CALGARY, ALBERTA--(Marketwire - Feb. 28,
2008) - NAL Oil & Gas Trust (TSX:NAE.UN) ("NAL" or the "Trust")
today announced its financial and operational results for the fourth
quarter and year ended December 31, 2007 as well as 2007 year end
reserves. All amounts are in Canadian dollars unless otherwise stated.
HIGHLIGHTS
NAL was successful in achieving all of its key performance
objectives for 2007. The Trust delivered strong operating and financial
performance, added opportunities, improved reserves replacement, lowered
finding and development costs, completed a strategic acquisition, and
maintained financial flexibility.
2007 Operating and Financial Performance
- The $245.7 million acquisition of Seneca Energy Canada Inc.
("Seneca") in September, 2007 added natural gas production in NAL's East
Central Alberta core area, a significant amount of undeveloped acreage
in West Central Alberta, and opened up a new opportunity area at
Monkman, B.C. The Trust added new geological and geophysical leadership
and retained Seneca's experienced technical team who will continue to
focus on new opportunities.
- Fourth quarter 2007 production volumes averaged 23,413 boe/d,
equally weighted between liquids and natural gas. Volume performance set
a new record for NAL, reflecting the first full quarter of Seneca
production. 2007 full year production averaged 20,501 boe/d, on track
with guidance. Excluding the volumes acquired with Seneca, production
averaged 19,037 boe/d, exceeding the 18,500 - 19,000 boe/d guidance that
the Trust provided in January, 2007.
- Crude oil prices, expressed in US$WTI, increased significantly
during 2007 but those increases were partly offset by lower natural gas
prices and the strengthening of the Canadian dollar. NAL's realized
price was relatively flat year over year at $54.88 per boe. The Trust's
royalty rate was essentially unchanged at 21.7 percent in 2007 and
higher costs related to Seneca volumes led to operating costs being
slightly higher than guidance at $9.34 per boe. Overall operating
netbacks before hedging gains or losses were flat at $34.57 per boe in
2007 versus $34.59 per boe in 2006.
- Revenue and funds from operations were largely unchanged in 2007.
Funds flow from operations per unit decreased by eight percent to $2.65
per unit, compared to $2.88 per unit in 2006. This decrease reflects the
issue of 2.3 million units under the DRIP program during the year, and
10.2 million units that were issued to finance a portion of the purchase
of Seneca, effective September 1, 2007. On a weighted average basis,
units outstanding were 82.6 million in 2007, compared to 76.4 million
units in 2006, an increase of eight percent. NAL maintained
distributions of $0.16 per month for a total of $1.92 per unit in 2007,
representing a lower payout ratio of 73 percent versus 77 percent in
2006.
- Excluding acquisitions, capital spending totaled $118.0 million in
2007, down slightly from $123.0 million in 2006. Of the $118.0 million,
$111.3 million was spent on exploration and development which was
comprised of $95.3 million in drilling, completions and tie-ins, with
$10.0 million spent on facilities and $6.0 million on land and seismic,
with significant focus on oil core areas of Southeast Saskatchewan.
- The Trust's $245.7 million acquisition of Seneca was financed with
$125.0 million in new equity and $100.0 million in the form of
convertible debentures, with the balance funded through bank debt. Net
bank debt, excluding the debentures, totaled $291.0 million at year end
representing a multiple of 1.1 times NAL's base case cash flow for 2008.
The Trust had $400.0 million in committed bank lines at year end,
resulting in over $100.0 million in unused borrowing capacity.
- NAL increased its inventory of undeveloped land by nearly 100,000
net acres in 2007. After expirees, the undeveloped land at December 31,
2007 totaled 304,479 net acres, an increase of 48 percent from 205,916
net acres at December 31, 2006.
- As to risk management, the Trust continues with its strategy to
layer in forward sale positions to protect cash flows, capital programs
and distributions. For 2008, the Trust has hedged 37 percent of its
forecast oil production (47 percent of net production after royalty)
through swaps and collars. Currently, the Trust's swap positions average
$87.40 in contracted U.S. dollars and $87.10 in contracted Canadian
dollars with collars being $74.93 - $83.58 in U.S dollars and $80.53 -
$88.73 contracted in Canadian dollars. In natural gas, current hedges
represent 30 percent (38 percent of net production after royalty), 90
percent with swaps averaging Cdn$7.38 per GJ and 10 percent with collars
with a Cdn$7.98 per GJ floor and $9.57 ceiling.
- NAL continued to build tax pool balances in 2007, finishing the
year with a total of $697.8 million, up 41 percent from $494.0 million
at year end 2006. Tax pools are forecast to grow while NAL remains a
trust, allowing it to shelter a portion of its future income from
taxation after 2010.
2007 RESERVES ADDED / FINDING AND DEVELOPMENT COSTS
- NAL improved its reserves added performance significantly during
2007. Year end proved plus probable reserves increased 17.2 percent from
58.2 million boe at year end 2006 to 68.2 million boe at the end of
2007 due to the Seneca acquisition and performance of our core areas.
Overall, the Trust replaced 234 percent of its production. Excluding
acquisitions, the replacement of production through discoveries,
extensions, infill drilling, well recompletions and technical revisions
increased from 25 percent in 2006 to 96 percent in 2007.
- At year end 2007, NAL's total reserves base continues to be
relatively conservative with a high percentage of proved to total proved
plus probable reserves (73 percent) with the proved producing reserves
representing 95 percent of the total proved category. The reserves mix
remains relatively consistent with NAL's current production at 41
percent crude oil, 10 percent natural gas liquids and 49 percent natural
gas.
- The Trust delivered solid finding and development costs
performance in 2007 with $13.99 per boe proved and $17.71 per boe proved
plus probable, including changes in future development costs,
representing a proved plus probable recycle ratio of 1.95 times.
Including the effects of acquisitions, the finding, development and
acquisition costs were $23.20 per boe proved and $21.67 on a proved plus
probable basis.
- At the end of 2007, NAL's reserve life index was 8.2 years,
remaining relatively consistent with the historical range of 8.0 to 8.6
years over the past five years.
- On a per unit basis, proved plus probable reserves per unit
increased from 0.747 boe at the end of 2006 to 0.754 boe at the end of
2007.
OUTLOOK FOR 2008
- On January 23, 2008, NAL provided guidance for full year 2008 with
production volumes and funds from operations forecast to be higher than
in 2007. The capital program will be consistent with 2007 spending
levels while rig and service costs are expected to be lower. NAL has
increased its inventory of opportunities significantly by adding new
prospecting capability, broadening opportunities and extensions in our
core areas, and working through the new prospects acquired in the Seneca
acquisition. NAL expects to be able to maintain distributions assuming
current commodity prices, and has an active hedging program which has
locked in average prices above our base case forecast. The Trust's debt
to cash flow ratios are expected to improve in 2008, and NAL has over
$100.0 million of available committed bank lines to take advantage of
opportunities which continue to be available.
2008 Guidance
-------------------------------------------------------------
Average total production (boe per day) 23,000 - 24,000
Capital expenditures ($ millions) 110 - 120
Operating costs ($/boe) 9.50 - 9.80
G&A ($/boe) 1.90 - 2.10
-------------------------------------------------------------
SUBSEQUENT EVENTS
- NAL participated in three significant exploratory wells during
2007 and early 2008. Two of those wells are expected to be onstream
early in the second quarter of 2008. The Trust has a 19 percent working
interest in an Upper Devonian natural gas discovery at Peppers 16-16 in
West Central Alberta. The well is expected to produce at an initial rate
of 10.0 MMcf/d of raw gas or 8.0 MMcf/d sales gas, representing
approximately 250 boe/d net to NAL, subject to gathering and plant
capacity constraints. Monkman a-26-E, in Northeast B.C., encountered two
productive sheets in the Permian Belcourt formation. The lower sheet
tested 30 MMcf/d of raw gas and the upper sheet tested 35 MMcf/d. NAL
has a 20 percent working interest in the well. The operator is still
evaluating pressure data to determine if it is possible to commingle
production from the two sheets. NAL has forecast this well to be
onstream at approximately 27 MMcf/d raw or 22 MMcf/d sales gas,
representing 700 boe/d net to NAL. Testing operations at a third well
are still ongoing at Monkman b-44-B where NAL has an 8.55 percent
working interest. A fourth exploratory well was spudded at Monkman
a-31-K early in 2008, and it will be evaluated later in the year.
Following a vertical pooling agreement with Talisman Energy, NAL has a
10 percent working interest.
- The Trust closed two private company acquisitions and one asset
purchase by February 27, 2008, all with interests in Southeast
Saskatchewan, for a total purchase price of approximately $64.4 million
net to the Trust. These transactions will add 2.1 million boe of proved
plus probable reserves in close proximity to existing fields at Alida
and Steelman/Elswick. For 2008, these acquisitions are expected to add
approximately 700 boe/d of production on an annualized basis with an
additional $5 million in capital expenditures. NAL's strategic partner,
Manulife Financial Corporation, participated equally in these
acquisitions, demonstrating the value of our strategic partnership and
their continued interest in adding investments in the oil and gas
sector. These 'tuck-in acquisitions' add to the Trust's cornerstone
presence in Southeast Saskatchewan, and position NAL for further
reserves additions as well as infrastructure and cost synergies.
SUMMARY
"2007 was the beginning of NAL's transition to become a dividend
paying corporation by 2011. We turned in very strong operating and
financial results in 2007, exceeding the guidance that was set out early
in the year, concluding a significant acquisition, adding land,
opportunities and capability, and achieving much improved F&D
costs," said Andrew Wiswell, President and Chief Executive Officer. "We
have positive momentum heading into 2008 supported by a well defined
operating plan, a growing opportunity base, a strong financial position
and a motivated team committed to delivering for our unitholders."
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.
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 Thursday, February 28, 2008, NAL
will hold a conference call to discuss the fourth quarter and 2007 year
end 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 webcast at
http://events.onlinebroadcasting.com/nal/022808/index.php
A recorded playback of the call will be available until March 6, 2008 by calling 1-800-408-3053, reservation 3252987.
Notes: (1) All amounts are in Canadian dollars unless otherwise stated.
(2) When converting natural gas to equivalent barrels of oil within
this report, NAL uses the widely recognized standard of 6
thousand cubic feet (Mcf) to one barrel of oil (boe). However,
boe's may be misleading, particularly if used in isolation.
A boe conversion ratio of 6 Mcf:1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
SENSITIVITY ANALYSIS
In our January 23, 2008 press release outlining 2008 guidance, NAL
provided a base and sensitivity case based upon different commodity
price scenarios. We have updated the scenarios including production from
the recent acquisition announced in February 2008 and adjusted the gas
and exchange rate in the Sensitivity case.
Key Assumptions
----------------------------------------------------------------------
Base Case Sensitivity Case
----------------------------------------------------------------------
Production (boe/d) 24,000 24,000
WTI Oil Price (US$/bbl) 80.00 90.00
AECO Natural Gas Price
(C$/GJ) 6.50 7.50
Exchange Rate (Cdn/USD) 1.00 1.00
----------------------------------------------------------------------
2008 Pro Forma Financial Results
----------------------------------------------------------------------
Base Case(i) Sensitivity Case(i)
----------------------------------------------------------------------
Funds from Operations
($MM) 267 298
Funds from Operations
($ per unit) $2.85 $3.18
Weighted average Units
Outstanding (MM) 93.7 93.7
Debt / Cash Flow 1.2 / 1.6(i)(i) 1.0 / 1.3(i)(i)
----------------------------------------------------------------------
(i)Includes realized hedging gains (losses)
(i)(i)Including convertible debentures
Impact on Annual Funds from Operations(i)
----------------------------------------------------------------------
Assumptions Change Amount (000s) Per Unit
----------------------------------------------------------------------
Commodity Prices
WTI oil (US$/bbl) $1.00 $3,000 $0.03
AECO natural gas (Cdn$/GJ) $0.10 $2,300 $0.02
----------------------------------------------------------------------
Volume Changes
Oil 100 bbl/d $1,800 $0.02
Natural gas 1,000 mcf/d $1,600 $0.02
----------------------------------------------------------------------
Rates
Exchange Rate - Cdn$/US$ $0.01 $2,400 $0.03
Interest Rate - Bank
prime lending rate 1% $2,900 $0.03
----------------------------------------------------------------------
(i)Compared to base case
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
Three Months Ended Years Ended December 31
---------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
FINANCIAL
Gross revenue, net of
royalties $86,262 $75,358 $319,334 $310,416
Cash flow from operating
activities 45,111 48,678 215,364 238,445
Cash flow per unit - basic 0.50 0.63 2.61 3.12
Cash flow per unit -
diluted 0.48 0.63 2.56 3.12
Funds from operations 59,537 55,795 218,745 219,776
Funds from operations per
Unit - basic 0.66 0.72 2.65 2.88
Funds from operations per
Unit - diluted 0.63 0.72 2.60 2.88
Net income 10,556 20,472 56,457 60,198
Distributions declared 43,340 39,663 158,601 169,589
Distributions per unit 0.48 0.51 1.92 2.22
Payout ratio:
based on cash flow from
operating activities 96% 81% 74% 71%
based on funds from
operations 73% 71% 73% 77%
Units outstanding (000's)
December 31 90,494 77,971 90,494 77,971
Weighted average 90,194 77,697 82,556 76,350
Capital expenditures 39,194 34,788 119,434 124,042
Corporate acquisitions - - 245,687 -
Net debt(1) 291,059 223,061 291,059 223,061
Convertible debentures
(at face value) 100,000 - 100,000 -
OPERATING
Daily production
Crude Oil (bbl/d) 9,633 9,700 9,305 9,367
Natural gas (mcf/d) 70,120 47,153 54,773 48,804
Natural gas liquids (bbl/d) 2,094 1,958 2,067 1,944
Oil equivalent (boe/d) 23,413 19,517 20,501 19,444
COST STRUCTURE
Costs per boe
Revenue before hedging
gains (losses) 56.48 49.78 54.88 53.97
Royalties (12.08) (10.36) (11.91) (11.79)
Operating costs (10.00) (7.13) (9.34) (8.31)
Other income 1.20 1.20 0.94 0.72
-------------------------------------------------------------------------
Operating netback before
hedging gains (losses) 35.60 33.49 34.57 34.59
Hedging gains (losses) (2.56) 1.00 (0.33) 0.48
-------------------------------------------------------------------------
Operating netback 33.04 34.49 34.24 35.07
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excluding convertible debentures
OIL AND GAS RESERVES
NAL's 2007 year end reserves were evaluated by McDaniel &
Associates Consultants Ltd. ("McDaniels"), independent engineering
consultants in Calgary, in accordance with National Instrument ("NI")
51-101. At December 31, 2007, the Trust's proved reserves totaled 49.6
million barrels of oil equivalent ("boe") and proved plus probable
("P+P") reserves amounted to 68.2 million boe.
NAL has a reserves committee, composed entirely of independent
directors, which is responsible for appointing the Trust's independent
engineering consultants and determining the scope of the annual reserves
review.
Some key points regarding NAL's 2007 reserves summary are:
- The acquisition of Seneca Energy Canada Inc. ("Seneca"), effective
September 1, 2007, along with some minor property acquisitions in
Alberta, added 10,262 Mboe of P+P reserves to the Trust.
- Additions for improved recovery, which includes discoveries,
extensions, infill drilling and well recompletions, amounted to 3,502
Mboe of proved and 4,981 Mboe of P+P reserves. This represents new
reserves added for development activity, over and above volumes that
were previously booked in the reserves report. These reserves additions
occurred across all of our core areas, with the larger ones resulting
from successful drilling results in the Alida, Midale, Elswick and
Steelman areas in Saskatchewan, the Garrington, Westward Ho and Pine
Creek areas in Alberta, as well as the new core property at Sukunka in
British Columbia.
- Overall technical revisions amounted to 5,630 Mboe for proved and
2,238 Mboe for P+P reserves. The technical revisions were widespread
among all producing areas, and were largely the result of positive
performance trends observed in numerous producing wells and the
recharacterization of reserves from probable to proved to reflect
increased levels of certainty.
- The total P+P reserves additions for improved recovery and
technical revisions of 7,219 Mboe represents a 96 percent replacement
ratio of the 2007 production of 7,483 Mboe. Including acquisitions, the
Trust's total reserves replacement ratio for 2007 was 234 percent.
- At December 31, 2007, over 95 percent of NAL's proved reserves
were in the Proved Producing category. NAL continues to take a
conservative approach in booking undeveloped reserves in the Proved
Undeveloped category, leading to a high degree of confidence in
exceeding our booked proved reserves.
- Using the P+P reserves of 68,212 Mboe and the number of
outstanding trust units at December 31, 2007 of 90,494,151, the P+P
reserves at year end 2007 amounted to 0.754 boe per unit. This
represents a slight increase from 0.747 boe per unit at year end 2006.
The following tables summarize NAL's estimated reserves volumes and
values using McDaniels price forecasts as of January 1, 2008. Gross
reserves volumes are based on the Trust's working interests before
deduction of royalties payable, and exclude any wells or properties in
which NAL has only a royalty interest. Net reserves represent the
Trust's working interest reserves after deducting royalties payable,
plus royalty interest reserves. The Light and Medium Oil category
includes a small amount of reserves classified as "heavy oil"
(approximately 20(o) API) under NI 51-101 guidelines. These reserves
represent approximately two percent of the Total Proved plus Probable
oil reserves and, as such, are not considered material in terms of
separate reporting. Similarly, the Natural Gas category includes
non-associated gas, solution gas from oil wells and coal bed methane
volumes, as the solution gas and coal bed methane volumes are not
considered material in terms of requiring separate reporting.
Numbers may not add exactly due to rounding.
-------------------------------------------------------------------
Summary of Oil and Gas Reserves
As at December 31, 2007
Forecast Prices and Costs
-------------------------------------------------------------------
Reserves
Light and Medium Oil Natural Gas
Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (MMcf) (MMcf)
-------------------------------------------------------------------
Proved
Developed Producing 19,616 17,174 138,075 116,702
Developed Non-Producing 199 173 3,580 2,898
Undeveloped 595 547 4,691 3,965
------------------------------------------
Total Proved 20,410 17,894 146,347 123,565
Probable 7,242 6,354 56,244 46,553
------------------------------------------
Total Proved Plus Probable 27,652 24,248 202,590 170,118
-------------------------------------------------------------------
-------------------------------------------------------------------
Reserves
Natural Gas Liquids Total BOE (6:1)
Gross Net Gross Net
Reserves Category (Mbbl) (Mbbl) (Mbbl) (Mbbl)
-------------------------------------------------------------------
Proved
Developed Producing 4,629 3,388 47,258 40,012
Developed Non-Producing 104 73 900 730
Undeveloped 83 60 1,459 1,268
------------------------------------------
Total Proved 4,816 3,522 49,618 42,010
Probable 1,979 1,428 18,595 15,540
------------------------------------------
Total Proved Plus Probable 6,795 4,949 68,212 57,550
-------------------------------------------------------------------
--------------------------------------------------------------------------
Net Present Values of Future Net Revenue
Forecast Prices and Costs
--------------------------------------------------------------------------
Before Income Taxes, Discounted at (percent/year)
0% 5% 10% 15%
Reserves Category (million $) (million $) (million $) (million $)
--------------------------------------------------------------------------
Proved
Developed Producing 1,487 1,181 988 856
Developed Non-Producing 28 21 17 14
Undeveloped 32 24 18 14
------------------------------------------------
Total Proved 1,547 1,226 1,023 88
Probable 639 382 259 190
------------------------------------------------
Total Proved Plus Probable 2,186 1,608 1,282 1,075
--------------------------------------------------------------------------
The table above shows the before-tax net present value ("NPV") of the Trust's reserves at various discount rates.
It should not be assumed that the estimated future net revenue is
representative of the fair market value of the properties of the Trust.
There is no assurance that such price and cost assumptions will be
attained and variances could be material.
A sensitivity case of the reserves evaluation was done to
incorporate the impact of the proposed new royalty regime in Alberta.
The result of that analysis, done using McDaniel's published price
forecasts of January 1, 2008, shows an increase to the Trust's NPV due
to the net benefit of reduced royalties on shallow gas wells which more
than offsets any increased royalties on deeper wells. The before tax NPV
discounted at 10 percent for the proved plus probable case increases
from $1,282 million to $1,286 million under the proposed new royalty
regime.
--------------------------------------------------------------------------
Summary of Pricing and Inflation Rate Assumptions
As at December 31, 2007
Forecast Prices and Costs
--------------------------------------------------------------------------
Oil
Edmonton Cromer Medium NATURAL GAS
WTI Cushing Par Price 29.3 degrees AECO Spot
Oklahoma 40 degrees API API Price
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/MMBtu)
--------------------------------------------------------------------------
2008 90.00 89.00 78.20 6.80
2009 86.70 85.70 75.30 7.38
2010 83.20 82.20 72.20 7.38
2011 79.60 78.50 69.00 7.38
2012 78.50 77.40 68.00 7.49
2013 77.30 76.20 66.90 7.70
Thereafter(i) +2%/yr +2%/yr +2%/yr +3%/r
--------------------------------------------------------------------------
---------------------------------------------------------
Natural Gas
Liquids
Edmonton Mix Inflation Rates Exchange Rate
Year ($Cdn/bbl) Percent/Year ($US/Cdn)
---------------------------------------------------------
2008 61.60 2.0 1.000
2009 60.20 2.0 1.000
2010 58.00 2.0 1.000
2011 55.80 2.0 1.000
2012 55.20 2.0 1.000
2013 54.70 2.0 1.000
Thereafter(i) +2%/yr 2.0 1.000
---------------------------------------------------------
(i) Price escalation rates are approximate.
--------------------------------------------------------------
Reconciliation of
Company Gross Reserves
By Principal Product Type
Forecast Prices and Costs
--------------------------------------------------------------
Associated and Non-
Light and Medium Oil Associated Gas
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (Mbbl) (Mbbl) (MMcf) (MMcf)
--------------------------------------------------------------
December 31, 2006 18,291 26,494 109,580 152,626
Improved Recovery(i) 1,731 1,947 8,575 15,059
Technical Revisions 2,542 894 13,568 4,886
Acquisitions 1,242 1,714 34,616 50,011
Dispositions 0 0 0 0
Production (3,396) (3,396) (19,992) (19,992)
December 31, 2007 20,410 27,652 146,347 202,590
--------------------------------------------------------------
--------------------------------------------------------------
Natural Gas Liquids Total BOE
Proved Proved
Plus Plus
Proved Probable Proved Probable
Factors (Mbbl) (Mbbl) (Mboe) (Mboe)
--------------------------------------------------------------
December 31, 2006 4,250 6,282 40,804 58,214
Improved Recovery(i) 342 524 3,502 4,981
Technical Revisions 827 530 5,630 2,238
Acquisitions 152 213 7,164 10,262
Dispositions 0 0 0 0
Production (754) (754) (7,483) (7,483)
December 31, 2007 4,816 6,795 49,618 68,212
--------------------------------------------------------------
(i) Improved Recovery includes discoveries, extensions,
infill drilling and well recompletions.
FINDING AND DEVELOPMENT COSTS
Finding and Development ("F&D") costs are reported below for P+P
reserves, in each case after eliminating the effects of acquisitions
and dispositions, and including changes in future development costs as
per NI 51-101 guidelines. The total reserves changes in the improved
recovery and technical revisions categories of the reconciliation table,
excluding the changes that relate to the acquired properties, are used
in the F&D calculation.
The capital spending of $107.96 million used in the F&D
calculation for 2007 represents the Trust's total expenditures for
drilling, completion and production equipment, plant and facility costs
(including maintenance capital items that supported our base production
volumes and helped maintain our low operating cost structure), plus
seismic and land costs, capitalized G&A and unit-based incentive
costs. The capital that was spent within properties that were acquired
in 2007 is not included in the F&D calculation, as it is included in
the FD&A calculation in the section which follows.
The F&D costs for 2007, as shown in the table below, were $13.99
per boe for proved and $17.71 per boe for P+P reserves. It should be
noted that the aggregate of the development costs incurred during the
year and the change in estimated future development costs generally will
not reflect total finding and development costs related to reserves
additions for that year. As a result, the three-year weighted average,
with changes tracked over time, provides a useful indicator of capital
effectiveness as it relates to reserves development. As shown in the
table below, the weighted average F&D costs for the three-year
period from 2005 through 2007 are $17.87 per boe for proved and $24.89
per boe for P+P reserves.
------------------------------------------------------------------------
2007
------------------------------------------------------------------------
Change in
Estimated
Actual Future
Spending Development
During 2007 Costs Total
------------- ----------- ---------
Capital (M$) Proved 107,961 10,458 118,419
Proved + Probable 107,961 7,486 115,447
------------------------------------------------------------------------
Improved Technical
Recovery Revisions Total
---------- ----------- ---------
Reserves (Mboe) Proved 3,053 5,415 8,467
Proved + Probable 4,120 2,400 6,519
------------------------------------------------------------------------
F&D ($/boe) Proved $13.99
Proved + Probable $17.71
------------------------------------------------------------------------
------------------------------------------------------------------------
3-YEAR WEIGHTED AVERAGE
------------------------------------------------------------------------
Change in
Estimated
Actual Future
Spending Development
Over 3 years Costs Total
------------- ----------- ---------
Capital (M$) Proved 280,952 (10,614) 270,338
Proved + Probable 280,952 12,434 293,386
------------------------------------------------------------------------
Improved Technical
Recovery Revisions Total
---------- ----------- ---------
Reserves (Mboe) Proved 4,996 10,131 15,126
Proved + Probable 9,211 2,579 11,789
------------------------------------------------------------------------
F&D ($/boe) Proved $17.87
Proved + Probable $24.89
------------------------------------------------------------------------
Some reporting issuers report F&D costs excluding changes in
future development capital ("FDC"). Although not NAL's usual practice,
we will provide the numbers on that basis for comparison purposes.
Excluding changes in FDC, the Trust's F&D costs for 2007 would be
$12.75 per boe for proved and $16.56 per boe for P+P. Another
methodology excludes capitalized G&A costs and unit-based incentive
costs from the current year capital. On that basis, our F&D costs
for 2007 would use $102.6 million of capital spending in the F&D
calculation, resulting in $12.12 per boe for proved and $15.74 per boe
for P+P.
FINDING, DEVELOPMENT AND ACQUISITION COSTS
A significant part of NAL's business activity in any given year is
the acquisition and, to a lesser degree, the disposition of properties.
In order to provide a more representative measure of the company's total
capital spending as it relates to reserves development, we report
Finding, Development and Acquisition ("FD&A") costs, which include
the effects of acquisitions and dispositions.
During 2007, the Trust completed the acquisition of Seneca, along
with some minor property acquisitions in Alberta. The FD&A
calculation incorporates all the components used in the F&D
calculation, plus the adjustments to capital spending and reserves
related to the acquisitions and disposition activities completed during
the year, as shown in the table below.
The FD&A costs for 2007 were $23.20 per boe for proved and
$21.67 per boe for P+P reserves. The weighted average FD&A costs for
the three-year period from 2005 through 2007 were $21.79 per boe for
proved and $19.24 per boe for P+P reserves. These three year averages
provide an appropriate measure of the Trust's overall capital spending
effectiveness.
2007
--------------------------------------------------------------------------
Change in
Actual Estimated
Spending Future Total
During Development Acquis- Dispos- Including
2007 Costs itions itions A&D
--------- ----------- -------- -------- ----------
Capital (M$) Proved 116,714 14,303 247,110 0 378,127
Proved +
Probable 116,714 15,070 247,110 0 378,894
--------------------------------------------------------------------------
Total
Improved Technical Acquis- Dispos- Including
Recovery Revisions itions itions A&D
--------- ----------- -------- -------- ----------
Reserves
(Mboe) Proved 3,502 5,631 7,164 0 16,297
Proved +
Probable 4,981 2,238 10,262 0 17,481
--------------------------------------------------------------------------
FD&A ($/boe) Proved $23.20
Proved +
Probable $21.67
--------------------------------------------------------------------------
3-YEAR WEIGHTED AVERAGE
--------------------------------------------------------------------------
Change in
Actual Estimated
Spending Future Total
Over Development Acquis- Dispos- Including
3 Years Costs itions itions A&D
--------- ----------- -------- -------- ----------
Capital (M$) Proved 310,166 24,851 634,707 (3,504) 966,220
Proved +
Probable 310,166 62,362 634,707 (3,504) 1,003,73
--------------------------------------------------------------------------
Total
Improved Technical Acquis- Dispos- Including
Recovery Revisions itions itions A&D
--------- ----------- -------- -------- ----------
Reserves
(Mboe) Proved 5,445 9,756 29,241 (104) 44,338
Proved +
Probable 10,072 2,638 39,586 (126) 52,170
--------------------------------------------------------------------------
FD&A ($/boe) Proved $21.79
Proved +
Probable $19.24
--------------------------------------------------------------------------
RESERVE LIFE INDEX
Reserve Life Index ("RLI") is calculated by dividing reserves at
December 31, 2007 by expected annual production for 2008. RLI is useful
in making generalized comparisons between companies but does not
accurately represent the anticipated life of the Trust's reserves. Due
to the natural decline of oil and gas production, the actual producing
life of oil and gas properties is much longer than the RLI calculation
would suggest.
In the McDaniels reserves report, the average production forecasted
for 2008 in the P+P reserves case is 22,910 boe/d. This number is
slightly below NAL's published guidance range of 23,000 to 24,000 boe/d
because the McDaniels report does not incorporate all of NAL's proposed
capital projects for 2008 or the related production uplift expected. For
consistency, the RLI calculation should be based on the reserves at
December 31, 2007 and the forecasted annual production for 2008 from the
reserves report. Using those numbers, NAL's RLI at December 31, 2007
was 8.2 years for P+P, down slightly from 8.5 years at year end 2006.
LAND AND SEISMIC
At December 31, 2007, NAL owned an average 36.0 percent working
interest in 845,232 gross acres (304,479 net acres) of undeveloped land.
Most of NAL's land is owned in partnership with Manulife Financial
Corporation, which results in NAL operating over 80 percent of its
production and prospective acreage. Based on an internal estimate and
using market benchmarks, NAL's undeveloped land and seismic value is
approximately $83.8 million.
NET ASSET VALUE
The following net asset value calculations are based on what is
generally referred to as the "produce-out" net present values of the
Trust's oil and gas reserves as evaluated by independent engineering
consultants in accordance with National Instrument 51-101.
December 31, 2007 December 31, 2006
------------------------------------------------------------------------
($000s, except per unit data) Using Forecast Using Forecast
Prices(4) Prices(5)
------------------------------------------------------------------------
Proved plus probable reserves
(before tax, discounted at 10%) 1,282,473 1,017,713
Undeveloped land and seismic(1) 83,758 47,800
Working capital (deficiency)(2) (15,429) (2,276)
Long-term debt (368,254) (221,790)
Asset retirement obligation(3) (55,986) (34,191)
Net asset value 926,562 807,256
Units outstanding (000s) 90,494 77,971
NAV per unit $10.24 $10.35
------------------------------------------------------------------------
(1) Internal estimate.
(2) Working capital deficiency excludes, the fair value of derivative
contracts and future income tax asset.
(3) The Asset Retirement Obligation ("ARO") is calculated based on the
same methodology that was used to calculate the ARO on NAL's year-
end financial statements, with two exceptions. Future expected ARO
costs are discounted at 10 percent and a deduction is made for
abandonment costs incorporated in the value of the proved plus probable
reserves. The balance on the year end balance sheets, $89.6 million for
2007 and $65.6 million for 2006, when discounted at 10 percent, result
in a total discounted ARO of $75.1 million and $54.0 million, at the
respective balance sheet dates. These balances are further reduced by
$19.1 million and $19.8 million, respectively, relating to abandonment
costs included in the reserve value.
(4) McDaniels price forecasts as of January 1, 2008.
(5) McDaniels price forecasts as of January 1, 2007.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in
conjunction with the audited consolidated financial statements for the
years ended December 31, 2007 and December 31, 2006 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, 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. 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 is 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 and future
income tax balances.
The following table reconciles cash flows from operating activities to funds from operations:
----------------------------------------------------------------------------
Three months ended December 31 Years ended December 31
-------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flow from
Operating activities 45,111 48,678 215,364 238,445
Add back change in non-cash
working capital 14,426 7,117 3,381 (18,669)
----------------------------------------------------------------------------
Funds from operations 59,537 55,795 218,745 219,776
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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", "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 are 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; 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, 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
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; 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 review; changes in tax laws; the
impact of the new SIFT legislation following the October 31, 2006
announcement 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, and
the Trust does not assume any obligation to publicly update or revise it
to reflect new events or circumstances except as required by law. The
forward-looking information contained in the MD&A is expressly
qualified by this cautionary statement.
ACQUISITION OF SENECA ENERGY CANADA INC. ("Seneca")
NAL successfully closed the acquisition of Seneca on August 31, 2007
for a price of $245.7 million including costs of $0.6 million. The
acquisition added 10.3 million boe of P+P reserves and production
averaging 4,400 boe/d from September 2007 to year end 2007. This
production is weighted 85 percent to natural gas. The transaction also
added 157,287 acres of net undeveloped land and growth opportunities to
the Trust.
The net cash consideration was financed by the issuance of 10.2
million units at a price of $12.20 per trust unit for proceeds of $125
million ($117.9 million net of issue costs), $100 million in 6.75%
convertible extendible unsecured subordinated debentures ($96 million
net of issue costs), and $31.8 million of bank debt.
EXPLORATION & DEVELOPMENT ACTIVITIES
The Trust spent $31.0 million on drilling operations during the
fourth quarter of 2007, versus $25.6 million a year earlier. For the
full year, NAL spent $95.3 million on drilling versus $87.9 million in
2006, plus another $10.0 million on plant and facilities construction,
and $6.0 million on land and seismic data acquisition.
The Trust participated in the drilling of 45 (18.06 net) wells
during the fourth quarter of 2007, and 126 gross (49.8 net) wells during
the year, compared to 191 gross (87.6 net) in 2006. Drilling for
shallow gas in Lake Erie and the Lacombe, Alberta areas was deferred due
to low natural gas prices.
Historically, NAL's assets have been concentrated in Southeast
Saskatchewan and Central Alberta, while the purchase of Seneca in 2007
added a new core area at Monkman in Northeast B.C. These areas are
accessible year-round and are well serviced by both production
infrastructure and oilfield services.
Fourth Quarter Drilling Activity
Crude Oil Natural Gas
-----------------------------
Gross Net Gross Net
-----------------------------------------------------------------
Operated wells 21 9.43 8 6.15
Non-operated wells 7 0.09 9 2.39
-----------------------------------------------------------------
Total wells drilled 28 9.52 17 8.54
-----------------------------------------------------------------
Service Wells Dry & Abandoned Total
----------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Operated wells - - - - 29 15.58
Non-operated wells - - - - 16 2.48
--------------------------------------------------------------------
Total wells drilled - - - - 45 18.06
--------------------------------------------------------------------
2007 Full Year Drilling Activity
Crude Oil Natural Gas
-----------------------------
Gross Net Gross Net
-----------------------------------------------------------------
Operated wells 64 29.50 20 14.40
Non-operated wells 16 1.55 26 4.35
-----------------------------------------------------------------
Total wells drilled 80 31.05 46 18.75
-----------------------------------------------------------------
Service Wells Dry & Abandoned Total
----------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------
Operated wells - - - - 84 43.90
Non-operated wells - - - - 42 5.90
--------------------------------------------------------------------
Total wells drilled - - - - 126 49.80
--------------------------------------------------------------------
Southeast Saskatchewan
NAL drilled 46 wells in Southeast Saskatchewan in 2007, testing new
exploration play concepts and adding over 2,000 boe/d of production net
to the Trust. Five of those wells were drilled to test the Bakken
formation in the Viewfield area, and results exceeded expectations. NAL
was also active in land acquisition, purchasing 31,013 gross acres
(15,531 net) of undeveloped land, including a block of 23,040 gross
(11,520 net) acres of contiguous land in the Hoffer area.
Central, Alberta
Through the purchase of Seneca, NAL added significant new land
holdings adjacent to its properties in the Brent, Hanna and Provost
areas. During the year, the Trust completed a number of cost-efficient
recompletion projects in the Drumheller area delivering attractive
returns and capital efficiency. The Trust now produces 2,050 boe/d in
the Drumheller area.
Sylvan Lake, Alberta
NAL completed a successful turnaround of its Sylvan Lake gas plant
in 2007 with minimal impact on production volumes. Immediately south of
Sylvan Lake in the Garrington and Westward Ho areas, the Trust enjoyed
success from the drilling of both crude oil and natural gas wells in the
Mannville formation. A total of 17 wells were recompleted in the
Glauconite, Cardium and Edmonton horizons.
Pine Creek, Alberta
NAL enjoyed continued success drilling infill wells in the Cardium
formation in the Pine Creek area of West Central Alberta. The Trust
participated in a deep, Devonian exploration well late in the year, and
that well is expected to be put on-stream as a natural gas producer at
the beginning of the second quarter of 2008.
Monkman, B.C.
Through the purchase of Seneca, NAL added a large block of
contiguous land in the Monkman area of Northeast B.C. There were already
three natural gas wells on the property producing a combined 12.2
million cubic feet of gas or 2,040 boe/d net to the Trust. During the
year NAL participated in the drilling of two additional deep tests, at
20 percent and 8.5 percent working interests respectively, both of which
were being evaluated at year end. In December, 2007, NAL bought
interests in an additional 6,782 gross (796 net) hectares of exploratory
acreage at the provincial Crown sale.
CAPITAL EXPENDITURES
Capital expenditures for the quarter ended December 31, 2007 totaled
$39.2 million compared with $34.8 million for the quarter ended
December 31, 2006. For the year ended December 31, 2007 capital
expenditures totaled $119.4 million as compared to $124.0 million for
the same period in 2006. Included in capital expenditures is $8.7
million relating to the Seneca properties for 2007.
Capital Expenditures ($000s)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Drilling, completion and
production equipment 30,971 25,619 95,327 87,901
Plant and facilities 3,308 4,715 9,988 14,598
Seismic 149 404 708 2,628
Land 2,545 2,243 5,330 7,730
----------------------------------------------------------------
Total exploitation and
development 36,973 32,981 111,353 112,857
----------------------------------------------------------------
Office equipment 792 772 1,297 4,080
Capitalized G&A 999 1,290 4,486 4,275
Capitalized unit-based
compensation 430 (295) 875 1,659
----------------------------------------------------------------
Total other capital 2,221 1,767 6,658 10,014
----------------------------------------------------------------
Property acquisitions
(dispositions), net - 40 1,423 1,171
----------------------------------------------------------------
Total capitalized
expenditures 39,194 34,788 119,434 124,042
----------------------------------------------------------------
----------------------------------------------------------------
PRODUCTION
Fourth quarter 2007 production of 23,413 boe/d (19,023 boe/d
excluding Seneca) exceeded production of 19,517 boe/d in the comparable
period of 2006 by 20 percent. The increase is mainly attributable to
Seneca production of 4,390 boe/d. The average production for December
was 23,365 boe/d, which includes 4,246 boe/d related to Seneca.
For the year ended December 31, 2007, production of 20,501 boe/d
(19,037 boe/d excluding Seneca) exceeded production in the comparable
period of 2006 of 19,444 boe/d. During 2007, NAL did not experience any
shut-in due to Enbridge capacity constraints although trucking volume
has increased.
Average Daily Production Volumes
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Oil (bbl/d) 9,633 9,700 9,305 9,367
Natural gas (Mcf/d) 70,120 47,153 54,773 48,804
NGL's (bbl/d) 2,094 1,958 2,067 1,944
Oil equivalent (boe/d) 23,413 19,517 20,501 19,444
----------------------------------------------------------------
----------------------------------------------------------------
Oil and natural gas liquids totaled 50 percent of production in the
fourth quarter with natural gas increasing to 50 percent due to the
Seneca acquisition.
Production Weighting
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Oil 41% 50% 45% 48%
Natural gas 50% 40% 45% 42%
NGL's 9% 10% 10% 10%
----------------------------------------------------------------
----------------------------------------------------------------
REVENUE
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs, totaled $121.7 million for the three months
ended December 31, 2007, 36 percent higher than the fourth quarter of
2006. The increase in revenue is attributable to a 20 percent increase
in production and a 13 percent increase in the average price per boe.
Compared to the fourth quarter of 2006, average commodity prices
increased by 13 percent due to higher crude oil and natural gas liquids
prices.
For the year ended December 31, 2007 gross revenue totaled $410.6
million, an increase of seven percent from the comparable period in
2006. This increase is attributable to a five percent increase in
production and a two percent increase in NAL oil equivalent pricing.
Revenue
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Revenue(1) ($000s) 121,651 89,374 410,647 383,077
$/boe 56.48 49.78 54.88 53.97
----------------------------------------------------------------
----------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation 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
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 fourth quarter average Canadian crude oil price per barrel,
net of transportation costs, was $79.43, as compared to $58.53 for the
comparable quarter of 2006. The increase in realized price quarter over
quarter of 36 percent, or $20.90/bbl, was primarily driven by a 51
percent increase in WTI (US$/bbl), over the comparable period (US$90.62
versus US$60.21), offset by a strengthening Canadian dollar. In
addition, NAL's crude differentials compared to WTI priced in Canadian
dollars increased realized prices.
For the fourth quarter of 2007, NAL's realized oil price was 89
percent of WTI in Canadian dollars, an increase of four percent from the
85 percent for the corresponding period in 2006. The increase in the
fourth quarter of 2007 resulted from a narrower differential between WTI
and Edmonton and Cromer posted prices, due to greater demand for light
crude in Western Canada in that time frame.
For the year ended December 31, 2007 similar trends were
experienced. NAL's average oil price was $70.79/bbl compared to
$65.30/bbl for 2006. The eight percent increase in realized price, year
over year, was driven by a nine percent increase in WTI (US$72.30 versus
US$66.22), a four percent increase in differentials, offset by a five
percent decrease in the exchange rate.
For the year ended December 31, 2007 NAL's realized oil price was 91
percent of WTI in Canadian dollars as compared to 87 percent in 2006.
Natural gas liquids averaged $58.52/bbl in the fourth quarter of
2007, a 35 percent increase from $43.24/bbl realized in 2006. For the
year ended December 31, 2007, natural gas liquids pricing averaged
$50.82/bbl, four percent higher than 2006.
NATURAL GAS MARKETING
Approximately 77 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 23 percent tied to NYMEX or other
indexed reference prices.
Lake Erie production accounted for seven percent of the Trust's
natural gas production in 2007, compared to eight percent in 2006. For
the fourth quarter of 2007, five percent of natural gas was produced
from Lake Erie; the decrease attributable to the gas weighted Seneca
acquisition.
For the three months ended December 31, 2007, the Trust's natural
gas sales averaged $6.20/mcf compared to $6.96/mcf in the comparable
period of 2006, a decrease of 11 percent. The quarter over quarter
decrease in gas prices was attributable to an 11 percent decrease in the
benchmark AECO prices. Natural gas prices from the Lake Erie property
averaged $7.37/mcf in the fourth quarter of 2007 compared to $8.16/mcf
in 2006, a decrease of 10 percent.
For the year ended December 31, 2007, NAL averaged $6.60/mcf,
compared to $7.03/mcf in 2006, a decrease of six percent. The decrease
is attributable to a two percent decrease in the benchmark daily AECO
prices and to marketing a portion of gas based on the monthly AECO,
which decreased five percent year over year. During 2007, the spread
between the spot and the monthly AECO prices was $0.17/mcf compared to
$0.42/mcf for 2006.
Average Pricing
(net of transportation charges)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Liquids
WTI (US$/bbl) 90.62 60.21 72.30 66.22
NAL average oil (Cdn$/bbl) 79.43 58.53 70.79 65.30
NAL natural gas liquids
(Cdn$/bbl) 58.52 43.24 50.82 48.70
Natural Gas (Cdn$/Mcf)
AECO - daily spot 6.15 6.90 6.44 6.56
AECO - monthly 6.00 6.36 6.61 6.98
NAL Western Canada natural gas 6.13 6.84 6.47 6.98
NAL Lake Erie natural gas 7.37 8.16 7.90 8.09
NAL average natural gas 6.20 6.96 6.60 7.03
NAL Oil Equivalent before
hedging (Cdn$/boe - 6:1) 56.48 49.78 54.88 53.97
Average Foreign Exchange
Rate (Cdn$/US$) 0.9807 1.139 1.0738 1.134
----------------------------------------------------------------
----------------------------------------------------------------
RISK MANAGEMENT
NAL employs risk management practices to assist in managing cash
flows and to support capital programs and distributions. NAL's
management is authorized to hedge up to 50 percent of its annual net of
royalty production. NAL's risk management programs are scaled in over
time using a combination of swaps and collars. During 2007, 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 for the quarter and year:
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Average crude volumes
hedged (bbl/d) 3,966 4,263 3,106 3,244
Crude oil realized
gain (loss) ($000's) (7,756) 1,170 (7,132) 1,158
Gain (loss) per bbl
hedged (21.26) 2.98 (6.29) 0.98
Average natural gas
volumes hedged (GJ/d) 19,978 7,304 16,633 3,337
Natural gas realized
gain ($000's) 2,246 628 4,697 2,217
Gain per GJ hedged 1.22 0.94 0.77 1.82
Average BOE hedged
(boe/d) 7,122 5,417 5,733 3,771
Total realized gain
(loss) ($000's) (5,510) 1,798 (2,435) 3,375
Gain (loss) per boe
hedged (8.41) 3.61 (1.16) 2.45
Gain (loss) per boe (2.56) 1.00 (0.33) 0.48
----------------------------------------------------------------
----------------------------------------------------------------
The Trust has recorded the fair value of risk management contracts
on the balance sheet effective January 1, 2007 in accordance with new
accounting standards, issued by the Canadian Institute of Chartered
Accountants ("CICA"), addressing financial instruments and hedges. These
standards require all derivative instruments to be recorded on the
balance sheet at fair value, with changes in the fair value recognized
in net income unless specific hedge criteria are met. 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.
The gain on derivative contracts presented in the statement of
income includes realized gains and losses, unrealized gains and losses
since January 1, 2007, and a reclassification from other comprehensive
income. The realized gain/loss represents actual cash settlements or
receipts under the respective contracts. The unrealized gain/loss
represents the change in the fair value of the contracts during the
period. The reclassification from other comprehensive income represents
the amortization of the fair value of the contracts on transition to the
new accounting standards, over the term of the contracts. On January 1,
2007, the fair value of the outstanding contracts of $4.5 million was
recorded as an asset with the offset being recorded in accumulated other
comprehensive income, a component of unitholders' equity. The amount
recorded in accumulated other comprehensive income was reclassified to
net income over the term of the respective contracts. During 2007, the
full amount of $4.5 million has been reclassified to net income, of
which $0.9 million was reclassified in the fourth quarter of 2007.
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 December 31, 2007 was a
liability of $9.6 million. The fair value of the liability of $9.6
million at December 31, 2007 was comprised of a $13.0 million liability
on oil contracts offset by a $3.4 million asset on gas contracts.
Fourth quarter income of 2007 includes an $8.2 million unrealized
loss on derivatives resulting from the change in the fair value of the
derivative contracts during the quarter from a liability of $1.4 million
at September 30, 2007 to a liability of $9.6 million at December 31,
2007. The $8.2 million unrealized loss was comprised of a $2.4 million
unrealized loss on natural gas contracts, and a $5.8 million unrealized
loss on crude oil contracts. The unrealized loss in the fourth quarter
is primarily attributable to stronger crude oil forward prices compared
to September 30, 2007 and an increase in derivative instruments held.
For the year ended December 31, 2007, income includes a $14.1
million unrealized loss resulting from the change in the fair value of
the derivative contracts during the year. The unrealized loss was
comprised of a $15.7 million loss on oil contracts, offset by a $1.6
million gain on gas contracts.
The gain/loss on derivative contracts for the quarter is as follows:
Gain (loss) on Derivative Contracts ($000's)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Unrealized gain (loss)
Crude oil contracts (5,789) - (15,709) -
Natural gas contracts (2,424) - 1,604 -
----------------------------------------------------------------
Unrealized loss (8,213) - (14,105) -
Realized gain (loss) (5,510) 1,798 (2,435) 3,375
Reclassification from
other comprehensive
income 874 - 4,521 -
----------------------------------------------------------------
Gain (loss) on
derivative contracts (12,849) 1,798 (12,019) 3,375
----------------------------------------------------------------
----------------------------------------------------------------
For 2008, NAL has the following risk management contracts outstanding:
-------------------------------------------------------------------------
CRUDE OIL US$ CDN$
-------------------------------------------------------------------------
Swap (bbls) 418,800 668,000
Swap (bbl/d) 1,144 1,825
$/bbl $87.40 $87.10
Collars (bbls) 407,800 122,000
Collars (bbl/d) 1,114 333
$/bbl $74.93 - $83.58 $80.53 - $88.73
Total (bbls) 826,600 790,000
Total (bbl/d) 2,258 2,158
-------------------------------------------------------------------------
-------------------------------------------------------------------------
---------------------------------------------------------
NATURAL GAS CDN$
---------------------------------------------------------
Swap (GJ) 7,434,500
Swap (GJ/d) 20,313
$/GJ 7.38
Collars (GJ) 882,000
Collars (GJ/d) 2,410
$/GJ $7.98 - $9.57
Total GJ 8,316,500
Total (GJ/d) 22,723
---------------------------------------------------------
---------------------------------------------------------
For 2009, NAL currently has AECO natural gas swap contracts in place
for 810,000 GJ or 2,219 GJ/d at an average price of $7.36, and collars
for 630,000 GJ or 1,726 GJ/d at average prices of $7.61 - $9.01. In
addition, WTI oil swap contracts are in place for 127,600 bbls or 350
bbls/d at Cdn$96.89 and 54,600 bbls or 150 bbls/d at US$96.92. In
addition, the Trust has WTI crude oil collar contracts in place for
54,600 bbls or 150 bbls/d at average prices of US$92.66 - $101.17.
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $26.0 million for the
three months ended December 31, 2007. Expressed as a percentage of gross
sales, net of transportation costs, before gain/loss on derivative
contracts, the net royalty rate was 21.4 percent for the quarter ended
December 31, 2007, up slightly from 20.8 percent experienced in the
comparable period the previous year.
For the year ended December 31, 2007, royalties were $89.1 million,
up from $83.7 million in 2006. Expressed as a percentage of gross sales,
net of transportation costs, before gain/loss on derivative contracts,
the royalty rate is consistent year over year at 21.7 percent for 2007
as compared to 21.8 percent in the prior year.
On October 25, 2007, Premier Stelmach announced the new royalty
regime for Alberta, effective January 2009. This new framework will
affect NAL in that conventional oil and gas royalties will now be on a
sliding scale that is determined by commodity price and productivity.
Natural gas royalties will increase from a cap of 35 percent to 50
percent, with rate caps at $16.59/GJ. Crude oil royalty rates will
increase from the current maximum of 35 percent to 50 percent, with rate
caps raised to $120/bbl.
The Trust has assessed the impact of these new royalties on its
production and the impact is minimal to the Trust, given the low level
of crude oil production in Alberta and a significant weighting towards
low producing gas wells. For the year ended December 31, 2007, 24
percent of crude oil and 80 percent of natural gas production is from
Alberta.
Royalty Expenses
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Net royalties ($000s) 26,013 18,594 89,139 83,668
As % of revenue 21.4 20.8 21.7 21.8
$/boe 12.08 10.36 11.91 11.79
----------------------------------------------------------------
----------------------------------------------------------------
OPERATING COSTS
For the quarter ended December 31, 2007, operating costs averaged
$10.00 per boe a 40 percent increase from the $7.13 per boe for the
quarter ended December 31, 2006. On a comparative basis, the fourth
quarter of 2006 was lower than expected as it includes several downward
adjustments for the activity from earlier in 2006 where actual costs
were less than estimated.
The Trust assumed full responsibility for the Seneca properties in
September and has since undertaken significant operating cost related
projects, some of which had been deferred during the sales process.
These activities include turnarounds, pipeline replacements, pump
changes and corrosion inhibition programs, which contributed towards
higher fourth quarter operating costs.
Full year 2007 operating costs increased 12 percent to $9.34 per boe
from $8.31 per boe in 2006. The Seneca properties contributed an
incremental $0.08 per boe in overall operating costs for 2007. In
addition, approximately $0.17 per boe is attributed to third party
processing fees relating to prior periods. The remaining cost increase
was a direct result of significant labour, third party processing fee
and property tax increases which had been included in our forecasts. For
2008, operating costs are expected to average $9.50 to $9.80 per boe.
Operating Costs
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Operating costs ($000s) 21,537 12,796 69,916 58,964
As a % of revenue 17.7 14.3 17.0 15.4
$/boe 10.00 7.13 9.34 8.31
----------------------------------------------------------------
----------------------------------------------------------------
OPERATING NETBACK
For the quarter ended December 31, 2007, NAL's operating netback,
before hedging gains (losses), was $35.60 per boe, an increase of six
percent from $33.49 for the quarter ended December 31, 2006. A 13
percent increase in average realized prices was offset by increased
royalties and operating costs in the fourth quarter of 2007.
For the year ended December 31, 2007, the operating netback, before
hedging gains (losses), was $34.57 per boe, comparable with 2006. The
increase in realized prices, year over year, of $0.91 per boe was offset
by a $1.03 per boe increase in operating costs.
Operating Netback ($/boe)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Revenue 56.48 49.78 54.88 53.97
Royalties, net (12.08) (10.36) (11.91) (11.79)
Operating expenses (10.00) (7.13) (9.34) (8.31)
Other income 1.20 1.20 0.94 0.72
-------------------------------------
Operating netback, before
hedging 35.60 33.49 34.57 34.59
Hedging gains (losses) (2.56) 1.00 (0.33) 0.48
-------------------------------------
Operating netback, after
hedging 33.04 34.49 34.24 35.07
----------------------------------------------------------------
----------------------------------------------------------------
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative ("G&A") expenses include direct costs
incurred by the Trust plus the reimbursement of the Manager's G&A
expenses incurred on the Trust's behalf.
For the three months ended December 31, 2007, G&A expenses were
$4.1 million, compared with $2.4 million in the comparable quarter of
2006. In addition, $1.0 million of G&A costs relating to
exploitation and development activities were capitalized in the fourth
quarter of 2007 compared with $1.3 million in the fourth quarter of
2006.
For the year ended December 31, 2007, total G&A has increased 24
percent to $18.9 million from $15.2 million. In 2007, $4.5 million of
G&A costs relating to exploitation and development activities were
capitalized, compared with $4.3 million in 2006. G&A expenses
increased to $14.4 million in 2007 compared with $10.9 million in 2006.
Total G&A increased $3.7 million year over year due to increased
compensation costs associated with hiring, compensating and retaining
staff. Included in G&A expenses in 2007 is a retention bonus of $1.0
million associated with an employee retention program established at
year end 2006. This represents a $0.13 per boe charge in 2007. G&A
excluding the retention bonus and unit-based compensation was $1.79 per
boe, on the lower end our full year guidance of $1.75 - $1.95 per boe.
General and Administrative Expenses
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
G&A expenses ($000s)
G&A 4,039 2,395 13,435 10,946
Retention bonus 57 - 969 -
----------------------------------------------------------------
Expensed G&A ($000s) 4,096 2,395 14,404 10,946
Capitalized G&A ($000s) 999 1,290 4,486 4,275
----------------------------------------------------------------
Total G&A ($000s) 5,095 3,685 18,890 15,221
Expensed G&A costs:
G&A, excluding retention
bonus ($/boe) 1.87 1.33 1.79 1.54
Retention bonus ($/boe) 0.03 0.13
----------------------------------------------------------------
Total G&A expenses ($/boe) 1.90 1.33 1.92 1.54
As % of revenue 3.4 2.6 3.5 2.8
Per trust unit ($) 0.05 0.03 0.17 0.14
----------------------------------------------------------------
----------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
The employees of NAL Resources Management Limited (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
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 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 fourth quarter of 2007, the Trust accrued $1.5 million of
unit based incentive compensation charges as compared to a $0.4 million
recovery in the comparable quarter of 2006. The fourth quarter recovery
of unit based compensation in 2006 is a reflection of a significant
drop in unit price that occurred following the Federal government's
announcement, on October 31, 2006, of their intentions to tax income
trusts.
On a year to date basis, the Trust has accrued $3.0 million compared
to $4.2 million in the comparable period in 2006. The reduction in unit
based compensation in 2007 is a reflection of a decrease in the unit
price and a decrease in the performance factors attached to the PTUs.
These reductions have resulted in the reversal of amounts accrued prior
to December 31, 2006 for units vesting in 2007 and 2008.
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 over time.
At December 31, 2007, the Trust has recorded a liability for unit
based incentive compensation in the amount of $5.0 million, of which
$1.7 million was paid in January 2008. The remaining balance represents
the Trust's estimated liability for the unit based incentive plan as at
December 31, 2007, of which $1.5 million is recorded as current as it is
payable by December 2008, and $1.7 million is long-term as it is
payable by December 2009.
Unit-Based Compensation
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 1,080 (131) 2,152 2,495
Capitalized ($000s) 430 (295) 875 1,659
----------------------------------------------------------------
Total unit-based
compensation ($000s) 1,510 (426) 3,027 4,154
Expensed unit-based
compensation:
As % of revenue 0.9 (0.1) 0.5 0.6
$/boe 0.50 (0.07) 0.29 0.35
Per trust unit ($) 0.01 0.00 0.03 0.03
----------------------------------------------------------------
MANAGEMENT CONTRACT AND FEES
The Trust is managed by the Manager. The Manager is a wholly-owned
subsidiary of Manulife Financial Corporation ("MFC") and manages, on
their behalf, 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 pursuant to a management
contract. This agreement 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.
The Trust paid $3.1 million (2006 - $1.3 million) for the
reimbursement of G&A expenses during the fourth quarter and $11.6
million (2006 - $6.6 million) year to date. The increase in charges from
the Manager is due to increased compensation charges (see General and
Administrative Expenses). 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, on a year to date basis, $2.2
million was paid in the first quarter of 2007 relating to notional
units that vested November 30, 2006.
The management contract was restructured effective May 31, 2006,
after which no further management fees are payable. Prior to this date
the Trust was required to pay a monthly management fee, of which $1.4
million was paid during 2006. Under the restructuring, the Trust agreed
to pay one-time $30 million restructuring fee in exchange for the
elimination of any management fees and for the acquisition of a 50
percent ownership in the Manager's administrative capital assets. Of the
$30 million restructuring fee $2.8 million was allocated to
administrative assets and capitalized as property, plant, and equipment.
The balance of $27.2 million, representing the elimination of future
management fees was recorded as a non-cash charge in income. In payment
of the restructuring fee, the Trust issued, to an affiliate of the
Manager, 1,592,357 units of the Trust at a price of $18.84 per unit. The
subscription price was based on the weighted average trading price of
the trust units over the five consecutive trading days ending on the
third trading day preceding March 1, 2006, the date of the agreement.
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 fourth quarter of 2007 was $266.6 million,
as compared to $213.9 million for the fourth quarter of 2006. NAL's
effective interest rate averaged 5.61 percent in 2007, compared with
5.06 percent in the fourth quarter of 2006. NAL's interest is at a
floating rate. The increase in the rate from the fourth quarter of 2006
is attributable to rate increases in the market.
For the year ended December 31, 2007 NAL's average outstanding debt
was $242.9 million, as compared with $203.2 million for the
corresponding period in 2006. NAL's effective interest rate in 2007
averaged 5.38 percent compared with 4.83 percent in 2006.
Interest on convertible debentures represents interest charges,
since the issuance of the debentures on August 28, 2007, at 6.75
percent, of $1.7 million and accretion of the debt discount of $0.5
million for the fourth quarter of 2007, and $2.3 million and $0.6
million, respectively, for full year 2007.
Interest and Debt ($000s)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Interest on bank debt 3,820 2,759 13,356 9,963
Interest on convertible
Debentures 2,178 - 2,965 -
----------------------------------------------------------------
Total interest 5,998 2,759 16,321 9,963
Bank debt outstanding
at period end 275,630 220,785 275,630 220,785
Convertible debentures
at period end 90,876 - 90,876 -
----------------------------------------------------------------
----------------------------------------------------------------
CASH FLOW NETBACK
For the quarter ended December 31, 2007, NAL's cash flow netback was
$28.08 per boe, an 11 percent decrease from $31.69 for the comparable
period in 2006. The decrease is due to lower operating netbacks after
hedging in 2007 and higher expenses.
For the year ended December 31, 2007, NAL's cash flow netback
decreased five percent to $29.93 compared to $31.59 in 2006. The
decrease is primarily attributable to lower operating netbacks after
hedging, higher G&A and interest expenses, offset partially by lower
unit based compensation and management fees.
Cash Flow Netback ($/boe)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Operating netback,
after hedging 33.04 34.49 34.24 35.07
Management fees - - - (0.19)
G&A expenses, excluding
retention bonus (1.87) (1.33) (1.79) (1.54)
Retention bonus (0.03) - (0.13) -
Unit-based incentive
Compensation (0.50) 0.07 (0.29) (0.35)
Interest and fees on
bank debt (1.77) (1.54) (1.78) (1.40)
Interest on convertible
debentures(1) (0.79) - (0.32) -
----------------------------------------------------------------
Cash flow netback 28.08 31.69 29.93 31.59
----------------------------------------------------------------
----------------------------------------------------------------
(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 December 31, 2007, depletion on property,
plant and equipment and accretion on the asset retirement obligations
increased by 20 percent over the comparable period in 2006 due to a 20
percent increase in production volumes.
For the year ended December 31, 2007, depletion and accretion
increased by 17 percent over the comparable period due to a five percent
increase in production and an 11 percent increase in the DDA rate per
boe of production.
The increase in the DDA rate per boe is largely attributable to the Seneca acquisition.
The DDA rate will fluctuate period over period depending on the
amount and type of capital expenditures and the amount of reserves
added.
Under Canadian GAAP, a ceiling test is applied to the carrying value
of the property, plant and equipment. The carrying value is assessed to
be recoverable when the sum of the undiscounted cash flows expected
from the production of proved reserves plus the lower of cost and market
of undeveloped land exceeds the carrying value. When the carrying value
is not assessed to be recoverable, an impairment loss is recognized to
the extent that the carrying value of assets exceeds the sum of the
discounted cash flows expected from the production of P+P reserves plus
the lower of cost and market of undeveloped land. The cash flows are
estimated using expected future commodity prices and costs and are
discounted using a risk-free interest rate. There was a significant
surplus in the ceiling test at the year end 2007.
Depletion, Depreciation and Accretion Expenses
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Depletion and depreciation
($000s) 42,888 35,725 155,392 133,079
Accretion of asset
retirement obligation
($000s) 1,564 1,258 5,533 4,984
----------------------------------------------------------------
Total DDA ($000s) 44,452 36,983 160,925 138,063
DDA rate per boe ($) 20.63 20.60 21.51 19.45
----------------------------------------------------------------
----------------------------------------------------------------
TAXES
In the fourth quarter of 2007, NAL had a future income tax reduction
of $2.0 million compared with $0.3 million in the corresponding period
for the prior year.
NAL had a future income tax reduction of $3.4 million in 2007 compared to $1.2 million in 2006.
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.
The following tax pools are available to the Trust and subsidiaries
(subject to assessment by income tax authorities) for future use as
deductions from taxable income:
----------------------------------------------------------------
($000s) 2007 2006
----------------------------------------------------------------
Intangible resource pools $463,715 $323,818
Undepreciated capital cost 202,632 149,383
Unit issue costs 13,815 9,437
Non-capital losses 17,661 11,495
----------------------------------------------------------------
Total tax pools $697,823 $494,133
----------------------------------------------------------------
----------------------------------------------------------------
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. Although further clarifications are expected, these
measures are now considered substantively enacted for purposes of
Canadian generally accepted accounting principles. Accordingly, the
Trust has measured future income tax assets and liabilities associated
with this new tax. There is no impact on the future tax recognized in
the financial statements resulting from the implementation of this tax
legislation, as it is expected that all existing taxable temporary
differences will reverse prior to January 1, 2011, the date the taxation
changes take effect. Accordingly, all taxable temporary differences
have been recognized at a zero taxation rate. The scheduling of the
reversal of temporary differences is based on management's best
estimates and current assumptions, which may change.
NET INCOME
Net income is a measure impacted by both cash and non-cash items.
The largest non-cash items impacting the Trust's net income are
depletion, accretion, unrealized gain or loss on derivative contracts
and future income taxes.
Net income for the fourth quarter of 2007 was $10.6 million compared
to $20.5 million for the comparable period in 2006. The decrease in net
income of $9.9 million is primarily due to a $7.2 million increase in
depletion, increased
operating costs of $8.7 million, increased
G&A and unit based compensation of $2.9 million, and increased
interest expense of $3.2 million, partially offset by higher revenues,
net of royalties and gain/loss on derivative contracts, of $11.0 million
and an increase in the future income tax reduction of $1.7 million.
Net income for the year ended December 31, 2007 of $56.5 million was
$3.7 million lower than the same period in 2006. In 2006, net income
includes a non-cash expense of $27.3 million relating to the
restructuring of the management contract. Excluding this amount net
income decreased year over year by $31.0 million, primarily due to a
$22.3 million increase in depletion, increased interest expense of $6.4
million, a $11.0 million increase in operating costs, offset by a $8.9
million increase in revenues, net of royalties and gain/loss on
derivative contracts.
Net Income ($000s)
----------------------------------------------------------------
Three months ended Years ended
December 31 December 31
-------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------
Net income 10,556 20,472 56,457 60,198
----------------------------------------------------------------
----------------------------------------------------------------
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of trust units, bank debt and convertible debentures.
As at December 31, 2007, NAL had 90,494,151 trust units outstanding,
compared with 77,971,268 trust units at December 31, 2006. The increase
from December 31, 2006 is attributable to 10,246,000 trust units issued
on close of the equity offering on August 31, 2007, and 2,276,883 trust
units issued under the distribution reinvestment program ("DRIP").
Under the equity offering, 10.2 million trust units were issued at a
price of $12.20 per trust unit for net proceeds, after issue costs, of
$117.9 million.
For the year ended December 31, 2007, the distribution reinvestment
plan resulted in 2.3 million trust units being issued at an average
price of $11.74 per trust unit for total proceeds of $26.7 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 three months ended December 31, 2007 and 17 percent for full year
2007, consistent with recent experience. The Trust continues to monitor
the participation in this plan in conjunction with its capital
requirements.
As at December 31, 2007 the Trust had total debt of $391.1 million,
including convertible debentures at face value of $100 million and a
working capital deficit of $15.4 million (excluding derivative contracts
and future income tax asset). Excluding the convertible debentures, net
debt was $291.1 million, compared with $223.1 million at December 31,
2006, and $274.5 million as at September 30, 2007.
At the end of the fourth quarter, the Trust had a net debt to equity
ratio of 0.77 compared to 0.49 at December 31, 2006. In addition, at
the end of the fourth quarter, the Trust had a net debt (excluding
convertible debentures) to 12 months trailing cash flow of 1.33 and a
total net debt to 12 months trailing cash flow of 1.79.
The Trust maintains a $400 million fully secured, extendible,
revolving credit facility. The credit facility revolves until April 30,
2008 at which time it is extendible for a further 364-day revolving
period upon agreement between the Trust and the bank syndicate. The
facility consists of a $390 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 2009.
Bank debt amounted to $275.6 million at December 31, 2007 compared
with $220.8 million as at December 31, 2006. Of the debt outstanding at
December 31, 2007, $273.5 million was outstanding under the production
facility and $2.1 million under the working capital facility.
Bank debt increased from $220.8 million as at December 31, 2006 to
$275.6 million as at December 31, 2007 primarily due to $31.8 million
required for the acquisition of Seneca.
On August 28, 2007, in connection with the acquisition of Seneca,
the Trust issued $100 million principal amount of 6.75% convertible
extendible unsecured subordinated debentures. Interest on these
debentures is paid semi-annually in arrears, on February 28 and August
31, and the debentures are convertible at the option of the holder, at
any time, into fully paid trust units at a conversion price of $14.00
per trust unit. The debentures mature on August 31, 2012 at which time
they are due and payable. The debentures are redeemable by the Trust at a
price of $1,050 per debenture on or after September 1, 2010 and on or
before August 31, 2011, and at a price of $1,025 per debenture on or
after September 1, 2011 and on or before August 31, 2012. On redemption
or maturity the Trust may opt to satisfy its obligation to repay the
principal by issuing trust units. Assuming conversion of all outstanding
debentures 7.1 million trust units would 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 will be
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 caption interest and accretion on convertible debentures in the
consolidated statements of income.
The Trust recognized $0.5 million of accretion of the debt discount
in the fourth quarter of 2007, and $0.6 million year to date.
As at February 28, 2008 the Trust has 93,331,575 trust units and $100 million in convertible debentures outstanding.
Year-end Capitalization
---------------------------------------------------------------------------
December December
31, 2007 31, 2006
---------------------------------------------------------------------------
Trust unit equity ($000s) 504,717 456,500
Bank debt ($000s) 275,630 220,785
Working capital deficit(1) ($000s) 15,429 2,276
---------------------------------------------------------------------------
Net debt excluding convertible debentures 291,059 223,061
Convertible debentures ($000s)(3) 100,000 -
---------------------------------------------------------------------------
Net debt 391,059 223,061
Net debt to equity 0.77 0.49
Net debt excluding convertible debentures
to trailing 12-month cash flow(2) 1.33 1.01
Net debt to trailing 12-month cash flow(2) 1.79 1.01
Trust units outstanding (000s) 90,494 77,971
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Working capital excludes derivative contracts and future income
tax asset.
(2) Calculated as net debt divided by funds from operations for the
previous 12 months.
(3) Convertible debentures included at face value.
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 contribution of funds from
operations, funds received from its DRIP and bank debt.
If assumptions underlying the forecast, including commodity prices
and production, change then the Trust may be required to reconsider is
financing, distribution level or capital expenditures.
Under the tax legislation regarding the change in the taxability of
the trusts, the Trust has a grandfathering period to 2011 until the
rules come into effect. The grandfathering period restricts "undue
expansion" of the Trust by placing growth limits for equity and
convertible debt based on the market capitalization of the Trust on
October 31, 2006, the date of the announcement. For 2008 the Trust has
approximately $597 million of room and for each of 2009 and 2010 an
additional $280 million each year.
ASSET RETIREMENT OBLIGATION
At December 31, 2007, the Trust reported an asset retirement
obligation ("ARO") balance of $89.6 million (2006 -$65.6 million) for
future abandonment and reclamation of the Trust's oil and gas properties
and facilities. The ARO balance was increased by $12.6 million due to
the Seneca acquisition, $11.4 million due to liabilities incurred and
revisions to estimates (2006 - $3.1 million), $5.5 million from
accretion expense (2006 - $5.0 million) and was reduced by $5.5 million
for actual abandonment and environmental expenditures incurred in 2007
(2006 - $4.4 million).
DISTRIBUTIONS TO UNITHOLDERS
For the three months ended December 31, 2007 the Trust distributed
96 percent of its cash flow from operating activities and 74 percent for
the full year, as compared to 81 percent and 71 percent respectively in
2006. 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 each period, due to the non-cash charges
included in net income. Cash flow from operations usually exceeds net
income as net income includes non-cash charges such as 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, 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 is not expected to 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 acquisition. NAL's productive capacity and future cash flow will
be dependent on its ability to acquire assets and find reserves at
appropriate economics. 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
-------------------------------------------------------------------
($000s except for Three months ended Years ended
percentages) December 31 December 31
----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------
Cash flow from operating
activities 45,111 48,678 215,364 238,445
Net income 10,556 20,472 56,457 60,198
Actual cash distributions
paid or payable 43,340 39,663 158,601 169,589
Excess (shortfall) of cash
flow from operating
activities over cash
distribution paid 1,771 9,015 56,763 68,856
Percentage of cash flow
from operations
distributed 96% 81% 74% 71%
Excess (shortfall) of net
income over cash
distributions paid (32,784) (19,191) (102,144) (109,391)
-------------------------------------------------------------------
-------------------------------------------------------------------
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 December 31, 2007, funds from operations
amounted to $59.5 million compared with $55.8 million for the three
months ended December 31, 2006. The 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 decreased eight
percent from $0.72 in 2006 to $0.66 in 2007 due to the increase in trust
units from the equity offering associated with the acquisition of
Seneca.
For the year ended December 31, 2007, funds from operations was
comparable with 2006 though decreased eight percent on a per unit basis
from $2.88 to $2.65 in 2007. The decrease is due to the equity offering
and units issued under the DRIP.
Funds from Operations
-------------------------------------------------------------------
Three months ended Years ended
December 31 December 31
----------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------
Funds from operations ($000s) 59,537 55,795 218,745 219,776
Funds from operations per
trust unit 0.66 0.72 2.65 2.88
Payout ratio based on funds
from operations 73% 71% 73% 77%
-------------------------------------------------------------------
-------------------------------------------------------------------
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) 3,672 3,672 3,366 - - -
Transportation agreement 1,123 1,123 84 - - -
Processing agreement(2) 469 446 428 414 401 384
Drilling rigs(3) 494 - - - - -
Retention bonus(4) 578 - - - - -
----------------------------------------------------------------------------
Total 6,336 5,241 3,878 414 401 384
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including
office space acquired with the Seneca acquisition, and 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 agreement.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.
ACQUISITION OF TIBERIUS EXPLORATION INC. ("Tiberius") AND SPEAR EXPLORATION INC. ("Spear").
On February 27, 2008, the Trust completed the acquisition of all of
the issued and outstanding shares of Tiberius and Spear. Total
consideration is approximately $115 million, before closing adjustments,
consisting of approximately 2.4 million trust units and $86.25 million
in cash.
Concurrently, the Trust entered into an agreement with a wholly
owned subsidiary of Manulife Financial Corporation ("MFC"), to
contribute the assets and liabilities of Tiberius and Spear to a limited
partnership owned 50 percent by the Trust and 50 percent by MFC. MFC
will acquire its 50 percent interest in the limited partnership by
payment of one half of the purchase price, being approximately $57.5
million.
Consequently, the total acquisition cost to the Trust for its 50
percent interest in the acquired companies will be approximately $57.5
million, comprising 2.4 million trust units and $28.75 million in cash.
MFC is a related party to the Trust, see Management Contract and Fees.
The new properties will contribute primarily light oil production
from the Tilston formation, along with associated natural gas and
natural gas liquids.
QUARTERLY INFORMATION
2007 2006
----------------------------------------------------------------------------
($000s, except per unit and production amounts)
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Revenue,
net of
royalties 86,262 78,573 83,268 71,231 75,358 75,798 77,988 81,272
Per unit 0.96 0.95 1.06 0.91 0.97 0.98 1.03 1.08
Funds from
operations
(1) 59,537 50,817 54,156 54,235 55,795 54,107 52,210 57,664
Per unit 0.66 0.61 0.69 0.69 0.72 0.70 0.69 0.77
Net income
(loss) 10,556 7,801 21,390 16,710 20,472 20,473 (5,357) 24,610
(2)
Per unit
- basic and
diluted 0.12 0.09 0.27 0.21 0.26 0.27 (0.07) 0.33
Average oil
equivalent
production
(boe/d-6:1) 23,413 20,182 18,946 19,422 19,517 19,079 19,012 20,181
----------------------------------------------------------------------------
(1) Represents cash flow from operating activities prior to the change
in non-cash working capital items.
(2) Includes non-cash management restructuring fee of $27.2 million.
SELECTED ANNUAL INFORMATION
Years ended December 31
----------------------------------------------------------------------------
($000s except per unit amounts) 2007 2006 2005
----------------------------------------------------------------------------
Oil, natural gas and liquid sales(1) 413,426 385,624 406,007
Net income 56,457 60,198 98,538
Net income per trust unit 0.68 0.79 1.41
Net income per trust unit - diluted 0.68 0.79 1.41
Distributions paid and declared 158,601 169,589 142,050
Distributions paid or declared per trust unit 1.92 2.22 2.01
Total assets 1,063,160 796,902 834,883
Total liabilities 558,443 340,402 340,393
Long term debt(2) 366,506 220,785 220,519
Unitholders' equity 504,717 456,500 494,490
Number of trust units outstanding at year end 90,494 77,971 73,977
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) 2005 restated as a result of a change in presentation.
(2) Includes bank debt and convertible debentures.
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has designed and evaluated the effectiveness of the
Trust's financial reporting disclosure controls and procedures as at
December 31, 2007 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 control 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 control over financial
reporting since September 30, 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 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
following discusses such accounting policies and is included in this
MD&A to assist investors in assessing the critical accounting
policies and practices of NAL and the likelihood of materially different
results being reported. 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. The following assessment of significant
accounting estimates is not meant to be exhaustive. NAL might realize
different results from the application of new accounting standards
published, from time to time, by various regulatory bodies.
Proved Oil and Gas Reserves
Under National Instrument 51-101 ("NI 51-101"), "proved" reserves
are those reserves that can be estimated with a high degree of certainty
to be recoverable (it is possible that the actual remaining quantities
recovered will exceed the estimated proved reserves). In accordance with
this definition, the level of certainty targeted by the reporting
company should result in at least a 90 percent probability at a company
aggregate level that the quantities actually recovered will equal or
exceed the estimated reserves. There was no such consideration of
probability under previous reporting rules. In the case of "probable"
reserves, which are less certain to be recovered than proved reserves,
NI 51-101 states that it must be equally likely that the actual
remaining quantities recovered will be greater or less than the sum of
the estimated proved plus probable ("P+P") reserves. As for certainty,
in order to report reserves as P+P, the reporting company must believe
that there is at least a 50 percent probability at a company aggregate
level that the quantities actually recovered will equal or exceed the
sum of the estimated P+P reserves. The implementation of NI 51-101 has
resulted in a more rigorous and uniform standardization of reserve
evaluation.
The oil and gas reserve estimates are made using all available
geological and reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions occur as a
result of changes in prices, costs, fiscal regimes, reservoir
performance or a change in NAL's plans. The effect of changes in proved
oil and gas reserves on the financial results and position of NAL is
described under the heading "Impairment of Property, Plant and
Equipment".
Depletion Expense
NAL uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting,
all costs associated with exploration and development are capitalized
whether or not the activities funded were successful. The aggregate of
net capitalized costs and estimated future development costs is
amortized using the unit of production method on estimated proved oil
and gas reserves.
An increase in estimated proved oil and gas reserves would result in
a corresponding reduction in depletion expense. A decrease in estimated
future development costs would result in a corresponding reduction in
depletion expense.
Impairment of Property, Plant & Equipment
NAL is required to review the carrying value of all property, plant
and equipment, including the carrying value of oil and gas assets, for
potential impairment. Impairment is indicated if the carrying value of
the long-lived oil and gas asset is not recoverable by the future
undiscounted cash flows. If impairment is indicated, the amount by which
the carrying value exceeds the estimated fair value of the property,
plant and equipment is charged to net income.
The cash flows used in the impairment assessment require management
to make assumptions and estimates about recoverable reserves (see Proved
Oil and Gas Reserves), future commodity prices and operating costs.
Changes in any of the assumptions, such as downward revision in
reserves, a decrease in future commodity prices, or an increase in
operating costs could result in an impairment of an asset's carrying
value.
Fair Value of Derivative Instruments
NAL utilizes financial derivatives to manage market risk. The
purpose of the hedge is to provide an element of stability to NAL's cash
flow in a volatile environment. NAL recognizes the fair value of
derivative contracts on its balance sheet with the change in fair value
recognized in net income of the period. The fair value of the derivative
contracts is based on forward commodity prices. Any change in commodity
prices will impact the fair value of the contracts and therefore net
income of the period.
Asset Retirement Obligation
NAL is required to recognize and measure liabilities associated with
capital assets. A liability is recognized equal to the discounted fair
value of the obligation in the period in which the asset is recorded
with an equal offset to the carrying amount of the asset. The liability
then accretes to its fair value with the passage of time. Management is
required to estimate the timing and future costs to settle liabilities.
Changes in the estimated future costs, the timing of these costs, and
the discount rate will impact the liability, related asset and expense.
Legal, Environmental Remediation and Other Contingent Matters
NAL is required to determine whether a loss is probable based on
judgment and interpretation of laws and regulations whether the loss can
reasonably be estimated. When the loss is determined, it is charged to
net income. NAL's management must continually monitor known and
potential contingent matters and make appropriate provisions by charges
to earnings when warranted by circumstances.
Income Tax Accounting
The determination of NAL's income and other tax liabilities requires
interpretation of complex laws and regulations often involving multiple
jurisdictions. All tax filings are subject to audit and potential
reassessments after the lapse of considerable time. Accordingly, the
actual income tax liability may differ significantly from that estimated
and recorded by management.
Future income taxes are recognized for temporary differences arising
in the Trust's subsidiaries and also those arising in the Trust that
reverse after 2011. No future taxes have been recognized for the Trust
based on management's estimates that the reversal of all temporary
differences will occur prior to 2011. Should the assumptions underlying
the estimate of the reversal of temporary differences change, including
future commodity prices, payout ratio, capital expenditures and
reserves, future taxes maybe recorded for the Trust.
NEW ACCOUNTING POLICY
Effective January 1, 2007 the Trust implemented the provisions of
CICA Handbook Section 3855 "Financial Instruments -- recognition and
measurement", Section 3861 "Financial Instruments -- disclosure and
presentation", Section 3865 "Hedges", Section 1530 "Comprehensive
Income", and certain provisions of Section 3251 "Equity".
These standards address the recognition and measurement of financial
assets, financial liabilities and non-financial derivatives. Financial
instruments are classified into one of four categories, and each
category determines how an instrument is measured and when and where
gains and losses are recognized. Instruments are either measured at fair
value or amortized cost, which is determined using the effective
interest method. The hedging standard provides guidance on when and how
hedge accounting may be performed and Section 1530 provides standards on
the reporting and display of comprehensive income and its components.
These standards have been applied by the Trust, on a prospective
basis, in accordance with the relevant transitional provisions. For full
details on the implications to the Trust of these standards, see Note 3
to the consolidated financial statements.
FUTURE ACCOUNTING CHANGES
The CICA issued new accounting standards: Section 1535 "Capital
Disclosures", Section 3862 "Financial Instruments - Disclosures", and
Section 3863 "Financial Instruments -- Presentation". These standards
will effective January 1, 2008.
Section 1535 "Capital Disclosures" establishes standards for
disclosing information about an entity's capital and how it is managed.
The 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 to revise and enhance
disclosure on financial instruments. These standards require entities to
provide disclosure in their financial statements that enable users to
evaluate the significance of financial instruments to the entity's
financial position and performance, and the nature and extent of risks
arising from financial instruments and how the entity manages those
risks. The standards establish presentation guidelines for financial
instruments and non-financial derivatives and deal with the
classification of financial instruments from the perspective of the
issuer, between liabilities and equity, the classification of related
interest, dividends, losses and gains, and the circumstances in which
financial assets and liabilities are offset.
The Trust is currently assessing the impact of these standards on
its financial statements. However, it is not anticipated that the
adoption of these new standards will impact the amounts reported in the
Trust's financial statements as they primarily relate to disclosure.
Dated: February 28, 2008
CONSOLIDATED BALANCE SHEETS
(thousands of dollars) (unaudited)
As at As at
December December
31, 2007 31, 2006
--------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1,394 $ 6,295
Accounts receivable and other 70,791 44,467
Derivative contracts (Note 13) 3,389 -
Future income tax asset (Note 12) 2,602 -
--------------------------------------------------------------------------
78,176 50,762
Future income tax asset (Note 12) 4,096 3,345
Property, plant and equipment (Notes 4 and 6) 980,888 742,795
--------------------------------------------------------------------------
$ 1,063,160 $ 796,902
--------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 73,135 $ 40,563
Distributions payable to unitholders 14,479 12,475
Derivative contracts (Note 13) 12,973 -
--------------------------------------------------------------------------
100,587 53,038
Bank debt (Note 7) 275,630 220,785
Convertible debentures (Note 8) 90,876 -
Unit-based incentive compensation (Note 9) 1,748 1,005
Asset retirement obligations (Note 10) 89,602 65,574
--------------------------------------------------------------------------
558,443 340,402
Unitholders' equity
Unitholders' capital (Note 11) 969,588 824,986
Equity component of convertible debentures
(Note 8) 5,759 -
Deficit (Note 11) (470,630) (368,486)
--------------------------------------------------------------------------
504,717 456,500
--------------------------------------------------------------------------
$ 1,063,160 $ 796,902
--------------------------------------------------------------------------
Commitments (Note 14)
Subsequent event (Note 15)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Trust units outstanding (000s) 90,494 77,971
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
Three Months Ended Years Ended
December 31 December 31
----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue
Oil, natural gas and liquid sales $ 122,548 $ 89,994 $ 413,426 $ 385,624
Crown royalties (19,138) (13,156) (64,798) (61,570)
Freehold and other royalties (6,875) (5,438) (24,341) (22,098)
----------------------------------------------------------------------------
96,535 71,400 324,287 301,956
Gain (loss) on derivative contracts
(Note 13):
Realized gain (loss) (5,510) 1,798 (2,435) 3,375
Unrealized loss (8,213) - (14,105) -
Reclassification from other
comprehensive income 874 - 4,521 -
----------------------------------------------------------------------------
(12,849) 1,798 (12,019) 3,375
Royalty and other income 2,576 2,160 7,066 5,085
----------------------------------------------------------------------------
86,262 75,358 319,334 310,416
----------------------------------------------------------------------------
Expenses
Operating 21,537 12,796 69,916 58,964
Transportation 897 620 2,779 2,547
General and administrative 4,096 2,395 14,404 10,946
Unit-based incentive compensation
(Note 9) 1,080 (131) 2,152 2,495
Management fees (Note 5) - - - 1,350
Restructuring fee (Note 5) - - - 27,299
Interest on bank debt 3,820 2,759 13,356 9,963
Interest and accretion on
convertible debentures 2,178 - 2,965 -
Depletion, depreciation and
amortization 42,888 35,725 155,392 133,079
Accretion on asset retirement
obligations 1,564 1,258 5,533 4,984
----------------------------------------------------------------------------
78,060 55,422 266,497 251,627
----------------------------------------------------------------------------
Income before taxes 8,202 19,936 52,837 58,789
Income tax recovery 350 274 267 200
Future income tax reduction 2,004 262 3,353 1,209
----------------------------------------------------------------------------
Total income taxes (Note 12) 2,354 536 3,620 1,409
----------------------------------------------------------------------------
Net income 10,556 20,472 56,457 60,198
Other comprehensive income:
Reclassification to net income, net
of tax of $1,349 (Notes 3 and 13) (613) - (3,172) -
----------------------------------------------------------------------------
Comprehensive income 9,943 20,472 53,285 60,198
----------------------------------------------------------------------------
Deficit, beginning of period (437,846) (349,295) (368,486) (259,095)
Net income 10,556 20,472 56,457 60,198
Distributions declared (Note 11) (43,340) (39,663) (158,601) (169,589)
----------------------------------------------------------------------------
Deficit, end of period $(470,630)$(368,486) $(470,630)$(368,486)
----------------------------------------------------------------------------
Net income per trust unit - basic
and diluted (Note 11) $ 0.12 $ 0.26 $ 0.68 $ 0.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average trust units
outstanding (000s) 90,194 77,697 82,556 76,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
Three Months Ended Years Ended
December 31 December 31
----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Operating Activities
Net income $ 10,556 $ 20,472 $ 56,457 $ 60,198
Items not involving cash:
Depletion, depreciation and
amortization 42,888 35,725 155,392 133,079
Accretion on asset retirement
obligations 1,564 1,258 5,533 4,984
Unrealized loss on derivative
contracts 8,213 - 14,105 -
Reclassification from other
comprehensive income (874) - (4,521) -
Future income tax reduction (2,004) (262) (3,353) (1,209)
Non-cash accretion expense on
convertible debentures 477 - 635 -
Restructuring fee - - - 27,159
Abandonment and environmental
expenditures (1,283) (1,398) (5,503) (4,435)
Change in non-cash working capital (14,426) (7,117) (3,381) 18,669
----------------------------------------------------------------------------
45,111 48,678 215,364 238,445
----------------------------------------------------------------------------
Financing Activities
Distributions paid to unitholders (36,834) (34,025) (129,862) (129,769)
Issue of trust units, net of issue
costs - - 117,867 -
Increase in bank debt 19,145 12,592 54,127 266
Issue of convertible debentures,
net of issue costs - - 96,000 -
Change in non-cash working capital 426 186 1,341 2,241
----------------------------------------------------------------------------
(17,263) (21,247) 139,473 (127,262)
----------------------------------------------------------------------------
Investing Activities
Acquisition of Seneca Energy
Canada Inc. (Note 4) 323 - (245,687) -
Additions to property, plant and
equipment (39,194) (34,828) (118,011) (120,030)
Property acquisitions - - (1,449) (1,267)
Proceeds from dispositions - 40 26 96
Reclamation reserve - 4,294 - 3,898
Change in non-cash working capital 6,325 2,169 5,383 11,291
----------------------------------------------------------------------------
(32,546) (28,325) (359,738) (106,012)
----------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents (4,698) (894) (4,901) 5,171
Cash and cash equivalents,
beginning of period 6,092 7,189 6,295 1,124
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 1,394 $ 6,295 $ 1,394 $ 6,295
----------------------------------------------------------------------------
Supplementary disclosure of cash
flow information:
Cash paid during the period for:
Interest $ 4,777 $ 2,726 $ 16,913 $ 9,816
Tax recovery $ (350) $ 62 $ (267) $ 136
----------------------------------------------------------------------------
Cash and cash equivalents is
comprised of:
Cash $ 1,394 $ 303 $ 1,394 $ 303
Short term investments - 5,992 - 5,992
----------------------------------------------------------------------------
$ 1,394 $ 6,295 $ 1,394 $ 6,295
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Years ended December 31, 2007 and 2006
(Tabular amounts in thousands of dollars, except per unit amounts)
(unaudited)
The financial results for the three months ended December 31, 2007 have not been separately reviewed by the external auditors.
1. STRUCTURE OF THE TRUST
The Trust is an open-ended investment trust formed under the laws of
the Province of Alberta. Operations commenced on May 9, 1996. The
principal undertakings of the Trust are to indirectly acquire and hold,
through its direct and indirect wholly owned subsidiaries and
partnerships, interests in oil and natural gas properties and to
distribute the net cash proceeds to its unitholders.
The Trust is managed by NAL Resources Management Limited (the
"Manager"). The Manager is a wholly-owned subsidiary of Manulife
Financial Corporation ("MFC") and manages, on their behalf, 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
operator. As a result, a significant portion of the net operating
revenues and capital expenditures represent joint operations amounts
from NAL Resources. These transactions are in the normal course of joint
operations and are based on the original exchange amounts established
through transactions with third parties.
2. SUMMARY OF ACCOUNTING POLICIES
Basis of Presentation
The Trust's financial statements have been prepared in accordance
with Generally Accepted Accounting Principles ("GAAP") in Canada and
they include the accounts of the Trust, its subsidiaries and
partnerships, which are wholly owned. All inter-entity transactions and
balances have been eliminated.
The preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, the disclosure of contingent
assets and liabilities at the date of the financial statements, and the
reported amounts of revenues and expenses during the period. Actual
results could differ from those estimated. In particular, the amounts
recorded for depletion and depreciation of property, plant and equipment
and for the accretion of asset retirement obligations are based on
estimates of reserves and future costs. The amounts recorded for
unit-based compensation are based on estimates of trust unit price and
performance factors, while the fair value estimates for derivatives are
based on expected future oil and natural gas prices and volatility in
these prices. The ceiling test calculation is based on estimates of
reserves, production rates, oil and natural gas prices, future costs and
other relevant assumptions. Future income taxes are based on estimates
as to the timing of the reversal of temporary differences, and tax rates
currently substantively enacted. By their nature, these estimates are
subject to measurement uncertainty and may impact the consolidated
financial statements of future periods.
Property, Plant and Equipment
The Trust follows the full cost method of accounting for petroleum
and natural gas properties, whereby all costs of acquiring petroleum and
natural gas properties and related development costs are capitalized
and accumulated in one cost centre. Such costs include land acquisition,
geological and geophysical expenditures, costs of drilling both
productive and non-productive wells, related plant and production
equipment costs and related overhead charges.
Proceeds from the sale of petroleum and natural gas properties are
applied against capitalized costs, with no gain or loss recognized,
unless such sale would alter the depletion rate by 20% or more.
Depletion of petroleum and natural gas properties and depreciation
of equipment is calculated using the unit of production method based on
total proved reserves before royalties, as determined by independent
petroleum engineers. Natural gas reserves are converted to barrels of
oil equivalent based on relative energy content (6:1). The depletion
base includes capitalized costs, plus future costs to be incurred in
developing proved reserves and excludes the unimpaired cost of
undeveloped land. Costs associated with undeveloped land are not subject
to depletion and are assessed periodically to assess whether impairment
has occurred. When proved reserves are assigned or the value of the
unproved property is considered to be impaired, the cost of the
undeveloped land or the amount of impairment is added to the costs
subject to depletion.
Petroleum and natural gas properties are evaluated in each reporting
period to determine that the carrying amount in a cost centre is
recoverable and does not exceed the fair value of the properties in the
cost centre.
The carrying amount of petroleum and natural gas properties is
assessed to be recoverable when the sum of the undiscounted cash flows
expected from the production of proved reserves plus the lower of cost
and market of undeveloped land, exceeds the carrying amount. When the
carrying amount is not assessed to be recoverable, an impairment loss is
recognized to the extent that the carrying amount of the cost centre
exceeds the sum of the discounted cash flows expected from the
production of proved and probable reserves, plus the lower of cost and
market of undeveloped land. The cash flows are estimated using expected
future commodity prices and costs and discounted using a risk-free rate.
Asset Retirement Obligations
The Trust recognizes the fair value of an asset retirement
obligation in the period in which it is incurred, on a discounted basis,
with a corresponding increase to the carrying amount of property, plant
and equipment. The asset recorded is depleted on a unit of production
basis over the life of the reserves. The liability amount is increased
each reporting period due to the passage of time and the amount of
accretion is charged to income in the period. Revisions to the estimated
timing of cash flows or to the original estimated undiscounted cost
could also result in an increase or decrease to the obligation. Actual
costs incurred upon settlement of the retirement obligation are charged
against the obligation to the extent of the liability recorded.
Income Taxes
The Trust is a taxable entity under the Canadian Income Tax Act and
until 2011 is taxable only on income that is not distributed or
distributable to unitholders, provided that the Trust continues to
adhere to the transition rules provided for under the Federal
legislation. The Trust meets the criteria qualifying for income tax
treatment permitting a tax deduction for distributions paid to the
unitholders in addition to other deductions available in the Trust. In
addition, the Trust is currently exempt from future income taxes because
it is contractually committed to distribute all of its income to its
unitholders. This tax treatment is only applicable up to 2011, at which
time the distributions paid to unitholders will not be deductible for
tax and the Trust will be taxed on its income similar to corporations.
The Trust follows the asset and liability method of accounting for
income taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to
differences between the amounts reported in the Trust's subsidiaries
financial statements and their respective tax bases, using substantively
enacted income tax rates. In addition, income tax liabilities and
assets are recognized for the estimated tax consequences of temporary
differences arising in the Trust that reverse after 2011. The effect of
the change in income tax rates on future income tax liabilities and
assets is recognized in income in the period that the change occurs. A
valuation allowance is recorded against any future income tax assets if
it is more likely than not that the asset will not be realized.
Financial Instruments
Financial instruments are required to be classified into one of five
categories: held for trading, held to maturity, loans and receivables,
available for sale or other liabilities. Cash and cash equivalents have
been designated as held for trading which are measured at fair value.
Accounts receivable are classified as loans and receivables which are
measured at amortized cost. Accounts payable and accrued liabilities,
distributions payable and bank debt are classified as other liabilities
which are measured at amortized cost, which is determined using the
effective interest method. The convertible debentures are classified as
debt on the balance sheet with a portion of the proceeds allocated to
equity. The debt component has been measured at amortized cost.
All derivative contracts are classified as held for trading and are
recorded on the balance sheet at fair value, with changes in the fair
value recognized in net income, unless specific hedge criteria are met.
The Trust has entered into certain derivative contracts in order to
reduce its exposure to market risks from fluctuations in commodity
prices. These instruments are not used for trading or speculative
purposes. The Trust has not designated 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. Proceeds and costs realized from holding the
derivative contracts are recognized in net income at the time each
transaction under a contract is settled. The fair value of derivative
contracts is based on an approximation of the amounts that would be
received or paid to settle these instruments at the end of the period,
with reference to forward prices.
Transaction costs are frequently attributed to the issue of a
financial asset or liability. The Trust has selected a policy of netting
all transaction costs with the related financial assets and
liabilities, and recording its bank debt net of deferred interest
payments. In accordance with this policy convertible debentures are
presented net of issue costs and bank debt is presented net of deferred
interest payments, with interest recognized in net income on an
effective interest basis.
The Trust applies trade date accounting for the recognition of a
purchase or sale of short term investments and derivative contracts.
The Trust measures and recognizes embedded derivatives separately
from host contracts when the economic characteristics and risks of the
embedded derivative are not closely related to those of the host
contract, when it meets the definition of a derivative, and when the
contract is not measured at fair value. Embedded derivatives are
recorded at fair value.
Joint Operations
Substantially all development and production activities are
conducted jointly with others and, accordingly, these financial
statements reflect only the Trust's proportionate interests in such
activities.
Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title passes to the purchaser.
Unit-Based Incentive Compensation
The Manager has established a unit-based incentive compensation plan
(the "Plan") for all employees. Under the Plan, employees receive cash
compensation based upon the value and overall return of a specified
number of awarded notional trust units on a fixed vesting date. The
notional trust unit grants are in the form of Restricted Trust Units
("RTUs") and Performance Trust Units ("PTU's"). Distributions paid on
the Trust's outstanding trust units during the vesting period are
assumed to be reinvested in the awarded notional trust units on the date
of distribution. The compensation incorporates the trust unit price and
the number of RTUs and PTU's outstanding at each period end. In
addition, for the PTU's there is a performance multiplier which is based
on the Trust's performance relative to its peers and may range from
zero to two times the value of the notional trust units held at vesting.
Compensation expense is recognized over the vesting period and is
determined based on the market price of the notional trust units at each
period end and an expected performance multiplier with a corresponding
increase or decrease in liabilities. Classification between current
liabilities and long-term liabilities is dependent on the expected
payout date.
The Trust charges the accrued compensation amounts relating to head
office employees to general and administrative expenses, the amounts
relating to field staff to operating costs, and the amounts relating to
exploitation and development personnel to property, plant and equipment.
The Trust has not incorporated an estimated forfeiture rate for
performance units that will not vest and accounts for actual forfeitures
as they occur.
Basic and Diluted per Trust Unit Calculation
Basic net income per trust unit is calculated by dividing net income
by the weighted average number of trust units outstanding. Diluted net
income per unit is calculated using the treasury stock method to
determine the dilutive effects of the convertible debentures. Dilutive
trust units are arrived at by taking the weighted average trust units
and the trust units issuable on conversion of the convertible
debentures, giving effect to the potential dilution that would occur had
conversion occurred at the beginning of the period or on issuance of
the convertible instrument, whichever is later.
Cash and Cash Equivalents
Cash and cash equivalents include short-term investments with a maturity of three months or less when purchased.
Comparative Information
Certain comparative figures have been reclassified to conform with current year presentation.
3. CHANGES IN ACCOUNTING POLICIES
Financial Instruments, Hedges, Comprehensive Income
Effective January 1, 2007 the Trust implemented the provisions of
CICA Handbook Section 3855 "Financial Instruments - recognition and
measurement", Section 3861 "Financial Instruments - disclosure and
presentation", Section 3865 "Hedges", Section 1530 "Comprehensive
Income" and certain provisions of Section 3251 "Equity".
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial derivatives.
Financial instruments are classified into one of five categories, each
category determines how an instrument is measured and when and where
gains and losses are recognized. Instruments are either measured at fair
value or amortized cost, which is determined using the effective
interest method. There were no changes to the measurement or
presentation of these financial assets or liabilities at the date of
adoption, other than bank debt as discussed below. Section 3865 provides
guidance on when and how hedge accounting may be used. Section 1530
provides standards on the reporting and display of comprehensive income
and its components. Other comprehensive income comprises certain
revenues, expenses, gains and losses not included in the determination
of net income. Section 3251 provides guidance on the presentation and
disclosure of the components of equity, including accumulated other
comprehensive income.
These standards were applied on a prospective basis on January 1,
2007, in accordance with the relevant transitional provisions with no
restatement of prior periods.
As a result of the new standards, the Trust began to fair value its
derivative contracts. On January 1, 2007, the Trust had derivative
contracts in place with a fair value of $4.5 million. The transitional
provisions of the new standards allowed for NAL's derivatives to be
recorded as an asset on January 1, 2007 with the offset being recorded
in accumulated other comprehensive income ("AOCI"), a component of
unitholders' equity. The amount recorded in AOCI has been reclassified
to net income during 2007 in accordance with the terms of the
derivatives.
On adoption, the Trust elected to recognize, as separate assets and
liabilities, only those embedded derivatives in hybrid instruments
issued, acquired or substantively modified after January 1, 2003. The
Trust did not identify any material embedded derivatives which required
separate recognition and measurement.
In accordance with Section 3855, bank debt is presented net of
deferred interest payments, with interest recognized in net income on an
effective interest basis. Previously, interest was recognized on a
straight-line basis with the deferred amount included in accounts
receivable. There was no impact at January 1, 2007 resulting from this
change.
Future Accounting Changes
The CICA issued new accounting standards: Section 1535 "Capital
Disclosures", Section 3862 "Financial Instruments - Disclosures", and
Section 3863 "Financial Instruments - Presentation". These standards are
effective January 1, 2008.
Section 1535 "Capital Disclosures" establishes standards for
disclosing information about an entity's capital and how it is managed.
The 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 to revise and enhance
disclosure on financial instruments. These standards require entities to
provide disclosure in their financial statements that enable users to
evaluate the significance of financial instruments to the entity's
financial position and performance, and the nature and extent of risks
arising from financial instruments and how the entity manages those
risks.
The Trust is currently assessing the impact of these standards on
its financial statements, however, it is not anticipated that the
adoption of these new standards will impact the amounts reported in the
Trust's financial statements as they primarily relate to disclosure.
4. CORPORATE ACQUISITION
On August 31, 2007 the Trust acquired all the issued and outstanding
shares of Seneca Energy Canada Inc. ("Seneca"), which has interests in
oil and natural gas properties and undeveloped land in East Central
Alberta, Northeast British Columbia and Saskatchewan. The results of
operations from these properties have been included in the consolidated
financial statements commencing September 1, 2007. The transaction was
accounted for using the purchase method of accounting with the fair
values assigned to net assets and consideration paid as follows:
Net assets acquired:
----------------------------------------------------------------------------
Working capital deficiency (including bank
indebtedness of $718) $ (4,366)
Property, plant and equipment 262,678
Asset retirement obligations (12,625)
----------------------------------------------------------------------------
$ 245,687
----------------------------------------------------------------------------
Consideration:
----------------------------------------------------------------------------
Cash $ 245,110
Acquisition costs 577
----------------------------------------------------------------------------
$ 245,687
----------------------------------------------------------------------------
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.
5. RELATED PARTY TRANSACTIONS
The Manager provides certain services pursuant to a management
contract. This contract requires the Trust to reimburse the Manager, at
cost, for general and administrative expenses ("G&A") incurred by
the Manager on behalf of the Trust. In 2007, the Trust paid $11.6
million (2006 - $6.6 million) for the reimbursement of G&A. The
Trust accrues for its share of unit based incentive compensation as
units vest, but only pays the Manager its share of the expense when cash
compensation is paid to employees under the terms of the unit based
incentive compensation plan. During 2007, $2.2 million was paid in the
first quarter of 2007 relating to notional units that vested November
30, 2006.
On May 31, 2006, the Trust's unitholders approved the restructuring
of the management contract with the Manager. Prior to this date the
Trust was required to pay an interim monthly management fee, of which
$1.4 million was paid during 2006. Prior to January 1, 2006, the Trust
was required to pay a monthly base management fee equal to three percent
of its net production revenue and a quarterly performance fee based on
the Trust's overall return compared to the S&P / TSX Capped Energy
Trust Index.
Under the terms of the restructuring, the Trust agreed to pay a
one-time $30 million restructuring fee in exchange for the elimination
of any further base and performance management fees payable by the Trust
and the acquisition of a 50 percent ownership in the Manager's
administrative capital assets, effective January 1, 2006. In payment of
the restructuring fee, the Trust issued, to an affiliate of the Manager,
1,592,357 trust units of the Trust at a price of $18.84 per trust unit.
The subscription price was based on the weighted average trading price
of the trust units over the five consecutive trading days ending on the
third trading day preceding March 1, 2006, the date of the agreement.
Of the $30 million restructuring fee, $2.8 million was allocated to
the administrative assets acquired and capitalized as property, plant
and equipment. The balance of $27.2 million, representing the
elimination of future management and performance fees, has been recorded
as a non-cash charge to income.
The following amounts are due to and from related parties as at
December 31 and have been included in accounts receivable and accounts
payable and accrued liabilities on the balance sheet:
2007 2006
----------------------------------------------------------------------------
Due from NAL Resources Limited $ 14,203 $ 1,478
Due to NAL Resources Management Limited $ (2,826) $ (3,718)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. PROPERTY, PLANT AND EQUIPMENT
Net book value as at December 31: 2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas properties, at cost $ 1,687,331 $ 1,293,854
Less: Accumulated depletion and depreciation (706,443) (551,059)
----------------------------------------------------------------------------
$ 980,888 $ 742,795
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Costs associated with undeveloped land of $30.1 million (2006 -
$nil) have been excluded from the depletion calculation for the year
ended December 31, 2007.
Future development costs for proved reserves of $41.6 million (2006 -
$49.3 million) have been included in the depletion calculation.
During 2007, the Trust capitalized $4.5 million (2006 - $4.3
million) of general and administrative costs and $0.9 million (2006 -
$1.7 million) of unit based incentive compensation that were directly
related to exploitation and development programs.
The Trust performed a ceiling test calculation at December 31, 2007
to assess the recoverable value of property, plant and equipment. The
oil and gas future prices are based on the January 1, 2008 commodity
price forecast of our independent reserve evaluators, adjusted for
commodity differentials specific to the Trust. The following table
summarizes the benchmark prices used in the ceiling test calculation.
Based on these assumptions, the undiscounted value of net reserves from
the Trust's proved reserves exceeded the carrying value of property,
plant and equipment as at December 31, 2007.
WTI Oil US$/Cdn$ WTI Oil AECO Gas
Year (US$/bbl) Exchange Rate (Cdn$/bbl) (Cdn$/GJ)
---------------------------------------------------------
2008 90.00 1.0 90.00 6.45
2009 86.70 1.0 86.70 7.00
2010 83.20 1.0 83.20 7.00
2011 79.60 1.0 79.60 7.00
2012 78.50 1.0 78.50 7.10
---------------------------------------------------------
Remainder(1) 2% 1.0 2% 2%
(1) Percentage change represents the change in each year after 2012 to the
end of the reserve life.
7. BANK DEBT
2007 2006
----------------------------------------------------------------------------
Production loan facility 273,528 $ 219,000
Working capital facility 2,102 1,785
----------------------------------------------------------------------------
Total debt outstanding 275,630 $ 220,785
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust maintains a $400 million fully secured, extendible,
revolving term credit facility with a syndicate of Canadian chartered
banks. This facility consists of a $390 million production facility and a
$10 million working capital facility. The total amount of the facility
is determined by reference to a borrowing base. The borrowing base is
calculated by the bank syndicate and is 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 was
renewed in April 2007, and revised in conjunction with the Seneca
acquisition in September 2007, and will revolve until April 30, 2008 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 2008, 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 2009 with a
final residual payment, if any, in May 2010.
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.
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 December 31,
2007 and 2006 all amounts outstanding were in Canadian dollars.
On December 31, 2007 the effective interest rate on amounts
outstanding under the credit facility was 5.74 percent (2006 - 5.18
percent).
8. CONVERTIBLE DEBENTURES
On August 28, 2007 the Trust issued $100 million principal amount of
6.75% convertible extendible unsecured subordinated debentures, at a
price of $1,000 per debenture. 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 anytime into
trust units at a conversion price of $14.00 per trust unit. The
debentures mature on August 31, 2012 at which time they are due and
payable. The debentures are redeemable by the Trust at a price of $1,050
per debenture on or after September 1, 2010 and on or before August 31,
2011, and at a price of $1,025 per debenture on or after September 1,
2011 and on or before August 31, 2012. On redemption or maturity the
Trust may opt to satisfy its obligation to repay the principal by
issuing trust units.
The 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 will be 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 caption
interest and accretion on convertible debentures in the consolidated
statements of income.
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) -
----------------------------------------------------------------------------
100,000 90,241 5,759
Accretion - 635 -
----------------------------------------------------------------------------
Balance, December 31, 2007 $ 100,000 $ 90,876 $ 5,759
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. UNIT-BASED INCENTIVE COMPENSATION PLAN
The Manager has a long term incentive plan under which employees
receive cash compensation based upon the value and overall return of a
specified number of awarded notional trust units on a fixed vesting
date. The notional trust unit grants are in the form of Restricted Trust
Units ("RTU's") and Performance Trust Units ("PTU's"). RTU's vest one
third on November 30 in each of the three years after grant. PTU's vest
on November 30, three years after grant.
The Trust recorded a total compensation expense of $3.0 million in
2007 of which $2.1 million was recorded as an expense and $0.9 million
as property, plant and equipment (2006 - $2.5 million expense, $1.7
million property, plant and equipment). The compensation expense was
based on the December 31, 2007 trust unit price of $11.60 (2006 -
$12.31), 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:
2007 2006
----------------------------------------------------------------------------
Balance, beginning of year $ 4,153 $ -
Increase in liability 3,027 4,153
Cash payout, relating to units vested November 30, 2006 (2,184) -
----------------------------------------------------------------------------
Balance, end of year $ 4,996 $ 4,153
----------------------------------------------------------------------------
Current portion of liability(1) $ 3,248 $ 3,148
----------------------------------------------------------------------------
Long-term liability $ 1,748 $ 1,005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in accounts payable and accrued liabilities.
10. 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 $89.6 million as at December 31, 2007 (2006
- $65.6 million) based on a total undiscounted and inflated amount of
cash flows required to settle its asset retirement obligations of $276.0
million (2006 - $224.7 million). These costs are expected to be made
over the next 45 years with the majority of the costs incurred between
2008 and 2033. NAL's credit-adjusted risk-free rate of eight percent
(2006 - eight percent) and an inflation rate of two percent (2006 - two
percent) were used to calculate the present value of the asset
retirement obligations.
The following table reconciles the Trust's asset retirement obligations.
2007 2006
----------------------------------------------------------------------------
Balance, beginning of year $ 65,574 $ 61,908
Accretion expense 5,533 4,984
Revisions to estimates 10,294 39
Liabilities incurred 1,079 3,078
Liabilities acquired (Note 4) 12,625 -
Liabilities settled (5,503) (4,435)
----------------------------------------------------------------------------
Balance, end of year $ 89,602 $ 65,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. UNITHOLDERS EQUITY
Unitholders' Capital
The Trust is authorized to issue 500 million trust units of which 90
million units were issued and outstanding as at December 31, 2007
(December 31, 2006 - 78 million). Each trust unit is transferable,
carries the right to one vote and represents an equal undivided
beneficial interest in any distributions from the Trust and in the
assets of the Trust in the event of termination or winding up of the
Trust. All trust units are of the same class with equal rights and
privileges.
Redemption
Unitholders may redeem their trust units for cash at any time, up to
an aggregate maximum value of $100,000 in any calendar month, by
delivering their trust unit certificates to the Trustee, accompanied by a
properly completed notice requesting redemption. The redemption amount
per trust unit will be the lesser of 95 percent of the market price of
the trust units on the principal market on which the trust units are
quoted as trading during the ten-trading day period commencing
immediately after the date on which the trust units are surrendered for
redemption, and the closing market price of the trust units or the
principal market on which the units are quoted for trading on the date
that the trust units are tendered for redemption.
Units Issued:
2007 2006
Units Amount Units Amount
----------------------------------------------------------------------------
Balance, beginning of the year 77,971 $ 824,986 73,977 $ 753,585
Issued for cash 10,246 125,001 - -
Issued under management agreement
restructuring (Note 5) - - 1,592 30,000
Less issue expenses - (7,134) - (29)
Issued from Distribution
Reinvestment Plan 2,277 26,735 2,402 41,430
----------------------------------------------------------------------------
Balance, end of the year 90,494 $ 969,588 77,971 $ 824,986
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Distribution Reinvestment Plan
The Trust has in place a Distribution Reinvestment Plan ("DRIP") and
a Premium Distribution Reinvestment Plan ("Premium DRIP"). The regular
DRIP entitles unitholders to reinvest cash distributions in additional
units of the Trust at 95 percent of the average market price with no
additional fees or commissions. The average market price is the
arithmetic average of the daily volume weighted average trading price of
the trust units during a defined period before the distribution payment
date.
The Premium DRIP component of the plan allows unitholders to
exchange new trust units, acquired by reinvesting their cash
distributions, for a cash payment from the plan broker equal to 102
percent of the monthly distribution on the applicable distribution
payment date.
The trust units issued under the Premium DRIP component of the plan
at a five percent discount to the average market price will be delivered
to the plan broker in exchange for 102 percent of the cash distribution
payable on the participant's existing trust units. At certain times and
at the discretion of management, the Premium DRIP may be suspended.
Cash Distributions
The Trust is required to distribute all of its cash available for
distribution each calendar month, in accordance with the terms of the
Trust Indenture. The cash available for distribution is defined as all
cash amounts received less all costs, expenses, liabilities or
obligations of the Trust, plus net proceeds from the issuance of units,
less any amounts the Trustee, upon recommendations of the Manager,
considers it necessary to retain. The amount considered necessary to
retain includes: any costs, expenses, liabilities or obligations which
are reasonably expected to be incurred such as for property, plant and
equipment; amounts required to be retained for repayment in order to
comply with loan agreements; an allowance for contingencies, working
capital, investments or acquisitions; or any amount appropriate to
retain for a reserve to stabilize distributions. The Trust intends to
continue to make cash distributions, however, these cash distributions
cannot be guaranteed.
Distributions since the inception of the Trust are as follows:
Total
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2005 $ 532,891
2006 distributions 169,589
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2006 $ 702,480
2007 distributions 158,601
----------------------------------------------------------------------------
Accumulated distributions at December 31, 2007 $ 861,081
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per Unit Information
Basic net income per trust unit is calculated using the weighted
average number of trust units outstanding. The calculation of diluted
net income per trust unit excludes the convertible debentures as the
trust units potentially issuable on the conversion of the convertible
debentures are anti-dilutive for the three months and year ended
December 31, 2007. Total weighted average trust units issuable on
conversion of the convertible debentures and excluded from the diluted
net income per trust unit calculation for the three months and year
ended December 31, 2007 were 7,142,857 and 2,465,753 respectively. As at
December 31, 2007, the total convertible debentures outstanding were
immediately convertible to 7,142,857 trust units.
Deficit
The deficit is comprised of the following:
2007 2006
------------------------------------------------------
Accumulated income $ 390,451 $ 333,994
Accumulated cash distributions (861,081) (702,480)
------------------------------------------------------
Deficit, end of year $ (470,630) $ (368,486)
------------------------------------------------------
------------------------------------------------------
The Trust has historically paid cash distributions in excess based
on cash flow generated in the period whereas accumulated non-cash items
such as depletion, depreciation, accretion, on derivative contracts.
Accumulated Other Comprehensive Income
2007 2006
----------------------------------------------------------------------------
Balance, beginning of year $ - $ -
Fair value of derivative instruments on transition
to new accounting standards, net of tax of $1,349
(Note 3) 3,172 -
Reclassification to net income in period, net of
tax $1,349 (Note 3) (3,172) -
----------------------------------------------------------------------------
Balance, end of year $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. INCOME TAXES
The provision for income taxes in the consolidated financial
statements differs from the result that would have been obtained by
applying the combined federal and provincial tax rate to income before
income taxes as follows:
2007 2006
----------------------------------------------------------------------------
Income before taxes $ 52,837 $ 58,789
Statutory income tax rate 33.4% 39.0%
Expected income tax expense 17,648 22,928
Increase (decrease) resulting from:
Non-deductible Crown charges - 8,471
Resource allowance - (9,208)
Alberta Royalty Tax Credit 17 (39)
Valuation allowance 32 200
Net income of the Trust (23,672) (24,937)
Other 2,397 968
Effect of future tax rate reductions (42) 208
----------------------------------------------------------------------------
Current and future income tax recovery (3,620) (1,409)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The future income tax asset is comprised of:
2007 2006
----------------------------------------------------------------------------
Property, plant and equipment $ (3,768) $ (6,794)
Future tax liability resulting from different year ends (2,570) -
Non-capital tax loss carry forward 4,396 3,197
Asset retirement obligations 6,985 7,889
Other 2,921 400
----------------------------------------------------------------------------
7,964 4,692
Valuation allowance (1,266) (1,347)
----------------------------------------------------------------------------
Future income tax asset $ 6,698 $ 3,345
----------------------------------------------------------------------------
Current asset $ 2,602 $-
Long-term asset $ 4,096 $ 3,345
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Trust meets the criteria qualifying it for income tax treatment
permitting a tax deduction for distributions paid to the unitholders in
addition to other deductions available in the Trust. At December 31,
2007, the book amounts of the Trust's assets and liabilities exceed the
tax basis by $213.5 million (2006 - $192.2 million).
The Trust has non-capital loss carry forwards of $17.0 million of
which $9.1 million expire between 2009 and 2015, and $7.9 million expire
between 2025 and 2027.
On June 22, 2007, the Budget Implementation Act, 2007 (Canada) was
enacted to, among other things, implement the October 31, 2006
announcement of the changes to taxability of Income Trusts, made by the
Department of Finance. Under this legislation, distributions to
unitholders will not be deductible by publicly traded income trusts and,
as a result, the Trust will be taxed on its income similar to
corporations. These measures are considered substantively enacted for
purposes of Canadian generally accepted accounting principles.
Accordingly, the Trust measured future income tax assets and liabilities
associated with this new tax. There is no impact on the future tax
recognized in the financial statements, resulting from the
implementation of this tax legislation as it is expected that all
taxable temporary differences of the Trust will reverse prior to January
1, 2011, the date the taxation changes take effect. Accordingly, all
taxable temporary differences have been recognized at a zero taxation
rate. The scheduling of the reversal of temporary differences is based
on management's best estimates and current assumptions, which may
change.
13. DERIVATIVE CONTRACTS AND RISK MANAGEMENT
Commodity Price Risk Management
NAL employs risk management practices to assist in managing cash
flows and support capital programs and distributions. NAL's management
is authorized to hedge up to 50% of its estimated annual net of
production. NAL's risk management programs tend to be scaled-in over
time using a combination of swaps and collars.
NAL currently has the following WTI oil contracts in place for 2008, denominated in U.S. dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
January-June 2-way 100 18,200 75.00 81.00 -
January-December 2-way 100 36,600 85.00 100.00 -
January-December 2-way 100 36,600 83.00 100.00 -
July-December 2-way 100 18,400 75.00 85.50 -
January-June 2-way 100 18,200 73.00 79.00 -
January-June 2-way 100 18,200 72.00 78.00 -
January-June 2-way 100 18,200 71.00 78.50 -
January 2-way 100 3,100 70.50 75.50 -
January-June 2-way 100 18,200 70.00 76.25 -
January 2-way 100 3,100 70.00 75.00 -
April-June 2-way 100 9,100 69.00 74.25 -
January-June 2-way 100 18,200 69.00 74.00 -
January-June 2-way 200 36,400 68.50 73.00 -
January-March 2-way 100 9,100 68.00 74.35 -
January-March 2-way 100 9,100 68.00 73.60 -
January-March 2-way 100 9,100 66.00 71.90 -
January-June 2-way 200 36,400 64.00 72.26 -
January-June 2-way 100 18,200 70.00 75.05 -
January-December 2-way 100 36,600 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 Collars 407,800 74.93 83.58 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volume Total Bought Put Sold Call Swap
Volume
----------------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
SWAPS
January-December swap 100 36,600 - - 73.50
April-December swap 100 27,500 - - 94.00
January-December swap 100 36,600 - - 92.18
January-December swap 100 36,600 - - 87.10
January-December swap 100 36,600 - - 79.10
January-December swap 100 36,600 - - 71.00
January-December swap 100 36,600 - - 80.75
March-October swap 100 24,500 - - 88.10
July-December swap 100 18,400 - - 94.50
July-December swap 100 18,400 - - 94.04
July-December swap 100 18,400 - - 92.00
July-December swap 100 18,400 - - 98.50
July-December swap 100 18,400 - - 98.25
July-December swap 100 18,400 - - 98.10
July-December swap 100 18,400 - - 97.25
July-December swap 100 18,400 - - 96.75
----------------------------------------------------------------------------
Weighted Average Swaps 418,800 - - 87.40
----------------------------------------------------------------------------
NAL currently has the following WTI oil contracts in place for 2008,
denominated in Canadian dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls Cdn$/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 -
January-December 2-way 100 36,600 87.10 97.35 -
February-June 2-way 100 15,100 71.75 76.88 -
February-December 2-way 100 33,500 72.40 77.54 -
----------------------------------------------------------------------------
Weighted Average 2-way 122,000 80.53 88.73 -
----------------------------------------------------------------------------
SWAPS
January-December swap 100 36,600 - - 84.90
January-December swap 100 36,600 - - 90.05
April-June swap 100 9,100 - - 71.55
February-December swap 100 33,500 - - 90.15
February-December swap 100 33,500 - - 90.05
April-December swap 100 27,500 - - 90.20
January-December swap 100 36,600 - - 89.05
January-December swap 100 36,600 - - 87.00
January-December swap 100 36,600 - - 83.80
January-June swap 100 18,200 - - 77.07
January-June swap 200 36,400 - - 75.05
January-December swap 100 36,600 - - 73.55
January-March swap 200 18,200 - - 70.00
July-December swap 100 18,400 - - 93.00
January-June swap 100 18,200 - - 73.77
July-December swap 100 18,400 - - 98.50
January-December swap 100 36,600 - - 90.70
April-December swap 100 27,500 - - 91.00
March-October swap 100 24,500 - - 87.50
January-June swap 100 18,200 - - 84.90
April-December swap 100 27,500 - - 96.50
April-December swap 100 27,500 - - 97.00
July-December swap 100 18,400 - - 94.00
July-December swap 200 36,800 - - 97.00
----------------------------------------------------------------------------
Weighted Average Swaps 668,000 - - 87.10
----------------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place for 2008:
Volume Total Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
COLLARS
January-March 2-way 1,000 91,000 8.40 10.15 -
January-March 2-way 2,000 182,000 8.40 10.25 -
January-March 2-way 1,000 91,000 8.40 10.40 -
January-March 2-way 1,000 91,000 8.00 9.40 -
November-December 2-way 1,000 61,000 7.30 8.50 -
November-December 2-way 1,000 61,000 7.75 9.05 -
November-December 2-way 1,000 61,000 7.55 9.10 -
November-December 2-way 1,000 61,000 7.55 9.05 -
November-December 2-way 1,000 61,000 7.30 8.60 -
November-December 2-way 1,000 61,000 7.85 9.25
November-December 2-way 1,000 61,000 8.00 9.50 -
----------------------------------------------------------------------------
Weighted Average 2-ways 882,000 7.98 9.57 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
----------------------------------------------------------------------------
SWAPS
January-March swap 1,000 91,000 - - 8.90
January-March swap 1,000 91,000 - - 9.13
January-December swap 2,000 732,000 - - 7.60
April-December swap 1,000 275,000 - - 7.40
January-December swap 2,000 732,000 - - 7.40
April-December swap 1,000 275,000 - - 7.31
January-December swap 2,000 732,000 - - 7.26
April-December swap 1,000 275,000 - - 7.05
February-December swap 1,000 335,000 - - 7.20
January-March swap 1,500 136,500 - - 7.20
March-December swap 1,000 306,000 - - 7.10
April-December swap 1,000 275,000 - - 7.15
April-December swap 1,000 275,000 - - 7.10
April-December swap 1,000 275,000 - - 7.05
April-December swap 1,000 275,000 - - 7.23
April-October swap 1,000 214,000 - - 7.35
April-October swap 1,000 214,000 - - 7.60
April-October swap 1,000 214,000 - - 7.85
April-December swap 1,000 275,000 - - 7.30
April-October swap 1,000 214,000 - - 7.65
April-October swap 1,000 214,000 - - 7.43
March-December swap 1,000 306,000 - - 7.10
April-October swap 1,000 214,000 - - 7.15
April-October swap 1,000 214,000 - - 7.09
April-October swap 1,000 214,000 - - 7.80
November-December swap 1,000 61,000 - - 8.66
----------------------------------------------------------------------------
Weighted Average Swaps 7,434,500 - - 7.38
----------------------------------------------------------------------------
For 2009, NAL has the following WTI contracts in place, denominated in U.S.
dollars:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
COLLARS
January-December 2-way 100 36,500 92.00 101.50 -
January-June 2-way 100 18,100 94.00 100.50 -
----------------------------------------------------------------------------
Weighted Average 2-ways 54,600 92.66 101.17 -
----------------------------------------------------------------------------
Total
Volume Volume Bought Put Sold Call Swap
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
----------------------------------------------------------------------------
SWAPS
January-June Swap 100 18,100 - - 97.25
January-December Swap 100 36,500 - - 96.75
----------------------------------------------------------------------------
Weighted Average Swaps 54,600 - - 96.92
----------------------------------------------------------------------------
For 2009, NAL has the following WTI 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$/bbl
----------------------------------------------------------------------------
SWAPS
January-September swap 100 27,300 - - 96.50
January-December swap 200 73,000 - - 97.00
January-September swap 100 27,300 - - 97.00
----------------------------------------------------------------------------
Weighted Average Swaps 127,600 - - 96.89
----------------------------------------------------------------------------
For 2009, NAL has the following AECO natural gas contracts in place:
Total
Volume Volume Bought Put Sold Call Swap
Term Contract GJ/d GJ Cdn$/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 -
----------------------------------------------------------------------------
Weighted Average 2-way 630,000 7.61 9.01 -
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Weighted Average Swaps 810,000 - - 7.36
----------------------------------------------------------------------------
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 Trust's bank debt, and cash and cash equivalents bear interest
at a floating market rate and, accordingly, the fair market value
approximates the carrying amount.
The fair value of the Trust's convertible debentures at December 31, 2007 was $98.0 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.
2007 2006
----------------------------------------------------------------------------
Current unrealized gain on derivative contracts $ 3,389 $-
Current unrealized loss on derivative contracts (12,973) -
----------------------------------------------------------------------------
Fair value of derivative contracts $ (9,584) $-
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On transition to Section 3865 on January 1, 2007, the fair value of
the outstanding contracts of $4.5 million was recorded in accumulated
other comprehensive income, with related tax of $1.3 million, and was
transferred to net income over the term of the respective contracts.
During 2007, the full amount of $4.5 million has been reclassified to
net income and is included in the gain (loss) on derivative contracts.
As at December 31, 2007, the total fair value of derivative
contracts was a liability of $9.6 million. The change in the fair value
for the year of $14.1 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 Years Ended
December 31 December 31
-----------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Unrealized loss, beginning
of period $ (1,371) $ - $ - $ -
Unrealized gain on adoption
of new accounting standards
(Note 3) - - 4,521 -
Unrealized loss, end of period (9,584) - (9,584) -
----------------------------------------------------------------------------
Unrealized loss (8,213) - (14,105) -
Realized gain (loss) in the period (5,510) 1,798 (2,435) 3,375
Reclassification from other
comprehensive income 874 - 4,521 -
----------------------------------------------------------------------------
Gain (loss) on derivative
contracts $(12,849) $ 1,798 $(12,019) $ 3,375
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Credit Risk Management
Accounts receivable includes 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. The credit risk associated with NAL Resources
is also considered to be minimal as amounts owing are from actual
collections of oil and gas sales.
Interest Rate Risk
The Trust is exposed to interest rate risk to the extent that bank debt is at a floating interest rate.
Foreign Exchange Risk
The Trust is exposed to foreign currency fluctuations as crude oil
and natural gas prices received are referenced to U.S. dollar
denominated prices.
14. COMMITMENTS
At December 31, 2007 the Trust had the following contractual obligations and commitments:
2008 2009 2010 2011 2012 Thereafter
----------------------------------------------------------------------------
Office lease(1) $3,672 $3,672 $3,366 $ - $ - $ -
Transportation agreement 1,123 1,123 84 - - -
Processing agreement(2) 469 446 428 414 401 384
Drilling rigs(3) 494 - - - - -
Retention bonus(4) 578 - - - - -
----------------------------------------------------------------------------
Total $6,336 $5,241 $3,878 $ 414 $ 401 $ 384
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including office
space acquired with the Seneca acquisition; and 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 gas processing agreement under take or pay arrangement.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
(4) Represents the Trust's share of the expected future payments under a
staff retention program.
15. SUBSEQUENT EVENT
On February 27, 2008, the Trust completed the acquisition all of the
issued and outstanding common shares of two private oil and gas
companies ("Private Companies"). Total consideration is approximately
$115 million before closing adjustments, consisting of approximately 2.4
million trust units and $86.25 million in cash.
In addition, the Trust entered into an agreement with a wholly owned
subsidiary of MFC, to contribute the assets and liabilities of the
Private Companies to a limited partnership owned 50 percent by the Trust
and 50 percent by MFC. MFC acquired its 50 percent interest in the
limited partnership by payment in cash for one half of the purchase
price for the Private Companies.
Consequently, the total acquisition cost to the Trust for its 50
percent interest in the acquired companies is approximately $57.5
million, comprising approximately 2.4 million trust units and $28.75
million in cash.
----------------------------------------------------------------------------
TRADING PERFORMANCE
For the Quarter Ended Full Year
31-Dec-07 30-Sep-07 31-Dec-06 30-Sep-06 2007 2006
----------------------------------------------------------------------------
PRICE
High $ 12.90 $ 13.65 $ 18.74 $ 21.70 $ 13.80 $ 21.70
Low $ 10.94 $ 11.52 $ 11.80 $ 16.14 $ 10.86 $ 11.80
Close $ 11.60 $ 12.22 $ 12.31 $ 17.57 $ 11.60 $ 12.31
Volume 18,375,644 17,663,336 27,691,472 12,786,792 68,024,233 65,412,678
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 Alberta, Saskatchewan and Ontario. Trust
units trade on the Toronto Exchange under the symbol "NAE.UN".
Contact Information:
NAL Oil & Gas Trust
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: 1-888-223-8792
(403) 515-3407 (FAX)
Email: investor.relations@nal.ca
Website: www.nal.ca