CALGARY--(CCNMatthews - May 1) - NAL Oil
& Gas Trust today announced its financial and operational results
for the first quarter ended March 31, 2007. All amounts are in Canadian
dollars unless otherwise stated.
FIRST QUARTER HIGHLIGHTS
- Production averaged 19,422 barrels of oil equivalent per day (boe/d)
during the first quarter of 2007, exceeding our first quarter
guidance range of 18,800 boe/d to 19,300 boe/d. The positive momentum
was supported by drilling activity in the fourth quarter of 2006, the
results of which carried over to the first quarter 2007. In addition,
first quarter capital spending as well as debottlenecking, workover
and recompletion activity added to strong production results.
- Capital spending during the first quarter totaled $27.1 million,
which was in line with guidance of $27.5 million for the quarter and
$106.0 million forecast for the full year. The Trust participated in
the drilling of 37 gross wells (14.54 net) during the quarter and
achieved a 100% success rate.
- NAL realized an average crude oil price of $61.60 Canadian per barrel
(bbl) during the first quarter, up $0.60/bbl from the first quarter
of 2006. Although the price of West Texas Intermediate crude oil was
down year-over-year, the decline was offset by a lower Canadian
dollar and higher market differentials. NAL's realized natural gas
price was also lower by 12 percent during the first quarter of 2007
due to the late arrival of winter weather.
- On a boe basis, NAL's realized price of $53.17 Canadian during the
quarter was five percent lower than the previous year. Lower
commodity prices were partially offset by hedging gains of $1.30 per
boe in the quarter compared to $0.14 per boe a year earlier.
- NAL's continued focus on active cost management contributed to first
quarter total operating costs being slightly lower year over year on
an absolute basis. On a per boe basis, first quarter operating costs
were $8.08, three percent higher than $7.84 a year ago on higher
volume.
- NAL's operating netback (price less royalties less operating costs)
was $33.84 per boe before hedging gains and $35.14 per boe after
taking into account hedging gains during the quarter. Because of our
high quality production and low operating costs, NAL's operating
netbacks generally represent top quartile performance compared to
trust industry peers.
- NAL paid out $37.6 million, or $0.48 per unit, in distributions
during the first quarter, representing a payout ratio of 69 percent.
With commodity prices near 2007 budgeted levels, the Board of
Directors of the Trust decided to continue monthly distributions at
$0.16 per unit which have been consistent since November 2006.
Monthly distributions are reviewed quarterly by the Board and are
influenced by commodity prices, requirements for capital, business
performance and overall market conditions.
- Net debt at the end of the quarter was $227.0 million, representing a
ratio of 1.05 times last twelve months' cash flow. At NAL's request,
NAL's syndicate of banks has recently approved a $25 million increase
in the Trust's credit lines to $325 million, leaving $95 million in
available lines of credit.
Outlook and Guidance
--------------------
"I am very encouraged with the performance and momentum that we have
been able to sustain through the early part of 2007," said Andrew
Wiswell, President and Chief Executive Officer. "These first quarter
results reflect the quality of our assets and the strength of our
operating teams, and we are solidly positioned to meet or exceed our
guidance for full year 2007.
-------------------------------------------------------------------------
2007 FY
2006 FY Actual Guidance 2007 Q1 Actual
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Production (boe/d) 19,444 18,500 - 19,000 19,422
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Costs ($/boe) 8.31 8.90 - 9.40 8.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------
General & Admin ($/boe) 1.54 1.75 - 1.95(*) 1.92(*)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital Spending ($MM) 124 106 27
-------------------------------------------------------------------------
(*) Excluding special retention bonus and unit based compensation.
Early in the second quarter, the management team completed its three
year plan for the Trust focusing on its existing properties and core
areas. The Trust has identified opportunities to sustain production in
the 18,000- 19,000 boe/d range for the 2007 through 2009 period.
For the balance of 2007, NAL's key strategies and priorities remain focused on the following:
- execute an effective capital program
- deliver targeted or better operational performance
- add incremental opportunities in core areas
- evaluate acquisition and partnering opportunities
- assess and understand alternate structures post 2010.
At 4:00 p.m. MDT on Tuesday, May 1, 2007 NAL will conduct a
conference call to discuss its first quarter results. Mr. Andrew
Wiswell, President and CEO, will host the conference call with other
members of the Management Team. The call is open to analysts, investors,
and all interested parties. If you wish to participate, call
1-800-590-1508. Those who are unable to listen to the call live may
listen to a recording of it by calling 1-877-289-8525, reservation
21228432 followed by the pound sign. The recording will be available
until May 9, 2007.
-------------------------------------------------------------------------
NAL Oil & Gas Trust will hold its Annual General Meeting of
Unitholders on May 9, 2007 at 9:30a.m. MDT in the Strand/Trivoli Room
of The Metropolitan Conference Centre,
333 - 4 Avenue SW, Calgary, Alberta.
-------------------------------------------------------------------------
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, boes 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.
Financial and Operating Highlights
(thousands of dollars, except per unit and boe data)
-------------------------------------------------------------------------
Three Months Ended
March 31 March 31 December 31
2007 2006 2006
-------------------------------------------------------------------------
FINANCIAL
Gross revenue, net of royalties $71,231(1) $81,272 $75,694
Net income 16,710(1) 24,610 20,472
Funds from operations 54,234 57,664 55,795
Distributions declared 37,606 42,597 39,663
Funds from operations per unit 0.69 0.77 0.72
Distributions declared per unit 0.48 0.57 0.51
Payout ratio 69% 74% 71%
Average number of units outstanding
(000s) 78,258 74,544 77,697
Total assets $790,139 $791,327 $796,902
Bank debt, net of working capital
excluding derivative contracts 227,014 181,443 223,061
Unitholders' equity 444,366 497,310 456,500
Costs per boe (6:1): Operating $8.08 $7.84 $7.13
General and
administrative,
excluding special
retention bonus 1.92 1.36 1.33
General and
administrative
special retention
bonus 0.32 - -
Unit-based incentive
compensation (0.01) 1.01 (0.07)
Management fees - 0.41 -
OPERATING
Daily production Oil (bbl) 9,326 9,552 9,700
Natural gas (Mcf) 47,718 51,937 47,153
Natural gas liquids
(bbl) 2,143 1,973 1,958
Oil equivalent
(boe - 6:1) 19,422 20,181 19,517
Average pricing, net of transportation
charges and before hedging gains
and losses
Liquids:
WTI (US$/bbl) 58.16 63.48 60.21
NAL average oil (Cdn$/bbl) 61.60 61.00 58.53
NAL natural gas liquids (Cdn$/bbl) 45.36 52.53 43.24
Natural gas:
AECO (Cdn$/Mcf) - daily spot 7.41 7.59 6.90
AECO (Cdn$/Mcf) - monthly 7.46 9.28 6.36
NAL natural gas Western Canada
(Cdn$/Mcf) 7.48 8.53 6.84
NAL natural gas Lake Erie (Cdn$/Mcf) 8.75 9.40 8.16
NAL average natural gas (Cdn$/Mcf) 7.58 8.59 6.96
NAL oil equivalent before hedging
gains (losses)(Cdn$/boe - 6:1) 53.17 56.12 49.77
Average foreign exchange rate (Cdn$/US$) 1.172 1.155 1.139
Operating netback before hedging gains
(losses) ($/boe) 33.84 35.57 32.48
Hedging gains per boe 1.30 0.14 1.00
Operating netback ($/boe) 35.14 35.71 33.48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes unrealized loss on derivative contracts due to
implementation of new accounting standards, January 1, 2007.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis ("MD&A") should be read in
conjunction with the Interim Consolidated Financial Statements for the
three months ended March 31, 2007 and the audited Consolidated Financial
Statements and MD&A for the year ended December 31, 2006 of NAL Oil
& Gas Trust ("NAL" or the "Trust"). It also 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.
Operating netbacks, cash flow netbacks and funds from operations are
not recognized measures under Canadian generally accepted accounting
principles ("GAAP"). Management believes that in addition to net income,
operating netbacks, cash flow netbacks, funds from operations and funds
from operations per unit are useful supplemental measures as they
provide an indication of the results generated by the Trust's principal
business activities prior to the consideration of how those activities
are financed. Investors should be cautioned, however, 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. NAL
calculates funds from operations prior to the change in non-cash working
capital related to operating activities, with the per unit amount
calculated using the weighted average units outstanding for the period.
FORWARD-LOOKING INFORMATION
This disclosure contains certain forward-looking statements that
involve substantial known and unknown risks and uncertainties, many of
which are beyond NAL's control, including: the impact of general
economic conditions in Canada and in the United States, industry
conditions, changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced, increased competition, the lack of
availability of qualified operating or management personnel,
fluctuations in commodity prices, foreign exchange or interest rates,
stock market volatility and fluctuations in market valuations of
companies with respect to announced transactions and the final
valuations thereof, and the ability to obtain required approvals from
regulatory authorities. NAL's actual results, performance or achievement
could differ materially from those expressed in, or implied by, these
forward-looking statements and, accordingly, no assurances can be given
that any of the events anticipated by the forward-looking statements
will transpire or occur, or if any of them do so, what benefits,
including the amount of proceeds, that NAL will derive therefrom.
DEVELOPMENT ACTIVITIES
The Trust participated in the drilling of 37 (14.54 net) wells during the first quarter with a success rate of 100 percent.
First Quarter Drilling Activity
-------------------------------------------------------------------------
Crude Oil Natural Gas Service Wells
------------------------------------------------
Gross Net Gross Net Gross Net
Operated wells 19 8.58 7 4.78 - -
Non-operated wells 3 0.38 8 0.8 - -
-------------------------------------------------------------------------
Total wells drilled 22 8.96 15 5.58 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Dry & Abandoned Total
--------------------------------
Gross Net Gross Net
Operated wells - - 26 13.36
Non-operated wells - - 11 1.18
---------------------------------------------------------
Total wells drilled - - 37 14.54
---------------------------------------------------------
---------------------------------------------------------
Southeast Saskatchewan Core area
--------------------------------
The Trust drilled 11 horizontal wells (4.9 net) during the quarter
spending $9.8 million. Two horizontal farmin wells were drilled in
Browning with initial production of 400 boe/d and 150 boe/d setting up
two further drills on 100 percent NAL lands. At Alida, there was
continued success with a three well horizontal program. In the
Nottingham area a successful edge well was drilled with low water cut
which will validate additional drilling for later in the year. Two
horizontal wells were farmed out and drilled successfully into the
Bakken in the Stoughton area. The Trust has retained a 25 percent
working interest with up to six additional follow up locations.
Additional drilling activity was also completed in the Midale and
Elswick (Non Op) areas.
Two contracted rigs will be drilling continuously for the rest of
2007, starting up again in May. In addition to the development drilling
program, a water flood project will be completed in the Rosebank area.
Gas Focus Core Area (Lacombe - Nevis - Hanna - Pine Creek)
----------------------------------------------------------
Activity for the quarter was split between new drilling and
facilities work associated with fourth quarter 2006 development
projects. There were five wells drilled (3.8 net) and significant tie in
work completed in Lacombe (CBM), Clive, Wilson Creek and Willisden
Green. Total capital for the quarter was $11.1 million. The Trust
brought on 275 boe/d of production associated with late 2006 development
and is positioned to bring on 425 boe/d of behind-pipe production
volumes in the second quarter. This production is associated with the
first quarter drilling program with some additional tie-ins of 2006
Lacombe CBM wells.
Success in Pine Creek (1.5 MMcf/d test) and in Hanna (100 bbl/d oil
test) has firmed up additional activity for the remainder of the year.
The Trust also expects to complete a four well drilling program for
Mannville gas targets in the Hanna area by year end. A 22 well Lacombe
CBM program has commenced following up on the success of our 2006
project. Three wells of this program were drilled in the first quarter
and the remainder will be finished post break up. Completion work will
be done as a continuous program after drilling all the wells to take
advantage of the cost savings associated with multi-well stimulation
activities. Infrastructure is in place for gas gathering, so tie-ins are
expected to proceed in an efficient time frame with production from the
2007 wells expected to commence in the third quarter.
Central Alberta Core Area
-------------------------
Eight wells (2.5 net) were drilled at a cost of $3.6 million.
Production from these wells (five operated and three non-operated) is
expected to be on stream in the second quarter. A successful
recompletion in Westward Ho is producing at 1.0 MMcf/d and a gathering
system reconfiguration linking up three compressors has created capacity
for an additional 100 boe/d of restricted production.
The remainder of the year will be focused on 15 identified
recompletions and drilling seven Mannville tests in the Garrington and
Westward Ho areas.
CAPITAL EXPENDITURES
Capital expenditures for the quarter ended March 31, 2007 were
consistent with budget and totaled $27.1 million, compared with $19.9
million in the quarter ended March 31, 2006.
The capital budget for full year 2007 remains at $106 million,
consistent with previous guidance. The Trust expects to drill 189 (87.1
net) wells during the year.
Capital Expenditures ($000s)
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Drilling, completion and production equipment $23,650 $14,551
Plant and facilities 2,252 1,644
Seismic 259 728
Land 251 441
Property acquisitions (dispositions) (25) (122)
-------------------------------------------------------------------------
Total exploitation and development 26,387 17,242
-------------------------------------------------------------------------
Office equipment 43 -
Capitalized G&A 767 912
Capitalized unit-based compensation (139) 1,736
-------------------------------------------------------------------------
671 2,648
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total capital expenditures 27,058 19,890
-------------------------------------------------------------------------
-------------------------------------------------------------------------
PRODUCTION
Trust production volumes exceeded first quarter guidance averaging
19,422 boe/d for the three months ended March 31, 2007. Year over year
production was four percent lower than the 20,181 boe/d for the
comparable period in 2006.
Our strong fourth quarter 2006 drilling program combined with first
quarter spending meeting expectations, resulted in daily production
exceeding our range of guidance for the first quarter (18,800-19,300
boe/d). As forecast, turnarounds, break up and wet weather normally
contribute to lower production for the second quarter. Positive
production momentum going into the second quarter plus tie-ins of
production behind pipe will support production and assist in moderating
the impact of plant turnarounds. At this point, the Trust maintains its
previously announced full year guidance of 18,500 - 19,000 boe/d and
will update the forecast in its second quarter 2007 press release.
Average Daily Production Volumes
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Oil (bbl/d) 9,326 9,552
Natural gas (Mcf/d) 47,718 51,937
NGL's (bbl/d) 2,143 1,973
Oil equivalent (boe/d) 19,422 20,181
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The Trust's production weighting was relatively unchanged from the
comparable period in 2006 with oil and natural gas liquids production
representing 59 percent of total production and natural gas 41 percent.
Production Weighting
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Oil 48% 47%
Natural gas 41% 43%
NGLs 11% 10%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
REVENUE AND FUNDS FROM OPERATIONS
Gross revenue from oil, natural gas and natural gas liquids sales,
after transportation costs, totaled $93.8 million for the three months
ended March 31, 2007, a nine percent decrease over the first quarter of
2006.
Revenue decreased year-over-year due to lower production volumes and
lower realized commodity prices. Compared to the first quarter of 2006,
production decreased four percent and average commodity prices
decreased by five percent for the first quarter of 2007, primarily due
to lower natural gas volumes and lower natural gas realized prices.
Funds from operations tracked revenues in the first quarter of 2007,
down six percent in total from the first quarter of 2006 and down 10
percent from $0.77 to $0.69 on a per unit basis.
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Revenue(1) ($000s) 93,839 102,885
$/boe 53.68 56.65
Funds from operations(2) ($000s) 54,234 57,664
$/boe 31.03 31.75
$/unit 0.69 0.77
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation prior to
royalties and excluding gain/loss on derivative contracts.
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
Average Pricing
(net of transportation charges)
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Liquids
WTI (US$/bbl) 58.16 63.48
NAL average oil (Cdn$/bbl) 61.60 61.00
NAL natural gas liquids (Cdn$/bbl) 45.36 52.53
Hedging gains 2.67 -
Natural Gas (Cdn$/Mcf)
AECO - daily spot 7.41 7.59
AECO - monthly 7.46 9.28
NAL Western Canada natural gas 7.48 8.53
NAL Lake Erie natural gas 8.75 9.40
NAL average natural gas 7.58 8.59
Hedging gains 0.01 0.06
NAL Oil Equivalent before hedging (Cdn$/boe - 6:1) 53.17 56.12
Average Foreign Exchange Rate (Cdn$/US$) 1.172 1.155
-------------------------------------------------------------------------
-------------------------------------------------------------------------
OIL MARKETING
NAL sells its crude oil based on refiners' posted prices at
Edmonton, Alberta, and Cromer, Manitoba, adjusted for transportation and
the quality of 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 first quarter average crude oil price per barrel, net of
transportation costs, was $61.60, as compared to $61.00 for the
comparable quarter of 2006. WTI (US$/bbl) decreased eight percent from
the comparable period in 2006 to $58.16 per barrel, however a slight
increase in the average exchange rate and improved differentials to WTI
resulted in a virtually equivalent realized oil price as compared to the
first quarter of 2006.
Natural gas liquids prices averaged $45.36 per barrel in the first quarter, 14 percent lower than the first quarter of 2006.
NATURAL GAS MARKETING
Approximately 92 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 8 percent tied to NYMEX or other
indexed referenced prices. Eight percent of the Trust's gas sales is
from its Lake Erie property and receives a higher price due to close
proximity to the Ontario and northeastern U.S. markets.
For the three months ended March 31, 2007, the Trust's gas sales
averaged $7.58/Mcf, as compared to $8.59/Mcf for the comparable quarter
in 2006, a decrease of 12 percent. The quarter-over-quarter decrease in
gas prices was attributable to decreased benchmark AECO prices. Natural
gas sales from the Lake Erie property averaged $8.75/Mcf in Q1 2007,
compared to $9.40/Mcf in 2006, a decrease of seven percent.
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 percent of its annual net production.
NAL's risk management programs tend to be scaled in over time using a
combination of swaps and collars. During the first quarter of 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.
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Average crude volumes hedged (bbl/d) 2,300 2,493
Crude oil realized gain (000's) $2,238 -
Gain per bbl $2.67 -
Average natural gas volumes hedged (GJ/d) 14,500 2,000
Natural gas realized gain (000's) $36 $246
Gain per Mcf $0.01 $0.06
Average BOE hedged 4,592 2,809
Total realized gain (000's) $2,274 $246
Gain per boe $1.30 $0.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 loss on derivative contracts presented in the income statement
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 will be reclassified
to net income over the term of the derivative contracts, of which $1.4
million was reclassified in the first 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 and market
valuations provided by third party sources. Accordingly, the magnitude
of the unrealized gain or loss will continue to fluctuate with changes
in commodity prices.
Using this methodology, the fair value of the derivatives at March
31, 2007 was a loss of $3.2 million. Accordingly, first quarter income
of 2007 includes a $7.7 million unrealized loss on derivatives resulting
from the change in the fair value of the derivative contracts during
the period. The loss was comprised of a $3.5 million unrealized loss on
crude oil contracts and a $4.2 million unrealized loss on natural gas
contracts. The loss is attributable to higher commodity forward prices
at March 31, 2007 as compared to December 31, 2006.
The gain/loss on derivative contracts for the quarter is as follows:
Gain (loss) on Derivative Contracts (000's)
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Realized gain 2,274 246
Unrealized (loss) (7,750) -
Reclassification from other comprehensive income 1,379 -
-------------------------------------------------------------------------
(4,097) 246
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the remainder of 2007, NAL has the following risk management contracts
outstanding.
Risk Management Contracts Summary
-------------------------------------------------------------------------
Crude Oil Natural Gas
-------------------------------------------------------------------------
Swap (bbls) 367,000 Swap (GJ) 1,925,000
$US/bbl 67.58 $Cdn/GJ $7.16
Collars (bbls) 431,100 Collars (GJ) 2,475,000
$US/bbl $63.86 - $71.65 $Cdn/GJ $6.61 - $8.48
Totals (bbls) 798,100 Total (GJ) 4,400,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
In addition, for 2008 the Trust has a 200 bbl/d crude oil collar in
place for January to June at US $64.00-$72.26, a 100 bbl/d collar for
January to March at US $66.00-$71.90 and a 100 bbl/d swap for January to
March at US$69.35. Natural gas contracts are in place for January to
March 2008 consisting of collars for 4,000 GJ/d at $8.40-$10.26 and
swaps for 3,500 GJ/d at $8.24.
ROYALTY EXPENSES
Crown, freehold and overriding royalties were $20.6 million for the
three months ended March 31, 2007. Expressed as a percentage of gross
sales, before gain/loss on derivative contracts, and transportation
costs, the net royalty rate was consistent with budget at 21.8 percent,
down from 23.2 percent for the same period last year, which incorporated
an adjustment to freehold mineral tax.
Royalty Expenses
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Net royalties ($000s) 20,560 24,056
As % of revenue(1) 21.8 23.2
$/boe 11.76 13.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Oil and natural gas and liquid sales before transportation and
gains/losses on derivative contracts.
OPERATING COSTS
For the quarter ended March 31, 2007, total operating costs were
lower compared to the similar period a year earlier. On a boe basis,
operating costs averaged $8.08, a three percent increase from the $7.84
for the quarter ended March 31, 2006, which related to higher annualized
production for 2006.
Costs for the first quarter are slightly lower than budget but trend
upward during the second and third quarters due to scheduled facility
maintenance.
Operating Costs
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Operating costs ($000s) 14,126 14,237
As % of revenue 15.1 13.8
$/boe 8.08 7.84
-------------------------------------------------------------------------
-------------------------------------------------------------------------
OPERATING NETBACK
For the quarter ended March 31, 2007, NAL's operating netback,
before realized gains on derivative contracts, was $33.84 per boe, a
decrease of five percent from $35.57 for the quarter ended March 31,
2006. The decrease was due to lower revenue and an increase in operating
costs, offset by a reduction in royalties. The decrease in revenue of
five percent was primarily driven by a 12 percent decrease in the
average realized natural gas price per Mcf and a 14 percent decrease in
NGL pricing per boe.
Operating Netback ($/boe)
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Revenue(1), 53.68 56.65
Royalties, net (11.76) (13.24)
Operating expenses (8.08) (7.84)
-------------------------------------------------------------------------
Operating netback, before hedging 33.84 35.57
Realized gains on derivative contracts 1.30 0.14
-------------------------------------------------------------------------
Operating netback, after hedging 35.14 35.71
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales less transportation
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 March 31, 2007, G&A expenses were
$3.9 million, compared with $2.5 million in the comparable quarter in
2006. In addition, $0.8 million of G&A costs relating to
exploitation and development activities were capitalized in the first
quarter of 2007, compared with $0.9 million in the first quarter of
2006.
Total G&A increased $1.3 million to $4.7 million in the first
quarter of 2007 due to increased compensation costs associated with
hiring, compensating and retaining employees. Included in G&A
expenses for the first quarter of 2007 is a retention bonus of $0.6
million associated with a staff retention program established at year
end 2006. This represents a $0.32 per boe charge in the first quarter
and is expected to average $0.20 per boe over the full year 2007.
G&A excluding the retention bonus and unit based compensation plan
is $1.92 per boe, in line with guidance for the year.
General and Administrative Expenses
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
G&A expenses ($000s)
G&A 3,355 2,464
Retention bonus 560 -
-------------------------------------------------------------------------
3,915 2,464
Capitalized G&A ($000s) 767 912
-------------------------------------------------------------------------
Total G&A ($000s) 4,682 3,376
Expensed G&A costs:
G&A, excluding retention bonus ($/boe) 1.92 1.36
Retention bonus ($/boe) 0.32 -
-------------------------------------------------------------------------
Total G&A expenses ($/boe) 2.24 1.36
As % of revenue 4.2 2.4
Per Trust unit ($) 0.05 0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
UNIT-BASED INCENTIVE COMPENSATION PLAN
The employees of the Manager are all members of a unit based
incentive plan (the "Plan"). The Plan results in employees receiving
cash compensation based upon the value and overall return of a specified
number of notional Trust units. The Plan consists of Restricted Trust
Units ("RTUs") and Performance Trust Units ("PTUs"). RTUs vest one third
on November 30 in each of three years after grant date. PTUs vest at
the end of three years. Distributions paid during the vesting period are
assumed to be reinvested in notional units on the date of distribution.
Upon vesting, the employee is entitled to a cash payout based on the
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 units held at vesting.
During the first quarter of 2007, the Trust recorded a reduction in
unit-based incentive compensation charges in the total amount of $0.2
million as compared to a charge of $3.6 million in the comparable
quarter of 2006. The reduction in unit based compensation expense in the
first quarter of 2007 is a reflection of the decrease in the unit price
of the Trust since December 31, 2006 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-ending unit price and performance factors.
The compensation charges relating to the units granted are
recognized over the vesting period based on the 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 March 31, 2007, the Trust has a payable for unit-based incentive
compensation in the amount of $1.8 million, of which $0.9 million is
expected to be paid in December 2007. The balance represents the
long-term portion of the Trust's estimated liability for the unit based
incentive plan as at March 31, 2007. This amount is payable in December
2008 and December 2009.
Unit-Based Compensation
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) (24) 1,838
Capitalized ($000s) (139) 1,736
-------------------------------------------------------------------------
Total unit-based compensation ($000s) (163) 3,574
Expensed unit-based compensation:
As % of revenue 0.0% 1.8%
$/boe (0.01) 1.01
Per Trust unit ($) 0.00 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
MANAGEMENT CONTRACT AND FEES
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
joint operator. As a result, a significant portion of the net operating
revenues and capital expenditures during the year is 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. The management contract was restructured effective May 31,
2006, after which no further management fees are payable. During the
first quarter of 2006, the Trust paid $750,000 for management fees. In
addition, the Trust paid $2.9 million (2006 - $2.1 million) for the
reimbursement of G&A expenses incurred by the Manager on behalf of
the Trust pursuant to the Management Contract. 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, $2.2
million was paid in the first quarter of 2007 relating to units that
vested November 30, 2006.
INTEREST
Interest expense includes charges on borrowings plus standby fees on
the unused portion of the bank credit facility. NAL's average
outstanding bank debt for the first quarter of 2007 was $223.6 million,
as compared to $207.0 million for the first quarter of 2006. As
forecast, net bank debt outstanding at March 31, 2007 was $227 million,
relatively consistent with the $223 million outstanding at December 31,
2006. NAL's effective interest rate averaged 5.14 percent in 2007,
compared with 4.51 percent in the first quarter of 2006. NAL's interest
is at floating rate. The increase in the rate from the first quarter of
2006 is attributable to rate increases in the market.
Interest expense for the year increased by $0.5 million to $2.9
million, as compared to $2.4 million for the comparable period in 2006.
Interest and Bank Debt ($000s)
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Interest on bank debt 2,859 2,370
Bank debt outstanding at period end 229,633 198,093
Net bank debt outstanding at period end(1) 227,014 181,443
Net bank debt-to-cash flow ratio 1.05 0.76
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital excluding
derivative contracts.
CASH FLOW NETBACK
For the quarter ended March 31, 2007, NAL's cash flow netback was
$31.27 per boe, comparable with $31.63 per boe in the first quarter of
2006. Operating netbacks, after hedging, were consistent year over year,
and the increase in G&A expenses and interest in the first quarter
of 2007 was offset by the reduction in unit-based incentive compensation
and the elimination of management fees.
Cash Flow Netback ($/boe)
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Operating netback, after hedging 35.14 35.71
Management fees - (0.41)
G&A expenses, excluding retention bonus (1.92) (1.36)
Retention bonus (0.32) -
Unit-based incentive compensation 0.01 (1.01)
Interest (1.64) (1.30)
-------------------------------------------------------------------------
Cash flow netback 31.27 31.63
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital excluding
derivative contracts.
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION
(DDA)
Depletion of oil and natural gas properties, including the
capitalized portion of the asset retirement obligation, and depreciation
of equipment are provided for on a unit-of-production basis using
estimated proved reserves volumes.
For the quarter ended March 31, 2007, depletion on property, plant
and equipment and accretion on the asset retirement obligation increased
by five percent over the comparable period in 2006 due to a nine
percent increase in the DDA rate per boe of production, partially offset
by a four percent decrease in production volumes.
The DDA rate will fluctuate period over period depending on the
amount and type of capital expenditures and the amount of reserves
added.
Depletion, Depreciation and Accretion Expenses
-------------------------------------------------------------------------
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
Depletion and depreciation ($000s) 34,428 32,905
Accretion of asset retirement obligation ($000s) 1,297 1,239
-------------------------------------------------------------------------
Total DDA ($000s) 35,725 34,144
DDA rate per boe ($) 20.44 18.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
TAXES
Taxes include federal and provincial capital and income taxes relating to the Trust and its subsidiary companies.
In the first quarter of 2007, NAL had a future income tax recovery
of $2.7 million compared with an expense of $0.05 million in the
corresponding period of the prior year. A substantial part of the $2.7
million recovery relates to the future tax resulting from the
recognition of derivative instruments on the balance sheet, due to the
implementation of new accounting standards, January 1, 2007.
The Trust is a taxable trust 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, and issue costs. In addition,
Canadian Exploration Expense ("CEE"), Canadian Development Expense
("CDE") and Undepreciated Capital Cost ("UCC") are incurred and are
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 income taxes in 2007.
As at March 31, 2007, the Trust's (including all subsidiaries)
estimated tax pools (unaudited) available for deduction from future
taxable income approximate $505 million, of which approximately 43
percent represents COGPE and 30 percent UCC, with the remaining balance
represented by CEE, CDE, trust unit issue costs and non-capital loss
carry forwards.
On March 29, 2007, the Minister of Finance introduced a bill to
implement the changes to taxability of Income Trusts as outlined on
October 31, 2006 and clarified on December 21, 2006. Under the proposed
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. The proposed rules, if passed
into law, would be applicable commencing in 2011. However, if the
proposed legislation is implemented, the Trust would be required to
recognize in its accounts, in the period in which the change is
substantially enacted, future income taxes on temporary differences in
the Trust.
CAPITAL RESOURCES AND LIQUIDITY
The capital structure of the Trust is comprised of Trust units and bank debt.
As at March 31, 2007, NAL had 78,533,618 units outstanding, compared
with 77,971,268 units at December 31, 2006. The increase from December
31, 2006 is attributable to units issued under the distribution
reinvestment program.
For the quarter ended March 31, 2007, the distribution reinvestment
("DRIP") plan resulted in 562,350 units being issued at an average price
of $11.66 per unit for total proceeds of $6.6 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 ("Premium DRIP") plan
allows unitholders to exchange such units for a cash payment from the
Plan Broker equal to 102 percent of the monthly distribution.
On March 10, 2006, the Trust announced the suspension of the Premium DRIP.
The participation rate in the regular DRIP averaged 17.5 percent
over the past quarter consistent with recent experience. The Trust
continues to monitor the participation in this plan in conjunction with
its capital requirements.
As at March 31, 2007 the Trust had bank debt of $227.0 million (net
of working capital excluding derivative contracts) compared with $223.1
million at December 31, 2006 and $181.4 million as at March 31, 2006. At
the end of the first quarter, the Trust had a net bank debt to equity
ratio of 0.51 and a net bank debt to twelve months trailing cash flow
ratio of 1.05.
The Trust recently renewed its credit facility and increased the
facility from $300 million to $325 million. The credit facility is a
fully secured, extendible, revolving facility and will revolve 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 $315 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, a portion of the cash flow otherwise available to unitholders
would be used to repay the facility in four equal quarterly
installments commencing May 2009.
Total bank debt amounted to $229.6 million at March 31, 2007
compared with $220.8 million as at December 31, 2006. Of the debt
outstanding at March 31, 2007, $227.8 million was outstanding under the
production facility and $1.8 million under the working capital facility.
Capitalization
-------------------------------------------------------------------------
March 31, Dec 31, March 31,
2007 2006 2006
-------------------------------------------------------------------------
Trust unit equity ($000s) 444,366 456,500 497,310
Bank debt ($000s) 229,633 220,785 198,093
Net bank debt(1) ($000s) 227,014 223,061 181,443
Net bank debt to equity 0.51 0.49 0.36
Net bank debt to trailing 12-month
cash flow 1.05 1.01 0.76
Units outstanding (000s) 78,534 77,971 75,159
-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital, excluding
derivative contracts.
Subject to fluctuations in commodity prices, the Trust anticipates
that it will continue to have adequate liquidity to fund planned capital
spending during 2007 through a contribution of funds from operations,
funds received from its distribution reinvestment program and bank
borrowings.
ASSET RETIREMENT OBLIGATION
At March 31, 2007, the Trust reported an Asset Retirement Obligation
("ARO") balance of $64.6 million ($65.6 million at December 31, 2006)
for future abandonment and reclamation of the Trust's oil and gas
properties and facilities. The ARO balance was increased by accretion
expense of $1.3 million in the first quarter of 2007 ($1.2 million in
the first quarter of 2006) and reduced by $1.9 million for actual
abandonment and environmental expenditures incurred in the first quarter
of 2007 ($1.1 million in the first quarter of 2006).
DISTRIBUTIONS TO UNITHOLDERS
The Trust sets distributions based upon commodity prices, financial
market conditions, internal capital investment opportunities and the
resulting impact on taxability and payout ratios. 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.
For the three months ended March 31, 2007, funds from operations
amounted to $54.2 million, compared with $57.7 million for the three
months ended March 31, 2006. NAL declared cash distributions of $37.6
million ($0.48 per unit) in the first quarter as compared to $42.6
million ($0.57 per unit) in the first quarter of 2006. This represented a
69 percent payout ratio for the quarter, compared with a 74 percent
payout ratio in the comparable quarter in 2006.
The weighted average number of units outstanding during the first
quarter of 2007 increased by five percent to 78.3 million from 74.5
million in 2006.
Distributions
-------------------------------------------------------------------------
Three months ended
March 31
2007 2006
-------------------------------------------------------------------------
Funds from operations ($000s) 54,234 57,664
Distributions declared ($000s) 37,606 42,597
Funds from operations per unit(1) $0.69 $0.77
Distributions declared per unit $0.48 $0.57
Weighted average units outstanding (000s) 78,258 74,544
-------------------------------------------------------------------------
(1) Based on weighted average units outstanding.
VARIABLE INTEREST ENTITIES
NAL has no variable interest entities.
CONTRACTUAL OBLIGATIONS
NAL has entered into several contract obligations as part of conducting
day-to-day business. NAL has the following commitments for the next five
years:
-------------------------------------------------------------------------
($000s) 2007 2008 2009 2010 2011
-------------------------------------------------------------------------
Office Lease(1) 2,010 2,580 2,580 2,365 -
Transportation 1,069 765 765 82 -
Processing Agreement(2) 368 469 446 428 414
Drilling rigs(3) 1,481 494 - - -
Retention bonus(4) 832 832 - - -
-------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, both base
rent and operating costs, held by the Manager, of which the Trust is
allocated a pro rata share (currently approximately 52 percent) of
the expense on a monthly basis.
(2) Represents a gas processing agreement with a take or pay arrangement.
(3) Represents the Trust's share of 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.
QUARTERLY INFORMATION
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
($000s, except per
unit and production
amounts) Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenue, net of
royalties 71,231(2) 75,694 75,798 77,988 81,272
Per unit 0.91 0.97 0.98 1.03 1.08
Funds from
operations(1) 54,234 55,795 54,107 52,210 57,664
Per unit 0.69 0.72 0.70 0.69 0.77
Net income 16,710 20,472 20,473 (5,357)(3) 24,610
Per unit 0.21 0.26 0.27 (0.07) 0.33
Average oil
equivalent
production
(boe/d - 6:1) 19,422 19,517 19,079 19,012 20,181
-------------------------------------------------------------------------
---------------------------------------------------
2005
---------------------------------------------------
($000s, except per
unit and production
amounts) Q4 Q3 Q2
---------------------------------------------------
Revenue, net of
royalties 95,643 85,613 71,482
Per unit 1.30 1.18 1.00
Funds from
operations(1) 65,837 62,442 49,881
Per unit 0.90 0.86 0.70
Net income 30,777 31,710 20,804
Per unit 0.42 0.44 0.29
Average oil
equivalent
production
(boe/d - 6:1) 20,514 19,710 18,349
---------------------------------------------------
(1) Represents cash flow from operating activities prior to the change in
non-cash working capital items.
(2) Includes unrealized loss on derivative instruments due to
implementation of new accounting standards Jan 1, 2007.
(3) Includes non-cash management restructuring fee of $27.2 million.
FINANCIAL REPORTING DISCLOSURE CONTROLS
Management has evaluated the effectiveness of the Trust's financial
reporting disclosure controls and procedures as at March 31, 2007, and
has concluded that such financial reporting disclosure controls and
procedures were effective as at that date.
CHANGES TO INTERNAL CONTROL OVER FINANCIAL REPORTING
There were no changes to the Trust's internal control over financial
reporting since December 31, 2006 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, 2006 audited consolidated financial
statements. Certain accounting policies require that management make
appropriate decisions when formulating estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and
expenses. The Manager reviews the estimates regularly. The emergence of
new information and changed circumstances may result in actual results
or changes to estimated amounts that differ materially from current
estimates. NAL might realize different results from the application of
new accounting standards published, from time to time, by various
regulatory bodies. An assessment of NAL's significant accounting
estimates is discussed in the MD&A filed with NAL's audited
consolidated financial statements for the year ended December 31, 2006.
NEW ACCOUNTING POLICIES
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, 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 2
to the interim consolidated financial statements.
Dated: May 1, 2007
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
-------------------------
As at As at
March 31, December 31,
2007 2006
(unaudited) (audited)
-------------------------
Assets
Current assets
Cash $5,123 $6,295
Accounts receivable and other 43,607 44,467
Derivative contracts (Note 2) 1,304 -
-------------------------------------------------------------------------
50,034 50,762
Future income tax asset 5,110 3,345
Property, plant and equipment, net 734,995 742,795
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$790,139 $796,902
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $33,546 $40,563
Distributions payable to unitholders 12,565 12,475
Derivative contracts (Note 2) 4,475 -
-------------------------------------------------------------------------
50,586 53,038
Bank debt (Note 3) 229,633 220,785
Derivative contracts (Note 2) 58 -
Unit-based incentive compensation (Note 4) 927 1,005
Asset retirement obligations (Note 5) 64,569 65,574
-------------------------------------------------------------------------
345,773 340,402
Unitholders' equity (Note 6)
Unitholders' capital 831,543 824,986
Deficit (389,382) (368,486)
Accumulated other comprehensive income 2,205 -
-------------------------------------------------------------------------
Deficit and accumulated other comprehensive
income (387,177) (368,486)
-------------------------------------------------------------------------
Unitholders' equity 444,366 456,500
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and unitholders' equity $790,139 $796,902
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Units outstanding (000s) 78,534 77,971
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND DEFICIT
(thousands of dollars, except per unit amounts) (unaudited)
------------------------
Three Three
months months
ended ended
March 31, March 31,
2007 2006
------------------------
Revenue
Oil, natural gas and liquids sales $94,436 $103,553
Crown royalties (15,029) (18,164)
Freehold and other royalties (5,531) (5,892)
-------------------------------------------------------------------------
73,876 79,497
Gain (loss) on derivative contracts (Note 2):
Realized gain 2,274 246
Unrealized loss (7,750) -
Reclassification from other comprehensive income 1,379 -
-------------------------------------------------------------------------
(4,097) 246
Royalty and other income 1,452 1,529
-------------------------------------------------------------------------
71,231 81,272
-------------------------------------------------------------------------
Expenses
Operating 14,126 14,237
Transportation costs 597 668
General and administrative 3,915 2,464
Unit-based incentive compensation (Note 4) (24) 1,838
Management fees - 750
Interest on bank debt 2,859 2,370
Depletion, depreciation and amortization 34,428 32,905
Accretion on asset retirement obligations 1,297 1,239
-------------------------------------------------------------------------
57,198 56,471
-------------------------------------------------------------------------
Income before taxes 14,033 24,801
-------------------------------------------------------------------------
Income and capital taxes (provision) (24) (138)
Future income tax recovery (provision) 2,701 (53)
-------------------------------------------------------------------------
Total income and capital taxes 2,677 (191)
-------------------------------------------------------------------------
Net Income 16,710 24,610
Other comprehensive income:
Reclassification to net income, net of tax
of $412 (Note 2) (967) -
-------------------------------------------------------------------------
Comprehensive Income 15,743 24,610
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of period (368,486) (259,095)
Net Income 16,710 24,610
Distributions declared (37,606) (42,597)
-------------------------------------------------------------------------
Deficit, end of period $(389,382) (277,082)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust unit $0.21 $0.33
-------------------------------------------------------------------------
Weighted average units outstanding (000s) 78,258 74,544
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
------------------------
Three Three
months months
ended ended
March 31, March 31,
2007 2006
------------------------
Operating Activities
Net income $16,710 $24,610
Items not involving cash:
Depletion, depreciation and amortization 34,428 32,905
Accretion on asset retirement obligations 1,297 1,239
Unrealized loss on derivative contracts 7,750 -
Reclassification from other comprehensive income (1,379) -
Future income tax provision (recovery) (2,701) 53
Abandonment and environmental expenditures (1,871) (1,143)
Decrease (increase) in non-cash working capital (1,268) 11,134
-------------------------------------------------------------------------
52,966 68,798
-------------------------------------------------------------------------
Financing Activities
Distributions to unitholders (37,516) (42,372)
Issue of Trust units, net of issue costs 6,557 20,807
Increase (decrease) in bank debt 8,848 (22,426)
Decrease (increase) in non-cash working capital 915 (318)
-------------------------------------------------------------------------
(21,196) (44,309)
-------------------------------------------------------------------------
Investing Activities
Additions to property, plant and equipment (27,083) (20,012)
Proceeds from dispositions 25 122
Reclamation reserve - (96)
Decrease in non-cash working capital (5,884) (4,919)
-------------------------------------------------------------------------
(32,942) (24,905)
-------------------------------------------------------------------------
Decrease in cash (1,172) (416)
Cash and cash equivalents, beginning of period 6,295 1,124
-------------------------------------------------------------------------
Cash and cash equivalents, end of period 5,123 $708
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure of cash flow information:
Cash paid during the period for:
Interest 2,831 $2,333
Taxes 24 $138
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Three months ended March 31, 2007
(Tabular amounts in thousands of dollars, except per unit amounts)
(unaudited)
1. SUMMARY OF ACCOUNTING POLICIES
Management prepared the interim consolidated financial statements of
NAL Oil & Gas Trust ("NAL" or the "Trust") in accordance with
accounting principles generally accepted in Canada and following the
same accounting policies and methods of computation as the
consolidated financial statements for the fiscal year ended
December 31, 2006, except for the implementation of new standards
addressing financial instruments, hedging and comprehensive income as
described below. The following disclosure is incremental to the
disclosure included within the annual financial statements. Please
read the interim consolidated financial statements in conjunction
with the consolidated financial statements and notes thereto in NAL's
annual report for the year ended December 31, 2006.
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 four
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. 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 revenues,
expenses, gains and losses not included in net income. Section 3251
provides guidance on the presentation and disclosure of the
components of equity, including accumulated other comprehensive
income.
These standards have been applied on a prospective basis, in
accordance with the relevant transitional provisions.
The Trust has entered into certain derivative contracts in order to
reduce its exposure to market risks from fluctuations in commodity
prices. In accordance with Section 3855, all derivative instruments
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 not designated its derivative contracts as effective
accounting hedges under Section 3865, even though the Trust considers
all commodity contracts to be effective economic hedges. Therefore,
changes in the fair value of the derivative instruments are
recognized in net income for the period.
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 allow 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 will be reclassified to net income over
the remaining term of the derivatives.
Accordingly, on January 1, 2007, the fair value of the derivatives of
$4.5 million was recorded as an asset on the balance sheet with a
corresponding increase in accumulated other comprehensive income
("AOCI").
The fair value of these derivative instruments is based on an
approximation of the amounts that would be received or paid to settle
these instruments at the end of the period, with reference to forward
prices and market valuations provided by third party sources.
In accordance with Section 3855 bank debt is presented net of
deferred interest payments, with interest recognized in net income on
an effective interest basis. Previously, interest was recognized on a
straightline basis with the deferred amount included in accounts
receivable. There was no impact at January 1, 2007 resulting from
this change.
2. DERIVATIVE CONTRACTS AND RISK MANAGEMENT
Commodity Price Risk Management
NAL employs risk management practices to assist in managing cash
flows and support capital programs and distributions. NAL's
management is authorized to hedge up to 50% of its annual net
production. NAL's risk management programs tend to be scaled-in over
time using a combination of swaps and collars.
As at March 31, 2007, the Trust had entered into the following
derivatives to protect its 2007 cash flow from the volatility of oil
and natural gas commodity prices.
For 2007, NAL has the following WTI oil contracts in place:
---------------------------------------------------------------------
Total Bought Sold
Volume Volume Put Call Swap
---------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
COLLARS
April-June 2-way 300 27,300 70.00 85.85 -
April-June 2-way 300 27,300 72.00 88.10 -
April-Dec 2-way 500 137,500 62.00 68.25 -
April-Dec 2-way 200 55,000 64.00 71.00 -
July-Dec 2-way 300 55,200 62.00 69.75 -
July-Dec 2-way 200 36,800 63.00 68.50 -
July-Dec 2-way 200 36,800 62.50 69.50 -
July-Dec 2-way 200 36,800 64.00 70.45 -
July-Dec 2-way 100 18,400 66.00 72.25 -
---------------------------------------------------------------------
Weighted Average Collars 431,100 63.86 71.65 -
---------------------------------------------------------------------
---------------------------------------------------------------------
SWAPS
July-Dec Swap 100 18,400 - - 69.10
April-Dec Swap 500 137,500 - - 65.05
April-Dec Swap 500 137,500 - - 72.33
July-Dec Swap 300 55,200 - - 61.07
July-Dec Swap(*) 100 18,400 - - 69.00
---------------------------------------------------------------------
Weighted Average Swaps 367,000 - - 67.58
---------------------------------------------------------------------
---------------------------------------------------------------------
For 2007, NAL has the following AECO natural gas contracts in place:
---------------------------------------------------------------------
Total Bought Sold
Volume Volume Put Call Swap
---------------------------------------------------------------------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
COLLARS
April-Dec 2-way 3,000 825,000 6.00 8.10 -
April-Dec 2-way 1,000 275,000 6.50 8.85 -
April-Dec 2-way 2,000 550,000 7.00 8.70 -
April-Dec 2-way 1,000 275,000 6.75 8.60 -
April-Dec 2-way 1,000 275,000 7.00 8.70 -
April-Dec 2-way 1,000 275,000 7.25 8.51 -
---------------------------------------------------------------------
Weighted Average Collars 2,475,000 6.61 8.48 -
---------------------------------------------------------------------
---------------------------------------------------------------------
SWAPS
April-Dec Swap 3,000 825,000 - - 6.77
April-Dec Swap 1,000 275,000 - - 7.90
April-Dec Swap 1,500 412,500 - - 7.20
April-Dec Swap 1,500 412,500 - - 7.43
---------------------------------------------------------------------
Weighted Average Swaps 1,925,000 - - 7.16
---------------------------------------------------------------------
---------------------------------------------------------------------
NAL currently has the following WTI oil contracts in place for fiscal
2008:
---------------------------------------------------------------------
Total Bought Sold
Volume Volume Put Call Swap
---------------------------------------------------------------------
Term Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
COLLARS
January-June 2-way 200 36,200 64.00 72.26 -
January-March 2-way(*) 100 9,100 66.00 71.90 -
---------------------------------------------------------------------
Weighted Average Collars 45,300 64.40 72.19 -
---------------------------------------------------------------------
---------------------------------------------------------------------
SWAPS
January-March Swap(*) 100 9,100 - - 69.35
---------------------------------------------------------------------
---------------------------------------------------------------------
NAL currently has the following AECO natural gas contracts in place
for fiscal 2008:
---------------------------------------------------------------------
Total Bought Sold
Volume Volume Put Call Swap
---------------------------------------------------------------------
Term Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
COLLARS
January-March 2-way 2,000 182,000 8.40 10.25 -
January-March 2-way(*) 1,000 91,000 8.40 10.15 -
January-March 2-way(*) 1,000 91,000 8.40 10.40 -
---------------------------------------------------------------------
Weighted Average Collars 364,000 8.40 10.26 -
---------------------------------------------------------------------
---------------------------------------------------------------------
SWAPS
January-March Swap 1,000 91,000 - - 8.90
January-March Swap 1,500 136,500 - - 7.20
January-March Swap(*) 1,000 91,000 - - 9.13
---------------------------------------------------------------------
Weighted Average Swaps 318,500 - - 8.24
---------------------------------------------------------------------
---------------------------------------------------------------------
(*)Entered into subsequent to quarter-end.
Fair Values
The carrying value 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 equivalents bear interest at a
floating market rate and, accordingly, the fair market value
approximates the carrying value.
Derivative contracts are recorded at fair value on the balance sheet
as current assets or current liabilities based on their fair values
on a contract by contract basis.
---------------------------------------------------------------------
Three months ended
March 31
2007 2006
---------------------------------------------------------------------
Current gain on the fair value of derivative
contracts $1,304 -
Current loss on the fair value of derivative
contracts (4,475) -
Non-current loss on fair value of derivative
contracts (58) -
---------------------------------------------------------------------
Unrealized loss on fair value of derivative
contracts ($3,229) $-
---------------------------------------------------------------------
---------------------------------------------------------------------
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
will be transferred to net income over the term of the respective
contracts. During the first quarter of 2007, $1.4 million has been
reclassified to net income and is included in the gain (loss) on
derivative contracts.
As at March 31, 2007 the total fair value of derivative contracts was
a loss of $3.2 million. The change in the fair value for the quarter
of $7.7 million has been recognized as a loss in the income
statement.
The following table reconciles the movement in the fair value of the
Trust's derivative contracts:
---------------------------------------------------------------------
Gain (loss) Three months ended
March 31
2007 2006
---------------------------------------------------------------------
Fair value, beginning of period - -
Fair value on transition to new accounting
standards (Note 1) $4,521 -
Fair value, end of period (3,229) -
---------------------------------------------------------------------
Change in fair value of contracts in the period (7,750) -
Realized gain in the period 2,274 246
Reclassification from other comprehensive income 1,379 -
---------------------------------------------------------------------
Gain (loss) on derivative contracts $(4,097) $246
---------------------------------------------------------------------
---------------------------------------------------------------------
3. BANK DEBT
The Trust, through its subsidiary NAL Ventures Trust, maintains a
$300 million fully secured, extendible, revolving term credit
facility with a syndicate of Canadian chartered banks. This facility
consists of a $290 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 present and after acquired properties and assets of
the Trust and its subsidiary and affiliated entities. The facility
was renewed in April 2007 and was increased from $300 million to
$325 million. The facility will revolve until April 30, 2008 and is
extendible at that time 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 in May 2010.
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. based 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.
On March 31, 2007 the effective interest rate on amounts outstanding
under the credit facility was 5.26 percent.
4. UNIT-BASED INCENTIVE COMPENSATION
The Trust recorded a compensation recovery of $0.2 million in the
first quarter of 2007 of which $24,000 was recorded to income and
$139,000 a reduction to capital ($2.5 million expensed and
$1.7 million capitalized for full year 2006) for the estimated cost
of the plan. The compensation expense was based on the March 31, 2007
unit price of $11.75 ($12.95 in 2006), accrued distributions,
performance factors, and the number of units vesting on maturity.
The following table reconciles the change in total accrued unit-based
incentive compensation relating to the plan:
---------------------------------------------------------------------
Three months
ended Year ended
March 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $4,153 $-
Increase (decrease) in liability (163) 4,153
Cash payout, relating to units vested
November 30, 2006 (2,184) -
---------------------------------------------------------------------
Balance, end of period $1,806 $4,153
---------------------------------------------------------------------
---------------------------------------------------------------------
Current portion of liability 879 3,148
---------------------------------------------------------------------
Long-term liability 927 1,005
---------------------------------------------------------------------
---------------------------------------------------------------------
5. 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 $64.6 million
as at March 31, 2007 based on a total undiscounted amount of cash
flows required to settle its asset retirement obligations of
$162.3 million (December 31, 2006 - $165.2 million). These costs are
expected to be incurred over the next 46 years with the majority of
the costs incurred between 2007 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.
---------------------------------------------------------------------
Three months
ended Year ended
March 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $65,574 $61,908
Accretion expense 1,297 4,984
Liabilities incurred (431) 3,117
Liabilities settled (1,871) (4,435)
---------------------------------------------------------------------
Balance, end of period $64,569 $65,574
---------------------------------------------------------------------
---------------------------------------------------------------------
6. UNITHOLDERS' EQUITY
Units Issued:
---------------------------------------------------------------------
Three months ended Year ended
March 31, 2007 December 31, 2006
---------------------------------------------------------------------
Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning
of period 77,971 $824,986 73,977 $753,585
Issued under management
agreement restructuring - - 1,592 30,000
Less: Issue expenses - - - (29)
Issued from Distribution
Reinvestment Plan 563 6,557 2,402 41,430
---------------------------------------------------------------------
Balance, end of period 78,534 $831,543 77,971 $824,986
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated Other Comprehensive Income:
---------------------------------------------------------------------
Three months
ended Year ended
March 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $- -
Fair value of derivative instruments on
transition to new accounting standards,
net of tax of $1,349 (Note 2) 3,172 -
Reclassification to net income in period,
net of tax of $412 (Note 2) (967) -
---------------------------------------------------------------------
Balance, end of period $2,205 -
---------------------------------------------------------------------
---------------------------------------------------------------------
Cash Distributions
The Trust is required to make a distribution of distributable cash
flow each calendar month, pursuant to the Trust Indenture. The
distributable cash flow is defined as cash flow of the Trust less a
discretionary amount, which the Trustee, upon recommendations of the
Manager, considers it necessary to retain.
7. COMPARATIVE NUMBERS
Certain comparative numbers have been reclassified to conform with
current period presentation.
TRADING PERFORMANCE
---------------------------------------------------------------------
For the Quarter Ended
------------------------------------------------
Price 31-Mar-07 31-Dec-06 31-Mar-06 31-Dec-05
---------------------------------------------------------------------
High 13.00 18.74 $20.25 $19.15
Low 10.86 11.80 $16.92 $13.39
Close 11.75 12.31 $19.58 $18.08
Volume 16,390,680 27,691,472 13,614,737 16,922,700
---------------------------------------------------------------------
---------------------------------------------------------------------
NAL Oil & Gas Trust is an open-end 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 Stock Exchange under the symbol "NAE.UN".
Contact Information:
Gordon Currie
Manager, Investor Relations
Telephone: (403) 294-3620 or Toll Free: (888) 223-8792
Fax: (403) 515-3407
Email: investor.relations@nal.ca
Website: www.nal.ca