CALGARY, ALBERTA--(Marketwire - Aug. 6,
2008) - NAL Oil & Gas Trust (TSX:NAE.UN) ("NAL" or the "Trust")
today announced its financial and operational results for the second
quarter ended June 30, 2008. All amounts are in Canadian dollars unless
otherwise stated.
On NAL's second quarter results, President and CEO Andrew Wiswell
commented: "the Trust reported its highest production volume and cash
flows in its twelve year history. The Board has authorized a further $8
million increase (for a full year total of $152 million net to the
Trust) in opportunity capital to position projects in 2009 and beyond."
Summary of Second Quarter
- Production volumes increased 25 percent in the second quarter to
23,791 barrels per day (boe/d), up from 19,094 in the second quarter
2007, driven primarily by the corporate acquisitions of Seneca Energy
Canada Inc. ("Seneca"), Tiberius Exploration Inc. ("Tiberius") and Spear
Exploration Inc. ("Spear") and the ongoing execution of our core
business and capital program. Production mix was 52 percent crude oil
and natural gas liquids and 48 percent natural gas.
- Funds from operations ("FFO") equaled $88.6 million in the
quarter, an increase of 65 percent from $54.2 million a year earlier
driven by higher volumes and stronger netbacks from higher commodity
prices. On a per unit basis, FFO of $0.94 ($0.89 fully diluted) compared
favourably with $0.69 ($0.69 fully diluted), an increase of 36 percent
year-over-year.
- Operating netbacks before corporate hedging programs equaled
$58.82 per boe versus $35.76 in second quarter a year earlier, an
increase of 64 percent. These higher netbacks are driven primarily by
our high quality crude and were achieved despite higher operating costs
due to inflationary pressure in the industry. At $10.37/boe in Q2, NAL's
operating costs remain better than the trust sector average.
- Capital expenditures increased to $27.7 million in the second
quarter versus $18.9 million a year earlier, taking advantage of higher
cash flows and broader opportunities in our asset base.
- Convertible debt outstanding decreased from $100.0 million to
$82.3 million at the end of the second quarter as $17.7 million of
debentures converted to units. At June 30, 2008, total net debt
(including convertible debentures) represented 1.1 times annualized
first half 2008 FFO.
2008 Guidance and Outlook
Production volumes during the second quarter were curtailed by tie
in delays, extended plant turnarounds, weather related road bans and
lower capital spending compared to plan due to inability to access
drilling and completion locations. Currently, the Trust has 900 boe/d of
production in the completion and tie in phase. With 60% of its capital
program still to be spent in Q3 and Q4, the Trust is forecasting
production within our 2008 full year guidance range with an expected
2008 exit rate in excess of 25,000 boe/d.
NAL provides the following update to the outlook for full year 2008:
2008 Full Year Outlook
January 23, May 1, August 6,
2008 2008 2008
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Production (boe/d) 23,000-24,000 24,400-24,800(1) 24,400-24,800(1)
Net capital
expenditures ($MM) 110 - 120 140 - 150 150 - 160
Operating costs
($/boe) 9.50 - 9.80 9.50 - 9.80 10.00 - 10.50
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(1) Includes non-controlling interest.
NAL outlines the following 2008 full year financial forecast based upon
certain assumptions:
2008 Forecast Assumptions Key Assumptions
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WTI oil price (U.S.$/bbl)(3) 100.00 120.00 130.00
AECO natural gas price
(C$/GJ)(3) 8.00 8.50 9.00
Exchange rate (Cdn/USD)(3) 1.02 1.02 0.98
Capital expenditures (C$ MM)(4) 160 160 160
Production (boe/d) 24,400(1)(2) 24,400(1)(2) 24,400(1)(2)
Monthly distribution ($/unit ) 0.16 0.16 0.16
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(1) Including February 2008 acquisitions of Tiberius/Spear.
(2) Includes non-controlling interest.
(3) Commodity and exchange rate forecasts assumptions for the July-December
2008 period.
(4) Includes non-controlling interest capital of $8 million, resulting in
trust net capital of $152 million.
2008 Financial Forecasts Sensitivities
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Funds from operation ($MM)(1) 333 349 353
Funds from operation ($/unit
basic) $3.51 $3.68 $3.73
Funds from operation ($/unit
fully diluted) $3.32 $3.49 $3.53
Payout ratio (%) 55 52 51
Payout with capital (%) 100 96 95
Payout with DRIP (%) 92 87 86
Debt / cash flow (x) 0.9 / 1.1(2) 0.8 / 1.0(2) 0.8 / 1.0(2)
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(1) Includes impact of hedging gains and losses
(2) Includes convertible debentures.
FORWARD-LOOKING INFORMATION
Please refer to our 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 outlook for full year 2008 and the 2008 full
year financial forecasts set forth above.
NON-GAAP MEASURES
Please refer to our 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
netbacks.
CONFERENCE CALL DETAILS
At 3:30 p.m. MST (5:30 p.m. EST) on Wednesday, August 6, 2008, NAL
will hold a conference call to discuss the second quarter 2008 results.
Mr. Andrew Wiswell, President and CEO, will host the conference call
with other members of the Management Team. The call is open to analysts,
investors, and all interested parties. If you wish to participate, call
1-866-300-4047 toll free across North America. The conference call will
also be accessible by internet at
http://events.onlinebroadcasting.com/nal/080608/index.php
A recorded playback of the call will be available until August 13, 2008 by calling 1-800-408-3053, reservation 3265792.
Notes: All amounts are in Canadian dollars unless otherwise stated.
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, boe's may be
misleading, particularly if used in isolation. A conversion ratio of
6 Mcf:1 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)
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Three months ended Six months ended
June 30 June 30
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2008 2007 2008 2007
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FINANCIAL
Gross revenue, net of royalties,
before hedging gains (losses) 149,356 77,197 266,188 151,764
Cash flow from operating activities 73,295 56,021 143,856 108,987
Cash flow per unit - basic 0.78 0.71 1.55 1.39
Cash flow per unit - diluted 0.74 0.71 1.47 1.39
Funds from operations 88,578 54,156 164,798 108,391
Funds from operations per unit
- basic 0.94 0.69 1.77 1.38
Funds from operations per unit
- diluted 0.89 0.69 1.68 1.38
Net income (loss) (17,572) 21,390 (3,839) 38,100
Distributions declared 45,302 37,877 89,327 75,483
Distributions per unit 0.48 0.48 0.96 0.96
Payout ratio:
based on cash flow from operating
activities 62% 68% 62% 69%
based on funds from operations 51% 70% 54% 70%
Units outstanding (000's)
Period end 95,277 79,086 95,277 79,086
Weighted average 94,101 78,824 92,909 78,543
Capital expenditures 27,714 18,925 63,907 45,984
Corporate acquisitions - - 58,363
Net debt(1) 288,201 222,408 288,201 222,408
Convertible debentures
(at face value) 82,259 - 82,259 -
OPERATING
Daily production(2)
Crude Oil (bbl/d) 10,286 9,114 10,270 9,240
Natural gas (mcf/d) 68,890 47,461 68,050 47,821
Natural gas liquids (bbl/d) 2,023 2,071 2,084 2,116
Oil equivalent (boe/d) 23,791 19,094 23,696 19,326
OPERATING NETBACK (boe)
Revenue before hedging gains (losses) 86.53 55.88 77.11 54.71
Royalties (17.99) (11.79) (15.83) (11.66)
Operating costs (10.37) (8.60) (10.14) (8.31)
Other income 0.65 0.27 0.51 0.35
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Operating netback before hedging 58.82 35.76 51.65 35.09
Hedging gains (losses) (10.04) 0.49 (6.31) 0.89
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Operating netback 48.78 36.25 45.34 35.98
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(1) Excluding convertible debentures.
(2) Includes royalty income volumes.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in
conjunction with the interim consolidated financial statements for the
three and six month periods ended June 30, 2008 and the audited
consolidated financial statements and MD&A for the year ended
December 31, 2007 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 and financial position. However, these terms do not have
any standardized meaning as prescribed by Canadian Generally Accepted
Accounting Principles ("GAAP"). Investors should be cautioned that these
measures should not be construed as an alternative to net income
determined in accordance with GAAP as an indication of NAL's
performance. NAL's method of calculating these measures may differ from
other income funds and companies and, accordingly, they may not be
comparable to measures used by other income funds and companies.
Funds from operations is calculated as cash flow from operating
activities before changes in non-cash working capital. Funds from
operations does not represent operating cash flows or operating profits
for the period and should not be viewed as an alternative to cash flow
from operating activities calculated in accordance with GAAP. Funds from
operations is considered by Management to be a more meaningful key
performance indicator of NAL's ability to generate cash to finance
operations and to pay monthly distributions. Funds from operations per
unit and cash flow from operations per unit are calculated using the
weighted average units outstanding for the period.
Payout ratio is calculated as distributions declared for a period as
a percentage of either cash flow from operating activities or funds
from operations; both measures are stated.
Net debt to trailing 12 months cash flow is calculated as net debt
as a proportion of funds from operations for the previous 12 months. Net
debt is defined as bank debt, plus convertible debentures at face
value, plus working capital, excluding derivative contracts, notes
payable/receivable and future income tax balances.
The following table reconciles cash flows from operating activities to funds from operations:
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Three months ended Six months ended
June 30 June 30
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$(000s) 2008 2007 2008 2007
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Cash flow from operating activities 73,295 56,021 143,856 108,987
Add back change in non-cash working
capital 15,283 (1,865) 20,942 (596)
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Funds from operations 88,578 54,156 164,798 108,391
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FORWARD-LOOKING INFORMATION
This discussion and analysis contains forward-looking information as
to the Trust's internal projections, expectations or 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" or
"resources" are forward-looking statements as they involve the implied
assessment, based on certain estimates and assumptions, that the
reserves and resources 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; 2008 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; 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 and development
activities and related expenditures.
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 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 risk and uncertainties include, without limitation: changes in
commodity prices; unanticipated operating results or production
declines; the impact of weather conditions on seasonal demand and
ability to execute the capital program; risks inherent in oil and gas
operations; imprecision of reserve estimates; limited, unfavorable or no
access to capital 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 realize the anticipated benefits of
acquisitions; general economic conditions in Canada, the United States
and globally; fluctuations in foreign exchange or interest rates;
changes in government regulation of the oil and gas industry, including
environmental regulation; changes in the royalty rates, particularly in
light of the Alberta government's royalty review; changes in tax laws;
including the impact of legislation relating to the taxation of
"specified investment flow-through" entities and proposed amendments to
the Income Tax Act (Canada) to permit the conversion of income trusts
into corporations by the Federal government; 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 and MD&A for the year ended December
31, 2007.
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.
ACQUISITION OF TIBERIUS EXPLORATION INC. AND SPEAR EXPLORATION INC.
Effective February 27, 2008 the Trust acquired all the issued and
outstanding common shares of Tiberius Exploration Inc. ("Tiberius") and
Spear Exploration Inc. ("Spear"), which have interests in southeast
Saskatchewan.
On February 29, 2008 the Trust transferred the assets into a newly
formed limited partnership ("Partnership") in exchange for a 50 percent
partnership interest and a note receivable of $3.7 million. A wholly
owned subsidiary of Manulife Financial Corporation ("MFC") acquired the
remaining 50 percent share in the Partnership and a note receivable of
$3.7 million, by payment in cash of one half of the total purchase price
for Tiberius and Spear. MFC is a related party to the Trust, see
"Management Contract and Fees".
The net acquisition cost to the Trust for its 50 percent share in
the acquired properties is $57.8 million, before acquisition costs,
comprised of $28.3 million in cash and $29.5 million from the issuance
of 2.4 million trust units at a price of $12.24 per unit. The unit price
was based on the average market price of the units at the announcement
date for the acquisition of February 11, 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. The equivalent carrying amounts of property, plant and
equipment related to this interest is recorded on the books of each
royalty holder and was removed from the books of the Partnership.
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. 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 are 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.
Consequently, substantially all analysis in the MD&A includes
100 percent of the results of the Partnership, with 50 percent of these
results being removed through the non-controlling interest.
The results of operations from the Tiberius and Spear properties
have been included in the consolidated financial statements of the Trust
commencing February 27, 2008, the closing date of the transaction.
The fair values assigned to the net assets acquired from Tiberius
and Spear and the consideration paid by the Trust is as follows:
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Net assets
acquired Total Disposition Trust, net Net to
$(000s): Acquisition to Manulife Acquisition NPI(1) Trust
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Cash $ 9,734 $ - $ 9,734 $ - $ 9,734
Working capital
deficiency (5,620) - (5,620) - (5,620)
Notes
receivable, net
from MFC - (3,750) (3,750) 49,599 45,849
Property, plant
and equipment 111,258 - 111,258 (49,599) 61,659
Future income
taxes (23,389) 11,588 (11,801) - (11,801)
Asset
retirement
obligations (1,636) - (1,636) - (1,636)
Goodwill 26,238 (12,003) 14,235 - 14,235
Non-controlling
interest - (54,057) (54,057) - (54,057)
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$ 116,585 $ (58,222) $ 58,363 $ - $ 58,363
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Consideration:
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Cash $ 86,118 $ (57,807) $ 28,311 $ - $ 28,311
Issuance of
trust units 29,496 - 29,496 - 29,496
Acquisition
costs 971 (415) 556 - 556
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$ 116,585 $ (58,222) $ 58,363 $ - $ 58,363
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(1) Net profit interest agreement entered into with MFC in exchange for a
note receivable.
The operations attributable to the Tiberius and Spear assets were as
follows:
Three months
ended
June 30, Net Impact to Year-to- Net Impact to
$ (000s) 2008(1) Trust(2) date(1) Trust(2)
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Total production
volumes (boes) 79,707 39,854 118,387 59,194
Production volumes
(boe/d) 876 438 650 325
Oil, natural gas and
liquid sales $ 9,244 $ 4,622 $ 13,154 $ 6,577
Royalties (834) (417) (1,372) (686)
Operating costs (867) (434) (1,188) (594)
General and
administrative (142) (71) (170) (85)
Unit-based incentive
compensation (61) (30) (81) (41)
Interest income, net 1,806 903 2,452 1,226
Depletion,
depreciation
and accretion (562) (281) (761) (380)
Net profit interest
expense (7,165) (3,583) (10,122) (5,061)
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Net income $ 1,419 $ 709 $ 1,912 $ 956
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(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 agreement,
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:
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Three months ended Six months ended
June 30 June 30
----------------------------------------
$(000s) 2008 2007 2008 2007
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Net profits interest expense $3,583 $ - $5,061 $ -
Share of net income attributable
to MFC 709 - 956 -
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$4,292 $ - $6,017 $ -
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EXPLORATION & DEVELOPMENT ACTIVITIES
The Trust spent $17.8 million on drilling operations during the
second quarter of 2008, versus $14.2 million in 2007 and participated in
the drilling of 23 (11.1 net) wells during the second quarter of 2008,
compared to seven (3.8 net) wells during the same period in 2007.
Drilling activity was up year over year but below expectations by $5
million due to weather and surface lease acquisition delays. Although
fewer locations were drilled than expected during the quarter, the
program was successful with all wells being cased for completion.
Activity is expected to remain high through the third and fourth
quarters with an additional 25 to 30 net wells expected to be drilled.
Historically, NAL's assets have been concentrated in southeast
Saskatchewan and central Alberta. The purchase of Seneca in 2007 added a
new core area at Monkman in northeast British Columbia and expanded the
Trust's W4M operations in the Hanna to Drumheller area of Alberta. The
Tiberius/Spear acquisition added to NAL's Nottingham/Alida operations in
southeast Saskatchewan.
Second Quarter Drilling Activity
Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
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Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 18 8.8 3 1.7 0 0.0 0 0.0 21 10.5
Non-operated
wells 2 0.6 0 0 0 0.0 0 0.0 2 0.6
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Total wells
drilled 20 9.4 3 1.7 0 0.0 0 0.0 23 11.1
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Year to Date Drilling Activity
Natural Service Dry &
Crude Oil Gas Wells Abandoned Total
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Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 40 20.9 9 6.4 0 0.0 0 0.0 49 27.3
Non-operated
wells 10 1.0 6 1.1 0 0.0 0 0.0 16 2.1
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Total wells
drilled 50 21.9 15 7.5 0 0.0 0 0.0 65 29.4
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Southeast Saskatchewan (Alida, Nottingham, Rosebank, Midale, Elswick)
In Saskatchewan, there were 16 (7.7 net) oil wells drilled during
the second quarter. Activity was primarily focused in the Mississippian
at Alida, Nottingham, Rosebank and Midale. The Trust expects to have two
drilling rigs working for the remainder of the year on Mississippian
and Bakken prospects in the area.
As at July 31, 2008, we have drilled three wells at Hoffer and they are currently being completed and evaluated.
Field operations were forced to shut in production of 300 boe/d on
average for the quarter on the newly acquired Tiberius and Spear
properties. This shut in occurred during April and May as a result of
road bans which prevented the Trust from hauling production to our
processing facilities from single well batteries. Planning and
procurement for new facilities to link these properties into the Trust's
Nottingham and Alida gathering systems are under way and construction
is expected to be completed during the third and fourth quarters of this
year.
Engineering and procurement work are completed for the Nottingham
gas plant expansion which will increase capacity from 13 mmcf/d to 18
mmcf/d. It is expected that equipment delivery and construction will
commence in October, with commissioning and start up to occur in early
2009.
Alberta (Garrington, Westward Ho, Drumheller, Pine Creek, Lacombe, Medicine River, Sylvan Lake)
In Alberta, NAL drilled seven (3.4 net) wells during the quarter
with results meeting expectations. The Trust expects to have one rig
working through the rest of the year drilling 10 - 15 stacked Mannville
opportunities in Pine Creek and the greater Sylvan Lake area with a
second rig used to drill three horizontal Cardium oil wells in the
Garrington/Sylvan areas.
Two Glauconite oil wells were brought on production at a combined
rate of 200 boe/d (net to the Trust) in the Hussar area of southern
Alberta. Three additional wells to be drilled in 2008 are expected to
delineate this new pool. The Trust has finished five recompletions in
the Drumheller area as part of a wellbore optimization program and
results have been positive with total production of 200 boe/d added.
The second quarter was significantly impacted by six extended
turnarounds at operated and third party facilities across central
Alberta. Volumes for the quarter were negatively impacted in excess of
NAL's forecasted amounts by an average of 300 boe/d for the quarter.
Most turnarounds were anticipated but several were extended and slow to
come back up to capacity. NAL had planned to redirect 650 boe/d of
production to another third party plant during one extended turnaround
but capacity became unavailable at that plant due to an outage that was
unknown at the time of our forecast.
Northeast British Columbia (Monkman)
In the Monkman area, the focus for 2008 is to participate in three
wells and tie in the a-26-E discovery. The exploration drill at c-21-K
(Trust 10 percent WI) has reached intermediate casing point and drilling
information to date is encouraging with rig release expected in
October. The a-37-F well (Trust 10 percent WI) is approaching
intermediate casing point and is also expected to be rig released in
October. One additional location (Trust 20 percent WI) is expected to
commence drilling in the fourth quarter using one of the existing rigs.
NAL expects to test successful wells during the fourth quarter, but is
not forecasting production from these wells in 2008.
The 2007 exploration drill at a-26-E was successfully tested in two
intervals at combined rates in excess of 60 mmcf/d gross raw gas and has
been subsequently tied into the Spectra Pine River Gas plant. The well
was on stream in May 2008, and is currently flowing at 40 - 45 mmcf/d
gross raw gas (approximately 7.5mmcf/d net sales gas for the Trust) from
one interval. Currently, the b-60-E well is being curtailed due to
operating efficiency being affected as the plant is approaching
capacity. Production from b-60-E and the second interval at a-26-E
provide ample deliverability to fill all additional interruptible
capacity that may become available through the current 40 mmcf/d
expansion and decline in total volumes going to the facility.
At the time of our January 2008 guidance, there was significant work
left to complete in order to get a-26-E on stream. This operation took a
month longer than expected and was finalized at the end of April rather
than April 1. As a result, production was below forecast by 850 boe/d
for April representing 283 boe/d average for the second quarter of 2008.
CAPITAL EXPENDITURES
Capital expenditures for the quarter ended June 30, 2008 totaled
$27.7 million (including $1.0 million of property acquisitions) compared
with $18.9 million for the quarter ended June 30, 2007.
On a year-to-date basis, capital expenditures totaled $63.9 million
compared to $46.0 million in the comparable period of 2007. Included in
2008 is $7.8 million of net property acquisitions.
The Board of Directors has approved an $8 million (net to the Trust)
increase to the capital budget for the full year 2008. This new capital
is intended to fund repositioning activities for land, seismic and
strategic drilling, setting up additional activity for 2009. The
production impact from any of this new capital spent on drilling will be
late in the year and have limited impact on NAL's production volumes
for full year 2008.
Year-to-date, NAL has spent 42 percent of its $152.0 million capital
budget (net to the Trust) and expects an active second half of 2008.
NAL's strategy of building future opportunities into its portfolio for
2009 - 2010 has resulted in 21 percent of its exploitation and
development capital being spent on plant and facilities, seismic and
land in the first six months of 2008 as compared to 12 percent a year
earlier. Over the balance of 2008, NAL expects that trend to continue as
it executes its capital program.
Capital Expenditures ($000s)
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Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Drilling, completion and production
equipment 17,754 14,198 40,284 37,849
Plant and facilities 3,476 2,143 6,707 4,395
Seismic 51 268 807 527
Land 2,828 106 3,822 357
----------------------------------------------------------------------------
Total exploitation and development 24,109 16,715 51,620 43,128
----------------------------------------------------------------------------
Office equipment 303 230 618 274
Capitalized G&A 1,401 1,669 2,343 2,436
Capitalized unit-based compensation 935 311 1,490 171
----------------------------------------------------------------------------
Total other capital 2,639 2,210 4,451 2,881
----------------------------------------------------------------------------
Property acquisitions
(dispositions), net 966 - 7,836 (25)
----------------------------------------------------------------------------
Total capitalized expenditures 27,714 18,925 63,907 45,984
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PRODUCTION
Second quarter 2008 production of 23,791 boe/d exceeded production
of 19,094 boe/d in the comparable period of 2007 by 25 percent. This
increase is attributable to the acquisition of Seneca, Tiberius and
Spear production as well as the ongoing execution of the Trust's capital
program.
For the six months ended June 30, 2008, production of 23,696 boe/d
exceeded the 19,326 boe/d for the comparable period in 2007, by a margin
of 23 percent for the same reasons.
Delay and unexpected down time had a significant impact on the
quarter as production was 880 boe/d below expectations due to the impact
of increased turnarounds, shut in production for road bans in
Saskatchewan and a one month start up delay at Monkman, British
Columbia. As a result of these timing issues, the Trust expects to meet
the lower end of production guidance (24,400 - 24,800 boe/d) for the
full year 2008.
June production (24,061 boe/d) gives management confidence that production for the balance of 2008 is expected to be on plan.
As of July 31, 2008, the Trust had 900 boe/d of production in the
completion and tie in phase that will come on stream during the third
quarter. The main contributing areas for this production are Pine Creek
(300 boe/d), central Alberta (400 boe/d), and southeast Saskatchewan
(200 boe/d).
It is anticipated that the December 2008 production exit rate will be in the 25,000 - 25,500 boe/d range.
Average Daily Production Volumes
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008(1) 2007(1) 2008(1) 2007(1)
----------------------------------------------------------------------------
Oil (bbl/d) 10,286 9,114 10,270 9,240
Natural gas (Mcf/d) 68,890 47,461 68,050 47,821
NGLs (bbl/d) 2,023 2,071 2,084 2,116
Oil equivalent (boe/d) 23,791 19,094 23,696 19,326
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Volumes include royalty income volumes.
The oil equivalent volumes of 23,791 boe/d for the second quarter of
2008 and 23,696 boe/d year-to-date include 438 boe/d and 325 boe/d,
respectively, attributable to the non-controlling interest in the
Tiberius and Spear properties. The Trust's net production, after
deducting the non-controlling interest, is 23,353 boe/d for the second
quarter of 2008 and 23,371 boe/d year-to-date.
Oil and natural gas liquids totaled 52 percent of production with
natural gas increasing to 48 percent of production as a result of the
natural gas weighted Seneca acquisition.
Production Weighting
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Oil 43% 48% 43% 48%
Natural gas 48% 41% 48% 41%
NGLs 9% 11% 9% 11%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs, totaled $187.3 million for the three months
ended June 30, 2008, 93 percent higher than the second quarter of 2007.
The increase is due to a 25 percent increase in production as a result
of acquisitions and the ongoing execution of our capital program, as
well as a 55 percent increase in the average realized price per boe. The
Trust's realized commodity prices increased for all production,
highlighted by a 73 percent quarter-over-quarter increase in realized
crude oil prices.
For the six month period ended June 30, 2008, revenue after
transportation costs totaled $332.6 million, an increase of 74 percent
from the comparable period in 2007. The increase is attributable to a 23
percent increase in production, due to acquisitions, and an increase of
41 percent in the average realized price per boe.
Revenue
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue(1) ($000s) 187,341 97,090 332,550 191,374
$/boe 86.53 55.88 77.11 54.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior to
royalties.
OIL MARKETING
NAL sells 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 West Texas Intermediate ("WTI") benchmark
price, transportation costs, exchange rates and the supply/demand
situation of particular crude oil quality streams during the year.
NAL's second quarter average realized Canadian crude oil price per
barrel, net of transportation costs, was $116.51, as compared to $67.18
for the comparable quarter of 2007. The increase in realized price
quarter-over-quarter of 73 percent, or $49.33/bbl, was primarily driven
by a 91 percent increase in WTI (U.S.$/bbl) over the comparable period,
offset by a strengthening Canadian dollar.
For the second quarter of 2008, NAL's crude oil price differential
compared to WTI priced in Canadian dollars was 93 percent, a one
percentage point decrease from the comparable period in 2007. The
differential is calculated as realized price as a percentage of WTI
stated in Canadian dollars.
For the six months ended June 30, 2008, NAL's average oil price was
$103.23 per barrel as compared to $64.37 for the comparable period in
2007. The increase in realized price was driven by an 80 percent
increase in WTI (US$/bbl). Differentials were consistent year-over-year
at 92 percent.
Natural gas liquids averaged $78.01/bbl in the second quarter of
2008, a 61 percent increase from $48.33/bbl realized in 2007. For the
six months ended June 30, 2008, natural gas liquids averaged $70.58/bbl,
an increase of 51 percent from the comparable period in 2007.
On July 22, 2008, SemGroup L.P. announced that the it and certain of
its North American subsidiaries had filed voluntary petitions for
reorganization under Chapter 11 of the U.S. Bankruptcy Code as well as
an application for creditor protection under the Companies' Creditors
Arrangement Act in Canada.
NAL has a maximum net potential exposure of $7.0 million from oil,
butane and condensate sales to SemCanada Crude Company ("SemCanada"), a
subsidiary of SemGroup, L.P. for the marketing of a portion of NAL's
production. NAL management has retained legal counsel and continues to
have discussions with SemCanada and its Monitor to best manage and
resolve this matter.NAL is currently uncertain what portion of the
exposure may be collectible, but the amount is not considered
significant to NAL's financial position. Further, no provision has been
made in the financial statements against this receivable as at June 30,
2008, since a reasonable determination of impairment can not be made at
this time.
NATURAL GAS MARKETING
Approximately 74 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 26 percent tied to NYMEX or other
indexed reference prices.
For the three months ended June 30, 2008, the Trust's natural gas
sales averaged $10.12/mcf compared to $7.40/mcf in the comparable period
of 2007, an increase of 37 percent. The quarter-over-quarter increase
in gas prices was attributable to a 44 percent increase in the benchmark
AECO daily spot prices.
Prices for Lake Erie natural gas increased to $12.12/mcf in the
second quarter of 2008, compared to $8.99/mcf in 2007, an increase of 35
percent. Lake Erie production of 3.48 mmcf/d accounted for five percent
of the Trust's natural gas production in the second quarter of 2008,
compared to seven percent in the same period of 2007; the decrease is
attributable to the gas weighted Seneca acquisition effective September
1, 2007. Natural gas sales from the Lake Erie property receive a higher
price due to the close proximity to the Ontario and Northeastern U.S.
markets.
For the six months ended June 30, 2008, NAL averaged $9.06/mcf, a 19
percent increase from the $7.59/mcf realized in the comparable period
in 2007.
Average Pricing
(net of transportation charges)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 123.99 65.03 110.94 61.60
NAL average oil (Cdn$/bbl) 116.51 67.18 103.23 64.37
NAL natural gas liquids (Cdn$/bbl) 78.01 48.33 70.58 46.82
Natural Gas (Cdn$/Mcf)
AECO -- daily spot 10.20 7.07 9.09 7.24
AECO -- monthly 9.35 7.37 8.21 7.42
NAL Western Canada natural gas 10.01 7.27 8.98 7.40
NAL Lake Erie natural gas 12.12 8.99 10.67 9.88
NAL average natural gas 10.12 7.40 9.06 7.59
NAL Oil Equivalent before hedging
(Cdn$/boe -- 6:1) 86.53 55.88 77.11 54.71
Average Foreign Exchange Rate
(Cdn$/U.S.$) 1.010 1.098 1.007 1.135
----------------------------------------------------------------------------
----------------------------------------------------------------------------
RISK MANAGEMENT
NAL employs risk management practices to assist in managing cash
flows and to support capital programs and distributions. NAL's
management has authorization to hedge up to 50 percent of budgeted total
production, net of royalties, for a period of up to two years.
Management's practice is to hedge more near-term volumes on a rolling 12
month forward basis with more limited volumes hedged in the 13 - 24
month forward period. The execution of NAL's hedging program is layered
in over time in small increments using a combination of swaps and
collars. As at June 30, 2008, NAL had several financial WTI oil
contracts and AECO natural gas contracts in place. The following is a
summary of the realized gains and losses on risk management contracts:
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Average crude volumes hedged (bbl/d) 4,833 2,300 4,516 2,300
Crude oil realized gain (loss)
($000's) (18,001) 700 (25,032) 2,937
Gain (loss) per bbl hedged (40.93) 3.34 (30.45) 7.06
Average natural gas volumes hedged
(GJ/d) 29,330 16,000 25,085 15,250
Natural gas realized gain (loss)
($000's) (3,729) 148 (2,189) 185
Gain (loss) per GJ hedged (1.40) 0.10 (0.48) 0.07
Average BOE hedged (boe/d) 9,466 5,113 8,479 4,981
Total realized gain (loss) ($000's) (21,730) 848 (27,221) 3,122
Gain (loss) per boe hedged (25.23) 1.82 (17.64) 3.46
Gain (loss) per boe (10.04) 0.49 (6.31) 0.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All derivative contracts are recorded on the balance sheet at fair
value. The Trust has not designated any of its derivative contracts as
effective accounting hedges, even though the Trust considers all
commodity contracts to be effective economic hedges. Therefore, 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. Accordingly, the
magnitude of the unrealized gain or loss will continue to fluctuate with
changes in commodity prices.
The fair value of the derivatives at June 30, 2008 was a liability
of $102.3 million, comprised of a $70.6 million liability on oil
contracts and a $31.7 million liability on gas contracts.
Second quarter income for 2008 includes a $70.2 million unrealized
loss on derivatives resulting from the change in the fair value of the
derivative contracts during the quarter from a liability of $32.1
million at March 31, 2008 to a liability of $102.3 million at June 30,
2008. The $70.2 million unrealized loss was comprised of a $53.9 million
unrealized loss on crude oil contracts, and a $16.3 million unrealized
loss on natural gas contracts. The unrealized loss in the second quarter
is primarily attributable to higher crude oil forward prices compared
to March 31, 2008. Average hedged boes for the second quarter were 9,466
as compared to 7,492 for the first quarter of 2008.
For the six months ended June 30, 2008, income includes an
unrealized loss of $92.7 million, resulting from the change in the fair
value of the derivatives during the period. The unrealized loss was
comprised of a $57.7 million unrealized loss on crude oil contracts, and
a $35.0 million unrealized loss on natural gas contracts. The
unrealized loss in the period is reflective of the significant increase
in commodity prices since December 31, 2007.
The gain/loss on derivative contracts is as follows:
Gain / Loss on Derivative Contracts ($000's)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Unrealized gain (loss)
Crude oil contracts (53,893) (1,811) (57,656) (5,340)
Natural gas contracts (16,255) 5,177 (35,027) 956
----------------------------------------------------------------------------
Unrealized gain (loss) (70,148)(1) 3,366 (92,683)(1) (4,384)
Realized gain (loss) (21,730) 848 (27,221) 3,122
Reclassification from other
comprehensive income - 1,394 - 2,773
----------------------------------------------------------------------------
Gain (loss) on derivative
contracts (91,878) 5,608 (119,904) 1,511
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on August 5, 2008, forward strip pricing, the unrealized losses
would be $9,457 for the three months ended June, 30, 2008, and $31,992
for the six months ended June 30, 2008, representing an improvement of
$60,691.
For the remainder of 2008, NAL has the following risk management contracts
outstanding:
----------------------------------------------------------------------------
CRUDE OIL U.S.$ CDN$
----------------------------------------------------------------------------
Swap (bbls) 337,300 361,900
Swap (bbl/d) 1,833 1,967
$/bbl $91.71 $91.64
Collars (bbls) 110,400 128,800
Collars (bbl/d) 600 700
$/bbl $84.17 - $95.75 $91.93 - $109.03
Total (bbls) 447,700 490,700
Total (bbl/d) 2,433 2,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS CDN$
----------------------------------------------------------------------------
Swap (GJ) 4,665,000
Swap (GJ/d) 25,353
$/GJ $7.42
Collars (GJ) 855,000
Collars (GJ/d) 4,647
$/GJ $8.00 - $9.70
Total GJ 5,520,000
Total (GJ/d) 30,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For 2009, NAL has the following risk management contracts outstanding:
----------------------------------------------------------------------------
CRUDE OIL U.S.$ CDN$
----------------------------------------------------------------------------
Swap (bbls) 272,900 209,100
Swap (bbl/d) 748 573
$/bbl $105.24 $100.21
Collars (bbls) 364,500 105,900
Collars (bbl/d) 998 290
$/bbl $109.91 - $156.39 $105.60 - $125.82
Total (bbls) 637,400 315,000
Total (bbl/d) 1,746 863
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NATURAL GAS CDN$
----------------------------------------------------------------------------
Swap (GJ) 1,598,000
Swap (GJ/d) 4,378
$/GJ $8.20
Collars (GJ) 2,510,000
Collars (GJ/d) 6,877
$/GJ $8.44 - $10.36
Total GJ 4,108,000
Total (GJ/d) 11,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $38.9 million for the
three months ended June 30, 2008. Expressed as a percentage of gross
sales net of transportation costs, before gain/loss on derivative
contracts, the net royalty rate was 20.8 percent for the quarter ended
June 30, 2008, down from 21.1 percent experienced in the comparable
period of the previous year.
Royalties increased to $17.99 per boe for the second quarter of
2008, an increase of 53 percent compared to the second quarter of 2007.
The increase is attributable to significantly higher commodity prices on
a quarter-over-quarter basis.
On a year-to-date basis, royalties were $68.3 million, up from $40.8
million in the comparable period of 2007. Expressed as a percentage of
gross sales net of transportation costs, before gain/loss on derivative
contracts, the net royalty rate was 20.5 percent as compared to 21.3
percent in the comparable period in 2007.
Royalty Expenses
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Royalties ($000s) 38,941 20,487 68,252 40,801
As % of revenue 20.8 21.1 20.5 21.3
$/boe 17.99 11.79 15.83 11.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING COSTS
Operating costs averaged $10.37 per boe for the quarter ended June
30, 2008, a 21 percent increase from the $8.60 per boe for the quarter
ended June 30, 2007. On a year-to-date basis, operating costs were
$10.14 per boe as compared to $8.31 in 2007.
Operating costs are projected to be $10.00 - $10.50 per boe for the
full year 2008. Costs have climbed steadily through 2007 and into 2008
with operations receiving ongoing cost increase notices from the Trust's
vendors resulting in a significant departure from year-over-year
spending profiles. Approximately $0.50 per boe of the current increase
is attributable to the full year effect of higher costs associated with
the Seneca production. The remaining $1.27 per boe increase is mainly
due to higher than forecast escalation in contract services, property
taxes, fuel, electricity and third party processing costs that have
occurred in the increasing commodity price environment.
Operating Costs
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Operating costs ($000s) 22,443 14,952 43,716 29,078
As a % of revenue 11.98 15.40 13.14 15.19
$/boe 10.37 8.60 10.14 8.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended June 30, 2008, NAL's operating netback before
hedging gains (losses) was $58.82 per boe, an increase of $23.06 from
$35.76 per boe for the quarter ended June 30, 2007. The increase was due
to higher revenues driven by stronger commodity prices, partially
offset by increases in royalties and operating expenses. Hedging losses
were $10.04 per boe in the second quarter of 2008, as compared to a gain
of $0.49 per boe in 2007.
On a year-to-date basis, similar trends resulted in an operating
netback, before hedging, of $51.65 per boe as compared to $35.09 per boe
in 2007.
Operating Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue 86.53 55.88 77.11 54.71
Royalties (17.99) (11.79) (15.83) (11.66)
Operating expenses (10.37) (8.60) (10.14) (8.31)
Other income 0.65 0.27 0.51 0.35
----------------------------------------
Operating netback, before hedging 58.82 35.76 51.65 35.09
Hedging gains (losses) (10.04) 0.49 (6.31) 0.89
----------------------------------------
Operating netback, after hedging 48.78 36.25 45.34 35.98
----------------------------------------------------------------------------
----------------------------------------------------------------------------
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses include direct costs
incurred by the Trust plus the reimbursement of the G&A expenses
incurred by NAL Resources Management Limited (the "Manager") on the
Trust's behalf.
For the three months ended June 30, 2008, G&A expenses were $4.5
million, compared with $3.8 million in the comparable quarter of 2007.
In addition, $1.4 million of G&A costs relating to exploitation and
development activities were capitalized in the second quarter of 2008
compared with $1.7 million in the second quarter of 2007. G&A
expense per boe, excluding retention bonus, was $2.08 in the quarter,
representing no change as compared to the equivalent quarter in 2007.
For the six months ended June 30, 2008, G&A expense increased
seven percent to $8.3 million from $7.8 million in the comparable period
in 2007. In addition, on a year-to-date basis, $2.3 million of G&A
costs relating to exploitation and development activities were
capitalized, compared with $2.4 million in 2007. Year-to-date total
G&A increased only $0.4 million despite a 23 percent increase in
production year-over-year due to acquisitions, which has resulted in
lower G&A per boe rates. The retention bonus program concluded on
June 30, 2008, ($0.03 per boe year-to-date) and there will be no further
expense relating to this program.
General and Administrative Expenses
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
G&A expenses ($000s)
G&A 4,494 3,614 8,135 6,975
Retention bonus 45 230 141 784
----------------------------------------------------------------------------
Expensed G&A ($000s) 4,539 3,844 8,276 7,759
Capitalized G&A ($000s) 1,401 1,669 2,343 2,436
----------------------------------------------------------------------------
Total G&A ($000s) 5,940 5,513 10,619 10,195
Expensed G&A costs:
G&A, excluding retention bonus
($/boe) 2.08 2.08 1.89 1.99
Retention bonus ($/boe) 0.02 0.13 0.03 0.22
----------------------------------------------------------------------------
Total G&A expenses ($/boe) 2.10 2.21 1.92 2.21
As % of revenue 2.4 4.0 2.5 4.1
Per trust unit ($) 0.05 0.05 0.09 0.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
The employees of the Manager are all members of a unit-based
incentive plan (the "Plan"). The Plan results in employees 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 one third
on November 30 in each of three years after grant date. PTUs vest on
November 30, three years after their 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 second quarter of 2008, the Trust accrued $2.8 million of
unit-based incentive compensation charges as compared to a $1.0 million
in the comparable quarter of 2007. The increase in unit-based
compensation in 2008 reflects an increase in unit price and the
performance factors attached to the PTUs.
On a year-to-date basis, the Trust has accrued $4.5 million compared
to $0.8 million in the comparable period in 2007. The increase in
unit-based compensation in 2008 is a result of an increase in the unit
price and an increase in the performance factors attached to the PTUs,
as compared to 2007 when the unit price and performance factors were
decreasing.
This calculation is made at the end of each quarter based on the
quarter end trust unit price and performance factors. The compensation
charges relating to the units granted are recognized over the vesting
period based on the trust unit price, number of RTUs and PTUs
outstanding, and the expected performance multiplier. As a result, the
expense recorded in the accounts will fluctuate in each quarter and over
time.
At June 30, 2008, the Trust has recorded a liability for unit-based
incentive compensation in the amount of $7.7 million, of which $3.2
million is recorded as current as it is payable in December 2008, and
$4.5 million is long-term as it is payable in December 2009 and December
2010.
Unit-Based Compensation
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 1,889 688 2,997 664
Capitalized ($000s) 935 311 1,490 171
----------------------------------------------------------------------------
Total unit-based compensation ($000s) 2,824 999 4,487 835
Expensed unit-based compensation:
As % of revenue 1.0 0.70 0.90 0.34
$/boe 0.87 0.40 0.69 0.19
Per trust unit ($) 0.02 0.01 0.03 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Full year 2008 G&A guidance of $1.90 - $2.10 per boe includes
unit-based compensation expense. On a year-to-date basis, G&A
expense, including $0.69 of unit-based compensation expense, was $2.61
per boe, exceeding guidance as a result of a higher than estimated trust
unit price and stronger relative performance factors.
MANAGEMENT CONTRACT AND FEES
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 a management contract. This contract
provides for no base or performance fees and requires the Trust to
reimburse the Manager at cost for general and administrative and
unit-based compensation expenses incurred by the Manager on behalf of
the Trust calculated on a unit of production basis.
The Trust paid $3.5 million (2007 - $3.1 million) for the
reimbursement of G&A expenses during the second quarter, and $6.5
million (2007 - $6.0 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
$1.8 million has been paid year-to-date, representing units that vested
November 30, 2007 (2007 - $2.2 million).
INTEREST
Interest on bank debt includes charges on borrowings, plus standby
fees on the unused portion of the bank credit facility. NAL's average
outstanding bank debt for the second quarter of 2008 was $313.6 million,
compared to $234.0 million for the second quarter of 2007. The increase
in average debt levels is primarily attributable to the debt required
for the acquisitions of Seneca ($31.8 million) and Tiberius and Spear
($28.3 million) and increased working capital. NAL's effective interest
rate averaged 4.87 percent during the second quarter of 2008, compared
to 5.46 percent during the comparable period in 2007. The decrease in
the rate from the second quarter of 2007 is attributable to rate
decreases in the market. NAL's interest is at a floating rate.
For the six months ended June 30, 2008, NAL's average debt was
$304.6 million, compared to $228.8 million for the corresponding period
in 2007. NAL's effective interest rate averaged 5.10 percent in 2008,
compared to 5.20 percent in 2007.
Interest on bank debt for the second quarter of 2008 was $3.9
million, an increase of $0.8 million from $3.1 million for the
comparable period in 2007. The increase was due to the higher average
debt levels, partially offset by the decrease in the average effective
interest rate for the second quarter of 2008. A similar trend is noted
for the six months ended June 30, 2008.
Interest on convertible debentures represents interest charges, at
6.75 percent, of $1.6 million ($3.3 million for the six months ended
June 30, 2008) and accretion of the debt discount of $0.4 million ($0.9
million for the six months ended June 30, 2008) for the second quarter
of 2008. The debentures were issued on August 28, 2007.
As at August 6, 2008, the Trust has 95,515,513 trust units and $79.8 million in convertible debentures outstanding.
Interest and Debt
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest on bank debt ($000s) 3,879 3,137 7,860 5,996
Interest and accretion on
convertible debentures ($000s) 2,071 - 4,213 -
----------------------------------------------------------------------------
Total interest ($000) 5,950 3,137 12,073 5,996
Bank debt outstanding at period end
($000s) 308,115 233,517 308,115 233,517
Convertible debentures at period
end ($000s) 75,561 - 75,561 -
$/boe:
Interest on bank debt 1.79 1.81 1.82 1.71
Interest on convertible debentures 0.74 - 0.76 -
Accretion on convertible
debentures 0.22 - 0.22 -
----------------------------------------------------------------------------
Total interest 2.75 1.81 2.80 1.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CASH FLOW NETBACK
For the quarter ended June 30, 2008, NAL's cash flow netback was
$43.28 per boe, a 36 percent increase from $31.83 for the comparable
period in 2007. The increase is due to higher operating netbacks after
hedging in 2008, partially offset by an increase in G&A, including
unit-based incentive compensation, ($0.36 per boe), and interest charges
($0.72 per boe). Similar trends are noted for the six months ended June
30, 2008.
Cash Flow Netback ($/boe)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Operating netback, after hedging 48.78 36.25 45.34 35.98
G&A expenses, including unit-based
incentive compensation (2.97) (2.61) (2.61) (2.40)
Interest on bank debt and
convertible debentures(1) (2.53) (1.81) (2.58) (1.71)
Cash flow netback 43.28 31.83 40.15 31.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATIONS ("DDA")
Depletion of oil and natural gas properties, including the
capitalized portion of the asset retirement obligations, and
depreciation of equipment is provided for on a unit-of-production basis
using estimated proved reserves volumes.
For the quarter ended June 30, 2008, depletion on property, plant
and equipment and accretion on the asset retirement obligations
increased by nine percent on a boe basis over the comparable period in
2007. The increase in the DDA rate per boe is largely attributable to
the acquisition of Seneca in August 2007 and Tiberius and Spear in
February 2008. Similar trends are noted for the six months ended June
30, 2008.
The DDA rate will fluctuate period over period depending on the
amount and type of capital expenditures and the amount of reserves
added.
Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Depletion and depreciation ($000s) 47,347 34,822 93,059 69,250
Accretion of asset retirement
obligation ($000s) 1,827 1,302 3,625 2,599
----------------------------------------------------------------------------
Total DDA ($000s) 49,174 36,124 96,684 71,849
DDA rate per boe ($) 22.71 20.79 22.42 20.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
TAXES
In the second quarter of 2008, NAL had a future income tax reduction
of $12.8 million compared with a $2.5 million provision in the
corresponding period for the prior year. For the six month period ended
June 30, 2008, NAL had a future income tax reduction of $19.3 million
compared to $0.2 million in 2007.
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. The
Trust does not expect to incur any cash taxes in 2008.
As at June 30, 2008, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximated $689.2 million, of which approximately 45
percent represented COGPE and 30 percent UCC, with the remaining balance
represented by CEE, CDE, trust unit issue costs and non-capital loss
carry forwards.
Based on current strip prices at June 30, 2008, and our forecast for
year-end tax pools, the Trust is not expected to be taxable in 2008.
This is in part attributable to the deferral of a small portion of
partnership income to the following year.
On June 22, 2007, the Budget Implementation Act, 2007 (Canada) was
enacted to, among other things, implement the October 31, 2006
announcement of the changes to taxability of income trusts made by the
Department of Finance. Under this legislation, distributions to
unitholders will not be deductible by publicly traded income trusts and,
as a result, the Trust will be taxed on its income similar to
corporations. These measures are now considered enacted for purposes of
GAAP. Accordingly, the Trust has measured future income tax assets and
liabilities associated with this new tax. During the second quarter of
2008, $5.0 million of future income tax liability has been recognized in
the financial statements. The future tax recognition in the second
quarter of 2008 is attributable to higher commodity prices resulting in a
small portion of temporary differences reversing after 2010. It is
expected that all remaining taxable temporary differences will reverse
prior to January 1, 2011, the date the taxation changes take effect. The
scheduling of the reversal of temporary differences is based on
management's best estimates and current assumptions, which may change.
Effective for the third quarter of 2008, the Trust income tax rate
is expected to decrease by three percent from the current 29.5 percent
to 26.5 percent once the new provincial SIFT tax rate is enacted. The
impact of this rate reduction is not expected to be significant for the
Trust.
NET INCOME (LOSS)
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
depletion, accretion, unrealized gains or losses on derivative contracts
and future income taxes.
The net loss for the second quarter of 2008 was ($17.6) million
compared to net income of $21.4 million for the comparable period in
2007. The decrease of $39.0 million is primarily due to an increased
loss on derivative contracts of $97.5 million, increased depletion of
$12.5 million, increased operating costs of $7.5 million, partially
offset by higher revenues, net of royalties, of $72.2 million and a
future tax reduction of $15.3 million.
Net loss for the six months ended June 30, 2008 of ($3.8) million
was $41.9 million lower than the comparable period of 2007. The decrease
is due to similar trends as noted for the second quarter of 2008.
Net Income (loss) ($000s)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Net income (loss) (17,572) 21,390 (3,839) 38,100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of trust units, bank debt and convertible debentures.
As at June 30, 2008, NAL had 95,277,293 trust units outstanding,
compared with 90,494,151 trust units at December 31, 2007. The increase
from December 31, 2007 is attributable to 2,408,898 trust units issued
on the acquisition of Tiberius and Spear, 1,267,204 trust units issued
on the conversion of outstanding convertible debentures and 1,107,040
trust units issued under the Trust's distribution reinvestment program
("DRIP").
Under the equity issuance associated with the acquisition of
Tiberius and Spear, 2.4 million trust units were issued at a price of
$12.24 per trust unit for a total consideration of $29.5 million.
For the six months ended June 30, 2008, the DRIP resulted in 1.1
million trust units being issued at an average price of $12.58 per trust
unit for total proceeds of $13.9 million.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so
at 95 percent of the average market price with no additional fees or
commissions. 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.
The participation rate in the regular DRIP averaged 16 percent over
the six months ended June 30, 2008, consistent with recent experience.
The Trust continues to monitor the participation in this plan in
conjunction with its capital requirements.
As at June 30, 2008 the Trust had net debt of $370.5 million (net of
working capital and excluding derivative contracts, notes
payable/receivable with MFC and future income tax asset), including
convertible debentures at face value of $82.3 million. Excluding the
convertible debentures, net debt was $288.2 million, compared with
$291.1 million at December 31, 2007, and $222.4 million as at June 30,
2007. The decrease in net debt, excluding convertible debentures, of
$2.9 million during the first half of 2008 is attributable to a $35.3
million positive change in working capital offset by increased bank debt
of $32.4 million.
Bank debt outstanding was $308.1 million at June 30, 2008 compared
with $275.6 million as at December 31, 2007. The $308.1 million is
comprised of $302.9 under the production facility and $5.2 million under
the working capital facility. The increase in the bank debt during the
first six months of 2008 is due to the acquisition of Tiberius and
Spear, of which $28.3 million was funded by debt. During the second
quarter, the Trust reduced bank debt by $5.3 million. During the first
half of 2008, working capital increased $35.3 million, which is a
reflection of the increase in funds from operations over the period.
Funds from operations increased to $164.8 million in the first six
months of 2008 from $110.4 million in the last six months of 2007, an
increase of $54.4 million or 49 percent. The increase in funds from
operations was driven by increased commodity prices.
At the end of the second quarter, the Trust had a net debt
(excluding convertible debentures) to 12 months trailing cash flow ratio
of 1.05 times and a total net debt (including convertible debentures)
to 12 months trailing cash flow ratio of 1.35 times.
During the second quarter, the current banking group agreed to
expand the bank group through the addition of two new banks and increase
the credit facility by $50 million to $450 million, subject to final
documentation approval, reflecting the Tiberius and Spear acquisitions.
The credit facility is a fully secured, extendible, revolving facility
and will revolve until April 29, 2009 at which time it is extendible for
a further 364-day revolving period upon agreement between the Trust and
the bank syndicate. The facility will consist 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 four
equal quarterly installments commencing May 2010.
The Trust has outstanding $82.3 million principal amount of 6.75%
convertible extendible unsecured subordinated debentures. Interest on
these debentures is paid semi-annually in arrears, on February 28 and
August 31, and the debentures are convertible at the option of the
holder, at any time, into fully paid trust units at a conversion price
of $14.00 per trust unit. During the second quarter of 2008, face value
$17.7 million in debentures were converted at $14.00 per unit into
1,267,204 trust units. 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. Assuming conversion of all
outstanding debentures at the conversion price, an additional 5.9
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 $0.9 million of accretion of the debt discount in the first six months of 2008.
As at August 6, 2008, the Trust has 95,515,513 trust units and $79.8 million in convertible debentures outstanding.
Capitalization
----------------------------------------------------------------------------
June 30, Dec 31, June 30,
2008 2007 2007
----------------------------------------------------------------------------
Trust unit equity ($000s) 471,221 504,717 433,510
Bank debt ($000s) 308,115 275,630 233,517
Working capital deficit (surplus)(1) ($000s) (19,914) 15,429 (11,109)
----------------------------------------------------------------------------
Net debt 288,201 291,059 222,408
Convertible debentures ($000s)(2) 82,259 100,000 -
----------------------------------------------------------------------------
Total Net debt(2) 370,460 391,059 222,408
Net debt to trailing 12 month cash flow(3) 1.05 1.33 1.02
Total Net debt to trailing 12 month cash
flow(2) 1.35 1.79 1.02
Trust units outstanding (000s) 95,277 90,494 79,086
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital excludes derivative contracts, the future income tax
asset, and notes payable/receivable with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt excluding convertible debentures divided by funds
from operations for the previous 12 months.
Subject to fluctuations in commodity prices, the Trust anticipates
that it will continue to maintain adequate liquidity to fund planned
capital spending during 2008 through a combination of funds from
operations, funds received from its DRIP and bank debt.
If assumptions underlying the forecast, including commodity prices
and production, change, the Trust may be required to reconsider its
financing, distribution level or capital expenditures.
Under the tax legislation regarding the change in the taxability 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 remaining six months of 2008, the Trust has
approximately $554 million of available safe harbour and, for each of
2009 and 2010, an additional $280 million.
ASSET RETIREMENT OBLIGATION
At June 30, 2008, the Trust reported an asset retirement obligation
("ARO") balance of $92.0 million ($89.6 million as at December 31, 2007)
for future abandonment and reclamation of the Trust's oil and gas
properties and facilities. The ARO balance was increased by $1.6 million
due to the Tiberius and Spear acquisitions, $0.5 million due to
liabilities incurred and revisions to estimates, and $3.6 million from
accretion expense and was reduced by $3.3 million for actual abandonment
and environmental expenditures incurred in 2008.
DISTRIBUTIONS TO UNITHOLDERS
For the three and six months ended June 30, 2008 the Trust
distributed 62 percent of its cash flow from operating activities, as
compared to 68 percent and 69 percent for the same periods in 2007. 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 (loss) each period, due to the non-cash charges included in net
income (loss). Cash flow from operations usually exceeds net income, as
net income includes non-cash charges such as depletion, depreciation,
accretion, future income tax expense and unrealized gains and losses on
derivative contracts.
The Trust bases its distributions on the cash flow of the Trust,
commodity prices, financial market conditions, internal capital
investment opportunities and the resulting impact on taxability. The
Trust develops an annual forecast, which is updated regularly by
management. The Board sets distributions at a level it believes will be
sustainable for a period of time and formally reviews distribution
levels quarterly.
Given that distributions exceed net income (loss), 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 2008 capital program may not fully replace
production. When the Trust sets distribution levels, depletion expense
is not considered to be indicative of a 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 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 proceeds from the DRIP and
debt. Over the medium term, fluctuations in commodity prices, other
market factors, or development opportunities may make it necessary to
fund the excess of distributions and capital expenditures over cash,
from the credit facility. The credit facility and other sources of cash
are expected to be sufficient to meet NAL's near term capital
requirements, sustain distributions and provide for the resources to
pursue potential growth opportunities.
NAL intends to continue to make cash distributions to unitholders.
However, these cash distributions cannot be guaranteed. The intent is to
continue to distribute a certain proportion of cash flow from operating
activities, the level of distributions being dependent on the drivers
of cash flow, namely production and commodity prices. The implication of
this policy is that the Trust is likely to continue to distribute in
excess of its net income for any given period. The future sustainability
of this distribution policy will be dependent upon maintaining
productive capacity through both capital expenditures and acquisitions. A
significant decrease in commodity prices could impact cash from
operating activities, access to credit facilities and the Trust's
ability to fund operations and maintain distributions.
Distributions
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
($000s except for percentages) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash flow from operating activities 73,295 56,021 143,856 108,987
Net income (loss) (17,572) 21,390 (3,839) 38,100
Actual cash distributions paid or
payable 45,302 37,877 89,327 75,483
Excess of cash flow from operating
activities over cash distribution
paid 27,993 18,144 54,529 33,504
Percentage of cash flow from
operations distributed 62% 68% 62% 69%
Shortfall of net income over cash
distributions paid (62,874) (16,487) (93,166) (37,383)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As stated in the non-GAAP measures section of the MD&A, NAL uses
funds from operations as a key performance indicator to measure the
ability of the Trust to generate cash from operations and to pay monthly
distributions.
For the three months ended June 30, 2008, funds from operations
amounted to $88.6 million, compared with $54.2 million for the three
months ended June 30, 2007. The 63 percent increase is due to increased
revenue driven by higher production and pricing offset partially by
higher costs. On a per trust unit basis, funds from operations increased
36 percent from $0.69 in 2007 to $0.94 in 2008, the increase in funds
from operations being partially offset by the increase in the number of
trust units outstanding due to equity issuances associated with the
acquisitions of Seneca, Tiberius and Spear.
For the six months ended June 30, 2008, funds from operations
increased 52 percent to $164.8 from $108.4 for the comparable period in
2007. The increase is primarily due to increased revenues driven by
higher prices and production.
Funds from Operations
----------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Funds from operations ($000s) 88,578 54,156 164,798 108,391
Funds from operations per trust
unit 0.94 0.69 1.77 1.38
Payout ratio based on funds from
operations 51% 70% 54% 70%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
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) 2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Office lease(1) 2,018 4,036 3,700 - - -
Transportation agreement 955 881 881 - - -
Processing agreement(2) 236 446 428 414 401 384
----------------------------------------------------------------------------
Total 3,209 5,363 5,009 414 401 384
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 a gas processing agreement with a take or pay component.
QUARTERLY INFORMATION
2008 2007 2006
----------------------------------------------------------------------------
($000s, except
per unit
and production
amounts) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Revenue, net of
royalties 58,861 89,611 86,262 78,573 83,268 71,231 75,358 75,798
Per unit 0.63 0.98 0.96 0.95 1.06 0.91 0.97 0.98
Funds from
operations(1) 88,578 76,220 59,537 50,817 54,156 54,234 55,795 54,107
Per unit 0.94 0.83 0.66 0.61 0.69 0.69 0.72 0.70
Net income (loss) (17,572) 13,733 10,556 7,801 21,390 16,710 20,472 20,473
Per unit - basic
and diluted (0.19) 0.15 0.12 0.09 0.27 0.21 0.26 0.27
Average oil
equivalent
production
(boe/d - 6:1) 23,791 23,601 23,656 20,369 19,094 19,561 19,517 19,079
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has designed and evaluated the effectiveness of the
Trust's financial reporting disclosure controls and procedures as at
June 30, 2008 and has concluded that such controls and procedures were
effective as at that date.
While NAL's management believes that the Trust's disclosure controls
and procedures provide a reasonable level of assurance with respect to
their effectiveness, they do not expect that such controls and
procedures will prevent all errors and fraud. A control system, no
matter how well conceived or operated, provides only reasonable, and not
absolute assurance that the objectives of the control system are met.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management has designed or caused to be designed under its
supervision, internal controls over financial reporting related to the
Trust and its subsidiaries, to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with Canadian GAAP.
There were no changes to the Trust's internal controls over
financial reporting since December 31, 2007 that have materially
affected, or are reasonably likely to materially affect, the Trust's
internal control over financial reporting.
CRITICAL ACCOUNTING ESTIMATES
The significant accounting policies used by NAL are disclosed in the
notes to NAL's December 31, 2007 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, 2007.
NEW ACCOUNTING STANDARDS
Effective January 1, 2008, the Trust implemented the provisions of
CICA Handbook Section 1535 "Capital Disclosures", Section 3862
"Financial Instruments - Disclosures", and Section 3863 "Financial
Instruments - Presentation".
Section 1535 establishes standards for disclosing information about
an entity's capital and how it is managed. This Section specifies
disclosure about objectives, policies and processes for managing
capital, quantitative data about what the entity regards as capital,
whether the entity has complied with any capital requirements, and if it
has not complied, the consequences of such non-compliance. Sections
3862 and 3863 establish standards for the presentation and disclosure of
information that enable users to evaluate the significance of financial
instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity
manages those risks.
The implementation of these new standards did not impact the Trust's
financial results but did, however, result in additional disclosures.
FUTURE ACCOUNTING CHANGES
International Financial Reporting Standards ("IFRS")
In February 2008, the Canadian Accounting Standards Board ("AcSB"),
confirmed that the changeover to IFRS from Canadian GAAP will be
required for publicly accountable enterprises interim and annual
financial statements effective for fiscal years beginning on or after
January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS
with comments due by July 31, 2008, wherein early adoption by Canadian
entities is also permitted. The Canadian Securities Administrators
("CSA") have also issued Concept Paper 52-402, which requested feedback
on the early adoption of IFRS as well as the continued use of US GAAP by
domestic issuers. The eventual changeover to IFRS represents a change
due to new accounting standards. The transition from current Canadian
GAAP to IFRS is a significant undertaking that may materially affect the
Trust's reported financial results.
The International Accounting Standards Board ("IASB") has stated
that it plans to issue an exposure draft relating to certain amendments
and exemptions to IFRS 1 in order to make it more useful to Canadian
entities adopting IFRS for the first time. One such exemption relating
to full cost oil and gas accounting is expected to reduce the
administrative burden in the transition from the current Canadian
Accounting Guideline 16 to IFRS. It is anticipated that this exposure
draft will not result in an amended IFRS 1 standard until late 2009. The
amendment will potentially permit the Trust to apply IFRS prospectively
to its full cost pool, rather than performing retrospective assessment
of capitalized exploration and development expenses, with the provision
that a ceiling test, under IFRS standards, be conducted at the
transition date.
Although the Trust has not completed its IFRS changeover plan, an
initial evaluation of IFRS 1 has been completed. NAL is planning
detailed reviews, in the third quarter, of the significant differences
between IFRS and Canadian GAAP as they apply to the Trust. During the
remainder of 2008, NAL will finalize its changeover plan, which will
include project structure and governance, resourcing and training, a
complete analysis of key GAAP differences and a phased plan to assess
accounting policies under IFRS, as well as potential IFRS 1 exemptions.
The Trust anticipates completing its project scoping, which will include
a timetable for assessing the impact on data systems, internal controls
over financial reporting, and business activities, such as financing
and compensation arrangements, by the end of 2008.
Dated: August 6, 2008
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $12,867 $1,394
Accounts receivable and other 111,182 70,791
Note receivable (Note 3) 49,599 -
Derivative contracts (Note 12) - 3,389
Future income tax asset 21,656 2,602
----------------------------------------------------------------------------
195,304 78,176
Future income tax asset - 4,096
Goodwill (Note 3) 14,235 -
Property, plant and equipment (Notes 3 and 5) 1,014,640 980,888
----------------------------------------------------------------------------
$1,224,179 $1,063,160
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $88,893 $73,135
Note payable (Note 3) 3,935 -
Distributions payable to unitholders 15,242 14,479
Derivative contracts (Note 12) 84,218 12,973
----------------------------------------------------------------------------
192,288 100,587
Bank debt (Note 6) 308,115 275,630
Convertible debentures (Note 7) 75,561 90,876
Derivative contracts (Note 12) 18,049 -
Unit-based incentive compensation (Note 8) 4,489 1,748
Asset retirement obligations (Note 9) 92,032 89,602
Future income tax liability 7,411 -
----------------------------------------------------------------------------
697,945 558,443
Non-controlling interest (Note 10) 55,013 -
Unitholders' equity
Unitholders' capital (Note 11) 1,030,280 969,588
Equity component of convertible debentures (Note
7) 4,737 5,759
Deficit (563,796) (470,630)
----------------------------------------------------------------------------
471,221 504,717
----------------------------------------------------------------------------
$1,224,179 $1,063,160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Trust units outstanding (000s) 95,277 90,494
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF INCOME (LOSS), COMPREHENSIVE INCOME (LOSS) AND
DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
Three months ended Six months ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue
Oil, natural gas and liquid
sales $ 188,297 $ 97,684 $ 334,440 $ 192,565
Crown royalties (28,834) (14,757) (50,682) (29,786)
Freehold and other royalties (10,107) (5,730) (17,570) (11,015)
----------------------------------------------------------------------------
149,356 77,197 266,188 151,764
Gain (loss) on derivative
contracts (Note 12):
Realized gain (loss) (21,730) 848 (27,221) 3,122
Unrealized gain (loss) (70,148) 3,366 (92,683) (4,384)
Reclassification from other
comprehensive income - 1,394 - 2,773
----------------------------------------------------------------------------
(91,878) 5,608 (119,904) 1,511
Other income 1,383 463 2,188 1,224
----------------------------------------------------------------------------
58,861 83,268 148,472 154,499
----------------------------------------------------------------------------
Expenses
Operating 22,443 14,952 43,716 29,078
Transportation 956 594 1,890 1,191
General and administrative 4,539 3,844 8,276 7,759
Unit-based incentive
compensation (Note 8) 1,889 688 2,997 664
Interest on bank debt 3,879 3,137 7,860 5,996
Interest and accretion on
convertible debentures 2,071 - 4,213 -
Depletion, depreciation and
amortization 47,347 34,822 93,059 69,250
Accretion on asset
retirement obligations 1,827 1,302 3,625 2,599
----------------------------------------------------------------------------
84,951 59,339 165,636 116,537
----------------------------------------------------------------------------
Income (loss) before taxes
and non-controlling interest (26,090) 23,929 (17,164) 37,962
Income tax provision (10) (84) (6) (108)
Future income tax reduction
(provision) 12,820 (2,455) 19,348 246
----------------------------------------------------------------------------
Total income tax reduction
(provision) 12,810 (2,539) 19,342 138
----------------------------------------------------------------------------
Income (loss) before
non-controlling interest (13,280) 21,390 2,178 38,100
Non-controlling interest
(Note 10) (4,292) - (6,017) -
----------------------------------------------------------------------------
Net income (loss) (17,572) 21,390 (3,839) 38,100
Other comprehensive income:
Reclassification to net
income, net of tax - (979) - (1,946)
----------------------------------------------------------------------------
Comprehensive income (loss) (17,572) 20,411 (3,839) 36,154
----------------------------------------------------------------------------
Deficit, beginning of period (500,922) (389,382) (470,630) (368,486)
Net income (loss) (17,572) 21,390 (3,839) 38,100
Distributions declared (45,302) (37,877) (89,327) (75,483)
----------------------------------------------------------------------------
Deficit, end of period $ (563,796) $ (405,869) $ (563,796) $ (405,869)
----------------------------------------------------------------------------
Net income (loss) per trust
unit - basic and diluted
(Note 11) $ (0.19) $ 0.27 $ (0.04) $ 0.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average trust units
outstanding (000s) 94,101 78,824 92,909 78,543
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
Three months ended Six months ended
June 30 June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
Operating Activities
Net income (loss) $ (17,572) $ 21,390 $ (3,839) $ 38,100
Items not involving cash:
Depletion, depreciation and
amortization 47,347 34,822 93,059 69,250
Accretion on asset retirement
obligations 1,827 1,302 3,625 2,599
Unrealized loss (gain) on
derivative contracts 70,148 (3,366) 92,683 4,384
Reclassification from other
comprehensive income - (1,394) - (2,773)
Future income tax provision
(reduction) (12,820) 2,455 (19,348) (246)
Non-cash accretion expense on
convertible debentures 464 - 941 -
Non-controlling interest 709 - 956 -
Abandonment and environmental
expenditures (1,525) (1,053) (3,279) (2,923)
Change in non-cash working capital (15,283) 1,865 (20,942) 596
----------------------------------------------------------------------------
73,295 56,021 143,856 108,987
----------------------------------------------------------------------------
Financing Activities
Distributions paid to unitholders (38,256) (37,789) (74,632) (75,305)
Issue of trust units, net of issue
costs - 6,608 (14) 13,165
Increase (decrease) in bank debt (5,255) 3,884 32,485 12,732
Change in non-cash working capital - - (426) 915
----------------------------------------------------------------------------
(43,511) (27,297) (42,587) (48,493)
----------------------------------------------------------------------------
Investing Activities
Acquisition of Tiberius and Spear
(Note 3) (371) - (77,355) -
Disposition of Tiberius and Spear
(Note 3) 115 - 58,222 -
Acquisition of Seneca - - 337 -
Additions to property, plant and
equipment (26,748) (18,925) (56,071) (46,009)
Property acquisitions (1,006) - (7,876) -
Proceeds from dispositions 40 - 40 25
Change in non-cash working capital (4,124) (9,853) (7,093) (15,736)
----------------------------------------------------------------------------
(32,094) (28,778) (89,796) (61,720)
----------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents (2,310) (54) 11,473 (1,226)
Cash and cash equivalents,
beginning of period 15,177 5,123 1,394 6,295
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ 12,867 $ 5,069 $ 12,867 $ 5,069
----------------------------------------------------------------------------
Supplementary disclosure of cash
flow information:
Cash paid during the period for:
Interest $ 3,342 $ 3,069 $ 9,864 $ 5,900
Tax $ 1,971 $ 84 $ 2,579 $ 108
----------------------------------------------------------------------------
Cash and cash equivalents is
comprised of:
Cash $ 2,864 $ 76 $ 2,864 $ 76
Short term investments 10,003 4,993 10,003 4,993
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 12,867 $ 5,069 $ 12,867 $ 5,069
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Six months ended June 30, 2008
(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, 2007, except
as described below. 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, 2007.
2. CHANGES IN ACCOUNTING POLICIES
New Accounting Standards
Effective January 1, 2008 the Trust implemented the provisions of
CICA Handbook Section 1535 "Capital Disclosures", Section 3862
"Financial Instruments - Disclosures", and Section 3863 "Financial
Instruments - Presentation".
Section 1535 establishes standards for disclosing information about
an entity's capital and how it is managed. This Section specifies
disclosure about objectives, policies and processes for managing
capital, quantitative data about what the entity regards as capital,
whether the entity has complied with all capital requirements, and if it
has not complied, the consequences of such non-compliance. Sections
3862 and 3863 establish standards for the presentation and disclosure of
information that enable users to evaluate the significance of financial
instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity
manages those risks.
The implementation of these new standards did not impact the Trust's
financial results but did, however, result in additional disclosures,
as provided in Note 12.
IFRS
In February 2008, the AcSB, confirmed that the changeover to IFRS
from Canadian GAAP will be required for publicly accountable enterprises
interim and annual financial statements effective for fiscal years
beginning on or after January 1, 2011. The AcSB issued the "omnibus"
exposure draft of IFRS with comments due by July 31, 2008, wherein early
adoption by Canadian entities is also permitted. The CSA have also
issued Concept Paper 52-402, which requested feedback on the early
adoption of IFRS as well as the continued use of US GAAP by domestic
issuers. The eventual changeover to IFRS represents a change due to new
accounting standards. The transition from current Canadian GAAP to IFRS
is a significant undertaking that may materially affect the Trust's
reported financial position and results of operations.
The IASB has stated that it plans to issue an exposure draft
relating to certain amendments and exemptions to IFRS 1 in order to make
it more useful to Canadian entities adopting IFRS for the first time.
One such exemption relating to full cost oil and gas accounting is
expected to reduce the administrative burden in the transition from the
current Canadian Accounting Guideline 16 to IFRS. It is anticipated that
this exposure draft will not result in an amended IFRS 1 standard until
late 2009. The amendment will potentially permit the Trust to apply
IFRS prospectively to its full cost pool, rather than the performing
retrospective assessment of capitalized exploration and development
expenses, with the provision that a ceiling test, under IFRS standards,
be conducted at the transition date.
Although the Trust has not completed its IFRS changeover plan, an
initial evaluation of IFRS 1 has been completed. NAL is planning
detailed reviews, in the third quarter, of the significant differences
between IFRS and Canadian GAAP as they apply to the Trust. During the
remainder of 2008, NAL will finalize the changeover plan, which will
include project structure and governance, resourcing and training, a
complete analysis of key GAAP differences and a phased plan to assess
accounting policies under IFRS as well as potential IFRS 1 exemptions.
The Trust anticipates completing its project scoping, which will include
a timetable for assessing the impact on data systems, internal controls
over financial reporting, and business activities, such as financing
and compensation arrangements, by the end of 2008.
Basis of Presentation
The Trust's financial statements include the accounts of the Trust
and all its subsidiaries and partnerships. All inter-entity transactions
and balances have been eliminated. Non-controlling interests in
subsidiaries and partnerships are presented as separate line items on
the consolidated balance sheet and the consolidated statement of income,
comprehensive income and deficit.
Goodwill
Goodwill is recorded on a business acquisition when the total
purchase price exceeds the fair value of the net identifiable assets and
liabilities of the acquired business. The goodwill balance is not
amortized but, instead, is assessed for impairment annually at year end,
or more frequently if events or changes in circumstances indicate the
asset might be impaired. To assess impairment, the fair value of the
reporting entity, deemed to be the consolidated Trust, is compared to
the carrying value of the reporting entity. If the fair value of the
Trust is less than the carrying value, then a second test is performed
to determine the amount of impairment. Any impairment is measured by
allocating the fair value of the consolidated Trust to the identifiable
assets and liabilities as if the Trust had been acquired in a business
combination for a purchase price equal to its fair value. The excess of
the fair value of the consolidated Trust over the amounts assigned to
the identifiable assets and liabilities is the implied value of the
goodwill. Any excess of the book value of goodwill over the implied
value of goodwill is the impairment amount. Any impairment will be
charged to net income in the period in which it occurs.
Comparative Information
Certain comparative figures have been reclassified to conform with current period presentation.
3. CORPORATE ACQUISITIONS
Effective February 27, 2008 the Trust acquired all the issued and
outstanding common shares of Tiberius Exploration Inc ("Tiberius") and
Spear Exploration Inc. ("Spear"), which have interests in southeast
Saskatchewan.
On February 29, 2008, the Trust transferred the assets into a
limited partnership ("Partnership") in exchange for a 50 percent
partnership interest and a note receivable of $3.7 million. A wholly
owned subsidiary of Manulife Financial Corporation ("MFC") acquired the
remaining 50 percent share in the Partnership and a note receivable of
$3.7 million, by payment in cash of one half of the total purchase price
for Tiberius and Spear. Accordingly, the net acquisition cost to the
Trust for its 50 percent share in the acquired properties is $57.8
million, before acquisition costs, comprised of $28.3 million in cash
and $29.5 million from the issuance of 2.4 million trust units at a
price of $12.24 per unit. The unit price was based on the weighted
average market price of the units at the announcement date for the
acquisition of February 11, 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. The equivalent carrying amount of property, plant and
equipment related to this interest in the reserves is recorded on the
books of each royalty holder.
The results of operations from these properties have been included
in the consolidated financial statements of the Trust commencing
February 27, 2008. A subsidiary of the Trust is the general partner
under the partnership agreement governing the Partnership and therefore
controls the Partnership. As a result, the Trust is required to
consolidate the results into its consolidated financial statements, with
the share of net income and net assets attributable to MFC presented as
a non-controlling interest.
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 Total Disposition Trust, net Net to
acquired Acquisition to Manulife Acquisition NPI(1) Trust
----------------------------------------------------------------------------
Cash $ 9,734 $ - $ 9,734 $ - $ 9,734
Working capital
deficiency (5,620) - (5,620) - (5,620)
Notes
receivable, net
from MFC - (3,750) (3,750) 49,599 45,849
Property, plant
and equipment 111,258 - 111,258 (49,599) 61,659
Future income
taxes (23,389) 11,588 (11,801) - (11,801)
Asset
retirement
obligations (1,636) - (1,636) - (1,636)
Goodwill 26,238 (12,003) 14,235 - 14,235
Non-controlling
interest - (54,057) (54,057) - (54,057)
----------------------------------------------------------------------------
$ 116,585 $ (58,222) $ 58,363 $ - $ 58,363
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration:
----------------------------------------------------------------------------
Cash $ 86,118 $ (57,807) $ 28,311 $ - $ 28,311
Issuance of
trust units 29,496 - 29,496 - 29,496
Acquisition
costs 971 (415) 556 - 556
----------------------------------------------------------------------------
$ 116,585 $ (58,222) $ 58,363 $ - $ 58,363
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net profits interest agreement entered into with MFC, in exchange for
a note receivable.
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.
4. RELATED PARTY TRANSACTIONS
The Trust is managed by the Manager. The Manager is a wholly-owned
subsidiary of MFC and manages on their behalf NAL Resources Limited
("NAL Resources"), another wholly-owned subsidiary of Manulife. The
disposition of a 50 percent interest in the Partnership holding the
Tiberius and Spear assets was to MFC, as outlined in Note 3.
The Manager provides certain services to the Trust pursuant to a
management contract. This contract 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 $3.5
million (2007 - $3.1 million) for the reimbursement of G&A expenses
during the second quarter, and $6.5 million (2007 - $6.0 million)
year-to-date. The Trust also pays the Manager its share of unit-based
compensation expense when cash compensation is paid to employees under
the terms of the Plan, of which $1.8 million has been paid year-to-date,
representing units that vested on November 30, 2007 (2007 - $2.2
million).
The notes payable and receivable due to/from MFC, are due on demand
and bear interest at prime plus three percent. Net interest of $1.2
million relating to these notes was received by the Trust for the six
months ended June 30, 2008 and is reported as other income.
The following amounts are due to and from related parties as at June
30, 2008 and have been included in accounts receivable, note
receivable, accounts payable and accrued liabilities, and note payable
on the balance sheet:
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Due from NAL Resources Limited $ 26,431 $ 14,203
Due to NAL Resources Management Limited (1,507) (2,826)
Due from Manulife Financial Corporation(1) 43,631 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 68,555 $ 11,377
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included on consolidation, eliminated through non-controlling interest.
5. PROPERTY, PLANT AND EQUIPMENT
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Petroleum and natural gas properties, at cost $ 1,814,142 $ 1,687,331
Less: Accumulated depletion and depreciation (799,502) (706,443)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$ 1,014,640 $ 980,888
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Costs associated with undeveloped land of $26.7 million (2007 -
$nil) have been excluded from the depletion calculation for the six
months ended June 30, 2008.
Future development costs for proved reserves of $49.8 million (2007 -
$27.3 million) have been included in the depletion calculation.
During 2008, the Trust capitalized $2.3 million (2007 - $2.4
million) of G&A costs and $1.5 million (2007 - $0.2 million) of
unit-based incentive compensation that were directly related to
exploitation and development programs.
6. BANK DEBT
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Production loan facility $ 302,908 $ 273,528
Working capital facility 5,207 2,102
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total debt outstanding $ 308,115 $ 275,630
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust maintains a fully secured, extendible, revolving term
credit facility with a syndicate of Canadian chartered banks. The
current facility consists of a $390 million production facility and a
$10 million working capital facility. The current bank group has agreed
to expand the bank group by two banks and increase the production
facility, by $50 million, to $440 million while maintaining the current
working capital facility of $10 million, subject to final documentation
approval. 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 a function of the net present value of the Trust's oil
and gas reserves and other assets.
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 29, 2009 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
2009, the amounts outstanding at that time will be converted to a
two-year term loan. The term loan will be payable in four equal
quarterly installments commencing May 2010 with a final residual
payment, if any, in May 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 June 30, 2008
and December 31, 2007 all amounts outstanding were in Canadian dollars.
On June 30, 2008 the effective interest rate on amounts outstanding
under the credit facility was 4.57 percent (2007 - 5.41 percent).
7. CONVERTIBLE DEBENTURES
The following table reconciles the principal amount, debt component and equity component of the convertible debentures.
Principal amount Debt component Equity component
of debentures of debentures of debentures
----------------------------------------------------------------------------
August 28, 2007 issuance $ 100,000 $ 94,241 $ 5,759
Issue costs - (4,000) -
Accretion - 635 -
----------------------------------------------------------------------------
Balance, December 31, 2007 100,000 90,876 5,759
Conversion to trust units (17,741) (16,256) (1,022)
Accretion - 941 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, June 30, 2008 $ 82,259 $ 75,561 $ 4,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. UNIT-BASED INCENTIVE COMPENSATION PLAN
The Trust recorded a total compensation expense of $4.5 million in
the first six months of 2008, of which $3.0 million was recorded as an
expense and $1.5 million as property, plant and equipment ($2.1 million
expensed and $0.9 million as property, plant and equipment for the year
ended December 31, 2007). The compensation expense was based on the June
30, 2008 trust unit price of $16.89 (2007 - $11.60), accrued
distributions, performance factors, and the number of units vesting on
maturity.
The following table reconciles the change in total accrued trust unit based incentive compensation relating to the plan:
Six months ended Year ended
June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
Balance, beginning of period $ 4,996 $ 4,153
Increase in liability 4,487 3,027
Cash payout, relating to units vested (1,767) (2,184)
----------------------------------------------------------------------------
Balance, end of period 7,716 $ 4,996
----------------------------------------------------------------------------
Current portion of liability(1) 3,227 $ 3,248
----------------------------------------------------------------------------
Long-term liability $ 4,489 $ 1,748
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.
9. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligation was estimated by the
Manager based on the Trust's net ownership interests in oil and natural
gas assets including well sites, gathering systems and processing
facilities, estimated costs to remediate, reclaim and abandon the wells
and facilities and the estimated timing of the costs to be incurred in
future periods. NAL has estimated the net present value of its asset
retirement obligations to be $92.0 million as at June 30, 2008 (2007 -
$89.6 million) based on a total undiscounted and inflated amount of cash
flows required to settle its asset retirement obligations of $276.6
million (2007 - $270.5 million). These costs are expected to be made
over the next 44 years with the majority of the costs incurred between
2008 and 2033. NAL's credit-adjusted risk-free rate of eight percent
(2007 - eight percent) and an inflation rate of two percent (2007 - two
percent) were used to calculate the present value of the asset
retirement obligations.
The following table reconciles the Trust's asset retirement obligations.
Six months ended Year ended
June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
Balance, beginning of period $ 89,602 $ 65,574
Accretion expense 3,625 5,533
Revisions to estimates (261) 10,294
Liabilities incurred 709 1,079
Liabilities acquired (Note 3) 1,636 12,625
Liabilities settled (3,279) (5,503)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of period $ 92,032 $ 89,602
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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. The non-controlling interest in the statement of income is
comprised of:
Three months ended Six months ended
June 30 June 30
----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Net profits interest $3,583 $ - $5,061 $ -
Share of net income attributable to
MFC 709 - 956 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$4,292 $ - $6,017 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. UNITHOLDERS EQUITY
Units Issued:
Six months ended Year ended
June 30, 2008 December 31, 2007
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of the period 90,494 $ 969,588 77,971 $824,986
Issued on corporate acquisition
(Note 3) 2,409 29,496 10,246 125,001
Less issue expenses (14) (7,134)
Issued from Distribution Reinvestment
Plan 1,107 13,932 2,277 26,735
Issued on conversion of debentures 1,267 17,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of the period 95,277 $1,030,280 90,494 $969,588
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Unit Information
Basic net income (loss) per trust unit is calculated using the
weighted average number of trust units outstanding. The calculation of
diluted net income (loss) per trust unit excludes the convertible
debentures as the trust units potentially issuable on the conversion of
the convertible debentures are anti-dilutive for the three and six
months ended June 30, 2008. Total weighted average trust units issuable
on conversion of the convertible debentures and excluded from the
diluted net income (loss) per trust unit calculation for the three and
six months ended June 30, 2008 were 6,815,850 and 6,979,354,
respectively.
12. FINANCIAL RISK MANAGEMENT
Overview
The Trust has exposure to the following risks from its use of
financial instruments: credit risk, liquidity risk and market risk.
This note presents information about the Trust's exposure to each of
the above risks, the Trust's objectives, policies and processes for
measuring and managing risk, and the Trust's management of capital.
Further quantitative disclosures are included throughout these financial
statements.
The Board of Directors has the responsibility to understand the
principal risks of the business and to achieve a proper balance between
the risks incurred and the potential return to Unitholders. The Board of
Directors have oversight for ensuring systems are in place which
effectively monitor and manage those risks with a view to the long term
viability of the Trust.
Credit Risk
Credit risk is the risk of financial loss to the Trust if a customer
or counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Trust's receivables. The
Trust is managed by the Manager. The Manager is a wholly-owned
subsidiary of MFC and manages on their behalf 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 operator. As a result, a significant
portion of the Trust's net operating revenues represent joint operations
from NAL Resources. Accordingly, accounts receivable include amounts
due from NAL Resources for oil, natural gas and natural gas liquids
sales. Oil and gas marketing is conducted by the Manager on behalf of
the Trust and NAL Resources generally with large creditworthy
purchasers, for which the Trust views the credit risk as low. Except as
noted below, NAL Resources, and ultimately the Trust, have not
historically experienced any collection issues with its oil and gas
marketers. The Manager does not obtain collateral from oil and natural
gas marketers or joint venture partners.
Cash and cash equivalents consist of cash bank balances and
short-term deposits maturing in less than 90 days. The Trust manages the
credit exposure related to short-term investments by selecting
established counter parties with high credit ratings and monitors all
investments, avoiding complex investment vehicles with higher risks such
as asset backed commercial paper.
The Trust does not have an allowance for doubtful accounts as at
June 30, 2008 and did not write-off any receivables during the first
half of 2008. The Trust does not have any receivable balances past due
as at June 30, 2008.
On July 22, 2008 SemCanada Crude Company ("SemCanada") filed
application for creditor protection under the Companies Creditors
Arrangement Act in Canada. SemCanada marketed a portion of the Trust's
oil, butane and condensate sales. NAL estimates that it has a maximum
net potential exposure of $7.0 million. A reasonable determination of
impairment, if any, cannot yet be made. NAL management has concluded
that its existing credit policy remains appropriate with the exception
of more regular review of purchasers. The events for this particular
credit issue could not have been foreseen. However, management is
currently reviewing all existing purchasers against its credit policy to
ensure credit worthiness given the current market conditions.
Liquidity Risk
Liquidity risk is the risk that the Trust will not be able to meet
its financial obligations as they are due. The Trust manages liquidity
by ensuring, as far as possible, that it will have sufficient liquidity
under both normal and stressed conditions.
The Trust prepares annual capital expenditure budgets, which are
regularly monitored and updated as necessary. As well, the Manager
utilizes authorizations for expenditure on both operated and
non-operated projects. Furthermore, the Manager operates a high
percentage of the Trust's properties, which allows for significant
control over future expenditures. To support the capital spending
program, the Trust maintains a fully secured, extendible, revolving term
credit facility, as outlined in Note 6.
The following are the contractual maturities of financial liabilities and associated interest payments as at June 30, 2008.
Financial Liability less than 1 Year 1-2 Years 2-5 Years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 88,893 $ - $ -
Distributions payable 15,242 - -
Unit-based incentive compensation - 3,839 650
Note payable 3,935 - -
Derivative contracts 84,218 18,049 -
Bank debt, principal (May 2010) - 77,029 231,086
Convertible debentures, principal - - 82,259
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total $192,288 $98,917 $313,995
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amount due within one year classified in accounts payable and accrued
liabilities.
Market risk
Market risk is the risk that changes in market prices, such as
foreign exchange rates, commodity prices, and interest rates will affect
the Trust's net income or the value of financial instruments.
Foreign currency exchange rate risk
Foreign currency exchange rate risk is the risk that the fair value
or future cash flows will fluctuate as a result of changes in foreign
exchange rates. Although substantially all of the Trust's oil and
natural gas sales are denominated in Canadian dollars, the underlying
market prices in Canada for oil and natural gas are impacted by changes
in the exchange rate between the Canadian and U.S. dollar. As at June
30, 2008, if the Canadian dollar had weakened $0.10 against the U.S.
dollar, with all other variables held constant, net income would have
been $3.4 million lower due to changes in the foreign exchange component
of U.S. dollar denominated commodity contracts. An equal and opposite
impact would have occurred to net income had the Canadian dollar
improved $0.10 against the U.S. dollar.
The Trust had no material foreign exchange related derivative
contracts in place as at, or during the six months ended, June 30, 2008.
Commodity price risk
Commodity price risk is the risk that the fair value or future cash
flows will fluctuate as a result of changes in commodity prices.
Commodity prices for oil and natural gas are impacted by not only the
relationship between the Canadian and U.S. dollar, but also
macroeconomic events that dictate the levels of supply and demand. The
Trust has attempted to mitigate commodity price risk by entering into
financial derivative contracts. The Trust's policy is to enter into
commodity contracts to a maximum of 50 percent of forecasted, net of
royalty, production volumes for a period of up to two years.
NAL currently has the following WTI oil contracts in place for 2008,
denominated in U.S. dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls U.S.$/bbl U.S.$/bbl U.S.$/bbl
----------------------------------------------------------------------------
COLLARS
July-December 2-way 100 18,400 85.00 100.00 -
July-December 2-way 100 18,400 83.00 100.00 -
July-December 2-way 100 18,400 75.00 85.50 -
July-December 2-way 100 18,400 76.00 87.00 -
July-December 2-way 100 18,400 94.00 100.50 -
July-December 2-way 100 18,400 92.00 101.50 -
----------------------------------------------------------------------------
Weighted Average 110,400 84.17 95.75 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls U.S.$/bbl U.S.$/bbl U.S.$/bbl
----------------------------------------------------------------------------
SWAPS
July-December swap 100 18,400 - - 73.50
July-December swap 100 18,400 - - 94.00
July-December swap 100 18,400 - - 92.18
July-December swap 100 18,400 - - 87.10
July-December swap 100 18,400 - - 79.10
July-December swap 100 18,400 - - 71.00
July-December swap 100 18,400 - - 80.75
July-October swap 100 12,300 - - 88.10
July-December swap 100 18,400 - - 94.50
July-December swap 100 18,400 - - 94.04
July-December swap 100 18,400 - - 92.00
July-December swap 100 18,400 - - 98.50
July-December swap 100 18,400 - - 98.25
July-December swap 100 18,400 - - 98.10
July-December swap 100 18,400 - - 97.25
July-December swap 100 18,400 - - 96.75
July-December swap 100 18,400 - - 100.00
November-
December swap 100 6,100 - - 100.03
November-
December swap 100 6,100 - - 103.00
July-December swap 100 18,400 - - 108.00
----------------------------------------------------------------------------
Weighted Average 337,300 - - 91.71
----------------------------------------------------------------------------
NAL currently has the following WTI oil contracts in place for 2008,
denominated in Canadian dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
----------------------------------------------------------------------------
COLLARS
July-December 2-way 100 18,400 85.00 94.40 -
July-December 2-way 100 18,400 85.00 96.00 -
July-December 2-way 100 18,400 87.10 97.35 -
July-December 2-way 100 18,400 72.40 77.54 -
July-December 2-way 100 18,400 103.00 132.75 -
July-December 2-way 100 18,400 104.00 134.75 -
July-December 2-way 100 18,400 107.00 130.45 -
----------------------------------------------------------------------------
Weighted Average 128,800 91.93 109.03 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
----------------------------------------------------------------------------
SWAPS
July-December swap 100 18,400 - - 84.90
July-December swap 100 18,400 - - 90.05
July-December swap 100 18,400 - - 90.15
July-December swap 100 18,400 - - 90.05
July-December swap 100 18,400 - - 90.20
July-December swap 100 18,400 - - 89.05
July-December swap 100 18,400 - - 87.00
July-December swap 100 18,400 - - 83.80
July-December swap 100 18,400 - - 73.55
July-December swap 100 18,400 - - 93.00
July-December swap 100 18,400 - - 90.70
July-December swap 100 18,400 - - 91.00
July-October swap 100 12,300 - - 87.50
July-December swap 100 18,400 - - 96.50
July-December swap 100 18,400 - - 97.00
July-December swap 100 18,400 - - 94.00
July-December swap 200 36,800 - - 97.00
July-December swap 100 18,400 - - 98.50
July-December swap 100 18,400 - - 110.50
----------------------------------------------------------------------------
Weighted Average 361,900 - - 91.64
----------------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place for
2008:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
November-
December 2-way 1,000 61,000 7.30 8.50 -
November-
December 2-way 1,000 61,000 7.75 9.05 -
November-
December 2-way 1,000 61,000 7.55 9.10 -
November-
December 2-way 1,000 61,000 7.55 9.05 -
November-
December 2-way 1,000 61,000 7.30 8.60 -
November-
December 2-way 1,000 61,000 7.85 9.25
November-
December 2-way 1,000 61,000 8.00 9.50 -
November-
December 2-way 1,000 61,000 8.00 9.50 -
November-
December 2-way 1,000 61,000 8.25 9.50 -
November-
December 2-way 1,000 61,000 8.25 9.75 -
November-
December 2-way 1,000 61,000 8.25 10.00 -
July-
October 2-way 1,000 123,000 8.50 11.00 -
November-
December 2-way 1,000 61,000 9.00 12.00 -
----------------------------------------------------------------------------
Weighted Average 855,000 8.00 9.70 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
SWAPS
July-December swap 2,000 368,000 - - 7.60
July-December swap 1,000 184,000 - - 7.40
July-December swap 2,000 368,000 - - 7.40
July-December swap 1,000 184,000 - - 7.31
July-December swap 2,000 368,000 - - 7.26
July-December swap 1,000 184,000 - - 7.05
July-December swap 1,000 184,000 - - 7.20
July-December swap 1,000 184,000 - - 7.10
July-December swap 1,000 184,000 - - 7.15
July-December swap 1,000 184,000 - - 7.10
July-December swap 1,000 184,000 - - 7.05
July-December swap 1,000 184,000 - - 7.23
July-October swap 1,000 123,000 - - 7.35
July-October swap 1,000 123,000 - - 7.60
July-October swap 1,000 123,000 - - 7.85
July-December swap 1,000 184,000 - - 7.30
July-October swap 1,000 123,000 - - 7.65
July-October swap 1,000 123,000 - - 7.43
July-December swap 1,000 184,000 - - 7.10
July-October swap 1,000 123,000 - - 7.20
July-October swap 1,000 123,000 - - 7.09
July-October swap 1,000 123,000 - - 7.80
November-
December swap 1,000 61,000 - - 8.66
July-October swap 1,000 123,000 - - 7.90
July-October swap 1,000 123,000 - - 8.02
July-October swap 1,000 123,000 - - 8.25
July-October swap 1,000 123,000 - - 8.40
----------------------------------------------------------------------------
Weighted Average 4,665,000 - - 7.42
----------------------------------------------------------------------------
For 2009, NAL has the following WTI oil contracts in place, denominated in
U.S. dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls U.S.$/bbl U.S.$/bbl U.S.$/bbl
----------------------------------------------------------------------------
COLLARS
January-
December 2-way 100 36,500 92.00 101.50 -
January-June 2-way 100 18,100 94.00 100.50 -
January-June 2-way 100 18,100 95.00 105.00 -
January-June 2-way 100 18,100 110.00 152.40 -
April-September 2-way 100 18,300 100.00 157.50 -
January-June 2-way 100 18,100 115.00 162.00 -
April-September 2-way 100 18,300 110.00 170.00 -
January-June 2-way 200 36,200 110.00 176.50 -
July-December 2-way 200 36,800 115.00 164.25 -
January-June 2-way 200 36,200 115.00 167.65 -
July-December 2-way 200 36,800 110.00 173.00 -
January-
December 2-way 100 36,500 120.00 175.00 -
July-December 2-way 100 18,400 120.00 181.50 -
January-June 2-way 100 18,100 120.00 182.25 -
----------------------------------------------------------------------------
Weighted Average 364,500 109.91 156.39 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls U.S.$/bbl U.S.$/bbl U.S.$/bbl
----------------------------------------------------------------------------
SWAPS
January-June swap 100 18,100 - - 97.25
January-December swap 100 36,500 - - 96.75
January-June swap 100 18,100 - - 100.00
January-June swap 100 18,100 - - 100.03
January-June swap 100 18,100 - - 103.00
January-December swap 100 36,500 - - 102.00
January-June swap 100 18,100 - - 97.50
January-June swap 100 18,100 - - 102.00
January-March swap 100 9,000 - - 101.50
April-June swap 100 9,100 - - 103.25
April-June swap 100 9,100 - - 103.27
January-June swap 100 18,100 - - 104.25
July-September swap 100 9,200 - - 105.00
July-December swap 200 36,800 - - 134.89
----------------------------------------------------------------------------
Weighted Average 272,900 - - 105.24
----------------------------------------------------------------------------
For 2009, NAL has the following WTI oil contracts in place, denominated in
Canadian dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbl/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
----------------------------------------------------------------------------
COLLARS
January-June 2-way 100 18,100 100.00 115.00 -
January-June 2-way 100 18,100 100.00 114.00 -
January-June 2-way 100 18,100 100.00 113.05 -
January-May 2-way 100 15,100 103.00 132.75 -
January-
December 2-way 100 36,500 115.00 140.50
----------------------------------------------------------------------------
Weighted Average 105,900 105.60 125.82 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbl/d Bbls Cdn$/bbl Cdn$/bbl Cdn$/bbl
----------------------------------------------------------------------------
SWAPS
January-
September swap 100 27,300 - - 96.50
January-
December swap 200 73,000 - - 97.00
January-
September swap 100 27,300 - - 97.00
January-March swap 100 9,000 - - 102.00
January-March swap 100 9,000 - - 102.75
January-March swap 100 9,000 - - 106.10
April-June swap 100 9,100 - - 105.10
January-March swap 100 9,000 - - 105.02
January-March swap 100 9,000 - - 106.05
April-June swap 100 9,100 - - 105.50
April-September swap 100 18,300 - - 108.00
----------------------------------------------------------------------------
Weighted Average 209,100 - - 100.21
----------------------------------------------------------------------------
For 2009, NAL has the following AECO natural gas contracts in place:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
January-March 2-way 1,000 90,000 8.00 9.50 -
January-March 2-way 1,000 90,000 7.75 9.05 -
January-March 2-way 1,000 90,000 7.85 9.25 -
January-March 2-way 1,000 90,000 7.55 9.10 -
January-March 2-way 1,000 90,000 7.55 9.05 -
January-March 2-way 1,000 90,000 7.30 8.60 -
January-March 2-way 1,000 90,000 7.30 8.50 -
January-March 2-way 1,000 90,000 8.00 9.50 -
January-March 2-way 1,000 90,000 8.25 9.50 -
January-March 2-way 1,000 90,000 8.25 9.75 -
January-March 2-way 1,000 90,000 8.25 10.00 -
January-March 2-way 1,000 90,000 8.50 10.00 -
January-March 2-way 1,000 90,000 8.50 9.50 -
January-March 2-way 1,000 90,000 8.65 9.75 -
January-March 2-way 1,000 90,000 8.75 9.75 -
January-March 2-way 1,000 90,000 9.00 12.00
April-October 2-way 1,000 214,000 8.50 11.26 -
April-October 2-way 1,000 214,000 9.00 11.25 -
April-October 2-way 1,000 214,000 9.00 11.55 -
April-October 2-way 1,000 214,000 9.00 12.10 -
April-October 2-way 1,000 214,000 9.00 11.05 -
----------------------------------------------------------------------------
Weighted Average 2,510,000 8.44 10.36 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
SWAPS
January-March swap 1,000 90,000 - - 7.40
January-March swap 1,000 90,000 - - 7.05
January-March swap 1,000 90,000 - - 7.05
January-March swap 1,000 90,000 - - 7.10
January-March swap 1,000 90,000 - - 7.15
January-March swap 1,000 90,000 - - 7.23
January-March swap 1,000 90,000 - - 7.31
January-March swap 1,000 90,000 - - 7.30
January-March swap 1,000 90,000 - - 8.66
January-March swap 1,000 90,000 - - 9.00
January-March swap 1,000 90,000 - - 9.10
January-March swap 1,000 90,000 - - 9.16
January-March swap 1,000 90,000 - - 9.23
April-October swap 1,000 214,000 - - 8.00
April-October swap 1,000 214,000 - - 10.00
----------------------------------------------------------------------------
Weighted Average 1,598,000 - - 8.20
----------------------------------------------------------------------------
These contracts and the contracts expired for the six months ended
June 30, 2008 resulted in settlement losses of $27.2 million (2007 -
$3.1 million gain). The unrealized gain or loss from derivative
contracts has been included on the balance sheet with changes in the
fair value reported separately on the statement of income. As at June
30, 2008, 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 $2.4
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
Interest rate risk is the risk that future cash flows will fluctuate
as a result of changes in market interest rates. The Trust is exposed
to interest rate fluctuations on its bank debt, which bears a floating
rate of interest. As at June 30, 2008, if interest rates had been one
percentage point lower, with all other variables held constant, net
income for the quarter would have been $0.7 million ($1.3 million for
the six months ended June 30, 2008) higher, due to lower interest
expense. An equal and opposite impact would have occurred to net income
had interest rates been one percentage point higher.
The Trust had no interest related derivative contracts in place as at, or during the six months ended, June 30, 2008.
Fair Values
The carrying amount of the Trust's financial instruments, including
accounts receivable, accounts payable and accrued liabilities, and
distributions payable, approximate their fair value due to their short
term to maturity.
The notes payable and receivable due to/from MFC, are due on demand
and bear interest at prime plus three percent. As the notes bear
interest at a floating market rate, the fair market value approximates
the carrying amount.
The Trust's bank debt and cash and cash equivalents bear interest at
floating market rates and, accordingly, the fair market value
approximates the carrying amount.
The fair value of the Trust's convertible debentures at June 30, 2008 was $98.4 million, based on market price.
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 derivative
contracts is determined by discounting the difference between the
contracted prices and published forward curves as of the balance sheet
date, using the remaining contracted oil and natural gas volumes.
Six months ended Year ended
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Long term unrealized loss on derivative contracts $ (18,049) $ -
Current unrealized gain on derivative contracts - 3,389
Current unrealized loss on derivative contracts (84,218) (12,973)
----------------------------------------------------------------------------
Current unrealized loss on derivative contracts (84,218) (9,584)
----------------------------------------------------------------------------
Fair value of derivative contracts $(102,267) $ (9,584)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2008, the total fair value of derivative contracts
was a liability of $102.3 million. The change in the fair value for six
months ended June 30, 2008 of $92.7 million has been recognized as an
unrealized loss in the statement of income.
The following table reconciles the movement in the fair value of the Trust's derivative contracts:
Three months ended Six months ended
June 30 June 30
-----------------------------------------
2008 2007 2008 2007
----------------------------------------------------------------------------
Unrealized loss, beginning of
period $ (32,119) $ (3,229) $ (9,584) $ -
Unrealized gain on adoption of new
accounting standards - - - 4,521
Unrealized gain (loss), end of
period (102,267) 137 (102,267) 137
----------------------------------------------------------------------------
Unrealized gain (loss) (70,148) 3,366 (92,683) (4,384)
Realized gain (loss) in the period (21,730) 848 (27,221) 3,122
Reclassification from other
comprehensive income - 1,394 - 2,773
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gain (loss) on derivative contracts $ (91,878) $ 5,608 $ (119,904) $ 1,511
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Management
The Trust's policy is to maintain a strong and flexible capital base
to ensure that distribution levels are sustainable, while at the same
time providing the flexibility to take advantage of operational and
acquisition opportunities.
The Trust manages its capital structure and makes adjustments to it
in light of changes in economic conditions and the risk characteristics
of the underlying oil and natural gas assets. The Trust considers its
capital structure to include unitholders' capital, bank debt,
convertible debentures and working capital (excluding derivative
contracts, notes with MFC and future income tax). In order to maintain
or adjust its capital structure, the Trust may adjust the amount of
distributions paid to unitholders, issue new trust units, adjust its
capital spending to modify debt levels, or suspend/resume its DRIP or
premium DRIP programs.
The Trust monitors its capital based on the ratio of its net debt to
12 months trailing funds from operations. This ratio is calculated as
net debt as a proportion of funds from operations for the previous 12
months. Funds from operations is defined as cash flow from operating
activities prior to the change in non-cash working capital. Net debt is
defined as bank debt, plus convertible debentures at face value, plus
working capital (excluding derivative contracts, notes with MFC and
future income tax balances). Net debt is measured with and without
convertible debentures. The Trust's strategy is to maintain a
conservative net debt to 12 month trailing funds from operations as
compared to other oil and gas trusts, both before and after taking into
account the convertible debentures. The Trust will, for the appropriate
opportunity, increase its debt to funds from operations ratio above the
Trust's average. In order to facilitate the management of this ratio,
the Trust prepares an annual budget which is approved by the Board of
Directors. On a monthly basis a reforecast for the year is prepared
based on updated commodity prices, results of operational activity and
other events. The monthly forecast is provided to the Board of
Directors.
As at June 30, 2008, the Trust had a net debt to 12 months trailing
funds from operations ratio of 1.35 to 1.0, as calculated in the table
below. At December 31, 2007, the Trust had a net debt to 12 months
trailing funds from operations ratio of 1.79 to 1, primarily
attributable to borrowings incurred to fund the Seneca acquisition.
The credit facility is determined by reference to the reserves of
the Trust (see Note 6) and is therefore commodity price sensitive. The
Trust is restricted under its credit facility from making distributions
to its unitholders in excess of its consolidated operating cash flow
during the 18 month period preceding the distribution date. As at June
30, 2008, the Trust is in full compliance with this external restriction
on distributions.
The Trust has no restrictions on the issuance of units other than the authorized limit of 500 million.
There has been no change in the approach to capital management during 2008.
Capitalization
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Trust unit equity ($000s) 471,221 504,717
Bank debt ($000s) 308,115 275,630
Working capital deficit (surplus)(1) ($000s) (19,914) 15,429
----------------------------------------------------------------------------
Net debt 288,201 291,059
Convertible debentures ($000s)(2) 82,259 100,000
----------------------------------------------------------------------------
Total net debt ($000s) (2) 370,460 391,059
Cash flow from operating activities for last 12
months ($000s) 250,233 215,364
Add back change in non-cash working capital ($000s) 24,919 3,381
----------------------------------------------------------------------------
Trailing 12 months funds from operations ($000s) 275,152 218,745
Net debt to trailing 12 month funds from
operations(3) 1.05 1.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total net debt to trailing 12-month funds from
operations(2) 1.35 1.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital excludes derivative contracts, the future income tax
asset and the notes receivable/payable with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt excluding convertible debentures divided by funds
from operations for the previous 12 months.
----------------------------------------------------------------------------
TRADING PERFORMANCE
For the Quarter Ended
30-Jun-08 31-Mar-08 30-Jun-07 31-Mar-07
----------------------------------------------------------------------------
PRICE
High $17.09 $13.47 $13.80 $13.00
Low $13.12 $10.81 $11.45 $10.86
Close $16.89 $13.25 $12.57 $11.75
Daily Average Volume 447,401 321,650 247,533 256,104
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NAL Oil & Gas Trust is an open-ended investment trust that
generates distributions through the acquisition, development, production
and marketing of oil, natural gas and natural gas liquids. The Trust
owns high quality assets in British Columbia, Alberta, Saskatchewan and
Ontario. Trust units trade on the Toronto Stock Exchange under the
symbol "NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Investor Relations
(403) 294-3600 or Toll Free: 1-888-223-8792
Email: Investor.Relations@nal.ca
Website: www.nal.ca