CALGARY, ALBERTA--(Marketwire - Nov. 9,
2010) - NAL Oil & Gas Trust ("NAL" or the "Trust") (TSX:NAE.UN)
today announced its financial and operational results for the third
quarter of 2010. All amounts are in Canadian dollars unless otherwise
stated.
"NAL's third quarter and year to date performance positions the
Trust to deliver on its full year guidance for 2010" stated Mr. Andrew
Wiswell, President and CEO.
2010 THIRD QUARTER HIGHLIGHTS
- Third quarter 2010 funds from operations of $60.0 million
represents an 11 percent increase over the same period a year ago. Key
drivers include a 26 percent increase in production plus higher
commodity prices partially offset by a higher Canadian dollar and lower
realized hedging gains ($11.1 million versus $18.8 million in the third
quarter of 2009).
- NAL's third quarter production volumes of 29,473 boe/d increased
by 25 percent year over year but were impacted by wet weather
conditions, pipeline interruptions and unanticipated third party plant
turnaround activity. Nine month average volumes of 29,732 boe/d
represent an increase of 27 percent over the same period in 2009.
- Operating netbacks before hedging improved to $23.26 per boe
compared to $22.77 per boe in the third quarter of 2009. Year-to-date,
operating netbacks before hedging improved by 28 percent to $26.63 per
boe compared to $20.78 a year earlier.
- Capital expenditures totaled $55.4 million drilling 41 gross (20.2
net) wells in the third quarter. Drilling, completion and tie-in
activities represented 86 percent of the program in which the Trust:
-- participated in six (three net) Cardium wells in the Garrington
and Cochrane areas delivering results consistent with forecast type
curves. One of these wells, the 3-17 (65 percent working interest)
Cochrane well is outperforming expectations with first month production
at rates of 300-400 boe/d. There will be an additional seven (3.5 net)
wells drilled in the fourth quarter completing 2010 oil programs;
-- drilled 24 (10.6 net) wells in Saskatchewan, primarily targeting
Mississippian oil at Alida, Steelman and Hoffer with results that
continue to meet expectations. The Trust intends to drill nine (4.5 net)
horizontal Mississippian oil wells in the fourth quarter with current
drilling activity focused on evaluating significant multi-zone potential
on the acreage offsetting Hoffer, and;
-- drilled five (100 percent working interest) Wabamun and Leduc oil wells at Irricana and Millard Lake.
- Subsequent to quarter end, the Trust drilled and completed a
second Wilrich well in the Edson area that was testing at gross rates
over 10 mmcf/d (70 percent working interest). Production for this well
is expected to be on stream in December 2010, and;
- Year-to-date the Trust has invested approximately $60 million in
land and seismic through crown sales and acquisitions adding significant
positions in core areas as part of an ongoing strategy for organic
resource development and positioning for future opportunity.
2010 GUIDANCE
NAL's guidance ranges remain unchanged. Full year average production
volumes are expected to be around the mid-point of the 29,500 - 30,500
boe/d range with capital expenditures and operating costs per boe in
line.
Current 2010 Guidance
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Production (boe/d) 29,500 - 30,500
Capital expenditures ($MM)(1) 210
Operating costs ($/boe) 10.75 - 11.25
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(1) Before Alberta Drilling Credits
CORPORATE CONVERSION
On October 20, 2010, NAL announced that its board of directors (the
"Board"), unanimously approved the conversion of the Trust to a dividend
paying exploration and production ("E&P") corporation to be named
NAL Energy Corporation (the "Corporation"). Completion of the conversion
is anticipated to occur on or about December 31, 2010. The change in
structure from a trust to a corporation does not affect the business
plan or disciplined operational and financial focus of NAL.
Following completion of the conversion, NAL's corporate strategy
will remain focused on delivering a total return focusing on income with
modest growth. Effective with the proposed conversion to a corporation
and commencing with the January 2011 dividend payable in February 2011,
NAL anticipates paying a monthly dividend of $0.07 per share, compared
to the current monthly cash distribution of $0.09 per unit. From a
Canadian taxable shareholder perspective, the new dividend level will be
approximately equivalent, on an after tax basis, to the current
distribution.
Consistent with NAL's current policy, the Board will continue to
assess dividend levels taking into consideration commodity prices,
internal capital investment opportunities, forecasted cash flow,
financial market conditions, availability of financing and taxability.
2011 OUTLOOK
NAL management remains encouraged by current drilling and
development programs in the Trust's core Mississippian and Cardium light
oil regions of southeast Saskatchewan and central Alberta. A
preliminary view of NAL's development program for 2011 will see the
Trust continue to direct approximately 75 - 85 percent of the proposed
development capital toward light oil projects and remain relatively
balanced between Cardium oil projects in Alberta and Mississippian oil
projects in Saskatchewan.
Based upon success in the 2010 development program, NAL's
preliminary estimates for the 2011 capital development program are in
the range of $200 - $230 million, assuming commodity prices of
US$83.00/bbl West Texas Intermediate ("WTI") and C$4.25/GJ AECO and a
CAD/USD foreign exchange rate of $0.97. Based upon this range of
spending, the annual average production is expected to be between 30,000
- 31,500 boe/d in 2011.
Consistent with the Trust's budget and planning process, NAL intends
to provide its detailed 2011 guidance and operational plans at the end
of January 2011.
As previously disclosed, the Trust initiated a divestment sales
process for approximately 1,100 boe/d (net to the Trust). Bidding closed
September 30, 2010 and discussions with potential purchasers is
ongoing.
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 guidance for full year 2010 and the outlook for
2011 set forth above.
NON-GAAP MEASURES
Please refer to the discussion of non-GAAP measures set forth under
the Management's Discussion and Analysis regarding the use of the
following terms: "funds from operations", "payout ratio" and "operating
netback".
CONFERENCE CALL DETAILS
At 3:30 p.m. MST (5:30 p.m. EST) on November 9, 2010, NAL will hold a
conference call to discuss the third quarter 2010 results. Mr. Andrew
Wiswell, President and CEO, will host the conference call with other
members of the management team. The call is open to analysts, investors
and all interested parties. If you wish to participate, call
1-866-226-1792 toll free across North America. The conference call will
also be accessible through the internet at
http://events.digitalmedia.telus.com/nal/110910/index.php
A recorded playback of the call will be available until November 16, 2010 by calling 1-800-408-3053, reservation 4188048.
Notes: (1) All amounts are in Canadian dollars unless otherwise stated.
(2) 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
(thousands of dollars, except per unit and boe data)
(unaudited)
-------------------------------------
Three months Nine months
ended Sept. 30 ended Sept. 30
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2010 2009 2010 2009
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FINANCIAL
Revenue (1) 115,755 86,298 374,149 249,610
Cash flow from operating activities 82,082 52,999 189,056 183,235
Cash flow per unit - basic 0.56 0.47 1.32 1.77
Cash flow per unit - diluted 0.54 0.44 1.28 1.64
Funds from operations 60,018 53,766 195,944 167,788
Funds from operations per
unit - basic 0.41 0.48 1.37 1.62
Funds from operations per
unit - diluted 0.40 0.44 1.32 1.50
Net income (loss) (781) 8,249 36,614 3,566
Distributions declared 39,529 30,290 116,075 87,528
Distributions per unit 0.27 0.27 0.81 0.85
Basic payout ratio:
based on cash flow from operating
activities 48% 57% 61% 48%
based on funds from operations 66% 56% 59% 52%
Basic payout ratio including capital
expenditures (2):
based on cash flow from operating
activities 119% 137% 155% 100%
based on funds from operations 163% 135% 150% 110%
Units outstanding (000's)
Period end 146,621 112,327 146,621 112,327
Weighted average 146,297 112,109 142,890 103,444
Capital expenditures (2) 58,510 42,376 176,863 96,264
Property acquisitions
(dispositions), net 88 - 30,466 2,534
Corporate acquisitions, net (3) 901 11,035 1,210 48,385
Net debt, excluding convertible
Debentures (4) 300,551 293,680 300,551 293,680
Convertible debentures
(at face value) 194,744 79,744 194,744 79,744
OPERATING
Daily production (5)
Crude oil (bbl/d) 11,404 9,467 11,610 9,725
Natural gas (Mcf/d) 92,518 69,706 92,255 68,778
Natural gas liquids (bbl/d) 2,650 2,334 2,746 2,244
Oil equivalent (boe/d) 29,473 23,418 29,732 23,433
OPERATING NETBACK ($/boe)
Revenue before hedging gains 42.69 40.06 46.10 39.02
Royalties (7.83) (6.94) (8.41) (6.99)
Operating costs (11.72) (10.52) (11.17) (11.42)
Other income (6) 0.12 0.17 0.11 0.17
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Operating netback before hedging 23.26 22.77 26.63 20.78
Hedging gains 4.20 8.84 2.33 10.82
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Operating netback 27.46 31.61 28.96 31.60
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(1) Oil, natural gas and liquid sales less transportation costs and prior
to royalties and hedging.
(2) Excludes property and corporate acquisitions, and is net of drilling
incentive credits of $3.6 million for the quarter ended September 30,
2010 and $9.9 million for the nine months ended September 30, 2010.
(3) Represents total consideration for corporate acquisitions including
fees.
(4) Bank debt plus working capital and other liabilities, excluding
derivative contracts, notes payable/receivable and future income tax
balances.
(5) Includes royalty interest volumes.
(6) Excludes minimal Trust interest paid on notes with Manulife Financial
Corporation.
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 and nine month periods ended September 30, 2010
and the audited consolidated financial statements and MD&A for the
year ended December 31, 2009 of NAL Oil & Gas Trust ("NAL" or the
"Trust"). It contains information and opinions on the Trust'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.
NON-GAAP FINANCIAL MEASURES
Throughout this discussion and analysis, Management uses the terms
funds from operations, funds from operations per unit, payout ratio,
cash flow from operations per unit, 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 Trust's principal business activities.
Management uses the terms to facilitate an understanding of the results
of operations. However, these terms do not have any standardized meaning
as prescribed by Canadian Generally Accepted Accounting Principles
("GAAP"). Investors should be cautioned that these measures should not
be construed as an alternative to net income determined in accordance
with GAAP 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 GAAP. 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 distributions. Funds from operations per
unit and cash flow from operations per unit are calculated using the
weighted average units outstanding for the period.
Payout ratio is calculated as distributions 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 future income tax balances.
The following table reconciles cash flows from operating activities to
funds from operations:
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Three months Nine months
ended September 30 ended September 30
-----------------------------------------
$(000s) 2010 2009 2010 2009
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Cash flow from operating activities 82,082 52,999 189,056 183,235
Add back change in non-cash working
capital (22,064) 767 6,888 (15,447)
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Funds from operations 60,018 53,766 195,944 167,788
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FORWARD-LOOKING INFORMATION
This discussion and analysis contains forward-looking information as
to the Trust'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 distributions to unitholders; reserves and reserves
values; 2010 production; the future tax treatment of the Trust; the
future corporate conversion of the Trust; the Trust'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; future results from operations; payout ratios; cost
estimates and royalty rates; drilling plans; tie-in of wells; future
development, exploration and acquisition 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, NAL
has 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 distributions that NAL intends to pay; the cost of expanding
property holdings; the ability to obtain equipment in a timely manner
to carry out exploration development activities; the ability to market
our oil and natural gas successfully to current and new customers; the
impact of increasing competition; the ability to obtain financing on
acceptable terms; and the ability to add production and reserves through
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: failure to obtain unitholder,
court, regulatory, or third party approval for the corporate
conversion; 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
volatility in 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 Trust including the Trust'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 the MD&A is made as of the date of this MD&A. The
forward-looking information contained in the MD&A is expressly
qualified by this cautionary statement.
EXPLORATION & DEVELOPMENT ACTIVITIES
The Trust spent $47.8 million on drilling, completion and tie-in
operations during the third quarter of 2010, compared to $34.6 million
during the third quarter of 2009, and drilled 41 (20.2 net) wells in the
third quarter, compared to 26 (12.3 net) wells during the same period
in 2009. NAL had up to eight rigs running through the quarter with up to
four rigs working in Saskatchewan and four in Alberta. Continuous rain
lead to one month of lost drilling days and numerous delays in moving
equipment for completions and tie-ins and disruptions to trucking
operations. As a result of poor field conditions, a significant portion
of the production from third quarter drilling was also delayed by
approximately one month.
The Trust has drilled 108 (52.8 net) wells year-to-date and is
planning to drill an additional 16 (8 net) wells during the remainder of
2010.
With NAL's multi-year inventory of locations in oil resource style
plays, the Trust expects to commence a strong drilling program in
January 2011 with 10 rigs operating across Alberta and Saskatchewan.
Third Quarter Drilling Activity
Crude Oil Natural Gas Service Wells
---------------------------------------------------
Gross Net Gross Net Gross Net
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Operated wells 35 18.8 1 0.7 0 0
Non-operated wells 1 0.1 4 0.6 0 0
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Total wells drilled 36 18.9 5 1.3 0 0
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Dry & Abandoned Total
-----------------------------------
Gross Net Gross Net
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Operated wells 0 0 36 19.5
Non-operated wells 0 0 5 0.7
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Total wells drilled 0 0 41 20.2
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Southeast Saskatchewan (Alida, Nottingham, Steelman, Hoffer)
In Saskatchewan, there were 24 (10.6 net) horizontal oil wells
drilled during the third quarter. Activity was focused on the
Mississippian in Alida, Steelman and Hoffer. Drilling in Hoffer
continues to meet expectations and facility engineering for a full scale
central battery is expected to be completed by the end of the fourth
quarter. The Trust intends to drill nine (4.5 net) additional horizontal
Mississippian oil wells in the fourth quarter with current drilling
activities focused on evaluating significant multi-zone potential on new
land blocks offsetting Hoffer with some development drilling in Alida,
Parkman and Midale.
Alberta (Cochrane, Garrington, Irricana, Edson)
In Alberta, NAL participated in drilling 17 (9.6 net) locations
including six (3.0 net) oil wells in the Cardium at Garrington and
Cochrane with five (100 percent working interest) Wabamun and Leduc
drills at Irricana and Millard Lake. The Trust also participated in five
(1.3) net gas wells in the greater Edson/Pine Creek area with
completions and tie-ins planned for the fourth quarter.
Test results in the Cardium are in line with Garrington type curves
supporting first month production rates averaging 175 boe/d. The 3-17
(65 percent WI) Cochrane well is outperforming expectations with first
month production rates of 300-400 boe/d. Surface land acquisition is
ongoing in this area for a significant gathering line to conserve
solution gas from Cardium drilling with construction targeted during the
first quarter of 2011. There will be an additional seven (3.5 net)
wells drilled in the fourth quarter finishing the current oil programs.
NAL recently drilled and completed a second Wilrich well in the
Edson area. The 1-8 well (70 percent working interest) was testing at
rates over 10 mmcf/d (gross) with tubing pressure of 1,000 psi.
Production for this well is expected to be on stream in December 2010.
The Trust is preparing for an active Cardium program early in 2011
focusing on Garrington and Cochrane. Other targets of interest will test
considerable oil opportunity in the Viking and Pekisko with development
drilling continuing at Irricana in the Wabamun and at Millard Lake in
the Leduc.
British Columbia (Fireweed, Sukunka)
There was no drilling in this gas focused area during the third
quarter. Production operations were impacted by the unanticipated
Spectra Pine River plant turnaround which spanned the last 10 days of
the second quarter and the first 11 days of the third quarter. As
discussed in the Trust's second quarter results, this outage resulted in
a complete shut-in of Sukunka volumes (2,700 boe/d) for this period
which impacted the quarter negatively by 300 boe/d. At Fireweed, the
Trust is currently preparing for a two well program in the liquids rich
Doig gas pool in the first quarter of 2011.
CAPITAL EXPENDITURES
Capital expenditures, before property acquisitions, for the quarter
ended September 30, 2010 totaled $58.5 million compared with $42.4
million for the quarter ended September 30, 2009. The year-over-year
increase is directly related to additional wells drilled on a larger
production base as well as a continued shift towards horizontal drilling
and multi-stage frac completions which significantly increases per well
costs.
On a year-to-date basis, capital expenditures, before property
acquisitions, totaled $176.9 million (net of $9.9 million in drilling
credits) compared to $96.3 million in the comparable period of 2009
which is due to increased drilling, significant expenditures on land and
slightly higher spending on facilities and seismic. NAL plans to invest
an additional $20-25 million of exploration and development capital in
the fourth quarter of 2010 to complete programs in the Cardium,
Mississippian and Wilrich zones.
To date during 2010, the Trust has invested approximately $60
million in land through crown sales and acquisitions adding significant
positions in southeast Saskatchewan and Alberta as part of an ongoing
strategy for organic resource development. This pre-investment will
increase development costs in the current year but is expected to
deliver significant reserve and production additions in the future.
Capital Expenditures ($000s)
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Drilling, completion and
Production equipment 47,803 34,599 138,444 72,685
Plant and facilities 3,403 1,264 5,185 9,654
Seismic (124) 806 1,688 1,053
Land 4,275 2,829 23,117 5,290
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Total exploration and development 55,357 39,498 168,434 88,682
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Office equipment 624 128 1,758 508
Capitalized G&A 1,930 1,266 6,226 4,260
Capitalized unit-based compensation 599 1,484 445 2,814
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Total other capital 3,153 2,878 8,429 7,582
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Total capitalized expenditures
before acquisitions 58,510 42,376 176,863 96,264
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Property acquisitions, net 88 - 30,466 2,534
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Total capitalized expenditures 58,598 42,376 207,329 98,798
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PRODUCTION
Third quarter 2010 production volume was 29,473 boe/d, an increase
of 26 percent compared to 23,418 boe/d in the same period of 2009.
Higher year-over-year production is related to the impact of
acquisitions completed later in 2009 and a strong drilling program
during the first three quarters of 2010. On a year-to-date basis,
production is 29,732 boe/d, compared to 23,433 boe/d for the comparable
period of 2009. Production in the quarter was negatively impacted by the
Sukunka Pine River Plant turnaround which equated to 300 boe/d with wet
weather, trucking and pipeline outage issues in southeast Saskatchewan
accounting for an additional 200-300 boe/d of lost production. The Trust
exited the third quarter with production over 30,000 boe/d and remains
positioned to deliver volumes around the midpoint of guidance (29,500 -
30,500 boe/d) for full year 2010, and an exit rate in the 30,500 -
31,000 boe/d range.
Average Daily Production Volumes
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Oil (bbl/d) 11,404 9,467 11,610 9,725
Natural gas (Mcf/d) 92,518 69,706 92,255 68,778
NGLs (bbl/d) 2,650 2,334 2,746 2,244
Oil equivalent (boe/d) 29,473 23,418 29,732 23,433
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Oil equivalent volumes of 29,473 boe/d for the third quarter of 2010
and 29,732 boe/d year-to-date include 251 boe/d (2009 - 370 boe/d) and
276 boe/d (2009 - 412 boe/d), respectively, attributable to the
non-controlling interest in the Tiberius and Spear properties (see
"Related Party Transactions"). The Trust's net production, after
deducting the non-controlling interest, is 29,222 boe/d for the third
quarter of 2010 (2009 - 23,048 boe/d) and 29,456 boe/d (2009 - 23,021
boe/d) year-to-date.
Oil and natural gas liquids totaled 48 percent of production with
natural gas at 52 percent during the first nine months of 2010. The
Trust's oil and liquids weighting is comparable to that in the same
period in 2009. NAL has invested 75 - 80 percent of its capital program
in oil projects which has added significant oil production, but the
impact of this volume has been offset by the gas weighted acquisition of
Breaker Energy Ltd. ("Breaker") which closed in December, 2009
resulting in gas-oil ratios remaining relatively flat. Going forward,
the Trust would expect its oil / liquids weighting to grow on an organic
basis by 1 - 3 percent year-over-year with a similar focus on resource
style oil projects.
Production Weighting
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Oil 39% 40% 39% 41%
Natural gas 52% 50% 52% 49%
NGLs 9% 10% 9% 10%
----------------------------------------------------------------------------
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REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs and prior to hedging, totaled $115.8 million
for the three months ended September 30, 2010, 34 percent higher than
the third quarter of 2009. This growth in revenue is due to a 26 percent
increase in production and a seven percent rise in the average realized
price per boe (five percent increase in the realized crude oil price
and a 14 percent increase in the realized natural gas price). The
increase in realized prices reflects higher West Texas Intermediate
("WTI") prices, partially offset by a stronger Canadian dollar, and
higher AECO prices in the third quarter of 2010.
For the nine month period ended September 30, 2010, revenue after
transportation costs totaled $374.1 million, an increase of
approximately 50 percent from the comparable period in 2009. The
increase is attributable to a 18 percent increase in the average
realized price per boe and a 27 percent increase in production. The
increase in realized prices reflects higher WTI prices, partially offset
by a stronger Canadian dollar, and higher AECO prices in the nine
months of 2010.
Revenue
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue (1) ($000s)
Oil 74,256 58,543 231,115 154,024
Gas 29,724 19,718 103,789 73,834
NGLs 11,617 8,069 39,130 21,199
Sulphur 158 (32) 115 553
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Total revenue 115,755 86,298 374,149 249,610
$/boe 42.69 40.06 46.10 39.02
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(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 third quarter average realized Canadian crude oil price per
barrel, net of transportation costs and excluding hedging, was $70.78,
compared to $67.22 for the comparable quarter of 2009. The increase in
realized price quarter-over-quarter of five percent, or $3.56/bbl, was
primarily driven by a 12 percent increase in the WTI price (US$/bbl)
over the comparable period, partially offset by a five percent increase
in the Canadian/U.S. dollar exchange rate.
For the third quarter of 2010, NAL's crude oil price differential
was 89 percent, the same percentage experienced during the comparable
period in 2009. The differential is calculated as the realized price as a
percentage of the WTI price stated in Canadian dollars.
For the nine months ended September 30, 2010, NAL's average oil
price was $72.92 per barrel compared to $58.01 for the same period in
2009. The increase in realized price was driven by a 36 percent increase
in the WTI price (US$/bbl) and an increase in crude oil differentials
to 91 percent from 87 percent in 2009, partially offset by a 11 percent
increase in the Canadian/U.S. dollar exchange rate.
Natural gas liquids averaged $47.65/bbl in the third quarter of
2010, a 27 percent increase from the $37.58/bbl realized in 2009. For
the nine months ended September 30, 2010, natural gas liquids averaged
$52.20/bbl, an increase of 51 percent from the comparable period in
2009.
NATURAL GAS MARKETING
Approximately 69 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 31 percent tied to NYMEX or other
indexed reference prices.
For the three months ended September 30, 2010, the Trust's natural
gas sales averaged $3.49/Mcf compared to $3.07/Mcf in the same period of
2009, an increase of 14 percent. The quarter-over-quarter increase in
gas prices was primarily attributable to an increase in the benchmark
AECO daily spot prices.
Prices for Lake Erie natural gas increased to $4.92/Mcf in the third
quarter of 2010, compared to $3.77/Mcf in 2009, an increase of 31
percent. Lake Erie production of 3.2 mmcf/d accounted for three percent
of the Trust's natural gas production in the third quarter of 2010, as
compared to five percent in the comparable period of 2009. Natural gas
sales from the Lake Erie property generally receive a higher price due
to the proximity of the Ontario and northeastern U.S. markets.
For the nine months ended September 30, 2010, NAL averaged
$4.12/Mcf, a five percent increase from the $3.93/Mcf realized in the
comparable period of 2009. The increase in natural gas prices was
attributable to a nine percent increase in the benchmark AECO daily spot
prices.
Average Pricing
(net of transportation charges)
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 76.20 68.30 77.66 57.00
NAL average oil (Cdn$/bbl) 70.78 67.22 72.92 58.01
NAL natural gas liquids (Cdn$/bbl) 47.65 37.58 52.20 34.60
Natural Gas (Cdn$/mcf)
AECO - daily spot 3.54 2.98 4.13 3.78
AECO - monthly 3.72 3.02 4.31 4.11
NAL Western Canada natural gas 3.44 3.04 4.08 3.88
NAL Lake Erie natural gas 4.92 3.77 5.17 5.05
NAL average natural gas 3.49 3.07 4.12 3.93
NAL Oil Equivalent before hedging
(Cdn$/boe - 6:1) 42.69 40.06 46.10 39.02
Average Foreign Exchange Rate
(Cdn$/US$) 1.039 1.097 1.036 1.170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 hedge more near-term volumes
on a six to 12 month forward basis with more limited volumes hedged in
future periods.
NAL hedges floating rate debt for periods of up to five years. As at
September 30, 2010, NAL had several interest rate swaps outstanding
with a total notional value of $139 million.
NAL's foreign exchange hedging policy currently provides
authorization to hedge up to 50 percent of its U.S. dollar exposure for
periods of up to 24 months. As at September 30, 2010, NAL had several
exchange rate contracts outstanding with a total notional value of US$96
million.
All derivative contract counterparties are Canadian chartered banks in the Trust's lending syndicate.
All derivative contracts are recorded on the balance sheet at fair
value based upon forward curves at September 30, 2010. 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 September 30,
2010. Accordingly, the magnitude of the unrealized gain or loss will
continue to fluctuate with changes in commodity prices, interest rates
and foreign exchange rates.
The fair value of the derivatives at September 30, 2010 was a net
asset of $10.4 million, comprised of a $7.6 million asset on gas
contracts, a $2.7 million asset on foreign exchange contracts and a $0.3
million asset on oil contracts offset by a $0.2 million liability on
interest rate swaps.
Third quarter income for 2010 includes a $6.8 million unrealized
loss on derivatives resulting from the change in the fair value of the
derivative contracts during the quarter from an unrealized gain of $17.2
million at June 30, 2010 to an unrealized gain of $10.4 million at
September 30, 2010. The $6.8 million unrealized loss was comprised of a
$4.3 million unrealized loss on crude oil contracts, a $1.0 million
unrealized loss on interest rate swaps, and a $3.5 million unrealized
loss on natural gas contracts, partially offset by a $2.0 million
unrealized gain on foreign exchange swaps.
For the nine months ended September 30, 2010, income includes an
unrealized gain of $12.9 million, resulting from the change in the fair
value of the derivative contracts during the period from an unrealized
loss of $2.5 million at December 31, 2009 to an unrealized gain of $10.4
million at September 30, 2010. The unrealized gain was comprised of a
$13.2 million unrealized gain on crude oil contracts and a $3.7 million
unrealized gain on natural gas contracts, partially offset by a $2.7
million unrealized loss on interest rate swaps and a $1.3 million
unrealized loss on foreign exchange swaps.
The gain/loss on all forward derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts ($000s)
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts (4,269) (184) 13,216 (56,151)
Natural gas contracts (3,517) (8,251) 3,656 (5,560)
Interest rate swaps (1,017) (374) (2,713) 2,776
Exchange rate swaps 1,977 3,310 (1,305) 5,448
----------------------------------------------------------------------------
Unrealized gain (loss) (6,826) (5,499) 12,854 (53,487)
Realized gain (loss):
Crude oil contracts 2,146 7,526 (2,648) 44,179
Natural gas contracts 7,821 8,331 17,218 19,794
Interest rate swaps (268) (226) (910) (433)
Exchange rate swaps 1,410 3,188 4,382 5,200
----------------------------------------------------------------------------
Realized gain 11,109 18,819 18,042 68,740
----------------------------------------------------------------------------
Gain on derivative contracts 4,283 13,320 30,896 15,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following is a summary of the realized gains and losses on risk
management contracts:
Realized Gain (Loss) on Derivative Contracts
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Commodity contracts:
Average crude volumes hedged
(bbl/d) 5,798 4,733 6,219 4,362
Crude oil realized gain
(loss) ($000s) 2,146 7,526 (2,648) 44,179
Gain (loss) per bbl hedged ($) 4.02 17.28 (1.56) 37.10
Average natural gas volumes
hedged (GJ/d) 42,000 23,130 39,670 20,850
Natural gas realized gain ($000s) 7,821 8,331 17,218 19,794
Gain per GJ hedged ($) 2.02 3.92 1.59 3.48
Average BOE hedged (boe/d) 12,433 8,387 12,486 7,656
Total realized commodity contracts
gain ($000s) 9,967 15,857 14,570 63,973
Gain per boe hedged ($) 8.71 20.55 4.27 30.61
Gain per boe ($) 3.68 7.36 1.79 10.00
Interest rate swaps realized loss
($000s) (268) (226) (910) (433)
Loss per boe ($) (0.10) (0.10) (0.11) (0.07)
Exchange rate swaps realized gain
($000s) 1,410 3,188 4,382 5,200
Gain per boe ($) 0.52 1.48 0.54 0.82
Total realized gain ($000s) 11,109 18,819 18,042 68,740
Gain per boe ($) 4.10 8.74 2.22 10.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average hedged volumes for the third quarter of 2010 were 12,433 boe/d
compared to 12,661 boe/d for the second quarter of 2010.
NAL has the following interest rate risk management contracts outstanding:
----------------------------------------------------------------------------
Amount Trust
(millions) Fixed Counterparty
INTEREST RATE CONTRACT Remaining Term (1) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating to fixed Oct 2010 - $39.0 1.5864% CAD-BA-CDOR
Dec 2011 (3 months)
Swaps-floating to fixed Oct 2010 - $22.0 1.3850% CAD-BA-CDOR
Jan 2013 (3 months)
Swaps-floating to fixed Oct 2010 - $22.0 1.5100% CAD-BA-CDOR
Jan 2014 (3 months)
Swaps-floating to fixed Oct 2010 - $14.0 1.8500% CAD-BA-CDOR
Mar 2013 (3 months)
Swaps-floating to fixed Oct 2010 - $14.0 1.8750% CAD-BA-CDOR
Mar 2013 (3 months)
Swaps-floating to fixed Oct 2010 - $14.0 1.9300% CAD-BA-CDOR
Mar 2014 (3 months)
Swaps-floating to fixed Oct 2010 - $14.0 1.9850% CAD-BA-CDOR
Mar 2014 (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount
NAL has the following exchange rate risk management contracts outstanding:
----------------------------------------------------------------------------
Average
Amount (1) Fixed Counterparty
INTEREST RATE CONTRACT Remaining Term (US$ MM) Rate Floating Rate
----------------------------------------------------------------------------
Forward-floating to fixed Oct 2010 - 27.0 1.0904 BofC Average
Dec 2010 Noon Rate
Forward-floating to fixed Jan 2011 - 60.0 1.0571 BofC Average
Dec 2011 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional US$ denominated commodity sales
In addition, NAL has the following exchange rate contract commitments:
1. From October to December 2010, NAL has a commitment to sell US$3 million
($1 million/month) at 1.045 if the monthly Bank of Canada average noon
rate exceeds 1.045. NAL is paid a premium of approximately $10,000 a
month when the average noon rate falls between 0.95 and 1.045.
2. For calendar 2011, NAL has a commitment to sell US$6 million
($500,000/month) at 1.12 if the monthly Bank of Canada average noon
rate exceeds 1.12. NAL is paid a premium of approximately $25,000 a
month when the average noon rate falls between 0.95 and 1.12.
NAL has the following commodity risk management contracts currently
outstanding:
CRUDE OIL Q4-10 Q1-11 Q2-11 Q3-11 Q4-11
----------------------------------------------------------------------------
US$ Collar Contracts
---------------------
$US WTI Collar Volume
(bbl/d) 1,900 800 800
Bought Puts - Average
Strike Price ($US/bbl) 68.03 81.25 81.25
Sold Calls - Average
Strike Price ($US/bbl) 80.62 94.47 94.47
US$ Swap Contracts
-------------------
$US WTI Swap Volume
(bbl/d) (1) 4,199 4,900 4,900 5,500 5,500
Average WTI Swap Price
($US/bbl) 83.47 87.39 87.39 88.05 88.05
Total Oil Volume (bbl/d) 6,099 5,700 5,700 5,500 5,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Two calendar 2011 500 bbl/d swap contracts with an average price of
$95.00 contain extendible call options. The extendible call option
provides the counterparty with the option to extend the contract into
calendar 2012 under the same price and volumetric terms. The
counterparty can exercise this option at any time prior to December 30,
2011.
NATURAL GAS Q4-10 Q1-11 Q2-11
----------------------------------------------------------------------------
Swap Contracts
---------------
AECO Swap Volume (GJ/d) 31,337 5,000 4,000
AECO Average Price
($Cdn/GJ) 5.52 5.61 5.78
Total Natural gas Volume
(GJ/d) 31,337 5,000 4,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the remainder of 2010, the Trust has outstanding contracts
representing approximately 45 percent of its net liquids and natural gas
production after royalties. For 2011, and subsequent to September 30,
2010, the Trust has added significant oil positions to its hedging
portfolio at fixed price swaps above US$87.00/bbl.
ROYALTY EXPENSES
Crown, freehold and overriding royalties totaled $21.2 million for
the three months ended September 30, 2010. Expressed as a percentage of
gross sales net of transportation costs, before gain/loss on derivative
contracts, the net royalty rate was 18.3 percent for the quarter ended
September 30, 2010. On a boe basis, royalties increased to $7.83 per boe
for the third quarter of 2010, an increase of 13 percent compared to
the third quarter of 2009. This increase is mainly due to a gas cost
allowance adjustment and additional freehold mineral taxes incurred as a
result of acquiring Breaker and Clipper.
On a year-to-date basis, royalties were $68.2 million, up from $44.7
million in the comparable period of 2009. Expressed as a percentage of
gross sales net of transportation costs, before gain/loss on derivative
contracts, the net royalty rate was 18.2 percent, slightly higher than
the comparable period of 2009.
On March 11, 2010, the Government of Alberta announced measures to
advance Alberta's competitiveness in the upstream oil and gas sector.
The royalty framework for natural gas and conventional oil was 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 system. The maximum royalty rate for
conventional oil is reduced at higher price levels from 50 percent to 40
percent. The maximum royalty rate for natural gas is reduced at higher
price levels from 50 percent to 36 percent.
For the nine months ended September 30, 2010, 44.1 percent of crude
oil production (1,398,981 bbl) and 65.6 percent of natural gas
production (16,511,597 Mcf) was from Alberta.
Royalty Expenses
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Royalties ($000s) 21,241 14,950 68,238 44,692
As % of revenue 18.3 17.3 18.2 17.9
$/boe 7.83 6.94 8.41 6.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING COSTS
Operating costs averaged $11.72 per boe for the quarter ended
September 30, 2010, compared to $10.52 per boe for the quarter ended
September 30, 2009. Operating costs were anticipated to be higher in the
quarter due to increased turn around and scheduled maintenance
activities. On a year-to-date basis, operating costs are $11.17 per boe
compared to $11.42 per boe in 2009 which is a 2.2 percent decrease. The
Trust expects full year costs to be in the mid-range of the $10.75 -
$11.25 per boe range of guidance, as all significant maintenance
activity has been completed, which is expected to result in fourth
quarter costs being significantly lower.
Operating Costs
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Operating costs ($000s) 31,768 22,657 90,654 73,056
As a % of revenue 27.4 26.3 24.2 29.3
$/boe 11.72 10.52 11.17 11.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OTHER INCOME
Other income was $0.08 per boe for the third quarter of 2010
compared to $0.11 per boe in the comparable quarter of 2009. Other
income includes gas processing fees, other miscellaneous income and fees
and interest income and interest expense on notes due from and to
Manulife Financial Corporation ("MFC") (see "Related Party
Transactions"). On a year-to-date basis, interest expense totaled $0.3
million compared to net interest income of $0.3 million for the same
period of 2009, the decrease being attributable to the repayment of a
note receivable from MFC in the first quarter of 2009.
Other Income
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest on notes with MFC ($000s) (113) (125) (333) 289
Other ($000s) 319 370 874 1,099
----------------------------------------------------------------------------
Total other income ($000s) 206 245 541 1,388
As a % of revenue 0.18 0.28 0.14 0.55
Interest on notes with MFC ($/boe) (0.04) (0.06) (0.04) 0.05
Other ($/boe) 0.12 0.17 0.11 0.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total other income ($/boe) 0.08 0.11 0.07 0.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended September 30, 2010, NAL's operating netback
before hedging gains was $23.26 per boe, an increase of two percent from
$22.77 per boe for the quarter ended September 30, 2009. The increase
was due to higher revenues, a result of higher commodity prices, offset
by increased operating cost, and increased royalty expense. Hedging
gains, related to commodity and exchange rate derivative contracts, were
$4.20 per boe in the third quarter of 2010, compared to $8.84 per boe
in 2009. The decrease in 2010 is attributable mainly to higher realized
crude oil prices.
On a year-to-date basis, the operating netback, before hedging, was
$26.63 per boe compared to $20.78 per boe in 2009. This increase is due
to higher revenues and lower operating costs, offset by increased
royalty expense. Hedging gains, related to commodity and exchange rate
derivative contracts, were $2.33 per boe for the nine months ended
September 30, 2010, compared to $10.82 per boe in 2009. The decrease in
2010 is attributable to lower oil hedging gains due to increasing crude
oil prices.
Operating Netback
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
Oil (bbl/d) 11,404 9,467 11,610 9,725
Gas (Mcf/d) 92,518 69,706 92,255 68,778
NGLs (bbl/d) 2,650 2,334 2,746 2,244
----------------------------------------------------------------------------
Total (boe/d) 29,473 23,418 29,732 23,433
REVENUE(1)
Oil ($/bbl) 70.78 67.22 72.92 58.01
Gas ($/Mcf) 3.49 3.07 4.12 3.93
NGLs ($/bbl) 47.65 37.58 52.20 34.60
----------------------------------------------------------------------------
Total ($/boe) 42.69 40.06 46.10 39.02
ROYALTIES
Oil ($/bbl) 14.46 13.47 14.42 11.85
Gas ($/Mcf) 0.20 0.11 0.38 0.32
NGLs ($/bbl) 17.80 11.06 15.38 9.73
----------------------------------------------------------------------------
Total ($/boe) 7.83 6.94 8.41 6.99
OPERATING EXPENSES
Oil ($/bbl) 11.72 10.52 11.17 11.42
Gas ($/Mcf) 1.95 1.75 1.86 1.90
NGLs ($/bbl) 11.72 10.52 11.17 11.42
----------------------------------------------------------------------------
Total ($/boe) 11.72 10.52 11.17 11.42
OTHER INCOME(2)
Oil ($/bbl) 0.04 0.04 0.03 0.04
Gas ($/Mcf) 0.03 0.04 0.03 0.04
NGLs ($/bbl) 0.04 0.11 0.03 0.11
----------------------------------------------------------------------------
Total ($/boe) 0.12 0.17 0.11 0.17
OPERATING NETBACK, BEFORE HEDGING
Oil ($/bbl) 44.64 43.27 47.36 34.78
Gas ($/Mcf) 1.37 1.25 1.91 1.75
NGLs ($/bbl) 18.17 16.11 25.68 13.56
----------------------------------------------------------------------------
Total ($/boe) 23.26 22.77 26.63 20.78
HEDGING GAINS/(LOSSES)(3)
Oil ($/bbl) 3.39 12.30 0.55 18.60
Gas ($/Mcf) 0.92 1.30 0.68 1.05
NGLs ($/bbl)
----------------------------------------------------------------------------
Total ($/boe) 4.20 8.84 2.33 10.82
OPERATING NETBACK, AFTER HEDGING
Oil ($/bbl) 48.03 55.57 47.91 53.38
Gas ($/Mcf) 2.29 2.55 2.59 2.80
NGLs ($/bbl) 18.17 16.11 25.68 13.56
----------------------------------------------------------------------------
Total ($/boe) 27.46 31.61 28.96 31.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation charges.
(2) Excludes interest on notes with MFC.
(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 Trust plus the reimbursement of the G&A expenses
incurred by NAL Resources Management Limited (the "Manager") on the
Trust's behalf.
For the three months ended September 30, 2010, G&A expenses were
$3.5 million, $0.6 million lower than the comparable quarter of 2009.
This decrease is primarily due to Breaker lease amortization and
sublease recoveries not being included in the third quarter of 2009. In
addition, $1.9 million of G&A costs relating to exploitation and
development activities were capitalized in the third quarter of 2010,
compared with $1.3 million in the third quarter of 2009. G&A expense
per boe was $1.30 in the quarter, as compared to $1.90 for the same
period in 2009.
For the nine months ended September 30, 2010, G&A expenses
increased 11 percent to $11.9 million from $10.8 million in the
comparable period in 2009. In addition, on a year-to-date basis, $6.2
million of G&A costs relating to exploitation and development
activities were capitalized, compared with $4.3 million in the
comparable period of 2009. G&A expense per boe was $1.47 in 2010,
compared to $1.68 in the first nine months of 2009.
The year-to-date increase in total year-to-date G&A of $3.1
million is attributable to unusually low costs in 2009 resulting from an
adjustment to the short term incentive payout, plus higher 2010
compensation costs due to acquisitions.
General and Administrative Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
G&A expenses ($000s)
Expensed 3,522 4,095 11,920 10,753
Capitalized 1,930 1,266 6,226 4,260
----------------------------------------------------------------------------
Total G&A ($000s) 5,452 5,361 18,146 15,013
Expensed G&A costs:
$/boe 1.30 1.90 1.47 1.68
As % of revenue 3.0 4.7 3.2 4.3
Per trust unit ($) 0.02 0.04 0.08 0.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
The employees of the Manager are all members of a unit-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 trust units of the Trust. The
Plan consists of Restricted Trust Units ("RTUs") and Performance Trust
Units ("PTUs"). RTUs vest as to one third of the amount of the grant on
November 30 in each of three years after the date of grant. PTUs vest on
November 30, three years from the date of grant. Distributions paid on
the Trust's outstanding trust units during the vesting period are
assumed to be paid on the awarded notional trust units and reinvested in
additional notional trust units on the date of distribution. Upon
vesting, the employee is entitled to a cash payout based on the trust
unit price at the date of vesting of the units held. In addition, the
PTUs have a performance multiplier which is based on the Trust's
performance relative to its peers and may range from zero to two times
the market value of the notional trust units held at vesting.
During the third quarter of 2010, the Trust recorded a $2.0 million
charge for unit-based incentive compensation that reflects the impact of
vesting additional notional units as well as an increase in the unit
price of the Trust. The unit price of the Trust increased nine percent,
from $10.60 at June 30, 2010 to $11.53 at September 30, 2010. An
increase in unit price results in previously accrued amounts being
increased.
Unit-based incentive compensation decreased by 63 percent compared
to the third quarter of 2009, from a $5.3 million charge in 2009 to a
$2.0 million charge in 2010. The period-over-period decrease is a
reflection of a nine percent increase in the trust unit price for the
quarter compared to a 36 percent increase in the trust unit price for
the comparable quarter last year, and lower relative performance factors
used to determine the 2010 payout.
On a year-to-date basis, the Trust has accrued $1.5 million compared to a $9.7 million charge in the comparable period of 2009.
At September 30, 2010, the trust unit price used to determine
unit-based incentive compensation was $11.53. The closing trust unit
price of the Trust on the Toronto Stock Exchange on November 8, 2010 was
$12.82.
The calculation of unit-based compensation expense is made at the
end of each quarter based on the quarter end trust unit price and
estimated performance factors. The compensation charges relating to the
units granted are recognized over the vesting period based on the trust
unit price, number of RTUs and PTUs outstanding and the expected
performance multiplier. As a result, the expense recorded in the
accounts will fluctuate in each quarter and over time.
At September 30, 2010, the Trust has recorded a total accumulated
liability for unit-based incentive compensation in the amount of $10.9
million, of which $6.3 million is recorded as a current liability, as it
is payable in December 2010, and $4.6 million is recorded as a
long-term liability, as it is payable in December 2011 and December
2012.
Unit-Based Compensation
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unit-based compensation ($000s):
Expensed 1,384 3,805 1,094 6,865
Capitalized 599 1,484 445 2,814
----------------------------------------------------------------------------
Total unit-based compensation 1,983 5,289 1,539 9,679
Expensed unit-based compensation:
As % of revenue 1.2 4.4 0.3 2.8
$/boe 0.51 1.77 0.13 1.07
Per trust unit ($) 0.01 0.03 0.01 0.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
RELATED PARTY TRANSACTIONS
The Trust is managed by the Manager. The Manager is a wholly-owned
subsidiary of MFC and also manages NAL Resources Limited ("NAL
Resources"), another wholly-owned subsidiary of MFC. NAL Resources and
the Trust 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 Trust and its
subsidiary entities pursuant to an Administrative Services and Cost
Sharing Agreement. This agreement requires the Trust to reimburse the
Manager at cost for G&A and unit-based compensation expenses
incurred by the Manager on behalf of the Trust. The Agreement does not
provide for any base or performance fees to be payable to the Manager.
The Trust paid $3.2 million (2009 - $3.4 million) for the
reimbursement of G&A expenses during the third quarter and $10.4
million (2009 - $8.7 million) year-to-date. The Trust also pays the
Manager its share of unit-based incentive compensation expense when cash
compensation is paid to employees under the terms of the Plan, of which
$7.0 million was paid in the first quarter of 2010, representing units
that vested on November 30, 2009 (2009 - $2.3 million).
At September 30, 2010 the Trust owed the Manager $1.1 million for
the reimbursement of G&A and had a payable to NAL Resources of $1.4
million relating to net operating revenues less capital expenditures.
The Trust and a wholly owned subsidiary of MFC jointly own a limited
partnership (the "Partnership"). 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.
The Trust, by virtue of being the owner of the general partner of
the Partnership under the partnership agreement, is required to
consolidate the results of the Partnership into its financial statements
on the basis that the Trust has control over the Partnership.
Accordingly, the Trust reports all revenues, expenses, assets and
liabilities of the Partnership, together with its wholly owned
subsidiaries and partnerships, in its consolidated financial statements.
The 50 percent share of net income and net assets of the Partnership
attributable to MFC is then deducted from net income and net assets as a
one-line entry, in the income statement and balance sheet, ensuring
that the bottom line net income and net assets reported represent only
the Trust's interest.
During the first quarter of 2009, MFC repaid the note receivable to
the Partnership of $49.6 million. The Partnership then paid an equal
distribution of $49.6 million to MFC. This resulted in a $49.6 million
reduction to the non-controlling interest on the balance sheet.
As at September 30, 2010, there is a note payable of $8.0 million
with MFC. The note payable is included on consolidation of the
Partnership, but is effectively eliminated through the non-controlling
interest. The note is due on demand, unsecured and bears interest at
prime plus three percent. The amount of the note payable to MFC is
adjusted to reflect MFC's share of the capital expenditures of the
Partnership which MFC has funded, less any loan repayments made.
Net interest expense on these notes of $0.1 million was payable by
the Trust for the third quarter of 2010 (2009 - $0.1 million net
interest expense), and net interest expense of $0.3 million (2009 - $0.3
million net interest income) has been payable by the Trust
year-to-date.
INTEREST
Interest on bank debt includes the interest rate charges on
borrowings, plus a standby fee, a stamping fee and the fee for renewal.
Interest on bank debt for the third quarter of 2010 was $2.8 which is
similar to the comparable period in 2009. Average outstanding bank debt
for the third quarter of 2010 was $224.8 million, $23.6 million lower
than the $248.4 million outstanding for the third quarter of 2009,
driven primarily by the $94.5 million in equity raised in the second
quarter, net of issue costs. NAL's effective interest rate averaged five
percent during the third quarter of 2010, compared to 4.41 percent
during the comparable period in 2009. The increase in the rate from the
third quarter of 2009 is attributable to higher overall borrowing rates
in the market. NAL's interest is calculated based upon a floating rate,
before the effect of any interest rate swaps. Higher interest rates
offset the impact of lower average bank borrowings.
For the nine months ended September 30, 2010, interest on bank debt
increased $0.9 million to $8.6 million, compared to $7.7 million in
2009. Average outstanding debt for the nine months ended September 30,
2010 decreased to $221 million, compared to $279.4 million for the
corresponding period of 2009, and the effective interest rate averaged
5.19 percent in 2010, compared to 3.68 percent in 2009.
Interest on convertible debentures represents interest charges of
$4.2 million for the three months ended September 30, 2010 ($12.4
million for the nine months ended September 30, 2010) compared to $1.7
million in the third quarter of 2009 ($5.2 million for the nine months
ended September 30, 2009).
The interest includes the interest on the convertible debentures
issued in 2007 at 6.75 percent and the interest on the debentures issued
in December 2009 at 6.25 percent. Accretion of the debt discount was
$1.0 million for the three months ended September 30, 2010 ($3.0 million
for the nine months ended September 30, 2010) as compared to $0.4
million for the three months ended September 30, 2009 ($1.1 million for
the nine months ended September 30, 2009). The increase in interest and
accretion is due to the December 2009 issuance of convertible
debentures.
Interest and Debt
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest on bank debt ($000s)(1) 2,831 2,761 8,587 7,686
Interest and accretion on
convertible debentures ($000s) 4,173 1,727 12,411 5,176
----------------------------------------------------------------------------
Total interest before interest
rate hedges($000s) 7,004 4,488 20,998 12,862
Realized loss on interest rate
swaps ($000s) 268 226 910 433
----------------------------------------------------------------------------
Total interest after interest
rate hedges ($000s) 7,272 4,714 21,908 13,295
----------------------------------------------------------------------------
Bank debt outstanding at period
end ($000s) 235,016 246,892 235,016 246,892
Convertible debentures at period
end ($000s)(2) 180,649 75,144 180,649 75,144
$/boe:
Interest on bank debt 1.04 1.28 1.06 1.20
Interest on convertible
debentures 1.17 0.62 1.16 0.63
Accretion on convertible
debentures 0.37 0.18 0.37 0.18
Loss on interest rate swaps 0.10 0.10 0.11 0.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total interest after interest rate
hedges 2.68 2.18 2.70 2.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes interest rate hedge impact.
(2) Debt component of the debentures, as reported on the balance sheet.
CASH FLOW NETBACK
For the quarter ended September 30, 2010, NAL's cash flow netback
was $23.28 per boe, a 10 percent decrease from $25.88 per boe for the
comparable period in 2009. The decrease was due to a lower operating
netback after hedging and higher interest charges on bank debt and
convertible debentures, offset by lower G&A expenses, including
unit-based incentive compensation.
For the nine months ended September 30, 2010, NAL's cash flow
netback was $24.97 per boe, an eight percent decrease from $27.00 per
boe in 2009. The decrease was due to a lower operating netback after
hedging and higher interest charge on bank debt and convertible
debentures, offset by lower G&A expenses.
Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Operating netback, after
hedging 27.46 31.61 28.96 31.60
G&A expenses, including
unit-based incentive
compensation (1.81) (3.67) (1.60) (2.75)
Corporate conversion cost (0.02) - (0.02) -
Interest on bank debt and
convertible debentures(1) (2.21) (1.90) (2.22) (1.83)
Interest on notes with MFC(2) (0.04) (0.06) (0.04) 0.05
Realized loss on interest rate
derivative contracts (0.10) (0.10) (0.11) (0.07)
----------------------------------------------------------------------------
Cash flow netback 23.28 25.88 24.97 27.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.
(2) Reported as other income.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATIONS ("DDA")
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 reserves volumes.
For the quarter ended September 30, 2010, depletion on property,
plant and equipment and accretion on the asset retirement obligations
was $25.42 per boe, 14 percent higher than the $22.38 per boe for the
same period in 2009. The increase in depletion rate per boe in 2010
reflects a higher depletion rate associated with the oil and gas
properties of Breaker which was acquired in December 2009. Similar
trends are noted for the nine months ended September 30, 2010.
The DDA rate will fluctuate period-over-period depending on the
amount and type of capital expenditures and the amount of reserves
added.
Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 66,222 46,209 192,161 132,196
Accretion of asset retirement
obligation ($000s) 2,708 2,003 8,034 5,717
----------------------------------------------------------------------------
Total DDA ($000s) 68,930 48,212 200,195 137,913
DDA rate per boe ($) 25.42 22.38 24.66 21.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TAXES
In the third quarter of 2010, NAL had a future income tax recovery
of $13.3 million compared to a $7.4 million recovery in the
corresponding period of the prior year. For the nine month period ended
September 30, 2010, NAL had a future income tax recovery of $25.9
million compared to $25.8 million in 2009.
The Trust is a taxable entity and files a trust income tax return
annually. The Trust's taxable income consists of royalty income,
distributions from a subsidiary trust and interest and dividends from
other subsidiaries, less deductions for the Trust's G&A expenses,
Canadian Oil and Gas Property Expense ("COGPE") and issue costs. In
addition, Canadian Exploration Expense ("CEE"), Canadian Development
Expense ("CDE") and Undepreciated Capital Cost ("UCC") are incurred and
deducted by the Trust's subsidiaries. The Trust is taxable only on
remaining income, if any, that is not distributed to unitholders.
As at September 30, 2010, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximated $1.4 billion, of which approximately 33
percent represented COGPE, 20 percent represented UCC, with the
remaining balance represented by CEE, CDE, trust unit issue costs and
non-capital loss carry forwards.
Estimated Tax Pools ($ millions)
----------------------------------------------------------------------------
September December
30, 2010 31, 2009
----------------------------------------------------------------------------
Canadian exploration expense 60 50
Canadian development expense 456 379
Canadian oil and gas property expense 470 436
Undepreciated capital costs 287 274
Other (including loss carry forwards) 131 128
----------------------------------------------------------------------------
Total estimated tax pools 1,404 1,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Based on current strip prices at September 30, 2010, the Trust is not expected to be taxable in 2010.
Under the specified investment flow-through ("SIFT") legislation,
effective January 1, 2011, distributions to unitholders will not be
deductible against income by publicly traded income trusts and, as a
result, the Trust will be taxed on its income similar to corporations.
These measures are considered enacted for purposes of GAAP. Accordingly,
the Trust has measured future income tax assets and liabilities under
the SIFT tax rules. The scheduling of the reversal of temporary
differences is based on management's best estimates and current
assumptions, which may change. Bill C-10, containing the legislation for
the provincial SIFT rate, received Royal Assent on March 12, 2009. The
Alberta provincial tax rate for 2011 is expected to be 10 percent. This
will result in an effective combined SIFT rate of 26.5 percent in 2011
and 25.0 percent in 2012, a three percent decrease from the original
legislation. The Trust has tax effected all temporary differences.
NON-CONTROLLING INTEREST
The Trust has recorded a non-controlling interest in respect of the
50 percent ownership interest held by MFC in the Partnership holding the
Tiberius and Spear assets (see "Related Party Transactions").
The non-controlling interest presented in the 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 non-controlling interest in the consolidated statement of income is comprised of:
Non-Controlling Interest ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Net profits interest expense 991 736 1,825 1,523
Share of net income attributable
to MFC (516) 80 (191) 788
----------------------------------------------------------------------------
475 816 1,634 2,311
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET INCOME
Net income is a measure impacted by both cash and non-cash items.
The largest non-cash items impacting the Trust's net income are DDA,
unrealized gains or losses on derivative contracts and future income
taxes.
The net loss for the third quarter of 2010 was $0.8 million compared
to net income of $8.2 million for the comparable period in 2009. The
decrease of $9.0 million was mainly due to increased DD&A expense
($20.7 million), increased operating costs ($9.1 million) and a
decreased gain on derivative contracts ($9.0 million), partially offset
by increased revenues net of royalties ($23.7 million) and a higher tax
reduction ($5.9 million).
Net income for the nine months ended September 30, 2010 of $36.6
million was $33.0 million greater than the comparable period of 2009.
The increase in net income in 2010 is attributable to increased revenues
net of royalties ($102.7 million), an increased gain on derivative
contracts ($15.6 million), partially offset by increased operating costs
($17.6 million), increased DD&A expense ($62.3 million) and
increased interest charges ($8.1 million).
Net Income ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2008
----------------------------------------------------------------------------
Net income (loss) (781) 8,249 36,614 3,566
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of trust units, bank debt and convertible debentures.
As at September 30, 2010, NAL had 146,620,602 trust units
outstanding, compared with 137,471,209 trust units as at December 31,
2009. The increase from December 31, 2009 is attributable to 1,599,393
units issued under the distribution reinvestment program ("DRIP") and a
new issuance pursuant to a bought deal offering of 7,550,000 trust units
in April 2010.
Under the DRIP, unitholders may elect to reinvest distributions or
make optional cash payments to acquire trust units from treasury 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 has averaged
15.66 percent during the year.
The premium distribution reinvestment plan ("Premium DRIP") allows
unitholders to exchange trust units for a cash payment, from the plan
broker, equal to 102 percent of the monthly distribution. The Premium
DRIP program has been suspended since March 10, 2006.
As at September 30, 2010, the Trust had net debt of $495.3 million
(net of working capital and other liabilities, excluding derivative
contracts, note payable with MFC and future income taxes) including
convertible debentures at face value of $194.7 million. Excluding the
convertible debentures, net debt was $300.6 million, compared with
$282.7 million at December 31, 2009. The increase in net debt, excluding
convertible debentures, of $17.8 million during 2010 is attributable to
increased bank debt of $4.3 million and an increase in working capital
deficiency of $13.5 million.
Bank debt outstanding was $235.0 million at September 30, 2010
compared with $230.7 million as at December 31, 2009. Of the $235.0
million outstanding at September 30, 2010, $234.2 million is outstanding
under the production facility and $0.8 million is outstanding under the
working capital facility.
At the end of the third quarter, the Trust had a net debt (excluding
convertible debentures) to 12 months trailing cash flow ratio of 1.16
times and a total net debt (including convertible debentures) to 12
months trailing cash flow ratio of 1.91 times.
During the second quarter of 2010, the Trust renewed its credit
facility at the previously approved amount of $550 million. The credit
facility is a fully secured, extendible, revolving facility and will
revolve until April 30, 2011 at which time it is extendible for a
further 364-day revolving period upon agreement between the Trust 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 Trust 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
Trust would be required to repay the facility in five equal quarterly
installments commencing May 1, 2012.
The Trust has two series of convertible debentures currently outstanding.
On December 3, 2009, the Trust 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 anytime, into fully paid trust units at a conversion price of
$16.50 per trust unit. The debentures mature on December 31, 2014 at
which time they are due and payable. The debentures are redeemable by
the Trust 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 Trust may opt to satisfy its
obligation to repay the principal by issuing trust units. If all of the
outstanding debentures were converted at the conversion price, an
additional 7.0 million trust units would be required to be issued.
In addition, the Trust has outstanding $79.7 million principal
amount of 6.75% 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
trust units at a conversion price of $14.00 per trust unit. The
debentures mature on August 31, 2012 at which time they are due and
payable. The debentures are redeemable by the Trust 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
Trust may opt to satisfy its obligation to repay the principal by
issuing trust units. If all of the outstanding debentures were converted
at the conversion price, an additional 5.7 million trust units would be
required to be issued.
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. As the debentures are converted to
trust units, a portion of the debt and equity amounts are transferred to
Unitholders' Capital. The debt component of the convertible debentures
is carried net of issue costs. The debt balance, net of issue costs,
accretes over time to the principal amount owing on maturity. The
accretion of the debt discount and the interest paid to debenture
holders are expensed each period as part of the line item "interest and
accretion on convertible debentures" in the consolidated statement of
income.
The Trust recognized $1.0 million (2009 - $0.4 million) of accretion
of the debt discount in the third quarter of 2010 and $3.0 million
(2009 - $1.1 million) year-to-date.
As at November 8, 2010, the Trust has 146,837,847 trust units and $194.7 million in convertible debentures outstanding.
Capitalization
----------------------------------------------------------------------------
September December September
30, 2010 31, 2009 30, 2009
----------------------------------------------------------------------------
Trust unit equity ($000s) 928,659 894,192 600,404
Bank debt ($000s) 235,016 230,713 246,892
Working capital deficit
(surplus) (1) ($000s) 65,535 52,014 46,788
----------------------------------------------------------------------------
Net debt excluding convertible
Debentures ($000s) 300,551 282,727 293,680
Convertible debentures ($000s) (2) 194,744 194,744 79,744
----------------------------------------------------------------------------
Net debt ($000s) 495,295 477,471 373,424
Net debt excluding convertible
debentures to trailing 12-month
cash flow (3) 1.16 1.23 1.25
Total net debt to trailing 12-month
cash flow (3) 1.91 2.07 1.59
Trust units outstanding (000s) 146,621 137,471 112,327
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital and other liabilities, excluding derivative contracts,
future income taxes and notes with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt divided by funds from operations for the
previous 12 months.
The Trust actively manages its payout ratio (including capital) to
ensure that its capital program can be executed and that distribution
levels are maintained. The targeted payout ratios may change over time
in response to market conditions and opportunities available to the
Trust. In addition to cash generated from operations, the Trust may use a
combination of equity and debt to take advantage of opportunities, both
internally generated and acquisitions. Funds from operations is a
non-GAAP measure used by management as an indicator of the Trust's
ability to generate cash from operations. Currently, the Trust has a
bank line of $550 million of which $235 million is drawn down at
September 30, 2010, leaving available capacity of $315 million.
Currently, the Trust has in place oil hedges for approximately 53
percent of net forecasted (after royalty) production for 2010. Crude
volumes are hedged at an average price of US$83.47 per bbl on fixed
price contracts. On collared contracts, crude volumes are hedged at an
average ceiling price of US$80.62 per bbl and at an average floor price
of US$68.03 per bbl. For natural gas, remaining 2010 hedges total
approximately 39 percent of net budgeted production volumes hedged at an
average floor price in excess of $5.52 per GJ ($5.82 per Mcf).
For 2011, the Trust expects to continue to execute its active
hedging program. Currently, the Trust has oil hedges in place for
approximately 45 - 50 percent of net forecasted (after royalty)
production for 2011. Crude volumes are hedged at an average price of
US$87.74 per bbl on fixed price contracts. On collared contracts, crude
volumes are hedged at an average ceiling price of US$94.47 per bbl and
at an average floor price of US$81.25 per bbl. For natural gas, 2011
hedges total approximately 3 percent of net budgeted production volumes
hedged at an average floor price in excess of $5.68 per GJ ($5.99 per
Mcf).
For 2011, NAL's capital program is designed to be scalable and
flexible in response to commodity prices and market conditions. For
2010, the Trust plans for a $210 million capital program, prior to
deduction of Alberta drilling credits. The Trust, through the Manager,
operates approximately 85 percent of the assets to which the capital
program is directed, allowing for significant flexibility over the
timing and scale of the program.
Fluctuations in commodity prices, market conditions or potential
growth opportunities may make it necessary to adjust forecasted capital
expenditures and/or distribution levels.
Under the tax legislation regarding the change in the taxation of
income trusts (the SIFT rules), the Trust has a grandfathering period to
January 1, 2011, when the rules come into effect. The grandfathering
period restricts "undue expansion" of the Trust by placing growth limits
for issuances of equity and convertible debt, based on the market
capitalization of the Trust on October 31, 2006, the date of the
announcement of the changes in the tax legislation. For the remainder of
2010, the Trust has approximately $417 million of safe harbour
available, after taking into consideration the equity offering that
closed during the second quarter of 2010.
ASSET RETIREMENT OBLIGATION
At September 30, 2010, the Trust reported an asset retirement
obligation ("ARO") balance of $135.8 million ($127.9 million as at
December 31, 2009) for future abandonment and reclamation of the Trust's
oil and gas properties and facilities. The ARO balance was increased by
$7.9 million to reflect $3.6 million liabilities incurred and revisions
to estimates and $8.0 million from accretion expense, and was reduced
by $3.7 million for actual abandonment and environmental expenditures
incurred during the first nine months.
DISTRIBUTIONS TO UNITHOLDERS
For the three and nine months ended September 30, 2010, the Trust
distributed 48 percent and 61 percent of its cash flow from operating
activities, respectively, as compared to 57 percent and 48 percent for
the same periods in 2009. The payout associated with cash flow from
operating activities will fluctuate significantly period over period as
cash flow from operating activities includes changes in non-cash working
capital associated with operating activities. The Trust has distributed
cash in excess of its net income in each period, due to the non-cash
charges included in net income. Cash flow from operations usually
exceeds net income, as net income includes non-cash charges such as DDA,
future income tax expense and unrealized gains and losses on derivative
contracts.
The Board of Directors of NAL Energy Inc. sets distribution levels
taking into consideration commodity prices, the forecasted cash flow of
the Trust, financial market conditions, availability of financing,
internal capital investment opportunities and taxability.
Given that distributions have exceeded net income during 2010, the
excess could be considered to be an economic return of capital to the
unitholders. The Trust's business model is such that it distributes a
certain proportion of its cash flow while retaining cash to execute
planned capital programs. As a result of the depleting nature of oil and
gas assets, some capital expenditure is required in order to minimize
production declines as well as to invest in facilities and
infrastructure. NAL's 2010 capital program may not fully replace
production. When the Trust sets distribution levels, depletion expense
is not considered to be indicative of the amount required to maintain
productive capacity, and therefore, net income is not considered a
driver of distribution levels. The Trust grows its productive capacity
and sustains its cash flow through development activities and
acquisitions. NAL's productive capacity and future cash flow will be
dependent on its ability to acquire assets and continue to find economic
reserves. Acquisitions are financed through equity, debt or a
combination of the two.
Generally, the capital expenditures of the Trust and the
distributions in any given period exceed the cash flow from operating
activities. The shortfall is financed from a combination of debt and
equity. Fluctuations in commodity prices, other market factors, or
growth opportunities may make it necessary to adjust forecasted capital
expenditures or distribution levels.
NAL intends to continue to make cash distributions to unitholders.
However, these cash distributions cannot be guaranteed. The primary
drivers of the level of distributions are the factors that contribute to
cash flow, namely production, operating costs and commodity prices as
well as the opportunities for capital expenditures. The future
sustainability of this distribution policy will be dependent upon
maintaining productive capacity through both capital expenditures and
acquisitions. A significant further decrease in commodity prices may
impact cash from operating activities, access to credit facilities and
the Trust's ability to fund operations and maintain distributions.
Distributions
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
($000s except for percentages) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash flow from operating activities 82,082 52,999 189,056 183,235
Net income (loss) (781) 8,249 36,614 3,566
Actual cash distributions paid or
payable 39,529 30,290 116,075 87,528
Excess of cash flow from operating
activities over cash distribution
paid 42,553 22,709 72,981 95,707
Percentage of cash flow from
operations distributed 48% 57% 61% 48%
Excess (shortfall) of net income
over cash distributions paid (40,310) (22,041) (79,461) (83,962)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As stated in the non-GAAP measures section of the MD&A, NAL uses
funds from operations as a key performance indicator to measure the
ability of the Trust to generate cash from operations and to pay monthly
distributions.
For the three months ended September 30, 2010, funds from operations
amounted to $60.0 million, compared with $53.8 million for the three
months ended September 30, 2009. The 12 percent increase is due to
higher revenues resulting from higher commodity prices, offset by lower
realized hedging gains of $7.7 million. On a per trust unit basis, funds
from operations decreased 15 percent from $0.48 in 2009 to $0.41 in
2010.
For the nine months ended September 30, 2010, funds from operations
increased 17 percent to $195.9 million from $167.8 million for the
comparable period of 2009. The increase is primarily due to higher
revenues driven by higher commodity prices, offset by lower realized
hedging gains of $50.7 million.
Funds from Operations
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Funds from operations ($000s) 60,018 53,766 195,944 167,788
Funds from operations per
trust unit 0.41 0.48 1.37 1.62
Payout ratio based on funds from
operations 66% 56% 59% 52%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
Joint Venture Partnership Agreement:
Effective April 20, 2009, the Trust 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 to earn an interest in freehold and crown acreage. The
Trust has a 65 percent interest in this agreement and MFC a 35 percent
interest and therefore the Trust'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 Trust) 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 undrilled freehold
and crown acreage will not be earned and the Trust will be subject to a
payment of 65 percent of a $5 million performance bond which reduces
with every expenditure. As at September 30, 2010, the Trust had spent
$10.1 million and, at the end of the current drilling program, the Trust
and MFC will have spent approximately $15.5 million, which is on track
to meet the commitments under this agreement.
Farm-in Agreement:
Effective August 10, 2009, the Trust and MFC entered into a Farm-in
Agreement with BP Canada. The arrangement consists of a two year initial
commitment, with a minimum capital commitment of $30 million ($18
million net) in the first year and $50 million ($30 million net) in the
second year, with an option for a third year, at NAL's election, for an
additional $50 million ($30 million net) commitment. The Trust 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 BP Canada. If the capital spending commitments are not met, interest
in the acreage will not be earned and the Trust will not be required to
pay any unspent amounts under the Agreement. As at September 30, 2010,
the Trust had spent $24.1 million (net) and satisfied its first year
commitment under the 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) 2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Office lease (1) 1,039 3,505 3,505 3,482 3,414
Office lease - Alberta Clipper
and 545 2,184 2,192 358 -
Breaker (2)
Transportation agreement 3,176 - - - -
Processing agreement (3) 599 2,242 401 384 -
Convertible debentures (4) - - 79,744 - 115,000
Bank debt - - 141,010 94,006 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 5,359 7,931 226,852 98,230 118,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Trust is allocated a pro rata share (currently
approximately 64 percent) of the expense on a monthly basis.
(2) Represents the full amount of the office lease assumed with the
acquisition of Alberta Clipper Inc. ("Alberta Clipper") and Breaker.
MFC will reimburse the Trust for 50 percent of the Alberta Clipper
obligation under a base price adjustment clause.
(3) Represents a gas processing agreement with a take or pay component.
(4) Principal amount.
QUARTERLY INFORMATION
2010
----------------------------------------------------------------------------
($000s, except per unit and
production amounts) Q3 Q2 Q1
----------------------------------------------------------------------------
Revenue, net of royalties (1) 100,657 105,925 135,662
Per unit 0.69 0.73 0.99
Cash flow from operations 82,082 43,326 63,648
Per unit 0.56 0.30 0.46
Funds from operations (2) 60,018 62,684 73,242
Per unit 0.41 0.43 0.53
Net income (loss) (781) 8,046 29,349
Per unit
basic (0.01) 0.06 0.21
diluted (0.01) 0.06 0.21
Average oil equivalent production
(boe/d - 6:1) 29,473 29,609 30,120
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
($000s, except per unit and
production amounts) Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Revenue, net of royalties (1) 88,165 85,988 60,922 77,791 161,156
Per unit 0.75 0.77 0.60 0.81 1.68
Cash flow from operations 53,060 52,999 63,690 66,546 77,326
Per unit 0.45 0.47 0.63 0.69 0.80
Funds from operations (2) 62,953 53,766 51,998 62,024 67,040
Per unit 0.53 0.48 0.51 0.64 0.70
Net income (loss) 5,634 8,249 (9,407) 4,724 55,374
Per unit
basic 0.05 0.07 (0.09) 0.05 0.58
diluted 0.05 0.07 (0.09) 0.05 0.56
Average oil equivalent
production
(boe/d - 6:1) 25,748(3) 23,418 23,049 23,836 23,984
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
DISCLOSURE CONTROLS AND PROCEDURES ("DC&P")
NAL's 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 Issuer's Annual and Interim Filings. The
control framework NAL's officers used to design NAL's ICFR is the
Internal Control - Integrated Framework published by the Committee of
Sponsoring Organizations of the Treadway Commission (the "COSO
Framework").
Under the supervision of the Chief Executive Officer and the Chief
Financial Officer, NAL conducted an evaluation of the effectiveness of
its ICFR as at December 31, 2009 based on the COSO Framework. Based on
this evaluation, the officers concluded that, as of December 31, 2009,
the controls are effective.
There has not been any change in NAL's ICFR during the first nine
months of 2010 that has materially affected, or is reasonably likely to
materially affect, NAL's ICFR.
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by NAL are disclosed in the
notes to NAL's December 31, 2009 audited consolidated financial
statements. Certain accounting policies require that management make
appropriate decisions when formulating estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and
expenses. The Manager reviews the estimates regularly. The emergence of
new information and changed circumstances may result in actual results
or changes in estimated amounts that differ materially from current
estimates. NAL might realize different results from the application of
new accounting standards published, from time to time, by various
regulatory bodies. An assessment of NAL's significant accounting
estimates is discussed in the MD&A filed with NAL's audited
consolidated financial statements for the year ended December 31, 2009.
FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards ("IFRS")
In February 2008, the Accounting Standards Board confirmed that the
transition date to IFRS from Canadian GAAP will be January 1, 2011 for
publicly accountable enterprises. Therefore, the Trust will be required
to report its results in accordance with IFRS starting in 2011, with
comparative disclosure for 2010.
The Trust has an IFRS conversion plan and has established timelines
for the completion and execution of the conversion project. The
conversion plan includes the following phases:
1. An IFRS diagnostic phase which involves a high level assessment of the
differences between Canadian GAAP and IFRS, identifying major impact
areas.
2. An in-depth review of GAAP differences and determination of transition
policy choices as well as ongoing IFRS accounting policies.
3. The implementation phase where solutions are developed and assessed.
This involves an evaluation of information systems, business processes,
procedures, internal controls and training to support the new accounting
requirements.
4. A post implementation phase which involves the parallel running of 2010
financial results, the preparation of IFRS financial statements and
disclosures and a review of processes and controls to make any required
changes.
The first two phases are complete. Phase three is substantially
completed, although procedures are being re-evaluated as the Trust moves
from policy choices to actual implementation. Phase four has started
and has included some parallel results, although this phase is not yet
fully complete.
The Trust considers the significant IFRS differences and majority of
the implementation work to be in relation to property, plant and
equipment ("PP&E"). IFRS policies for PP&E have been developed,
however it is premature to provide meaningful numerical analysis on the
impact of the changes. Further details are provided below.
The Trust has also identified a number of other areas where
potentially significant differences between Canadian GAAP and IFRS exist
for the Trust. Provisions, including asset retirement obligations
("ARO") and unit based compensation have been reviewed, accounting
policies recommended and implementation steps developed. The review of
presentation and disclosure standards has been performed and changes to
financial statement formats are summarized.
In July 2009, the International Accounting Standards Board ("IASB")
issued certain amendments and exemptions to IFRS 1 in order to make it
more practical for Canadian entities adopting IFRS for the first time.
The amendment allows the Trust to elect to measure its oil and gas
assets at the date of transition to IFRS using the net book value based
on Canadian GAAP at December 31, 2009, allowing for IFRS to be adopted
prospectively to its full cost pool, rather than performing
retrospective assessment of the oil and gas assets and related
expenditures. The Trust will apply this election on adoption of IFRS.
As noted above, the most significant change will be to PP&E. The
Trust, like many other Canadian oil and gas reporting issuers, applies
the "full cost" accounting methodology to its oil and gas assets. Under
full cost, capital expenditures are maintained in a single cost centre
for each country, and the cost centre is subject to a single depletion
calculation and impairment test. IFRS will require a much more detailed
assessment of oil and gas assets as follows:
- Capital expenditures will have to be segregated between
exploration and evaluation ("E&E") and development and production
("D&P") assets. In addition, assets will have to be aggregated at a
component level. Transitional amounts have been calculated and recorded,
which requires establishing the book value of the undeveloped land and
unproved properties and then allocating the remaining carrying value to
the D&P assets, based on reserve allocations for each component.
Therefore, subject to impairment testing, the value of PP&E assets
under previous Canadian GAPP will be equivalent to previous D&P and
E&E assets together under IFRS on January 1, 2010.
- For depletion and depreciation purposes, the Trust must determine
an appropriate depletion or depreciation method, and must deplete by
component. In addition, there is the option to deplete using a reserve
base of proved reserves or both proved plus probable reserves. NAL will
deplete its oil and gas properties using proved plus probable reserves
process under the unit of production methodology. As a result of
depleting on a proved plus probable basis, and all other things being
equal, depletion expense will be lower than when depletion expense is
calculated on a proved basis (as is the case under Canadian GAAP).
- Impairment tests are to be calculated at a cash generating unit
level ("CGU"), which is defined as the lowest level of assets that
produce independent cash inflows. The Trust has identified its CGU's for
this purpose. An impairment test has been performed individually for
all CGU's on transition with no impairment noted. On a go forward basis,
an impairment test must be performed when indicators suggest there may
be impairment. In addition, the recognition of impairment in a prior
year must be reversed should impairment conditions reverse.
Provisions and contingent liabilities and assets, including ARO are
identified and calculated somewhat differently under IFRS. A major
difference between current Canadian standards and IFRS appears to be the
discount rate used to measure the ARO. Under current Canadian standards
a credit adjusted risk free rate is used in calculating the provision.
Under IFRS, a risk free rate should be used when the expected cash flows
are risked. Within the industry, there has been a debate on whether
there should be a risk component applied to conventional property
estimated cash outflows. A lower discount rate will increase the
provision on transition to IFRS with a corresponding charge to a
retained earnings or deficit. Further, onerous contracts will require
identification and, to the extent they exist, must be recorded as a
liability on the balance sheet. On transition, it is not expected that
any onerous contracts exist that would require recognition under IFRS
for the Trust.
IFRS will allow the Trust to use IFRS rules for business
combinations on a prospective basis rather than restating all business
combinations. The Trust intends to elect this exemption on transition to
IFRS. The IFRS business combination rules converge with the new CICA
Handbook Section 1582 that is also effective for NAL on January 1, 2011,
however, early adoption is permitted.
The Trust has elected under IFRS to treat convertible debentures as
debt. The convertible debentures are valued on a marked to market basis
and the entire $12 million equity component is eliminated. On conversion
to a corporation, there will be a requirement to bifurcate the
debentures back to their equity and debt components.
Deferred income taxes are expected to be impacted due to the
requirement under IFRS to apply the highest applicable tax rate to the
temporary differences in question at the Trust level (rather than the
most likely rate under Canadian GAAP). As a result, deferred taxes on
the statement of financial position are expected to increase, due to an
increase in the expected tax rate of approximately 39 percent. Further,
on conversion to a corporation, it is expected that the tax rate will
decrease to approximately 25 percent, thus reducing deferred taxes.
Regular reporting on the status of IFRS is provided to the Board of
Directors through the Audit Committee. In addition, the Trust has
actively engaged its auditors in the conversion project and will
continue to engage them in ongoing discussions as the project
progresses.
The development of the Trust's opening balance sheet in accordance
with IFRS, as at January 1, 2010, is mostly complete, but remains
subject to finalization. Financial systems have been modified to
accommodate the reporting of both Canadian GAAP financial results and
IFRS financial results in 2010. In addition, modifications have been
made to ensure data is captured with the added level of granularity
required under IFRS. As accounting policies are finalized further
modifications to the financial systems may be required. Other IT systems
that capture data used in the financial system are under review as to
whether any modifications are still required.
Internal staff has been assigned to lead the transition project,
supplemented with consultants as required. Training of key internal
finance and accounting personnel is underway both through external IFRS
oil and gas training and internal training. As accounting policies are
finalized, training will be expanded to other key personnel within the
organization.
As accounting policies are finalized under IFRS, NAL will be
assessing the impact on its various business activities, including
banking arrangements, compensation arrangements and risk management
agreements.
Internal business processes and controls are being assessed and
developed to enable the collection of information so that data can be
attained in the manner necessary to report under IFRS both on an ongoing
basis and on transition. For example, processes are currently being
developed and scrutinized to enable the monitoring of E&E assets and
when the transfer to D&P will occur. As processes are developed or
amended, internal controls are being assessed to determine any required
changes. This has been, and continues to be, an ongoing process to
ensure all changes in accounting policies include appropriate controls
and procedures.
In addition, NAL will also ensure that adequate information
regarding the transition is provided to all stakeholders on a timely
basis.
The International Accounting Standards Board is currently
undertaking an extractive activities project to develop accounting
standards specifically related to the oil and gas industry. However, it
is not expected that the project will be completed prior to IFRS
adoption in Canada.
The transition from Canadian GAAP to IFRS is a significant
undertaking that may materially affect our reported financial position
and results of operations. The Trust is confident that it will meet the
requirements for transition by the changeover deadline.
Dated: November 9, 2010
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
September 30, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 38 $ 1,604
Accounts receivable 45,573 61,631
Prepaids and other receivables 4,157 15,663
Derivative contracts (Note 11) 10,621 6,285
Future income tax asset - 3,132
----------------------------------------------------------------------------
60,389 88,315
Derivative contracts (Note 11) - 2,461
Future income tax asset 6,461 -
Goodwill 14,722 14,722
Property, plant and equipment (Note 3) 1,525,464 1,503,952
----------------------------------------------------------------------------
$ 1,607,036 $ 1,609,450
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 95,061 $ 110,897
Note payable (Note 2) 7,953 8,907
Distributions payable to unitholders 13,196 12,372
Derivative contracts (Note 11) - 11,231
Future income tax liability 707 -
----------------------------------------------------------------------------
116,917 143,407
Bank debt (Note 4) $ 235,016 $ 230,713
Convertible debentures (Note 5) 180,649 177,977
Derivative contracts (Note 11) 252 -
Other liabilities (Note 6) 7,046 7,643
Asset retirement obligations (Note 8) 135,820 127,872
Future income tax liability - 24,778
Non-controlling interest (Note 9) 2,677 2,868
----------------------------------------------------------------------------
678,377 715,258
Unitholders' equity
Unitholders' capital (Note 10) 1,595,957 1,482,029
Equity component of convertible debentures
(Note 5) 12,628 12,628
Deficit (Note 10) (679,926) (600,465)
----------------------------------------------------------------------------
928,659 894,192
----------------------------------------------------------------------------
$ 1,607,036 $ 1,609,450
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (Note 12)
Trust units outstanding (000s) 146,621 137,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF INCOME (LOSS), COMPREHENSIVE INCOME (LOSS) AND
DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
Three months ended Nine months ended
September 30 September 30
----------------------------------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue
Oil, natural gas and
liquid sales $ 117,409 $ 87,373 $ 379,045 $ 252,752
Crown royalties (15,481) (9,563) (50,371) (30,917)
Freehold and other
royalties (5,760) (5,387) (17,867) (13,775)
----------------------------------------------------------------------------
96,168 72,423 310,807 208,060
Gain (loss) on
derivative contracts
(Note 11):
Realized gain 11,109 18,819 18,042 68,740
Unrealized gain (loss) (6,826) (5,499) 12,854 (53,487)
----------------------------------------------------------------------------
4,283 13,320 30,896 15,253
Other income 206 245 541 1,388
----------------------------------------------------------------------------
100,657 85,988 342,244 224,701
----------------------------------------------------------------------------
Expenses
Operating 31,768 22,657 90,654 73,056
Transportation 1,654 1,075 4,896 3,142
General and
administrative 3,522 4,095 11,920 10,753
Unit-based incentive
compensation (Note 7) 1,384 3,805 1,094 6,865
Corporate conversion
costs 42 - 160 -
Interest on bank debt 2,831 2,761 8,587 7,686
Interest and accretion
on convertible debentures 4,173 1,727 12,411 5,176
Depletion, depreciation
and amortization 66,222 46,209 192,161 132,196
Accretion on asset
retirement obligations 2,708 2,003 8,034 5,717
----------------------------------------------------------------------------
114,304 84,332 329,917 244,591
----------------------------------------------------------------------------
Income (loss) before
taxes and
non-controlling interest (13,647) 1,656 12,327 (19,890)
Income tax recovery
(expense) (6) - (4) 1
Future income tax
reduction 13,347 7,409 25,925 25,766
----------------------------------------------------------------------------
Total income tax
reduction 13,341 7,409 25,921 25,767
----------------------------------------------------------------------------
Income (loss) before
non-controlling interest (306) 9,065 38,248 5,877
Non-controlling interest
(Note 9) (475) (816) (1,634) (2,311)
----------------------------------------------------------------------------
Net income (loss) and
comprehensive income
(loss) (781) 8,249 36,614 3,566
----------------------------------------------------------------------------
Deficit, beginning of
period (639,616) (551,433) (600,465) (489,512)
Net income (loss) (781) 8,249 36,614 3,566
Distributions declared (39,529) (30,290) (116,075) (87,528)
----------------------------------------------------------------------------
Deficit, end of period $ (679,926) $ (573,474) $ (679,926) $ (573,474)
----------------------------------------------------------------------------
Net income (loss) per
trust unit (Note 10)
Basic $ (0.01) $ 0.07 $ 0.26 $ 0.03
Diluted $ (0.01) $ 0.07 $ 0.26 $ 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average trust
units outstanding (000s) 146,297 112,109 142,890 103,444
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
Three months ended Nine months ended
September 30 September 30
----------------------------------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Operating Activities
Net income (loss) $ (781) $ 8,249 $ 36,614 $ 3,566
Items not involving
cash:
Depletion,
depreciation and
amortization 66,222 46,209 192,161 132,196
Accretion on asset
retirement obligations 2,708 2,003 8,034 5,717
Unrealized loss
(gain) on derivative
contracts 6,826 5,499 (12,854) 53,487
Future income tax
reduction (13,347) (7,409) (25,925) (25,766)
Non-cash accretion
expense on convertible
debentures 1,015 382 3,017 1,140
Non-controlling interest (516) 80 (191) 788
Lease amortization (426) (217) (1,225) (217)
Abandonment and
reclamation (1,683) (1,030) (3,687) (3,123)
Change in non-cash
working capital 22,064 (767) (6,888) 15,447
----------------------------------------------------------------------------
82,082 52,999 189,056 183,235
----------------------------------------------------------------------------
Financing Activities
Distributions paid to
unitholders (32,757) (25,828) (97,187) (85,178)
Increase (decrease) in
bank debt 18,695 2,569 4,303 (114,292)
Issue of trust units,
net of issue costs (104) (424) 94,472 81,593
Note repayment from
MFC (Note 2) - - - 49,599
Partnership
distribution paid to MFC - - - (53,302)
Issuance of
convertible
debentures, net of
issue costs - - (345) -
Change in non-cash
working capital - (5,697) - (5,615)
----------------------------------------------------------------------------
(14,166) (29,380) 1,243 (127,195)
----------------------------------------------------------------------------
Investing Activities
Additions to property,
plant and equipment (58,510) (42,376) (176,863) (96,264)
Property acquisitions (223) - (45,380) (2,799)
Proceeds from
dispositions 135 - 14,914 265
Acquisition of Breaker (901) - (901) -
Acquisition of Clipper - (84) - (833)
Acquisition of
Spearpoint - (9,749) - (9,749)
Disposition of Clipper - 645 - 53,302
Disposition of
Spearpoint - 6,772 (309) 6,772
Change in non-cash
working capital (9,130) 16,196 16,674 (7,314)
----------------------------------------------------------------------------
(68,629) (28,596) (191,865) (56,620)
----------------------------------------------------------------------------
Increase (decrease) in
cash and cash
equivalents (713) (4,977) (1,566) (580)
Cash and cash
equivalents, beginning
of period 751 9,981 1,604 5,584
----------------------------------------------------------------------------
Cash and cash
equivalents, end of
period $ 38 $ 5,004 $ 38 $ 5,004
----------------------------------------------------------------------------
Supplementary
disclosure of cash
flow information:
Cash paid (received)
during the period for:
Interest $ 3,879 $ 4,883 $ 19,308 $ 14,161
Tax - (206) 502 $(278)
----------------------------------------------------------------------------
Cash and cash
equivalents is
comprised of:
Cash $ 38 $ 5,004 $ 38 $ 5,004
Short term
investments - - - -
----------------------------------------------------------------------------
$ 38 $ 5,004 $ 38 $ 5,004
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Refer to Notes 8 and 10 for significant non-cash amounts not included in
The cash flow statement.
See accompanying notes.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Nine months ended September 30, 2010
(Tabular amounts in thousands of dollars, except per unit amounts)
(unaudited)
1. SUMMARY OF ACCOUNTING POLICIES
Management prepared the interim consolidated financial statements of
NAL Oil & Gas Trust ("NAL" or the "Trust") in accordance with
accounting principles generally accepted in Canada and following the
same accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2009. The
following disclosure is incremental to the disclosure included within
the annual financial statements. Please read the interim consolidated
financial statements in conjunction with the consolidated financial
statements and notes thereto in NAL's annual report for the year ended
December 31, 2009.
2. RELATED PARTY TRANSACTIONS
The Trust is managed by NAL Resources Management Limited (the
"Manager"). The Manager is a wholly-owned subsidiary of Manulife
Financial Corporation ("MFC") and also manages on its behalf NAL
Resources Limited, another wholly-owned subsidiary of MFC.
The Manager provides certain services to the Trust pursuant to an
administrative services and cost sharing agreement. This agreement
requires the Trust to reimburse the Manager, at cost, for general and
administrative ("G&A") expenses incurred by the Manager on behalf of
the Trust. The Trust paid $3.2 million (2009 - $3.4 million) for the
reimbursement of G&A expenses during the third quarter and $10.4
million (2009 - $8.7 million) year-to-date. The Trust also pays the
Manager its share of unit-based compensation expense when cash
compensation is paid to employees under the terms of the Manager's
incentive compensation plans, of which, $7.0 million has been paid
year-to-date relating to notional units that vested on November 30, 2009
(2009 - $2.3 million).
The Trust and a wholly owned subsidiary of MFC jointly own a limited
partnership (the "Partnership"). This Partnership holds the assets
acquired from the acquisition of Tiberius Exploration Inc. and Spear
Exploration Inc. ("Tiberius and Spear") in February 2008. Both the Trust
and MFC have 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 exchange for this interest, the royalty
holders each paid $49.6 million to the Partnership by way of promissory
notes in 2008. Although the MFC note resided in the Partnership, it was
consolidated by virtue of the Trust having control of the Partnership as
described below.
The Trust, by virtue of being the owner of the general partner under
the partnership agreement, is required to consolidate the results of
the Partnership into its financial statements on the basis that the
Trust has control over the Partnership.
During the first quarter of 2009, MFC repaid the note receivable to
the Partnership for $49.6 million. The Partnership then paid an equal
distribution of $49.6 million to MFC. This resulted in a $49.6 million
reduction to the non-controlling interest (Note 9). In addition, during
2009 the Partnership paid distributions to its partners, MFC's share
being $5.0 million (Note 9).
As at September 30, 2010, there is a note payable of $8.0 million
with MFC arising from the Tiberius and Spear acquisition. The note
payable is included on consolidation of the Partnership, but is
effectively eliminated through the non-controlling interest. The note is
due on demand, unsecured and bears interest at prime plus three
percent. The amount of the note payable to MFC is adjusted to reflect
MFC's share of the capital expenditures of the Partnership which MFC has
funded, less any loan repayments made.
Net interest expense on this note of $0.1 million was payable by the
Trust for the third quarter of 2010 (2009 - $0.1 million net interest
expense), and net interest expense of $0.3 million (2009 - $0.3 million
net interest income) was payable by the Trust for the first nine months
of 2010. This amount is reported as other income.
The following amounts are due to and from related parties as at
September 30, 2010 and December 31, 2009 and have been included in
prepaids and other receivables, accounts payable and accrued liabilities
and note payable on the balance sheet:
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Due from NAL Resources Limited $ (1,401) $ 1,731
Due to NAL Resources
Management Limited (1,111) (8,753)
Due to Manulife Financial
Corporation(1) (8,260) (9,472)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ (10,772) $ (16,494)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included on consolidation, eliminated through non-controlling interest.
Represents note payable of $8.0 million (2009: $8.9 million), plus
Amounts due from (to) MFC of ($0.3) million (2009: ($0.6) million),
presented in accounts payable/ accounts receivable, relating to the net
interest and NPI amounts due.
3. PROPERTY, PLANT AND EQUIPMENT
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Petroleum and natural gas
properties, at cost $ 2,792,941 $ 2,579,268
Less: Accumulated depletion and
depreciation (1,267,477) (1,075,316)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 1,525,464 $ 1,503,952
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The calculation of third quarter depletion and depreciation included
future development costs for proved reserves of $209.2 million (2009 -
$41.8 million) and excluded costs associated with undeveloped land and
unproved properties of $171.1 million (2009 - $46.8 million).
During the nine months ended September 30, 2010, the Trust
capitalized $6.2 million (2009 - $4.3 million) of G&A costs and $0.4
million (2009 - $2.8 million) of unit-based incentive compensation that
were directly related to exploitation and development programs.
4. BANK DEBT
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Production loan facility $ 234,195 $ 230,713
Working capital facility 821 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt outstanding $ 235,016 $ 230,713
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust 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 Trust's oil and gas reserves and other assets.
Given that the borrowing base is dependent on the Trust'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 Trust and its subsidiary and affiliated entities. The facility will
revolve until April 30, 2011 at which time it may be extended for a
further 364-day revolving period upon agreement between the Trust and
the bank syndicate. If the credit facility is not extended in April
2011, 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, 2012.
The Trust is restricted under the credit facility from making
distributions to its unitholders in excess of its consolidated operating
cash flow during the 18 month period preceding the distribution date.
The Trust is in compliance with this covenant.
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 Trust. As at September 30,
2010 and December 31, 2009 all amounts outstanding were in Canadian
dollars.
On September 30, 2010 the effective interest rate on amounts
outstanding under the credit facility was 5.19 percent (2009 - 3.68
percent). The Trust's interest charge includes this fixed interest rate
component, plus a standby fee, a stamping fee and the fee for renewal.
5. CONVERTIBLE DEBENTURES
The following table reconciles the principal amount, debt component and
equity component of the convertible debentures.
Nine months ended
September 30, 2010
----------------------------------------------------------------------------
6.25% 6.75% Total
----------------------------------------------------------------------------
Principal, beginning of period 115,000 79,744 194,744
Issued during period - - -
----------------------------------------------------------------------------
Principal, end of period 115,000 79,744 194,744
----------------------------------------------------------------------------
Debt component, beginning of period 102,450 75,527 177,977
Issued during period - - -
Issue costs (345) - (345)
Accretion 1,854 1,163 3,017
----------------------------------------------------------------------------
Debt component, end of period 103,959 76,690 180,649
----------------------------------------------------------------------------
Equity component, beginning of period 8,036 4,592 12,628
Issued during period - - -
----------------------------------------------------------------------------
Equity component, end of period 8,036 4,592 12,628
----------------------------------------------------------------------------
Year ended
December 31, 2009
----------------------------------------------------------------------------
6.25% 6.75% Total
----------------------------------------------------------------------------
Principal, beginning of period - 79,744 79,744
Issued during period 115,000 - 115,000
----------------------------------------------------------------------------
Principal, end of period 115,000 79,744 194,744
----------------------------------------------------------------------------
Debt component, beginning of period - 74,004 74,004
Issued during period 106,965 - 106,965
Issue costs (4,714) - (4,714)
Accretion 199 1,523 1,722
----------------------------------------------------------------------------
Debt component, end of period 102,450 75,527 177,977
----------------------------------------------------------------------------
Equity component, beginning of period - 4,592 4,592
Issued during period 8,036 - 8,036
----------------------------------------------------------------------------
Equity component, end of period 8,036 4,592 12,628
----------------------------------------------------------------------------
6. OTHER LIABILITIES
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Unit-based incentive compensation
(Note 7) 4,611 3,935
Excess office lease obligation (1) 2,435 3,708
----------------------------------------------------------------------------
7,046 7,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Trust for 50 percent of the Alberta Clipper obligation of
$0.6 million under a base price adjustment clause.
7. UNIT-BASED INCENTIVE COMPENSATION PLAN
The Trust recorded total compensation expense of $1.5 million in the
first nine months of 2010, of which $1.1 million was recorded as an
expense and $0.4 million as property, plant and equipment ($8.8 million
was expensed through earnings and $3.7 million recorded as property,
plant and equipment for the year ended December 31, 2009). The
compensation expense was based on the September 30, 2010 trust unit
price of $11.53 (December 31, 2009 - $13.74), accrued distributions,
performance factors and the number of units vesting on maturity.
The following table reconciles the change in total accrued trust unit-based incentive compensation relating to the plan:
Nine months ended Year ended
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of period 16,411 6,274
Increase in liability 1,539 12,461
Cash payout, relating to units
vested (7,006) (2,324)
----------------------------------------------------------------------------
Balance, end of period 10,944 16,411
----------------------------------------------------------------------------
Current portion of liability(1) 6,333 12,476
----------------------------------------------------------------------------
Long-term liability(2) 4,611 3,935
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.
(2) Included in other liabilities, (Note 6).
The following table sets forth a reconciliation of the Trust's incentive
plan activity for the nine months ended September 30, 2010.
Number of Number of
Restricted Performance
Units Units Total
----------------------------------------------------------------------------
Balance, beginning of period 253,641 520,510 774,151
Allocation rate change 22,998 47,199 70,195
Issued 121,538 252,369 373,907
Exercised (118,355) - (118,355)
Forfeited (41,029) (84,904) (125,933)
----------------------------------------------------------------------------
Balance, end of period 238,793 735,172 973,965
----------------------------------------------------------------------------
Exercisable, end of period - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the Trust's asset retirement obligations.
Nine months ended Year ended
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of period $ 127,872 $ 90,844
Accretion expense 8,034 7,856
Revisions to estimates (569) 558
Liabilities incurred 1,919 1,522
Liabilities acquired 2,462 32,311
Liabilities disposed (211) -
Liabilities settled (3,687) (5,219)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period $ 135,820 $ 127,872
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL's estimated credit-adjusted risk-free rate of eight to nine
percent (2009 - eight to nine percent) and an inflation rate of two
percent (2009 - two percent) were used to calculate the present value of
the asset retirement obligations.
9. NON-CONTROLLING INTEREST
The Trust has recorded a non-controlling interest in respect of the
50 percent ownership interest held by MFC in the Partnership holding the
Tiberius and Spear assets. The non-controlling interest on the balance
sheet represents 50 percent of the net assets of the Partnership as
follows:
Nine months ended Year ended
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Non-controlling interest,
beginning of period $ 2,868 $ 56,380
Net income attributable to
non-controlling interest (191) 1,040
Distributions to MFC(1) - (54,552)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-controlling interest, end of
period $ 2,677 $ 2,868
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes $49.6 million distribution paid following settlement of note
receivable (Note 2).
The non-controlling interest in the statement of income is comprised of:
Three months ended Nine months ended
September 30 September 30
--------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Net profits interest
expense $ 991 $ 736 $ 1,825 $ 1,523
Share of net income
attributable to MFC (516) 80 (191) 788
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 475 $ 816 $ 1,634 $ 2,311
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. UNITHOLDERS EQUITY
Units Issued:
Nine months ended Year ended
September 30, 2010 December 31, 2009
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of the
period 137,471 $ 1,482,029 96,181 $ 1,042,183
Equity offering 7,550 100,038 9,603 86,422
Issued on corporate
acquisition - - 30,453 345,075
Less issue expenses (net
of tax) - (4,174) - (3,565)
Issued from Distribution
Reinvestment Plan 1,600 18,064 1,234 11,914
----------------------------------------------------------------------------
Balance, end of the
period 146,621 $ 1,595,957 137,471 $ 1,482,029
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Unit Information
Basic per trust unit amounts are calculated using the weighted
average number of trust units outstanding. The calculation of diluted
net income per trust unit includes the weighted average trust units
potentially issuable on the conversion of the convertible debentures.
For the three and nine months ended September 30, 2010 and 2009, the
trust units potentially issuable on the conversion of the convertible
debentures are anti-dilutive and are therefore excluded from the
calculation. Total weighted average trust units issuable on conversion
of the convertible debentures and excluded from the diluted net income
per trust unit calculation for the three and nine months ended September
30, 2010 were 12,665,697 (2009 - 5,696,000). As at September 30, 2010,
the total convertible debentures outstanding were immediately
convertible to 12,665,697 trust units.
Deficit
The deficit is comprised of the following:
Nine months ended Year ended
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Accumulated income $ 598,845 $ 562,231
Accumulated cash distributions (1,278,771) (1,162,696)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ (679,926) $ (600,465)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL RISK MANAGEMENT
Foreign currency exchange rate risk
NAL has the following exchange rate derivative contracts outstanding:
----------------------------------------------------------------------------
Total
Remaining
Contracted Trust Counterparty
EXCHANGE RATE Remaining Amount(1) Fixed Floating
CONTRACT Term (US$ MM) Rate Rate
----------------------------------------------------------------------------
Forward-floating to fixed Oct 2010 - 27.0 1.0904 BofC Average
Dec 2010 Noon Rate
Forward-floating to fixed Jan 2011 - 60.0 1.0571 BofC Average
Dec 2011 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional US$ denominated commodity sales.
In addition, NAL has the following exchange rate contract commitments:
(i) From October to December 2010, NAL has a commitment to sell US$3
million ($1 million/month) at 1.045 if the monthly Bank of Canada
average noon rate exceeds 1.045. NAL is paid a premium of approximately
$10,000 a month when the average noon rate falls between 0.95 and 1.045.
(ii) From January to December 2011, NAL has a commitment to sell
US$6 million ($500,000/month) at 1.12 if the monthly Bank of Canada
average noon rate exceeds 1.12. NAL is paid a premium of approximately
$25,000 a month when the average noon rate falls between 0.95 and 1.12.
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
September 30, 2010, if exchange rates had strengthened by $0.01, with
all other variables held constant, net income for the period would have
been $0.6 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 $0.01 weaker.
Commodity price risk
NAL has the following commodity risk management contracts outstanding:
CRUDE OIL Q4-10 Q1-11 Q2-11 Q3-11 Q4-11
----------------------------------------------------------------------------
US$ Collar Contracts
$US WTI Collar Volume (bbl/d) 1,900 800 800
Bought Puts - Average Strike
Price ($US/bbl) 68.03 81.25 81.25
Sold Calls - Average Strike
Price ($US/bbl) 80.62 94.47 94.47
US$ Swap Contracts
$US WTI Swap Volume (bbl/d) (1) 4,199 4,900 4,900 5,500 5,500
Average WTI Swap Price ($US/bbl) 83.47 87.39 87.39 88.05 88.05
Total Oil Volume (bbl/d) 6,099 5,700 5,700 5,500 5,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Two calendar 2011 500 bbl/d swap contracts with an average price of
$95.00 contain extendible call options. The extendible call option
provides the counterparty with the option to extend the contract into
calendar 2012 under the same price and volumetric terms. The
counterparty can exercise this option at any time prior to December 30,
2011.
NATURAL GAS Q4-10 Q1-11 Q2-11
----------------------------------------------------------------------------
Swap Contracts
AECO Swap Volume (GJ/d) 31,337 5,000 4,000
AECO Average Price ($Cdn/GJ) 5.52 5.61 5.78
Total Natural gas Volume (GJ/d) 31,337 5,000 4,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the remainder of 2010, the Trust has outstanding contracts
representing approximately 45 percent of its net liquids and natural gas
production after royalties. For 2011, the Trust has outstanding
contracts representing 23 percent of its net liquids and natural gas
products after royalties.
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 September
30, 2010, 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 $1.2
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
NAL has the following interest rate derivative contracts outstanding:
----------------------------------------------------------------------------
Trust
INTEREST RATE Remaining Amount Fixed Counterparty
CONTRACT Term (millions)(1) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Dec 2011 $39.0 1.5864% (3 months)
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Jan 2013 $22.0 1.3850% (3 months)
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Jan 2014 $22.0 1.5100% (3 months)
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Mar 2013 $14.0 1.8500% (3 months)
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Mar 2013 $14.0 1.8750% (3 months)
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Mar 2014 $14.0 1.9300% (3 months)
Swaps-floating Oct 2010 - CAD-BA-CDOR
to fixed Mar 2014 $14.0 1.9850% (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
September 30, 2010, if interest rates had been one percent lower, with
all other variables held constant, net income for the period would have
been $3.0 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 Derivative Contracts
Derivative 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$79.97 per barrel to
US$86.15 per barrel for oil and $3.43 per GJ to $4.31 per GJ for natural
gas) as of the balance sheet date, using the remaining contracted oil
and natural gas volumes. 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 1.012 percent
to 1.822 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 1.027 to 1.038) 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:
Nine months ended Year ended
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Fair value of commodity contracts $ 7,940 $ (8,932)
Fair value of interest rate swaps (252) 2,461
Fair value of foreign exchange
rate swaps 2,681 3,986
----------------------------------------------------------------------------
$ 10,369 $ (2,485)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The gain/(loss) on derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts (4,269) (184) 13,216 (56,151)
Natural gas contracts (3,517) (8,251) 3,656 (5,560)
Interest rate swaps (1,017) (374) (2,713) 2,776
Exchange rate swaps 1,977 3,310 (1,305) 5,448
----------------------------------------------------------------------------
Unrealized gain (loss) (6,826) (5,499) 12,854 (53,487)
Realized gain (loss):
Crude oil contracts 2,146 7,526 (2,648) 44,179
Natural gas contracts 7,821 8,331 17,218 19,794
Interest rate swaps (268) (226) (910) (433)
Exchange rate swaps 1,410 3,188 4,382 5,200
----------------------------------------------------------------------------
Realized gain 11,109 18,819 18,042 68,740
----------------------------------------------------------------------------
Gain on derivative
contracts 4,283 13,320 30,896 15,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------
These contracts are presented on the balance sheet as short term/long term,
assets and liabilities as follows:
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Current unrealized loss on
derivative contracts $ - $ (11,231)
Current unrealized gain on
derivative contracts 10,621 6,285
----------------------------------------------------------------------------
Current unrealized gain (loss) on
derivative contracts 10,621 (4,946)
Long term unrealized gain (loss)
on derivative contracts (252) 2,461
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net fair value of derivative
contracts $ 10,369 $ (2,485)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table reconciles the movement in the fair value of the Trust's
derivative contracts:
Three months ended Nine months ended
September 30 September 30
--------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unrealized gain (loss),
beginning of period $ 17,195 $ 17,826 $ (2,485) $ 65,406
Unrealized gain
acquired(1) - - - 408
Unrealized gain, end of
period 10,369 12,327 10,369 12,327
----------------------------------------------------------------------------
Unrealized gain (loss)
for the period (6,826) (5,499) 12,854 (53,487)
Realized gain in the
period 11,109 18,819 18,042 68,740
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gain on derivative
contracts $4,283 $ 13,320 $ 30,896 $ 15,253
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumed on acquisition of Alberta Clipper Energy Inc.
Capital Management
The Trust's policy is to maintain a strong and flexible capital base
to ensure that distribution levels are sustainable, while at the same
time providing the flexibility to take advantage of operational and
acquisition opportunities.
The Trust 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 Trust considers its
capital structure to include Unitholders' Capital, bank debt,
convertible debentures, other liabilities, and working capital
(excluding derivative contracts, notes with MFC and future income tax)
as shown below. In order to maintain or adjust its capital structure,
the Trust may adjust the amount of distributions paid to unitholders,
issue new trust units, adjust its capital spending to modify debt
levels, or suspend/resume its DRIP or Premium DRIP programs.
The Trust 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, notes with MFC and future income tax balances).
Net debt is measured with and without convertible debentures. The
Trust's strategy is to maintain a conservative net debt to 12 month
trailing funds from operations as compared to other oil and gas trusts,
both before and after taking into account the convertible debentures.
The Trust will, for the appropriate opportunity, increase its debt to
funds from operations ratio above the Trust's average. In order to
facilitate the management of this ratio, the Trust 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 September 30, 2010, the Trust had a total net debt to 12
months trailing funds from operations ratio of 1.91, as calculated in
the table below. At December 31, 2009, the Trust had a total net debt to
12 months trailing funds from operations ratio of 2.07. The decrease in
the net debt to 12 months trailing funds from operations ratio in 2009
is attributable to higher funds from operations, primarily due to higher
commodity prices and volumes, offset by higher operating and interest
expenses.
The credit facility is determined based on the reserves of the Trust
(see Note 4) and is therefore commodity price sensitive. The Trust is
restricted under its credit facility from making distributions to its
unitholders in excess of its consolidated operating cash flow during the
18 month period preceding the distribution date. As at September 30,
2010 and December 31, 2009, the Trust was in full compliance with this
external restriction on distributions.
The Trust has no restrictions on the issuance of units other than the authorized limit of 500 million.
Under the tax legislation regarding the change in the taxation of
income trusts, the Trust has a grandfathering period to 2011, when the
rules come into effect. The grandfathering period restricts "undue
expansion" of the Trust by placing growth limits for issuances of equity
and convertible debt, based on the market capitalization of the Trust
on October 31, 2006, the date the announcement of the changes in the tax
legislation. At September 30, 2010, the Trust has approximately $417
million of available safe harbour.
There has been no change in the approach to capital management during 2010.
Capitalization
----------------------------------------------------------------------------
September 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Trust unit equity $ 928,659 $ 894,192
Bank debt 235,016 230,713
Working capital deficit(1) 65,535 52,014
----------------------------------------------------------------------------
Net debt 300,551 282,727
Convertible debentures(2) 194,744 194,744
----------------------------------------------------------------------------
Total net debt(2) $ 495,295 $ 477,471
Cash flow from operating
activities for last 12 months $ 242,116 $ 236,295
Add back change in non-cash
working capital 16,781 (5,554)
----------------------------------------------------------------------------
Trailing 12 months funds from
operations $ 258,897 $ 230,741
Net debt to trailing 12 month
funds from operations(3) 1.16 1.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total net debt to trailing
12-month funds from operations(4) 1.91 2.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital and other liabilities, excluding derivative contracts,
future income taxes and notes with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt excluding convertible debentures divided by funds
from operations for the previous 12 months.
(4) Calculated as total debt divided by funds from operations for the
previous 12 months.
12. COMMITMENTS
(i) Joint Venture Partnership Agreement:
Effective April 20, 2009, the Trust 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 to earn an interest in freehold and crown acreage. The
Trust has a 65 percent interest in this agreement and MFC a 35 percent
interest and therefore the Trust'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 Trust) 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 undrilled freehold
and crown acreage will not be earned and the Trust will be subject to a
payment of 65 percent of a $5 million performance bond which reduces
with every expenditure. As at September 30, 2010, the Trust had spent
$10.1 million and, at the end of the current drilling program, the Trust
and MFC will have spent approximately $15.5 million, which is on track
to meet the commitments under this agreement.
(ii) Farm-in Agreement:
Effective August 10, 2009, the Trust and MFC entered into a farm-in
agreement with BP Canada. The arrangement consists of a two year initial
commitment, with a minimum capital commitment of $30 million in the
first year and $50 million in the second year, with an option for a
third year, at NAL's election, for an additional $50 million commitment.
The Trust 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 BP Canada. If the capital spending
commitments are not met, interest in the acreage will not be earned and
the Trust will not be required to pay any unspent amounts under the
Agreement. As at September 30, 2010, the Trust had spent $24.1 million
(net) and satisfied its first year commitment under the agreement.
(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:
----------------------------------------------------------------------------
2010 2011 2012 2013 2014
----------------------------------------------------------------------------
Office lease (1) 1,039 3,505 3,505 3,482 3,414
Office lease - Clipper and
Breaker (2) 545 2,184 2,192 358 -
Transportation agreement 3,176 - - - -
Processing agreement (3) 599 2,242 401 384 -
Convertible debentures (4) - - 79,744 - 115,000
Bank debt - - 141,010 94,006 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 5,359 7,931 226,852 98,230 118,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Trust is allocated a pro rata share (currently
approximately 64 percent) of the expense on a monthly basis.
(2) Represents the full amount of the office lease assumed with the
acquisition of Alberta Clipper and Breaker Energy Ltd. MFC will
reimburse the Trust for 50 percent of the Alberta Clipper obligation
under a base price adjustment clause.
(3) Represents a gas processing agreement with a take or pay component.
(4) Principal amount.
13. SUBSEQUENT EVENTS
On October 22, 2010, the Trust entered into an agreement to purchase
oil and gas properties for $23.5 million, subject to normal purchase
price adjustments. This purchase is expected to close in December 2010.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TRADING PERFORMANCE
For the Quarter Ended
-----------------------------------------------------
30-Sept-10 30-Jun-10 30-Sept-09 30-Jun-09
----------------------------------------------------------------------------
PRICE
High $ 11.53 $ 13.57 $ 12.75 $ 10.53
Low $ 9.96 $ 9.68 $ 8.48 $ 6.63
Close $ 11.53 $ 10.60 $ 12.70 $ 9.37
Daily Average Volume 732,492 601,723 439,319 459,603
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL Oil & Gas Trust provides investors with a yield-oriented
opportunity to participate in the Canadian upstream conventional oil and
gas industry. The Trust generates monthly cash distributions for its
Unitholders by pursuing a strategy of acquiring, developing, producing
and selling crude oil, natural gas and natural gas liquids from pools in
southeastern Saskatchewan, central Alberta, northeastern British
Columbia and Lake Erie, Ontario. Trust units trade on the Toronto Stock
Exchange under the symbol "NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Investor Relations
403.294.3620 or Toll Free: 888.223.8792
403.294.3601 (FAX)
Investor.Relations@nal.ca
www.nal.ca