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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Centamin Plc | TSX:CEE | Toronto | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 2.32 | 2.26 | 2.29 | 0 | 12:15:31 |
Hot Features
Premium
NAL Oil & Gas Trust ("NAL" or the "Trust") (TSX:NAE.UN) today announced its
financial and operational results for the third quarter of 2009. All amounts are
in Canadian dollars unless otherwise stated.
On NAL's third quarter, Mr. Andrew Wiswell stated "After posting another solid
quarter, the Trust remains on track to deliver results within guidance for 2009.
Over the past twelve months, NAL has created positive momentum through
consistent and reliable operations in southeast Saskatchewan, the Cardium oil
resource play in central Alberta and the successful execution of several
transactions to add attractive opportunities, all while maintaining a strong
balance sheet position. The Trust is well positioned to create sustainable value
and deliver competitive total returns for its unitholders. As we look toward
2011, we remain committed to a plan of converting to a dividend paying
corporation and to continue to deliver results and capture value adding
opportunities with our financial partner Manulife Financial Corporation".
THIRD QUARTER 2009 ACCOMPLISHMENTS
NAL's overall performance exceeded management's financial, operational and
strategic objectives. Accomplishments include:
- On October 13, 2009, NAL announced the acquisition of Breaker Energy Ltd.
("Breaker"), an oil weighted junior E&P company (see comments below).
- The Trust remains on track to deliver 2009 full year average production
volumes consistent with guidance;
- Third quarter operating costs of $10.52/boe represent a 10 percent decrease
from the same period of 2008 and reflect the focus of NAL's operations teams to
reduce costs;
- At September 30, 2009, the Trust currently has approximately $200 million in
available credit on its lines of $450 million, providing financial flexibility
to fund NAL's capital program and continue to participate selectively in
corporate and property acquisitions;
- NAL's debt to trailing 12 month cash flow ratios remain solid at 1.25 times
excluding convertible debentures and 1.59 times including convertible
debentures.
ACQUISITION OF BREAKER ENERGY LTD.
On October 13, 2009, NAL announced the acquisition of Breaker for total
consideration of approximately $400 million. The acquisition is consistent with
NAL's strategy to grow by adding quality assets with future upside opportunity
while maintaining financial capability. The acquisition is expected to increase
NAL's year-end production by 28 percent to over 31,000 boe/d and increase
reserves by more than 30 percent to approximately 96 MMboe. Breaker's operated
assets add significant low risk development projects which complement the
Trust's Cardium horizontal multi-stage frac program.
The acquisition is expected to close December 10, 2009, with full integration
expected to occur by the end of the first quarter of 2010.
2009 UPDATED GUIDANCE
Based upon positive year-to-date performance, the Trust has updated its
guidance for 2009.
January 2009 August 2009 November 2009
Guidance Guidance Updated Guidance(1)
----------------------------------------------------------------------------
Production (boe/d) 22,000 - 23,000 23,000 - 24,000 23,500 - 24,000
Net capital expenditures
($MM) 95 125 -135 135
Operating costs ($/boe) 11.60- 11.90 11.60 - 11.90 11.30 - 11.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note (1) Excludes proposed Breaker acquisition.
OUTLOOK
NAL will outline its 2010 guidance and forecast in mid-January 2010.
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 2009 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 3:00 p.m. MDT (5:00 p.m. EDT) on November 3, 2009, NAL will hold a conference
call to discuss the third quarter 2009 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/110309/index.php
A recorded playback of the call will be available until November 10, 2009 by
calling 1-800-408-3053, reservation 3565817.
Notes: (1) All amounts are in Canadian dollars unless otherwise stated.
(2) When converting natural gas to barrels of oil equivalent (boe)
within this report, 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 Nine months ended
Sept. 30 Sept. 30
----------------------------------------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
FINANCIAL
Revenue(1) 86,298 175,448 249,610 507,998
Cash flow from operating activities 52,999 98,860 183,235 242,716
Cash flow per unit - basic 0.47 1.03 1.77 2.59
Cash flow per unit - diluted 0.44 0.99 1.64 2.46
Funds from operations 53,766 79,233 167,788 244,031
Funds from operations per unit
- basic 0.48 0.83 1.62 2.60
Funds from operations per unit
- diluted 0.44 0.79 1.50 2.48
Net income 8,249 111,045 3,566 107,206
Distributions declared 30,290 45,968 87,528 135,295
Distributions per unit 0.27 0.48 0.85 1.44
Basic payout ratio:
based on cash flow from operating
activities 57% 46% 48% 56%
based on funds from operations 56% 58% 52% 55%
Basic payout ratio including capital
expenditures(2) :
based on cash flow from operating
activities 136% 96% 100% 99%
based on funds from operations 134% 119% 109% 98%
Units outstanding (000's)
Period end 112,327 95,945 112,327 95,945
Weighted average 112,109 95,664 103,444 93,834
Capital expenditures(3) 42,375 53,189 96,264 109,260
Property acquisitions
(dispositions), net - 373 2,534 8,209
Corporate acquisitions, net 11,035 14 48,385 58,378
Net debt, excluding convertible
debentures(4) 293,680 303,330 293,680 303,330
Convertible debentures (at face
value) 79,744 79,744 79,744 79,744
OPERATING
Daily production
Crude oil (bbl/d) 9,467 9,989 9,725 10,176
Natural gas (Mcf/d) 69,706 70,425 68,778 68,847
Natural gas liquids (bbl/d) 2,334 2,081 2,244 2,083
Oil equivalent (boe/d) 23,418 23,808 23,433 23,733
OPERATING NETBACK (boe)
Revenue before hedging gains 40.06 80.11 39.02 78.12
Royalties (6.94) (16.90) (6.99) (16.19)
Operating costs (10.52) (11.63) (11.42) (10.64)
Other income(5) 0.17 0.12 0.17 0.19
----------------------------------------------------------------------------
Operating netback before hedging 22.77 51.70 20.78 51.48
Hedging gains (losses) 8.84 (7.59) 10.82 (6.74)
----------------------------------------------------------------------------
Operating netback 31.61 44.11 31.60 44.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties.
(2) Capital expenditures included are net of non-controlling interest amount
of $0.4 million (2008 - $4.7) for the three months ended September 30,
2009 and $1.5 million (2008 - $5.2) for the nine months ended September
30, 2009, attributable to the Tiberius and Spear properties.
(3) Excludes property and corporate acquisitions.
(4) Bank debt plus working capital and other liabilities, excluding
derivative contracts, notes payable/receivable and future income tax
balances.
(5) Excludes minimal Trust interest paid on notes with Manulife Financial
Corporation.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in conjunction
with the interim unaudited consolidated financial statements for the three and
nine month periods ended September 30, 2009 and the audited consolidated
financial statements and MD&A for the year ended December 31, 2008 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 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 Nine months ended
Sept. 30 Sept. 30
---------------------------------------
$(000s) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash flow from operating activities 52,999 98,860 183,235 242,716
Add back change in non-cash working
capital 767 (19,627) (15,447) 1,315
----------------------------------------------------------------------------
Funds from operations 53,766 79,233 167,788 244,031
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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; 2009 and 2010
production; future tax treatment of the Trust; future structure 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; rates of return; and the successful acquisition of Breaker
Energy Ltd.
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 and development activities; our ability
to market our oil and natural gas successfully to current and new customers; the
impact of increasing competition; our ability to obtain financing on acceptable
terms; and our ability to add production and reserves through our development
and exploitation activities.
Although NAL believes that the expectations reflected in the forward-looking
information contained in the MD&A and the press release through which it was
disseminated, and the assumptions on which such forward-looking information are
made, are reasonable, readers are cautioned not to place undue reliance on such
forward looking statements as there can be no assurance that the plans,
intentions or expectations upon which the forward-looking information are based
will occur. Such information involves known and unknown risks, uncertainties and
other factors that may cause actual results or events to differ materially from
those anticipated and which may cause NAL's actual performance and financial
results in future periods to differ materially from any estimates or projections
of future performance. These risks and uncertainties include, without
limitation: changes in commodity prices; unanticipated operating results or
production declines; the impact of weather conditions on seasonal demand and
NAL's ability to execute its capital program; risks inherent in oil and gas
operations; the imprecision of reserve estimates; limited, unfavorable or no
access to capital or credit markets; the impact of competitors; the lack of
availability of qualified operating or management personnel; the ability to
obtain industry partner and other third party consents and approvals, when
required; failure to complete the acquisition of Breaker Energy Ltd.; failure to
realize the anticipated benefits of acquisitions, including Breaker Energy Ltd.;
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, including the impact of
legislation relating to the taxation of "specified investment flow-through"
entities; stock market volatility and market valuations; OPEC's ability to
control production and balance global supply and demand for crude oil at desired
price levels; political uncertainty, including the risk of hostilities in the
petroleum producing regions of the world; and other risk factors discussed in
other public filings of the 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.
RECENT DEVELOPMENTS
PLAN OF ARRANGEMENT - BREAKER ENERGY LTD.
On October 13, 2009, NAL and Breaker Energy Ltd. ("Breaker") entered into an
arrangement agreement pursuant to which NAL will acquire all of the issued and
outstanding common shares of Breaker by way of Plan of Arrangement. Under the
arrangement, Breaker shareholders will receive 0.475 NAL trust units for each
share of Breaker held, resulting in the expected issuance of approximately 24.7
million trust units. The transaction is subject to the approval of the Breaker
shareholders, the Court of Queen's Bench of the Province of Alberta and
regulatory authorities, and is expected to close on December 10, 2009.
The acquisition is anticipated to add 6,700 boe/d of production to the Trust and
23 million boe of proved plus probable reserves, in addition to 140,000 acres of
net undeveloped land and $270 million of tax pools.
DISPOSITION OF NON-CORE PROPERTY
The sale of a non-operated property is expected to close in the fourth quarter
for net proceeds of $15 million, subject to final adjustments.
ACQUISITION OF SPEARPOINT ENERGY CORP.
Effective August 10, 2009, the Trust acquired all of the issued and outstanding
common shares of Spearpoint Energy Corp. ("Spearpoint") for cash of $10.6
million, prior to acquisition costs. The assets of Spearpoint include natural
gas production in Alberta and a farm-in agreement with BP Canada Energy Company.
Concurrent with the corporate acquisition, the Trust entered into an Asset
Purchase and Sale Agreement ("PSA") with Manulife Financial Corporation ("MFC"),
pursuant to which MFC acquired a 40 percent working interest in all of the
Spearpoint petroleum and natural gas properties and the farm-in agreement for a
base price of $6.5 million payable in cash.
Included within the PSA is a base price adjustment clause that ensures the Trust
and MFC share 60 percent / 40 percent, respectively, in all assets or
liabilities related to Spearpoint that pertain to periods on or prior to the
effective date of the acquisition, regardless of their date of discovery or
disclosure. The base price adjustment calculation adjusts the purchase price
that MFC pays the Trust for any change in working capital from amounts
determined at the time the base price of $6.5 million was established. As at
September 30, 2009, the Trust had a receivable from MFC of $0.3 million relating
to these price adjustments.
After taking into effect the MFC disposition and MFC's share of the assets and
liabilities to be settled under the base price adjustment clause, the Trust
acquired property, plant and equipment of $10.7 million and a future income tax
asset of $0.5 million and assumed liabilities including a note payable of $5.7
million, a working capital deficiency of $0.9 million and asset retirement
obligations of $0.4 million, for consideration of $4.2 million.
MFC is a related party to the Trust, see "Related Party Transactions".
ACQUISITION OF ALBERTA CLIPPER ENERGY INC.
Effective June 1, 2009, the Trust acquired all of the issued and outstanding
common shares of Alberta Clipper Energy Inc. ("Clipper"), which has interests in
petroleum and natural gas properties and undeveloped land in Alberta and
northeast British Columbia.
The Trust issued 5.7 million trust units at a price of $6.45 a trust unit for
total consideration, before acquisition costs, of $36.6 million. The trust unit
price was based on the weighted average market price of trust units at the date
of announcement, being March 23, 2009. The purchase price included the
assumption of $78.9 million in bank debt.
Concurrent with the corporate acquisition, the Trust entered into an Asset
Purchase and Sale Agreement (the "Clipper PSA") with MFC, pursuant to which MFC
acquired a 50 percent working interest in all of the Clipper petroleum and
natural gas properties for a base price of $52.5 million payable in cash. The
proceeds received from MFC were used to partially repay the assumed bank debt.
Included within the Clipper PSA is a base price adjustment clause that ensures
the Trust and MFC share equally in all assets or liabilities related to Clipper
that pertain to periods on or prior to the effective date of the acquisition,
regardless of their date of discovery or disclosure. The base price adjustment
calculation will adjust the purchase price that MFC pays the Trust for any
change in working capital from amounts determined at the time the base price of
$52.5 million was established. In addition, the costs associated with contracts
outstanding at the date of acquisition will be equally shared between both
parties on an ongoing basis, as the obligations are settled by the Trust. The
amounts due under this base price adjustment clause are to be settled no more
frequently than quarterly commencing December 2009. As at September 30, 2009,
the Trust had a receivable from MFC of $0.8 million relating to these price
adjustments.
As a result, after taking into effect the MFC disposition and MFC's share of the
assets and liabilities to be settled under the base price adjustment clause, the
Trust acquired property, plant and equipment of $55.4 million, a derivative
contract of $0.4 million and a future tax asset (reflecting the excess of tax
pools over book value) of $17.9 million, representing assets totaling $73.7
million, and assumed liabilities including asset retirement obligations of $7.3
million, bank debt of $26.4 million, a working capital deficiency of $1.1
million and a lease obligation of $1.5 million, for consideration of $37.4
million, including estimated acquisition costs of $0.8 million.
EXPLORATION & DEVELOPMENT ACTIVITIES
The Trust spent $34.6 million on drilling, completion and tie-in operations
during the third quarter of 2009, compared to $39.2 million during the third
quarter of 2008 and drilled 26 (12.3 net) wells as compared to 33 (15.7 net)
wells during the same period in 2008.
Drilling in the quarter was focused on horizontal oil wells in Saskatchewan and
Alberta. The Trust is expecting to drill 78 (37 net) wells for full year 2009
including 57 (25 net) that have been drilled year-to-date and a 21 (12 net) well
program to be executed in the fourth quarter. The remaining drilling program
will also be heavily weighted to oil including 8 (6 net) Cardium and 11 (5 net)
Mississippian horizontals. Full year estimates consist of 17 (4 net) gas wells
and 61 (33 net) oil wells of which 24 (16 net) will be Cardium and 32 (15 net)
will be Mississippian wells.
Third Quarter Drilling Activity
Service Dry &
Crude Oil Natural Gas Wells Abandoned Total
---------------------------------------------------------
Gross Net Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Operated wells 19 11.3 0 0 0 0 0 0 19 11.3
Non-operated wells 1 0.2 6 0.8 0 0 0 0 7 1.0
----------------------------------------------------------------------------
Total wells drilled 20 11.5 6 0.8 0 0 0 0 26 12.3
----------------------------------------------------------------------------
Southeast Saskatchewan
In Saskatchewan, there were 10 (4.7 net) horizontal oil wells drilled during the
third quarter. Activity was focused on the Mississippian in Alida, Torquay and
Nottingham with initial production rates ranging from 50-250 bbls/d. The Trust
intends to drill 11 (5.0 net) horizontal Mississippian oil wells in the fourth
quarter following up on successful new pool discoveries, infills and extensions.
While the Cardium play in Alberta has recently been the focus of market
attention, the economics in Mississippian light oil projects remain as good or
better and is the reason the Trust continues to balance its capital expenditures
between the two distinctly different resource plays. The Nottingham gas plant
expansion was commissioned in October and plans to bring on incremental volumes
in November are currently underway.
Alberta
In Alberta, NAL participated in drilling 15 (7.4 net) wells including 10 (6.7
net) wells in the Cardium at Garrington, Cochrane and Pine Creek. Many
completion and tie-in operations were running through the end of the quarter
with first month production numbers after load fluid recovery expected in
November. Overall, results remain in-line with expectations and management
remains encouraged by the potential of this resource. For the remainder of the
year, the Trust intends to drill 8 (6 net) horizontal Cardium oil wells in
Garrington and Pine Creek to delineate significant Cardium acreage related to
recently announced transactions. Reduced drilling and completion costs coupled
with execution efficiency gains continue to be a focus for NAL and it is
expected that costs will be lower as the program matures. Current drill,
completion and tie-in costs for Cardium horizontal wells are in the $3.0 million
range.
Northeast British Columbia
Production in Sukunka was significantly impacted by failures related to third
party operated gathering systems and several unplanned outages at the Pine River
Plant. This down time equated to 600 boe/d of lost production in the quarter.
However, due to low gas prices throughout the period, funds flow from operations
was only impacted by $330,000. The first week of production in October was back
at full capability, producing approximately 2,600 boe/d. The non-operated well
at a-100-c (Trust 20 percent working interest) reached total depth during the
quarter, initial completion work was done and the well is currently standing
while further completion operations are being evaluated.
FOCUS OF FUTURE ACTIVITY
Commodity prices have been challenging in 2009 but NAL's strong balance sheet,
balanced production mix, hedging strategy and support from its partner MFC have
positioned the Trust well to take advantage of challenging market conditions.
Upon the completion of the recently announced acquisition of Breaker, the Trust
will have completed four significant transactions during 2009, increasing
production and reserves by more than 30 percent and adding access to a broad
land position of more than 1.5 million gross acres. The Trust has also added
significant prospecting capability with the addition of key technical staff.
Efforts are underway to catalogue a multi-year oil and gas drilling inventory
from this significantly expanded land portfolio.
The use of cost effective horizontal drilling techniques with multi-stage
fracing has unlocked significant low risk oil reserves and value for our
unitholders. NAL is well positioned in the Cardium oil resource with acreage at
Garrington, Cochrane and Pine Creek in central Alberta, and in Mississippian oil
in southeast Saskatchewan with new opportunities added in the Wabamun formation
(at Irricana) and Leduc formation (at Millard Lake) through the proposed Breaker
transaction. Current oil prices coupled with provincial royalty incentive
programs drive compelling economics for oil development that produce recycle
ratios exceeding two times, rates of return in the 30 - 50 percent range, and
attractive netbacks. The Trust currently intends to remain focused on an oil
weighted program through 2010, but retains significant leverage and flexibility
to shift capital toward gas projects should a recovery in natural gas prices
emerge.
NAL continues to build gas inventory on its expanded land position but will wait
on a gas price recovery which yields economics that can compete with the Trust's
expanded oil portfolio. The use of horizontal drilling and multi stage fracing
will play a large part in any gas development program in the future as the Trust
currently has catalogued more than 100 ready-to-drill horizontal wells in the
Rock Creek, Falher, Halfway, Viking, Doig and Mannville zones. It is expected
that NAL will spend 20 - 30 percent of its exploration and development budget in
2010 on strategic gas drilling to prove up reserves. Selective prospects with
high initial gas rate potential and high liquid yields that deliver competitive
economic returns will be considered in the program to take advantage of
attractive government incentives.
CAPITAL EXPENDITURES
Capital expenditures, before property acquisitions, for the quarter ended
September 30, 2009 totaled $42.4 million compared with $53.2 million for the
quarter ended September 30, 2008. The decrease in capital spending
year-over-year is largely a function of relatively higher land and facilities
spending during the third quarter of 2008. NAL is on track with plans to
evaluate the significant oil opportunities that have been compiled over the
course of the year through strategic partnerships and land acquisitions. Crude
prices in the quarter have continued to be relatively strong, supporting
increased spending, with full year capital expenditures expected to be $135
million excluding acquisitions.
On a year-to-date basis, capital expenditures, before property acquisitions,
totaled $96.3 million compared to $109.3 million in the comparable period of
2008.
Capital Expenditures ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Drilling, completion and production
equipment 34,599 39,237 72,685 79,520
Plant and facilities 1,264 4,542 9,654 11,249
Seismic 806 69 1,053 876
Land 2,829 8,293 5,290 12,115
----------------------------------------------------------------------------
Total exploitation and development 39,498 52,141 88,682 103,760
----------------------------------------------------------------------------
Office equipment 128 562 508 1,181
Capitalized G&A 1,266 824 4,260 3,167
Capitalized unit-based compensation 1,484 (338) 2,814 1,152
----------------------------------------------------------------------------
Total other capital 2,878 1,048 7,582 5,500
----------------------------------------------------------------------------
Total capitalized expenditures
before acquisitions 42,376 53,189 96,264 109,260
----------------------------------------------------------------------------
Property acquisitions
(dispositions), net - 373 2,534 8,209
----------------------------------------------------------------------------
Total capitalized expenditures 42,376 53,562 98,798 117,469
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PRODUCTION
Third quarter 2009 production was 23,418 boe/d, compared to production of 23,808
boe/d in the same period of 2008. This two percent decline was entirely
attributed to unplanned third party facilities outages at Sukunka that
negatively impacted the quarter by 600 boe/d. The Trust's internal forecast was
23,700 boe/d for the third quarter and, without this outage volumes would have
been in the 24,000 boe/d range. It is anticipated that fourth quarter production
will be 24,000-24,400 boe/d dependent on the timing of new production tie-ins.
Full year average production is still expected to be at the higher end of our
guidance of 23,000 - 24,000 boe/d. Provided the proposed Breaker acquisition
closes as scheduled, the Trust anticipates fourth quarter average production to
be 25,000 - 25,500 boe/d, with the impact on full year average volumes being
muted due to the December 10, 2009 close date. Year-over-year, oil production
was down five percent in the quarter which was mainly attributable to production
declines in Saskatchewan. The development program in Saskatchewan was reduced in
response to substantially lower commodity prices during the first quarter of
2009 and the program was not ramped back up until after spring break-up.
Average Daily Production Volumes
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Oil (bbl/d) 9,467 9,989 9,725 10,176
Natural gas (Mcf/d) 69,706 70,425 68,778 68,847
NGLs (bbl/d) 2,334 2,081 2,244 2,083
Oil equivalent (boe/d) 23,418 23,808 23,433 23,733
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil equivalent volumes of 23,418 boe/d for the third quarter of 2009 and 23,433
boe/d year-to-date include 370 boe/d (2008 - 379 boe/d) and 412 boe/d (2008 -
343 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 23,048 boe/d
for the third quarter of 2009 (2008 - 23,429 boe/d) and 23,021 boe/d (2008 -
23,390 boe/d) year-to-date.
Oil and natural gas liquids totaled 51 percent of production with natural gas at
49 percent during the first nine months of 2009.
Production Weighting
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Oil 40% 42% 41% 43%
Natural gas 50% 49% 49% 48%
NGLs 10% 9% 10% 9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales, after
transportation costs and prior to hedging, totaled $86.3 million for the three
months ended September 30, 2009, 51 percent lower than the third quarter of
2008. The decrease is due to a two percent decrease in production and a 50
percent decrease in the average realized price per boe, driven by a 41 percent
decrease in the realized crude oil price and a 63 percent decrease in the
realized natural gas price. The decrease in realized prices reflects lower West
Texas Intermediate ("WTI") prices, partially offset by a weaker Canadian dollar,
and lower AECO prices in the third quarter of 2009.
For the nine month period ended September 30, 2009, revenue after transportation
costs totaled $249.6 million, a decrease of 51 percent from the comparable
period in 2008. The decrease is attributable to a 50 percent decrease in the
average realized price per boe and a one percent decrease in production. The
decrease in realized price reflects lower WTI prices, partially offset by a
weaker Canadian dollar, and lower AECO prices in 2009.
Revenue
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue(1) ($000s)
Oil 58,543 104,949 154,024 297,894
Gas 19,718 53,152 73,834 165,392
NGLs 8,069 15,034 21,199 41,805
Sulphur (32) 2,313 553 2,907
----------------------------------------------------------------------------
Total revenue 86,298 175,448 249,610 507,998
$/boe 40.06 80.11 39.02 78.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior
to royalties and hedging.
OIL MARKETING
NAL markets its crude oil based on refiners' posted prices at Edmonton, Alberta
and Cromer, Manitoba adjusted for transportation and the quality of crude oil at
each field battery. The refiners' posted prices are influenced by the WTI
benchmark price, transportation costs, exchange rates and the supply/demand
situation of particular crude oil quality streams during the year.
NAL's third quarter average realized Canadian crude oil price per barrel, net of
transportation costs excluding hedging, was $67.22, as compared to $114.20 for
the comparable quarter of 2008. The decrease in realized price
quarter-over-quarter of 41 percent, or $46.98/bbl, was primarily driven by a 42
percent decrease in WTI (U.S.$/bbl) over the comparable period, partially offset
by a five percent decrease in the value of the Canadian dollar.
For the third quarter of 2009, NAL's crude oil price differential was 90
percent, a decrease of three percentage points from the comparable period in
2008. The differential is calculated as realized price as a percentage of WTI
stated in Canadian dollars. The decrease in 2009 resulted from a wider
differential between WTI and Edmonton/Cromer posted prices, due to lower demand
for light crude in western Canada during the third quarter.
For the nine months ended September 30, 2009, NAL's average oil price was $58.01
per barrel as compared to $106.84 for the comparable period in 2008. The 46
percent decrease in realized price was driven by a 50 percent decrease in WTI
(US$/bbl) and a decrease in crude oil differentials to 87 percent from 92
percent in 2008, partially offset by a 15 percent decrease in the value of the
Canadian dollar.
Natural gas liquids averaged $37.58/bbl in the third quarter of 2009, a 52
percent decrease from the $78.53/bbl realized in 2008. For the nine months ended
September 30, 2009, natural gas liquids averaged $34.60/bbl, a decrease of 53
percent from the comparable period in 2008.
NATURAL GAS MARKETING
Approximately 75 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 25 percent tied to NYMEX or other indexed reference prices.
For the three months ended September 30, 2009, the Trust's natural gas sales
averaged $3.07/Mcf compared to $8.20/Mcf in the comparable period of 2008, a
decrease of 63 percent. The quarter-over-quarter decrease in gas prices was
attributable to a 61 percent decrease in the benchmark AECO daily spot prices.
Prices for Lake Erie natural gas decreased to $3.77/Mcf in the third quarter of
2009, compared to $9.98/Mcf in 2008, a decrease of 62 percent. Lake Erie
production of 3.5 mmcf/d accounted for five percent of the Trust's natural gas
production in the third quarter of 2009, the same percentage experienced during
the comparable period of 2008. Natural gas sales from the Lake Erie property
generally receive a higher price due to the proximity of the Ontario and
Northeastern U.S. markets.
For the nine months ended September 30, 2009, NAL averaged $3.93/Mcf, a 55
percent decrease from the $8.77/Mcf realized in the comparable period of 2008.
The decrease in natural gas prices was attributable to a 56 percent decrease in
the benchmark AECO daily spot prices.
Average Pricing
(net of transportation charges)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 68.30 117.98 57.00 113.29
NAL average oil (Cdn$/bbl) 67.22 114.20 58.01 106.84
NAL natural gas liquids (Cdn$/bbl) 37.58 78.53 34.60 73.25
Natural Gas (Cdn$/mcf)
AECO - daily spot 2.98 7.73 3.78 8.64
AECO - monthly 3.02 9.25 4.11 8.55
NAL Western Canada natural gas 3.04 8.11 3.88 8.68
NAL Lake Erie natural gas 3.77 9.98 5.05 10.44
NAL average natural gas 3.07 8.20 3.93 8.77
NAL oil equivalent before hedging
(Cdn$/boe - 6:1) 40.06 80.11 39.02 78.12
Average foreign exchange rate
(Cdn$/US$) 1.0974 1.0418 1.1698 1.0186
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 to hedge up to
60 percent of forecasted total production, net of royalties. This was increased
from 50 percent to 60 percent at the November 3, 2009 Board meeting.
Management's practice is to hedge more near-term volumes on a six 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 September 30, 2009, NAL had several financial WTI oil contracts
and AECO natural gas contracts in place.
NAL's interest rate hedging policy currently provides authorization to hedge up
to 50 percent of outstanding debt for periods of up to five years. As at
September 30, 2009, 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 the Trust's U.S. dollar exposure for periods of up to 24
months. As at September 30, 2009, NAL had several exchange rate swaps
outstanding with a total notional value of U.S.$64.0 million.
All derivative contract counterparties are Canadian chartered banks in the
Trust's lending syndicate.
All derivative contracts are recorded on the balance sheet at fair value based
upon forward curves at September 30, 2009. Changes in the fair value of the
derivative contracts are recognized in net income for the period.
Fair value is calculated at a point in time based on an approximation of the
amounts that would be received or paid to settle these instruments, with
reference to forward prices at September 30, 2009. Accordingly, the magnitude of
the unrealized gain or loss will continue to fluctuate with changes in commodity
prices, interest rates and foreign exchange rates.
The fair value of the derivatives at September 30, 2009 was a net asset of $12.3
million, comprised of a $2.5 million asset on interest rate swaps, a $4.8
million asset on gas contracts and a $5.4 million asset on foreign exchange
contracts, partially offset by a $0.4 million liability on oil contracts.
Third quarter income for 2009 includes a $5.5 million unrealized loss on
derivatives resulting from the change in the fair value of the derivative
contracts during the quarter from an unrealized gain of $17.8 million at June
30, 2009, to an unrealized gain of $12.3 million at September 30, 2009. The $5.5
million unrealized loss was comprised of a $0.2 million unrealized loss on crude
oil contracts, an $8.2 million unrealized loss on natural gas contracts and a
$0.4 million unrealized loss on interest rate swaps, partially offset by a $3.3
million unrealized gain on foreign exchange swaps.
For the nine months ended September 30, 2009, income includes an unrealized loss
of $53.5 million, resulting from the change in the fair value of the derivative
contracts during the period, from an unrealized gain of $65.4 million at
December 31, 2008 and a $0.4 million unrealized gain acquired with Clipper, to
an unrealized gain of $12.3 million at September 30, 2009. The unrealized loss
was comprised of a $56.1 million unrealized loss on crude oil contracts and a
$5.6 million unrealized loss on natural gas contracts, partially offset by a
$2.8 million unrealized gain on interest rate swaps and a $5.4 million
unrealized gain on foreign exchange swaps.
The risk management policies for 2010 are expected to remain consistent with
2009. The Trust's current positions are summarized in the tables below.
The gain/loss on all forward derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts (184) 70,892 (56,151) 13,236
Natural gas contracts (8,251) 40,161 (5,560) 5,134
Interest rate swaps (374) - 2,776 -
Exchange rate swaps 3,310 - 5,448 -
----------------------------------------------------------------------------
Unrealized gain (loss) (5,499) 111,053 (53,487) 18,370
Realized gain (loss):
Crude oil contracts 7,526 (13,119) 44,179 (38,151)
Natural gas contracts 8,331 (3,508) 19,794 (5,697)
Interest rate swaps (226) - (433) -
Exchange rate swaps 3,188 - 5,200 -
----------------------------------------------------------------------------
Realized gain (loss) 18,819 (16,627) 68,740 (43,848)
----------------------------------------------------------------------------
Gain (loss) on derivative
contracts 13,320 94,426 15,253 (25,478)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following is a summary of the realized gains and losses on risk
management contracts:
Realized Gain (Loss) on Derivative Contracts
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Commodity contracts:
Average crude volumes hedged (bbl/d) 4,733 5,100 4,362 4,712
Crude oil realized gain (loss)
($000s) 7,526 (13,119) 44,179 (38,151)
Gain (loss) per bbl hedged ($) 17.28 (27.96) 37.10 (29.55)
Average natural gas volumes hedged
(GJ/d) 23,130 30,000 20,850 26,735
Natural gas realized gain (loss)
($000s) 8,331 (3,508) 19,794 (5,697)
Gain (loss) per GJ hedged ($) 3.92 (1.27) 3.48 (0.78)
Average BOE hedged (boe/d) 8,387 9,839 7,656 8,936
Total realized commodity contracts
gain ($000s) 15,857 (16,627) 63,973 (43,848)
Gain (loss) per boe hedged ($) 20.55 (18.37) 30.61 (17.91)
Gain (loss) per boe ($) 7.36 (7.59) 10.00 (6.74)
Interest rate swaps realized loss
($000s) (226) - (433) -
Loss per boe ($) (0.10) - (0.07) -
Exchange rate swaps realized gain
($000s) 3,188 - 5,200 -
Gain per boe ($) 1.48 - 0.82 -
Total realized gain (loss) ($000s) 18,819 (16,627) 68,740 (43,848)
Gain (loss) per boe ($) 8.74 (7.59) 10.75 (6.74)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average hedged boes for the third quarter of 2009 were 8,387 as compared to
6,394 for the second quarter of 2009.
NAL has the following interest rate risk management contracts outstanding:
----------------------------------------------------------------------------
INTEREST Remaining Amount Trust Fixed Counterparty
RATE Term (Cdn$ MM)(1) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating Oct 2009 -
to fixed Dec 2011 $ 39.0 1.5864% CAD-BA-CDOR (3 months)
Swaps-floating Oct 2009 -
to fixed Jan 2013 $ 22.0 1.3850% CAD-BA-CDOR (3 months)
Swaps-floating Oct 2009 -
to fixed Jan 2014 $ 22.0 1.5100% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2013 $ 14.0 1.8500% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2013 $ 14.0 1.8750% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2014 $ 14.0 1.9300% CAD-BA-CDOR (3 months)
Swaps-floating Mar 2010 -
to fixed Mar 2014 $ 14.0 1.9850% CAD-BA-CDOR (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount
NAL has the following exchange rate risk management contracts outstanding:
----------------------------------------------------------------------------
EXCHANGE Remaining Amount Trust Fixed Counterparty
RATE Term (US$ MM)(1) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating Oct 2009 -
to fixed Nov 2009 $ 4.0 1.2730 BofC Average Noon Rate
Swaps-floating Oct 2009 -
to fixed Nov 2009 $ 4.0 1.2875 BofC Average Noon Rate
Swaps-floating Oct 2009 -
to fixed Nov 2009 $ 4.0 1.2625 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1583 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1100 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1200 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1225 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1300 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1420 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1525 BofC Average Noon Rate
Swaps-floating Dec 2009 -
to fixed Dec 2010 $ 6.5 1.1000 BofC Average Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional US$ denominated commodity sales
NAL has the following commodity risk management contracts outstanding:
CRUDE OIL Q4-09 Q1-10 Q2-10 Q3-10 Q4-10
----------------------------------------------------------------------------
US$ Collar Contracts
---------------------
$US WTI Collar Volume (bbl/d) 300 3,500 3,300 2,600 2,400
Bought Puts - Average Strike
Price ($US/bbl) $ 62.67 $ 61.86 $ 62.27 $ 64.90 $ 65.10
Sold Calls - Average Strike
Price ($US/bbl) $ 71.85 $ 72.90 $ 73.23 $ 76.42 $ 76.88
US$ Swap Contracts
-------------------
$US WTI Swap Volume (bbl/d) 1,700 700 1,200 - -
Average WTI Swap Price
($US/bbl) $ 61.94 $ 75.36 $ 75.67 - -
Cdn$ Collar Contracts
----------------------
$Cdn WTI Collar Volume
(bbl/d) 1,500 300 - - -
Bought Puts - Average
Strike Price ($Cdn/bbl) $ 102.07 $ 66.00 - - -
Sold Calls - Average
Strike Price ($Cdn/bbl) $ 137.63 $ 80.17 - - -
Cdn$ Swap Contracts
--------------------
$Cdn WTI Swap Volume (bbl/d) 1,300 - - - -
Average WTI Swap Price
($Cdn/bbl) $ 92.55 - - - -
Total Oil Volume (bbl/d) 4,800 4,500 4,500 2,600 2,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS Q4-09 Q1-10 Q2-10 Q3-10 Q4-10
----------------------------------------------------------------------------
Collar Contracts
-----------------
AECO Collar Volume (GJ/d) 1,685 - - - -
Bought Puts - AECO Average
Strike Price ($Cdn/GJ) $ 8.90 - - - -
Sold Calls - AECO Average
Strike Price ($Cdn/GJ) $ 11.44 - - - -
Swap Contracts
---------------
AECO Swap Volume (GJ/d) 32,663 30,000 30,000 31,000 14,337
AECO Average Price ($Cdn/GJ) $ 5.57 $ 5.86 $ 5.60 $ 5.62 $ 5.67
Total Natural Gas Volume
(GJ/d) 34,348 30,000 30,000 31,000 14,337
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the remainder of 2009, the Trust has outstanding contracts representing
approximately 49 percent of its net liquids and natural gas production after
royalties, assuming a royalty rate of 17.5 percent.
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $15.0 million for the three months
ended September 30, 2009. Expressed as a percentage of gross sales net of
transportation costs, before gain/loss on derivative contracts, the net royalty
rate was 17.3 percent for the quarter ended September 30, 2009, a decrease from
the 21.1 percent experienced in the same period of the previous year.
Royalties decreased to $6.94 per boe for the third quarter of 2009, a decrease
of 59 percent compared to the third quarter of 2008. The decrease is
attributable to lower commodity prices on a quarter-over-quarter basis.
On a year-to-date basis, royalties were $44.7 million, down from $105.3 million
in the comparable period of 2008. Expressed as a percentage of gross sales net
of transportation costs, before gain/loss on derivative contracts, the net
royalty rate was 17.9 percent as compared to 20.7 percent in the comparable
period of 2008.
On January 1, 2009, the new royalty framework for Alberta became effective. This
new framework, first announced on October 25, 2007, provides for conventional
oil and gas royalties calculated on a sliding scale that is determined by
commodity price and production volumes. Natural gas royalty rates have increased
from 35 percent to 50 percent, with rates capped at $16.59/GJ. Crude oil royalty
rates have increased from 35 percent to 50 percent, with rates capped at
$120/bbl.
In response to the economic downturn, on November 19, 2008 the Government of
Alberta announced special transitional rates for some conventional oil and gas
wells. The lower transitional rates apply to newly drilled oil and gas wells at
depths between 1,000 and 3,500 metres.
On March 3, 2009, the Government of Alberta announced a new three point
incentive program for the energy sector. Firstly, there is a drilling royalty
credit for new conventional oil and natural gas wells. The credit is on a
sliding scale, based on prior year production levels, to a maximum of $200 per
metre drilled or 50 percent of the royalties owed. Secondly, there is a new well
incentive program that provides for a maximum five per cent royalty rate for the
first 12 months of production up to a maximum of 50,000 barrels of oil or 500
million cubic feet of natural gas. The 12 month period starts on the date of
production provided it occurs between April 1, 2009 and March 31, 2010. Thirdly,
the province will invest $30 million in a fund committed to abandoning and
reclaiming old well sites, to encourage the clean up of inactive oil and gas
wells. On June 25, 2009, the Government of Alberta announced a one year
extension to the drilling royalty credit and new well incentive program to March
31, 2011. The five percent royalty rate incentive is reported within royalties
and the $200 per metre drilling credit is reported against capital.
For the nine months ended September 30, 2009, 29 percent of crude oil and 70
percent of natural gas production is from Alberta.
Royalty Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Royalties ($000s) 14,950 37,015 44,692 105,267
As % of revenue 17.3 21.1 17.9 20.7
$/boe 6.94 16.90 6.99 16.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING COSTS
Operating costs averaged $10.52 per boe for the quarter ended September 30,
2009, a ten percent decrease from $11.63 per boe for the quarter ended September
30, 2008. Year-over-year operating cost decreases are a direct result of an
aggressive program focused on cost reduction in NAL's operations. Reduced power
costs as a result of significantly lower natural gas prices have also been a
large contributor to lower costs in 2009.
On a year-to-date basis, operating costs were $11.42 per boe compared to $10.64
per boe in 2008. The Trust expects costs to continue to moderate with full year
operating costs anticipated to be in the range of $11.30 - $11.60 per boe.
Operating Costs
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Operating costs ($000s) 22,657 25,463 73,056 69,179
As a % of revenue 26.3 14.51 29.3 13.62
$/boe 10.52 11.63 11.42 10.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OTHER INCOME
Other income was $0.11 per boe for the third quarter of 2009 compared to $0.53
per boe in the comparable quarter of 2008. Other income includes gas processing
fees, blending income, other miscellaneous income and fees and interest income
and interest expense on notes due from and to MFC (see "Related Party
Transactions"). The note receivable from MFC was settled in the first quarter of
2009, resulting in interest expense on the note payable in the third quarter of
2009 of $0.1 million, as compared to net interest income of $0.9 million in the
third quarter of 2008.
On a year-to-date basis interest on notes totaled $0.3 million compared to $2.1
million for the comparable period of 2008, the decrease being attributable to
the MFC note repayment in March 2009.
Other Income
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest on notes with MFC ($000s) (125) 890 289 2,109
Other ($000s) 370 255 1,099 1,224
----------------------------------------------------------------------------
Total other income ($000s) 245 1,145 1,388 3,333
As a % of revenue 0.28 0.65 0.55 0.66
Interest on notes with MFC ($/boe) (0.06) 0.41 0.05 0.32
Other ($/boe) 0.17 0.12 0.17 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total other income ($/boe) 0.11 0.53 0.22 0.51
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended September 30, 2009, NAL's operating netback, before
hedging gains, was $22.77 per boe, a decrease of 56 percent from $51.70 per boe
for the quarter ended September 30, 2008. The decrease was due to lower revenues
as a result of lower commodity prices, partially offset by decreased royalty
expense and operating costs. Hedging gains, related to commodity and exchange
rate derivative contracts, were $8.84 per boe in the third quarter of 2009, as
compared to a loss of $7.59 per boe in 2008, attributable mainly to lower
realized commodity prices in 2009.
On a year-to-date basis, NAL's operating netback, before hedging gains, was
$20.78 per boe compared to $51.48 per boe in 2008. The decrease was due to lower
revenue as a result of lower commodity prices, and slightly higher operating
costs, partially offset by lower royalty expense. Hedging gains, related to
commodity and exchange rate derivative contracts, were $10.82 for the nine
months ended September 30, 2009, as compared to a loss of $6.74 per boe in 2008,
attributable mainly to lower realized commodity prices in 2009.
Operating Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue 40.06 80.11 39.02 78.12
Royalties (6.94) (16.90) (6.99) (16.19)
Operating expenses (10.52) (11.63) (11.42) (10.64)
Other income(1) 0.17 0.12 0.17 0.19
----------------------------------------
Operating netback, before hedging 22.77 51.70 20.78 51.48
Hedging gains (losses)(2) 8.84 (7.59) 10.82 (6.74)
----------------------------------------
Operating netback, after hedging 31.61 44.11 31.60 44.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 September 30, 2009, G&A expenses were $4.1 million,
compared with $3.8 million in the comparable quarter of 2008. In addition, $1.3
million of G&A costs relating to exploitation and development activities were
capitalized in the third quarter of 2009, compared with $0.8 million in the
third quarter of 2008. G&A expense per boe was $1.90 in the quarter, as compared
to $1.72 for the same period in 2008.
For the nine months ended September 30, 2009, G&A expenses decreased eight
percent to $10.8 million from $11.7 million in the comparable period in 2008. 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 $3.2
million in the comparable period of 2008. G&A expense per boe was $1.68 in 2009
as compared to $1.79 in 2008.
Total G&A is comparable year-over-year at $15.0 million for the nine months
ended September 30, 2009 compared to $14.8 million for the same period in 2008.
General and Administrative Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
G&A expenses ($000s)
G&A 4,095 3,792 10,753 11,547
Retention bonus - (35) - 106
----------------------------------------------------------------------------
Expensed G&A ($000s) 4,095 3,757 10,753 11,653
Capitalized G&A ($000s) 1,266 824 4,260 3,167
----------------------------------------------------------------------------
Total G&A ($000s) 5,361 4,581 15,013 14,820
Expensed G&A costs:
G&A, excluding retention bonus
($/boe) 1.90 1.73 1.68 1.77
Retention bonus ($/boe) - (0.01) - 0.02
----------------------------------------------------------------------------
Total G&A expenses ($/boe) 1.90 1.72 1.68 1.79
As % of revenue 4.7 2.1 4.3 2.3
Per trust unit ($) 0.04 0.04 0.10 0.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 receiving cash compensation based upon
the value and overall return of a specified number of notional trust units. 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 units on the date of
distribution. Upon vesting, the employee is entitled to a cash payout based on
the trust unit price at the date of vesting of the units held. In addition, the
PTUs have a performance multiplier which is based on the Trust's performance
relative to its peers and may range from zero to two times the market value of
the notional trust units held at vesting.
During the third quarter of 2009, the Trust recorded a $5.3 million charge for
unit-based incentive compensation that reflects the impact of vesting and
increase in the unit price. The unit price of the Trust increased by 36 percent,
from $9.37 at June 30, 2009 to $12.70 at September 30, 2009. An increase in unit
price results in previously accrued amounts being increased.
Unit-based incentive compensation increased from a recovery of $0.9 million in
the third quarter of 2008 to a charge of $5.3 million in 2009. This increase is
a reflection of the increase in unit price used to determine the compensation
during the third quarter of 2009, as compared to a decline in unit price during
the third quarter of 2008 (from $16.89 at June 30, 2008 to $12.53 at September
30, 2008). A decrease in unit price results in previously accrued amounts being
reversed.
On a year-to-date basis, the Trust has accrued $9.7 million compared to $4.0
million in the comparable period of 2008. The increase period-over-period is
mainly attributable to a 58 percent increase in unit price during 2009 as
compared to an eight percent increase in unit price during 2008.
At September 30, 2009, the unit price used to determine unit-based incentive
compensation was $12.70. The closing unit price of the Trust on the Toronto
Stock Exchange on November 2, 2009 was $11.27.
The calculation of unit-based compensation expense is made at the end of each
quarter based on the quarter end trust unit price and estimated performance
factors. The compensation charges relating to the units granted are recognized
over the vesting period based on the trust unit price, number of RTUs and PTUs
outstanding, and the expected performance multiplier. As a result, the expense
recorded in the accounts will fluctuate in each quarter and over time.
At September 30, 2009, the Trust has recorded a total accumulated liability for
unit-based incentive compensation in the amount of $13.6 million, of which $7.0
million is recorded as current as it is payable in December 2009, and $6.6
million is long-term as it is payable in December 2010 and December 2011.
Unit-Based Compensation
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Unit-based compensation ($000s):
Expensed 3,805 (561) 6,865 2,816
Capitalized 1,484 (338) 2,814 1,152
----------------------------------------------------------------------------
Total unit-based compensation 5,289 (899) 9,679 3,968
Expensed unit-based compensation:
As % of revenue 4.4 (0.3) 2.8 0.6
$/boe 1.77 (0.26) 1.07 0.43
Per trust unit ($) 0.03 (0.01) 0.07 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 (the
"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 $3.4 million (2008 - $3.1 million) for the reimbursement of G&A
expenses during the third quarter and $8.7 million (2008 - $9.6 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 $2.3 million was paid in the first quarter of 2009,
representing units that vested on November 30, 2008 (2008 - $1.8 million). These
reimbursements are included in the G&A and unit-based compensation amounts
discussed above.
At September 30, 2009 the Trust owed the Manager $1.8 million for the
reimbursement of G&A and had a receivable from NAL Resources of $2.8 million,
$1.7 million relating to net operating revenues less capital expenditures and
$1.1 million relating to the base price adjustment clauses, arising from the
disposition of 50 percent of the working interest of Clipper and 40 percent of
the working interest of Spearpoint to MFC.
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. 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 over the Partnership as described below.
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 note receivable bore interest at prime plus
three percent. The Partnership then paid an equal distribution of $49.6 million
to MFC. This resulted in a $49.6 million reduction to the non-controlling
interest on the balance sheet.
As at September 30, 2009, there is a note payable of $9.2 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 these notes of $0.1 million was payable by the Trust for
the third quarter of 2009 (2008 - $0.9 million net interest income), and net
interest income of $0.3 million, year-to-date (2008 - $2.1 million), was
received by the Trust, and is reported as other income.
INTEREST
Interest on bank debt includes charges on borrowings, plus standby fees on the
unused portion of the bank credit facility. Interest on bank debt for the third
quarter of 2009 was $2.8 million, a decrease of $0.5 million from $3.3 million
for the comparable period in 2008. The decrease was due to a lower average
effective interest rate and lower average debt levels. Average outstanding bank
debt for the third quarter of 2009 was $248.4 million, $46.3 million lower than
the $294.7 million outstanding during the third quarter of 2008. NAL's effective
interest rate averaged 4.41 percent during the third quarter of 2009, compared
to 4.44 percent during the comparable period in 2008. The decrease in the rate
from the third quarter of 2008 is attributable to lower overall borrowing rates
in the market. NAL's interest is calculated based upon a floating rate.
Similar trends are noted for the nine months ended September 30, 2009, as
interest on bank debt decreased $3.5 million to $7.7 million, compared to $11.2
million in 2008. Average outstanding debt for the nine months ended September
30, 2009 decreased to $279.4 million compared to $301.3 million for the
corresponding period of 2008. In addition, the effective interest rate averaged
3.68 percent in 2009 compared to 4.88 percent in 2008.
Interest on convertible debentures represents interest charges of $1.7 million
for the three months ended September 30, 2009 ($5.2 million for the nine months
ended September 30, 2009) compared to $1.7 million ($6.0 million for the nine
months ended September 30, 2008), based on interest at 6.75 percent, and
accretion of the debt discount of $0.4 million (2008 - $0.3 million) for the
three months ended September 30, 2009, and $1.1 million (2008 - $1.3 million)
for the nine months ended September 30, 2009. The decrease in interest and
accretion in 2009 is due to conversions of debentures to trust units that
occurred during 2008.
Interest and Debt
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest on bank debt ($000s)(1) 2,761 3,295 7,686 11,155
Interest and accretion on
convertible debentures ($000s) 1,727 1,739 5,176 5,952
----------------------------------------------------------------------------
Total interest ($000) 4,488 5,034 12,862 17,107
Bank debt outstanding at period end
($000s) 246,892 270,982 246,892 270,982
Convertible debentures at period end
($000s)(2) 75,144 73,628 75,144 73,628
$/boe:
Interest on bank debt 1.28 1.50 1.20 1.72
Interest on convertible debentures 0.62 0.62 0.63 0.71
Accretion on convertible debentures 0.18 0.17 0.18 0.21
----------------------------------------------------------------------------
Total interest 2.08 2.29 2.01 2.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes interest rate hedge impact.
(2) Debt component of the debentures, as reported on the balance sheet.
CASH FLOW NETBACK
For the quarter ended September 30, 2009, NAL's cash flow netback was $25.88 per
boe, a 37 percent decrease from $40.94 per boe for the comparable period in
2008. The decrease was due to a lower operating netback after hedging, higher
G&A expenses, including unit-based incentive compensation and the swing from
interest income to interest expense on the notes with MFC, partially offset by
lower interest charges.
For the nine months ended September 30, 2009, NAL's cash flow netback was $27.00
per boe, a 33 percent decrease from $40.41 per boe in 2008. The decrease was due
to a lower operating netback after hedging, lower interest income on the notes
with MFC and higher G&A expenses, including unit-based incentive compensation,
offset by lower interest charges.
Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Operating netback, after hedging 31.61 44.11 31.60 44.74
G&A expenses, including unit-based
incentive compensation (3.67) (1.46) (2.75) (2.22)
Interest on bank debt and
convertible debentures(1) (1.90) (2.12) (1.83) (2.43)
Interest on notes with MFC(2) (0.06) 0.41 0.05 0.32
Realized loss on interest rate
derivative contracts (0.10) - (0.07) -
----------------------------------------------------------------------------
Cash flow netback 25.88 40.94 27.00 40.41
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.
(2) Reported as other income.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATIONS ("DDA")
Depletion of oil and natural gas properties, including the capitalized portion
of the asset retirement obligations, and depreciation of equipment is provided
for on a unit-of-production basis using estimated proved reserves volumes.
For the quarter ended September 30, 2009, depletion on property, plant and
equipment and accretion on the asset retirement obligations was $22.38 per boe,
six percent lower than the $23.71 per boe for the same period in 2008. The
decrease in depletion rate per boe in 2009 reflects an increase in proved
reserves volumes and a decrease in the related cost base, year-over-year.
Similar trends are noted for the nine months ended September 30, 2009.
The DDA rate will fluctuate period-over-period depending on the amount and type
of capital expenditures and the amount of reserves added.
Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 46,209 50,092 132,196 143,151
Accretion of asset retirement
obligation ($000s) 2,003 1,833 5,717 5,458
----------------------------------------------------------------------------
Total DDA ($000s) 48,212 51,925 137,913 148,609
DDA rate per boe ($) 22.38 23.71 21.56 22.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TAXES
In the third quarter of 2009, NAL had a future income tax recovery of $7.4
million compared to a $27.5 million expense in the corresponding period of the
prior year. For the nine month period ended September 30, 2009, NAL had a future
income tax recovery of $25.8 million compared to an $8.1 million expense in
2008.
The Trust is a taxable entity and files a trust income tax return annually. The
Trust's taxable income consists of royalty income, distributions from a
subsidiary trust and interest and dividends from other subsidiaries, less
deductions for the Trust's G&A expenses, Canadian Oil and Gas Property Expense
("COGPE"), and issue costs. In addition, Canadian Exploration Expense ("CEE"),
Canadian Development Expense ("CDE") and Undepreciated Capital Cost ("UCC") are
incurred and deducted by the Trust's subsidiaries. The Trust is taxable only on
remaining income, if any, that is not distributed to unitholders.
As at September 30, 2009, the Trust's (including all subsidiaries) estimated tax
pools (unaudited) available for deduction from future taxable income
approximated $964.1 million, of which approximately 35 percent represented COGPE
and 22 percent represented UCC, with the remaining balance represented by CEE,
CDE, trust unit issue costs and non-capital loss carry forwards.
Estimated Tax Pools ($ millions)
----------------------------------------------------------------------------
September 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Canadian exploration expense 44 12
Canadian development expense 270 202
Canadian oil and gas property expense 339 301
Undepreciated capital costs 212 209
Other (including loss carry forwards) 99 14
----------------------------------------------------------------------------
Total estimated tax pools 964 738
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Based on current strip prices at September 30, 2009, the Trust is not expected
to be taxable in 2009.
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 that in the original legislation.
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 operations attributable to the Tiberius and Spear assets were as
follows:
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------------------------------------------
($000s) Net Impact to Net Impact to
2009(1) Trust(2) 2009(1) the Trust(2)
----------------------------------------------------------------------------
Total production volumes
(boes) 68,042 34,021 224,558 112,279
Production volumes (boe/d) 740 370 823 412
Oil, natural gas and liquid
sales 4,230 2,115 12,367 6,184
Royalties (463) (232) (1,540) (770)
Operating costs (569) (284) (2,993) (1,496)
General and administrative (79) (40) (240) (120)
Unit-based incentive
compensation (114) (57) (216) (108)
Interest income (expense),
net (250) (125) 580 290
Depletion, depreciation and
accretion (1,125) (562) (3,337) (1,669)
Net profit interest expense (1,471) (736) (3,046) (1,523)
----------------------------------------------------------------------------
Net income 159 79 1,575 788
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Total results of the Partnership consolidated into the results of the
Trust
(2) Net impact to the Trust, removing 50 percent of results attributable to
MFC
The non-controlling interest presented in the statement of income has two
components: the royalty paid to MFC under the NPI, being a cash payment to the
royalty holder, and 50 percent of net income remaining in the Partnership, after
NPI expense, attributable to MFC. This share of net income attributable to MFC
is a non-cash item.
The non-controlling interest in the consolidated statement of income is
comprised of:
Non-Controlling Interest ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Net profits interest expense 736 2,010 1,523 7,071
Share of net income attributable to
MFC 80 1,151 788 2,107
----------------------------------------------------------------------------
816 3,161 2,311 9,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 third quarter of 2009 was $8.2 million compared to $111.0
million for the comparable period in 2008. The decrease of $102.8 million was
mainly due to decreased gains on derivative contracts ($81.1 million), decreased
revenues net of royalties ($67.0 million) and increased unit-based compensation
($4.4 million), partially offset by decreased operating costs ($2.8 million),
lower depletion (3.9 million), a future income tax recovery ($34.9 million) and
no bad debt expense in 2009 ($6.9 million).
Net income for the nine months ended September 30, 2009 of $3.6 million was
$103.6 million less than the net income of the comparable period of 2008. The
decrease in 2009 is attributable to decreased revenues net of royalties ($197.6
million), increased operating costs ($3.9 million) and increased unit-based
compensation $(4.0 million), partly offset by increased gains on derivative
contracts ($40.7 million), decreased future income taxes ($33.9 million),
decreased DDA expense ($11.0 million), decreased interest expense ($4.2 million)
and no bad debt expense in 2009 ($6.9 million).
Net Income ($000s)
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Net Income 8,249 111,045 3,566 107,206
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of trust units, bank debt and
convertible debentures.
As at September 30, 2009, NAL had 112,327,078 trust units outstanding, compared
with 96,181,397 as at December 31, 2008. The increase from December 31, 2008 is
attributable to 5,675,834 units issued on the acquisition of Clipper, 9,602,500
issued under an equity offering and 867,347 units issued under the Trust's
distribution reinvestment program ("DRIP").
On May 28, 2009, the Trust closed an equity offering of 9,602,500 trust units at
a price of $9.00 per trust unit for total gross proceeds of $86.4 million, which
included the exercise in full of the over-allotment option granted to the
underwriters as part of the offering.
Under the DRIP, unitholders may elect to reinvest distributions or make optional
cash payments to acquire trust units from treasury under the DRIP at 95 percent
of the average market price with no additional fees or commissions. The
operation of the DRIP was reinstated effective with the March distribution
payable on April 15, 2009, following suspension of the program in October 2008.
Participation in the DRIP has averaged 13.6 percent since reinstatement.
The premium distribution reinvestment plan ("Premium DRIP") allows unitholders
to exchange such units for a cash payment, from the plan broker, equal to 102
percent of the monthly distribution. The Premium DRIP program has been suspended
since March 10, 2006.
As at September 30, 2009, the Trust had net debt of $373.4 million (net of
working capital and other liabilities, excluding derivative contracts, note
payable with MFC and future income taxes) including the convertible debentures
at face value of $79.7 million. Excluding the convertible debentures, net debt
was $293.7 million, compared with $319.9 million at December 31, 2008. The
decrease in net debt, excluding convertible debentures, of $26.2 million during
2009 is attributable to decreased bank debt of $35.4 million, offset by a
negative change in working capital of $9.2 million.
Bank debt outstanding was $246.9 million at September 30, 2009 compared with
$282.3 million as at December 31, 2008. Of the $246.9 million outstanding at
September 30, 2009, all is outstanding under the production facility.
At the end of the third quarter, the Trust had a net debt (excluding convertible
debentures) to 12 months trailing cash flow ratio of 1.25 times and a total net
debt (including convertible debentures) to 12 months trailing cash flow ratio of
1.59 times.
During the second quarter, the Trust renewed its credit facility at the
previously approved amount of $450 million. The credit facility is a fully
secured, extendible, revolving facility and will revolve until April 28, 2010 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
$440 million production facility and a $10 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 April 29, 2011.
The Trust has outstanding $79.7 million principal amount of 6.75% convertible
extendible unsecured subordinated debentures. Interest on the 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 of $4
million. 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 $0.4 million (2008 - $0.3 million) of accretion of the debt
discount in the third quarter of 2009 and $1.1 million (2008 - $1.3 million)
year-to-date.
As at November 2, 2009, the Trust has 112,456,063 trust units and $79.7 million
in convertible debentures outstanding.
Capitalization
----------------------------------------------------------------------------
Sept. 30, Dec. 31, Sept. 30,
2009 2008 2008
----------------------------------------------------------------------------
Trust unit equity ($000s) 600,404 557,263 545,551
Bank debt ($000s) 246,892 282,332 270,982
Working capital deficit
(surplus)(1) ($000s) 46,788 37,602 32,348
----------------------------------------------------------------------------
Net debt excluding convertible
debentures ($000s) 293,680 319,934 303,330
Convertible debentures ($000s)(2) 79,744 79,744 79,744
----------------------------------------------------------------------------
Net debt ($000s) 373,424 399,678 383,074
Net debt excluding convertible
debentures to trailing 12-month
cash flow(3) 1.25 1.03 1.00
Total net debt to trailing 12-month
cash flow(3) 1.59 1.28 1.26
Trust units outstanding (000s) 112,327 96,181 95,945
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 current economic slowdown, reduced availability of credit, and challenging
equity markets have resulted in the Trust setting its objective for 2009 to
operating within forecasted funds from operations and targeting an annual total
payout ratio of not more than 110 percent (distributions plus capital
expenditures). 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 $450 million of which $247 million is drawn down at
September 30, 2009, leaving available capacity of $203 million.
On March 11, 2009, the Trust announced a reduction in distributions from $0.11
per unit to $0.09 per unit commencing with the distribution to be paid on April
15, 2009. This reduction was made in response to declining commodity prices,
taking into account the needs of the ongoing capital program and the maintenance
of a strong balance sheet.
For 2009, the Trust is benefiting from an active hedging program at prices above
current market levels. Currently, the Trust has in place oil hedges for
approximately 44 percent of net forecasted production (after royalty) for the
remaining three months of 2009. Volumes are hedged at an average floor price of
$85.14 per boe. For natural gas, remaining 2009 hedges total approximately 54
percent of net budgeted production volumes hedged at an average floor price in
excess of $5.73 per GJ (or $6.04 per Mcf).
NAL's capital program for 2009 has been designed to be scalable and flexible in
response to commodity prices and market conditions. The initial plan for a $110
million capital program, with the expectation to drill approximately 82 (40 net)
wells, was reduced in February by $15 million in response to weaker commodity
prices. Based upon positive second quarter performance and the opportunities
added, the Trust increased its capital program to $125 - $135 million. The
Trust, through the Manager, operates over 90 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, other market factors and growth opportunities
may make it necessary to adjust planned capital expenditures or distribution
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 2009 and 2010, the
Trust has approximately $965.7 million of available safe harbour, excluding the
impact of the Breaker acquisition, all of which is currently available.
ASSET RETIREMENT OBLIGATION
At September 30, 2009, the Trust reported an asset retirement obligation ("ARO")
balance of $102.8 million ($90.8 million as at December 31, 2008) for future
abandonment and reclamation of the Trust's oil and gas properties and
facilities. The ARO balance was increased by $7.7 million in relation to the
acquisition of Clipper and Spearpoint, $1.7 million due to liabilities incurred
and revisions to estimates and $5.7 million from accretion expense, and was
reduced by $3.1 million for actual abandonment and environmental expenditures
incurred during the first nine months.
DISTRIBUTIONS TO UNITHOLDERS
For the three and nine months ended September 30, 2009, the Trust distributed 57
percent and 48 percent of its cash flow from operating activities, respectively,
as compared to 46 percent and 56 percent for the same periods in 2008. 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 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 2009, 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 2009 capital program may not fully replace
production. When the Trust sets distribution levels, depletion expense is not
considered to be an indicative measure for maintaining 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 the credit facility. However, given the current economic slowdown,
the Trust is targeting cash flow to be no more than 110 percent of distributions
and capital expenditures on an annual basis in order to preserve the Trust's
balance sheet. Fluctuations in commodity prices, other market factors and 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. 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 or continuing low commodity prices may impact cash
from operating activities, access to credit facilities and the Trust's ability
to fund operations and maintain distributions.
Distributions
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
($000s except for percentages) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash flow from operating activities 52,999 98,860 183,235 242,716
Net income 8,249 111,045 3,566 107,206
Actual cash distributions paid or
payable 30,290 45,968 87,528 135,295
Excess of cash flow from operating
activities over cash distribution
paid 22,709 52,892 95,707 107,421
Percentage of cash flow from
operations distributed 57% 46% 48% 56%
Excess (shortfall) of net income
over cash distributions paid (22,041) 65,077 (83,962) (28,089)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As stated in the non-GAAP measures section of the MD&A, NAL uses funds from
operations as a key performance indicator to measure the ability of the Trust to
generate cash from operations and to pay monthly distributions.
For the three months ended September 30, 2009, funds from operations amounted to
$53.8 million, compared with $79.2 million for the three months ended September
30, 2008. The 32 percent decrease is primarily due to lower revenues resulting
from lower commodity prices. On a per trust unit basis, funds from operations
decreased 42 percent from $0.83 in 2008 to $0.48 in 2009.
For the nine months ended September 30, 2009, funds from operations decreased 31
percent to $167.8 from $244.0 million for the comparable period of 2008. The
decrease is primarily due to lower revenues driven by lower commodity prices,
offset by realized hedging gains of $68.8 million.
Funds from Operations
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Funds from operations ($000s) 53,766 79,233 167,788 244,031
Funds from operations per trust unit 0.48 0.83 1.62 2.60
Payout ratio based on funds from
operations 56% 58% 52% 55%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
partnership agreement with a senior industry partner. The arrangement consists
of a three year commitment to spend $50 million to earn an interest in freehold
and crown acreage. The 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 earn an interest in over 150 sections (97.5 net) of freehold and
crown acreage. If the capital spending commitments are not met, interests in the
freehold and crown acreage will not be earned and the Trust will not be required
to pay unspent commitment amounts to the senior industry partner. As at
September 30, 2009, the Trust had spent $2.4 million under this arrangement.
Farm-in Agreement:
Effective August 10, 2009, the Trust and MFC entered into a Farm-in Agreement
with a senior industry partner. The arrangement consists of a two year initial
commitment, with a minimum capital commitment of $40 million in the first year
and $57 million in the second year, with an option for a third year, at NAL's
election, for an additional $50 million commitment. The 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 September 30, 2009, no amounts have been spent under this agreement.
Flow-through shares:
In conjunction with the acquisition of Clipper, the Trust assumed flow-through
share obligations related to common shares issued by Clipper on December 4,
2008. As a result, the Trust must incur qualifying resource expenditures
amounting to $7.5 million before December 31, 2009. The related tax impact was
recorded on the acquisition of Clipper. The qualifying expenditures were
renounced to shareholders of Clipper as at December 31, 2008. The obligation
remaining for this flow-through share issue was $2.6 million as at September 30,
2009.
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) 2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Office lease(1) 1,036 3,798 - - -
Office lease - Clipper(2) 173 692 699 703 234
Transportation agreement 680 1,317 1,317 306 -
Processing agreement(3) 84 428 414 401 384
Convertible debentures(4) - - - 79,744 -
Bank debt - - 148,135 98,757 -
----------------------------------------------------------------------------
Total 1,973 6,235 150,565 179,911 618
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 58 percent) of the expense on a monthly basis.
(2) Represents the full amount of the office lease assumed with the
acquisition of Clipper. MFC will reimburse the Trust for 50 percent of
the obligation under the base price adjustment clause (see "Acquisition
of Alberta Clipper Energy Inc.")
(3) Represents a gas processing agreement with a take or pay component.
(4) Principal amount.
QUARTERLY INFORMATION
2009 2008 2007
----------------------------------------------------------------------------
($000s, except
per unit and
production
amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Revenue,
net of
royalties(1) 85,988 60,922 77,791 161,156 234,993 58,861 89,611 86,262
Per unit 0.77 0.60 0.81 1.68 2.46 0.63 0.98 0.96
Funds from
operations(2) 53,766 51,998 62,024 67,040 79,233 88,578 76,220 59,537
Per unit 0.48 0.51 0.64 0.70 0.83 0.94 0.83 0.66
Net income
(loss) 8,249 (9,407) 4,724 55,374 111,045 (17,572) 13,733 10,556
Per unit
basic 0.07 (0.09) 0.05 0.58 1.16 (0.19) 0.15 0.12
diluted 0.07 (0.09) 0.05 0.56 1.11 (0.19) 0.15 0.12
Average oil
equivalent
production
(boe/d - 6:1) 23,418 23,049 23,836 23,984 23,808 23,791 23,601 23,656
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
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.
They have designed ICFR, or caused it to be designed under their supervision, to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with Canadian GAAP. The control framework the officers used to design NAL's ICFR
is the Internal Control - Integrated Framework published by the Committee of
Sponsoring Organizations of the Treadway Commission ("COSO").
While management believes that NAL's controls provide a reasonable level of
assurance with regard to their effectiveness, they do not expect that the DC&P
or ICFR will prevent all errors and fraud. A control system, no matter how well
conceived or operated, can provide only reasonable, but not absolute, assurance
that the objectives of the control system are met.
There were no material changes in the Trust's ICFR for the quarter ended
September 30, 2009.
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by NAL are disclosed in the notes to
NAL's December 31, 2008 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, 2008.
NEW ACCOUNTING STANDARDS
Goodwill and Intangible Assets
Effective January 1, 2009, the Trust implemented the provisions of CICA Handbook
Section 3064, "Goodwill and Intangible Assets". Section 3064 establishes
standards for the recognition, measurement, presentation and disclosure of
goodwill and intangible assets. Standards concerning goodwill are unchanged from
the previous standards, resulting in no impact to the consolidated financial
statements of the Trust from the implementation of this Section.
Financial Instruments - Disclosures
In May 2009, the CICA amended Section 3862, "Financial Instruments -
Disclosures", to include additional disclosure requirements about fair value
measurement for financial instruments and liquidity risk disclosures. These
amendments require a three level hierarchy that reflects the significance of the
inputs used in making the fair value measurements. Fair values of assets and
liabilities included in Level 1 are determined by reference to quoted prices in
active markets for identical assets and liabilities. Assets and liabilities in
Level 2 include valuations using inputs other than quoted prices for which all
significant outputs are observable, either directly or indirectly. Level 3
valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. These amendments became effective for NAL on
December 31, 2009.
FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards ("IFRS")
The Trust continues to prepare for the forthcoming conversion to IFRS. 2009
activities to date have concentrated on an in-depth review of the significant
Canadian GAAP differences and their related policy choices. Other areas being
addressed include the impacts on information systems, internal controls,
financial reporting, debt covenants and compensation arrangements. For further
details on the transition plan please refer to the annual MD&A.
Dated: November 3, 2009
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
September 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 5,004 $ 5,584
Accounts receivable and other 52,989 57,825
Note receivable (Note 3) - 49,599
Derivative contracts (Note 12) 10,835 65,680
----------------------------------------------------------------------------
68,828 178,688
Derivative contracts (Note 12) 5,508 -
Future income tax asset 7,721 -
Goodwill 14,722 14,722
Property, plant and equipment (Notes
2 and 4) 1,051,494 1,017,187
----------------------------------------------------------------------------
$1,148,273 $1,210,597
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued
liabilities $ 87,194 $ 84,732
Note payable (Note 3) 9,227 9,609
Distributions payable to unitholders 10,109 15,389
Future income tax liability 1,172 16,788
----------------------------------------------------------------------------
107,702 126,518
Bank debt (Note 5) 246,892 282,332
Convertible debentures (Note 6) 75,144 74,004
Derivative contracts (Note 12) 4,016 274
Other liabilities (Note 7) 7,478 890
Asset retirement obligations (Note 9) 102,771 90,844
Future income tax liability - 22,092
Non-controlling interest (Note 10) 3,866 56,380
----------------------------------------------------------------------------
547,869 653,334
Unitholders' equity
Unitholders' capital (Note 11) 1,169,286 1,042,183
Equity component of convertible
debentures (Note 6) 4,592 4,592
Deficit (Note 11) (573,474) (489,512)
----------------------------------------------------------------------------
600,404 557,263
----------------------------------------------------------------------------
$1,148,273 $1,210,597
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments (Note 13)
Subsequent event (Note 14)
Trust units outstanding (000s) 112,327 96,181
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue
Oil, natural gas and
liquid sales $ 87,373 $ 176,437 $ 252,752 $ 510,877
Crown royalties (9,563) (27,415) (30,917) (78,097)
Freehold and other royalties (5,387) (9,600) (13,775) (27,170)
----------------------------------------------------------------------------
72,423 139,422 208,060 405,610
Gain (loss) on derivative
contracts (Note 12):
Realized gain (loss) 18,819 (16,627) 68,740 (43,848)
Unrealized gain (loss) (5,499) 111,053 (53,487) 18,370
----------------------------------------------------------------------------
13,320 94,426 15,253 (25,478)
Other income 245 1,145 1,388 3,333
----------------------------------------------------------------------------
85,988 234,993 224,701 383,465
----------------------------------------------------------------------------
Expenses
Operating 22,657 25,463 73,056 69,179
Transportation 1,075 989 3,142 2,879
General and administrative 4,095 3,757 10,753 11,653
Unit-based incentive
compensation (Note 8) 3,805 (561) 6,865 2,816
Interest on bank debt 2,761 3,295 7,686 11,155
Interest and accretion on
convertible debentures 1,727 1,739 5,176 5,952
Bad debt expense - 6,901 - 6,901
Depletion, depreciation
and amortization 46,209 50,092 132,196 143,151
Accretion on asset
retirement obligations 2,003 1,833 5,717 5,458
----------------------------------------------------------------------------
84,332 93,508 244,591 259,144
----------------------------------------------------------------------------
Income (loss) before taxes
and non-controlling interest 1,656 141,485 (19,890) 124,321
Income tax recovery - 209 1 203
Future income tax
reduction
(expense) 7,409 (27,488) 25,766 (8,140)
----------------------------------------------------------------------------
Total income tax reduction
(expense) 7,409 (27,279) 25,767 (7,937)
----------------------------------------------------------------------------
Income before non-controlling
interest 9,065 114,206 5,877 116,384
Non-controlling interest
(Note 10) (816) (3,161) (2,311) (9,178)
----------------------------------------------------------------------------
Net income and comprehensive
income 8,249 111,045 3,566 107,206
----------------------------------------------------------------------------
Deficit, beginning of
period (551,433) (563,796) (489,512) (470,630)
Net income 8,249 111,045 3,566 107,206
Distributions declared (30,290) (45,968) (87,528) (135,295)
----------------------------------------------------------------------------
Deficit, end of period $(573,474) $ (498,719) $(573,474) $ (498,719)
----------------------------------------------------------------------------
Net income per trust unit
(Note 11)
Basic $ 0.07 $ 1.16 $ 0.03 $ 1.14
Diluted $ 0.07 $ 1.11 $ 0.03 $ 1.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average trust
units outstanding (000s) 112,109 95,664 103,444 93,834
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
Three months ended Nine months ended
Sept. 30 Sept. 30
----------------------------------------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Operating Activities
Net income $ 8,249 $ 111,045 $ 3,566 $ 107,206
Items not involving cash:
Depletion, depreciation and
amortization 46,209 50,092 132,196 143,151
Accretion on asset
retirement obligations 2,003 1,833 5,717 5,458
Unrealized loss (gain) on
derivative contracts 5,499 (111,053) 53,487 (18,370)
Future income tax
(reduction) expense (7,409) 27,488 (25,766) 8,140
Non-cash accretion expense
on convertible debentures 382 379 1,140 1,320
Non-controlling interest 80 1,151 788 2,107
Lease amortization (217) - (217) -
Abandonment and
environmental expenditures (1,030) (1,702) (3,123) (4,981)
Change in non-cash working
capital (767) 19,627 15,447 (1,315)
----------------------------------------------------------------------------
52,999 98,860 183,235 242,716
----------------------------------------------------------------------------
Financing Activities
Distributions paid to
unitholders (25,828) (38,918) (85,178) (113,550)
Increase (decrease) in bank
debt 2,569 (37,133) (114,292) (4,648)
Issue of trust units, net of
issue costs (424) - 81,593 (14)
Note repayment from MFC
(Note 3) - - 49,599 -
Partnership distribution
paid to MFC - (1,500) (53,302) (1,500)
Change in non-cash working
capital (5,697) - (5,615) (426)
----------------------------------------------------------------------------
(29,380) (77,551) (127,195) (120,138)
----------------------------------------------------------------------------
Investing Activities
Additions to property, plant
and equipment (42,376) (53,189) (96,264) (109,260)
Property acquisitions - (373) (2,799) (8,249)
Proceeds from dispositions - - 265 40
Acquisition of Clipper
(Note 2) (84) - (833) -
Disposition of Clipper
(Note 2) 645 - 53,302 -
Acquisition of Spearpoint
(Note 2) (9,749) - (9,749) -
Disposition of Spearpoint
(Note 2) 6,772 - 6,772 -
Acquisition of Tiberius and
Spear - (14) - (77,369)
Disposition of Tiberius and
Spear - - - 58,221
Acquisition of Seneca - - - 337
Change in non-cash working
capital 16,196 21,909 (7,314) 14,817
----------------------------------------------------------------------------
(28,596) (31,667) (56,620) (121,463)
----------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (4,977) (10,358) (580) 1,115
Cash and cash equivalents,
beginning of period 9,981 12,867 5,584 1,394
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 5,004 $ 2,509 $ 5,004 $ 2,509
----------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid (received) during
the period for:
Interest $ 4,883 $ 4,913 $ 14,161 $ 14,777
Tax $ (206) $ 2,202 $ (278) $ 6,905
----------------------------------------------------------------------------
Cash and cash equivalents is
comprised of:
Cash $ 5,004 $ 2,509 $ 5,004 $ 2,509
Short term investments - - - -
----------------------------------------------------------------------------
$ 5,004 $ 2,509 $ 5,004 $ 2,509
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Refer to Notes 2, 9 and 11 for significant non-cash amounts not included in
the cash flow statement.
See accompanying notes.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Nine months ended September 30, 2009
(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, 2008. 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, 2008.
Financial Instruments - Disclosures
In May 2009, the Canadian Institute of Chartered Accountants amended Section
3862, "Financial Instruments - Disclosures", to include additional disclosure
requirements about fair value measurement for financial instruments and
liquidity risk disclosures. These amendments require a three level hierarchy
that reflects the significance of the inputs used in making the fair value
measurements. Fair values of assets and liabilities included in Level 1 are
determined by reference to quoted prices in active markets for identical assets
and liabilities. Assets and liabilities in Level 2 include valuations using
inputs other than quoted prices for which all significant outputs are
observable, either directly or indirectly. Level 3 valuations are based on
inputs that are unobservable and significant to the overall fair value
measurement. These amendments became effective for NAL on December 31, 2009.
2) CORPORATE ACQUISITIONS
i) Alberta Clipper Energy Inc.
Effective June 1, 2009, the Trust acquired all of the issued and outstanding
common shares of Alberta Clipper Energy Inc. ("Clipper"), which has interests in
petroleum and natural gas properties and undeveloped land in Alberta and
northeast British Columbia.
As consideration the Trust issued 5.7 million trust units at a price of $6.45 a
trust unit for total consideration, before acquisition costs, of $36.6 million.
The trust unit price was based on the weighted average market price of trust
units at the date of announcement, being March 23, 2009. This purchase price
included the assumption of $78.9 million in bank debt.
The results of Clipper have been included in the accounts of the Trust from June
1, 2009. The transaction was accounted for using the purchase method of
accounting. The fair values assigned to the net assets, and the consideration
paid by the Trust, are as follows:
----------------------------------------------------------------------------
Net Assets acquired:
Working capital deficiency (including cash of $2) $ (1,886)
Derivative contract 408
Property, plant and equipment 115,945
Future income taxes 17,858
Excess office lease obligation(1) (1,446)
Asset retirement obligations (14,592)
Bank debt (78,852)
----------------------------------------------------------------------------
$ 37,435
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration:
Issuance of trust units $ 36,600
Acquisition costs 835
----------------------------------------------------------------------------
$ 37,435
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the present value of an office lease obligation, in excess of
the value of a sublease.
The above amounts are estimates made by management based on currently available
information. Amendments may be made to the purchase allocation as cost
estimates and balances are finalized.
Concurrent with the acquisition, the Trust entered into a Purchase and Sale
Agreement ("PSA") with Manulife Financial Corporation ("MFC"), pursuant to which
MFC acquired a 50% working interest in the Clipper petroleum and natural gas
properties for a cash base price of $52.5 million. The cash received from MFC
was used to partially repay the assumed bank debt.
Included within the PSA is a base price adjustment clause that ensures the Trust
and MFC share equally in all assets or liabilities related to Clipper that
pertain to periods on or prior to the effective date of the acquisition,
regardless of their date of discovery or disclosure. The base price adjustment
calculation will adjust the purchase price that MFC pays the Trust for any
change in working capital from amounts determined at the time the base price of
$52.5 million was established. In addition, the costs associated with contracts
outstanding at the date of acquisition will be equally shared between both
parties on an ongoing basis as the obligations are settled by the Trust. The
amounts due under this base price adjustment clause are to be settled no more
than quarterly commencing December 2009. As at September 30, 2009, the Trust
had a receivable from MFC of $0.8 million relating to the base price adjustment.
As a result, after taking into effect the MFC disposition and MFC's share of the
assets and liabilities to be settled under the base price adjustment clause, the
Trust acquired property, plant and equipment of $55.4 million, a derivative
contract of $0.4 million and a future tax asset of $17.9 million and assumed
asset retirement obligations of $7.3 million, bank debt of $26.4 million, a
working capital deficiency of $1.1 million and a lease obligation of $1.5
million, for consideration of $37.4 million, including estimated acquisition
costs.
ii) Spearpoint Energy Corp.
Effective August 10, 2009, the Trust acquired all of the issued and outstanding
common shares of Spearpoint Energy Corp. ("Spearpoint") for cash of $10.6
million, prior to acquisition costs. The fair values assigned to the net
assets, and the consideration paid by the Trust, are as follows:
----------------------------------------------------------------------------
Net Assets acquired:
Cash $ 1,201
Working capital deficiency (2,183)
Property, plant and equipment 17,792
Future income taxes 525
Asset retirement obligation (685)
Note payable (5,700)
----------------------------------------------------------------------------
$ 10,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration:
Cash $ 10,590
Acquisition costs 360
----------------------------------------------------------------------------
$ 10,950
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above amounts are estimates made by management based on currently available
information. Amendments may be made to the purchase allocation as cost
estimates and balances are finalized.
Concurrent with the acquisition, the Trust entered into a Purchase and Sale
Agreement (the "Spearpoint PSA") with MFC, pursuant to which MFC acquired a 40
percent working interest in all of the Spearpoint petroleum and natural gas
properties and the farm-in agreement for a base price of $6.5 million payable in
cash.
Included within the Spearpoint PSA is a base price adjustment clause that
ensures the Trust and MFC share 60 percent / 40 percent, respectively, in all
assets or liabilities related to Spearpoint that pertain to periods on or prior
to the effective date of the acquisition, regardless of their date of discovery
or disclosure. The base price adjustment calculation will adjust the purchase
price that MFC pays the Trust for any change in working capital from amounts
determined at the time the base price of $6.5 million was established. As at
September 30, 2009, the Trust had a receivable from MFC of $0.3 million relating
to these price adjustments.
As a result, after taking into effect the MFC disposition and MFC's share of the
assets and liabilities to be settled under the base price adjustment clause, the
Trust acquired property, plant and equipment of $10.7 million and a future
income tax asset of $0.5 million and assumed a note payable of $5.7 million,
asset retirement obligations of $0.4 million and a working capital deficiency of
$0.9 million, for consideration of $4.2 million.
3) RELATED PARTY TRANSACTIONS
The Trust is managed by NAL Resources Management Limited (the "Manager"). The
Manager is a wholly-owned subsidiary of MFC and also manages on their 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 $3.4 million
(2008 - $3.1 million) for the reimbursement of G&A expenses during the third
quarter and $8.7 million (2008 - $9.6 million) in the 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, $2.3 million has been paid year-to-date relating
to notional units that vested on November 30, 2008 (2008 - $1.8 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 note receivable bore interest at prime plus
three percent. 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 10).
As at September 30, 2009, there is a note payable of $9.2 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 these notes of $0.1 million was payable by the Trust for
the third quarter of 2009 (2008 - $0.9 million net interest income), and net
interest income of $0.3 million (2008 - $2.1 million) year-to-date was received
by the Trust and is reported as other income.
The following amounts are due to and from related parties as at September 30,
2009 and December 31, 2008 and have been included in accounts receivable, note
receivable, accounts payable and accrued liabilities and note payable on the
balance sheet:
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Due to NAL Resources Limited(1) $ 2,782 $ (10,042)
Due to NAL Resources Management Limited (1,776) (3,881)
Due (to) from Manulife Financial
Corporation(2) (9,979) 45,512
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ (8,973) $ 31,589
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes base price adjustment due (to) from MFC, relating to the
Clipper and Spearpoint asset dispositions to MFC, of $1.1 million
(Note 2).
(2) Included on consolidation, eliminated through non-controlling interest.
Represents note payable $9.2 million (2008 - $9.6 million), plus
amounts due from (to) MFC of ($0.8) million (2008 - $5.5 million),
presented in accounts payable/ accounts receivable, relating to the net
interest and NPI amounts due.
4. PROPERTY, PLANT AND EQUIPMENT
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Petroleum and natural gas properties,
at cost $ 2,076,027 $ 1,909,524
Less: Accumulated depletion and
depreciation (1,024,533) (892,337)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 1,051,494 $ 1,017,187
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Costs associated with undeveloped land and unproved properties of $46.8 million
(2008 - $34.3 million) have been excluded from the depletion calculation for the
nine months ended September 30, 2009.
Future development costs for proved reserves of $41.8 million (2008 - $49.8
million) have been included in the depletion calculation.
During the nine months ended September 30, 2009, the Trust capitalized $4.3
million (2008 - $3.2 million) of G&A costs and $2.8 million (2008 - $1.2
million) of unit-based incentive compensation that were directly related to
exploitation and development programs.
5. BANK DEBT
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Production loan facility $ 246,892 $ 281,984
Working capital facility - 348
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt outstanding $ 246,892 $ 282,332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $440 million production facility and a $10 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 28,
2010 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 2010, 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 April 29, 2011.
The Trust is restricted under the credit facility from making distributions to
its unitholders in excess of its consolidated operating cash flow during the 18
month period preceding the distribution date. The Trust is in compliance with
this covenant.
Amounts are advanced under the credit facility in Canadian dollars by way of
prime interest rate based loans and by issues of bankers' acceptances and in
U.S. dollars by way of U.S. based interest rate and Libor based loans. The
interest charged on advances is at the prevailing interest rate for bankers'
acceptances, Libor loans, lenders' prime or U.S. base rates plus an applicable
margin or stamping fee. The applicable margin or stamping fee, if any, varies
based on the consolidated debt-to-cash flow ratio of the Trust. As at September
30, 2009 and December 31, 2008 all amounts outstanding were in Canadian dollars.
On September 30, 2009 the effective interest rate on amounts outstanding under
the credit facility was 3.68 percent (2008 - 4.52 percent). The Trust's
interest charge includes this fixed interest rate component, plus a standby fee,
a stamping fee and the fee for renewal.
6. CONVERTIBLE DEBENTURES
The following table reconciles the principal amount, debt component and equity
component of the convertible debentures.
Debt Equity
Principal amount of component of component of
debentures debentures debentures
----------------------------------------------------------------------------
Balance, December 31, 2007 $ 100,000 $ 90,876 $ 5,759
Conversion to trust units (20,256) (18,568) (1,167)
Accretion - 1,696 -
----------------------------------------------------------------------------
Balance, December 31, 2008 $ 79,744 $ 74,004 $ 4,592
Accretion - 1,140 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, September 30, 2009 $ 79,744 $ 75,144 $ 4,592
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. OTHER LIABILITIES
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Unit-based incentive compensation $ 6,600 $ 890
Excess office lease obligation (Note 2)(1) 878 -
----------------------------------------------------------------------------
$ 7,478 $ 890
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Clipper. MFC will reimburse the Trust for 50 percent of the
obligation under the base price adjustment clause (Note 2).
8. UNIT-BASED INCENTIVE COMPENSATION PLAN
The Trust recorded a total compensation expense of $9.7 million in the first
nine months of 2009, of which $6.9 million was recorded as an expense and $2.8
million as property, plant and equipment ($1.8 million was expensed and $0.8
million recorded as property, plant and equipment for the year ended December
31, 2008). The compensation expense was based on the September 30, 2009 trust
unit price of $12.70 (December 31, 2008 - $8.05), accrued distributions,
performance factors and the number of units vesting on maturity.
The following table reconciles the change in total accrued trust unit-based
incentive compensation relating to the plan:
Nine months ended Year ended
Sept. 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of period $ 6,274 $ 5,311
Increase in liability 9,679 2,730
Cash payout, relating to units
vested (2,324) (1,767)
----------------------------------------------------------------------------
Balance, end of period $ 13,629 $ 6,274
----------------------------------------------------------------------------
Current portion of liability(1) $ 7,029 $ 5,384
----------------------------------------------------------------------------
Long-term liability(2) $ 6,600 $ 890
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.
(2) Included in other liabilities.
9. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the Trust's asset retirement obligations.
Nine months ended Year ended
Sept. 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of period $ 90,844 $ 89,602
Accretion expense 5,717 7,299
Revisions to estimates 559 (262)
Liabilities incurred 1,067 1,422
Liabilities acquired, net (Note 2) 7,707 1,636
Liabilities settled (3,123) (8,853)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period $ 102,771 $ 90,844
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL's estimated credit-adjusted risk-free rate of nine percent (2008 - eight to
nine percent) and an inflation rate of two percent (2008 - two percent) were
used to calculate the present value of the asset retirement obligations.
10. 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 (Note 3). The non-controlling interest on the balance sheet represents
50 percent of the net assets of the Partnership as follows:
Nine months ended Year ended
Sept. 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Non-controlling interest, beginning
of period $ 56,380 $ -
Non-controlling interest on
acquisition - 54,057
Net income attributable to
non-controlling interest 788 3,823
Distributions to MFC(1) (53,302) (1,500)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Non-controlling interest, end of
period $ 3,866 $ 56,380
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes $49.6 million distribution paid following settlement of note
receivable (Note 3).
The non-controlling interest in the statement of income is comprised of:
Three months ended Nine months ended
Sept. 30 Sept. 30
---------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Net profits interest expense $ 736 $ 2,010 $ 1,523 $ 7,071
Share of net income attributable to
MFC 80 1,151 788 2,107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 816 $ 3,161 $ 2,311 $ 9,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. UNITHOLDERS EQUITY
Units Issued:
Nine months ended Year ended
Sept. 30, 2009 December 31, 2008
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of the period 96,181 $ 1,042,183 90,494 $ 969,588
Equity offering 9,603 86,422 - -
Issued on corporate acquisition
(Note 2) 5,676 36,600 2,409 29,496
Less issue expenses (net of tax
of $1,280) - (3,549) - (29)
Issued from Distribution
Reinvestment Plan 867 7,630 1,831 23,393
Issued on conversion of debentures - - 1,447 19,735
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of the period 112,327 $ 1,169,286 96,181 $ 1,042,183
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 nine months ended
September 30, 2009, the trust units potentially issuable on the conversion of
the convertible debentures are anti-dilutive and are therefore excluded from the
calculation. Total weighted average trust units issuable on conversion of the
convertible debentures and excluded from the diluted net income per trust unit
calculation for the three and nine months ended September 30, 2009 were
5,696,000. For the three and nine months ended September 30, 2008, an
additional 5,723,975 and 6,557,840 trust units, respectively, were included in
the diluted income per trust unit calculation. As at September 30, 2009, the
total convertible debentures outstanding were immediately convertible to
5,696,000 trust units.
Deficit
The deficit is comprised of the following:
Nine months ended Year ended
Sept. 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Accumulated income $ 556,597 $ 553,031
Accumulated cash distributions (1,130,071) (1,042,543)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ (573,474) ($489,512)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. FINANCIAL RISK MANAGEMENT
Foreign currency exchange rate risk
During 2009 the Trust has entered into foreign exchange rate derivative
contracts. NAL's management has authorization to fix the exchange rate on up to
50 percent of the Trust's U.S. dollar exposure for periods of up to 24 months.
Trust
Amount(1) Fixed Counterparty
EXCHANGE RATE Remaining Term (US$ MM) Rate Floating Rate
----------------------------------------------------------------------------
Swaps-floating BofC Average
to fixed Oct 2009 - Nov 2009 $ 4.0 1.2730 Noon Rate
Swaps-floating BofC Average
to fixed Oct 2009 - Nov 2009 $ 4.0 1.2875 Noon Rate
Swaps-floating BofC Average
to fixed Oct 2009 - Nov 2009 $ 4.0 1.2625 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1583 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1100 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1200 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1225 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1300 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1420 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1525 Noon Rate
Swaps-floating BofC Average
to fixed Dec 2009 - Dec 2010 $ 6.5 1.1000 Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional US$ denominated commodity sales
The fair value of foreign exchange derivative contracts has been included on the
balance sheet with changes in the fair value reported separately on the
statement of income as unrealized gain (loss). As at September 30, 2009, if
exchange rates had strengthened by $0.01, with all other variables held
constant, net income for the period would have been $0.6 million higher, due to
changes in the fair value of the derivative contracts. An equal and opposite
effect would have occurred to net income had exchange rates been $0.01 weaker.
Commodity price risk
NAL has the following commodity risk management contracts outstanding:
CRUDE OIL Q4-09 Q1-10 Q2-10 Q3-10 Q4-10
----------------------------------------------------------------------------
US$ Collar Contracts
$US WTI Collar Volume (bbl/d) 300 3,500 3,300 2,600 2,400
Bought Puts - Average Strike
Price ($US/bbl) $ 62.67 $ 61.86 $ 62.27 $ 64.90 $ 65.10
Sold Calls - Average Strike
Price ($US/bbl) $ 71.85 $ 72.90 $ 73.23 $ 76.42 $ 76.88
US$ Swap Contracts
$US WTI Swap Volume (bbl/d) 1,700 700 1,200 - -
Average WTI Swap Price
($US/bbl) $ 61.94 $ 75.36 $ 75.67 - -
Cdn$ Collar Contracts
$Cdn WTI Collar Volume (bbl/d) 1,500 300 - - -
Bought Puts - Average Strike
Price ($Cdn/bbl) $ 102.07 $ 66.00 - - -
Sold Calls - Average Strike
Price ($Cdn/bbl) $ 137.63 $ 80.17 - - -
Cdn$ Swap Contracts
$Cdn WTI Swap Volume (bbl/d) 1,300 - - - -
Average WTI Swap Price
($Cdn/bbl) $ 92.55 - - - -
Total Oil Volume (bbl/d) 4,800 4,500 4,500 2,600 2,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS Q4-09 Q1-10 Q2-10 Q3-10 Q4-10
----------------------------------------------------------------------------
Collar Contracts
AECO Collar Volume (GJ/d) 1,685 - - - -
Bought Puts - AECO Average
Strike Price ($Cdn/GJ) $ 8.90 - - - -
Sold Calls - AECO Average
Strike Price ($Cdn/GJ) $ 11.44 - - - -
Swap Contracts
AECO Swap Volume (GJ/d) 32,663 30,000 30,000 31,000 14,337
AECO Average Price ($Cdn/GJ) $ 5.57 $ 5.86 $ 5.60 $ 5.62 $ 5.67
Total Natural Gas Volume
(GJ/d) 34,348 30,000 30,000 31,000 14,337
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair value of commodity derivative contracts has been included on the
balance sheet with changes in the fair value reported separately on the
statement of income as unrealized gain (loss). As at September 30, 2009, 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 $2.7 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 $0.10 per Mcf higher.
Interest rate risk
NAL has the following interest rate derivative contracts outstanding:
Counterparty
Amount Trust Floating
INTEREST RATE Remaining Term (Cdn$MM)(1) Fixed Rate Rate
----------------------------------------------------------------------------
Swaps-floating CAD-BA-CDOR
to fixed Oct 2009 - Dec 2011 $ 39.0 1.5864% (3 months)
Swaps-floating CAD-BA-CDOR
to fixed Oct 2009 - Jan 2013 $ 22.0 1.3850% (3 months)
Swaps-floating CAD-BA-CDOR
to fixed Oct 2009 - Jan 2014 $ 22.0 1.5100% (3 months)
Swaps-floating CAD-BA-CDOR
to fixed Mar 2010 - Mar 2013 $ 14.0 1.8500% (3 months)
Swaps-floating CAD-BA-CDOR
to fixed Mar 2010 - Mar 2013 $ 14.0 1.8750% (3 months)
Swaps-floating CAD-BA-CDOR
to fixed Mar 2010 - Mar 2014 $ 14.0 1.9300% (3 months)
Swaps-floating CAD-BA-CDOR
to fixed Mar 2010 - Mar 2014 $ 14.0 1.9850% (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount
The fair value of interest rate derivative contracts has been included on the
balance sheet with changes in the fair value reported separately on the
statement of income as unrealized gain (loss). As at September 30, 2009, if
interest rates had been one percent lower, with all other variables held
constant, net income for the period would have been $4.2 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$70.61 per barrel to US$75.99 per barrel for oil and $5.45 per
GJ to $7.98 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
2.002 percent to 2.643 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
1.0679 to 1.0686) as of the balance sheet date, using the notional U.S. dollar
amount and outstanding term of the swap. The fair value of the derivative
contracts is as follows:
Nine months ended Year ended
Sept. 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Fair value of commodity contracts $ 4,377 $ 65,680
Fair value of interest rate swaps 2,502 (274)
Fair value of foreign exchange rate
swaps 5,448 -
----------------------------------------------------------------------------
$ 12,327 $ 65,406
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The gain/(loss) on derivative contracts is as follows:
Gain / (Loss) on Derivative Contracts
----------------------------------------------------------------------------
Three months ended Nine months ended
Sept. 30 Sept. 30
--------------------------------------------
2009 2008 2009 2008
----------------------------------------------------------------------------
Unrealized gain (loss):
Crude oil contracts $ (184) $ 70,892 $ (56,151) $ 13,236
Natural gas contracts (8,251) 40,161 (5,560) 5,134
Interest rate swaps (374) - 2,776 -
Exchange rate swaps 3,310 - 5,448 -
----------------------------------------------------------------------------
Unrealized gain (loss) (5,499) 111,053 (53,487) 18,370
Realized gain (loss):
Crude oil contracts 7,526 (13,119) 44,179 (38,151)
Natural gas contracts 8,331 (3,508) 19,794 (5,697)
Interest rate swaps (226) - (433) -
Exchange rate swaps 3,188 - 5,200 -
----------------------------------------------------------------------------
Realized gain (loss) 18,819 (16,627) 68,740 (43,848)
----------------------------------------------------------------------------
Gain (loss) on derivative
contracts $ 13,320 $ 94,426 $ 15,253 $ (25,478)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
These contracts are presented on the balance sheet as short term / long
term, assets and liabilities as follows:
Sept. 30, December 31,
2009 2008
----------------------------------------------------------------------------
Long term unrealized loss on derivative
contracts $ (4,016) $ (274)
Long term unrealized gain on derivative
contracts 5,508 -
----------------------------------------------------------------------------
Net long term unrealized gain (loss) on
derivative contracts 1,492 (274)
Current unrealized gain on derivative
contracts 10,835 65,680
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net fair value of derivative contracts $ 12,327 $ 65,406
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table reconciles the movement in the fair value of the Trust's
derivative contracts:
Three months ended Nine months ended
Sept. 30 Sept. 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Unrealized gain (loss),
beginning of period $ 17,826 $ (102,267) $ 65,406 $ (9,584)
Unrealized gain acquired(1) - - 408 -
Unrealized gain, end of period 12,327 8,786 12,327 8,786
----------------------------------------------------------------------------
Unrealized gain (loss) for the
period (5,499) 111,053 (53,487) 18,370
Realized gain (loss) in the
period 18,819 (16,627) 68,740 (43,848)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gain (loss) on derivative
contracts $ 13,320 $ 94,426 $ 15,253 $ (25,478)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Assumed on acquisition of Clipper (Note 2)
13. COMMITMENTS
(i) Joint Venture Partnership Agreement
Effective April 20, 2009, the Trust and MFC entered into a joint venture
partnership agreement with a senior industry partner. The arrangement consists
of a three year commitment to spend $50 million on or before August 31, 2012,
that provides the Trust and MFC an opportunity 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. The three year commitment to the Trust 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 earn an interest in over 150 (97.5 net) sections of freehold and
crown acreage. If the capital spending commitments are not met, interests in
the freehold and crown acreage will not be earned and the Trust will not be
required to pay unspent commitment amounts under the arrangement. As at
September 30, 2009, the Trust has spent $2.4 million under this agreement.
(ii) Farm-in Agreement
Effective August 10, 2009, the Trust and MFC entered into a Farm-in Agreement
with a senior industry partner. The arrangement consists of a two year initial
commitment, with a minimum capital commitment of $40 million in the first year
and $57 million in the second year, with an option for a third year, at NAL's
election, for an additional commitment of $50 million. The 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. As at
September 30, 2009, no amounts have been spent under this agreement.
(iii) Flow-through Shares
In conjunction with the acquisition of Clipper, the Trust assumed flow-through
share obligations related to common shares issued by Clipper on December 4,
2008. As a result, the Trust must incur qualifying resource expenditures
amounting to $7.5 million before December 31, 2009. The related tax impact was
recorded on the acquisition of Clipper. The qualifying expenditures were
renounced to shareholders of Clipper as at December 31, 2008. The obligation
remaining for this flow-through share issue was $2.6 million as at September 30,
2009.
(iv) 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) 2009 2010 2011 2012 2013
----------------------------------------------------------------------------
Office lease(1) 1,036 3,798 - - -
Office lease - Clipper(2) 173 692 699 703 234
Transportation agreement 680 1,317 1,317 306 -
Processing agreement(3) 84 428 414 401 384
Convertible debentures(4) - - - 79,744 -
Bank debt - - 148,135 98,757 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 1,973 6,235 150,565 179,911 618
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 58 percent) of the expense on a monthly basis.
(2) Represents the full amount of the office lease assumed with the
acquisition of Clipper. MFC will reimburse the Trust for 50 percent of
the obligation under the base price adjustment clause (Note 2).
(3) Represents a gas processing agreement with a take or pay component.
(4) Principal amount.
14. SUBSEQUENT EVENT
Plan of Arrangement - Breaker Energy Ltd.
On October 13, 2009, NAL and Breaker Energy Ltd. ("Breaker") entered into an
arrangement agreement pursuant to which NAL will acquire all of the issued and
outstanding common shares of Breaker by way of Plan of Arrangement. Under the
arrangement, Breaker shareholders will receive 0.475 NAL trust units for each
share of Breaker held, resulting in the expected issuance of approximately 24.7
million trust units. The transaction is subject to the approval of the Breaker
shareholders, the Court of Queen's Bench of the Province of Alberta and
regulatory authorities, and is expected to close on December 10, 2009.
TRADING PERFORMANCE
For the Quarter Ended
----------------------------------------------------
30-Sept-09 30-Jun-09 30-Sept-08 30-Jun-08
----------------------------------------------------------------------------
PRICE
High $ 12.75 $ 10.53 $ 17.10 $ 17.09
Low $ 8.48 $ 6.63 $ 11.50 $ 13.12
Close $ 12.70 $ 9.37 $ 12.53 $ 16.89
Daily Average Volume 439,319 459,603 380,141 447,401
----------------------------------------------------------------------------
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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