NAL Oil & Gas Trust reports strong third quarter results and generates positive momentum for 2006
CALGARY--(CCNMatthews - Nov. 9) - NAL Oil & Gas Trust (TSX: NAE.UN) (the "Trust" or "NAL") today announced its financial and operational results for the third quarter of 2005. All amounts are in Canadian dollars unless otherwise stated.
Third Quarter Highlights
- On October 11, 2005 the Trust announced a 19 percent increase in distributions from $0.16 to $0.19 per month effective with the distribution payable on November 15, 2005.
- Delivered positive production momentum in the third quarter, 2005 through excellent operating performance in all core areas resulting in a 54 percent increase in volume over third quarter, 2004 and stronger exit rates for 2005.
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BOE per Day(1)
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Nine months ended September 30, 2005 18,514
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Three months ended September 30, 2005 19,710
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Exit rate, September, 2005 20,000
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Exit rate forecast, December, 2005 20,700
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Full year average, 2005 19,000
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- Funds available for distributions in the third quarter were $62.4 million, an increase of 106 percent compared to $30.3 million in the same period in 2004.
- Through the Addison acquisition and our capital program in 2005, the Trust continues to move towards targeting a higher natural gas weighting and better overall oil/gas balance. For the third quarter 2005, the Trust's production was 48 percent oil, 41 percent natural gas and 11 percent natural gas liquids compared to 64 percent oil, 32 percent natural gas and 4 percent natural gas liquids a year earlier.
- The Trust's netbacks per boe continued to increase to Cdn$40.34 per barrel in Q3, 2005 before hedging, a 35 percent increase over the same period in 2004.
- An analysis of G&A expenses and capitalization practices has resulted in higher capitalization of G&A and a resulting adjustment to 2005 G&A expenses, lowering G&A to $0.45 per boe in Q3 and $1.39 per boe for the nine months ended September 30, 2005.
- The fee structure of the Management Contract with NAL Resources is being renegotiated and will result in a lower fee structure for the Trust effective January 1, 2006. This fee renegotiation will be completed by year end 2005.
- Long-term debt (net of working capital) has been reduced to $215 million compared to more than $250 million after the Addison acquisition.
- 2005 crude oil hedges on 41 percent of total production expire December 31, 2005. Natural gas hedges expired October 31, 2005 and gas production will receive full market price for November and December 2005. Currently, the Trust is unhedged for 2006.
- Payout ratios have been lowered to 56 percent in Q3, 2005 and 64 percent over the nine-month period ending September 30, 2005.
- The Trust has been advised that it will be included as one of the Income Trusts in the S&P/TSX Composite Index scheduled to be implemented in late 2005/early 2006.
- At 9:00 a.m. MST on Thursday, November 10, 2005 NAL will conduct a conference call to discuss its third 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 1-800-865-0780. Those who are unable to listen to the call live may listen to a recording of it by calling 1-800-633-8284, reservation No. 21268579. The recording will be available until November 20, 2005.
(1) 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 equivalent (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.
President's Message
On November 9, 2005 NAL Oil and Gas Trust announced positive third quarter 2005 operating and financial results with all key measures delivering year over year improvement. These results position the Trust for a strong finish in the fourth quarter of 2005 and creates significant momentum going into 2006.
These results are positive trends and are driven by strong operational activity in all our core areas. Our technical and operational teams are focused on delivering operational excellence and maximizing performance from our existing asset base. Delivering operational excellence means maximizing recoveries and extending the life of our reservoirs and facilities, means planning and executing multi-well programs, means leveraging the latest tools and technologies such as 3D seismic and horizontal drilling, means assessing multi-zone potential - all while maintaining our Industry recognized strong environmental, health and safety performance and respect to communities in which we operate.
Priorities
----------
As a new CEO to the organization effective June 1, 2005, my first priority was to review the Trust's operating plans and strategies to ensure we were positioned to drive strong performance and to continue to deliver sustainable distributions. Clearly, the execution of our operating plans and momentum in Q3 and Q4, 2005 positions us well to continue to perform. This momentum is supported by a strong asset base concentrated in core areas, high working interest and control through operatorship of our properties, and an inventory of internal investment opportunities of 18-24 months.
With our operating plans clarified, our next priority was to identify certain initiatives that would drive positive change and position the Trust for improved performance in the future. These initiatives are key priorities for our management team and our organization as we move forward into 2006:
- Setting clear direction and targets, focusing on our people and our performance through our four core strategies: Growth in cash flow, operational excellence, conservative financial management and building organizational capability. These targets will be finalized as part of our 2006 budget process to be completed by year end 2005.
- Renegotiating the management contract to reduce management fees to the Trust.
- Reviewing the Trust's G&A to ensure appropriate costs, capitalization and reporting.
- Revisiting short-term and long-term incentive plans to ensure competitiveness, strong linkage to performance targets and unitholder returns and appropriate reporting and disclosure.
- Continuing to enhance our independent board governance through clarifying roles, mandates and structure.
Progress will continue to be made on these initiatives during 2006.
Forecasts for 2005 -2006
------------------------
As to our current estimates for full year 2005, our current forecasts are as follows:
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Measure Full Year 2005 Estimate
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Production 19,000 boe per day
Operating costs $7.70 - $7.85
G&A $1.40 - $1.50
Capital expenditures $70 - $72 million
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Our budgets for 2006 are currently being developed and further guidance will be provided in early 2006.
Building our Financial Team
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We are making meaningful progress in building our financial team adding key experience and capability. Our CFO search remains active with discussions ongoing with quality candidates. Our Controller position has been filled by Bob McKay, an experienced internal candidate with a CMA and 20 years' business and operating experience. We have also added Tracy Wood as Manager of Financial Reporting. A Chartered Accountant, Tracy comes to us after 13 years with a large public accounting firm, most recently as an Associate Audit Partner. We have also added experienced resources in tax, cash management and financial analysis.
Government of Canada Review of Trusts
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The Federal Government's recent announcement that it is reviewing the policies in relation to flow through entities and income trusts has created uncertainty in the income trust market and volatility in unit price. In addition, the Government has expressed concern that the conversion from corporations to a structure focused on maintaining stable distributions may result in economic slow down and reduced productivity. To address these issues, the Government has issued a consultation paper on the topic and has invited interested parties to submit comments.
NAL would encourage unitholders to participate in the process by contacting their Member of Parliament at:
www.canada.gc.ca/directories/direct_e.html or contacting the Minister of Finance, The Honourable Ralph Goodale, Department of Finance, 104 O'Connor Street, Ottawa, Ontario K1A 0A6. Telephone: 613-996-4743. Fax: 613-996-9760. Email:
goodale.R@parl.gc.ca by the end of November.
Summary
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In summary, we are very committed to delivering performance and ongoing change and look forward to delivering consistently strong returns to our unitholders.
Andrew Wiswell
President and Chief Executive Officer
Financial and Operating Highlights
(thousands of dollars, except per unit and boe data)
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Quarter Quarter Quarter 9 Months 9 Months
Ended Ended Ended Ended Ended
September June September September September
FINANCIAL 30, 2005 30, 2005 30, 2004 30, 2005 30, 2004
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Gross revenue, net
of royalties $ 84,833 $ 70,797 $ 43,989 $ 216,247 $ 123,203
Net income 31,710 20,804 13,279 67,761 33,113
Funds from
operations
Deduct: 63,546 50,237 30,809 157,804 86,249
Contributions to
reclamation
reserve (72) (157) (100) (326) (321)
Actual
abandonment and
environmental
costs (1,104) (356) (363) (1,992) (911)
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Funds available
for distribution
before: 62,370 49,724 30,346 155,486 85,017
Funds applied to
debt and capital (27,565) (15,462) (5,606) (55,393) (14,070)
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Distributions
declared 34,805 34,262 24,740 100,093 70,947
Funds available
for distribution
per unit 0.86 0.70 0.58 2.26 1.64
Distributions
declared per unit 0.48 0.48 0.47 1.44 1.37
Debt repayment and
capital per unit 0.38 0.22 0.11 0.82 0.27
Average number
of units
outstanding 72,345,238 71,187,715 52,494,452 68,770,046 51,645,169
Total assets $821,421 $820,166 $421,493 $821,421 $421,493
Long-term debt,
net of working
capital 214,508 229,005 87,772 214,508 87,772
Unitholders'
equity 487,979 475,198 272,714 487,979 272,714
Costs per boe
(6:1):
Operating $8.55 $7.14 $6.98 $7.50 6.16
General and
administrative 0.45 2.31 1.57 1.39 1.49
Management fees 1.19 1.17 1.77 1.12 1.63
OPERATING
Daily production
Oil (bbl) 9,432 9,197 8,145 9,279 8,217
Natural gas
(Mcf) 48,738 43,254 24,572 44,548 25,895
Natural gas
liquids (bbl) 2,155 1,943 567 1,810 666
Oil equivalent
(boe - 6:1) 19,710 18,349 12,807 18,514 13,199
Average pricing,
net of
transportation
charges
Liquids:
WTI (US$/bbl) 63.19 53.18 43.85 55.40 39.13
NAL average oil
(Cdn$/bbl) 67.28 57.94 52.48 60.37 45.37
Natural gas
liquids
(Cdn$/bbl) 51.94 45.84 41.05 46.95 36.79
Natural gas:
AECO (Cdn$/Mcf) 9.25 7.32 6.67 7.81 6.69
Natural gas
Western Canada
(Cdn$/Mcf) 8.51 7.87 6.31 7.77 6.51
Natural gas
Lake Erie
(Cdn$/Mcf) 11.73 9.14 7.76 9.88 8.22
NAL average
natural gas
(Cdn$/Mcf) 8.81 7.99 6.60 7.97 6.82
Oil equivalent
(Cdn$/boe - 6:1) 59.66 52.67 47.82 54.02 43.63
Average foreign
exchange rate
Cdn$/US$ 1.2012 1.2435 1.3074 1.2239 1.3281
Operating netback
before hedging
gains/losses
($/boe) 40.34 34.96 29.78 35.73 28.77
Hedging gains
(losses) per boe (3.05) (0.51) - (1.27) (1.33)
Operating netback
($/boe) 37.29 34.45 29.78 34.46 27.44
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Management's Discussion and Analysis
------------------------------------
Please read Management's Discussion and Analysis (MD&A) in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2005, and the audited consolidated financial statements and MD&A for the year ended December 31, 2004.
Operating netbacks, funds from operations, funds available for distribution and funds available for distribution per unit are not recognized measures under Canadian generally accepted accounting principles (GAAP). Management believes that in addition to net income, operating netbacks, funds from operations, funds available for distribution and funds available for distribution 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 or how the results are taxed. 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 companies' and accordingly, they may not be comparable to measures used by other companies. NAL calculates funds from operations as prior to the change in non-cash working capital related to operating activities. Funds available for distribution is calculated based on funds from operations less contributions to the reclamation reserve and actual abandonment and environmental costs, with the per unit amount calculated using the weighted average units outstanding for the period.
Distributions to Unitholders
Funds available for distribution in the third quarter rose to $62.4 million or $0.86 per unit, compared with $30.3 million or $0.58 per unit for the same three-month period in 2004. A 25 percent rise in oil equivalent commodity pricing, combined with a 54 percent increase in production, drove the year-over-year increase. Distributions declared per unit for the quarter increased by $0.01 from $0.47 to $0.48 per unit, an increase of 2 percent. Effective October 21, 2005, the Company announced an increase in monthly distributions from $0.16 to $0.19 per unit, a 19 percent increase, which is anticipated to be sustainable for the foreseeable future.
Weighted average units outstanding increased by 38 percent due to the Addison acquisition and participation in the Distribution Reinvestment Plans.
Unitholders' Distributions
(thousands of dollars, except per unit amounts) (unaudited)
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3 Months 3 Months 9 Months 9 Months
Ended Ended Ended Ended
September September September September
30, 2005 30, 2004 30, 2005 30, 2004
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Funds from operations $63,546 $30,809 $157,804 $86,249
Deduct:
Contributions to
reclamation reserve (72) (100) (326) (321)
Actual abandonment costs (1,104) (363) (1,992) (911)
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Funds available for
distribution before 62,370 30,346 155,486 85,017
Funds applied to debt
repayment and capital (27,565) (5,606) (55,393) (14,070)
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Distributions declared $34,805 $24,740 $100,093 $70,947
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Distributable income
per unit(1) $0.86 $0.58 $2.26 $1.64
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Distributions declared
per unit $0.48 $0.47 $1.44 $1.37
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Weighted average units
outstanding 72,345,238 52,494,452 68,770,046 51,645,169
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(1) Based on weighted average units outstanding
Operating Highlights
Development Activities
The Trust participated in the drilling of 82 (47.73 net) wells during the third quarter with a success rate of 99 percent. In Alberta, our activities were focused on shallow gas drilling in Brent and coalbed methane on the Addison properties at Nevis. In southeastern Saskatchewan, we continued to focus on light oil development opportunities utilizing horizontal drilling technology.
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Q3 2005 Service Dry &
Drilling Crude Oil Natural Gas Wells Abandoned Total
Activity Gross Net Gross Net Gross Net Gross Net Gross Net
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Operated wells 8 3.67 49 40.49 0 0.00 0 0.00 57 44.15
Non-operated
wells 6 0.18 12 2.80 4 0.00 3 0.60 25 3.58
Total wells
drilled 14 3.85 61 43.29 4 0.00 3 0.60 82 47.73
Year-to-date
total 40 12.24 91 52.36 6 0.25 4 1.05 141 65.90
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Coalbed Methane ("CBM")
-----------------------
During the third quarter, approximately $4.5 million was invested in the development of the dry Horseshoe Canyon coals. At Nevis, 15 (8.02 net) wells were drilled during the quarter to complete the 18 (9.45 net) well program initiated during the second quarter. Production tests from these wells exceeded management's expectations by testing at average rates greater than 200 Mcf/day per well (gross) representing a total of 1.9 MMcf/day net to the Trust. In addition, seven (3.7 net) of the 18 CBM wells encountered Belly River sands and will be dually completed. These Belly River zones tested at a combined rate of 2.5 MMcf/day net to the Trust. The Trust has installed new processing and compression facilities which are operated and controlled by the Trust. This facility was commissioned in October and tie-ins are scheduled to be completed during November. Initial production from the area is forecast to be approximately 3.0 MMcf/day net to the Trust.
At Lacombe, a five (3.5 net) well CBM pilot program was initiated by drilling one (0.7 net) well during the third quarter. The remaining wells will be drilled and tested during the fourth quarter and are expected to be on production by the first quarter, 2006. The results of these wells will be used to establish the scope of the CBM development program scheduled for 2006.
Shallow Gas
-----------
NAL invested approximately $6 million during the third quarter pursuing shallow gas development opportunities in east-central Alberta. At Brent/Hanna, 31 (30.86 net) wells were drilled targeting long reserve life tight gas from the Second White Specks. Seventeen (17.0 net) of these wells were tied-in during the quarter adding a total of 600 Mcf/day of net production to the Trust on average for September. The 14 remaining wells have been tied-in during October with similar results.
Also in Brent, five (1.56 net) wells were drilled during the quarter targeting Viking gas in the non-operated Provost Unit. An additional seven (2.19 net) wells will be drilled in the Unit during the fourth quarter. Completion and testing will occur during Q4 and production is anticipated to come on-stream late in 2005 and early in 2006.
Saskatchewan Oil
----------------
Active development of the Trust's oil assets in southeastern Saskatchewan continued during the quarter by investing $4.5 million to drill and tie-in a total of 11 (3.80 net) horizontal oil wells. At Browning, two (1.5 net) wells were brought on production late in the quarter. At Elswick, two (0.89 net) wells were brought on production in addition to one (0.13 net) well drilled during the previous quarter. At Steelman, two (0.62 net) wells were brought on production in addition to one well at each of Alida (0.45 net), Nottingham (0.22 net) and Lost Horse Hills (0.12 net). By the end of the third quarter, these wells added a total of over 400 boed of net production to the Trust.
Lake Erie Gas
-------------
This year's non-operated shallow gas development program under Lake Erie, Ontario was completed by drilling a total of nine (1.81 net) wells during the third quarter. Of these wells, four (0.81 net) were brought on production in August, two (0.40 net) are being tied-in in October and three (0.60 net) were dry and abandoned. In total, the Trust invested approximately $2.0 million during 2005 to drill and complete 22 (4.33 net) wells with an overall success rate of 86 percent. Net production additions from the program are estimated to be 0.5 MMcf/day. Gas sales from Lake Erie receive a premium price, typically 25 percent higher than average Alberta prices.
Production
During the third quarter, the Trust's production averaged 19,710 boed, up 54 percent from the third quarter, 2004 and 7 percent higher than Q2, 2005. This increase year over year is attributable to the Addison acquisition and strong operating performance and drilling results from all our core areas.
For the nine months ended September 30, 2005, production increased by 40 percent despite wet weather and turnarounds lowering production in Q2, 2005.
The Trust anticipates full year production to average 19,000 boed which is at the high end of our previously stated guidance of 18,500 to 19,000 boed. The Trust expects to exit 2005 averaging approximately 20,700 boed.
Daily Production Volumes
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3 months ended September 30 9 months ended September 30
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2005 2004 % Change 2005 2004 % Change
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Oil (bbl/d) 9,432 8,145 16% 9,279 8,217 13%
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Natural gas
(Mcf/d) 48,738 24,572 98% 44,548 25,895 72%
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NGL (bbl/d) 2,155 567 280% 1,810 666 172%
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Oil equivalent
(boed) 19,710 12,807 54% 18,514 13,199 40%
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As a result of the Addison acquisition, the Trust's weighting to natural gas has increased significantly. For the third quarter, 2005, gas was 41 percent and oil, 48 percent of total production, compared to 32 percent gas and 64 percent oil a year earlier.
Production Volume Weighting
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3 months ended September 30 9 months ended September 30
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2005 2004 % Change 2005 2004 % Change
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Oil 48% 64% (25)% 50% 62 (19)%
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Natural Gas 41% 32% 28% 40% 33 21%
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NGL 11% 4% 175% 10% 5 100%
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Commodity Prices
Crude Oil and Natural Gas Liquids (NGLs)
----------------------------------------
Throughout the third quarter world oil prices remained strong. WTI benchmark crude averaged US$63.19/bbl during this period, up 44 percent from US$43.85 a year ago and 19 percent higher than US$53.18 in the second quarter of 2005. NAL's oil price per barrel averaged $67.28, up 28 percent from the prior year period and 16 percent higher than the previous quarter. An 8 percent increase in the Canadian dollar, as compared to the quarter ended September 30, 2004, partially mitigated the rise in year-over-year oil pricing. Hedging contracts in place during the three months ended September 30, 2005, negatively affected NAL's third quarter realized crude price by $4.97/bbl or $4.3 million in aggregate.
Year-over-year, the price per barrel of natural gas liquids rose by 27 percent to $51.94/bbl compared to $41.05 in the third quarter, 2004. Compared to the second quarter of 2005, the natural gas liquids price increased by 13 percent.
For the nine-month period ended September 30, 2005, the average oil price of $60.37 was 33 percent higher than the $45.37/bbl price realized a year earlier. The aggregate hedging impact for the nine months negatively affected NAL's nine-month realized crude prices by $2.01/bbl or $5.1 million in aggregate.
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3 months ended September 30 9 months ended September 30
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2005 2004 % Change 2005 2004 % Change
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NAL average oil
(Cdn$/bbl) 67.28 52.48 28 60.37 45.37 33
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NAL average
natural gas
(Cdn$/Mcf) 8.81 6.60 33 7.97 6.82 17
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NGL (Cdn$/bbl) 51.94 41.05 27 46.95 36.79 28
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Oil equivalent
(Cdn$/boe) 59.66 47.82 25 54.02 43.63 24
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Natural Gas
-----------
Western Canadian average natural gas prices were 39 percent higher compared to the same quarter in 2004. The AECO reference price averaged $9.25/Mcf in the third quarter of 2005 compared with $6.67/Mcf in the comparable period of 2004. Third quarter 2005 natural gas prices were 26 percent higher versus the second quarter of 2005 when the AECO daily index price averaged $7.32/Mcf.
Natural gas from our Lake Erie production was sold at $11.73/Mcf in the third quarter, up 51 percent from $7.76/Mcf a year ago and up 28 percent from the second quarter of 2005. Lake Erie's gas represents 9.5 percent of NAL's total year-to-date natural gas production and is premium priced due to its proximity to both the Ontario and northeastern U.S. markets.
On an overall basis, NAL received an average third quarter natural gas price, net of transportation costs, of $8.81/Mcf, up 33 percent from the $6.60/Mcf reported in the same period last year and up 10 percent compared to the second quarter, 2005. Hedging contracts in place during the three months ended September 30, 2005 negatively affected the realized natural gas price by $0.28/Mcf or $1.2 million in aggregate.
For the nine-month period ended September 30, 2005, the overall natural gas price realized was $7.97/Mcf, a 17 percent increase over the $ 6.82/Mcf price a year earlier. The aggregate hedging effect for the nine months negatively affected NAL's nine-month realized natural gas price by $0.10/Mcf or $1.3 million in aggregate.
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3 months ended September 30 9 months ended September 30
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2005 2004 % Change 2005 2004 % Change
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AECO (Cdn$/Mcf) 9.25 6.67 39 7.81 6.69 17
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Western Canada
(Cdn$/Mcf) 8.51 6.31 35 7.77 6.51 19
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Lake Erie
(Cdn$/Mcf) 11.73 7.76 51 9.88 8.22 20
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NAL average
natural gas
(Cdn$/Mcf) 8.81 6.60 33 7.97 6.82 17
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Risk Management
NAL has entered into certain fixed price contracts for both oil and natural gas as a measure to support cash flow and distributions and to protect the balance sheet. A table detailing 2005 hedging positions is set out below.
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% of net
Daily Daily
Time Type of Quantity Hedged Produc-
Year Period Commodity Contract Hedged Price tion
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2005 Apr - Dec Oil Financial 3,900 bbls Cdn$63.85/bbl 41
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Natural
2005 Apr - Oct Gas Financial 17,000 GJ Cdn$6.95/GJ 33
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In total, the hedging loss for the nine-month period ended September 30, 2005 is $6.4 million. Looking forward, the estimated fair value of the pricing contracts in place at September 30, 2005 was an unrealized loss of $6.9 million for the October 1 to December 31, 2005 period. This value was based on the difference between the respective financial contract price and the market- based forward-pricing curve of the related commodity as at September 30, 2005.
Revenue and Funds from Operations
Gross revenue(1) from oil, natural gas and natural gas liquids sales totaled $108 million in the three months ended September 30, 2005, - a 92 percent increase over the same period last year. A 54 percent rise in quarterly production, driven primarily by the Addison Acquisition, and a 25 percent increase in oil equivalent pricing were the major contributing factors. Funds from operations tracked revenues, up 106 percent over last year's third quarter.
For the nine-month period ended September 30, 2005 a 73 percent increase in revenues and an 83 percent increase in funds from operations were realized.
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3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Revenue(1)
($000's) 108,178 56,340 92 273,036 157,820 73
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$/boe 59.66 47.82 25 54.02 43.64 24
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(1) Oil, natural gas and liquids sales less transportation costs and
hedging
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3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Funds from
operations
($000's) 63,546 30,809 106 157,804 86,249 83
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$/boe 35.04 26.15 34 31.22 23.85 31
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Net Income
Net income for the three months ended September 30, 2005 was $31.7 million, $18.4 million higher than the $13.3 million recorded in the third quarter of 2004. This higher net income was driven by higher production and commodity prices, partially offset by somewhat higher royalties, depletion and operating costs.
Net income for the nine months ended September 30, 2005 increased by 105 percent, based on similar drivers.
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3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Net income
($000's) 31,710 13,279 139 67,761 33,113 105
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As % of
revenue(1) 29.3 23.6 24 24.8 21.0 18
---------------------------------------------------------
$/boe 17.49 11.27 55 13.41 9.16 46
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(1) Oil, natural gas, and liquids sales less transportation costs and
hedging
Royalties
Crown, freehold and overriding royalties net of Alberta Royalty Tax Credit ("ARTC") were $25.1 million for the three months ended September 30, 2005. Expressed as a percentage of gross sales, before hedging and transportation costs, the net royalty rate was 21.9 percent for the quarter.
The royalty per boe for the three-month period ended September 30, 2005 includes changes in the Saskatchewan Resource Surcharge applicable to the Trust effective April 1, 2005. This new surcharge increased royalties by an incremental $1 million in both Q2 and Q3.
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3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Net royalties
($000's) 25,062 13,030 92 60,940 36,258 68
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As % of
revenue(1) 21.9 23.0 0 21.6 22.2 (3)
---------------------------------------------------------
$/boe 13.82 11.06 25 12.06 10.03 20
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(1) Oil, natural gas, and liquids sales excluding hedging gains/losses
Operating Costs
For the three months ended September 30, 2005 operating costs averaged $8.55 per boe, a 22 percent increase over the same period in 2004. This increase was driven by higher costs in the gas weighted Addison properties, full completion of the turnaround activity commenced in the second quarter, active workover, repair and maintenance programs, as well as higher overall costs due to strong demand for people, equipment and services in the industry.
For the nine months ended September 30, 2005 operating costs averaged $7.50 per barrel which compares favorably to industry averages.
The Trust expects full year 2005 operating costs to average in the range of $7.70 - $7.85 per boe.
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3 months ended September 30 9 months ended September 30
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2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Operating costs
($000's) 15,511 8,224 89 37,915 22,288 70
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As % of revenue 14.3 14.6 (2) 13.9 14.1 (1)
---------------------------------------------------------
$/boe 8.55 6.98 22 7.50 6.16 22
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Operating Netback
NAL's operating netback before hedging continued to be top quartile at $40.34 per boe, up 35 percent from the $29.78 recorded in the same period a year ago. Record high crude oil pricing led to a 25 percent increase in oil equivalent pricing. This increase was partially offset by higher operating expenses and net royalties.
Similar trends in operating netback were experienced for the nine-month period ended September 30, 2005.
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($/boe) 3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Revenue, net of
transportation
costs 62.71 47.82 31 55.29 44.96 23
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Royalties, net (13.82) (11.06) 25 (12.06) (10.03) 20
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Operating
expenses (8.55) (6.98) 22 (7.50) (6.16) 22
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Operating
netback, before
hedging 40.34 29.78 35 35.73 28.77 24
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Hedging effect (3.05) - - (1.27) (1.33) (5)
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Operating
netback, after
hedging 37.29 29.78 25 34.46 27.44 26
---------------------------------------------------------
General & Administrative (G&A)
During the third quarter the Trust completed a review of G&A expenses, which concluded that certain costs relating to exploitation and development activity during the first six months of 2005 had been under-capitalized. An adjustment of $1.8 million relating to expenses incurred prior to June 30, 2005 was made during Q3 to capitalize these expenses. As a result of these adjustments, G&A costs for the three months ended September 30, 2005, were $0.45 per boe.
We anticipate that the full year 2005 G&A will be in the range of $1.40 to $1.50 per boe.
---------------------------------------------------------
3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
G&A costs
($000's) 817 1,845 (56) 7,033 5,383 31
---------------------------------------------------------
As % of revenue 0.8 3.3 (76) 2.6 3.4 (24)
---------------------------------------------------------
$/boe 0.45 1.57 (71) 1.39 1.49 7
---------------------------------------------------------
Per Trust
unit ($) 0.01 0.04 (75) 0.10 0.10 -
---------------------------------------------------------
Management Fees
Total management fees for the three months ended September 30, 2005 amounted to $2.1 million, comparable to the same period last year. These management fees are comprised of base fees and performance fees tied to a market index. Base management fees fluctuate with revenues and operating cash flows which were higher year-over-year due to higher production and commodity prices.
There was no performance fee recorded based on the Trust's third quarter performance which did not exceed the performance of its peers based on the S&P/TSX Capped Energy Trust Index (the "Index"). NAL's total return for the three months ended September 30, 2005, was 15.3 percent compared with a 23.2 percent return for the Index. Total year-to-date management fees were $5.7 million or $1.12 per boe in 2005, compared with $5.9 million or $1.63 per boe for the same period in 2004.
For the nine-month period ended September 30, 2005 management fees were lower by four percent due primarily to no performance fee being payable during the period.
---------------------------------------------------------
3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Management fees
($000's) 2,162 2,082 4 5,674 5,912 (4)
---------------------------------------------------------
As % of revenue 2.0 3.7 (46) 2.1 3.7 (43)
---------------------------------------------------------
$/boe 1.19 1.77 (33) 1.12 1.63 (31)
---------------------------------------------------------
Per trust
unit ($) 0.03 0.04 (25) 0.08 0.11 (27)
---------------------------------------------------------
Interest
Interest expense for the quarter ended September 30, 2005 was
$2.8 million. Year-over-year third quarter interest charges increased by
$1.9 million due to a higher average debt after the February 10, 2005 Addison
acquisition.
---------------------------------------------------------
3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Interest
($000's) 2,823 932 203 7,721 3,014 156
---------------------------------------------------------
Depletion, Depreciation and Accretion
In the third quarter of 2005 depletion on property, plant and equipment and accretion on the asset retirement obligation increased over the comparable period in 2004, primarily because of higher production volumes. Third quarter depletion and accretion charges amounted to $31.8 million in 2005 compared with $17.6 million for 2004. Per boe, depletion and accretion rose 18 percent to $17.56 in the third quarter from $14.92 a year ago.
For the nine months ended September 30, 2005 depletion and accretion expenses were $88.7 million compared to $53.2 million for the same period in 2004. On a per barrel basis, depletion and accretion rose 19 percent to $17.56 compared to $14.72 in the comparable nine-month period, primarily due to the Addison acquisition.
---------------------------------------------------------
3 months ended September 30 9 months ended September 30
---------------------------------------------------------
2005 2004 % Change 2005 2004 % Change
---------------------------------------------------------
Depletion and
accretion
($000's) 31,847 17,576 81 88,738 53,225 67
---------------------------------------------------------
Capital Resources and Liquidity
The capital structure of the Trust is comprised of trust units and debt.
As at September 30, 2005 NAL had 72,847,451 units outstanding - 19,783,311 units more than on December 31, 2004 reflecting the 17,000,000 units issued through the January 12, 2005, prospectus and additional units issued through the Trust's Distribution Reinvestment Plan ("DRIP"). Commencing with the February 15 distribution payment, the premium component of NAL's DRIP was temporarily reinstated after being suspended in October 2004. The DRIP generated net proceeds of $15.9 million in the third quarter and $38.6 million for the nine months to date. The proceeds were used to fund existing capital programs and to reduce debt.
Net debt was $214.5 million at the end of September 2005, with a net debt at 1.02 times 12 months' trailing cash flow. By year end, with lower debt levels and strong fourth quarter cash flows, the debt to cash flow ratio is forecast to be in the range of 0.9.
NAL maintains a $300 million, fully secured, extendible revolving term bank credit facility. 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, the cash flows otherwise available to unitholders would be used to repay the credit facility.
-----------------------------------------------------------
($000's) September 30, 2005 December 31, 2004 September 30, 2004
-----------------------------------------------------------
Trust unit
equity 487,979 261,037 272,714
Long-term debt 238,800 93,700 92,200
Debt to equity 0.49 0.36 0.34
Net debt(1) 214,508 96,864 87,772
Net debt to
trailing
12-month cash
flow(2) 1.02 0.84 0.79
-----------------------------------------------------------
(1) Net debt is long-term debt net of working capital.
(2) Determination of third quarter 2005 ratio based on an annualized
September 2005 year-to-date cash flow to adjust for the Addison
acquisition.
Contractual Obligations
NAL enters into many contractual obligations as part of conducting day-to-day business. NAL has the following long-term commitments for the remaining years indicated:
($000's) 2005 2006 2007 2008 2009
-------------------------------------------------------------------------
Office lease(1) 558 2,238 1,765 - -
Transportation Agreement(2) 218 70 - - -
(1) Represents the full amount of the office lease, both base rent and
operating costs, held by the Manager of which NAL is allocated a pro
rata share of the expense on a monthly basis. Included in office
lease is a $1.5 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) Includes transportation commitments associated with the Addison
Energy acquisition.
Off-Balance Sheet Arrangements/Variable Interest Entities
NAL has no off-balance sheet arrangements or variable interest entities.
Capital Expenditures
Capital expenditures in the third quarter of 2005 amounted to $28.8 million compared with $16.4 million a year ago. For the nine months ended September 30, 2005 capital expenditures totaled $46.9 million as compared to $31.6 million in the same period in 2004.
Effective February 10, 2005 NAL completed a corporate acquisition of Addison Energy Inc. resulting in the acquisition of assets in Alberta for approximately $387.5 million after purchase-price adjustments. For further details of the Addison transaction, see Note 1 to the financial statements.
----------------------------------
3 months ended 9 months ended
September 30 September 30
----------------------------------
2005 2004 2005 2004
----------------------------------
Drilling, completion and production
equipment 21,036 14,478 36,385 25,572
----------------------------------
Plant and facilities 3,093 1,357 4,435 2,981
----------------------------------
Seismic 1,462 36 1,619 660
----------------------------------
Other(1) 3,235 603 4,494 2,447
----------------------------------
Total capital expenditures 28,826 16,474 46,933 31,660
-----------------------------------
(1) Includes land purchases and capitalized G&A
As a result of positive results, timely receipt of regulatory approvals
and availability of crews and equipment, we have increased our 2005 capital
expenditure program from the $68 million budgeted to $70 - $72 million.
Quarterly Information
--------------------------------------------------------------
Financial 2005 2004 2003
--------------------------------------------------------------
Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
--------------------------------------------------------------
Revenue, net
of royalties
and trans-
portation 84,833 70,797 60,617 43,110 43,989 40,674 38,540 37,697
Per unit 1.17 0.99 0.97 0.81 0.84 0.79 0.76 0.75
Funds from
oper-
ations 63,546 50,237 44,021 29,633 30,809 28,789 26,651 24,413
Per unit 0.88 0.71 0.69 0.56 0.59 0.56 0.52 0.48
Distributions
declared
per unit 0.48 0.48 0.48 0.48 0.47 0.45 0.45 0.45
Net income 31,710 20,804 15,247 11,754 13,279 10,871 8,963 3,252
Per unit 0.44 0.29 0.24 0.22 0.25 0.21 0.18 0.06
--------------------------------------------------------------
The summary of quarterly information demonstrates a consistent trend in improving financial performance and financial performance per unit, driven by strong commodity prices and production additions contributed by the significant acquisition of Addison in 2005 and the Nexen properties in 2003.
Critical Accounting Estimates
The significant accounting policies used by NAL are disclosed in the notes to NAL's December 31, 2004 audited financial statements. Certain accounting policies require that management make appropriate decisions when formulating estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discusses such accounting policies and is included in Management's Discussion and Analysis to assist investors in assessing the critical accounting policies and practices of NAL and the likelihood of materially different results being reported. NAL's management reviews its 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.
The following assessment of significant accounting estimates is not meant to be exhaustive. NAL might realize different results from the application of new accounting standards published, from time to time, by various regulatory bodies.
Proved Oil and Gas Reserves
---------------------------
Under National Instrument 51-101 ("NI 51-101"), "proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable (it is likely that the actual remaining quantities recovered will exceed the estimated proved reserves). In accordance with this definition, the level of certainty targeted by the reporting company should result in at least a 90 percent probability at a company aggregate level that the quantities actually recovered will equal or exceed the estimated reserves. There was no such consideration of probability under previous reporting rules. In the case of "probable" reserves, which are less certain to be recovered than proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable ("P+P") reserves. As for certainty, in order to report reserves as P+P, the reporting company must believe that there is at least 50 percent probability at a company aggregate level that the quantities actually recovered will equal or exceed the sum of the estimated P+P reserves. The implementation of NI 51-101 has resulted in a more rigorous and uniform standardization of reserve evaluation.
The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in NAL's plans. The effect of changes in proved oil and gas reserves on the financial results and position of NAL is described under the heading "Full Cost Accounting for Oil and Gas Activities ("Ceiling Test")".
Depletion Expense
-----------------
NAL uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether or not the activities funded were successful. The aggregate of net capitalized costs and estimated future development costs, less estimated salvage values, is amortized using the unit of production method based on estimated proved oil and gas reserves.
An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense.
Impairment of Property, Plant & Equipment
-----------------------------------------
NAL is required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived oil and gas asset is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the property, plant and equipment is charged to earnings.
Fair Value of Derivative Instruments
------------------------------------
Periodically NAL utilizes financial derivatives to manage market risk. The purpose of the hedge is to provide an element of stability to NAL's cash flow in a volatile environment. NAL discloses the estimated fair value of open hedging contracts as at the end of a reporting period.
Asset Retirement Obligation
---------------------------
NAL adopted the CICA Handbook, section 3110 on asset retirement obligations on January 1, 2004. The application of this standard requires the recognition and measurement of liabilities associated with capital assets. The standard recognizes a liability equal to the discounted fair value of the obligation in the period in which the asset is recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value with the passage of time. This standard requires management to estimate the timing and future costs to settle liabilities.
Legal, Environmental Remediation and Other Contingent Matters
-------------------------------------------------------------
NAL is required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. NAL's management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstance.
Income Tax Accounting
---------------------
The determination of NAL's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessments after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.
Changes in Accounting Policies
------------------------------
There were no new accounting policies adopted during the nine months ended September 30, 2005.
Dated November 9, 2005
Consolidated Balance Sheets
(thousands of dollars)
-----------------------
As at As at
September December
30, 2005 31, 2004
(unaudited) (audited)
------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $3,876 $1,111
Accounts receivable and other 53,608 19,709
------------------------------------------------------------------
57,484 20,820
Reclamation reserve 3,760 3,434
Future income tax asset 3,371 4,676
Property, plant and equipment, net
(Notes 1 and 2) 756,806 386,715
------------------------------------------------------------------
$821,421 $415,645
------------------------------------------------------------------
------------------------------------------------------------------
Liabilities and
Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $21,536 $15,494
Distributions payable to unitholders 11,656 8,490
Current portion of long-term debt - 23,425
------------------------------------------------------------------
33,192 47,409
Long-term debt (Note 4) 238,800 70,275
Asset retirement obligations (Note 3) 61,450 36,924
------------------------------------------------------------------
333,442 154,608
Unitholders' equity
Unitholders' capital (Note 5) 735,894 476,620
Accumulated income 243,019 175,258
Accumulated distributions (490,934) (390,841)
------------------------------------------------------------------
487,979 261,037
------------------------------------------------------------------
Commitments (Note 7)
------------------------------------------------------------------
$821,421 $415,645
------------------------------------------------------------------
Units outstanding 72,847,451 53,064,140
------------------------------------------------------------------
------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Income and Accumulated Income
(thousands of dollars, except per unit amounts) (unaudited)
----------------------------------------------
Quarter Quarter 9 Months 9 Months
Ended Ended Ended Ended
September September September September
30, 2005 30, 2004 30, 2005 30, 2004
-------------------------------------------------------------------------
Revenue
Oil, natural gas and
liquids sales(1) $108,958 $56,724 $275,152 $158,871
Transportation costs (780) (384) (2,116) (1,051)
Royalty and other income 1,717 679 4,151 1,641
Crown royalties, net of
ARTC (18,496) (10,197) (45,068) (28,562)
Freehold and other
royalties (6,566) (2,833) (15,872) (7,696)
-------------------------------------------------------------------------
84,833 43,989 216,247 123,203
-------------------------------------------------------------------------
Expenses
Operating 15,511 8,224 37,915 22,288
General and administrative 817 1,845 7,033 5,383
Management fees 2,162 2,082 5,674 5,912
Interest on long-term debt 2,823 932 7,721 3,014
Depletion, depreciation and
amortization 30,663 16,875 85,353 51,125
Accretion on asset
retirement obligations 1,184 701 3,385 2,100
-------------------------------------------------------------------------
53,160 30,659 147,081 89,822
-------------------------------------------------------------------------
Income before taxes 31,673 13,330 69,166 33,381
Income and capital taxes 26 (97) (100) (357)
Future income tax recovery
(provision) 11 46 (1,305) 89
-------------------------------------------------------------------------
Net income 31,710 13,279 67,761 33,113
Accumulated income,
beginning of period 211,309 150,225 175,258 130,391
-------------------------------------------------------------------------
Accumulated income, end of
period $243,019 $163,504 $243,019 $163,504
-------------------------------------------------------------------------
Net income per trust unit $0.44 $0.25 $0.99 $0.64
-------------------------------------------------------------------------
Weighted average units
outstanding 72,345,238 52,494,452 68,770,046 51,645,169
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of hedging
See accompanying notes
Consolidated Statements of Cash Flows
(thousands of dollars) (unaudited)
----------------------------------------------
Quarter Quarter 9 Months 9 Months
Ended Ended Ended Ended
September September September September
30, 2005 30, 2004 30, 2005 30, 2004
-------------------------------------------------------------------------
Operating activities
Net income $31,710 $13,279 $67,761 $33,113
Items not involving cash:
Depletion, depreciation
and amortization 30,663 16,875 85,353 51,125
Accretion on asset
retirement obligations 1,184 701 3,385 2,100
Future income tax
provision (recovery) (11) (46) 1,305 (89)
-------------------------------------------------------------------------
Funds from operations 63,546 30,809 157,804 86,249
Abandonment and
environmental expenditures (1,104) (363) (1,992) (911)
Decrease (increase) in
non-cash working capital (19,848) 139 (35,719) 3,396
-------------------------------------------------------------------------
42,594 30,585 120,093 88,734
-------------------------------------------------------------------------
Financing Activities
Distributions to
unitholders (34,635) (24,084) (96,927) (70,066)
Issue of trust units, net
of issue costs 15,876 9,937 259,274 25,922
Advances from (repayment
of) long-term debt (11,300) (5,300) 145,100 (11,300)
-------------------------------------------------------------------------
(30,059) (19,447) 307,447 (55,444)
-------------------------------------------------------------------------
Investing Activities
Business acquisition - (181) (384,994) (1,014)
Investment in property,
plant and equipment (28,961) (16,367) (47,077) (30,645)
Proceeds from dispositions - - - 934
Reclamation reserve (72) (100) (326) (321)
Decrease (increase) in
non-cash working capital 13,232 4,623 7,622 (2,602)
--------------------------------------------------------------------------
(15,801) (12,025) (424,775) (33,648)
-------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (3,266) (887) 2,765 (358)
Cash and cash equivalents,
beginning of period 7,142 1,103 1,111 574
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $3,876 $216 $3,876 $216
-------------------------------------------------------------------------
Supplementary disclosure of
cash flow information:
Cash paid during the
period for:
Interest $2,799 $909 $7,666 $2,936
Taxes $(26) $97 $100 $357
-------------------------------------------------------------------------
See accompanying notes
Notes to Interim Consolidated Financial Statements
Three and Nine Months Ended September 30, 2005
(Tabular amounts in thousands of dollars, except per unit amounts)
(Unaudited)
Management prepared the interim consolidated financial statements of
NAL Oil and 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, 2004. 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, 2004.
1. Business Combination
--------------------
Effective February 10, 2005 the Trust acquired all of the issued and
outstanding shares of Addison Energy Inc. ("Addison") for
consideration of $389.4 million. The Addison acquisition was
accounted for using the purchase method of accounting with the
results of operations being included from the date of the
acquisition. The following table summarizes the allocation of the
purchase price to the net assets of Addison.
-------------------------------------------
Purchase allocation of Addison
-------------------------------------------
Cash $387,492
Related fees and expenses 1,871
-------------------------------------------
Cost of acquisition $389,363
-------------------------------------------
-------------------------------------------
Cash $4,369
Working capital deficiency (257)
Asset retirement obligations (22,974)
Property, plant and equipment 408,225
-------------------------------------------
Total consideration $389,363
-------------------------------------------
-------------------------------------------
The fair value of property, plant and equipment and asset retirement
obligations reflects the Trust's 70 percent remaining interest in the
Addison properties following the disposal of a 30 percent interest to
Manulife Financial Corporation ("MFC"). The Trust received
$165 million in cash from MFC, which has been offset against the cost
of the acquisition in the above purchase equation.
The above amounts are estimates made by management based on currently
available information. Amendments may be made to the purchase
equation as the cost estimates and tax balances are finalized.
2. Property, Plant and Equipment
-----------------------------
Net book value as at:
September December
30, 2005 31, 2004
---------------------------------------------------------------------
Oil and natural gas properties, at cost $1,141,178 $685,737
Less: Accumulated depletion and depreciation (384,372) (299,022)
---------------------------------------------------------------------
$756,806 $386,715
---------------------------------------------------------------------
During the nine months ended September 30, 2005 the Trust
capitalized $4.0 million (2004 - $1.4 million) of general and
administrative costs that were directly related to exploitation and
development programs.
3. Asset Retirement Obligations
----------------------------
NAL's asset retirement obligations result from net ownership
interests in oil and natural gas assets including well sites,
gathering systems and processing facilities. NAL estimates the total
undiscounted amount of cash flows required to settle its asset
retirement obligations is approximately $160.9 million that will be
incurred between 2005 and 2052. The majority of the costs will be
incurred between 2005 and 2020. A credit-adjusted risk-free rate of
8 percent was used to calculate the fair value of the asset
retirement obligations.
A reconciliation of the asset retirement obligations is provided
below.
September December September
30, 2005 31, 2004 30, 2004
---------------------------------------------------------------------
Balance, beginning of period $36,924 $34,914 $34,914
Accretion expense 3,385 2,821 2,100
Liabilities acquired (note 1) 22,974 - -
Liabilities incurred 159 887 1,174
Liabilities settled (1,992) (1,698) (911)
---------------------------------------------------------------------
Balance, end of period $61,450 $36,924 $37,277
---------------------------------------------------------------------
---------------------------------------------------------------------
4. Long-term Debt
--------------
The Trust has a revolving credit facility of $300 million. The credit
facility is fully secured by a floating debenture over the Trust's
assets and a general assignment of book debts. Amounts advanced under
the credit facility bear interest at the bank's prime rate or at
Bankers' Acceptance rates plus a stamping fee charge.
The credit facility will revolve until April 27, 2006 whereupon it
may be renewed for a further 364 days upon agreement between the
Trust and the bank. In the event that the credit facility is not
extended at the end of the 364-day period, it converts into a term
facility repayable in four equal installments commencing on the day
that is one year and one day immediately following the term out date.
The effective interest rate on the outstanding amounts at September
30, 2005 was approximately 4.5 percent.
5. Trust Units
-----------
Issued at:
September 30, 2005 December 31, 2004
--------------------------------------------
Units Amount Units Amount
---------------------------------------------------------------------
Balance, beginning of
period 53,064 $476,620 50,565 $448,683
Issued for cash 17,000 232,900 - -
Less: Issue expenses - (12,255) - -
Issued from Distribution
Reinvestment Plan 2,783 38,629 2,499 27,937
---------------------------------------------------------------------
Balance, end of period 72,847 $735,894 53,064 $476,620
---------------------------------------------------------------------
---------------------------------------------------------------------
6. Financial Instruments
---------------------
The Trust, from time to time, implements a price risk management
program whereby the commodity price associated with a portion of its
future production is fixed. The Trust sells forward a portion of its
future production through a combination of fixed-price sales
contracts with customers and commodity swap agreements with financial
counter parties. The forward and futures contracts are subject to
market risk from fluctuating commodity prices and exchange rates;
however, gains or losses on the contracts are offset by changes in
the value of the Trust's production.
As at September 30, 2005 the Trust had the following pricing
contracts in place:
Time Type of Daily Quantity
Year Period Commodity Contract Hedged Hedged Price
---------------------------------------------------------------------
2005 Apr-Dec Oil Financial 3,900 bbls Cdn$63.85
2005 Apr-Oct Natural gas Financial 17,000 GJ Cdn$6.95
The estimated fair value of the pricing contracts in place at
September 30, 2005, was an unrealized loss of $6.9 million. This
value was based on the difference between the respective financial
contract price and the market-based forward-pricing curve of the
related commodity as at September 30, 2005.
7. Commitments
-----------
NAL enters into many contract obligations as part of conducting
day-to day business. NAL has the following long-term commitments for
the years indicated:
($000's) 2005 2006 2007 2008 2009
---------------------------------------------------------------------
Office lease(1) 558 2,238 1,765 - -
Transportation Agreement(2) 218 70 - - -
(1) Represents the full amount of the office lease, both base rent
and operating costs, held by the Manager of which NAL is
allocated a pro rata share of the expense on a monthly basis.
Included in office lease is a $1.5 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) Includes transportation commitments associated with the Addison
Energy acquisition.
Forward-Looking Statements
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 personnel or management, fluctuations in foreign exchange or interest rates, stock market volatility and market valuations of companies with respect to announced transactions and the final valuations thereof, and obtaining required approval of 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.
Trading Performance
For the
Quarter
Ended 30-Sept-05 30-Jun-05 31-Mar-05 31-Dec-04 30-Sep-04
-------------------------------------------------------------------------
PRICE
High $17.80 $14.98 $14.69 $15.29 $14.29
Low $14.31 $13.13 $12.82 $12.60 $11.68
Close $15.95 $14.25 $13.80 $13.55 $14.29
Volume 18,992,928 12,790,674 23,391,175 15,265,465 9,359,852
Conference call
---------------
At 9:00 a.m. MST on Thursday, November 10, 2005 NAL will conduct a conference call to discuss its third 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 1-800-865-0780. Those who are unable to listen to the call live may listen to a recording of it by calling 1-800-633-8284, reservation No. 21268579. The recording will be available until November 20, 2005.
We appreciate your interest in NAL Oil and Gas Trust and look forward to your participation in our conference call.
Contact Information:
NAL Oil and Gas Trust
Andrew B. Wiswell
President and CEO
(403) 294-3636
NAL Oil and Gas Trust
Murielle J. Fisette
Assistant Corporate Secretary
(403) 294-3637 or Toll Free: (888) 223-8792
Fax: (403) 294-3699
Email: Investor.Relations@nal.ca
Website: www.nal.ca
