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 ($10 million).
OUTLOOK
For the remainder of 2010, NAL expects to continue to be active in drilling our
oil resource opportunities in the Cardium and Mississippian plays. The Trust is
planning to provide an operational update in September, 2010.
2010 GUIDANCE
The Trust's guidance remains unchanged from its update in May, 2010. As
previously outlined, NAL is forecasting a 2010 full year average in the range of
29,500 - 30,500 boe per day with a projected production volume exit rate in
excess of 31,000 boe per day.
Current 2010 Guidance
----------------------------------------------------------------------------
Production (boe/d) 29,500 - 30,500
Capital expenditures ($MM)(i) 210
Operating costs ($/boe) 10.75 - 11.25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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)
----------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Operating netback before hedging 25.31 20.30 28.32 19.77
Hedging gains 2.18 10.65 1.40 11.82
----------------------------------------------------------------------------
Operating netback 27.49 30.95 29.72 31.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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:
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------
$ (000s) 2010 2009 2010 2009
----------------------------------------------------------------------------
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)
----------------------------------------------------------------------------
Funds from operations 62,684 51,998 135,926 114,022
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total wells
drilled 17 9.7 3 1.8 0 0 0 0 20 11.5
----------------------------------------------------------------------------
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)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total exploration and development 36,847 13,797 113,077 49,184
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total other capital 3,187 3,155 5,276 4,704
----------------------------------------------------------------------------
Total capitalized expenditures
before acquisitions 40,034 16,952 118,353 53,888
----------------------------------------------------------------------------
Property acquisitions, net 43,080 1,221 30,378 2,535
----------------------------------------------------------------------------
Total capitalized expenditures 83,114 18,173 148,731 56,423
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Oil 39% 42% 39% 42%
Natural gas 51% 49% 52% 49%
NGLs 10% 9% 9% 9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total revenue 121,511 82,650 258,394 163,312
$/boe 45.10 39.40 47.80 38.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties and hedging.
OIL MARKETING
NAL markets its crude oil based on refiners' posted prices at Edmonton, Alberta
and Cromer, Manitoba adjusted for transportation and the quality of crude oil at
each field battery. The refiners' posted prices are influenced by the WTI
benchmark price, transportation costs, exchange rates and the supply/demand
situation of particular crude oil quality streams during the year.
NAL's 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 $4.38/Mcf realized in the comparable period of 2009. The
increase in natural gas prices was attributable to a six percent increase in the
benchmark AECO daily spot prices.
Average Pricing
(net of transportation charges)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-----------------------------------------
2010 2009 2010 2009
----------------------------------------------------------------------------
Liquids
WTI (US$/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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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".
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