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
----------------------------------------------------------------------------
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:
----------------------------------------------------------------------------
Three months Nine months
ended September 30 ended September 30
-----------------------------------------
$(000s) 2010 2009 2010 2009
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Operated wells 35 18.8 1 0.7 0 0
Non-operated wells 1 0.1 4 0.6 0 0
----------------------------------------------------------------------------
Total wells drilled 36 18.9 5 1.3 0 0
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Dry & Abandoned Total
-----------------------------------
Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 0 0 36 19.5
Non-operated wells 0 0 5 0.7
----------------------------------------------------------------------------
Total wells drilled 0 0 41 20.2
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total capitalized expenditures
before acquisitions 58,510 42,376 176,863 96,264
----------------------------------------------------------------------------
Property acquisitions, net 88 - 30,466 2,534
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total revenue 115,755 86,298 374,149 249,610
$/boe 42.69 40.06 46.10 39.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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".
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