gain on sale of oil and gas
properties.
(3) Realized hedging gains/losses on commodity and exchange rate derivative
contracts.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses include direct costs incurred by the
Corporation plus the reimbursement of the G&A expenses incurred by NAL Resources
Management Limited (the "Manager") on the Corporation's behalf.
For the three months ended March 31, 2011, G&A expenses were $7.4 million,
compared with $5.9 million in the comparable quarter of 2010. G&A expense per
boe was $2.95 in the quarter, as compared to $2.17 for the same period in 2010.
The year-over-year increase in total G&A of $1.5 million is attributable to
higher consulting and information systems costs in the first quarter of 2011.
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
G&A ($000s) 7,431 5,882
($/boe) 2.95 2.17
As % of revenue 6.1 4.3
Per share ($) 0.05 0.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SHARE-BASED INCENTIVE COMPENSATION PLAN
The employees of the Manager are all members of a share-based incentive plan
(the "Plan"). The Plan results in employees of the Manager receiving cash
compensation based upon the value and overall return of a specified number of
notional common shares. The Plan consists of Restricted Share Units ("RSUs") and
Performance Share Units ("PSUs"). One third of each RSU grant vests on November
30 in each of the three years after the date of grant. PSUs vest on November 30,
three years from the date of grant. Dividends paid on the Corporation's
outstanding shares during the vesting period are assumed to be paid on the
awarded notional shares and reinvested in additional notional shares on the date
of distribution. Upon vesting, the employee of the Manager is entitled to a cash
payout based on the share price at the date of vesting of the shares held. In
addition, the PSUs have a performance multiplier which is based on the
Corporation's performance relative to its peers and may range from zero to two
times the market value of the notional shares held at vesting.
During the first quarter of 2011, the Corporation recorded a $0.6 million charge
for share-based incentive compensation that reflects the impact of vesting,
additional notional shares and an increase in the share price. The share price
of the Corporation increased by two percent from $12.95 at December 31, 2010 to
$13.23 at March 31, 2011. An increase in share price results in previously
accrued amounts being increased.
Share-based incentive compensation remained relatively constant as compared to
the first quarter of 2010, from $0.7 million in 2010 to $0.6 million in 2011.
At March 31, 2011, the share price used to determine share-based incentive
compensation was $13.23. The closing share price of the Corporation on the
Toronto Stock Exchange on May 18, 2011 was $12.40.
The calculation of share-based compensation expense is made at the end of each
quarter based on the quarter end share price and estimated performance factors.
The compensation charges relating to the shares granted are recognized over the
vesting period based on the share price, number of RSUs and PSUs outstanding,
and the expected performance multiplier. As a result, the expense recorded in
the accounts will fluctuate in each quarter and over time.
At March 31, 2011, the Corporation has recorded a total accumulated liability
for share-based incentive compensation in the amount of $6.5 million, of which
$4.8 million is recorded as current as it is payable in December 2011, and $1.7
million is long-term as it is payable in December 2012 and December 2013.
Share-Based Compensation
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Share-based compensation ($000s) 636 686
As % of revenue 0.5 0.5
$/boe 0.25 0.25
Per share ($) - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
RELATED PARTY TRANSACTIONS
The Corporation continues to be managed by the Manager. The Manager is a
wholly-owned subsidiary of Manulife Financial Corporation ("MFC") and also
manages NAL Resources Limited ("NAL Resources"), another wholly-owned subsidiary
of MFC. NAL Resources and the Corporation maintain ownership interests in many
of the same oil and natural gas properties in which NAL Resources is the joint
operator. As a result, a significant portion of the net operating revenues and
capital expenditures during the year are based on joint amounts from NAL
Resources. These transactions are in the normal course of joint operations and
are measured using the fair value established through the original transactions
with third parties.
The Manager provides certain services to the Corporation and its subsidiary
entities pursuant to an administrative services and cost sharing agreement. This
agreement requires the Corporation to reimburse the Manager at cost for G&A and
share-based compensation expenses incurred by the Manager on behalf of the
Corporation calculated on a unit of production basis. The agreement does not
provide for any base or performance fees to be payable to the Manager.
The Corporation paid $6.2 million (2010 - $3.6 million) for the reimbursement of
G&A expenses during the first quarter. The Corporation also pays the Manager its
share of share-based incentive compensation expense when cash compensation is
paid to employees under the terms of the Plan, of which $6.8 million was paid in
the first quarter of 2011, representing shares that vested on November 30, 2010
(2010 - $6.9 million).
At March 31, 2011 the Corporation owed the Manager $2.1 million for the
reimbursement of G&A and had a receivable from NAL Resources of $2.6 million,
relating to operating revenue less capital expenditures.
In conjunction with the Reorganization, a partnership that was indirectly owned
jointly by the Corporation and MFC was dissolved on December 31, 2010. The
Partnership held the assets acquired from the acquisitions of Tiberius and Spear
in February 2008. See "Structure of the Business" in this MD&A for more
information.
As part of the original structuring of the Partnership in 2008, both the Trust
and MFC entered into net profit interest royalty agreements ("NPI") with the
Partnership. These agreements entitle each royalty holder to a 49.5 percent
interest in the cash flow from the Partnership's reserves.
In addition, in the Partnership there was a note payable to MFC, which was
settled on dissolution of the Partnership. At January 1, 2010, the note payable
of $8.9 million was included on consolidation of the Partnership, but was
effectively eliminated through the non-controlling interest. The note was due on
demand, unsecured and bore interest at prime plus three percent.
INTEREST
Interest on bank debt includes the interest rate charge on borrowings, plus a
standby fee, a stamping fee and the fee for renewal. Interest on bank debt for
the first quarter of 2011 was $3.2 million, an increase of $0.1 million from
$3.1 million for the comparable period in 2010. The increase was due to an
increase in average debt levels, partially offset by a decrease in effective
interest rates. Average outstanding bank debt for the first quarter of 2011 was
$259.3 million, $26.8 million higher than the $232.5 million outstanding for the
first quarter of 2010. NAL's effective interest rate averaged 5.05 percent
during the first quarter of 2011, compared to 5.39 percent during the comparable
period in 2010. The decrease in the rate from the first quarter of 2010 is
attributable to decreases in the bank fees that are included in debt costs
partially offset by increases in interest rates. NAL's interest is calculated
based upon a floating rate before the effect of any interest rate swaps.
Interest on convertible debentures represented interest charges of $3.1 million
for the three months ended March 31, 2011 and March 31, 2010. The interest
includes the interest on the 2007 debentures at 6.75 percent and the interest on
the debentures issued in December 2009 at 6.25 percent. Amortization of the debt
premium was $0.6 million for the three months ended March 31, 2011. During 2010,
the convertible debentures were recorded at fair value resulting in no accretion
or amortization in 2010 (refer to "Capital Resources and Liquidity" in this MD&A
for further detail).
Interest and Debt
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Interest on bank debt ($000s)(1) 3,229 3,086
Interest and amortization on convertible debentures
($000s) 2,549 3,142
----------------------------------------------------------------------------
Total interest ($000) 5,778 6,228
Bank debt outstanding at period end ($000s) 255,306 244,695
Convertible debentures at period end ($000s) (2) 198,926 204,362
$/boe:
Interest on bank debt 1.28 1.14
Interest on convertible debentures 1.25 1.16
Amortization on convertible debentures (0.24) -
----------------------------------------------------------------------------
Total interest 2.29 2.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes interest rate contract impact.
(2) Debt component of the debentures, as reported on the balance sheet.
CASH FLOW NETBACK
For the quarter ended March 31, 2011, NAL's cash flow netback was $23.60 per
boe, a 15 percent decrease from $27.74 per boe for the comparable period in
2010. The decrease was due to a lower operating netback after hedging,
higher G&A expenses, including share-based incentive compensation, and
higher interest charges.
Cash Flow Netback ($/boe)
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Operating netback, after hedging 29.38 32.59
G&A expenses, including share-based incentive
compensation (3.20) (2.42)
Interest on bank debt and convertible debentures(1) (2.53) (2.30)
Interest on notes with MFC(2) - (0.04)
Realized loss on interest rate derivative contracts (0.05) (0.09)
----------------------------------------------------------------------------
Cash flow netback 23.60 27.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.
(2) Reported as other income.
GAIN ON DISPOSITION OF OIL AND GAS PROPERTIES
During the first quarter of 2011 NAL disposed of certain non-core properties
resulting in a gain of $12.5 million (2010 - $11.2 million). The
gain is computed as the difference between sales proceeds and the net book
value.
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Gain on sale of oil and gas properties ($000s) 12,534 11,193
As a % of revenue 10.3 8.2
$/boe 4.97 4.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
DEPLETION, ACCRETION OF ASSET RETIREMENT OBLIGATIONS AND IMPAIRMENT
Depletion of oil and natural gas properties, including the capitalized portion
of the asset retirement obligations, and depreciation of equipment is provided
for on a unit-of-production basis using estimated proved plus probable reserves
volumes.
For the quarter ended March 31, 2011, depletion on property, plant and equipment
was $18.40 per boe, three percent higher than the $17.80 per boe for the same
period in 2010.
Accretion on asset retirement obligation was $2.5 million for the first quarter
in 2011, a seven percent decrease from $2.7 million at the comparable period of
2010 due to disposition of properties.
Impairment in the first quarter of 2011 was $5.2 million compared to no
impairment taken in the first quarter of 2010. Impairment is recognized if the
carrying amount of PP&E is greater than their recoverable amount, and it is
calculated on a cash generating unit basis ("CGU") see "Accounting Policies"
section of this MD&A for more information. A CGU is the lowest level at which
there are identifiable cash inflows. NAL has determined that it has nine CGUs.
The impairment has occurred in natural gas CGUs due to lower gas prices compared
to December 31, 2010. Once gas prices recover and the fair value of assets
increase, NAL is required to reverse any impairment previously recognized in net
income, net of what depletion would have been had the asset not been impaired
and increase the carrying value of the CGU to which it relates. The reversal
cannot exceed the amount previously written off.
The depletion rate will fluctuate period-over-period depending on the amount and
type of capital expenditures and the amount of reserves added.
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Depletion ($000s) 46,412 48,265
Depletion rate per boe ($) 18.40 17.80
Accretion of asset retirement obligation ($000s) 2,544 2,701
Impairment ($000s) 5,200 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TAXES
In the first quarter of 2011, NAL had a deferred income tax reduction of $0.3
million compared to a $2.7 million expense in the corresponding period of the
prior year.
As at March 31, 2011, the Corporation's (including all subsidiaries) estimated
tax pools available for deduction from future taxable income approximated $1.4
billion, of which approximately 31 percent represented COGPE, 17 percent
represented UCC, with the balance represented by CEE, CDE, share issue costs and
non-capital loss carry forwards.
Estimated Tax Pools ($ millions)
December 31,
March 31, 2011 2010
----------------------------------------------------------------------------
Canadian exploration expense 58 57
Canadian development expense 417 376
Canadian oil and gas property expense 432 456
Undepreciated capital costs 242 251
Other (including loss carry forwards) 246 279
----------------------------------------------------------------------------
Total estimated tax pools 1,395 1,419
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Based on current strip prices at March 31, 2011, the Corporation is not expected
to be taxable in 2011.
MINORITY INTEREST
The Corporation had recorded a minority interest in respect of the 50 percent
ownership interest indirectly held by MFC in the Partnership holding the
Tiberius and Spear assets (see "Structure of the Business") for the period ended
March 31, 2010. As the Partnership was dissolved December 31, 2010, no minority
interest was recorded for the period ended March 31, 2011.
The minority interest presented in the 2010 statement of income has two
components: the royalty paid to MFC under the NPI, being a cash payment to the
royalty holder, and 50 percent of net income remaining in the Partnership, after
NPI expense, attributable to MFC. This share of net income attributable to MFC
is a non-cash item.
The minority interest in the consolidated statement of income is comprised of:
Three months ended March 31
-----------------------------
($000s) 2011 2010
----------------------------------------------------------------------------
Net profits interest expense - 618
Share of net income attributable to MFC - 314
----------------------------------------------------------------------------
- 932
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET INCOME
Net income is a measure impacted by both cash and non-cash items. The largest
non-cash items impacting the Corporation's net income are depletion, accretion,
unrealized gains or losses on derivative contracts gains or losses on disposals
of property, plant and equipment, future income taxes and impairment
losses/reversals, should these occur.
The loss for the first quarter of 2011 was $1.5 million compared to $50.2
million of net income for the comparable period in 2010. The decrease of $51.7
million was mainly due to decreased revenues net of royalties ($12.5 million),
decreased gains on derivative contracts ($41.2 million), increased G&A ($1.5
million), an impairment loss in 2011 of $5.2 million offset by decreased
operating costs ($0.8 million), decreased DD&A expense ($1.9 million), a lower
tax expense ($3.0 million), a higher gain on disposition in 2011 ($1.3 million)
and a fair value adjustment and issuance costs related to convertible debentures
in 2010 ($1.0 million).
Three months ended March 31
-----------------------------
($000s) 2011 2010
----------------------------------------------------------------------------
Net income (loss) (1,510) 50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Corporation is comprised of common shares, bank
debt and convertible debentures.
As at March 31, 2011, NAL had 147,781,497 common shares outstanding, compared
with 147,248,494 common shares as at December 31, 2010. The increase from
December 31, 2010 is attributable to 533,003 shares issued under the
Corporation's dividend reinvestment plan ("DRIP").
Under the DRIP, shareholders may elect to reinvest dividends or make optional
cash payments to acquire common shares from treasury under the DRIP at 95
percent of the average market price with no additional fees or commissions. The
operation of the DRIP was reinstated effective with the March distribution
payable on April 15, 2009, following suspension of the program in October 2008.
Participation in the DRIP averaged 20 percent for this quarter.
As at March 31, 2011, the Corporation had net debt of $528.7 million (net of
working capital and other liabilities, excluding derivative contracts and
deferred taxes) including the convertible debentures at face value of $194.7
million. Excluding the convertible debentures, net debt was $334.0 million,
compared with $310.3 million at December 31, 2010. The increase in net debt,
excluding convertible debentures, of $23.7 million during 2011 is attributable
to a negative change in working capital of $35.4 million partially offset by
decreased bank debt of $11.7 million.
Bank debt outstanding was $255.3 million at March 31, 2011 compared with $267.0
million as at December 31, 2010. Of the $255.3 million outstanding at March 31,
2011, $254.8 million is outstanding under the production facility, and $0.5
million is under the working capital facility.
At the end of the first quarter, the Corporation had a net debt (excluding
convertible debentures) to 12 months trailing cash flow ratio of 1.26 times and
a total net debt (including convertible debentures) to 12 months trailing cash
flow ratio of 2.00 times.
Subsequent to quarter end, the Corporation had its previously approved credit
facility amount of $550 million renewed. The credit facility is a fully secured,
extendible, revolving facility and will revolve until April 30, 2012 at which
time it is extendible for a further 364-day revolving period upon agreement
between the Corporation and the bank syndicate. The facility consists of a $535
million production facility and a $15 million working capital facility. The
credit facility is fully secured by first priority security interests in all
present and after acquired properties and assets of the Corporation and its
subsidiary and affiliated entities. The purpose of the facility is to fund
property acquisitions and capital expenditures. Principal repayments to the bank
are not required at this time. Should principal repayments become mandatory, and
in the absence of refinancing arrangements, the Corporation would be required to
repay the facility in five equal quarterly installments commencing May 1, 2013.
The Corporation has two series of convertible debentures currently outstanding.
On December 3, 2009, the Corporation issued $115 million principal amount of
6.25 percent convertible unsecured subordinated debentures. Interest on the
debentures is paid semi-annually in arrears, on June 30 and December 31, and the
debentures are convertible at the option of the holder, at any time, into fully
paid common shares at a conversion price of $16.50 per common share. The
debentures mature on December 31, 2014 at which time they are due and payable.
The debentures are redeemable by the Corporation at a price of $1,050 per
debenture on or after January 1, 2013 and on or before December 31, 2013, and at
a price of $1,025 per debenture on or after January 1, 2014 and on or before
December 31, 2014. On redemption or maturity, the Corporation may opt to satisfy
its obligation to repay the principal by issuing common shares. If all of the
outstanding debentures were converted at the conversion price, an additional 7.0
million common shares would be required to be issued.
In addition, the Corporation has outstanding $79.7 million principal amount of
6.75 percent convertible extendible unsecured subordinated debentures. Interest
on these debentures is paid semi-annually in arrears, on February 28 and August
31, and the debentures are convertible at the option of the holder, at any time,
into fully paid common shares at a conversion price of $14.00 per common share.
The debentures mature on August 31, 2012 at which time they are due and payable.
The debentures are redeemable by the Corporation at a price of $1,050 per
debenture on or after September 1, 2010 and on or before August 31, 2011, and at
a price of $1,025 per debenture on or after September 1, 2011 and on or before
August 31, 2012. On redemption or maturity, the Corporation may opt to satisfy
its obligation to repay the principal by issuing common shares. If all of the
outstanding debentures were converted at the conversion price, an additional 5.7
million common shares would be required to be issued.
Subsequent to December 30, 2010, the convertible debentures are classified as
debt on the balance sheet with a portion of the proceeds allocated to equity,
representing the value of the conversion feature. Prior to December 31, 2010, as
a trust, the convertible debentures were fair valued with no equity portion. As
the debentures are converted to common shares, a portion of the debt and equity
amounts are transferred to Share Capital. The debt balance amortizes over time
to the principal amount owing on maturity. The amortization of the debt premium
and the interest paid to debenture holders are reflected each period as part of
the line item "interest and amortization on convertible debentures" in the
consolidated statement of income.
The Corporation recognized $0.6 million (2010 - nil) of amortization of the debt
premium in the first quarter of 2011.
As at May 19, 2011, the Corporation has 148,188,597 common shares and $194.7
million in convertible debentures outstanding.
Capitalization
March 31, December 31, March 31,
2011 2010 2010
----------------------------------------------------------------------------
Shareholders' equity ($000s) 869,962 895,750 887,937
Bank debt ($000s) 255,306 266,965 244,695
Working capital deficit(1) ($000s) 78,697 43,337 63,760
----------------------------------------------------------------------------
Net debt excluding convertible
debentures 334,003 310,302 308,455
Convertible debentures ($000s)(2) 194,744 194,744 194,744
----------------------------------------------------------------------------
Net debt 528,747 505,046 503,199
Net debt excluding convertible
debentures to trailing 12-month
cash flow(3) 1.26 1.11 1.24
Total net debt to trailing 12-month
cash flow(3) 2.00 1.80 2.03
Common shares outstanding (000s) 147,781 147,248 137,881
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital and other liabilities, excludes derivative contracts,
deferred tax and note with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt divided by funds from operations for the previous
12 months.
Funds from operations is a non-IFRS measure used by management as an indicator
of the Corporation's ability to generate cash from operations. Assuming the
Corporation's commodity price and guidance assumptions are attained, dividend
levels represent a payout ratio in the range of 40 - 50 percent of funds from
operations. The Corporation renewed its bank line of $550 million of which $255
million is drawn at March 31, 2011, leaving available capacity of $295 million.
For 2011, the Corporation expects to continue to benefit from an active hedging
program. Currently, the Corporation has in place oil hedges for approximately 52
percent of net forecasted (after royalty) production for 2011. Crude volumes are
hedged at an average price of US$87.89 per boe on fixed price contracts. On
collared contracts, crude volumes are hedged at an average ceiling price of
US$97.06 per boe and at an average floor price of US$85.00 per boe. For natural
gas, remaining 2011 hedges total approximately 25 percent of net budgeted
production volumes hedged at an average floor price in excess of $4.07 per GJ
($4.29 per Mcf).
NAL's capital program is designed to be scalable and flexible in response to
commodity prices and market conditions. For 2011, the Corporation plans for a
$200 - 230 million capital program. The Corporation, through the Manager,
operates approximately 95 percent of the assets to which the capital program is
directed, allowing for significant flexibility over the scale and timing of the
program.
Fluctuations in commodity prices, market conditions or potential growth
opportunities may make it necessary to adjust forecasted capital expenditures
and/or distributions levels.
ASSET RETIREMENT OBLIGATION
At March 31, 2011, the Corporation reported an asset retirement obligation
("ARO") balance of $126.0 million ($149.0 million as at December 31, 2010) for
future abandonment and reclamation of the Corporation's oil and gas properties
and facilities. The ARO balance was increased by revisions to estimates and $2.5
million from accretion expense, and was reduced by $23.1 million for property
dispositions and $2.4 million for actual abandonment and reclamation
expenditures incurred during the first quarter. Liabilities incurred to the
quarter were offset by revisions to estimates.
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
Joint Venture Agreement:
Effective April 20, 2009, the Corporation and MFC entered into a joint venture
agreement with a senior industry partner. The arrangement consists of a three
year commitment to spend $50 million to earn an interest in freehold and crown
acreage. The Corporation has a 65 percent interest in this agreement and MFC a
35 percent interest and therefore the Corporation's net commitment is $32.5
million. The agreement is exclusive and structured to be extendible for up to an
additional six years for a total potential commitment of $150 million ($97.5
million net to the Corporation) to earn an interest in over 150 sections (97.5
net) of freehold and crown acreage. If the capital spending commitments are not
met, interests in the freehold and crown acreage will not be earned and the
Corporation will not be required to pay unspent commitment amounts to the senior
industry partner. As at March 31, 2011, the Corporation had spent $14.0 million
under this agreement.
Farm-in Agreement:
Effective August 10, 2009, the Corporation and MFC entered into a farm-in
agreement with a senior industry partner. The arrangement consists of a two year
initial commitment, with a minimum capital commitment of $40 million in the
first year and $57 million in the second year, with an option for a third year,
at NAL's election, for an additional $50 million commitment. The Corporation has
a 60 percent interest in this agreement and MFC a 40 percent interest. The
agreement provides the opportunity to earn an interest in approximately 1,400
gross sections of undeveloped oil and gas rights in Alberta held by the partner.
If the capital spending commitments are not met, interest in the acreage will
not be earned and the Corporation will not be required to pay any unspent
amounts under the Agreement. As at March 31, 2011, the Corporation had spent
$36.7 million under this agreement.
Other:
NAL has entered into several contractual obligations as part of conducting
day-to-day business. NAL has the following commitments for the next five years:
($000s) 2011 2012 2013 2014 2015
----------------------------------------------------------------------------
Office lease(1) 1,431 2,146 2,132 2,092 2,092
Office lease - Clipper and Breaker(2) 1,473 2,211 364 - -
Transportation agreement 3,126 2,352 2,209 1,030 124
Processing agreement(3) 466 197 184 - -
Convertible debentures(4) - 79,744 - 115,000 -
Bank debt - - 153,146 102,098 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 6,496 86,650 158,035 220,220 2,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including both
base rent and operating costs, in relation to the lease held by the
Manager, of which the Corporation is allocated a pro rata share
(currently approximately 60 percent) of the expense on a monthly basis.
(2) Represents the full amount of office lease assumed with the acquisitions
of Clipper and Breaker. MFC will reimburse the Corporation for 50
percent of the Clipper obligation under the base price adjustment
clause.
(3) Represents gas processing agreements with take or pay components.
(4) Principal amount.
QUARTERLY INFORMATION
2011 2010 2009
----------------------------------------------------------------------------
($000s, except
per share
and production
amounts) Q1 Q4 Q3 Q2 Q1 Q4(4) Q3(4) Q2(4)
----------------------------------------------------------------------------
Revenue,
net of
royalties
(1) 82,391 85,685 101,258 106,332 136,209 88,165 85,988 60,922
Per share 0.56 0.58 0.69 0.74 0.99 0.75 0.77 0.60
Cash flow 60,983 72,152 88,400 48,152 68,248 53,060 52,999 63,690
Per share 0.41 0.49 0.60 0.33 0.50 0.45 0.47 0.63
Funds from
operations
(2) 62,997 67,645 65,696 67,848 79,481 62,953 53,766 51,998
Per share 0.43 0.46 0.45 0.47 0.58 0.53 0.48 0.51
Net income
(loss) (1,510)(22,017) 7,430 23,443 50,169 5,634 8,249 (9,407)
Per share
basic (0.01) (0.15) 0.05 0.16 0.36 0.05 0.07 (0.09)
diluted (0.01) (0.14) 0.05 0.16 0.35 0.05 0.07 (0.09)
Average oil
equivalent
production
(boe/d -
6:1) 28,024 28,596 29,473 29,609 30,120 25,748(3) 23,418 23,049
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents revenue, net of royalties, plus gain (loss) on derivative
contracts
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items
(3) Includes Breaker volumes effective December 11, 2009.
(4) As computed under previous CGAAP.
DISCLOSURE CONTROLS AND PROCEDURES ("DC&P")
The Chief Executive Officer and the Chief Financial Officer ("certifying
officers") have designed DC&P, or caused them to be designed under their
supervision, to provide reasonable assurance that all material information
required to be disclosed by NAL in its interim filings is processed, summarized
and reported within the time periods specified in applicable securities
legislation.
INTERNAL CONTROL OVER FINANCIAL REPORTING ("ICFR")
NAL's certifying officers are responsible for establishing and maintaining ICFR,
as such term is defined in National Instrument 52-109 Certification of
Disclosure in Issuers' Annual and Interim Filings. The control framework NAL's
officers used to design NAL's ICFR is the Internal Control - Integrated
Framework (the "COSO Framework") published by The Committee of Sponsoring
Organizations of the Treadway Commission ("COSO").
The certifying officers designed ICFR, or caused it 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.
There has not been any change in NAL's ICFR during the interim period ended
March 31, 2011 that has materially affected, or is reasonably likely to
materially affect, NAL's ICFR.
ACCOUNTING POLICIES
The Corporation has prepared its March 31, 2011 Interim Consolidated Financial
Statements in accordance with IFRS1, First-time Adoption of International
Financial Reporting Standards, and with IAS 34, Interim Financial Reporting, as
issued by the IASB. Previously, the Corporation prepared its financial
statements in accordance with Canadian GAAP, or previous CGAAP. The adoption of
IFRS has not had a material impact on the Corporation's operations and strategic
decisions.
The Corporation's IFRS accounting policies are provided in Note 2 to the Interim
Consolidated Financial Statements. In addition, Note 14 to the Interim
Consolidated Financial Statements presents reconciliations between the
Corporation's 2010 previous CGAAP results and the 2010 IFRS results. The
reconciliations include the Consolidated Balance Sheets as at January 1, 2010,
March 31, 2010 and December 31, 2010, and Consolidated Statement of Earnings,
Comprehensive Income, Changes in Shareholders Equity and Cash Flows for the
three months ended March 31, 2010 and for the 12 months ended December 31, 2010.
The following discussion explains the significant differences between NAL's
previous CGAAP accounting policies and those applied by the Corporation under
IFRS. IFRS policies have been retrospectively and consistently applied except
where specific IFRS1 optional and mandatory exemptions permitted an alternative
treatment upon transition to IFRS for first-time adopters.
The most significant changes to the Corporation's accounting policies relate to
the accounting for property, plant and equipment. Under previous CGAAP, NAL
followed the Canadian Institute of Chartered Accountants ("CICA") guideline on
full cost accounting in which all costs directly associated with the acquisition
of, the exploration for, and the development of natural gas and crude oil
reserves were capitalized in one cost centre. Costs accumulated within the cost
centre were depleted using the unit-of-production method based on proved
reserves determined using estimated future prices and costs. Upon transition to
IFRS, the Corporation was required to adopt new accounting policies, including
exploration and evaluation costs ("E&E") and development and production costs
("D&P").
Under IFRS, E&E costs are those expenditures for an area where technical
feasibility and commercial viability has not yet been determined. D&P costs
include those expenditures for areas where technical feasibility and commercial
viability has been determined.
A) Property, plant and equipment (PP&E) and Exploration and evaluation assets
The Corporation elected to apply the IFRS1 exemption available to entities which
followed full cost accounting under previous CGAAP. This exemption permits the
total carrying value of PP&E and E&E under IFRS on transition to equal the
carrying value under previous CGAAP, subject to an impairment test. In addition,
conversion to IFRS requires the allocation of the carrying amount of the full
cost pool under previous CGAAP to E&E, and to components and CGUs for PP&E
assets. Firstly, E&E assets were recorded at their carrying amount under
previous CGAAP. The remaining previous CGAAP carrying amount was then allocated,
pro-rata to components (Areas) for D&P assets ("PP&E"), based on proved plus
probable reserve values, using the present values at a 10 percent discount rate.
E&E assets are required to be segregated from D&P assets. At January 1, 2010
these assets were $88.1 million, representing their carrying value under
previous CGAAP. In order to present PP&E assets in accordance with IFRS, this
$88.1 million was reclassified to E&E on NAL's financial statements at January
1, 2010. These assets comprise exploratory undeveloped land and possible
reserves assigned as a result of business acquisitions. As at March 31, 2010 and
December 31, 2010, NAL's E&E assets were $90.1 million and $63.1 million,
respectively.
Under previous CGAAP these assets were included in the full cost pool as CGAAP
PP&E, in accordance with the CICA's full cost accounting guideline. Under IFRS,
these costs are initially recorded as E&E, and on determination of technical
feasibility and commercial viability of the assets the capitalized costs are
then moved to PP&E. Under IFRS, unrecoverable E&E costs and costs incurred prior
to obtaining the legal rights to explore are expensed.
B) Capitalized costs - PP&E
Under IFRS, employee costs included in general and administrative charges and
share-based compensation charges are capitalized to the extent they are directly
attributable to PP&E and E&E. For the year ended December 31, 2010, $9.3 million
of such costs are expensed under IFRS that were capitalized under previous
CGAAP. For the three months ended March 31, 2010 $1.8 million were expensed that
were capitalized under previous CGAAP.
Additionally for the year ended December 31, 2010, lease rentals of $7.7 million
were expensed under previous CGAAP, while under IFRS the Corporation has elected
to capitalize these amounts. For the three months ended March 31, 2010, $1.8
million has been capitalized.
C) Depreciation and depletion
Under previous CGAAP, depletion was based on NAL's single cost centre, on a unit
of production basis using total proved reserves. Costs subject to depletion
excluded possible reserve locations and undeveloped land.
Under IFRS, depletion is provided for at a component level, defined as an Area
by NAL, on a unit of production basis using total proved plus probable reserves.
Costs subject to depletion are D&P assets excluding land under development.
For the year ended December 31, 2010, depletion decreased by $50.6 million from
previous CGAAP, primarily as a result of the change in depletion base to proved
plus probable reserves. For the three months ended March 31, 2010 depletion
decreased by $13.8 million. There was no impact to January 1, 2010 due to the
IFRS1 election discussed above.
D) Impairment
Under previous CGAAP, impairment was recognized if the carrying amount exceeded
the undiscounted cash flows from proved reserves for NAL's single cost centre.
The amount of impairment was then measured as the amount by which the carrying
value of the cost centre exceeded the sum of proved plus probable reserves
discounted at a risk free rate plus the cost of unproved interests and land, net
of impairment. Impairments recognized under previous CGAAP were not reversed.
Under IFRS, an impairment is recognized if the carrying value exceeds the
recoverable amount for a cash-generating unit ("CGU"). CGUs are aggregations of
areas capable of generating independent cash inflows. If the carrying value of
the CGU exceeds the recoverable amount, the CGU is written down with an
impairment recognized in net income. Impairments under IFRS are reversed when
there has been a subsequent increase in recoverable amounts. Impairment
reversals are recognized in net income and the carrying amount of the CGU is
increased.
Impairment tests were completed on transition, resulting in no impairment charge
to PP&E or E&E at January 1, 2010.
For the year ended December 31, 2010, NAL recognized a $32.8 million impairment
loss relating to four gas focused CGUs in Alberta, northeast British Columbia
and Ontario. The impairment recognized was based on the difference between the
December 31, 2010 net book value of the CGUs and the recoverable amount. The
recoverable amount was determined using fair value less costs to sell based on
discounted future cash flows of proved plus probable reserves. Under previous
CGAAP, these assets were tested as one cost centre with no impairment resulting
at December 31, 2010.
E) Gains on dispositions
Under previous CGAAP, gains on dispositions were typically not recognized.
Proceeds from dispositions were deducted from the full cost pool unless the
deduction resulted in a change to the depletion rate of 20 percent or more, in
which case a gain or loss was recorded.
Under IFRS, gains or losses are recorded on dispositions of properties and are
calculated as the difference between the proceeds and the net book value of the
assets disposed of at the time of disposition. For the year ended December 31,
2010, NAL recognized $17.6 million as gains on disposition under IFRS, compared
to no gain recognized under previous CGAAP. Similarly, a gain of $11.2 million
was recognized for the three months ended March 31, 2010 under IFRS with no gain
recorded under previous CGAAP.
F) Asset Retirement Obligations and Accretion
Under previous CGAAP, the asset retirement obligations were measured at the
estimated fair value of the expenditures expected to be incurred. Liabilities
were not remeasured to reflect period end discount rates.
Under IFRS, the asset retirement obligation is measured as the best estimate of
the expenditure to be incurred and requires the liability to be remeasured using
the period end discount rate.
As NAL elected the oil and gas assets IFRS1 exemption, the ARO exemption
available to full cost entities was also elected. This exemption allows for the
remeasurement of ARO on IFRS transition with the offset to retained earnings.
The carrying value under previous CGAAP at December 31, 2009 of $127.9 million
was revalued under IFRS, resulting in an opening IFRS balance at January 1, 2010
of $134.4 million. On transition to IFRS, NAL recorded the difference of $6.5
million as an increase to the liability with an offset to retained earnings. At
December 31, 2010, the liability was increased by $4.3 million. The adjustments
primarily reflect the remeasurement of the obligation using an eight percent
discount rate at both dates.
In addition, accretion of the liability is impacted by the change in the
recognized amount. For the year ended December 31, 2010, accretion decreased by
$1.1 million as compared to previous CGAAP.
G) Other Liabilities and Accounts Payable
The Corporation elected to apply the exemption to restate the liability for
share-based compensation on transition with the offset to retained earnings.
This is applicable to awards that have not vested prior to January 1, 2010,
which applies to all of the outstanding grants at NAL.
The adjustment to the liability for share-based compensation is to reflect a
forfeiture rate which was not included under previous CGAAP. On transition to
IFRS, the payable was reduced by $0.7 million to reflect the inclusion of a
forfeiture rate. For the full year 2010, the expense for share-based
compensation increased by $1.5 million due to the expensing of amounts
capitalized under previous CGAAP, offset slightly by the inclusion of a
forfeiture rate.
H) Convertible Debentures
As a trust, NAL designated its convertible debentures as a financial liability
at fair value through profit or loss on transition to IFRS. As at January 1,
2010, the fair value of the convertible debentures was $203.7 million, based on
quoted market prices. Under previous CGAAP, the convertible debentures were
bifurcated between debt and equity in the amounts of $178.0 million and $12.6
million, respectively at December 31, 2009. The difference between the fair
value and CGAAP, carrying value was charged to retained earnings on transition
to IFRS.
At each quarter end the debentures were fair valued based on the then prevailing
market price with the adjustment taken to income. Any accretion expense
previously recognized through income under previous CGAAP was eliminated. On
conversion to a corporation on December 31, 2010, the debentures carrying value,
which represented the fair value on December 31, 2010, was bifurcated between
their debt and equity components, as required under IFRS.
On December 31, 2010, the fair value of the debentures was $204.5 million, which
following the corporate conversion was allocated $5.0 million to equity and
$199.5 million to debt.
In addition, for the period the debentures were held at fair value through
profit and loss any issue costs associated with the debentures were expensed, of
which $0.3 million was expensed in 2010. Under previous CGAAP these issue costs
were netted against the debt component of the debentures.
I) Minority Interest
The mandatory exception under IFRS1 allows for the prospective application in
the accounting for minority interest.
Therefore, the minority interest has only been adjusted under IFRS to reflect
the changes to the income statement and net assets of the jointly owned
Partnership with MFC (Note 4) as compared to previous CGAAP.
Under IFRS minority interests are presented as part of equity rather than a
liability as under previous CGAAP.
J) Deferred Taxes
Under IFRS, NAL is required to record deferred taxes at the trust level at 39
percent, being the tax rate applicable to the undistributed profit of the Trust.
Therefore, while a trust, the tax rate was significantly higher under IFRS
compared to previous CGAAP, as under previous CGAAP the rate used represented
the anticipated rate at time of the temporary difference reversal. On conversion
to a corporation, corporate tax rates apply, which resulted in a decrease to
previously recorded deferred tax amounts under IFRS at the trust level. Deferred
taxes have also been adjusted to reflect the tax effect arising from the
difference between IFRS and previous CGAAP as noted above. In addition, the
deferred tax impact to share issue costs has been reflected.
Under IFRS, all deferred tax is presented as a long term asset or liability.
Under previous CGAAP, future income tax presentation was based on the
presentation of the underlying asset or liability.
K) Other Exemptions
Business combinations
NAL elected the exemption not to restate Business Combinations, prior to January
1, 2010, in accordance with IFRS. There were no adjustments required to business
combinations prior to January 1, 2010.
The remaining IFRS1 exemptions were not applicable or material to the
preparation of NAL's Consolidated Balance Sheet on transition at January 1,
2010.
RECENT PRONONOUNCEMENTS ISSUED
All accounting standards effective for periods beginning on or after January 1,
2011 have been adopted as part of the transition to IFRS. The following new IFRS
pronouncements have been issued but are not effective and may have an impact on
the Corporation:
As of January 1, 2013, NAL will be required to adopt IFRS 9, Financial
Instruments, which is the result of the first phase of the IASB's project to
replace IAS 39, Financial Instruments: Recognition and Measurement. The new
standard replaces the current multiple classification and measurement models for
financial assets and liabilities with a single model that has only two
classification categories: amortized cost and fair value. The adoption of this
standard should not have a material impact on NAL's consolidated financial
statements.
CRITICAL ACCOUNTING ESTIMATES
Management is required to make judgments, assumptions and estimates in applying
its accounting policies and practices, which have a significant impact on the
financial results of the Corporation. The preceding discussion outlines the
Corporation's significant accounting policies and practices adopted under IFRS.
The following discussion outlines the accounting policies and practices
involving the use of estimates that are critical to determining NAL's financial
results.
Property, plant and equipment and Exploration and evaluation assets
Reserves estimates can have a significant impact on earnings, as they are a key
input to the Corporation's depletion calculations and impairment tests. Costs
accumulated within each area are depleted using the unit-of-production method
based on proved plus probable reserves using estimated future commodity prices
and costs. Costs subject to depletion include estimated future costs to be
incurred in developing proved and probable reserves. A downward revision in
reserves estimates or an increase in estimated future development costs could
result in the recognition of a higher depletion charge to net income.
D&P costs, are aggregated into cash-generating units ("CGU") based on their
ability to generate largely independent cash flows. If the carrying value of the
CGU exceeds the recoverable amount, the cash-generating unit is written down
with an impairment recognized in net income. E&E assets are assessed for
impairment, together with D&P assets in total, when they are reclassified to
property, plant and equipment, and/or if facts and circumstances suggest that
the carrying amount exceeds the recoverable amount. If an E&E impairment is
indicated when combined with the D&P assets, it is recognized through the
statement of income. The recoverable amount of an asset or cash-generating unit
is the greater of its fair value less costs to sell and its value in use. Fair
value less costs to sell may be determined using discounted future net cash
flows of proved and probable reserves using forecast prices and costs. A
downward revision in reserves estimates could result in the recognition of
impairments charged to net income.
Reversals of impairments are recognized when there has been a subsequent
increase in the recoverable amount. In this event, the carrying amount of the
asset or cash-generating unit is increased to its revised recoverable amount
with an impairment reversal recognized in net income, net of what depletion
would have been had the asset not been impaired.
All of NAL's oil and gas reserves and resources are evaluated and reported on by
independent qualified reserves evaluators. The estimation of reserves is a
subjective process. Forecasts are based on engineering data, projected future
rates of production, estimated commodity price forecasts and the timing of
future expenditures, all of which are subject to numerous uncertainties and
various interpretations. Reserves estimates can be revised upward or downward
based on the results of future drilling, testing, production levels and
economics of recovery based on cash flow forecasts. Contingent resources are not
classified as reserves due to the absence of a commercial development plan that
includes a firm intent to develop within a reasonable time frame.
Asset Retirement Obligations
Asset retirement obligations include present obligations where the Corporation
will be required to retire tangible long-lived assets such as producing well
sites, and natural gas processing plants. The asset retirement obligation is
measured at the present value of the expenditure to be incurred. The associated
asset retirement cost is capitalized as part of the cost of the related asset.
Changes in the estimated obligation resulting from revisions to estimated
timing, amount of cash flows or changes in discount rate are recognized as a
change in the asset retirement obligation and the related asset retirement cost.
Increases in the estimated asset retirement obligation and costs increase the
corresponding charges of accretion and depletion to net income. A decrease in
discount rates increases the asset retirement obligation, which increases future
accretion charged to net earnings. Actual expenditures incurred are charged
against the accumulated asset retirement obligation.
Goodwill
Goodwill, which represents the excess of purchase price over fair value of net
assets acquired, is assessed for impairment annually at December 31 of each
year. Goodwill is currently attributed to the area to which it relates.
To assess impairment, the goodwill carrying amount is compared to the
recoverable amount of the aggregated cash-generating units to which the goodwill
is allocated. If the carrying amount for the cash-generating unit exceeds the
recoverable amount, the associated goodwill is written down with an impairment
recognized in net income. Goodwill impairments are not reversed.
The recoverable amount is the greater of the cash-generating unit's fair value
less costs to sell and its value in use. Fair value less costs to sell may be
determined using discounted future net cash flow of proved and probable reserves
using forecast prices and costs. A downward revision in reserves estimates could
result in the recognition of a goodwill impairment charge to net income.
Income Taxes
NAL follows the balance sheet method of accounting for income taxes. Under this
method, deferred income taxes are recorded for the effect of any temporary
difference between the accounting and income tax basis of an asset or liability,
using the substantively enacted income tax rates. Current income taxes for the
current and prior periods are measured at the amount expected to be recoverable
from or payable to the taxation authorities based on the income tax rates
enacted or substantively enacted at the end of the reporting period. The
deferred income tax assets and liabilities are adjusted to reflect changes in
enacted or substantively enacted income tax rates that are expected to apply,
with the corresponding adjustment recognized in net income or in shareholders'
equity depending on the item to which the adjustment relates.
Tax interpretations, regulations and legislation in the various jurisdictions in
which the Corporation subsidiaries operate are subject to change. As such,
income taxes are subject to measurement uncertainty and the interpretations can
impact net income through the income tax expense arising from the changes in
deferred income tax assets or liabilities.
Derivative Financial Instruments
As described in the Risk Management section of this MD&A, derivative financial
instruments are used by NAL to manage its exposure to market risks relating to
commodity prices, foreign currency exchange rates and interest rates.
Derivative financial instruments are recorded at fair value. Instruments are
recorded in the balance sheet as either an asset or liability with changes in
fair value recognized in net income. Realized gains or losses are presented as
the contracts are settled. Unrealized gains and losses are presented at the end
of each respective reporting period based on the change in fair value and are
recognized in net income. The estimate of fair value of all derivative
instruments is based on approximation of the amounts that would be received or
paid to settle these instruments at the end of the period, with reference to
forward prices, foreign exchange rates and interest rates. The estimated fair
value of financial assets and liabilities is subject to measurement uncertainty.
Share-based Compensation
Share-based compensation is recognized over the vesting period, based on the
market price of the notional common share at each period end and an expected
performance multiplier and forfeiture rate, in the statement of income with a
corresponding increase or decrease in liabilities.
Dated: May 19, 2011
Consolidated Balance Sheet
(In thousands of Canadian dollars)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, 2010 January 1, 2010
March 31, 2011 (Note 14) (Note 14)
----------------------------------------------------------------------------
Assets
Current assets
Cash $ - $ 821 $ 1,604
Accounts receivable 55,226 57,839 61,631
Prepaids and other
receivables 8,467 14,532 15,663
Derivative contracts
(Note 12) - 422 6,285
----------------------------------------------------------------------------
63,693 73,614 85,183
Derivative contracts
(Note 12) 1,057 - 2,461
Deferred tax asset 41,276 49,380 34,627
Goodwill 14,722 14,722 14,722
Property, plant and
equipment (Note 5) 1,464,283 1,472,660 1,415,830
Exploration and
evaluation assets(Note
5) 65,822 63,127 88,122
----------------------------------------------------------------------------
$1,650,853 $1,673,503 $1,640,945
----------------------------------------------------------------------------
Liabilities and
Shareholders' Equity
Current liabilities
Accounts payable and
accrued liabilities 128,792 100,265 110,715
Note payable - - 8,907
Dividends payable to
shareholders 10,345 13,252 12,372
Derivative contracts
(Note 12) 31,235 7,819 11,231
----------------------------------------------------------------------------
170,372 121,336 143,225
Bank debt (Note 6) 255,306 266,965 230,713
Convertible debentures
(Note 7) 198,926 199,520 203,730
Other liabilities (Note
8) 3,253 3,012 7,173
Derivative contracts
(Note 12) - 2,503 -
Asset retirement
obligations (Note 10) 126,038 149,015 134,358
Deferred tax liability 26,996 35,402 51,199
----------------------------------------------------------------------------
780,891 777,753 770,398
Shareholders' equity
Share capital 897,500 890,777 -
Unitholders' capital - - 1,485,421
Equity component of
convertible
debentures(Note 7) 4,973 4,973 -
Minority interest - - 3,370
Deficit (32,511) - (618,244)
----------------------------------------------------------------------------
869,962 895,750 870,547
----------------------------------------------------------------------------
$1,650,853 $1,673,503 $1,640,945
----------------------------------------------------------------------------
Commitments (Note 13)
Common shares
outstanding (000's) 147,781 147,248 137,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Income (loss) and Comprehensive Income (loss)
(In thousands of Canadian dollars, except per share amounts)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
March 31,
2011 2010 (Note 14)
Revenue
Oil, natural gas and liquid sales $ 123,175 $ 138,520
Crown royalties (14,301) (16,558)
Freehold and other royalties (5,488) (6,041)
----------------------------------------------------------------------------
103,386 115,921
Gain (loss) on derivative contracts (Note 12):
Realized gain (998) 1,448
Unrealized gain (loss) (20,278) 18,509
----------------------------------------------------------------------------
(21,276) 19,957
Other income 281 331
----------------------------------------------------------------------------
82,391 136,209
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Expenses
Operating 27,257 28,070
Transportation 1,423 1,637
General and administrative 7,431 5,882
Share-based incentive compensation 636 686
Interest on bank debt 3,229 3,086
Interest and amortization on convertible
debentures 2,549 3,142
Fair value adjustment on convertible debentures - 632
Convertible debenture issue costs - 344
Gain on disposition of property, plant and
equipment (12,534) (11,193)
Impairment of oil and gas assets (Note 5) 5,200 -
Depletion and depreciation 46,412 48,265
Accretion on asset retirement obligations 2,544 2,701
----------------------------------------------------------------------------
84,147 83,252
----------------------------------------------------------------------------
Income (loss) before taxes (1,756) 52,957
Current tax expense (56) (59)
Deferred tax reduction(expense) 302 (2,729)
----------------------------------------------------------------------------
Total tax reduction(expense) 246 (2,788)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) and comprehensive income (loss) $ (1,510) $ 50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Attributable to:
Equity holders of the Corporation $ (1,510) $ 49,237
Minority interest - 932
----------------------------------------------------------------------------
Net income (loss) and comprehensive income
(loss) $ (1,510) $ 50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share (Note 11)
Basic (0.01) 0.36
Diluted (0.01) 0.35
----------------------------------------------------------------------------
Weighted average shares outstanding (000s) 147,534 137,660
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Cash Flows
(In thousands of Canadian dollars)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
March 31
2011 2010 (Note 14)
----------------------------------------------------------------------------
Operating Activities
Net income (loss) $ (1,510) $ 49,237
Items not involving cash:
Depletion and depreciation 46,412 48,265
Accretion on asset retirement obligations 2,544 2,701
Unrealized loss (gain) on derivative contracts 20,278 (18,509)
Gain on disposition of property, plant and
equipment (12,534) (11,193)
Fair value adjustment on convertible debentures - 632
Deferred tax expense (recovery) (302) 2,729
Minority interest - 314
Lease amortization (432) (376)
Impairment of oil and gas assets 5,200 -
Interest expense and amortization on convertible
debentures 5,778 6,228
Debenture issue costs - 344
Abandonment and reclamation (2,437) (891)
Change in non-cash working capital (2,014) (11,233)
----------------------------------------------------------------------------
60,983 68,248
----------------------------------------------------------------------------
Financing Activities
Dividends paid to shareholders (27,185) (31,969)
Increase (decrease) in bank debt (11,659) 13,982
Issue of shares, net of issue costs - (155)
Convertible debenture issue costs - (344)
Interest expense (5,684) (6,796)
Change in non-cash working capital (688) 568
----------------------------------------------------------------------------
(45,216) (24,714)
----------------------------------------------------------------------------
Investing Activities
Property, plant and equipment expenditures (80,781) (79,283)
Exploration and evaluation expenditures (2,789) (2,013)
Proceeds from dispositions 27,090 14,676
Disposition of Spearpoint - (309)
Change in non-cash working capital 39,892 26,833
----------------------------------------------------------------------------
(16,588) (40,096)
----------------------------------------------------------------------------
Increase (decrease) in cash (821) 3,438
Cash, beginning of period 821 1,604
----------------------------------------------------------------------------
Cash, end of period $ - $ 5,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Changes in Equity
(In thousands of Canadian dollars)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Equity
component
of
Number Shareholders convertible
of Shares Equity debentures
----------------------------------------------------------------------------
Balance at January 1, 2010 137,471 $1,485,421 $ -
Net income before minority interest - - -
Net income attributable to minority
interest - - -
Less issue costs (net of tax of $54) - (155) -
Issued from Distribution Reinvestment
Plan 410 5,179 -
Dividends declared - -
----------------------------------------------------------------------------
Balance at March 31, 2010 137,881 $1,490,445 -
Net income before minority interest - - -
Equity offering 7,550 100,038 -
Issue costs (net of tax of $1,692) - (4,869) -
Issued from Distribution Reinvestment
Plan 1,817 20,159 -
Dividends declared - - -
Dissolution of partnership - - -
Reclassification of deficit to share
capital (Note 1) - (714,996) -
Equity component of convertible
debentures on conversion to corporation - - 4,973
----------------------------------------------------------------------------
Balance at December 31, 2010 147,248 890,777 4,973
Net loss - - -
Issued from Distribution Reinvestment
Plan 533 6,723 -
Dividends declared - - -
----------------------------------------------------------------------------
Balance at March 31, 2011 147,781 $ 897,500 $ 4,973
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Minority Total
Deficit interest Equity
----------------------------------------------------------------------------
Balance at January 1, 2010 $(618,244) $ 3,370 $ 870,547
Net income before minority interest 50,169 - 50,169
Net income attributable to minority
interest (932) 314 (618)
Less issue costs (net of tax of $54) - - (155)
Issued from Distribution Reinvestment
Plan - - 5,179
Dividends declared (37,185) - (37,185)
----------------------------------------------------------------------------
Balance at March 31, 2010 $(606,192) $ 3,684 $ 887,937
Net income before minority interest 9,788 - 9,788
Equity offering - - 100,038
Issue costs (net of tax of $1,692) - - (4,869)
Issued from Distribution Reinvestment
Plan - - 20,159
Dividends declared (118,592) - (118,592)
Dissolution of partnership - (3,684) (3,684)
Reclassification of deficit to share
capital (Note 1) 714,996 - -
Equity component of convertible
debentures on conversion to corporation - - 4,973
----------------------------------------------------------------------------
Balance at December 31, 2010 - - 895,750
Net loss (1,510) - (1,510)
Issued from Distribution Reinvestment
Plan - - 6,723
Dividends declared (31,001) - (31,001)
----------------------------------------------------------------------------
Balance at March 31, 2011 $ (32,511) $ - $ 869,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
Notes to the consolidated interim financial statements
Three months ended March 31, 2011
(Tabular amounts in thousands of Canadian dollars, except per share amounts)
(unaudited)
1) NATURE OF OPERATIONS AND STRUCTURE OF THE CORPORATION
NAL Energy Corporation ("NAL" or the "Corporation") is engaged in the
exploration for, and the development and production of natural gas, natural gas
liquids and crude oil in Western Canada. The Corporation resulted from a
reorganization effective December 31, 2010 as part of a Plan of Arrangement
involving, among others, NAL Oil & Gas Trust (the "Trust"), the Corporation, and
the security holders of the Trust ("Reorganization").
Pursuant to the Reorganization, the Trust was restructured from an open-ended
unincorporated trust to NAL Energy Corporation, a publicly traded exploration
and development corporation. Unitholders of the Trust received one common share
of the Corporation for each trust unit held. The Corporation and its
subsidiaries now carry on the business formerly carried on by the Trust and its
subsidiaries. The outstanding convertible debentures of the Trust were assumed
by NAL and are now convertible into common shares of the Corporation, rather
than trust units of the Trust, with the same terms and conditions as those
previously agreed to by the Trust.
Pursuant to the Reorganization, share capital was reduced by the amount of the
deficit of the Trust on December 31, 2010.
The Reorganization to a corporation has been accounted for on a continuity of
interest basis and accordingly, the consolidated financial statements for 2010
and 2011 reflect the financial position, results of operations and cash flows as
if the Corporation had carried on the business formerly carried on by the Trust.
References to NAL or the Corporation in these financial statements for periods
prior to December 31, 2010 are references to the Trust and for periods after
December 30, 2010 are references to NAL Energy Corporation. Additionally, NAL or
the Corporation refers to shares, shareholders, and dividends which are
comparable to units, unitholders and distributions previously under the Trust.
The Corporation, as with the Trust, continues to be managed by NAL Resources
Management Limited (the "Manager"). The Manager is a wholly-owned subsidiary of
Manulife Financial Corporation ("MFC") and manages, on their behalf, NAL
Resources Limited ("NAL Resources"), another wholly-owned subsidiary of MFC. NAL
Resources and the Corporation maintain ownership interests in many of the same
oil and natural gas properties. NAL Resources operates these properties on
behalf of the Corporation and MFC. As a result, a significant portion of the net
operating revenues and capital expenditures represent joint operations amounts
from NAL Resources. These transactions are in the normal course of joint
operations and are based on the original exchange amounts established through
transactions with third parties.
The interim consolidated financial statements were authorized for issue by the
Board of Directors on May 19, 2011.
2) SUMMARY OF ACCOUNTING POLICIES
(a) Conversion to International Financial Reporting Standards ("IFRS") and
Statement of Compliance
These are the Corporation's first IFRS consolidated interim financial statements
as at March 31, 2011, including 2010 comparative periods. They comprise the
initial period of the Corporation's annual audited financial statements to be
issued under IFRS at December 31, 2011. As a result these interim consolidated
financial statements have been prepared in accordance with IFRS1 "First-time
Adoption of International Financial Reporting Standards" ("IFRS1") and IAS34
"Interim Financial Reporting". The consolidated interim financial statements do
not include all of the information required for full annual financial
statements.
An explanation of how the transition to IFRS has affected the reported financial
position, financial performance and cash flows of the Corporation is provided in
Note 14. That note includes reconciliations as at January 1, 2010, as at and for
the three months ended March 31, 2010 and as at and for the year ended December
31, 2010.
(b) Basis of Presentation
The Corporation's consolidated financial statements are stated in Canadian
dollars, which is the Corporation's functional currency, and include the
accounts of the Corporation and its subsidiary entities. The Corporation and its
subsidiary entities are all incorporated in Canada. All inter-entity
transactions and balances have been eliminated. The accounting policies set out
below have been applied consistently to all periods presented in these
consolidated condensed interim financial statements. They have also been applied
in preparing an opening IFRS statement of financial position as at January 1,
2010 for the purposes of the transition to IFRS, as required by IFRS1.
(c) Basis of Measurement
The consolidated financial statements have been prepared on the historical cost
basis except for the following:
- Convertible Debentures were classified as financial liabilities at fair value
through profit and loss until conversion to a corporation. Subsequent to the
Reorganization, the convertible debentures were bifurcated between debt and
equity, with the bond premium amortized over the period to maturity. The equity
portion is carried at the historic carrying amount determined at the time of
Reorganization, subject to any debenture conversions.
- Derivative contracts are classified at fair value through profit and loss.
The methods used to measure fair values are discussed within the notes to which
they relate.
(d) Use of Estimates and Judgments
The preparation of financial statements in conformity with IFRS requires
management to make judgments, estimates and assumptions that affect the
application of accounting policies and the reported amounts of assets,
liabilities, income and expenses. Actual results may differ from these
estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions
to accounting estimates are recognized in the period in which the estimates are
revised and in any future periods affected.
Reserve estimates including production profiles, future development costs, and
discount rates are a critical part of many of the estimated amounts and
calculations contained in the financial statements. These estimates are verified
by third party professional engineers, who work with information provided by the
Corporation to establish reserve determinations. These determinations are
updated at least on an annual basis, and more frequently as significant business
combinations take place.
Significant areas of estimation, uncertainty and critical judgments in applying
accounting policies that impact the amounts recognized in the interim
consolidated financial statements include:
- Impairment testing - estimates of reserves, future commodity prices, future
costs, production profiles, discount rates, and market value of land.
- Depletion and depreciation - oil and natural gas reserves, including future
prices, costs and reserve base to use on calculation of depletion.
- Asset Retirement Obligations ("ARO") - estimates relating to amounts,
likelihood, timing, inflation and discount rates.
- Share-based Compensation - forfeiture rates and performance factors.
- Derivatives - expected future oil and natural gas prices and expected
volatility in these prices, expected interest rates, expected future foreign
exchange rates.
- Deferred Tax - estimates of reversal of temporary differences, tax rates
substantively enacted, and likelihood of assets being realized.
- Provisions and Contingencies - estimates relating to onerous contracts,
including discount rates associated with long term contracts.
(e) Basis of Consolidation
Subsidiaries are entities controlled by the Corporation. Control exists when the
Corporation has the power to govern the financial and operating policies of an
entity so as to obtain benefits from its activities. In assessing control,
potential voting rights that are currently exercisable are taken into account.
The financial statements of subsidiaries are included in the consolidated
interim financial statements from the date that control commences until the date
that control ceases.
The purchase method of accounting is used to account for acquisitions of
subsidiaries and assets that meet the definition of a business under IFRS. The
cost of an acquisition is measured at the fair value of the assets given, equity
instruments issued and liabilities incurred or assumed at the date of exchange.
Identifiable assets acquired and liabilities and contingent liabilities assumed
in a business combination are measured initially at their fair values at the
acquisition date. The excess of the cost of acquisition over the fair value of
the identifiable assets, liabilities and contingent liabilities acquired is
recorded as goodwill. If the cost of acquisition is less than the fair value of
the net assets of the subsidiary acquired, the difference is recognized
immediately in the income statement.
(f) Joint Operations
Many of the Corporation's oil and natural gas activities involve jointly
controlled assets. The consolidated interim financial statements include the
Corporation's share of these jointly controlled assets and a proportionate share
of the relevant revenue and related costs.
(g) Financial Instruments
A financial instrument is any contract that gives rise to a financial asset of
one entity and to a financial liability or equity instrument of another entity.
Upon initial recognition, all financial instruments, including derivatives, are
recognized on the balance sheet at fair value. Subsequent measurement is then
dependent on the financial instruments being classified into one of five
categories: Financial liabilities or financial assets at fair value through
profit or loss, held to maturity investments, loans and receivables, available
for sale financial assets; or other financial liabilities.
The Corporation will assess at each reporting period whether a financial asset
is impaired. An impairment loss, if any, is included in net income.
Transaction costs are frequently attributable to the issue of a financial asset
or liability. For financial assets or liabilities measured at fair value through
profit and loss, these costs are expensed. For all other financial assets and
liabilities, these costs are netted in the initial carrying amount recorded.
(i) Non-derivative financial instruments
Non-derivative financial instruments comprise cash and cash equivalents,
accounts and other receivables, accounts payable and accrued liabilities,
dividends payable to shareholders, notes payable, convertible debentures and
bank debt. Non-derivative financial instruments are recognized initially at fair
value plus, for instruments not at fair value through profit and loss, any
directly attributable transaction costs. Subsequent to initial recognition,
non-derivative financial instruments are measured as described below.
Cash and cash equivalents comprises cash on hand, term deposits held with banks,
other short-term highly liquid investments with original maturities of three
months or less. The Corporation has classified cash and cash equivalents and
accounts and other receivables as loans and receivables, which are measured at
amortized cost less any impairment losses. Accounts payable and accrued
liabilities, dividends payable to shareholders, notes payable and bank debt are
classified as other financial liabilities which are measured at amortized cost,
which is determined using the effective interest method.
As a Trust, the convertible debentures were considered to contain an embedded
derivative related to the conversion feature. On transition to IFRS, an election
was made to treat the convertible debentures as a whole as a financial liability
at fair value through profit and loss, based on the debenture market value as at
the reporting date. On Reorganization, the embedded equity feature ceased to be
a derivative and the Company ceased to fair value the convertible debentures as
a whole, and the equity feature had to be bifurcated. Therefore, the fair value
of the convertible debenture was determined at that time, with the debt and
equity then recorded separately. Subsequent to the Reorganization, the equity
portion is recorded at its assigned cost and the debt portion is recorded at
amortized cost.
(ii) Derivative financial instruments
The Corporation has entered into certain financial derivative contracts in order
to manage exposure to market risks from fluctuations in commodity prices,
foreign exchange and interest rates. These instruments are not used for trading
or speculative purposes. The Corporation has not designated its financial
derivative contracts as effective accounting hedges, and thus not applied hedge
accounting, even though the Corporation considers all derivative contracts to be
effective economic hedges. As a result, all financial derivative contracts are
classified as fair value through profit or loss and are recorded on the balance
sheet at fair value. Proceeds and costs realized from holding the derivative
contracts are recognized in net income at the time each transaction under a
contract is settled. The fair value of derivative contracts is based on an
approximation of the amounts that would be received or paid to settle these
instruments at the end of the period, with reference to forward prices, foreign
exchange rates and interest rates.
The Corporation applies trade date accounting for the recognition of a purchase
or sale of short term investments and derivative contracts.
(iii) Unitholder's equity/share capital
The Trust's units are classified as equity. Incremental costs directly
attributable to the issue of trust units were recognized as a deduction from
equity, net of any tax effects.
Shares of the Corporation are classified as equity and are presented at cost net
of transaction costs, and any tax effects.
(iv) Impairment of Financial Assets
A financial asset is assessed at each reporting date to determine whether there
is any objective evidence that it is impaired, namely if one or more events have
had a negative effect on the estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is
calculated as the difference between its carrying amount and the present value
of the estimated future cash flows discounted at the original effective interest
rate.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an
event occurring after the impairment loss was recognized. For financial assets
measured at amortized cost, the reversal is recognized in profit or loss.
(h) Property, Plant and Equipment and Exploration and Evaluation Assets
(i) Recognition and measurement
Exploration and Evaluation ("E&E") expenditures:
Pre-license costs ("Pre-E&E"), or costs incurred before acquiring legal rights
to explore are recognized in the statement of income as incurred. Once a legal
right to explore has been established, but before technical feasibility and
commercial viability has been determined, costs are capitalized as E&E. E&E
expenditures can include the costs of acquiring licenses on exploratory lands or
assigned values on business acquisitions for possible reserves.
The technical feasibility and commercial viability of extracting oil and natural
gas resources is generally considered to be determinable when proved and/or
probable reserves exist. Upon determination of technical feasibility and
commercial viability, intangible E&E assets are first tested for impairment, and
then moved to Development and Production assets.
In addition, exploration and evaluation assets are assessed for impairment when
facts and circumstances suggest that the carrying amount exceeds the recoverable
amount.
Development and Production ("D&P") costs:
Items of property, plant and equipment ("PP&E"), which include oil and natural
gas development and production assets, are measured at cost, including asset
retirement costs, less accumulated depletion and depreciation and accumulated
net impairment losses.
D&P costs are accumulated on an Area basis and are grouped into cash generating
units ("CGUs) for impairment testing. CGUs are the smallest group of assets that
generate independent cash flows. NAL has defined nine CGUs.
Gains and losses on disposition of property, plant and equipment, property swaps
and farm-outs are recorded. Gains and losses are determined by comparing the
proceeds from disposal or fair value of the asset received with the disposed
amount of carrying amount of PP&E and ARO and are recognized in the Statement of
Income.
(ii) Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and
commercial viability and the costs of replacing parts of property, plant and
equipment are recognized as oil and natural gas interests only when they
increase the future economic benefits embodied in the specific asset to which
they relate. All other expenditures are recognized in profit or loss as
incurred. Such capitalized oil and natural gas interests generally represent
costs incurred in developing proved and/or probable reserves and bringing in or
enhancing production from such reserves, and are accumulated on a field or
geotechnical area basis. The carrying amount of any replaced or sold component
is derecognized. The costs of the day-to-day servicing of property, plant and
equipment are recognized in profit or loss as incurred.
(iii) Depletion and depreciation
The net carrying value of D&P assets is depleted on a unit of production basis
on proved and probable reserves, using estimated future prices and cost, and
taking into account estimated future development costs. Future development costs
are estimated taking into account the level of development required to produce
the reserves. These estimates are reviewed by independent reserve engineers at
least annually.
Depletion is calculated at a "component" level, which is defined as those parts
of assets with similar characteristics that are significant in relation to the
total cost of the asset. For the Corporation, components relating to D&P assets
are consistent with the areas determined by management.
Depreciation methods, useful lives, and residual values are reviewed at each
reporting date.
(iv) Impairment
The carrying amounts of the Corporation's D&P assets are reviewed at each
reporting date to determine whether there is any indication of impairment. If
any such indication exists, then the asset's recoverable amount is estimated.
Goodwill is allocated to CGUs on acquisition and for these CGUs, impairment is
tested each year end, or more frequently if indications of impairment exist.
E&E assets are assessed for impairment, together with D&P assets in total, when
they are reclassified to property, plant and equipment, and/or if facts and
circumstances suggest that the carrying amount exceeds the recoverable amount.
If an E&E impairment is indicated when combined with the D&P assets, it is
recognized through the statement of income.
For the purpose of impairment testing, D&P assets are grouped together into
CGUs. The recoverable amount of a CGU is the greater of its value in use and its
fair value less costs to sell. CGUs are reviewed annually for reasonableness and
continued applicability, or on a more frequent basis should conditions change
that would materially impact classification.
In assessing value in use, the estimated future cash flows are discounted to
their present value using a pre-tax discount rate that reflects current market
assessments of the time value of money and the risks specific to the asset.
Value in use is generally computed by reference to the present value of the
future cash flows expected to be derived from production of proved and probable
reserves.
Fair value less costs to sell is generally determined as the current market bid
price, when an active market exists. The intent is that this represents what a
market participant would pay to acquire control of the CGU.
An impairment loss is recognized if the carrying amount of an asset or its CGU
exceeds its estimated recoverable amount. Impairment losses are recognized in
the statement of income. Impairment losses recognized in respect of CGUs are
allocated first to reduce the carrying amount of any goodwill allocated to the
units and then to reduce the carrying amounts of the other assets in the unit on
a pro rata basis.
An impairment loss in respect of goodwill is not reversed. In respect of other
assets, impairment losses recognized in prior years are assessed at each
reporting date for any indications that the loss has decreased or no longer
exists. An impairment loss is reversed if there has been a change in the
estimates used to determine the recoverable amount. An impairment loss is
reversed only to the extent that the asset's carrying amount does not exceed the
carrying amount that would have been determined, net of depletion and
depreciation or amortization, if no impairment loss had been recognized.
(i) Goodwill
Goodwill arising through a business combination is assigned at the time
acquired, to a cash generating unit or units that are expected to benefit from
the synergies of the combination. It is measured at cost less accumulated
impairment losses. No amortization is recorded for goodwill.
Acquisitions prior to January 1, 2010:
As part of its transition to IFRS, the Corporation elected to restate only those
business combinations that occurred on or after January 1, 2010. In respect of
acquisitions prior to January 1, 2010, goodwill represents the amount recognized
under the Corporation's previous accounting framework, previous CGAAP.
Acquisitions on or after January 1, 2010:
For acquisitions on or after January 1, 2010, goodwill represents the excess of
the cost of the acquisition over the net fair value of the identifiable assets,
liabilities and contingent liabilities of the acquiree. When the excess is
negative, it is recognized immediately in profit for loss.
(j) Share-Based Incentive Compensation
The Manager has established a share-based incentive compensation plan (the
"Plan") for all employees. Under the Plan, employees receive cash compensation
based upon the value and overall return of a specified number of awarded
notional common shares on a fixed vesting date. The notional common shares are
in the form of Restricted Share Units ("RSUs") and Performance Share Units
("PSUs"). Dividends paid on the Corporation's outstanding common shares during
the vesting period are assumed to be reinvested in the awarded notional common
shares on the date of dividend. Compensation expense incorporates the common
share price and the number of RSUs and PSUs outstanding at each period end. In
addition, for the PSUs there is a performance multiplier which is based on the
Corporation's performance relative to its peers and may range from zero to two
times the value of the notional common shares held at vesting.
Compensation expense is recognized over the vesting period and is determined
based on the market price of the notional common shares at each period end and
an expected performance multiplier with a corresponding increase or decrease in
liabilities. Classification between current liabilities and long-term
liabilities is dependent on the expected payout date.
The Corporation charges the accrued compensation amounts relating to head office
employees to general and administrative expenses.
The Corporation has incorporated an estimated forfeiture rate for common shares
that will not vest, that is adjusted to reflect the actual number of awards that
vest.
(k) Provisions
A provision is recognized if, as a result of a past event, the Corporation has a
present legal or constructive obligation that can be estimated reliably, and it
is probable that an outflow of economic benefits will be required to settle the
obligation. Provisions are determined by discounting the expected future cash
flows at a pre-tax rate that reflects current market assessments of the time
value of money and the risks specific to the liability. Provisions are not
recognized for future operating losses.
(i) Asset Retirement Obligations
The Corporation's activities give rise to dismantling, decommissioning and site
disturbance re-mediation activities. Provision is made for the estimated cost of
site restoration and capitalized in the relevant asset category.
Asset retirement obligations are measured at the present value of management's
best estimate of expenditure required to settle the present obligation at the
balance sheet date. The discount rate applied is the credit adjusted risk free
rate. Subsequent to the initial measurement, the obligation is adjusted at the
end of each period to reflect the passage of time, changes in the estimated
future cash flows underlying the obligation, and the discount rate applied is
adjusted to the current applicable rate as at each reporting period. The
increase in the provision due to the passage of time is recognized as accretion
of asset retirement obligations whereas increases/decreases due to changes in
the estimated future cash flows are capitalized. Actual costs incurred upon
settlement of the retirement obligations are charged against the provision to
the extent the provision was established.
(ii) Onerous Contracts
A provision for onerous contracts is recognized by the Corporation when the
expected benefits to be derived from a contract are lower than the unavoidable
cost of meeting its obligations under the contract. The provision is measured at
the present value of the lower of the expected cost of terminating the contract
and the expected net costs of continuing with the contract. Before a provision
is established, the Corporation recognizes any impairment loss on associated
assets, if applicable.
(l) Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title
passes to the purchaser and if collection is reasonably assured.
(m) Income Tax
The Corporation is a taxable entity under the Income Tax Act (Canada).
As a Trust, the organization was a taxable entity under the Income Tax Act
(Canada) and until 2011 was taxable only on income that was not distributed or
distributable to unitholders, provided that the Trust continued to adhere to the
transition rules provided for under the Federal legislation. The Trust met the
criteria qualifying for income tax treatment permitting a tax deduction for
distributions paid to the unitholders in addition to other deductions available
in the Trust until its conversion to a Corporation on December 31, 2010.
Current and deferred tax expense is recognized in profit or loss except to the
extent that it relates to items recognized directly in equity, in which case it
is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year,
using tax rates enacted or substantively enacted at the reporting date, and any
adjustment to tax payable in respect of previous years.
Deferred tax is recognized using the balance sheet method, providing for
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or
liabilities in a transaction that is not a business combination. In addition,
deferred tax is not recognized for taxable temporary differences arising on the
initial recognition of goodwill. Deferred tax is measured at the tax rates that
are expected to be applied to temporary differences when they reverse, based on
the laws that have been enacted or substantively enacted by the reporting date.
Deferred tax assets and liabilities are offset if there is a legally enforceable
right to offset, and they relate to income taxes levied by the same tax
authority on the same taxable entity, or on different tax entities, with the
intent to settle current tax liabilities and assets on a net basis or the tax
assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future
taxable profits will be available against which the temporary difference can be
utilized. Deferred tax assets are reviewed at each reporting date and are
reduced to the extent that it is no longer probable that the related tax benefit
will be realized.
(n) Basic and Diluted per Share Calculation
Basic per share amounts are calculated by dividing net income by the weighted
average number of common shares outstanding. Diluted net income per share is
calculated using the "if converted method" to determine the dilutive effects of
the convertible debentures. Dilutive shares are arrived at by taking the
weighted average shares and the shares issuable on conversion of the convertible
debentures, giving effect to the potential dilution that would occur had
conversion occurred at the beginning of the period or on issuance of the
convertible instrument, whichever is later. Interest and accretion on
convertible debentures is added back to net income, net of tax in calculating
diluted net income per share/unit.
3) NEW IFRS STANDARDS
The International Accounting Standards Board ("IASB") has issued certain new
accounting standards and interpretations that are expected to have minimal
impact to the Corporation's financial statements.
The Corporation has reviewed new and revised accounting pronouncements that have
been issued but are not yet effective and determined that the following may have
an impact on the Corporation:
As at January 1, 2013, NAL will be required to adopt IFRS 9, "Financial
Instruments", which is the result of the first phase of the IASB's project to
replace IAS 39, "Financial Instruments: Recognition and Measurement". The new
standard replaces the current multiple classification and measurement models for
financial assets and liabilities with a single model that has only two
classification categories: amortized cost and fair value. The adoption of this
standard should not have a material impact on NAL's consolidated financial
statements.
4) RELATED PARTY TRANSACTIONS
NAL has several subsidiaries within its corporate structure. Two active entities
hold the working interests in the oil and gas properties being NAL Petroleum
Ltd. ("ACE") and Addison Energy Limited Partnership ("Addison"). The partners of
Addison are ACE and NAL.
In addition, there are several inactive subsidiaries, namely, NAL Canada West
Inc., NAL Properties Inc., Startech Energy and NAL Energy Inc.
The Corporation is managed by the Manager. The Manager is a wholly-owned
subsidiary of MFC and also manages on their behalf NAL Resources, another
wholly-owned subsidiary of MFC.
The Manager continues to provide certain services to the Corporation pursuant to
an Administrative Services and Cost Sharing Agreement. This agreement requires
the Corporation to reimburse the Manager, at cost, for general and
administrative ("G&A") expenses incurred by the Manager on behalf of the
Corporation. The Corporation paid $6.2 million (2010 - $3.6 million) for the
reimbursement of G&A expenses during the first quarter. The Corporation also
pays the Manager its portion of share-based compensation expense when cash
compensation is paid to employees under the terms of the Manager's incentive
compensation plans, of which $6.8 million has been paid in the first three
months of 2011 relating to notional shares that vested on November 30, 2010
(2010 - $6.9 million).
In conjunction with the Reorganization, a partnership that was jointly owned by
the Corporation and MFC was dissolved on December 31, 2010. This Partnership
held the assets acquired from the acquisitions of Tiberius and Spear in February
2008.
Prior to December 31, 2010 the Corporation, by virtue of being the owner of the
general partner of the Partnership, was required to consolidate the results of
the Partnership into its financial statements on the basis that the Corporation
had control over the Partnership. The Corporation had recorded a minority
interest in respect of the 50 percent ownership held by MFC. As a result of the
Partnership dissolution on December 31, 2010, the Corporation only reflects its
proportionate share of the Partnership's assets, liabilities, revenues and
expenses in the March 31, 2011 financial statements. Accordingly at March 31,
2011 and December 31, 2010, no minority interest was reflected on the balance
sheet. For the three months ended March 31, 2010, the minority interest in the
statement of income is comprised of:
Three months ended March 31
2011 2010
----------------------------------------------------------------------------
Net profits interest expense $ - $ 618
Share of net income attributable to MFC - 314
----------------------------------------------------------------------------
$ - $ 932
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As a part of the original structuring of the Partnership in 2008, both the
Corporation and MFC entered into net profit interest royalty agreements with the
Partnership. These agreements entitled each royalty holder to a 49.5 percent
interest in the cash flow from the Partnership's reserves.
In addition, in the Partnership there was a note payable to MFC, which was
settled on dissolution. At January 1, 2010, the note payable of $8.9 million was
included on consolidation of the Partnership, but was effectively eliminated
through the non-controlling interest. The note was due on demand, unsecured and
bore interest at prime plus three percent.
The following amounts are due to and from related parties as at March 31, 2011
and December 31, 2010 and have been included in prepaids and other receivables,
accounts payable and accrued liabilities and note payable on the balance sheet:
March 31, December 31,
2011 2010
----------------------------------------------------------------------------
Due from (to) NAL Resources Limited $ 2,556 $ 8,149
Due to NAL Resources Management Limited (2,094) (8,705)
Due (to) from Manulife Financial Corporation 34 (265)
----------------------------------------------------------------------------
$ 496 $ (821)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5) PROPERTY, PLANT AND EQUIPMENT AND EXPLORATION AND EVALUATION ASSETS
(i) Property, Plant and Equipment ("PP&E")
Three months ended March 31
2011 2010
----------------------------------------------------------------------------
Gross cost
Opening balance, beginning of period 1,673,359 $ 1,415,830
Additions 80,781 79,592
Asset retirement cost additions and revisions (414) 3,169
Disposals (41,442) (3,686)
Transfers from evaluation and exploration
assets 94 -
----------------------------------------------------------------------------
$ 1,712,378 $ 1,494,905
----------------------------------------------------------------------------
Accumulated depletion and impairment losses
Opening balance, beginning of period 200,699 $ -
Disposals (4,216) -
Depletion for the period 46,412 48,265
Impairment losses 5,200 -
----------------------------------------------------------------------------
$ 248,095 $ 48,265
----------------------------------------------------------------------------
Net book value
Opening balance, beginning of period $ 1,472,660 $ 1,415,830
Additions 80,367 82,761
Depletion for the period (46,412) (48,265)
Disposals (37,226) (3,686)
Transfers from evaluation and exploration
assets 94 -
Impairment losses (5,200) -
Reversal of impairment losses - -
----------------------------------------------------------------------------
$ 1,464,283 $ 1,446,640
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The calculation of first quarter depletion included future development costs for
proved plus probable reserves of $419.1 million (2010 - $404.2 million).
Undeveloped land amounting to $48.8 million (2010 - $51.0 million) is included
in PP&E assets and has not been included in the depletable base while
development activity is completed on this development acreage.
(ii) Exploration and evaluation assets
Three months ended March 31
2011 2010
----------------------------------------------------------------------------
Net book value
Opening balance, beginning of period $ 63,127 $ 88,122
Additions 2,789 2,013
Transfers to PP&E (94) -
----------------------------------------------------------------------------
$ 65,822 $ 90,135
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(iii) Impairment of oil and gas assets
During the first three months of 2011, impairment losses of $5.2 million were
recorded and reported as impairment of oil and gas assets in the statement of
income. The impairment related to D&P assets was calculated using the fair value
less costs to sell approach, which was based on the engineering report, using
future prices as at April 1, 2011 and future costs, discounted at a rate
commensurate with market transactions.
These impairment losses were recognized in three natural gas CGUs, which have no
goodwill assigned, and were the result of a further reduction in forward natural
gas prices as estimated by the Corporation's independent engineers.
6) BANK DEBT
The Corporation maintains a fully secured, extendible, revolving term credit
facility with a syndicate of Canadian chartered banks and one U.S. based lender.
The facility consists of a $535 million production facility and a $15 million
working capital facility. The total amount of the facility is determined by
reference to a borrowing base. The borrowing base is calculated by the bank
syndicate and is based on the net present value of the Corporation's oil and gas
reserves and other assets. Given that the borrowing base is dependent on the
Corporation's reserves and future commodity prices, lending limits are subject
to change on renewal.
The credit facility is fully secured by first priority security interests in all
existing and future acquired properties and assets of the Corporation and its
subsidiary and affiliated entities. The facility will revolve until April 30,
2012 at which time it may be extended for a further 364-day revolving period
upon agreement between the Corporation and the bank syndicate. If the credit
facility is not extended in April 2012, the amounts outstanding at that time
will be converted to a two-year term loan. The term loan will be payable in five
equal quarterly installments commencing May 1, 2013.
Amounts are advanced under the credit facility in Canadian dollars by way of
prime interest rate based loans and by issues of bankers' acceptances and in
U.S. dollars by way of U.S. based interest rate and Libor based loans. The
interest charged on advances is at the prevailing interest rate for bankers'
acceptances, Libor loans, lenders' prime or U.S. base rates plus an applicable
margin or stamping fee. The applicable margin or stamping fee, if any, varies
based on the consolidated debt-to-cash flow ratio of the Corporation. As at
March 31, 2011 and December 31, 2010 all amounts outstanding were in Canadian
dollars.
On March 31, 2011 the effective interest rate on amounts outstanding under the
credit facility was 5.05 percent (2010 - 3.33 percent). The Corporation's
interest charge includes this fixed interest rate component, plus a standby fee,
a stamping fee and the fee for renewal.
7) CONVERTIBLE DEBENTURES
Prior to the Reorganization, the convertible debentures were recorded at fair
value and classified as debt. On conversion to a Corporation on December 31,
2010, the fair value of the convertible debentures at that date was bifurcated
between debt and equity. As a result, $5.0 million of debt was re-classified as
equity, with the remaining debt premium to be amortized into income over the
term to maturity.
The following table reconciles the principal amount, debt component and
equity component of the convertible debentures:
Three months ended Year ended
March 31, 2011 December 31, 2010
----------------------------------------------------------------------------
6.25% 6.75% Total 6.25% 6.75% Total
----------------------------------------------------------------------------
Principal, beginning
of period 115,000 79,744 194,744 115,000 79,744 194,744
Issued during period - - - - - -
----------------------------------------------------------------------------
Principal, end of
period 115,000 79,744 194,744 115,000 79,744 194,744
----------------------------------------------------------------------------
Debt component,
beginning of period 116,506 83,014 199,520 119,600 84,130 203,730
Issued during period - - - - - -
Premium amortization (94) (500) (594) - - -
Fair value adjustment
to Dec 30, 2010 - - - 1,161 (398) 763
Reclassification to
equity - - - (4,255) (718) (4,973)
----------------------------------------------------------------------------
Debt component, end of
period 116,412 82,514 198,926 116,506 83,014 199,520
----------------------------------------------------------------------------
Equity component,
beginning of period 4,255 718 4,973 - - -
Reclassification from
debt - - - 4,255 718 4,973
Issued during period - - - - - -
----------------------------------------------------------------------------
Equity component, end
of period 4,255 718 4,973 4,255 718 4,973
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8) OTHER LIABILITIES
March 31, December 31,
2011 2010
----------------------------------------------------------------------------
Share-based incentive compensation (Note 9) $1,686 $1,009
Excess office lease obligation (1) $1,567 $2,003
----------------------------------------------------------------------------
$3,253 $3,012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the present value of the long-term portion of the office
lease obligation, in excess of a sub-lease, assumed on the acquisition
of Alberta Clipper Energy Inc. and Breaker Energy Ltd. MFC will
reimburse the Corporation for 50 percent of the Alberta Clipper
obligation of $0.7 million under a base price adjustment clause.
9) SHARE-BASED INCENTIVE COMPENSATION PLAN
The Manager has a long term incentive plan under which employees receive cash
compensation based upon the value and overall return of a specified number of
awarded notional shares on a fixed vesting date. The notional share grants are
in the form of Restricted Share Units ("RSUs") and Performance Share Units
("PSUs"). One third of each RSU grant vests on November 30 in each of the three
years after the date of grant. PSUs vest on November 30, three years after the
date of grant.
Pursuant to the Reorganization, all previously issued Restricted Trust Units and
Performance Trust Units were amended such that instead of them representing one
notional unit they represent one notional share on the same terms and continue
to be governed by the same terms under the Plan.
The Corporation recorded total share based compensation expense of $0.6 million
in the first three months of 2011 ($0.7 million was expensed through earnings
for the three months ended March 31, 2010). The compensation expense was based
on the March 31, 2011 share price of $13.23 (March 31, 2010 - $12.95), accrued
dividends, performance factors and the estimated number of shares vesting on
maturity.
A forfeiture rate is estimated on the grant date and is adjusted to reflect the
actual number of shares that vested. Forfeiture rates incorporated in the
calculations are 10 percent for a one year vest, 15 percent for a two year vest
and 20 percent for a three year vest.
The Corporation has a deferred share unit plan ("DSU") under which directors of
the Corporation receive cash compensation based upon the value and the overall
return of a specified number of notional shares. The notional shares vest on
retirement of the director.
The following table reconciles the change in total accrued share-based
incentive compensation relating to the plan:
Three months ended Year ended
March 31, December 31,
2011 2010
----------------------------------------------------------------------------
Balance, beginning of period $ 13,209 $ 15,759
Increase in liability 636 4,545
Cash payout, relating to shares vested(1) (7,386) (7,095)
----------------------------------------------------------------------------
Balance, end of period $ 6,459 $ 13,209
----------------------------------------------------------------------------
Current portion of liability(2) $ 4,773 $ 12,200
----------------------------------------------------------------------------
Long-term liability(3) $ 1,686 $ 1,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes cash payout under Directors' DSU plan of $0.5 million (December
31, 2010 - $0.3 million).
(2) Included in accounts payable and accrued liabilities.
(3) Included in other liabilities.
The following table sets forth a reconciliation of the Corporation's
incentive plan activity for the quarter ended March 31, 2011 and 2010.
2011
----------------------------------------------------------------------------
Number of Number of
Restricted Performance
Shares Shares Total
----------------------------------------------------------------------------
Balance, beginning of quarter 122,482 543,011 665,493
Allocation rate change(1) (6,859) (30,407) (37,266)
Issued 188,885 180,724 369,609
Exercised - - -
Forfeited (2,901) (8,569) (11,470)
----------------------------------------------------------------------------
Balance, end of quarter 301,607 684,759 986,366
----------------------------------------------------------------------------
Exercisable, end of quarter - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Allocation rate change reflects change in proportion of expenses charged
to the Corporation from the Manager based on relative production of the
Corporation and MFC.
2010
----------------------------------------------
Number of Number of
Restricted Performance
Shares Shares Total
----------------------------------------------------------------------------
Balance, beginning of quarter 295,121 670,030 965,151
Allocation rate change(1) 28,990 65,818 94,808
Issued 9,866 2,466 12,332
Exercised (106,237) - (106,237)
Forfeited (5,083) (21,600) (26,683)
----------------------------------------------------------------------------
Balance, end of quarter 222,657 716,714 939,371
----------------------------------------------------------------------------
Exercisable, end of quarter - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Allocation rate change reflects change in proportion of expenses charged
to the Corporation from the Manager based on relative production of the
Corporation and MFC.
10) ASSET RETIREMENT OBLIGATIONS
The following table reconciles the Corporation's asset retirement
obligations.
Three months ended Year ended
March 31, December 31,
2011 2010
----------------------------------------------------------------------------
Balance, beginning of period $149,015 $134,358
Accretion expense 2,544 11,006
Revisions to estimates (910) -
Liabilities incurred 496 4,515
Liabilities acquired - 6,797
Liabilities disposed (22,670) (1,044)
Liabilities settled (2,437) (6,617)
----------------------------------------------------------------------------
Balance, end of period $126,038 $149,015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL's estimated credit-adjusted risk-free rate of eight percent (2010 - eight
percent) and an inflation rate of two percent (2010 - two percent) were used to
calculate the present value of the asset retirement obligations.
11) NET INCOME (LOSS) PER SHARE
Basic net income (loss) per share is calculated using the weighted average
number of shares outstanding. The calculation of diluted net income per share
includes the weighted average shares potentially issuable on the conversion of
the convertible debentures. For the three months ended March 31, 2011, the
shares potentially issuable on the conversion of the convertible debentures are
anti-dilutive and are therefore excluded from the calculation. Total weighted
average shares issuable on conversion of the convertible debentures and excluded
from the diluted net income per share calculation for the three months ended
March 31, 2011 was 12,665,697, as they were anti-dilutive. For the three months
ended March 31, 2010, 12,665,697 common shares were included in the diluted
earnings per share calculation as they were dilutive. As at March 31, 2011, the
total convertible debentures outstanding were immediately convertible to
12,665,697 shares (March 31, 2010 - 12,665,697).
12) FINANCIAL RISK MANAGEMENT
Overview
The Corporation has exposure to the following risks from its use of financial
instruments: credit risk, liquidity risk and market risk.
This note presents information about the Corporation's exposure to each of the
above risks, the Corporation's objectives, policies and processes for measuring
and managing risk, and the Corporation's management of capital. Certain other
quantitative disclosures are included throughout these financial statements.
The Board of Directors has the responsibility to understand the principal risks
of the business and to achieve a proper balance between the risks incurred and
the potential return to shareholders. The Board of Directors has oversight for
ensuring systems are in place which effectively monitor and manage those risks
with a view to the long term viability of the Corporation.
Credit risk
Credit risk is the risk of financial loss to the Corporation if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Corporation's receivables. The
Corporation is managed by the Manager. The Manager is a wholly-owned subsidiary
of MFC and manages on its behalf NAL Resources, another wholly-owned subsidiary
of MFC. NAL Resources and the Corporation maintain ownership interests in many
of the same oil and natural gas properties in which NAL Resources is the
operator. As a result, a significant portion of the Corporation's net operating
revenues represent joint operations from NAL Resources. Accordingly, accounts
receivable include amounts due from NAL Resources for oil, natural gas and
natural gas liquids sales. Oil and gas marketing is conducted by the Manager on
behalf of the Corporation and NAL Resources, generally with large creditworthy
purchasers, for which the Corporation views the credit risk as low. NAL
Resources, and ultimately the Corporation, has not historically experienced any
collection issues with their oil and gas marketers. The Manager does not obtain
collateral from oil and natural gas marketers.
Cash and cash equivalents, when outstanding, consist of cash bank balances and
short-term deposits maturing in less than 90 days. Derivative contracts consist
of commodity contracts and foreign exchange rate contracts denominated in U.S.
dollars for periods of up to two years and interest rate contracts for periods
of up to five years. The Corporation manages the credit exposure related to
short-term investments and derivative contracts by dealing with established
counter-parties with high credit ratings and monitors all investments, avoiding
complex investment vehicles with higher risks such as asset backed commercial
paper. All derivative contract counterparties are Canadian chartered banks in
NAL's lending syndicate.
NAL management has reviewed its existing credit policy and has implemented more
regular reviews of purchasers to ensure credit worthiness given the current
market conditions.
The carrying amounts of cash, accounts and other receivables and derivatives
represent the maximum credit exposure.
The Corporation considers all amounts greater than 90 days to be past due.
Generally, the Corporation does not have amounts past due, due to receiving a
significant portion of net operating revenues from NAL Resources. No receivables
were past due as at March 31, 2011 and March 31, 2010.
Liquidity risk
Liquidity risk is the risk that the Corporation will not be able to meet its
financial obligations as they are due. The Corporation manages liquidity by
ensuring, as far as possible, that it will have sufficient liquidity under both
normal and stressed conditions.
The Corporation requires significant cash to fund capital programs necessary to
maintain or increase production and develop reserves, to acquire strategic oil
and gas assets, to repay maturing debt and to pay dividends.
The Corporation's capital programs are funded principally by internally
generated cash flows and undrawn committed borrowing facilities. The Corporation
also hedges a portion of its production to protect cash flow in the event of
commodity price declines. To support the capital spending program, the
Corporation maintains a fully secured, extendible, revolving term credit
facility, as outlined in Note 6.
The Corporation prepares annual capital expenditure budgets, which are regularly
monitored and updated as necessary. As well, the Manager utilizes authorizations
for expenditures on both operated and non-operated projects. Furthermore, the
Manager operates a high percentage of the Corporation's properties, which allows
for significant control over future expenditures.
The Corporation's non-derivative financial liabilities include its accounts
payable and accrued liabilities, dividends payable to shareholders, bank debt
and convertible debentures. The Corporation's derivative financial liabilities
include its commodity contracts. The following table outlines cash flows
associated with the maturities of the Corporation's financial liabilities.
The following are the contractual maturities of financial liabilities as at
March 31, 2011.
Non-Derivative Financial less than
Liability 1 Year 1 - 2 Years 2 - 5 Years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 128,792 $ - $ -
Dividends payable to
shareholders 10,345 - -
Bank debt, principal - - 255,306
Convertible debentures,
principal - 79,744 115,000
----------------------------------------------------------------------------
Total $ 139,137 $ 79,744 $ 370,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------
less than
Derivative Financial Liability 1 Year 1 - 2 Years 2 - 5 Years
----------------------------------------------------------------------------
Commodity contracts $ 31,235 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Market risk
Market risk is the risk that changes in market prices, such as foreign exchange
rates, commodity prices, and interest rates will affect the Corporation's net
income or the value of financial instruments.
Foreign currency exchange rate risk
Foreign currency exchange rate risk is the risk that the fair value or future
cash flows will fluctuate as a result of changes in foreign exchange rates.
Although substantially all of the Corporation's oil and natural gas sales are
denominated in Canadian dollars, the underlying market prices in Canada for oil
and natural gas are impacted by changes in the exchange rate between the
Canadian and U.S. dollar.
NAL's management has authorization from the Board to fix the exchange rate on up
to 50 percent of the Corporation's U.S. dollar exposure for periods of up to 24
months.
NAL has the following Canadian dollar / U.S. dollar foreign exchange option
contracts outstanding.
----------------------------------------------------------------------------
Fixed Notional
Rate (US) per Counterparty
(CAD/USD) month Term Floating Rate
----------------------------------------------------------------------------
1.05 $2.0 MM Apr 1, 2011 to Dec 31, 2011 BofC Monthly Average
Noon Rate
1.0608 $0.5 MM Apr 1, 2011 to Dec 31, 2011 BofC Monthly Average
Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL has a monthly commitment to settle the above fixed rates against the
Bank of Canada monthly average noon rate.
----------------------------------------------------------------------------
Option Monthly
Payout Notional Premium
Range (US) per Counterparty Received
(CAD/USD) month Term Floating Rate (CAD)
----------------------------------------------------------------------------
$0.93 - $1.01 $3.0 MM May 1, 2011 to BofC Monthly Average $60K
Dec 31, 2011 Noon Rate
$0.93 - $1.01 $2.0 MM Jan 1, 2012 to BofC Monthly Average $40K
Jun 30, 2012 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
When the monthly average noon spot foreign exchange rate is outside the payout
range, the monthly premium is forfeited. NAL is committed to selling the above
listed USD at the upper payout range value for that month when the average noon
spot foreign exchange rate exceeds the payout range.
----------------------------------------------------------------------------
Option Fixing Notional
Range (US) Counterparty
(CAD/USD) per month Term Floating Rate
----------------------------------------------------------------------------
$0.94 - $1.06 $0.5 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
$0.95 - $1.07 $0.5 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
$0.94 - $1.08 $0.5 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
$0.95 - $1.04 $0.5 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
$0.95 - $1.0125 $0.5 MM Apr 1, 2011 to BofC Monthly Average
Jun 30, 2012 Noon Rate
$0.95 - $1.0138 $1.0 MM Apr 1, 2011 to BofC Monthly Average
Jun 30, 2012 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
When the monthly average noon spot foreign exchange rate exceeds the lower
fixing rate, NAL is committed to selling the above listed USD at the upper
fixing rate for that month. To the extent the monthly average noon spot foreign
exchange rate is below the lower fixing rate, NAL has no commitment to sell USD.
----------------------------------------------------------------------------
Option
Fixing Notional
Range (US) Counterparty
(CAD/USD) per month Term Floating Rate
----------------------------------------------------------------------------
$1.05 - $1.15 $1.0 MM Apr 1, 2011 to BofC Monthly Average
Dec 31, 2011 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
When the monthly average noon spot foreign exchange rate exceeds the fixing
range, NAL is committed to selling the above listed USD at the lower fixing rate
for that month. To the extent the monthly average spot foreign exchange rate is
below the lower fixing rate, NAL has a commitment to sell the above listed USD
at the lower fixing rate. When the monthly average noon spot foreign exchange
rate falls within the fixing range, NAL has no commitment to sell USD.
The fair value of foreign exchange derivative contracts has been included on the
balance sheet with changes in the fair value reported separately on the
statement of income as unrealized gain (loss). As at March 31, 2011, if exchange
rates had strengthened by $0.01, with all other variables held constant, net
income for the period would have been $0.7 million higher, due to changes in the
fair value of the derivative contracts. An equal and opposite effect would have
occurred to net income had exchange rates been $0.01 weaker.
Commodity price risk
Commodity price risk is the risk that the fair value or future cash flows will
fluctuate as a result of changes in commodity prices. Commodity prices for oil
and natural gas are impacted by not only the relationship between the Canadian
and U.S. dollar, but also macroeconomic events that dictate the levels of supply
and demand. The Corporation has attempted to mitigate commodity price risk by
entering into financial derivative contracts. The Corporation's policy is to
enter into commodity contracts to a maximum of 60 percent of forecasted, net of
royalty, production volumes for a period of up to two years.
NAL has the following commodity risk derivative contracts outstanding:
CRUDE OIL Q2-11 Q3-11 Q4-11 Q1-12 Q2-12 Q3-12 Q4-12
----------------------------------------------------------------------------
US$ Collar Contracts
$US WTI Collar Volume
(bbl/d) 1,000 200 200 800 800 700 700
Bought Puts - Average
Strike Price ($US/bbl) 83.00 90.00 90.00 101.25 101.25 101.43 101.43
Sold Calls - Average
Strike Price ($US/bbl) 95.68 100.50 100.50 117.95 117.95 117.66 117.66
US$ Swap Contracts
$US WTI Swap Volume
(bbl/d) 4,900 5,700 5,700 500 500 500 500
Average WTI Swap Price
($US/bbl) 87.39 88.10 88.10 109.60 109.60 109.60 109.60
Total Oil Volume (bbl/d) 5,900 5,900 5,900 1,300 1,300 1,200 1,200
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Two calendar 2011 500 bbl/d swap contracts with an average price of $95.00
contain extendable call options. The extendible call option provides the
counterparty with the option to extend the contract into calendar 2012 under the
same price and volumetric terms. The counterparty can exercise this option any
time before December 31, 2011.
NATURAL GAS Q2-11 Q3-11 Q4-11 Q1-12 Q2-12 Q3-12 Q4-12
----------------------------------------------------------------------------
Swap Contracts
---------------
AECO Swap Volume (GJ/d) 20,000 21,000 21,000 24,000 5,000 5,000 3,674
AECO Average Price
($Cdn/GJ) 4.32 3.95 3.95 3.98 4.15 4.15 4.15
Total Natural Gas Volume
(GJ/d) 20,000 21,000 21,000 24,000 5,000 5,000 3,674
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair value of commodity derivative contracts has been included on the
balance sheet with changes in the fair value reported separately on the
statement of income as unrealized gain (loss). As at March 31, 2011, if oil and
natural gas liquids prices had been $1.00 per barrel lower and natural gas
prices $0.10 per Mcf lower, with all other variables held constant, net income
for the period would have been $1.9 million higher, due to changes in the fair
value of the derivative contracts. An equal and opposite effect would have
occurred to net income had oil and natural gas liquids prices been $1.00 per
barrel higher and natural gas $0.10 per Mcf higher.
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Corporation is exposed to interest rate
fluctuations on its bank debt, which bears a floating rate of interest. The
Corporation has attempted to mitigate interest rate risk by entering into
derivative contracts.
The contracts have a combined notional debt amount of $139 million and require
NAL to make fixed quarterly payments. In exchange, the counterparties are
required to pay the Corporation a floating rate of interest based on the average
rate for Canadian dollar bankers' acceptances. The Corporation's interest charge
includes this fixed interest rate component plus a standby fee, a stamping fee
and the fee for renewal. The Corporation's policy is to enter into interest rate
swap contracts to fix the interest rate on up to 50 percent of outstanding bank
debt for periods of up to five years.
NAL has the following interest rate derivative contracts outstanding:
----------------------------------------------------------------------------
Remaining Amount Corporation Counterparty
INTEREST RATE Term (Cdn$MM)(1) Fixed Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating Apr 2011 - $39.0 1.5864% CAD-BA-CDOR (3 months)
to fixed Dec 2011
Swaps-floating Apr 2011 - $22.0 1.3850% CAD-BA-CDOR (3 months)
to fixed Jan 2013
Swaps-floating Apr 2011 - $22.0 1.5100% CAD-BA-CDOR (3 months)
to fixed Jan 2014
Swaps-floating Apr 2011 - $14.0 1.8750% CAD-BA-CDOR (3 months)
to fixed Mar 2013
Swaps-floating Apr 2011 - $14.0 1.9850% CAD-BA-CDOR (3 months)
to fixed Mar 2014
Swaps-floating Apr 2011 - $14.0 1.8500% CAD-BA-CDOR (3 months)
to fixed Mar 2013
Swaps-floating Apr 2011 - $14.0 1.9300% CAD-BA-CDOR (3 months)
to fixed Mar 2014
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount
The fair value of interest rate derivative contracts has been included on the
balance sheet with changes in the fair value reported separately on the
statement of income as unrealized gain (loss). As at March 31, 2011, if interest
rates had been one percent lower, with all other variables held constant, net
income for the year would have been $2.9 million lower, due to changes in the
fair value of the derivative contracts. An equal and opposite effect would have
occurred to net income had interest rates been one percent higher.
Fair Value of Financial Instruments
The carrying amount of the Corporation's financial instruments, including
accounts receivable, accounts payable and accrued liabilities, and dividends
payable to shareholders, approximate their fair value due to their short term to
maturity.
The Corporation's bank debt and cash bear interest at floating market rates and,
accordingly, the fair market value approximates the carrying amount.
The fair value of the Corporation's convertible debentures is based on quoted
and observable market values, which is used to mark-to-market the convertible
debentures within the financial statements. On conversion to a Corporation, the
convertible debentures are no longer fair valued. The mark-to-market on the
convertible debentures is included in the December 31, 2010 convertible
debenture total of $199,520.
Other liabilities include share-based compensation liabilities as well as excess
office lease obligations.
Share-based compensation liabilities are recorded at fair value and are based
upon the outstanding shares, valued at the Corporation's share price at the
reporting date, performance factors and the number of shares vesting on maturity
and estimated forfeitures.
The excess office lease obligation represents the present value of the long-term
portion of office lease obligations, in excess of sub-leases, assumed on
previous business acquisitions.
Derivative commodity contracts are recorded at fair value on the balance sheet
as current or long-term, assets or liabilities, based on their fair values on a
contract-by-contract basis. The fair value of commodity contracts is determined
as the difference between the contracted prices and published forward curves
(ranging from US$105.10 per barrel to US$108.35 per barrel for oil and $3.59 per
GJ to $4.12 per GJ for natural gas) as of the balance sheet date, using the
remaining contracted oil and natural gas volumes with option contracts also
including an element of volatility. The fair value of the interest rate swaps is
determined by discounting the difference between the contracted interest rate
and forward bankers' acceptances rates (ranging from 0.956 percent to 2.192
percent) as of the balance sheet date, using the notional debt amount and
outstanding term of the swap. The fair value of the exchange rate derivatives is
calculated as the discounted value of the difference between the contracted
exchange rate and the market forward exchange rates (ranging from 0.9684 to
0.9813) as of the balance sheet date, using the notional U.S. dollar amount and
outstanding term of the swap. The fair value of the derivative contracts is as
follows:
March 31, December 31,
2011 2010
----------------------------------------------------------------------------
Fair value of commodity contracts $ (34,979) $ (13,717)
Fair value of interest rate swaps 1,012 706
Fair value of foreign exchange rate swaps 3,789 3,111
----------------------------------------------------------------------------
$ (30,178) $ (9,900)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The gain/(loss) on derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts $ (21,318) 1,546
Natural gas contracts 56 15,021
Interest rate swaps 306 191
Exchange rate swaps 678 1,751
----------------------------------------------------------------------------
Unrealized gain (loss) (20,278) 18,509
Realized gain (loss):
Crude oil contracts (3,127) (2,082)
Natural gas contracts 916 2,497
Interest rate swaps (129) (257)
Exchange rate swaps 1,342 1,290
----------------------------------------------------------------------------
Realized gain (loss) (998) 1,448
----------------------------------------------------------------------------
Gain (loss) on derivative contracts $ (21,276) $ 19,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------
These contracts are presented on the balance sheet as short term / long
term, assets and liabilities as follows:
March 31, December 31,
2011 2010
----------------------------------------------------------------------------
Current unrealized loss on derivative
contracts $ (31,235) $ (7,819)
Current unrealized gain on derivative
contracts - 422
----------------------------------------------------------------------------
Current unrealized loss on derivative
contracts $ (31,235) (7,397)
Long term unrealized gain on derivative
contracts 1,057 -
Long term unrealized loss on derivative
contracts - (2,503)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net fair value of derivative contracts $ (30,178) $ (9,900)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at March 31, 2011, the total fair value of derivative contracts was a net
liability of $30.2 million (December 31, 2010 - net liability of $9.9 million).
The change in the fair value for the quarter ended March 31, 2011 of $20.3
million has been recognized as an unrealized loss in the statement of income
(year ended December 31, 2010 - $7.4 million unrealized loss).
The following table reconciles the movement in the fair value of the
Corporation's derivative contracts:
Three months ended March 31
-----------------------------
2011 2010
----------------------------------------------------------------------------
Unrealized (loss), beginning of period $ (9,900) $ (2,485)
Unrealized (loss) gain, end of period (30,178) 16,024
----------------------------------------------------------------------------
Unrealized (loss) gain for the period (20,278) 18,509
Realized gain (loss) in the period (998) 1,448
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gain (loss) on derivative contracts $ (21,276) $ 19,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The financial instruments carried at fair value, being the derivative contracts,
are required to be classified into a hierarchy that prioritizes the inputs used
to measure the fair value. The three levels of the fair value hierarchy are:
Level 1: Unadjusted quoted prices in active markets for identical assets or
liabilities;
Level 2: Inputs other than quoted prices that are observable for the asset or
liability either directly or indirectly; and
Level 3: Inputs that are not based on observable market data.
Fair values are classified as Level 1 when the related derivative is actively
traded and a quoted price is available. If different levels of inputs are used
to measure a financial instrument's fair value, the classification within the
hierarchy is based on the lowest level input that is significant to the fair
value measurement. The following table illustrates the classification of the
financial instruments within the fair value hierarchy as at March 31, 2011:
----------------------------------------------------------------------------
Assets at fair value as at March 31, 2011
-------------------------------------------
Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Foreign exchange rate contracts - 3,789 - 3,789
Interest rate contracts - 1,012 - 1,012
----------------------------------------------------------------------------
- 4,801 - 4,801
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities at fair value as at
March 31, 2011
-------------------------------------------
Level 1 Level 2 Level 3 Total
----------------------------------------------------------------------------
Crude oil contracts - 34,979 - 34,979
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Management
The Corporation's policy is to maintain a strong and flexible capital base to
ensure that dividend levels are sustainable, while at the same time providing
the flexibility to take advantage of operational and acquisition opportunities.
The Corporation manages its capital structure and makes adjustments to it in
light of changes in economic conditions and the risk characteristics of the
underlying oil and natural gas assets. The Corporation considers its capital
structure to include common shares, bank debt, convertible debentures, other
liabilities, and working capital (excluding derivative contracts and future
income tax) as shown below. In order to maintain or adjust its capital
structure, the Corporation may adjust the amount of dividends paid to
shareholders, issue new shares, adjust its capital spending to modify debt
levels, or suspend/resume its DRIP programs.
The Corporation monitors its capital based on the ratio of its net debt to 12
months trailing funds from operations. This ratio, which is a non-GAAP measure,
is calculated as net debt as a proportion of funds from operations for the
previous 12 months. Funds from operations is defined as cash flow from operating
activities prior to the change in non-cash working capital. Net debt is defined
as bank debt, plus convertible debentures at face value, plus working capital
(excluding derivative contracts and future income tax balances and including
other liabilities). Net debt is measured with and without convertible
debentures. The Corporation's strategy is to maintain a conservative net debt to
12 month trailing funds from operations as compared to other oil and gas
companies, both before and after taking into account the convertible debentures.
The Corporation will, for the appropriate opportunity, increase its debt to
funds from operations ratio above the Corporation's average. In order to
facilitate the management of this ratio, the Corporation prepares an annual
budget which is approved by the Board of Directors. On a monthly basis a
reforecast for the year is prepared based on updated commodity prices, results
of operational activity and other events. The monthly forecast is provided to
the Board of Directors.
As at March 31, 2011, the Corporation had a total net debt to 12 months trailing
funds from operations ratio of 2.00 (March 31, 2010 - 2.03), as calculated in
the table below. The increase in the net debt to 12 months trailing funds from
operations ratio in 2011 is attributable to a relatively higher total net debt
increase compared to the increase in funds from operations.
The Corporation has no restrictions on the issuance of common shares.
There has been no change in the approach to capital management during the first
quarter of 2011.
Capitalization
March 31, December 31, March 31,
2011 2010 2010
----------------------------------------------------------------------------
Shareholders' equity ($000s) 869,962 895,750 887,937
Bank debt ($000s) 255,306 266,965 244,695
Working capital deficit(1) ($000s) 78,697 43,337 63,760
----------------------------------------------------------------------------
Net debt excluding convertible
debentures 334,003 310,302 308,455
Convertible debentures ($000s)(2) 194,744 194,744 194,744
----------------------------------------------------------------------------
Net debt 528,747 505,046 503,199
Net debt excluding convertible
debentures to trailing 12-month
cash flow(3) 1.26 1.11 1.24
Total net debt to trailing
12-month cash flow(3) 2.00 1.80 2.03
Common shares outstanding (000s) 147,781 147,248 137,881
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital and other liabilities, excludes derivative contracts,
deferred tax and note with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt divided by funds from operations for the previous
12 months.
13) COMMITMENTS
(i) Joint Venture Agreement
Effective April 20, 2009, the Corporation and MFC entered into a joint venture
agreement with a senior industry partner. The arrangement consists of a three
year commitment to spend $50 million on or before August 31, 2012, that provides
the Corporation and MFC an opportunity to earn an interest in freehold and crown
acreage. The Corporation has a 65 percent interest in this agreement and MFC a
35 percent interest. The three year commitment to the Corporation is $32.5
million. The agreement is exclusive and structured to be extendible for up to an
additional six years for a total potential commitment of $150 million ($97.5
million net to the Corporation) to earn an interest in over 150 (97.5 net)
sections of freehold and crown acreage. If the capital spending commitments are
not met, interests in the freehold and crown acreage will not be earned and the
Corporation will not be required to pay unspent commitment amounts under the
arrangement. As at March 31, 2011, the Corporation has spent $14.0 million under
this agreement.
(ii) Farm-in Agreement
Effective August 10, 2009, the Corporation and MFC entered into a farm-in
agreement with a senior industry partner. The arrangement consists of a two year
initial commitment, with a minimum capital commitment of $40 million in the
first year and $57 million in the second year, with an option for a third year,
at NAL's election, for an additional commitment of $50 million. The Corporation
has a 60 percent interest in this agreement and MFC a 40 percent interest. The
agreement provides the opportunity to earn an interest in approximately 1,400
gross sections of undeveloped oil and gas rights in Alberta held by the partner.
If the capital spending commitments are not met, interest in the acreage will
not be earned and the Corporation will not be required to pay any unspent
amounts. As at March 31, 2011, the Corporation has spent $36.7 million under
this agreement and met its first year commitment.
(iii) Other
NAL has entered into several contractual obligations as part of conducting
day-to-day business. NAL has the following commitments for the next five years:
----------------------------------------------------------------------------
($000s) 2011 2012 2013 2014 2015
----------------------------------------------------------------------------
Office lease(1) $ 1,431 $ 2,146 $ 2,132 $ 2,092 $ 2,092
Office lease - Clipper
and Breaker(2) 1,473 2,211 364 - -
Transportation agreement 3,126 2,352 2,209 1,030 124
Processing agreements(3) 466 197 184 - -
Convertible debentures(4) - 79,744 - 115,000 -
Bank debt - - 153,146 102,098 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total $ 6,496 $ 86,650 $158,035 $220,220 $ 2,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the Corporation's share of office lease commitments,
including both base rent and operating costs, in relation to the lease
held by the Manager, of which the Corporation is allocated a pro rata
share (currently approximately 60 percent) of the expense on a monthly
basis.
(2) Represents the full amount of the office leases assumed with the
acquisitions of Clipper and Breaker. MFC will reimburse the Corporation
for 50 percent of the Clipper obligation under the base price adjustment
clause.
(3) Represents gas processing agreements with take or pay components.
(4) Principal amount.
14) TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS ("IFRS")
As stated in Note 2, these interim consolidated financial statements are the
first set of financial statements presented by the Corporation in accordance
with Canadian generally accepted accounting principles for publicly accountable
enterprises (being IFRS as adopted by the Canadian AcSB). Accordingly, these
interim consolidated financial statements have been prepared in accordance with
IFRS1, "First- time adoption of International Financial Reporting Standards" and
with IAS 34,. "Interim Reporting" as issued by the IASB. Previously the
Corporation prepared its consolidated financial statements in accordance with
previous Canadian GAAP ("CGAAP"). The accounting policies as set out in Note 2
outline the basis for the preparation of these financial statements.
IFRS1 requires the presentation of comparative information as at the January 1,
2010 transition date and subsequent comparative periods as well as the
consistent and retroactive application of IFRS accounting policies. To assist
with the transition, IFRS1 outlines certain mandatory exceptions and optional
exemptions that NAL could elect to eliminate the need for retroactive
application of standards in certain circumstances.
In preparing the opening IFRS balance sheet, the Corporation has adjusted
amounts reported previously in financial statements prepared in accordance with
previous CGAAP. Reconciliations of previous CGAAP to IFRS as required by IFRS1
are set out in the tables which follow. A summary of the significant policy
changes and exemptions are discussed in the notes that follow the
reconciliations.
Reconciliation of Equity at January 1, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
January 1, 2010 January 1, 2010
as stated under as restated
CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Assets
Current assets
Cash $ 1,604 $ - $ 1,604
Accounts receivable 61,631 - 61,631
Prepaids and other
receivables 15,663 - 15,663
Derivative contracts 6,285 - 6,285
Future income tax
assets 3,132 (3,132) J -
----------------------------------------------------------------------------
88,315 (3,132) 85,183
Derivative contracts 2,461 - 2,461
Goodwill 14,722 - 14,722
Deferred tax asset - 34,627 J 34,627
Property, plant and
equipment 1,503,952 (88,122) A 1,415,830
Exploration and
evaluation assets - 88,122 A 88,122
----------------------------------------------------------------------------
$ 1,609,450 $ 31,495 $ 1,640,945
----------------------------------------------------------------------------
Liabilities and
Shareholders' Equity
Current liabilities
Accounts payable and
accrued liabilities $ 110,897 $ (182) G $ 110,715
Note payable 8,907 - 8,907
Dividends payable to
shareholders 12,372 - 12,372
Derivative contracts 11,231 - 11,231
----------------------------------------------------------------------------
143,407 (182) 143,225
Bank debt 230,713 - 230,713
Convertible debentures 177,977 25,753 H 203,730
Other liabilities 7,643 (470) G 7,173
Asset retirement
obligations 127,872 6,486 F 134,358
Deferred income tax
liability 24,778 26,421 J 51,199
Minority interest 2,868 (2,868) I -
----------------------------------------------------------------------------
715,258 55,140 770,398
Shareholders' equity
Share capital 1,482,029 3,392 J 1,485,421
Equity component of
convertible debentures 12,628 (12,628) H -
Minority interest - 3,370 I 3,370
Deficit (600,465) (17,779) (618,244)
----------------------------------------------------------------------------
894,192 (23,645) 870,547
----------------------------------------------------------------------------
$ 1,609,450 $ 31,495 $ 1,640,945
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Equity at March 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, 2010 March 31, 2010
as stated as restated
under CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Assets
Current assets
Cash $ 5,042 $ - $ 5,042
Accounts receivable 51,255 - 51,255
Prepaids and other
receivables 11,301 - 11,301
Derivative contracts 24,714 - 24,714
----------------------------------------------------------------------------
92,312 - 92,312
Derivative contracts 2,652 - 2,652
Goodwill 14,722 - 14,722
Deferred tax asset - 35,847 J 35,847
Property, plant and
equipment 1,511,167 (64,527) A - F 1,446,640
Exploration and
evaluation assets - 90,135 A 90,135
----------------------------------------------------------------------------
$ 1,620,853 $ 61,455 $ 1,682,308
----------------------------------------------------------------------------
Liabilities and
Shareholders' Equity
Current liabilities
Accounts payable and
accrued liabilities $ 111,495 (135) G $ 111,360
Note payable 8,331 - 8,331
Dividends payable
to shareholders 12,409 - 12,409
Derivative contracts 11,342 - 11,342
Deferred tax
liability 1,665 (1,665) J -
----------------------------------------------------------------------------
145,242 (1,800) 143,442
Bank debt 244,695 - 244,695
Convertible debentures 178,624 25,738 H 204,362
Other liabilities 8,135 (546) G 7,589
Asset retirement
obligations 131,917 7,219 F 139,136
Deferred income tax
liability 17,818 37,329 J 55,147
Minority interest 3,042 (3,042) I -
----------------------------------------------------------------------------
729,473 64,898 794,371
Shareholders' equity
Share capital 1,487,053 3,392 J 1,490,445
Equity component of
convertible debentures 12,628 (12,628) H -
Minority interest - 3,684 I 3,684
Deficit (608,301) 2,109 (606,192)
----------------------------------------------------------------------------
891,380 (3,443) 887,937
----------------------------------------------------------------------------
$ 1,620,853 $ 61,455 $ 1,682,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Equity at December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2010 as 2010 as
stated restated
under CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Assets
Current assets
Cash $ 821 $ - $ 821
Accounts receivable 57,839 - 57,839
Prepaids and other
receivables 14,532 - 14,532
Derivative contracts 422 - 422
Future income tax
assets 3,830 (3,830) J -
----------------------------------------------------------------------------
77,444 (3,830) 73,614
Deferred tax asset 17,152 32,228 J 49,380
Goodwill 14,722 - 14,722
Property, plant and
equipment 1,503,546 (30,886) A - F 1,472,660
Exploration and
evaluation assets - 63,127 A 63,127
----------------------------------------------------------------------------
1,612,864 60,639 1,673,503
----------------------------------------------------------------------------
Liabilities and
Shareholders' Equity
Current liabilities
Accounts payable and
accrued liabilities 100,837 (572) G 100,265
Note payable - - -
Dividends payable to
shareholders 13,252 - 13,252
Derivative contracts 7,819 - 7,819
----------------------------------------------------------------------------
121,908 (572) 121,336
Bank debt 266,965 - 266,965
Convertible debentures 181,672 17,848 H 199,520
Other liabilities 3,057 (45) G 3,012
Derivative contracts 2,503 - 2,503
Asset retirement
obligations 144,738 4,277 F 149,015
Deferred tax liability - 35,402 J 35,402
----------------------------------------------------------------------------
720,843 56,910 777,753
Shareholders' equity
Share capital 879,393 11,384 J 890,777
Equity component of
convertible debentures 12,628 (7,655) H 4,973
Deficit - - -
----------------------------------------------------------------------------
892,021 3,729 895,750
----------------------------------------------------------------------------
$ 1,612,864 $ 60,639 $ 1,673,503
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Net Income for the three months ended March 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
March 31, 2010 March 31, 2010
as stated as restated
under CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Revenue
Oil, natural gas and
liquid sales $ 138,520 $ - $ 138,520
Crown royalties (17,105) 547 B (16,558)
Freehold and other
royalties (6,041) - (6,041)
----------------------------------------------------------------------------
115,374 547 115,921
Gain on derivative
contracts:
Realized gain 1,448 - 1,448
Unrealized gain 18,509 - 18,509
----------------------------------------------------------------------------
19,957 - 19,957
Other income 331 - 331
----------------------------------------------------------------------------
135,662 547 136,209
----------------------------------------------------------------------------
Expenses
Operating 29,304 (1,234) B 28,070
Transportation 1,637 - 1,637
General and
administrative 4,359 1,523 B 5,882
Share-based incentive
compensation 439 247 B 686
Interest on bank debt 3,086 - 3,086
Interest and accretion
on convertible debentures 4,133 (991) H 3,142
Fair value adjustment
on convertible debentures - 632 H 632
Convertible debenture
issue costs - 344 H 344
Gain on disposition of
property, plant and
equipment - (11,193) E (11,193)
Depletion and
depreciation 62,036 (13,771) C 48,265
Accretion on asset
retirement obligations 2,631 70 F 2,701
----------------------------------------------------------------------------
107,625 (24,373) 83,252
----------------------------------------------------------------------------
Income before taxes 28,037 24,920 52,957
Current tax expense (59) - (59)
Deferred tax reduction
(expense) 2,163 (4,892) J (2,729)
----------------------------------------------------------------------------
Total tax reduction
(expense) 2,104 (4,892) (2,788)
----------------------------------------------------------------------------
Net income and
comprehensive income $ 30,141 $ 20,028 $ 50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Attributable to:
Equity holders of the
Corporation $ 29,349 $ 19,888 $ 49,237
Minority interest 792 140 932
----------------------------------------------------------------------------
Net income and
comprehensive income $ 30,141 $ 20,028 $ 50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per share
Basic $ 0.21 $ 0.15 $ 0.36
Diluted $ 0.21 $ 0.14 $ 0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Net Income for the year ended December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2010 2010
as stated as restated
under CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Revenue
Oil, natural gas and
liquid sales $ 497,538 $ - $ 497,538
Crown royalties (65,032) 2,132 B (62,900)
Freehold and other
royalties (23,585) - (23,585)
----------------------------------------------------------------------------
408,921 2,132 411,053
Gain (loss) on
derivative contracts:
Realized gain 24,446 - 24,446
Unrealized loss (7,415) - (7,415)
----------------------------------------------------------------------------
17,031 - 17,031
Other income 1,403 - 1,403
----------------------------------------------------------------------------
427,355 2,132 429,487
----------------------------------------------------------------------------
Expenses
Operating 117,523 (5,612) B 111,911
Transportation 6,501 - 6,501
General and
administrative 16,393 7,821 B 24,214
Share-based incentive
compensation 3,170 1,462 B 4,632
Corporate conversion
costs 1,483 - 1,483
Interest on bank debt 11,794 - 11,794
Interest and accretion
on convertible debentures 16,562 (4,041) H 12,521
Fair value adjustment
on convertible debentures - 763 H 763
Convertible debenture
issue costs - 345 H 345
Gain on disposition
of property, plant and
equipment - (17,596) E (17,596)
Depletion and
depreciation 251,343 (50,556) C 200,787
Impairment of oil and
gas assets - 32,804 D 32,804
Accretion on asset
retirement obligations 12,112 (1,106) F 11,006
----------------------------------------------------------------------------
436,881 (35,716) 401,165
----------------------------------------------------------------------------
Income (loss) before
taxes (9,526) 37,848 28,322
Current tax recovery 782 - 782
Deferred tax reduction 41,154 (11,233) J 29,921
----------------------------------------------------------------------------
Total tax expense 41,936 (11,233) 30,703
----------------------------------------------------------------------------
Net income and
comprehensive income $ 32,410 $ 26,615 $ 59,025
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per share
Basic $ 0.23 $ 0.18 $ 0.41
Diluted $ 0.23 $ 0.18 $ 0.41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Cash Flows for the three months ended March 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
March 31, 2010 March 31, 2010
as stated as restated
under CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Operating Activities
Net income $ 29,349 19,888 $ 49,237
Items not including
cash:
Depletion and
depreciation 62,036 (13,771) C 48,265
Accretion on asset
retirement obligations 2,631 70 F 2,701
Unrealized loss (gain)
on derivative contracts (18,509) - (18,509)
Gain on disposition of
property, plant and
equipment - (11,193) E (11,193)
Fair value adjustment
on convertible
debentures - 632 H 632
Deferred tax
(reduction) expense (2,163) 4,892 J 2,729
Non-controlling
interest 174 140 I 314
Lease amortization (376) - (376)
Interest expense - 6,228 6,228
Convertible debenture
issue costs - 344 344
Non-cash accretion
expense on convertible
debentures 991 (991) H -
Abandonment and
reclamation (891) - (891)
----------------------------------------------------------------------------
73,242 6,239 79,481
Change in non-cash
working capital (9,594) (1,639) (11,233)
----------------------------------------------------------------------------
63,648 4,600 68,248
----------------------------------------------------------------------------
Financing Activities
Distributions paid to
shareholders (31,969) - (31,969)
Increase in bank debt 13,982 - 13,982
Issue of shares, net
of issue costs (155) - (155)
Convertible debenture
issue costs (344) - (344)
Interest expense - (6,796) (6,796)
Change in non-cash
working capital - 568 568
----------------------------------------------------------------------------
(18,486) (6,228) (24,714)
----------------------------------------------------------------------------
Investing Activities
Additions to property,
plant and equipment (78,319) (964) (77,283)
Additions to
exploration and
evaluation assets - (2,013) (2,013)
Property acquisitions (1,974) 1,974 -
Proceeds from
dispositions 14,676 - 14,676
Disposition of
Spearpoint (309) - (309)
Change in non-cash
working capital 24,202 2,631 26,833
----------------------------------------------------------------------------
(41,724) 1,628 (40,096)
----------------------------------------------------------------------------
Increase in cash 3,438 - 3,438
Cash, beginning of
period 1,604 - 1,604
----------------------------------------------------------------------------
Cash, end of period $ 5,042 $ - $ 5,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Cash Flows for the year ended December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2010 2010 as
as stated restated
under CGAAP Adjustments Notes under IFRS
----------------------------------------------------------------------------
Operating Activities
Net income $ 32,410 26,615 $ 59,025
Items not including
cash:
Depletion and
depreciation 251,343 (50,556) C 200,787
Accretion on asset
retirement obligations 12,112 (1,106) F 11,006
Unrealized loss (gain)
on derivative contracts 7,415 - 7,415
Gain on disposition of
property, plant and
equipment - (17,596) E (17,596)
Fair value adjustment
on convertible
debentures - 763 H 763
Impairment of oil and
gas properties - 32,804 32,804
Deferred tax
(reduction) expense (41,154) 11,233 J (29,921)
Lease amortization (1,655) - (1,655)
Interest expense - 24,315 24,315
Convertible debenture
issue costs - 345 345
Non-cash accretion
expense on convertible
debentures 4,040 (4,040) H -
Abandonment and
reclamation (6,617) - (6,617)
----------------------------------------------------------------------------
257,894 22,777 280,671
Change in non-cash
working capital (3,754) 35 (3,719)
----------------------------------------------------------------------------
254,140 22,812 276,952
----------------------------------------------------------------------------
Financing Activities
Distributions paid to
shareholders (129,559) - (129,559)
Increase in bank debt 36,252 - 36,252
Issue of shares, net
of issue costs 94,466 - 94,466
Convertible debenture
issue costs (345) - (345)
Interest expense - (29,044) (29,044)
Change in non-cash
working capital - 4,729 4,729
----------------------------------------------------------------------------
814 (24,315) (23,501)
----------------------------------------------------------------------------
Investing Activities
Additions to property,
plant and equipment (203,038) (41,118) (244,156)
Additions to
exploration and
evaluation assets - (25,986) (25,986)
Property acquisitions (68,607) 68,607 -
Proceeds from
dispositions 22,178 - 22,178
Acquisition of Breaker (901) - (901)
Disposition of
Spearpoint (309) - (309)
Change in non-cash
working capital (4,968) - (4,968)
----------------------------------------------------------------------------
(255,645) 1,503 (254,142)
----------------------------------------------------------------------------
(Decrease) Increase in
cash (691) (691)
Cash, beginning of year 1,604 1,604
Dissolution of partnership (92) (92)
----------------------------------------------------------------------------
Cash, end of year $ 821 $ - $ 821
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A) Property, plant and equipment (PP&E) and Exploration and evaluation assets (E&E)
The Corporation elected to apply the IFRS1 exemption available to entities which
followed full cost accounting under previous CGAAP. This exemption permits the
total carrying value of PP&E and E&E under IFRS on transition to equal the
carrying value under previous CGAAP, subject to an impairment test. In addition,
conversion to IFRS requires the allocation of the carrying amount of the full
cost pool under previous CGAAP to E&E, and to components and CGUs for PP&E
assets. Firstly, E&E assets were recorded at the carrying amount under previous
CGAAP. The remaining previous CGAAP carrying amount was then allocated, pro-rata
to components (Areas) for D&P assets ("PP&E"), based on proved plus probable
reserve values, using the present values at a 10 percent discount rate.
Impairment tests were completed on transition, resulting in no impairment charge
to PP&E or E&E at January 1, 2010.
E&E assets are required to be segregated from D&P assets. At January 1, 2010
these assets were $88.1 million, representing their carrying value under
previous CGAAP. These assets comprise possible reserves assigned as a result of
business acquisitions. As at March 31, 2010 and December 31, 2010, NAL's E&E
assets were $90.1 million and $63.1 million, respectively.
Under previous CGAAP these assets were included in the full cost pool as PP&E,
in accordance with the CICA's full cost accounting guideline. Under IFRS, these
costs are initially recorded as E&E, on determination of technical feasibility
and commercial viability of the assets the capitalized costs are moved to PP&E.
B) Capitalized costs - PP&E
Under IFRS, employee costs included in general and administrative charges and
share-based compensation charges are capitalized to the extent they are directly
attributable to PP&E and E&E. The Corporation has adjusted its capitalization
policy to comply with IFRS. For the year ended December 31, 2010, $9.3 million
of such costs are expensed under IFRS that were originally capitalized under
previous CGAAP. For the three months ended March 31, 2010 $1.8 million were
expensed.
Additionally for the year ended December 31, 2010, lease rentals of $7.7 million
were expensed under previous CGAAP, while under IFRS the Corporation has elected
to capitalize these amounts. For the three months ended March 31, 2010, $1.9
million has been capitalized.
C) Depreciation and depletion
Under previous CGAAP, depletion was based on NAL's single cost centre, on a unit
of production basis using total proved reserves. Costs subject to depletion
excluded possible reserve locations and undeveloped land.
Under IFRS, depletion is provided for at a component level, defined as an Area
by NAL, on a unit of production basis using total proved plus probable reserves.
Costs subject to depletion are D&P assets excluding land under development.
For the year ended December 31, 2010, depletion decreased by $50.6 million from
previous CGAAP, primarily a result of the change in depletion base to proved
plus probable reserves. For the three months ended March 31, 2010 depletion
decreased by $13.8 million. There was no impact to January 1, 2010 due to the
IFRS1 election discussed above.
D) Impairment
Under previous CGAAP, impairment was recognized if the carrying amount exceeded
the undiscounted cash flows from proved reserves for NAL's single cost centre.
The amount of impairment was then measured as the amount by which the carrying
value of the cost centre exceeded the sum of proved plus probable reserves
discounted at a risk free rate plus the cost of unproved interests and land, net
of impairment. Impairments recognized under previous CGAAP were not reversed.
Under IFRS, an impairment is recognized if the carrying value exceeds the
recoverable amount for a cash-generating unit ("CGU"). If the carrying value
exceeds the recoverable amount of the CGU, the CGU is written down with an
impairment recognized in net income. Impairments under IFRS are reversed when
there has been a subsequent increase in recoverable amounts. Impairment
reversals are recognized in net income and the carrying amount of the CGU is
increased.
For the year ended December 31, 2010, NAL recognized a $32.8 million impairment
loss relating to gas focused CGUs in Alberta, northeast British Columbia and
Ontario. The impairment recognized was based on the difference between the
December 31, 2010 net book value of the CGUs and the recoverable amount. The
recoverable amount was determined using fair value less costs to sell based on
discounted future cash flows of proved plus probable reserves. Under previous
CGAAP, these assets were included in the one cost centre, which was not impaired
at December 31, 2010.
E) Gains on dispositions
Under previous CGAAP, gains on dispositions were typically not recognized.
Proceeds from dispositions were deducted from the full cost pool unless the
deduction resulted in a change to the depletion rate of 20 percent or more, in
which case a gain or loss was recorded.
Under IFRS, gains or losses are recorded on dispositions of properties and are
calculated as the difference between the proceeds and the net book value of the
assets disposed of at the point of disposition. For the year ended December 31,
2010, NAL recognized $17.6 million as gains on disposition, compared to no gain
recognized under previous CGAAP. A gain of $11.2 million was recognized for the
three months ended March 31, 2010.
F) Asset Retirement Obligations and Accretion
Under previous CGAAP, the asset retirement obligations were measured at the
estimated fair value of the expenditures expected to be incurred. Liabilities
were not remeasured to reflect period end discount rates.
Under IFRS, the asset retirement obligation is measured as the best estimate of
the expenditure to be incurred and requires the liability to be remeasured using
the period end discount rate.
As NAL elected the oil and gas assets IFRS1 exemption, the ARO exemption
available to full cost entities was also elected. This exemption allows for the
remeasurement of ARO on IFRS transition with the offset to retained earnings.
The carrying value under previous CGAAP at December 31, 2009 of $127.9 million
was revalued under IFRS, resulting in an opening IFRS balance at January 1, 2010
of $134.4 million. On transition to IFRS, NAL recorded the difference of $6.5
million as an increase to the liability with an offset to retained earnings. At
December 31, 2010, the liability was increased by $4.3 million. The adjustments
primarily reflect the remeasurement of the obligation using an 8% discount rate
at both dates.
In addition, accretion of the liability is impacted by the change in the
recognized amount. For the year ended December 31, 2010, accretion decreased by
$1.1 million as compared to previous CGAAP.
G) Other Liabilities and Accounts Payable
The adjustment to the liability for share-based compensation is to reflect a
forfeiture rate which was not included under previous CGAAP. On transition to
IFRS, the payable was reduced by $0.7 million to reflect the inclusion of a
forfeiture rate. For the full year 2010, the expense for share-based
compensation increased by $1.5 million due to the expensing of amounts
capitalized under previous CGAAP, offset slightly by the inclusion of a
forfeiture rate.
H) Convertible Debentures
As a trust, NAL designated its convertible debentures as a financial liability
at fair value through profit or loss on transition. As at January 1, 2010, the
fair value of the Corporation's convertible debentures was $203.7 million, based
on quoted market prices. Under previous CGAAP, the convertible debentures were
bifurcated between debt and equity in the amounts of $178.0 million and $12.6
million, respectively at December 31, 2009. The difference between the fair
value and CGAAP carrying value was charged to retained earnings on transition.
At each quarter end, the convertible debentures were fair valued based on the
then prevailing market price with the adjustment taken to income. Any accretion
expense previously recognized through income under previous CGAAP was
eliminated. On conversion to a corporation, on December 31, 2010, the
convertible debentures carrying value, which represented the fair value on
December 31, 2010, was bifurcated between their debt and equity components, as
required under IFRS.
On December 31, 2010, the fair value of the convertible debentures was $204.5
million, which following the corporate conversion was allocated $5.0 million to
equity and $199.5 million to debt.
In addition, for the period the convertible debentures were held at fair value
through profit and loss any issue costs associated with the convertible
debentures were expensed, of which $0.3 million was expensed in 2010. Under
previous CGAAP these issue costs were netted against the debt component of the
convertible debentures.
I) Minority Interest
The mandatory exception under IFRS1 allows for the prospective application in
the accounting for a minority interest.
Therefore, the minority interest has only been adjusted under IFRS to reflect
the changes to the income statement and net assets of the jointly owned
Partnership with MFC (Note 4) as compared to previous CGAAP.
Under IFRS, minority interests are presented as part of equity rather than a
liability as under previous CGAAP.
J) Deferred Taxes
Under IFRS, NAL is required to record deferred taxes at the Trust level at 39
percent, being the tax rate applicable to the undistributed profit of the Trust.
Therefore, while a trust, the tax rate was significantly higher under IFRS
compared to previous CGAAP, as under previous CGAAP the rate used represented
the anticipated rate at time of the temporary difference reversal. On conversion
to a corporation, corporate tax rates apply, which resulted in a decrease to
previously recorded deferred tax amounts under IFRS at the trust level. Deferred
taxes have also been adjusted to reflect the tax effect arising from the
difference between IFRS and previous CGAAP as noted above. In addition, the
deferred tax impact to share issue costs has been reflected.
Under IFRS, all deferred tax is presented as a long-term asset or liability.
Under previous CGAAP, future income tax presentation was based on the
presentation of the underlying asset or liability.
K) Other Exemptions
Business combinations
NAL elected the exemption not to restate business combinations, prior to January
1, 2010, in accordance with IFRS. There were no adjustments required to business
combinations prior to January 1, 2010.
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