CALGARY, ALBERTA--(Marketwire - Aug. 10,
2010) - NAL Oil & Gas Trust ("NAL" or the "Trust") today announced
its financial and operational results for the second quarter of 2010.
All amounts are in Canadian dollars unless otherwise stated.
"NAL's performance is on track to deliver on its full year guidance"
stated Mr. Andrew Wiswell, President and CEO, on NAL's second quarter.
"Operationally, we are positioned for a strong 2010 production exit rate
that is expected to be in excess of 31,000 boe per day. In the second
half of the year, the Trust will continue to prove up opportunities
through the drill bit on acreage that has been added in our core areas
in the Cardium light oil resource play in Alberta and the Mississippian
light oil opportunity in southeast Saskatchewan. In addition, operating
costs and netbacks are showing strong year-over-year improvement.
Financially, the Trust is well capitalized with equity and available
bank lines to execute on its business plan, and we continue to actively
manage the hedging portfolio to reduce commodity price, interest rate
and foreign exchange risks".
2010 MID-YEAR HIGHLIGHTS
- For the first half of 2010, NAL's production averaged 29,863 boe
per day, on track with full year guidance and an increase of 27 percent
over the same period in 2009.
- Second quarter 2010 funds from operations of $63 million
represents a 21 percent increase over the same period a year ago. Key
drivers include a 28 percent increase in production plus higher
commodity prices partially offset by a higher Canadian dollar and
significantly lower realized hedging gains ($5 million versus $22
million in Q2 2009).
- Operating costs were lower by seven percent quarter-over-quarter from $11.80 to $10.98 per boe.
- Operating netbacks before hedging improved by 25 percent to $25.31
per boe compared to $20.30 per boe in the second quarter of 2009.
Year-to-date, operating netbacks before hedging improved by 43 percent
to $28.32 per boe compared to $19.77 a year earlier.
- Spent $40 million in capital, drilling 20 gross (11.5 net) wells in the second quarter.
- 87 percent of capital focused on drilling, completion and tie-in
activities with a 100 percent success rate in oil focused programs.
Year-to-date capital totals $118 million with 77 percent spent on
drilling, completion and tie-in activities and $19 million (16 percent)
spent on new land acquisitions:
-- Participated in eight (five net) Cardium wells in the Garrington
and Cochrane areas delivering results consistent with forecast type
curves;
-- Drilled eight (3.7 net) wells in Saskatchewan, primarily
targeting Mississippian oil at Alida, Steelman and Hoffer with first
month average production rates between 100 - 200 boe/d (Trust 50 percent
working interest); and
-- Drilled one Fireweed, B.C. well with a first month average production rate of approximately 800 boe per day.
- Followed up on the new pool discovery at Hoffer in SE Saskatchewan
by adding 244 gross sections of undeveloped land (50 percent working
interest) at an average cost of $525 per acre which compares favorably
with recent Crown sales at over $1,000 per acre.
- Successfully completed a $100 million equity financing with
proceeds directed primarily to toward 2010 capital program of $35
million ($175 million increased to $210 million), additional
Hoffer/Edson land ($50 million) and other tuck-in acquisitions ($10
million).
OUTLOOK
For the remainder of 2010, NAL expects to continue to be active in
drilling our oil resource opportunities in the Cardium and Mississippian
plays. The Trust is planning to provide an operational update in
September, 2010.
2010 GUIDANCE
The Trust's guidance remains unchanged from its update in May, 2010.
As previously outlined, NAL is forecasting a 2010 full year average in
the range of 29,500 - 30,500 boe per day with a projected production
volume exit rate in excess of 31,000 boe per day.
Current 2010 Guidance
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Production (boe/d) 29,500 - 30,500
Capital expenditures ($MM)(i) 210
Operating costs ($/boe) 10.75 - 11.25
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(i) Before Alberta Drilling Credits
CORPORATE CONVERSION
NAL plans to convert to a dividend paying corporation towards the
end of 2010. By itself, the change in structure of the underlying entity
from a trust to a corporation, does not affect our business plan or our
disciplined operational and financial focus.
NAL's Board will continue to assess the Trust's dividend and payout
policy based upon commodity prices, NAL's asset base, opportunities and
market conditions. Upon conversion, the Trust's total return will be
driven by a combination of yield and growth, with yield expected to
remain a meaningful component of the overall return. Specific payout and
dividend levels will be established closer to the time of conversion.
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 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. MDT (5:30 p.m. EDT) on August 10, 2010, NAL will hold a
conference call to discuss the second 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
1-800-769-8320 toll free across North America. The conference call will
also be accessible through the internet at
http://events.digitalmedia.telus.com/nal/081010/index.php
A recorded playback of the call will be available until August 17, 2010 by calling 1-800-408-3053, reservation 1823803.
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)
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Three months ended Six months ended
June 30 June 30
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2010 2009 2010 2009
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FINANCIAL
Revenue(1) $121,511 $ 82,650 $258,394 $163,312
Cash flow from operating activities 43,326 63,690 106,974 130,236
Cash flow per unit - basic 0.30 0.63 0.76 1.31
Cash flow per unit - diluted 0.30 0.60 0.74 1.27
Funds from operations 62,684 51,998 135,926 114,022
Funds from operations per unit -
basic 0.43 0.51 0.96 1.15
Funds from operations per unit -
diluted 0.42 0.50 0.92 1.11
Net income (loss) 8,046 (9,407) 37,395 (4,683)
Distributions declared 39,361 27,422 76,546 57,238
Distributions per unit 0.27 0.27 0.54 0.58
Basic payout ratio:
based on cash flow from operating
activities 91% 43% 72% 44%
based on funds from operations 63% 53% 56% 50%
Basic payout ratio including capital
expenditures(2) :
based on cash flow from operating
activities 183% 70% 182% 85%
based on funds from operations 127% 85% 143% 97%
Units outstanding (000's)
Period end 145,968 111,865 145,968 111,865
Weighted average 144,617 101,868 141,157 99,040
Capital expenditures(2) 40,034 16,952 118,353 53,888
Property acquisitions
(dispositions), net 43,080 1,221 30,378 2,535
Corporate acquisitions, net(3) - 37,350 309 37,350
Net debt, excluding convertible
debentures(4) 269,451 266,894 269,451 266,894
Convertible debentures (at face
value) 194,744 79,744 194,744 79,744
OPERATING
Daily production(5)
Crude oil (bbl/d) 11,643 9,725 11,715 9,857
Natural gas (Mcf/d) 90,928 67,654 92,121 68,306
Natural gas liquids (bbl/d) 2,812 2,048 2,795 2,199
Oil equivalent (boe/d) 29,609 23,049 29,863 23,440
OPERATING NETBACK ($/boe)
Revenue before hedging gains 45.10 39.40 47.80 38.49
Royalties (8.85) (7.44) (8.69) (7.01)
Operating costs (10.98) (11.80) (10.89) (11.88)
Other income(6) 0.04 0.14 0.10 0.17
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Operating netback before hedging 25.31 20.30 28.32 19.77
Hedging gains 2.18 10.65 1.40 11.82
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Operating netback 27.49 30.95 29.72 31.59
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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 $3.9 million for the quarter ended June 30, 2010
and $6.3 million for the six months ended June 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 six month periods ended June 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 the understanding of the results
of operations. However, these terms do not have any standardized
meaning as prescribed by Canadian Generally Accepted Accounting
Principles ("GAAP"). Investors should be cautioned that these measures
should not be construed as an alternative to net income determined in
accordance with GAAP as an indication of NAL's performance. NAL's method
of calculating these measures may differ from other income funds and
companies and, accordingly, they may not be comparable to measures used
by other income funds and companies.
Funds from operations is calculated as cash flow from operating
activities before changes in non-cash working capital. Funds from
operations does not represent operating cash flows or operating profits
for the period and should not be viewed as an alternative to cash flow
from operating activities calculated in accordance with GAAP. Funds from
operations is considered by Management to be a more meaningful key
performance indicator of NAL's ability to generate cash to finance
operations and to pay monthly distributions. Funds from operations per
unit and cash flow from operations per unit are calculated using the
weighted average units outstanding for the period.
Payout ratio is calculated as distributions declared for a period as
a percentage of either cash flow from operating activities or funds
from operations; both measures are stated.
Net debt to trailing 12 months cash flow is calculated as net debt
as a proportion of funds from operations for the previous 12 months. Net
debt is defined as bank debt, plus convertible debentures at face
value, plus working capital and other liabilities, excluding derivative
contracts, notes payable/receivable and future income tax balances.
The following table reconciles cash flows from operating activities to funds from operations:
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Three months ended Six months ended
June 30 June 30
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$ (000s) 2010 2009 2010 2009
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Cash flow from operating activities 43,326 63,690 106,974 130,236
Add back change in non-cash working
capital 19,358 (11,692) 28,952 (16,214)
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Funds from operations 62,684 51,998 135,926 114,022
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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 and its subsidiaries; 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, we
have made assumptions regarding, among other things: future oil and
natural gas prices; future capital expenditure levels; future oil and
natural gas production levels; future exchange rates; the amount of
future cash distributions that we intend to pay; the cost of expanding
our property holdings; our ability to obtain equipment in a timely
manner to carry out exploration development activities; our ability to
market our oil and natural gas successfully to current and new
customers; and the impact of increasing competition; our ability to
obtain financing on acceptable terms; and our ability to add production
and reserves through our development and exploitation activities.
Although NAL believes that the expectations reflected in the
forward-looking information contained in the MD&A and the press
release through which it was disseminated, and the assumptions on which
such forward-looking information are made, are reasonable, readers are
cautioned not to place undue reliance on such forward looking statements
as there can be no assurance that the plans, intentions or expectations
upon which the forward-looking information are based will occur. Such
information involves known and unknown risks, uncertainties and other
factors that may cause actual results or events to differ materially
from those anticipated and which may cause NAL's actual performance and
financial results in future periods to differ materially from any
estimates or projections of future performance. These risks and
uncertainties include, without limitation: changes in commodity prices;
unanticipated operating results or production declines; the impact of
weather conditions on seasonal demand and NAL's ability to execute its
capital program; risks inherent in oil and gas operations; the
imprecision of reserve estimates; limited, unfavorable or no access to
capital or credit markets; the impact of competitors; the lack of
availability of qualified operating or management personnel; the
inability to obtain industry partner and other third party consents and
approvals, when required; failure to realize the anticipated benefits of
acquisitions; general economic conditions in Canada, the United States
and globally; fluctuations in foreign exchange or interest rates;
changes in government regulation of the oil and gas industry, including
environmental regulation; changes in royalty rates; changes in tax laws,
stock market volatility and 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 $34.7 million on drilling, completion and tie-in
operations during the second quarter of 2010, compared to $7.6 million
during the second quarter of 2009, and drilled 20 (11.5 net) wells in
the second quarter, compared to five (2.7 net) wells during the same
period in 2009. Drilling was accelerated on six Cardium wells in
Garrington utilizing two pads to work from through break up. Access
conditions were also favorable in Irricana, Fireweed and Edson allowing
additional operations to proceed. NAL had up to eight rigs running
through the quarter with up to four rigs working in Saskatchewan, one in
British Columbia and three in Alberta. A significant portion of the
production from the second quarter drilling will be on stream during the
third quarter.
The Trust has drilled 68 (32.6 net) wells year-to-date and is
planning to drill an additional 61 (33 net) horizontal wells during the
remainder of the year.
Second Quarter Drilling Activity
Crude Natural Service Dry &
Oil Gas Wells Abandoned Total
-------------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 17 9.7 2 1.7 0 0 0 0 19 11.4
Non-operated
wells 0 0 1 0.1 0 0 0 0 1 0.1
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Total wells
drilled 17 9.7 3 1.8 0 0 0 0 20 11.5
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Southeast Saskatchewan (Alida, Nottingham, Steelman, Hoffer)
In Saskatchewan, there were eight (3.7 net) horizontal oil wells
drilled during the second quarter. Activity was focused on the
Mississippian in Alida, Steelman and Hoffer. The Trust expects to have
11 wells on stream at Hoffer by the end of July producing approximately
1,300 boe/d (650 boe/d net). Production from this program is expected to
positively impact third quarter volumes as wet conditions accounted for
23 lost drilling days and shut in volumes at single well battery
operations during the quarter. The Trust intends to drill 40 (20 net)
additional horizontal Mississippian oil wells in the third and fourth
quarters across its expanded land base, largely focused in the greater
Hoffer area. Facility planning is under way with expectations for full
scale battery construction during the first quarter of 2011.
Alberta (Cochrane, Garrington, Irricana, Edson)
In Alberta, NAL participated in drilling 11 (6.9 net) locations with
nine (6 net) oil wells drilled in the Cardium at Garrington/Cochrane
and the Wabamun at Irricana. The majority of production from this
program is expected to be brought on stream in the third quarter. Test
results are in line with type curves supporting first month production
rates of 180 - 200 boe/d. A Wilrich gas well (70 percent working
interest) was also drilled and tested in the Edson area with final test
rates of 10 mmcfd at a flowing well head pressure of 1200 psi. For the
remainder of 2010, the Trust intends to drill 21 (12.8 net) wells in
Alberta with 17 (11 net) Cardium, Leduc and Wabamun oil wells and four
(2 net) liquid rich gas wells in the Edson and Kakwa areas.
British Columbia (Fireweed, Sukunka)
NAL drilled a 100 percent working interest liquid rich Doig gas well
in the second quarter at Fireweed with a first month average production
rate of approximately 800 boe/d. Sukunka gas production was down for 21
days in June and July for a planned turn around at the Spectra Pine
River gas plant. Production resumed at full capability (2,600 boe/d net)
in the second week of July as expected.
CAPITAL EXPENDITURES
Capital expenditures, before property acquisitions, for the quarter
ended June 30, 2010 totaled $40.0 million compared with $17.0 million
for the quarter ended June 30, 2009. The year-over-year increase is
directly related to the corresponding increase in wells drilled as well
as a continued shift towards horizontal drilling and multi-stage frac
completions which significantly increases per well costs.
On a year-to-date basis, capital expenditures, before property
acquisitions, totaled $118.4 million compared to $53.9 million in the
comparable period of 2009 due to increased drilling and significant land
acquisitions. NAL expects to spend an additional $92 million of
exploration and development capital in the second half of 2010, focused
primarily on Cardium and Mississippian oil opportunities. The $30
million in year-to-date property acquisitions and dispositions relates
primarily to oil focused transactions at Hoffer and Alida/Nottingham,
partially offset by the sale of a minor Bakken position earlier in the
year.
Capital Expenditures ($000s)
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Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
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Drilling, completion and production
equipment 34,648 7,622 90,641 38,086
Plant and facilities 1,355 5,531 1,782 8,390
Seismic 151 158 1,812 247
Land 693 486 18,842 2,461
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Total exploration and development 36,847 13,797 113,077 49,184
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Office equipment 844 142 1,134 380
Capitalized G&A 2,772 1,835 4,296 2,994
Capitalized unit-based compensation (429) 1,178 (154) 1,330
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Total other capital 3,187 3,155 5,276 4,704
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Total capitalized expenditures
before acquisitions 40,034 16,952 118,353 53,888
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Property acquisitions, net 43,080 1,221 30,378 2,535
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Total capitalized expenditures 83,114 18,173 148,731 56,423
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PRODUCTION
Second quarter 2010 production volume was 29,609 boe/d, compared to
production of 23,049 boe/d in the same period of 2009. Higher
year-over-year production in the second quarter is related to the impact
of acquisitions completed in 2009 and an aggressive drilling program
during the first half of 2010. As in previous years, second quarter
production tends to be the lowest of the year due to turnaround
activities and limited access for well operations due to spring break
up. The Trust actively manages and anticipates these activities and the
impacts on production during the quarter were in line with expectations.
Turnaround activity and plant outages in Sukunka (-300 boe/d for the
second and third quarters), Fireweed (-300 boe/d) and minor volume
outages in central Alberta and Saskatchewan (-200 boe/d) contributed to
an average reduction of 800 boe/d of production for the quarter which
were included in the Trust's forecasts. On a year-to-date basis,
production of 29,863 boe/d, compared to 23,440 boe/d for the comparable
period of 2009. The Trust remains well positioned to deliver volumes at
the midpoint of guidance (29,500 - 30,500 boe/d) for full year 2010 and
an exit rate in excess of 31,000 boe/d.
Average Daily Production Volumes
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Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
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Oil (bbl/d) 11,643 9,725 11,715 9,857
Natural gas (Mcf/d) 90,928 67,654 92,121 68,306
NGLs (bbl/d) 2,812 2,048 2,795 2,199
Oil equivalent (boe/d) 29,609 23,049 29,863 23,440
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Oil equivalent volumes of 29,609 boe/d for the second quarter of
2010 and 29,863 boe/d year-to-date include 275 boe/d (2009 - 423 boe/d)
and 288 boe/d (2009 - 432 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 29,334 boe/d for the second
quarter of 2010 (2009 - 22,626 boe/d) and 29,575 boe/d (2009 - 23,008
boe/d) year-to-date.
Oil and natural gas liquids totaled 48 percent of production with
natural gas at 52 percent during the first half of 2010. The Trust's oil
and liquids weighting is three percent lower than for the comparative
period in 2009 due to volumes delivered from the gas weighted
acquisitions completed late in 2009.
Production Weighting
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Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
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Oil 39% 42% 39% 42%
Natural gas 51% 49% 52% 49%
NGLs 10% 9% 9% 9%
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REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs and prior to hedging, totaled $121.5 million
for the three months ended June 30, 2010, 47 percent higher than the
second quarter of 2009. The increase is due to a 28 percent increase in
production and a 14 percent increase in the average realized price per
boe, driven by a 16 percent increase in the realized crude oil price and
a 11 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 second quarter of 2010.
For the six month period ended June 30, 2010, revenue after
transportation costs totaled $258.4 million, an increase of 58 percent
from the comparable period in 2009. The increase is attributable to a 24
percent increase in the average realized price per boe and a 27 percent
increase in production. 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 first six months of 2010.
Revenue
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Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue(1) ($000s)
Oil 75,774 54,798 156,859 95,481
Gas 32,000 21,540 74,064 54,116
NGL's 13,761 6,152 27,513 13,130
Sulphur (24) 160 (42) 585
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Total revenue 121,511 82,650 258,394 163,312
$/boe 45.10 39.40 47.80 38.49
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(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties and hedging.
OIL MARKETING
NAL markets its crude oil based on refiners' posted prices at
Edmonton, Alberta and Cromer, Manitoba adjusted for transportation and
the quality of crude oil at each field battery. The refiners' posted
prices are influenced by the WTI benchmark price, transportation costs,
exchange rates and the supply/demand situation of particular crude oil
quality streams during the year.
NAL's second quarter average realized Canadian crude oil price per
barrel, net of transportation costs and excluding hedging, was $71.52,
compared to $61.92 for the comparable quarter of 2009. The increase in
realized price quarter-over-quarter of 16 percent, or $9.60/bbl, was
primarily driven by a 31 percent increase in the WTI price (US$/bbl)
over the comparable period, partially offset by a 12 percent increase in
the value of the Canadian dollar.
For the second 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 realized price as a
percentage of the WTI price stated in Canadian dollars.
For the six months ended June 30, 2010, NAL's average oil price was
$73.98 per barrel compared to $53.52 for the comparable period in 2009.
The increase in realized price was driven by a 53 percent increase in
the WTI price (US$/bbl) and an increase in crude oil differentials to 91
percent from 86 percent in 2009, partially offset by a 14 percent
increase in the value of the Canadian dollar.
Natural gas liquids averaged $53.78/bbl in the second quarter of
2010, a 63 percent increase from the $33.01/bbl realized in 2009. For
the six months ended June 30, 2010, natural gas liquids averaged
$54.39/bbl, an increase of 65 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 June 30, 2010, the Trust's natural gas
sales averaged $3.87/Mcf compared to $3.50/Mcf in the comparable period
of 2009, an increase of 11 percent. The quarter-over-quarter increase in
gas prices was attributable to a 13 percent increase in the benchmark
AECO daily spot prices.
Prices for Lake Erie natural gas decreased to $4.91/Mcf in the
second quarter of 2010, compared to $5.16/Mcf in 2009, a decrease of
five percent. Lake Erie production of 3.3 mmcf/d accounted for four
percent of the Trust's natural gas production in the second 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 six months ended June 30, 2010, NAL averaged $4.44/Mcf, a
one percent increase from the $4.38/Mcf realized in the comparable
period of 2009. The increase in natural gas prices was attributable to a
six percent increase in the benchmark AECO daily spot prices.
Average Pricing
(net of transportation charges)
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Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
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Liquids
WTI (US$/bbl) 78.10 59.62 78.40 51.35
NAL average oil (Cdn$/bbl) 71.52 61.92 73.98 53.52
NAL natural gas liquids (Cdn$/bbl) 53.78 33.01 54.39 32.99
Natural Gas (Cdn$/mcf)
AECO - daily spot 3.89 3.44 4.43 4.18
AECO - monthly 3.86 3.66 4.61 4.65
NAL Western Canada natural gas 3.83 3.42 4.41 4.31
NAL Lake Erie natural gas 4.91 5.16 5.30 5.75
NAL average natural gas 3.87 3.50 4.44 4.38
NAL Oil Equivalent before hedging
(Cdn$/boe - 6:1) 45.10 39.40 47.80 38.49
Average Foreign Exchange Rate
(Cdn$/US$) 1.028 1.167 1.034 1.206
----------------------------------------------------------------------------
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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. The execution of NAL's commodity hedging program is
layered in using a combination of swaps and collars. As at June 30,
2010, NAL had several financial WTI oil contracts and AECO natural gas
contracts in place.
NAL hedges floating rate debt for periods of up to five years. As at
June 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 June 30, 2010, NAL had several
exchange rate contracts outstanding with a total notional value of US$84
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 June 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 June 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 June 30, 2010 was a net asset
of $17.2 million, comprised of an $0.8 million asset on interest rate
swaps, an $11.1 million asset on gas contracts, a $0.7 million asset on
foreign exchange contracts and a $4.6 million asset on oil contracts.
Second quarter income for 2010 includes a $1.2 million unrealized
gain on derivatives resulting from the change in the fair value of the
derivative contracts during the quarter from an unrealized gain of $16.0
million at March 31, 2010 to an unrealized gain of $17.2 million at
June 30, 2010. The $1.2 million unrealized gain was comprised of a $15.9
million unrealized gain on crude oil contracts, offset by a $1.9
million unrealized loss on interest rate swaps, a $5.0 million
unrealized loss on foreign exchange swaps and a $7.8 million unrealized
loss on natural gas contracts.
For the six months ended June 30, 2010, income includes an
unrealized gain of $19.7 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 $17.2
million at June 30, 2010. The unrealized gain was comprised of a $17.5
million unrealized gain on crude oil contracts and a $7.2 million
unrealized gain on natural gas contracts, partially offset by a $1.7
million unrealized loss on interest rate swaps and a $3.3 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 ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts 15,939 (34,769) 17,485 (55,967)
Natural gas contracts (7,848) (10) 7,173 2,691
Interest rate swaps (1,887) 3,828 (1,696) 3,150
Exchange rate swaps (5,033) 1,467 (3,282) 2,138
----------------------------------------------------------------------------
Unrealized gain (loss) 1,171 (29,484) 19,680 (47,988)
Realized gain (loss):
Crude oil contracts (2,712) 15,901 (4,794) 36,653
Natural gas contracts 6,900 4,507 9,397 11,463
Interest rate swaps (385) (178) (642) (207)
Exchange rate swaps 1,682 1,929 2,972 2,012
----------------------------------------------------------------------------
Realized gain 5,485 22,159 6,933 49,921
----------------------------------------------------------------------------
Gain (loss) on derivative contracts 6,656 (7,325) 26,613 1,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following is a summary of the realized gains and losses on risk
management contracts:
Realized Gain (Loss) on Derivative Contracts
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Commodity contracts:
Average crude volumes hedged (bbl/d) 6,500 4,737 6,433 4,173
Crude oil realized gain (loss) ($000s) (2,712) 15,901 (4,794) 36,653
Gain (loss) per bbl hedged ($) (4.58) 36.88 (4.12) 48.52
Average natural gas volumes hedged
(GJ/d) 39,000 10,484 38,486 19,691
Natural gas realized gain ($000s) 6,900 4,507 9,397 11,463
Gain per GJ hedged ($) 1.94 4.72 1.35 3.22
Average BOE hedged (boe/d) 12,661 6,394 12,513 7,284
Total realized commodity contracts
gain ($000s) 4,188 20,408 4,603 48,116
Gain per boe hedged ($) 3.63 35.07 2.03 36.50
Gain per boe ($) 1.56 9.73 0.85 11.35
Interest rate swaps realized loss
($000s) (385) (178) (642) (207)
Loss per boe ($) (0.14) (0.08) (0.12) (0.05)
Exchange rate swaps realized gain
($000s) 1,682 1,929 2,972 2,012
Gain per boe ($) 0.62 0.92 0.55 0.47
Total realized gain ($000s) 5,485 22,159 6,933 49,921
Gain per boe ($) 2.04 10.57 1.28 11.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average hedged boe for the second quarter of 2010 were 12,661 compared to
12,363 for the first quarter of 2010.
NAL has the following interest rate risk management contracts outstanding:
----------------------------------------------------------------------------
Amount Trust Counterparty
(millions) Fixed Floating
INTEREST RATE CONTRACT Remaining Term (1) Rate Rate
----------------------------------------------------------------------------
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Dec 2011 $39.0 1.5864% (3 months)
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Jan 2013 $22.0 1.3850% (3 months)
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Jan 2014 $22.0 1.5100% (3 months)
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Mar 2013 $14.0 1.8500% (3 months)
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Mar 2013 $14.0 1.8750% (3 months)
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Mar 2014 $14.0 1.9300% (3 months)
Swaps-floating to CAD-BA-CDOR
fixed July 2010 - Mar 2014 $14.0 1.9850% (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount
NAL has the following exchange rate risk management contracts outstanding:
----------------------------------------------------------------------------
Trust
Amount(1) Fixed Counterparty
EXCHANGE RATE CONTRACT Remaining Term (US$ MM) Rate Floating
----------------------------------------------------------------------------
Rate
Swaps-floating to BofC Average
fixed July 2010 - Dec 2010 54.0 1.0904 Noon Rate
Swaps-floating to BofC Average
fixed Jan 2011 - Dec 2011 30.0 1.0522 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional US$ denominated commodity sales
In addition, NAL has the following exchange rate contract commitments:
1. From July to December 2010, NAL has a commitment to sell US$6
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 $25,000 a month
when the average noon rate falls between 0.95 and 1.12.
NAL has the following commodity risk management contracts outstanding:
CRUDE OIL Q3-10 Q4-10 Q1-11 Q2-11
----------------------------------------------------------------------------
US$ Collar Contracts
---------------------
$US WTI Collar Volume (bbl/d) 2,100 1,900 800 800
Bought Puts - Average Strike Price
($US/bbl) 67.50 68.03 81.25 81.25
Sold Calls - Average Strike Price
($US/bbl) 79.70 80.62 94.47 94.47
US$ Swap Contracts
---------------------
$US WTI Swap Volume (bbl/d) 3,665 3,900 700 700
Average WTI Swap Price ($US/bbl) 83.60 83.45 83.08 83.08
Total Oil Volume (bbl/d) 5,765 5,800 1,500 1,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS Q3-10 Q4-10 Q1-11 Q2-11
----------------------------------------------------------------------------
Swap Contracts
---------------
AECO Swap Volume (GJ/d) 42,000 31,337 5,000 4,000
AECO Average Price ($Cdn/GJ) 5.55 5.52 5.61 5.78
Total Natural gas Volume (GJ/d) 42,000 31,337 5,000 4,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the remainder of 2010, the Trust has outstanding contracts
representing approximately 47 percent of its net liquids and natural gas
production after royalties.
ROYALTY EXPENSES
Crown, freehold and overriding royalties totaled $23.9 million for
the three months ended June 30, 2010. Expressed as a percentage of gross
sales net of transportation costs, before gain/loss on derivative
contracts, the net royalty rate was 19.6 percent for the quarter ended
June 30, 2010, an increase from the 18.9 percent experienced in the same
period of the previous year.
Royalties increased to $8.85 per boe for the second quarter of 2010,
an increase of 19 percent compared to the second quarter of 2009. The
increase is attributable to higher commodity prices on a
quarter-over-quarter basis.
On a year-to-date basis, royalties were $47.0 million, up from $29.7
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, the same percentage
experienced during 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 six months ended June 30, 2010, 45 percent of crude oil
production (946,638 bbl) and 66 percent of natural gas production
(10,968,256 mcf) is from Alberta.
Royalty Expenses
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Royalties ($000s) 23,851 15,608 46,997 29,742
As % of revenue 19.6 18.9 18.2 18.2
$/boe 8.85 7.44 8.69 7.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING COSTS
Operating costs averaged $10.98 per boe for the quarter ended June
30, 2010, down seven percent from $11.80 per boe for the quarter ended
June 30, 2009. Operating costs continue to trend down driven by lower
natural gas prices impacting the cost of power and continued gains from
an aggressive optimization program in field operations.
On a year-to-date basis, operating costs are $10.89 per boe compared
to $11.88 per boe in 2009. Operating costs for the full year are
expected to be at the mid range of guidance ($10.75 - $11.25 per boe) as
industry activity increases from 2009 levels and the Trust continues
its program to reduce costs in all areas of its business.
Operating Costs
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Operating costs ($000s) 29,582 24,759 58,886 50,399
As a % of revenue 24.3 30.0 22.8 30.9
$/boe 10.98 11.80 10.89 11.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OTHER INCOME
Other income was nil per boe for the second quarter of 2010 compared
to $0.08 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 MFC (see
"Related Party Transactions"). On a year-to-date basis, interest expense
totaled $0.2 million compared to net interest income of $0.4 million
for the comparable period of 2009, the decrease being attributable to
the repayment of a note receivable from Manulife Financial Corporation
("MFC") in the first quarter of 2009.
Other Income
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest on notes with MFC ($000s) (108) (129) (220) 414
Other ($000s) 112 308 555 729
----------------------------------------------------------------------------
Total other income ($000s) 4 179 335 1,143
As a % of revenue - 0.2 0.1 0.7
Interest on notes with MFC ($/boe) (0.04) (0.06) (0.04) 0.10
Other ($/boe) 0.04 0.14 0.10 0.17
----------------------------------------------------------------------------
Total other income ($/boe) - 0.08 0.06 0.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended June 30, 2010, NAL's operating netback before
hedging gains was $25.31 per boe, a increase of 25 percent from $20.30
per boe for the quarter ended June 30, 2009. The increase was due to
higher revenues, a result of higher commodity prices, and decreased
operating costs, partially offset by increased royalty expense. Hedging
gains, related to commodity and exchange rate derivative contracts, were
$2.18 per boe in the second quarter of 2010, as compared to $10.65 per
boe in 2009, the decrease in 2010 attributable mainly to higher realized
crude oil prices.
On a year-to-date basis, similar trends resulted in an operating
netback, before hedging, of $28.32 per boe compared to $19.77 per boe in
2009. Hedging gains, related to commodity and exchange rate derivative
contracts, were $1.40 for the six months ended June 30, 2010, as
compared to $11.82 per boe in 2009, the decrease in 2010 attributable to
lower oil hedging gains due to increasing crude oil prices.
Operating Netback
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
Oil (bbl/d) 11,643 9,725 11,715 9,857
Gas (Mcf/d) 90,928 67,654 92,121 68,306
NGLs (bbl/d) 2,812 2,048 2,795 2,199
----------------------------------------------------------------------------
Total (boe/d) 29,609 23,049 29,863 23,440
REVENUE
Oil ($/bbl) 71.52 61.92 73.98 53.52
Gas ($/Mcf) 3.87 3.50 4.44 4.38
NGLs ($/bbl) 53.78 33.01 54.39 32.99
----------------------------------------------------------------------------
Total ($/boe) 45.10 39.40 47.80 38.49
ROYALTIES
Oil ($/bbl) 15.00 14.03 15.14 11.34
Gas ($/Mcf) 0.52 0.24 0.49 0.50
NGLs ($/bbl) 14.38 9.23 13.43 8.40
----------------------------------------------------------------------------
Total ($/boe) 8.85 7.44 8.69 7.01
OPERATING EXPENSES
Oil ($/bbl) 10.98 12.08 10.89 12.44
Gas ($/Mcf) 1.83 1.97 1.82 1.95
NGLs ($/bbl) 10.98 10.53 10.89 10.17
----------------------------------------------------------------------------
Total ($/boe) 10.98 11.80 10.89 11.88
OTHER INCOME(1)
Oil ($/bbl) 0.07 0.22 0.17 0.24
Gas ($/Mcf) - 0.01 0.01 0.02
NGLs ($/bbl) 0.06 0.12 0.12 0.15
----------------------------------------------------------------------------
Total ($/boe) 0.04 0.14 0.10 0.17
OPERATING NETBACK, BEFORE HEDGING
Oil ($/bbl) 45.61 36.03 48.12 29.98
Gas ($/Mcf) 1.52 1.30 2.14 1.95
NGLs ($/bbl) 28.48 13.37 30.19 14.57
----------------------------------------------------------------------------
Total ($/boe) 25.31 20.30 28.32 19.77
HEDGING GAINS/(LOSSES)(2)
Oil ($/bbl) (0.97) 20.15 (0.86) 21.67
Gas ($/Mcf) 0.83 0.73 0.56 0.93
NGLs ($/bbl) - - - -
----------------------------------------------------------------------------
Total ($/boe) 2.18 10.65 1.40 11.82
OPERATING NETBACK, AFTER HEDGING
Oil ($/bbl) 44.64 56.18 47.26 51.65
Gas ($/Mcf) 2.35 2.03 2.70 2.88
NGLs ($/bbl) 28.48 13.37 30.19 14.57
----------------------------------------------------------------------------
Total ($/boe) 27.49 30.95 29.72 31.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes interest on notes with MFC.
(2) 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 June 30, 2010, G&A expenses were $4.0
million consistent with the comparable quarter of 2009. In addition,
$2.8 million of G&A costs relating to exploitation and development
activities were capitalized in the second quarter of 2010, compared with
$1.8 million in the second quarter of 2009. G&A expense per boe was
$1.50 in the quarter, as compared to $1.92 for the same period in 2009.
For the six months ended June 30, 2010, G&A expenses increased
26 percent to $8.4 million from $6.7 million in the comparable period in
2009. In addition, on a year-to-date basis, $4.3 million of G&A
costs relating to exploitation and development activities were
capitalized, compared with $3.0 million in the comparable period of
2009. G&A expense per boe was $1.55 in 2010, compared to $1.57 in
2009.
The year-to-date increase in total year-to-date G&A of $3.0
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 Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
G&A expenses ($000s)
Expensed 4,039 4,031 8,398 6,658
Capitalized 2,772 1,835 4,296 2,994
----------------------------------------------------------------------------
Total G&A ($000s) 6,811 5,866 12,694 9,652
Expensed G&A costs:
$/boe 1.50 1.92 1.55 1.57
As % of revenue 3.3 4.9 3.3 4.1
Per trust unit ($) 0.03 0.04 0.06 0.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 second quarter of 2010, the Trust recorded a $1.2 million
reduction for unit-based incentive compensation that reflects a
decrease in the unit price and PTU performance multipliers, partially
offset by the impact of vesting. The trust unit price of the Trust
decreased by 18 percent, from $12.95 at March 31, 2010 to $10.60 at June
30, 2010. A decrease in unit price results in previously accrued
amounts being reversed.
Unit-based incentive compensation decreased by 129 percent compared
to the second quarter of 2009, from a $3.9 million charge in 2009 to a
reduction of $1.2 million in 2010. The period-over-period decrease is a
reflection of a 18 percent decrease in the trust unit price for the
quarter compared to a 38 percent increase in the trust unit price for
the comparable quarter last year, and lower relative performance factors
used to determine the compensation.
On a year-to-date basis, the Trust has recorded a recovery of $0.4
million compared to a $4.4 million charge in the comparable period of
2009.
At June 30, 2010, the trust unit price used to determine unit-based
incentive compensation was $10.60. The closing trust unit price of the
Trust on the Toronto Stock Exchange on August 9, 2010 was $10.94.
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 June 30, 2010, the Trust has recorded a total accumulated
liability for unit-based incentive compensation in the amount of $9.0
million, of which $4.8 million is recorded as a current liability, as it
is payable in December 2010, and $4.2 million is long-term, as it is
payable in December 2011 and December 2012.
Unit-Based Compensation
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unit-based compensation ($000s):
Expensed (729) 2,767 (290) 3,060
Capitalized (429) 1,178 (154) 1,330
----------------------------------------------------------------------------
Total unit-based compensation (1,158) 3,945 (444) 4,390
Expensed unit-based compensation:
As % of revenue (0.6) 3.3 (0.1) 1.9
$/boe (0.27) 1.32 (0.05) 0.72
Per trust unit ($) (0.01) 0.03 0.00 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 calculated on a unit of
production basis. The Agreement does not provide for any base or
performance fees to be payable to the Manager.
The Trust paid $3.6 million (2009 - $3.4 million) for the
reimbursement of G&A expenses during the second quarter and $7.2
million (2009 - $5.3 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 June 30, 2010 the Trust owed the Manager $1.4 million for the
reimbursement of G&A and had a receivable from NAL Resources of
$13.3 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"). This Partnership holds the assets
acquired from the acquisitions of Tiberius Exploration Inc. ("Tiberius")
and Spear Exploration Inc. ("Spear") in February 2008. In addition,
both the Trust and MFC entered into net profit interest royalty
agreements ("NPI") with the Partnership. These agreements entitle each
royalty holder to a 49.5 percent interest in the cash flow from the
Partnership's reserves.
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 June 30, 2010, there is a note payable of $7.6 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 second quarter of 2010 (2009 - $0.1 million net
interest expense), and net interest expense of $0.2 million (2009 - $0.4
million net interest income) was 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 second quarter of 2010 was $2.7 million, a
decrease of $0.3 million from $3.0 million for the comparable period in
2009 due to lower average debt levels. Average outstanding bank debt
for the second quarter of 2010 was $205.7 million, $87.7 million lower
than the $293.4 million outstanding for the second quarter of 2009,
driven primarily by the $94.7 million in equity raised in the second
quarter, net of issue costs. NAL's effective interest rate averaged 5.22
percent during the second quarter of 2010, compared to 4.05 percent
during the comparable period in 2009. The increase in the rate from the
second 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.
For the six months ended June 30, 2010, interest on bank debt
increased $0.9 million to $5.8 million, compared to $4.9 million in
2009. Average outstanding debt for the six months ended June 30, 2010
decreased to $219.0 million, compared to $294.9 million for the
corresponding period of 2009, and the effective interest rate averaged
5.30 percent in 2010, compared to 3.37 percent in 2009.
Interest on convertible debentures represents interest charges of
$3.1 million for the three months ended June 30, 2010 ($6.2 million for
the six months ended June 30, 2010) compared to $1.3 million in the
second quarter of 2009 ($2.7 million for the six months ended June 30,
2009).
The interest includes the interest on the 2007 debentures at 6.75
percent and the interest on the debentures issued in December 2009 at
6.25 percent. Accretion of the debt discount was $1.0 million for the
three months ended June 30, 2010 ($2.0 million for the six months ended
June 30, 2010) as compared to $0.4 million for the three months ended
June 30, 2009 ($0.8 million for the six months ended June 30, 2009). The
increase in interest and accretion is due to the December 2009 issuance
of convertible debentures.
Interest and Debt
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Interest on bank debt ($000s)(1) 2,670 2,962 5,756 4,925
Interest and accretion on
convertible debentures ($000s) 4,105 1,725 8,238 3,449
----------------------------------------------------------------------------
Total interest before interest rate
hedges($000) 6,775 4,687 13,994 8,374
Loss on interest rate swaps ($000s) 385 178 642 207
----------------------------------------------------------------------------
Total interest after interest rate
hedges ($000s) 7,160 4,865 14,636 8,581
----------------------------------------------------------------------------
Bank debt outstanding at period end
($000s) 216,321 244,323 216,321 244,323
Convertible debentures at period
end ($000s)(2) 179,634 74,762 179,634 74,762
$/boe:
Interest on bank debt 0.99 1.41 1.06 1.16
Interest on convertible debentures 1.15 0.64 1.15 0.63
Accretion on convertible
debentures 0.37 0.18 0.37 0.18
Loss on interest rate swaps 0.14 0.08 0.12 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total interest after interest rate
hedges 2.65 2.31 2.70 2.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 June 30, 2010, NAL's cash flow netback was
$23.90 per boe, a six percent decrease from $25.52 per boe for the
comparable period 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, including
unit-based incentive compensation.
For the six months ended June 30, 2010, NAL's cash flow netback was
$25.83 per boe, a six percent decrease from $27.56 per boe in 2009. The
decrease was due to a lower operating netback after hedging and higher
interest charge on bank debt and convertible debentures, offset by a
lower G&A expenses, including unit-based incentive compensation.
Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Operating netback, after hedging 27.49 30.95 29.72 31.59
G&A expenses, including unit-based
incentive compensation (1.23) (3.24) (1.50) (2.29)
Corporate conversion cost (0.04) - (0.02) -
Interest on bank debt and
convertible debentures(1) (2.14) (2.05) (2.21) (1.79)
Interest on notes with MFC(2) (0.04) (0.06) (0.04) 0.10
Realized loss on interest rate
derivative contracts (0.14) (0.08) (0.12) (0.05)
----------------------------------------------------------------------------
Cash flow netback 23.90 25.52 25.83 27.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 June 30, 2010, depletion on property, plant
and equipment and accretion on the asset retirement obligations was
$24.72 per boe, 16 percent higher than the $21.29 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 Energy Ltd. ("Breaker") which was acquired in December 2009.
Similar trends are noted for the six months ended June 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 Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 63,903 42,779 125,939 85,987
Accretion of asset retirement
obligation ($000s) 2,695 1,886 5,326 3,714
----------------------------------------------------------------------------
Total DDA ($000s) 66,598 44,665 131,265 89,701
DDA rate per boe ($) 24.72 21.29 24.28 21.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TAXES
In the second quarter of 2010, NAL had a future income tax recovery
of $10.4 million compared to a $12.2 million recovery in the
corresponding period of the prior year. For the six month period ended
June 30, 2010, NAL had a future income tax recovery of $12.6 million
compared to $18.4 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 June 30, 2010, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximated $1.4 billion, of which approximately 34
percent represented COGPE, 21 percent represented UCC, with the
remaining balance represented by CEE, CDE, trust unit issue costs and
non-capital loss carry forwards.
Estimated Tax Pools ($ millions)
----------------------------------------------------------------------------
June 30, December 31,
2010 2009
----------------------------------------------------------------------------
Canadian exploration expense 61 50
Canadian development expense 419 379
Canadian oil and gas property expense 466 436
Undepreciated capital costs 282 274
Other (including loss carry forwards) 140 128
----------------------------------------------------------------------------
Total estimated tax pools 1,368 1,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Based on current strip prices at June 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 Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Net profits interest expense 216 544 834 787
Share of net income attributable to
MFC 151 92 325 708
----------------------------------------------------------------------------
367 636 1,159 1,495
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
Net income for the second quarter of 2010 was $8.0 million compared
to a net loss of $9.4 million for the comparable period in 2009. The
improvement of $17.4 million was mainly due to increased revenues net of
royalties ($31.2 million), an increased gain on derivative contracts
($14.0 million) and decreased unit-based compensation expense ($3.5
million), offset by increased DD&A expense ($21.1 million),
increased operating costs ($4.8 million) and a lower tax reduction ($1.8
million).
Net income for the six months ended June 30, 2010 of $37.4 million
was $42.1 million greater than the comparable period of 2009. The
increase in net income in 2010 is attributable to increased revenues net
of royalties ($79.0 million), an increased gain on derivative contracts
($24.7 million) and decreased unit-based compensation expense ($3.4
million), offset by increased operating costs ($8.5 million), increased
DD&A expense ($40.0 million), increased interest charges ($5.6
million) and a lower tax reduction ($5.8 million).
Net Income (loss) ($000s)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2008
----------------------------------------------------------------------------
Net income (loss) 8,046 (9,407) 37,395 (4,683)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of trust units, bank debt and convertible debentures.
As at June 30, 2010, NAL had 145,968,199 trust units outstanding,
compared with 137,471,209 trust units as at December 31, 2009. The
increase from December 31, 2009 is attributable to 946,990 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
14.97 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 June 30, 2010, the Trust had net debt of $464.2 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 $269.5 million, compared with
$282.7 million at December 31, 2009. The decrease in net debt, excluding
convertible debentures, of $13.3 million during 2010 is attributable to
decreased bank debt of $14.4 million, offset by a change in working
capital of $1.1 million.
Bank debt outstanding was $216.3 million at June 30, 2010 compared
with $230.7 million as at December 31, 2009. Of the $216.3 million
outstanding at June 30, 2010 $214.9 million is outstanding under the
production facility and $1.4 million is outstanding under the working
capital facility.
At the end of the second quarter, the Trust had a net debt
(excluding convertible debentures) to 12 months trailing cash flow ratio
of 1.07 times and a total net debt (including convertible debentures)
to 12 months trailing cash flow ratio of 1.84 times.
During the second quarter, 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 second quarter of 2010 and $2.0 million
(2009 - $0.8 million) year-to-date.
As at August 9, 2010, the Trust has 146,184,108 trust units and $194.7 million in convertible debentures outstanding.
Capitalization
----------------------------------------------------------------------------
June 30, December 31, June 30,
2010 2009 2009
----------------------------------------------------------------------------
Trust unit equity ($000s) 962,333 894,192 618,335
Bank debt ($000s) 216,321 230,713 244,323
Working capital deficit
(surplus)(1) ($000s) 53,130 52,014 22,571
----------------------------------------------------------------------------
Net debt excluding convertible
debentures 269,451 282,727 266,894
Convertible debentures
($000s)(2) 194,744 194,744 79,744
----------------------------------------------------------------------------
Net debt 464,195 477,471 346,638
Net debt excluding convertible
debentures to trailing
12-month cash flow(3) 1.07 1.23 1.03
Total net debt to trailing
12-month cash flow(3) 1.84 2.07 1.33
Trust units outstanding (000s) 145,968 137,471 111,865
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 $216 million is drawn down at June
30, 2010, leaving available capacity of $334 million.
For 2010, the Trust expects to continue to execute its active
hedging program. Currently, the Trust has in place oil hedges for
approximately 49 percent of net forecasted (after royalty) production
for 2010. Crude volumes are hedged at an average price of US$83.52 per
bbl on fixed price contracts. On collared contracts, crude volumes are
hedged at an average ceiling price of US$80.14 per bbl and at an average
floor price of US$67.75 per bbl. For natural gas, remaining 2010 hedges
total approximately 46 percent of net budgeted production volumes
hedged at an average floor price in excess of $5.54 per GJ ($5.84 per
Mcf).
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 distributions levels.
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 of the announcement of the changes in the
tax legislation. For the remainder of 2010, the Trust has approximately
$423 million of safe harbour available, after taking into consideration
the equity offering that closed during the second quarter of 2010.
ASSET RETIREMENT OBLIGATION
At June 30, 2010, the Trust reported an asset retirement obligation
("ARO") balance of $134.1 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 $6.2 million
to reflect $2.9 million liabilities incurred and revisions to estimates
and $5.3 million from accretion expense, and was reduced by $2.0
million for actual abandonment and environmental expenditures incurred
during the first six months.
DISTRIBUTIONS TO UNITHOLDERS
For the three and six months ended June 30, 2010, the Trust
distributed 91 percent and 72 percent of its cash flow from operating
activities, respectively, as compared to 43 percent and 44 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 Six months ended
June 30 June 30
----------------------------------------
($000s except for percentages) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash flow from operating activities 43,326 63,690 106,974 130,236
Net income (loss) 8,046 (9,407) 37,395 (4,683)
Actual cash distributions paid or
payable 39,361 27,422 76,546 57,238
Excess of cash flow from operating
activities over cash distribution
paid 3,965 36,268 30,428 72,998
Percentage of cash flow from
operations distributed 91% 43% 72% 44%
Excess (shortfall) of net income
over cash distributions paid (31,315) (36,829) (39,151) (61,921)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30, 2010, funds from operations
amounted to $62.7 million, compared with $52.0 million for the three
months ended June 30, 2009. The 21 percent increase is due to higher
revenues resulting from higher commodity prices, offset by lower
realized hedging gains of $16.7 million. On a per trust unit basis,
funds from operations decreased 16 percent from $0.51 in 2009 to $0.43
in 2010.
For the six months ended June 30, 2010, funds from operations
increased 19 percent to $135.9 million from $114.0 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 $43.0 million.
Funds from Operations
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Funds from operations ($000s) 62,684 51,998 135,926 114,022
Funds from operations per trust unit 0.43 0.51 0.96 1.15
Payout ratio based on funds from
operations 63% 53% 56% 50%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30, 2010, the Trust had spent $5.3
million and at the end of the current drilling program, the Trust and
MFC will have spent approximately $15 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 the partner. 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 June 30,
2010, the Trust had spent $21.8 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) 2,078 3,505 3,505 3,482 3,414
Office lease - Alberta Clipper 1,089 2,184 2,192 358 -
and Breaker(2)
Transportation agreement 6,351 - - - -
Processing agreement(3) 1,198 2,242 401 384 -
Convertible debentures(4) - - 79,744 - 115,000
Bank debt - - 129,793 86,528 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 10,716 7,931 215,635 90,752 118,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 the base price adjustment clause.
(3) Represents a gas processing agreement with a take or pay component.
(4) Principal amount.
QUARTERLY INFORMATION
2010 2009
----------------------------------------------------------------------------
($000s, except per unit and
production amounts) Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Revenue, net of royalties(1) 105,925 135,662 88,165 85,988
Per unit 0.73 0.99 0.75 0.77
Cash flow from operations 43,326 63,648 53,060 52,999
Per unit 0.30 0.46 0.45 0.47
Funds from operations(2) 62,684 73,242 62,953 53,766
Per unit 0.43 0.53 0.53 0.48
Net income (loss) 8,046 29,349 5,634 8,249
Per unit
basic 0.06 0.21 0.05 0.07
diluted 0.06 0.21 0.05 0.07
Average oil equivalent production
(boe/d - 6:1) 29,609 30,120 25,748(3) 23,418
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
($000s, except per unit and
production amounts) Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Revenue, net of royalties(1) 60,922 77,791 161,156 234,993
Per unit 0.60 0.81 1.68 2.46
Cash flow from operations 63,690 66,546 77,326 98,860
Per unit 0.63 0.69 0.80 1.03
Funds from operations(2) 51,998 62,024 67,040 79,233
Per unit 0.51 0.64 0.70 0.83
Net income (loss) (9,407) 4,724 55,374 111,045
Per unit
basic (0.09) 0.05 0.58 1.16
diluted (0.09) 0.05 0.56 1.11
Average oil equivalent production
(boe/d - 6:1) 23,049 23,836 23,984 23,808
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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,
NAL's ICFR provides reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for
external purposes in accordance with Canadian GAAP.
There has not been any change in NAL's internal control over
financial reporting during the first six months of 2010 that has
materially affected, or is reasonably likely to materially affect, NAL's
internal control over financial reporting.
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 progress to date has
included evaluation and implementation changes to information systems
and business processes as well as IFRS training to relevant personnel.
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.
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 are being developed. The
review of presentation and disclosure standards has been performed and
changes to financial statements 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 the entity's previous 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 intends to use this election on adoption of
IFRS.
The most significant change identified 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 have to be segregated between exploration and
evaluation ("E&E") and development and production ("D&P")
assets. In addition, assets 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.
- For depletion and depreciation purposes, the Trust must determine
an appropriate depletion or depreciation method, and must deplete by
component. There is the choice whether to deplete E&E assets or not.
In addition, there is the option to deplete using a reserve base of
proved reserves or both proved plus probable reserves. NAL has
determined not to deplete E&E assets and to deplete its oil and gas
properties using both proved plus probable reserves.
- 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 identified its CGU's for
this purpose. An impairment test is performed individually for all CGU's
on transition and there is no impairment noted. On a go forward, 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. ARO
calculations are expected to be impacted due to differences in the
discount rates to be used to present value the liability. In addition,
under IFRS, ARO is required to be revalued each reporting period at the
then prevailing interest rate. This may increase or decrease the ARO
recorded on the balance sheet depending on the direction of change in
interest rates. In addition, onerous contracts will require
identification and, to the extent they exist, must be recorded as a
liability on the balance sheet.
IFRS will allow the Trust to use IFRS rules for business
combinations on a prospective basis rather than restating all business
combinations. 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 intends to elect
this exemption on transition to IFRS.
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 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 in progress. 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 has begun 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, during 2010.
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 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 will be an ongoing process throughout 2010 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. As we have not finalized our accounting
policies, we are unable to quantify the impact of adopting IFRS on our
financial statements. Notwithstanding this, the Trust is confident that
it will meet the requirements for transition by the changeover deadline.
Dated: August 10, 2010
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
June 30, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $751 $1,604
Accounts receivable 43,954 61,631
Prepaids and other receivables 26,154 15,663
Derivative contracts (Note 11) 16,821 6,285
Future income tax asset - 3,132
----------------------------------------------------------------------------
87,680 88,315
Derivative contracts (Note 11) 765 2,461
Goodwill 14,722 14,722
Property, plant and equipment (Note 3) 1,531,704 1,503,952
----------------------------------------------------------------------------
$1,634,871 $1,609,450
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $103,745 $110,897
Note payable (Note 2) 7,600 8,907
Distributions payable to unitholders 13,137 12,372
Derivative contracts (Note 11) 391 11,231
Future income tax liability 2,584 -
----------------------------------------------------------------------------
127,457 143,407
Bank debt (Note 4) $216,321 $230,713
Convertible debentures (Note 5) 179,634 177,977
Other liabilities (Note 6) 7,107 7,643
Asset retirement obligations (Note 8) 134,093 127,872
Future income tax liability 4,733 24,778
Non-controlling interest (Note 9) 3,193 2,868
----------------------------------------------------------------------------
672,538 715,258
Unitholders' equity
Unitholders' capital (Note 10) 1,589,321 1,482,029
Equity component of convertible debentures
(Note 5) 12,628 12,628
Deficit (Note 10) (639,616) (600,465)
----------------------------------------------------------------------------
962,333 894,192
----------------------------------------------------------------------------
$1,634,871 $1,609,450
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (Note 12)
Trust units outstanding (000s) 145,968 137,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF INCOME (LOSS), COMPREHENSIVE INCOME (LOSS)
AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
Three months ended Six months ended
June 30 June 30
----------------------------------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue
Oil, natural gas and
liquid sales $ 123,116 $ 83,676 $ 261,636 $ 165,379
Crown royalties (17,785) (10,743) (34,890) (21,354)
Freehold and other
royalties (6,066) (4,865) (12,107) (8,388)
----------------------------------------------------------------------------
99,265 68,068 214,639 135,637
Gain (loss) on derivative
contracts (Note 11):
Realized gain 5,485 22,159 6,933 49,921
Unrealized gain (loss) 1,171 (29,484) 19,680 (47,988)
----------------------------------------------------------------------------
6,656 (7,325) 26,613 1,933
Other income 4 179 335 1,143
----------------------------------------------------------------------------
105,925 60,922 241,587 138,713
----------------------------------------------------------------------------
Expenses
Operating 29,582 24,759 58,886 50,399
Transportation 1,605 1,026 3,242 2,067
General and
administrative 4,039 4,031 8,398 6,658
Unit-based incentive
compensation (Note 7) (729) 2,767 (290) 3,060
Corporate conversion
costs 118 - 118 -
Interest on bank debt 2,670 2,962 5,756 4,925
Interest and accretion on
convertible debentures 4,105 1,725 8,238 3,449
Depletion, depreciation
and amortization 63,903 42,779 125,939 85,987
Accretion on asset
retirement obligations 2,695 1,886 5,326 3,714
----------------------------------------------------------------------------
107,988 81,935 215,613 160,259
----------------------------------------------------------------------------
Income (loss) before
taxes and non-controlling
interest (2,063) (21,013) 25,974 (21,546)
Income tax recovery
(expense) 61 - 2 1
Future income tax
reduction 10,415 12,242 12,578 18,357
----------------------------------------------------------------------------
Total income tax
reduction 10,476 12,242 12,580 18,358
----------------------------------------------------------------------------
Income (loss) before
non-controlling interest 8,413 (8,771) 38,554 (3,188)
Non-controlling interest
(Note 9) (367) (636) (1,159) (1,495)
----------------------------------------------------------------------------
Net income (loss) and
comprehensive income
(loss) 8,046 (9,407) 37,395 (4,683)
----------------------------------------------------------------------------
Deficit, beginning of
period (608,301) (514,604) (600,465) (489,512)
Net income (loss) 8,046 (9,407) 37,395 (4,683)
Distributions declared (39,361) (27,422) (76,546) (57,238)
----------------------------------------------------------------------------
Deficit, end of period $(639,616) $(551,433) $(639,616) $(551,433)
----------------------------------------------------------------------------
Net income (loss) per
trust unit (Note 10)
Basic $ 0.06 $ (0.09) $ 0.26 $ (0.05)
Diluted $ 0.06 $ (0.09) $ 0.26 $ (0.05)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average trust
units outstanding (000s) 144,617 101,868 141,157 99,040
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
Three months ended Six months ended
June 30 June 30
----------------------------------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Operating Activities
Net income (loss) $ 8,046 $ (9,407) $ 37,395 $ (4,683)
Items not involving cash:
Depletion, depreciation and
amortization 63,903 42,779 125,939 85,987
Accretion on asset
retirement obligations 2,695 1,886 5,326 3,714
Unrealized loss (gain) on
derivative contracts (1,171) 29,484 (19,680) 47,988
Future income tax reduction (10,415) (12,242) (12,578) (18,357)
Non-cash accretion expense
on convertible debentures 1,011 380 2,002 758
Non-controlling interest 151 92 325 708
Lease amortization (423) - (799) -
Abandonment and reclamation (1,113) (974) (2,004) (2,093)
Change in non-cash working
capital (19,358) 11,692 (28,952) 16,214
----------------------------------------------------------------------------
43,326 63,690 106,974 130,236
----------------------------------------------------------------------------
Financing Activities
Distributions paid to
unitholders (32,461) (22,801) (64,430) (59,350)
Increase (decrease) in bank
debt (28,374) (139,447) (14,392) (116,861)
Issue of trust units, net of
issue costs 94,731 82,017 94,576 82,017
Note repayment from MFC
(Note 2) - - - 49,599
Partnership distribution paid
to MFC - (3,500) - (53,302)
Issuance of convertible
debentures (1) - (345) -
Change in non-cash working
capital - 48 - 81
----------------------------------------------------------------------------
33,895 (83,683) 15,409 (97,816)
----------------------------------------------------------------------------
Investing Activities
Additions to property, plant
and equipment (40,034) (16,952) (118,353) (53,888)
Property acquisitions (43,183) (1,485) (45,157) (2,799)
Proceeds from dispositions 103 264 14,779 264
Acquisition of Clipper - (748) - (748)
Disposition of Clipper - 52,657 - 52,657
Disposition of Spearpoint - - (309) -
Change in non-cash working
capital 1,602 (16,377) 25,804 (23,509)
----------------------------------------------------------------------------
(81,512) 17,359 (123,236) (28,023)
----------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (4,291) (2,634) (853) 4,397
Cash and cash equivalents,
beginning of period 5,042 12,615 1,604 5,584
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 751 $ 9,981 $ 751 $ 9,981
----------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid (received) during
the period for:
Interest $ 8,633 $ 4,600 $ 15,429 $ 9,278
Tax $ 443 - $ 502 $ (72)
----------------------------------------------------------------------------
Cash and cash equivalents is
comprised of:
Cash $ 751 $ 3,982 $ 751 $ 3,982
Short term investments - 5,999 - 5,999
----------------------------------------------------------------------------
$ 751 $ 9,981 $ 751 $ 9,981
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
Six months ended June 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 $3.6 million (2009 - $3.4 million) for the
reimbursement of G&A expenses during the second quarter and $7.2
million (2009 - $5.3 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 June 30, 2010, there is a note payable of $7.6 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 second quarter of 2010 (2009 - $0.1 million net interest
expense), and net interest expense of $0.2 million (2009 - $0.4 million
net interest income) was payable by the Trust for the first half of
2010. This amount is reported as other income.
The following amounts are due to and from related parties as at June
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:
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Due from NAL Resources Limited $13,000 $1,731
Due to NAL Resources Management Limited (1,410) (8,753)
Due to Manulife Financial Corporation(1) (8,008) (9,472)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$3,582 $(16,494)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included on consolidation, eliminated through non-controlling interest.
Represents note payable $7.6 million (2009: $8.9 million), plus amounts
due from (to) MFC of ($0.4) 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
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Petroleum and natural gas properties, at
cost $2,732,959 $2,579,268
Less: Accumulated depletion and
depreciation (1,201,255) (1,075,316)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$1,531,704 $1,503,952
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The calculation of second 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 $165.2 million (2009 - $45.1 million).
During the six months ended June 30, 2010, the Trust capitalized
$4.3 million (2009 - $3.0 million) of G&A costs and had a recovery
of $0.2 million (2009 - a $1.3 million charge) of unit-based incentive
compensation that were directly related to exploitation and development
programs.
4. BANK DEBT
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Production loan facility $214,901 $230,713
Working capital facility 1,420 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt outstanding $216,321 $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 June 30, 2010
and December 31, 2009 all amounts outstanding were in Canadian dollars.
On June 30, 2010 the effective interest rate on amounts outstanding
under the credit facility was 5.3 percent (2009 - 4.36 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.
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
6.25% 6.75% Total 6.25% 6.75% Total
----------------------------------------------------------------------------
Principal, beginning
of period $115,000 $79,744 $194,744 $ - $79,744 $ 79,744
Issued during
period - - - 115,000 - 115,000
----------------------------------------------------------------------------
Principal, end of
period $115,000 $79,744 $194,744 $115,000 $79,744 $194,744
----------------------------------------------------------------------------
Debt component,
beginning
of period $102,450 $75,527 $177,977 $ - $74,004 $ 74,004
Issued during
period - - - 106,965 - 106,965
Issue costs (345) - (345) (4,714) - (4,714)
Accretion 1,229 773 2,002 199 1,523 1,722
----------------------------------------------------------------------------
Debt component,
end of
period $103,334 $76,300 $179,634 $102,450 $75,527 $177,977
----------------------------------------------------------------------------
Equity component,
beginning
of period $ 8,036 $ 4,592 $ 12,628 $ - $ 4,592 $ 4,592
Issued during
period - - - 8,036 - 8,036
----------------------------------------------------------------------------
Equity component,
end of
period $ 8,036 $ 4,592 $ 12,628 $ 8,036 $ 4,592 $ 12,628
----------------------------------------------------------------------------
6. OTHER LIABILITIES
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Unit-based incentive compensation
(Note 7) $4,243 $3,935
Excess office lease obligation (1) 2,864 3,708
----------------------------------------------------------------------------
$7,107 $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 Inc. and Breaker Energy Ltd. MFC will reimburse the
Trust for 50 percent of the Alberta Clipper obligation of $0.6 million
under the base price adjustment clause.
7. UNIT-BASED INCENTIVE COMPENSATION PLAN
The Trust recorded a $0.4 million recovery in the first six months
of 2010, of which $0.3 million was recorded as a recovery through
earnings and $0.1 million as a deduction to 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 June 30, 2010 trust
unit price of $10.60 (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:
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of
period $16,411 $6,274
Increase (decrease) in
liability (444) 12,461
Cash payout, relating to
units vested (6,968) (2,324)
----------------------------------------------------------------------------
Balance, end of period $ 8,999 $16,411
----------------------------------------------------------------------------
Current portion of
liability(1) $ 4,756 $12,476
----------------------------------------------------------------------------
Long-term liability(2) $ 4,243 $ 3,935
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.
(2) Included in other liabilities, (Note 6)
8. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the Trust's asset retirement obligations.
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of
period $127,872 $90,844
Accretion expense 5,326 7,856
Revisions to estimates (569) 558
Liabilities incurred 1,181 1,522
Liabilities acquired 2,462 32,311
Liabilities disposed (175) -
Liabilities settled (2,004) (5,219)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period $134,093 $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:
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Non-controlling interest, beginning of
period $2,868 $56,380
Net income attributable to
non-controlling interest 325 1,040
Distributions to MFC(1) - (54,552)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-controlling interest, end of
period $3,193 $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 Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Net profits interest expense $ 216 $ 544 $ 834 $ 787
Share of net income attributable to MFC 151 92 325 708
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 367 $ 636 $ 1,159 $ 1,495
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. UNITHOLDERS EQUITY
Units Issued:
Six months ended Year ended
June 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) - (4,096) - (3,565)
Issued from Distribution
Reinvestment Plan 947 11,350 1,234 11,914
----------------------------------------------------------------------------
Balance, end of the period 145,968 $ 1,589,321 $137,471 $ 1,482,029
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Unit Information
Basic net income per trust unit is 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 six months ended June 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 six months ended June 30,
2010 were 12,665,697 (2009 - 5,696,000) and 12,665,697 (2009 -
5,696,000), respectively. As at June 30, 2010, the total convertible
debentures outstanding were immediately convertible to 12,665,697 trust
units.
Deficit
The deficit is comprised of the following:
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Accumulated income $ 599,626 $ 562,231
Accumulated cash distributions (1,239,242) (1,162,696)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$(639,616) $(600,465)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL RISK MANAGEMENT
Foreign currency exchange rate risk
NAL has the following exchange rate derivative contracts outstanding:
----------------------------------------------------------------------------
Total
Remaining
Contracted Trust
EXCHANGE RATE Amount(1) Fixed Counterparty
CONTRACT Remaining Term (US$ MM) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating July 2010 -
to fixed Dec 2010 54.0 1.0904 BofC Average Noon Rate
Swaps-floating Jan 2011 -
to fixed Dec 2011 30.0 1.0522 BofC Average Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional US$ denominated commodity sales.
In addition, NAL has the following exchange rate contract commitments:
(i) From July to December 2010, NAL has a commitment to sell US$6
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
June 30, 2010, if exchange rates had strengthened by $0.01, with all
other variables held constant, net income for the period would have been
$0.8 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 $0.01 weaker.
Commodity price risk
NAL has the following commodity risk management contracts outstanding:
CRUDE OIL Q3-10 Q4-10 Q1-11 Q2-11
----------------------------------------------------------------------------
US$ Collar Contracts
---------------------
$US WTI Collar Volume (bbl/d) 2,100 1,900 800 800
Bought Puts - Average Strike Price
($US/bbl) 67.50 68.03 81.25 81.25
Sold Calls - Average Strike Price
($US/bbl) 79.70 80.62 94.47 94.47
US$ Swap Contracts
-------------------
$US WTI Swap Volume (bbl/d) 3,665 3,900 700 700
Average WTI Swap Price ($US/bbl) 83.60 83.45 83.08 83.08
Total Oil Volume (bbl/d) 5,765 5,800 1,500 1,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS Q3-10 Q4-10 Q1-11 Q2-11
----------------------------------------------------------------------------
Swap Contracts
AECO Swap Volume (GJ/d) 42,000 31,337 5,000 4,000
AECO Average Price ($Cdn/GJ) 5.55 5.52 5.61 5.78
Total Natural gas Volume (GJ/d) 42,000 31,337 5,000 4,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 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 $1.7
million higher, due to changes in the fair value of the derivative
contracts. An equal and opposite effect would have occurred to net
income had 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 July 2010 - CAD-BA-CDOR
to fixed Dec 2011 $39.0 1.5864% (3 months)
Swaps-floating July 2010 - CAD-BA-CDOR
to fixed Jan 2013 $22.0 1.3850% (3 months)
Swaps-floating July 2010 - CAD-BA-CDOR
to fixed Jan 2014 $22.0 1.5100% (3 months)
Swaps-floating July 2010 - CAD-BA-CDOR
to fixed Mar 2013 $14.0 1.8500% (3 months)
Swaps-floating July 2010 - CAD-BA-CDOR
to fixed Mar 2013 $14.0 1.8750% (3 months)
Swaps-floating July 2010 - CAD-BA-CDOR
to fixed Mar 2014 $14.0 1.9300% (3 months)
Swaps-floating July 2010 - $14.0 1.9850% CAD-BA-CDOR
to fixed Mar 2014 (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
June 30, 2010, if interest rates had been one percent lower, with all
other variables held constant, net income for the period would have been
$4.1 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$75.63 per barrel to
US$80.40 per barrel for oil and $3.70 per GJ to $5.30 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 0.883 percent
to 2.316 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 1.0631 to 1.0714) 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:
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Fair value of commodity contracts $15,726 $(8,932)
Fair value of interest rate swaps 765 2,461
Fair value of foreign exchange rate
swaps 704 3,986
----------------------------------------------------------------------------
$17,195 $(2,485)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The gain/(loss) on derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts 15,939 (34,769) 17,485 (55,967)
Natural gas contracts (7,848) (10) 7,173 2,691
Interest rate swaps (1,887) 3,828 (1,696) 3,150
Exchange rate swaps (5,033) 1,467 (3,282) 2,138
----------------------------------------------------------------------------
Unrealized gain (loss) 1,171 (29,484) 19,680 (47,988)
Realized gain (loss):
Crude oil contracts (2,712) 15,901 (4,794) 36,653
Natural gas contracts 6,900 4,507 9,397 11,463
Interest rate swaps (385) (178) (642) (207)
Exchange rate swaps 1,682 1,929 2,972 2,012
----------------------------------------------------------------------------
Realized gain 5,485 22,159 6,933 49,921
----------------------------------------------------------------------------
Gain (loss) on derivative contracts 6,656 (7,325) 26,613 1,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
These contracts are presented on the balance sheet as short term/long term,
assets and liabilities as follows:
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Current unrealized loss on derivative
contracts $ (391) $(11,231)
Current unrealized gain on derivative
contracts 16,821 6,285
----------------------------------------------------------------------------
Current unrealized gain (loss) on
derivative contracts 16,430 (4,946)
Long term unrealized gain on derivative
contracts 765 2,461
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net fair value of derivative contracts $17,195 $ (2,485)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table reconciles the movement in the fair value of the Trust's
derivative contracts:
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Unrealized gain (loss), beginning of
period $16,024 $ 46,902 $ (2,485) $ 65,406
Unrealized gain acquired(1) - 408 - 408
Unrealized gain, end of period 17,195 17,826 17,195 17,826
----------------------------------------------------------------------------
Unrealized gain (loss) for the
period 1,171 (29,484) 19,680 (47,988)
Realized gain in the period 5,485 22,159 6,933 49,921
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gain (loss) on derivative contracts $ 6,656 $ (7,325) $ 26,613 $ 1,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumed on acquisition of Alberta Clipper Energy Inc.
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 June 30, 2010, the Trust had spent $5.3
million and at the end of the current drilling program, the Trust and
MFC will have spent approximately $15 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 the partner. 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 June 30, 2010, the Trust had spent $21.8 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) 2,078 3,505 3,505 3,482 3,414
Office lease - Clipper and Breaker(2) 1,089 2,184 2,192 358 -
Transportation agreement 6,351 - - - -
Processing agreement(3) 1,198 2,242 401 384 -
Convertible debentures(4) - - 79,744 - 115,000
Bank debt - - 129,793 86,528 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 10,716 7,931 215,635 90,752 118,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Energy Inc. and Breaker Energy Ltd. MFC
will reimburse the Trust for 50 percent of the Clipper obligation under
the base price adjustment clause.
(3) Represents a gas processing agreement with a take or pay component.
(4) Principal amount.
TRADING PERFORMANCE
For the Quarter Ended
-------------------------------------------
30-Jun-10 31-Mar-10 30-Jun-09 31-Mar-09
----------------------------------------------------------------------------
PRICE
High $13.57 $14.95 $10.53 $8.99
Low $9.68 $12.50 $6.63 $5.38
Close $10.60 $12.95 $9.37 $6.80
Daily Average Volume 601,723 589,149 459,603 359,591
----------------------------------------------------------------------------
NAL Oil & Gas Trust provides investors with a yield-oriented
opportunity to participate in the Canadian Upstream Conventional Oil and
Gas Industry. The Trust generates monthly cash distributions for its
Unitholders by pursuing a strategy of acquiring, developing, producing
and selling crude oil, natural gas and natural gas liquids from pools in
southeastern Saskatchewan, central Alberta, northeastern British
Columbia and Lake Erie, Ontario. Trust units trade on the Toronto Stock
Exchange under the symbol "NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Investor Relations
403.294.3620 or Toll Free: 888.223.8792
403.294.3601 (FAX)
Investor.Relations@nal.ca
www.nal.ca