CALGARY--(CCNMatthews - Aug. 9) - NAL Oil & Gas Trust (TSX:NAE.UN) (the "Trust") today announced its financial and operational results for the second quarter ended June 30, 2006. All amounts are in Canadian dollars unless otherwise stated.
SECOND QUARTER HIGHLIGHTS
- NAL continued to deliver volume performance in the second quarter of
2006 with daily production averaging 19,012 boe/d, an increase of
four percent over the 18,349 boe/d in the same period of 2005. The
production mix remained relatively balanced at 57 percent crude oil
and natural gas liquids, and 43 percent natural gas. As budgeted,
production declined in the second quarter due to scheduled plant
turnarounds and a lower level of drilling activity during spring
breakup, but is expected to recover in the third and fourth quarters
with the completion of turnarounds and higher capital spending.
Production in the first half of 2006 averaged 19,593 boe/d, which was
consistent with the guidance range provided for full year 2006.
- The Trust's oil equivalent pricing increased to $55.20 per boe in the
second quarter of 2006 from $52.67 per boe a year earlier. Higher
West Texas Intermediate crude oil prices were partially offset by an
increase in the value of the Canadian dollar, and natural gas prices
were significantly lower year-over-year. As expected, operating costs
rose from $7.84 per boe in the first quarter of 2006 to $9.63 per boe
in the second quarter, as a result of scheduled plant turnarounds and
correspondingly lower production volumes during the period. For the
full year, operating costs are still expected to be within the
guidance range of $8.30-$8.70 per boe. Taking into account a minor
hedging gain in the second quarter of 2006 versus a small hedging
loss in the second quarter of 2005, NAL's operating netback was
essentially unchanged at $34.51 per boe versus $34.45 per boe a year
earlier.
- Funds from operations increased to $52.8 million in the second
quarter of 2006 compared to $50.3 million a year earlier, driven
largely by higher production volumes and commodity prices. Funds from
operations per unit were essentially unchanged at $0.70 versus $0.71
in the second quarter of 2005 as a result of issuing additional units
to fund capital expenditures through a successful distribution
reinvestment program and to fund a one-time payment to restructure
NAL's management contract. Distributions increased to $43.3 million
or $0.57 per unit during the second quarter of 2006, from
$34.3 million or $0.48 per unit during the second quarter of 2005,
for a payout ratio of 82 percent versus 68 percent. The payout ratio
for the first half of 2006 was 76 percent. Distributions are
currently $0.19 per month and August will represent the eleventh
consecutive month at that level.
- Capital expenditures of $25.7 million in the second quarter of 2006
were in line with the budget as NAL accessed the equipment and
services required to execute its exploitation and development program
as planned. The Trust drilled 40 gross wells (16.5 net) during the
second quarter for a total of 65 gross wells (23.5 net) during the
first six months of the year. Capital expenditures for the first half
of 2006 totaled $47.5 million, which was significantly higher than
the $18.1 million spent in the comparable period last year. NAL is
forecasting an increase in its 2006 capital budget from $95 million
to $103 to $108 million, driven primarily by $3 to $4 million in
incremental spending on land for future opportunities in its core
areas, an additional $2.8 million in capital assets acquired as part
of management contract restructuring and capitalized expense
associated with its new unit-based long-term incentive plan.
Additional spending on land will not contribute to reserves and
production in 2006 but will assist in positioning the Trust to
sustain production in 2007 and beyond.
- Net debt continued to decline to $186.3 million at the end of the
second quarter of 2006 compared to $229.0 million at the end of the
second quarter of 2005 and $198.4 million at year-end 2005. The
Trust's net debt to cash flow ratio continued to trend lower at
0.78 times trailing twelve months' funds from operations. During the
first half of 2006 the distribution reinvestment ("DRIP") and premium
distribution ("Premium DRIP") programs resulted in 1.5 million
additional trust units being issued at successively higher prices,
raising a total of $26.9 million in new equity. Lower debt levels
allowed the Trust to suspend its Premium DRIP program effective with
the April 2006 distribution. The regular DRIP remains in place and
the participation rate averaged 14 percent in the second quarter of
2006.
- During the second quarter, the Trust obtained unitholder approval for
the restructuring of its management contract with NAL Resources
Management Limited. Subsequent to completion of the restructuring,
base and performance fees have been eliminated, governance has been
enhanced and the Trust now has the flexibility to terminate the
agreement on 90 days' notice in order to facilitate future
transactions. In exchange for these benefits, the Trust paid a tax
deductible restructuring fee of $30 million funded through the
issuance of 1,592,357 units at $18.84 per unit. Of the restructuring
fee, $27.3 million was recorded as a one-time, non-cash charge to
income during the second quarter, which reduced net income from
$21.9 million to a loss of $5.4 million in the second quarter of
2006.
- With the exception of the increase in capital spending, NAL confirms
that its guidance for the year remains unchanged from the ranges
announced on January 18, 2006.
2006 Guidance Update
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2006 Full Year Six-Month Actual
Guidance As Issued Results Ending
January 18, 2006 June 30, 2006
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Total production (boe/d) 19,200-19,800 19,593
Capital expenditures ($MM) 95 47.5
Operating costs ($/boe) 8.30-8.70 8.71
G&A ($/boe) 1.70-1.85 1.67
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- NAL recently announced the addition of Gordon Lackenbauer of Calgary,
Alberta to the Trust's Board of Directors effective July 1, 2006.
With 36 years of experience in investment banking, most recently with
BMO Nesbitt Burns, Mr. Lackenbauer brings significant financial
expertise to his new position. He replaces Richard Coles of Toronto,
Ontario who stepped down on June 30, 2006 after having served on the
Board for ten years. NAL also wishes to acknowledge the contribution
made by Troy Wagner during his ten years with the Trust. Mr. Wagner
served as Vice President of Operations until his departure at the end
of July to join a start-up exploration company.
FINANCIAL AND OPERATING HIGHLIGHTS
(thousands of dollars, except per unit and boe data)
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Three Three Three Six Six
Months Months Months Months Months
Ended Ended Ended Ended Ended
June 30, March 31, June 30, June 30, June 30,
2006 2006 2005 2006 2005
-------------------------------------------------------------------------
FINANCIAL
Gross revenue, net
of royalties $77,352 $80,604 $70,797 $157,956 $131,414
Net income (loss) (5,358) 24,610 20,804 19,252 36,051
Funds from operations 52,805 59,502 50,279 112,307 94,158
Distributions declared 43,268 42,597 34,262 85,865 65,288
Funds from operations
per unit 0.70 0.80 0.71 1.50 1.41
Distributions declared
per unit 0.57 0.57 0.48 1.14 0.96
Payout ratio 82% 72% 68% 76% 69%
Average number of units
outstanding (000s) 75,869 74,544 71,188 75,210 66,953
Total assets $788,519 $791,327 $820,166 $788,519 $820,166
Bank debt, net of
working capital 186,333 181,443 229,005 186,333 229,005
Unitholders' equity 484,734 497,310 475,198 484,734 475,198
Costs per boe (6:1):
Operating $9.63 $7.84 $7.14 $8.71 $6.91
General and
administrative 2.00 1.36 2.31 1.67 1.92
Management fees 0.35 0.41 1.17 0.38 1.08
OPERATING
Daily production
Oil (bbl) 8,959 9,552 9,197 9,254 9,202
Natural gas (Mcf) 48,861 51,937 43,254 50,390 42,419
Natural gas
liquids (bbl) 1,910 1,973 1,943 1,941 1,635
Oil equivalent
(boe - 6:1) 19,012 20,181 18,349 19,593 17,906
Average pricing, net of
transportation charges
and hedging
Liquids:
WTI (US$/bbl) 70.70 63.48 53.18 67.11 51.89
NAL average oil
(Cdn$/bbl) 71.35 61.00 57.94 65.88 56.77
NAL natural gas
liquids (Cdn$/bbl) 49.86 52.53 45.84 50.76 43.60
Natural gas:
AECO (Cdn$/Mcf) -
daily spot 6.03 7.59 7.32 6.81 7.10
AECO (Cdn$/Mcf) -
monthly 6.28 9.28 6.80 7.77 6.76
NAL natural gas
Western Canada
(Cdn$/Mcf) 6.32 8.59 7.87 7.65 7.33
NAL natural gas
Lake Erie (Cdn$/Mcf) 7.73 9.40 9.14 8.55 8.82
NAL average natural
gas (Cdn$/Mcf) 6.45 8.65 7.99 7.72 7.47
NAL oil equivalent
(Cdn$/boe - 6:1) 55.20 56.26 52.67 56.01 50.87
Average foreign exchange
rate (Cdn$/US$) 1.122 1.155 1.244 1.139 1.235
Operating netback before
hedging gains (losses)
($/boe) 34.14 35.57 34.96 34.87 33.15
Hedging gains (losses)
($/boe) 0.37 0.14 (0.51) 0.25 (0.27)
Operating netback ($/boe) 34.51 35.71 34.45 35.12 32.88
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Second Quarter Drilling Activity
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Crude Oil Natural Gas Service Wells
--------------------------------------------------
Gross Net Gross Net Gross Net
Operated wells 6 2.84 14 10.42 0 0.00
Non-operated
wells 4 0.38 15 2.90 1 0.00
Total wells
drilled 10 3.22 29 13.32 1 0.00
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Year-to-date total
wells drilled 27 9.09 35 14.45 3 0.00
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--------------------------------------------------------
Dry & Abandoned Total
---------------------------------
Gross Net Gross Net
Operated wells 0 0.00 20 13.26
Non-operated
wells 0 0.00 20 3.28
Total wells
drilled 0 0.00 40 16.54
--------------------------------------------------------
Year-to-date total
wells drilled 0 0.00 65 23.54
--------------------------------------------------------
--------------------------------------------------------
Exploitation and Development Expenditures ($000s)
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Drilling, completion and
production equipment 14,503 9,225 29,054 15,349
Plant and facilities 2,446 767 4,090 1,342
Seismic 981 111 1,709 157
Land 4,968 85 5,409 437
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22,898 10,188 40,262 17,285
Office equipment(1) 3,262 - 3,262 -
Capitalized G&A 1,162 495 2,075 822
Capitalized unit-based
incentive compensation 187 - 1,923 -
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Total capital expenditures 27,509 10,683 47,522 18,107
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(1) Includes $2.8 million in assets acquired as part of the management
agreement restructuring.
Average Daily Production Volumes
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Oil (bbl/d) 8,959 9,197 9,254 9,202
Natural gas (Mcf/d) 48,861 43,254 50,390 42,419
NGL's (bbl/d) 1,910 1,943 1,941 1,635
Oil equivalent (boe/d) 19,012 18,349 19,593 17,906
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For the three and six months ended June 30, 2006, production weighting was
relatively unchanged with oil and natural gas liquids production representing
57 percent and natural gas, 43 percent.
Production Weighting
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Oil 47% 50% 47% 51%
Natural gas 43% 39% 43% 40%
NGLs 10% 11% 10% 9%
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-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Revenue(1) ($000s) 95,508 88,090 198,639 164,858
$/boe 55.20 52.76 56.01 50.87
Funds from operations(2)
($000s) 52,805 50,279 112,307 94,158
$/boe 30.52 30.11 31.67 29.05
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-------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales less transportation and after
hedging.
(2) Represents cash flow from operating activities prior to the change in
non-cash working capital items, excluding unpaid unit-based incentive
compensation charges.
Average Pricing
(net of transportation charges and after hedging)
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Liquids:
WTI (US$/bbl) 70.70 53.18 67.11 51.89
NAL average oil (Cdn$/bbl) 71.35 57.94 65.88 56.77
NAL natural gas liquids
(Cdn$/bbl) 49.86 45.84 50.76 43.60
Natural Gas: (Cdn$/Mcf)
AECO 6.03 7.32 6.81 7.10
NAL Western Canada natural
gas 6.32 7.87 7.65 7.33
NAL Lake Erie natural gas 7.73 9.14 8.55 8.82
NAL average natural gas 6.45 7.99 7.72 7.47
NAL Oil Equivalent
(Cdn$/boe - 6:1) 55.20 52.67 56.01 50.87
Average Foreign Exchange
Rate 1.122 1.244 1.139 1.235
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Financial WTI Oil Contracts in Place as at June 30, 2006
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Bought Sold
Contract Volume Sold Put Put Call
-------- ------ -------- --- ----
Term Bbls/d US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
Jan. 1 to Dec. 31, 2006 3-way 300 52.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 58.50 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.50 74.00
Jan. 1 to Dec. 31, 2006 3-way 600 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 74.00
-------------------------------------------------------------------------
2,700 48.44 58.22 72.83
July 1 to Dec. 31, 2006 Collar 300 - 68.00 80.90
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2006 weighted average 3,000 48.44 59.20 73.64
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Financial AECO Natural Gas Contracts in Place as at June 30, 2006
-------------------------------------------------------------------------
Contract Volume Bought Put Sold Call
-------- ------ ---------- ---------
Term GJ's/day Cdn$/GJ Cdn$/GJ
-------------------------------------------------------------------------
Jan. 1 to Dec. 31, 2006 Collar 2,000 9.50 14.40
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-------------------------------------------------------------------------
NAL has designated these derivatives as accounting hedges under the
Canadian Institute of Chartered Accountants (the "CICA") accounting guideline
AcG13 and, accordingly, has not recorded the fair value of these instruments
in the consolidated financial statements as at June 30, 2006. As at June 30,
2006 the unrealized fair value of these hedges was a loss of $1,540,345.
Subsequent to quarter end, the Trust has entered into further crude oil
contracts as follows:
-------------------------------------------------------------------------
Contract Volume Bought Put Sold Call
-------- ------ ---------- ---------
Term Bbls/day US$/bbl US$/bbl
-------------------------------------------------------------------------
July 1 to Dec. 31, 2006 Collar 300 70.00 84.85
Aug. 1 to Dec. 31, 2006 Collar 300 72.00 87.35
Jan. 1 to June 30, 2007 Collar 300 70.00 85.85
Jan. 1 to June 30, 2007 Collar 300 72.00 88.10
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-------------------------------------------------------------------------
Royalty Expenses
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Net royalties ($000s) 19,135 18,651 43,191 35,878
As % of revenue(1) 20.0 20.8 21.7 21.5
$/boe 11.06 11.17 12.18 11.07
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-------------------------------------------------------------------------
(1) Oil, natural gas and liquids sales before transportation and
hedging.
Operating Costs
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating costs ($000s) 16,666 11,917 30,903 22,404
As % of revenue 17.4 13.5 15.6 13.6
$/boe 9.63 7.14 8.71 6.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Netback ($/boe)
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Production Revenue, net of
transportation costs 54.83 53.27 55.76 51.13
Royalties, net (11.06) (11.17) (12.18) (11.07)
Operating expenses (9.63) (7.14) (8.71) (6.91)
Operating netback, before
hedging 34.14 34.96 34.87 33.15
Hedging gains (losses) 0.37 (0.51) 0.25 (0.27)
Operating netback, after
hedging 34.51 34.45 35.12 32.88
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-------------------------------------------------------------------------
General and Administrative Expenses
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
G&A expenses 3,464 3,452 5,928 5,428
Capitalized G&A 1,162 495 2,075 822
------------------------------------------
Total G&A 4,626 3,947 8,003 6,250
Expensed G&A costs:
As % of revenue 3.6 3.9 3.0 3.3
$/boe 2.00 2.07 1.67 1.67
Per Trust unit ($) 0.05 0.05 0.08 0.08
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-------------------------------------------------------------------------
Unit-Based Compensation
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Unit-based compensation:
Expensed ($000s) 595 398 2,433 788
Capitalized ($000s) 187 - 1,923 -
-----------------------------------------
Total unit-based
compensation ($000s) 782 398 4,356(1) 788
Expensed unit-based compensation:
As % of revenue 0.6 0.5 1.2 0.5
$/boe 0.34 0.24 0.69 0.24
Per trust unit ($) 0.01 0.01 0.03 0.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes $2.1 million relating to vesting periods prior to 2006.
Management Fees
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Base management fees ($000s) 600 1,958 1,350 3,512
As % of revenue 0.6 2.2 0.7 2.1
$/boe 0.35 1.17 0.38 1.08
Per trust unit ($) 0.01 0.03 0.02 0.05
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-------------------------------------------------------------------------
Interest and Bank Debt ($000s)
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Interest on bank debt 2,338 2,790 4,708 4,898
Bank debt outstanding at
period end 191,325 250,100 191,325 250,100
Net bank debt outstanding
at period end(1) 186,333 229,005 186,333 229,005
Net bank debt-to-cash
flow ratio 0.78 1.20 0.78 1.20
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-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
Cash Flow Netback ($/boe)
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Operating netback, after hedging 34.51 34.45 35.12 32.88
Management fees (0.35) (1.17) (0.38) (1.08)
G&A expenses (2.00) (2.07) (1.67) (1.67)
Interest (1.35) (1.67) (1.33) (1.51)
-----------------------------------------
Cash flow netback 30.81 29.54 31.74 28.62
-------------------------------------------------------------------------
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Depletion, Depreciation and Accretion Expenses
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Depletion and depreciation
($000s) 31,236 28,267 64,141 54,690
Accretion of asset retirement
obligation ($000s) 1,240 1,178 2,479 2,201
-------------------------------------------------------------------------
Total DDA ($000s) 32,476 29,445 66,620 56,891
DDA rate per boe ($) 18.77 17.63 18.79 17.55
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-------------------------------------------------------------------------
Capitalization
-------------------------------------------------------------------------
June 30, December 31, June 30,
2006 2005 2005
-------------------------------------------------------------------------
Trust unit equity ($000s) 484,734 494,490 475,198
Bank debt ($000s) 191,325 220,519 250,100
Net bank debt(1) ($000s) 186,333 198,351 229,005
Net bank debt to equity 0.38 0.40 0.48
Net bank debt to trailing
12-month cash flow 0.78 0.89 1.20
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-------------------------------------------------------------------------
(1) Net bank debt is bank debt net of working capital.
Distributions
-------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------------------------------------
Funds from operations ($000s) 52,805 50,279 112,307 94,158
Distributions declared ($000s) 43,268 34,262 85,865 65,288
Funds from operations
per unit(1) 0.70 0.71 1.50 1.41
Distributions declared per unit 0.57 0.48 1.14 0.96
Weighted average units
outstanding (000s) 75,869 71,188 75,210 66,953
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-------------------------------------------------------------------------
(1) Based on weighted average units outstanding.
OFF-BALANCE SHEET ARRANGEMENTS/VARIABLE INTEREST ENTITIES
NAL has no off-balance sheet arrangements or 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) 2006 2007 2008 2009 2010
-------------------------------------------------------------------------
Office lease(1) 1,448 2,734 2,580 2,580 2,365
Transportation agreement 1,342 659 659 89 -
Processing agreement(2) 260 491 469 446 428
Drilling rigs(3) 988 1,975 494 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 54 percent) of
the expense on a monthly basis. Included in office lease is a
$0.6 million commitment related to the Addison acquisition. The
commitment started in February 2005 and extends 30 months. NAL has
subsequently sublet the premises.
(2) Represents a gas processing agreement with a take or pay arrangement
associated with the Addison acquisition.
(3) Represents the Trust's share of the minimum payments required under
drilling rig contracts held by NAL Resources.
QUARTERLY INFORMATION
-------------------------------------------------------------------------
2006 2005
-------------------------------------------------------------------------
($000s, except per
unit and production
amounts) Q2 Q1 Q4 Q3 Q2 Q1
-------------------------------------------------------------------------
Revenue, net of
royalties and
transportation
costs 77,352 80,604 94,856 84,833 70,797 60,617
Per unit 1.02 1.08 1.29 1.17 0.99 0.97
Funds from
operations 52,805 59,502 65,050 62,442 50,279 43,879
Per unit 0.70 0.80 0.89 0.86 0.71 0.70
Net income (loss) (5,357) 24,610 30,777 31,710 20,804 15,247
Per unit (0.07) 0.33 0.42 0.44 0.29 0.24
Average oil
equivalent
production
(boe/d - 6:1) 19,012 20,181 20,514 19,710 18,349 17,457
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------
2004
-------------------------------------
($000s, except per
unit and production
amounts) Q4 Q3
-------------------------------------
Revenue, net of
royalties and
transportation
costs 43,110 43,989
Per unit 0.81 0.84
Funds from
operations 28,846 30,446
Per unit 0.54 0.58
Net income (loss) 11,754 13,279
Per unit 0.22 0.25
Average oil
equivalent
production
(boe/d - 6:1) 12,958 12,807
-------------------------------------
-------------------------------------
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
As at As at
June 30, December 31,
2006 2005
(unaudited) (audited)
----------------------------
Assets
Current assets
Cash and cash equivalents $10,650 $1,124
Accounts receivable and other 37,996 64,830
Reclamation reserve (Note 3) 4,193 -
-------------------------------------------------------------------------
52,839 65,954
Reclamation reserve (Note 3) - 3,898
Future income tax asset 3,289 2,136
Property, plant and equipment, net (Note 4) 732,391 748,715
-------------------------------------------------------------------------
$788,519 $820,703
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $33,203 $29,730
Distributions payable to unitholders 14,644 14,056
-------------------------------------------------------------------------
47,847 43,786
Bank debt (Note 5) 191,325 220,519
Unit-based incentive compensation (Note 6) 1,813 -
Asset retirement obligations (Note 7) 62,800 61,908
-------------------------------------------------------------------------
303,785 326,213
Unitholders' equity
Unitholders' capital (Note 8) 810,441 753,585
Accumulated income 293,049 273,796
Accumulated distributions (618,756) (532,891)
-------------------------------------------------------------------------
484,734 494,490
-------------------------------------------------------------------------
$788,519 $820,703
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments (Note 10)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Units outstanding (000s) 77,076 73,977
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes
CONSOLIDATED STATEMENTS OF INCOME AND ACCUMULATED INCOME
(thousands of dollars, except per unit amounts) (unaudited)
-------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------
Revenue
Oil, natural gas and
liquids sales(1) $96,144 $88,775 $199,943 $166,194
Transportation costs (636) (685) (1,304) (1,336)
Royalty and other income 979 1,358 2,508 2,434
Crown royalties, net of ARTC (13,908) (13,842) (32,072) (26,572)
Freehold and other royalties (5,227) (4,809) (11,119) (9,306)
-------------------------------------------------------------------------
77,352 70,797 157,956 131,414
-------------------------------------------------------------------------
Expenses
Operating 16,666 11,917 30,903 22,404
General and administrative 3,464 3,452 5,928 5,428
Unit-based incentive
compensation (Note 6) 595 398 2,433 788
Management fees (Note 2) 600 1,958 1,350 3,512
Restructuring fee (Note 2) 27,299 - 27,299 -
Interest on bank debt 2,338 2,790 4,708 4,898
Depletion, depreciation
and amortization 31,236 28,267 64,141 54,690
Accretion on asset
retirement obligations 1,240 1,178 2,479 2,201
-------------------------------------------------------------------------
83,438 49,960 139,241 93,921
-------------------------------------------------------------------------
Income (loss) before taxes (6,086) 20,837 18,715 37,493
-------------------------------------------------------------------------
Income and capital taxes (478) (45) (616) (126)
Future income tax recovery
(provision) 1,207 12 1,154 (1,316)
-------------------------------------------------------------------------
Total income and capital taxes 729 (33) 538 (1,442)
-------------------------------------------------------------------------
Net Income (loss) (5,357) 20,804 19,253 36,051
Accumulated income, beginning
of period 298,406 190,505 273,796 175,258
-------------------------------------------------------------------------
Accumulated income,
end of period $293,049 $211,309 $293,049 $211,309
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income (loss) per
Trust unit $(0.07) $0.29 $0.26 $0.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average units
outstanding (000s) 75,869 71,188 75,210 66,953
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) After hedging.
See accompanying notes
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars) (unaudited)
-------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2006 2005 2006 2005
-------------------------------------------
Operating Activities
Net income (loss) $(5,357) $20,804 $19,253 $36,051
Items not involving cash:
Depletion, depreciation
and amortization 31,236 28,267 64,141 54,690
Accretion on asset
retirement obligations 1,240 1,178 2,479 2,201
Future income tax provision (1,207) (12) (1,154) 1,316
Restructuring fee 27,159 - 27,159 -
Abandonment and environmental
expenditures (861) (356) (2,004) (888)
Decrease (increase) in
non-cash working capital 8,011 (8,609) 19,144 (15,871)
-------------------------------------------------------------------------
60,221 41,272 129,018 77,499
-------------------------------------------------------------------------
Financing Activities
Distributions to unitholders (42,904) (34,068) (85,276) (62,292)
Issue of Trust units, net
of issue costs 6,049 15,897 26,856 243,398
Increase (decrease) in
bank debt (6,768) (9,500) (29,194) 156,400
Decrease (increase) in
non-cash working capital 1,062 (160) 744 -
-------------------------------------------------------------------------
(42,561) (27,831) (86,870) 337,506
-------------------------------------------------------------------------
Investing Activities
Acquisition of Addison
Energy Inc. - (1,837) - (384,994)
Additions to property,
plant and equipment (24,669) (10,624) (44,681) (18,116)
Proceeds from dispositions - - 123 -
Reclamation reserve (198) (157) (294) (254)
Decrease (increase) in
non-cash working capital 17,149 4,061 12,230 (5,610)
-------------------------------------------------------------------------
(7,718) (8,557) (32,622) (408,974)
-------------------------------------------------------------------------
Increase in cash 9,942 4,884 9,526 6,031
Cash, beginning of period 708 2,258 1,124 1,111
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $10,650 $7,142 $10,650 $7,142
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid during the
period for:
Interest $2,299 $2,771 $4,632 $4,867
Taxes $478 $45 $616 $126
-------------------------------------------------------------------------
See accompanying notes
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Six months ended June 30, 2006
(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, 2005, except for implementation of unit-based incentive
compensation. 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, 2005.
Unit-Based Incentive Compensation
The Manager has established a unit-based incentive compensation plan
for employees, for which grants are in the form of Restricted Trust
Units ("RTU's") and Performance Trust Units ("PTU's"). As
participants in the plan receive a cash payment on a fixed vesting
date, compensation expense is determined based on the intrinsic value
of the units at each period end. The valuation incorporates the
period end trust unit price, number of RTU's and PTU's outstanding at
each period end, and certain management assumptions. RTU's vest
one-third on November 30 in each of three years after grant date.
PTU's vest at the end of three years. Compensation expense is
recognized over the vesting period with a corresponding increase or
decrease in liabilities. Classification between accrued liabilities
and other long-term liabilities is dependent on the expected payout
date.
The Trust charges amounts relating to head office employees to
general and administrative expenses, amounts relating to field staff
to operating costs, and 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, rather, the Trust accounts for
actual forfeitures as they occur.
2. 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 venture operator. As a result, a significant
portion of the net operating revenues and capital expenditures during
the year is based on joint venture amounts from NAL Resources. These
transactions are in the normal course of joint venture operations and
are measured using the fair value established through the original
transactions with third parties.
The Manager provides certain services pursuant to the Management
Contract for which, 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. Such fees amounted to $1,958,000 for the quarter ended
June 30, 2005 and $3,512,000 for the six months ended June 30, 2005.
In addition, the Trust paid $1.9 million (2005 - $2.9 million) for
the reimbursement of G&A expenses incurred by the Manager on behalf
of the Trust pursuant to the Management Contract for the second
quarter of 2006, and $3.6 million (2005 - $4.5 million) year to date.
The Trust also pays the Manager its share of unit-based incentive
compensation expense when cash compensation is paid to employees
under the terms of the Plan.
On May 31, 2006 the Trust's unitholders approved the restructuring of
the Management Contract with the Manager. Under the restructuring,
the Trust paid 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. Immediately following the payment of the
Restructuring Fee, an affiliate of the Manager subscribed for
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.
Of the $30 million Restructuring Fee, $2.8 million has been 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. During 2006 the Trust paid
an interim management fee of $250,000 per month in the first quarter
and $300,000 per month in the second quarter, up to the closing of
the restructuring transaction on May 31, 2006.
3. RECLAMATION RESERVE
Effective May 31, 2006 the Trust's unitholders approved certain
amendments to a royalty agreement involving the business of the
Trust, which had provided for the establishment of a reserve
("Reclamation Reserve") to assist in funding future asset retirement
obligations. One of the amendments to be made to the royalty
agreement will provide for the elimination of the requirement for the
Reclamation Reserve. Accordingly, the balance in the reserve has been
reclassified to current assets in advance of the transfer of funds to
the general working capital of the Trust.
4. PROPERTY, PLANT AND EQUIPMENT ("PP&E")
---------------------------------------------------------------------
Net book value as at: June 30, December 31,
2006 2005
---------------------------------------------------------------------
Oil and natural gas properties, at cost 1,251,940 $1,204,123
Less: Accumulated depletion and depreciation (519,549) (455,408)
---------------------------------------------------------------------
$732,391 $748,715
---------------------------------------------------------------------
---------------------------------------------------------------------
During the six months ended June 30, 2006, the Trust capitalized
$2.1 million (2005 - $0.8 million) of general and administrative
costs and $1.9 million of unit-based incentive compensation expense
(2005 - $nil) that were directly related to exploitation and
development programs. (See Note 6).
No property costs have been excluded from the depletion and
depreciation calculation.
5. 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 second 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 2006 and will revolve until April 26, 2007 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 2007, 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 April 2008 with a final residual payment, if any, in
April 2009.
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. base 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.
On June 30, 2006 the effective interest rate on amounts outstanding
under the credit facility was 5.05 percent.
6. UNIT-BASED INCENTIVE COMPENSATION PLAN
In January 2006, the Board of Directors approved a revised unit-based
incentive plan (the "Plan") for all employees of the Manager. The
Plan will result 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 ("RTU's") and
Performance Trust Units ("PTU's"). RTU's vest one third on
November 30 in each of three years after grant date. PTU's 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, 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 market value of the notional units held at
vesting.
The first payment under the previous plan was made in December 2005,
the charge for which was accrued throughout the year and of which
$788,000 was charged to income in the first six months of 2005,
including $398,000 related to the second quarter of 2005. With the
expansion of the Plan and the introduction of the annual vesting
provision in 2006, the Trust has commenced to record its share of the
value associated with the notional units in its accounts over the
vesting period.
During the second quarter of 2006, the Trust accrued $782,000 of
unit-based incentive compensation charges in its accounts of which,
$595,000 has been charged to income and $187,000 relating to
exploitation and development personnel has been capitalized in
Property, Plant and Equipment.
On a year-to-date basis, the Trust has accrued $4.3 million of
unit-based incentive compensation charges in its accounts of which
$2.4 million has been charged to income and $1.9 million has been
capitalized. Of the $4.3 million accrued to date, $2.5 million is
expected to be paid in December 2006 and has been included in current
liabilities. The balance represents the long-term portion of the
Trust's estimated liability for the unit-based incentive plan as at
June 30, 2006. This amount is payable in December 2007 and 2008.
The compensation charges relating to the units granted are recognized
over the vesting period based on the unit price, number of RTU's and
PTU's outstanding and the expected performance multiplier. As a
result, the expense recorded in the accounts will fluctuate over
time.
7. 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 $62.8 million
as at June 30, 2006 based on a total undiscounted amount of cash
flows required to settle its asset retirement obligations of
$158.4 million (2005 - $158.5 million). These costs are expected to
be incurred over the next 46 years with the majority of the costs
incurred between 2006 and 2033. NAL's credit-adjusted risk-free rate
of eight percent (2005 - eight percent) and an inflation rate of two
percent (2005 - 1.5 percent) were used to calculate the present value
of the asset retirement obligations.
The following table reconciles the Trust's asset retirement
obligations.
---------------------------------------------------------------------
Six Months Six Months
Ended Ended Year Ended
June 30, June 30, December 31,
2006 2005 2005
---------------------------------------------------------------------
Balance, beginning of period $61,908 $36,924 $36,924
Accretion expense 2,479 2,201 4,582
Liabilities incurred 417 22,442 23,374
Liabilities settled (2,004) (888) (2,972)
---------------------------------------------------------------------
Balance, end of period $62,800 $60,679 $61,908
---------------------------------------------------------------------
---------------------------------------------------------------------
8. UNITHOLDERS' EQUITY
Units Issued:
---------------------------------------------------------------------
Six Months Ended Year Ended
June 30, 2006 December 31, 2005
--------------------------------------
(000s) Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning of period 73,977 753,585 53,064 $476,620
Issued under management
agreement restructuring
(Note 2) 1,592 30,000 - -
Issued for cash - - 17,000 232,900
Less: Issue expenses - (29) - (12,333)
Issued from Distribution
Reinvestment Plan 1,507 26,885 3,913 56,398
---------------------------------------------------------------------
Balance, end of period 77,076 $810,441 73,977 $753,585
---------------------------------------------------------------------
---------------------------------------------------------------------
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As at June 30, 2006 the Trust had entered into the following
derivatives to protect its 2006 cash flow from the volatility of oil
and natural gas commodity prices:
Financial WTI oil contracts in place as at June 30, 2006:
---------------------------------------------------------------------
Sold Bought Sold
Volume Put Put Call
------ ------- ------- -------
Term Contract Bbls/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Jan. 1 to Dec. 31, 2006 3-way 300 52.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 58.50 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 57.50 74.00
Jan. 1 to Dec. 31, 2006 3-way 600 48.00 57.00 72.50
Jan. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 72.50
Feb. 1 to Dec. 31, 2006 3-way 300 48.00 60.00 74.00
July 1 to Dec. 31, 2006 Collar 300 - 68.00 80.90
---------------------------------------------------------------------
2006 weighted average 3,000 48.44 59.20 73.64
---------------------------------------------------------------------
---------------------------------------------------------------------
Financial AECO natural gas contracts in place as at June 30, 2006:
---------------------------------------------------------------------
Volume Bought Put Sold Call
------ ----------- ---------
Term Contract GJ/d Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
Jan. 1 to Dec. 31, 2006 Collar 2,000 9.50 14.40
---------------------------------------------------------------------
---------------------------------------------------------------------
The estimated fair value of the above contracts, all of which qualify
for hedge accounting, was a loss of $1,540,345 as at June 30, 2006.
These instruments have no carrying value recorded in the financial
statements.
Subsequent to June 30, 2006, the Trust entered into further crude oil
contracts as follows:
---------------------------------------------------------------------
Volume Bought Put Sold Call
------ ---------- ---------
Term Contract Bbls/day US$/bbl US$/bbl
---------------------------------------------------------------------
July 1 to Dec. 31, 2006 Collar 300 70.00 84.85
Aug. 1 to Dec. 31, 2006 Collar 300 72.00 87.35
Jan. 1 to June 30, 2007 Collar 300 70.00 85.85
Jan. 1 to June 30, 2007 Collar 300 72.00 88.10
---------------------------------------------------------------------
---------------------------------------------------------------------
10. COMMITMENTS
At December 31, 2005 the Trust had the following contractual
obligations and commitments:
---------------------------------------------------------------------
($000s) 2006 2007 2008 2009 2010
---------------------------------------------------------------------
Office lease(1) 1,448 2,734 2,580 2,580 2,365
Transportation agreement 1,342 659 659 89 -
Processing agreement(2) 260 491 469 446 428
Drilling rigs(3) 988 1,975 494 - -
---------------------------------------------------------------------
(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
54 percent) of the expense on a monthly basis. Included in office
lease is a $0.6 million commitment related to the Addison Energy
acquisition. The commitment started in February 2005 and extends
30 months. NAL has subsequently sublet the premises.
(2) Represents gas processing agreement under take or pay arrangement
associated with Addison Energy acquisition.
(3) Represents the Trust's share of the minimum payments required
under drilling rig contracts held by NAL Resources.
11. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform to
current period presentation.
TRADING PERFORMANCE
-------------------------------------------------------------------------
For the Quarter Ended
-----------------------------------------------------
Price 30-Jun-06 31-Mar-06 30-Jun-05 31-Mar-05
-------------------------------------------------------------------------
High $20.67 $20.25 $14.98 $14.69
Low $18.26 $16.92 $13.13 $12.82
Close $20.00 $19.58 $14.25 $13.80
Volume 11,319,677 13,614,737 12,790,674 23,391,175
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NAL Oil & Gas Trust
Gordon Currie
Manager, Investor Relations
(403) 294-3620 or Toll Free: 1-888-223-8792
Fax: (403) 515-3407
Email: Investor.Relations@nal.ca
Website: www.nal.ca