NAL Oil & Gas Trust Reports Record Second Quarter Results
CALGARY--(CCNMatthews - Aug. 8) - NAL Oil & Gas Trust (TSX:NAE.UN) (the "Trust" or "NAL") today announced its financial and operational results for the second quarter of 2005. All amounts are in Canadian dollars unless otherwise stated.
Second Quarter Highlights
- The Trust produced 18,349 barrels of oil equivalent per day (boed(1)), a 38 percent increase over the second quarter of 2004
- Funds available for distribution were $49.7 million, an increase of 75 percent compared with $28.4 million for the second quarter of 2004. On a per unit weighted average basis, funds available for distribution were $0.70, up 27 percent from the same period in 2004.
- Distributions paid totaled $0.48 per Trust unit, an increase of 7 percent year-over-year, providing an annualized cash-on-cash yield of 13 percent based on a quarter-end closing price of $14.25. Payout
ratio was 70% for the first 6 months of 2005, compared with 85% a year earlier.
- Subsequent to the Addison acquisition, in March 2005, the Trust hedged approximately 50 percent of total net daily oil production at a fixed price of Cdn$63.85 per barrel (bbl) for the period April 1, 2005 to December 31, 2005 and a similar percentage of natural gas at Cdn$6.95 per Gigajoule (Cdn$7.30 per Mcf) for the period April 1, 2005 to October 31, 2005.
- Temporarily reinstated the Premium Distribution Component of our Distribution Reinvestment Plan to fund repayment of Debt and capital expenditures, resulting in an additional funding of approximately $5 million per month. This Premium DRIP program plus strong operational cash flows will reduce our net debt levels to one times cash flow.
- Received the Canadian Association of Petroleum Producers 2005 Stewardship of Excellence Award, in the Health and Safety Performance category, for NAL's improved Safety Management System.
- Announced the appointment of Mr. Andrew Wiswell as President and Chief Executive Officer effective May 31, 2005, the date of Mr. Donald P. Driscoll's retirement.
(1) When converting natural gas to equivalent barrels of oil within this report, NAL uses the widely recognized standard of 6 thousand cubic feet (Mcf) to one barrel of oil equivalent (boe). However, boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
President's Message
In my first President's message to you, let me say that I am excited and honored to have the opportunity to lead NAL into its next phase of growth.
NAL truly has some unique attributes that have driven performance in the past and positions it to continue to deliver in the future. These attributes include a competitive track record of delivering consistent returns, strong technical teams driving operating performance, a conservative balance sheet and financial management attitude, attractive internal investment opportunities and a positive relationship with Manulife.
As to our second quarter highlights, we have continued to generate record performance driven primarily by the Addison acquisition and strong commodity prices.
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Performance Highlights Quarter Quarter
Ended Ended
June 30, June 30,
2005 2004 % Change
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Production (boe/d) 18,349 13,259 +38
Average Oil Price (Cdn$/bbl) 57.94 43.48 +33
Average Natural Gas Price (Cdn$/Mcf) 7.99 7.12 +12
Funds from Operations ($ Millions) 50.2 28.8 +74
Distributions ($/unit) 0.48 0.45 +7
Payout Ratio (%) 69 82 -16
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We also substantially completed the integration of the Addison
acquisition and are actively working the properties.
For the six months ended June 30, 2005 NAL's performance follows a
similar trend.
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Performance Highlights 6 Months 6 Months
Ended Ended
June 30, June 30,
2005 2004 % Change
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Production (boed) 17,906 13,397 +34
Average Oil Price (Cdn$/bbl) 56.77 41.98 +35
Average Natural Gas Price (Cdn$/Mcf) 7.47 6.86 +9
Funds from Operations ($ Millions) 94.3 55.4 +70
Distributions ($/unit) 0.96 0.90 +7
Payout Ratio (%) 70 85 -18
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As to our operational highlights, wet weather delayed drilling and tie in activities which deferred some of our capital program, especially in Central Alberta and SE Saskatchewan. Production levels were also affected by planned and unplanned turnarounds at facilities, as well as by the delay in closing of the Addison acquisition from February 1 to February 10, 2005. We are now very active in our operations early in Q3 and expect strong activity for the balance of 2005. Areas to highlight include our 30-well Brent Second White Specks program, initiating the 18-well Horseshoe Canyon coalbed methane project at Nevis and executing a new 3D seismic program at Westward Ho on the Addison lands, scheduled to be completed in Q3, 2005.
We are particularly proud of our Health and Safety performance, which has been a focus of our operating groups for some time. We were recognized by the Industry by receiving the Canadian Association of Petroleum Producers 2005 Stewardship of Excellence Award for Health and Safety performance. This award acknowledges NAL's work since 2000 improving our safety management system as well as our demonstrated long-term and substantive performance improvements.
As we look forward, our Board and Management Team will continue to build our strategic direction and plan around four key elements:
- Consistent volume growth
- Strong operational performance
- Conservative financial management
- Growing organizational capabilities
As to the outlook for the balance of 2005, we are forecasting high levels of activity in all areas of our operations. We expect to complete a capital program in the $65-70 million range, consistent with 2005 budget of $68 million. This capital spending will focus on drilling and completion in our core areas and over 80% of the program is focused on operated properties where equipment has been committed to deliver the program. Overall production levels are expected to build on an exit rate of 19,000 boed at the end of Q2, 2005 to average 18,500 - 19,000 boed for full year 2005. Operating costs are expected to remain at below Industry averages over the course of 2005.
We look forward to delivering consistent and sustained overall performance for our unitholders.
Sincerely,
Andrew Wiswell
President and Chief Executive Officer
Financial and Operating Highlights
(thousands of dollars, except per unit and boe data)
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3 Months 3 Months 3 Months 6 Months 6 Months
Ended Ended Ended Ended Ended
June 30, March 31, June 30, June 30, June 30,
FINANCIAL 2005 2005 2004 2005 2004
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Gross revenue,
net of royalties
and transportation $70,797 $60,617 $40,674 $131,414 $79,214
Net income 20,804 15,247 10,871 36,051 19,834
Funds from Operations
Deduct: 50,237 44,021 28,789 94,258 55,440
Contributions
to reclamation
reserve (157) (97) (94) (254) (221)
Actual abandonment
and environmental
costs (356) (532) (308) (888) (548)
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Funds available for
distribution before: 49,724 43,392 28,387 93,116 54,671
Funds applied to
debt and capital (15,462) (12,366) (5,086) (27,828) (8,464)
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Distributions
declared 34,262 31,026 23,301 65,288 46,207
Distributions
declared per unit 0.48 0.48 0.45 0.96 0.90
Debt repayment and
capital per unit 0.22 0.20 0.10 0.42 0.17
Total assets $820,166 $830,463 $423,901 $820,166 $423,901
Long-term debt, net
of working capital 229,005 249,740 86,767 229,005 86,767
Unitholders' equity 475,198 472,759 274,238 475,198 274,238
Costs per boe (6:1):
Operating $ 7.14 $ 6.67 $ 5.79 $ 6.91 5.77
General and
administrative 2.31 1.51 1.48 1.92 1.45
Management fees 1.17 0.99 1.63 1.08 1.57
OPERATING
Daily production
Oil (bbl) 9,197 9,206 8,205 9,202 8,254
Natural gas (Mcf) 43,254 41,575 26,254 42,419 26,563
Natural gas
liquids (bbl) 1,943 1,322 678 1,635 716
Oil equivalent
(boe - 6:1) 18,349 17,457 13,259 17,906 13,397
Average pricing,
net of
transportation
charges
Liquids:
WTI (US$/bbl) 53.18 49.90 38.33 51.89 36.74
NAL average oil
(Cdn$/bbl) 57.94 55.59 43.48 56.77 41.98
Natural gas
liquids
(Cdn$/bbl) 45.84 40.29 34.44 43.60 34.23
Natural gas:
AECO (Cdn$/Mcf) 7.32 6.69 6.80 7.10 6.70
Natural gas
Western Canada
(Cdn$/Mcf) 7.87 6.76 6.81 7.33 6.57
Natural gas
Lake Erie
(Cdn$/Mcf) 9.14 8.50 8.50 8.82 8.25
NAL average
natural gas
(Cdn$/Mcf) 7.99 6.93 7.12 7.47 6.86
Oil equivalent
(Cdn$/boe- 6:1) 52.67 48.86 43.15 50.87 41.62
Average foreign
exchange rate
Cdn$/US$ 1.2435 1.2266 1.3597 1.2348 1.3386
Operating
netback ($/boe) 34.45 31.23 27.48 32.88 26.32
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Management's Discussion and Analysis
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Please read Management's Discussion and Analysis (MD&A) in conjunction with the unaudited interim consolidated financial statements for the three and six months ended June 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 second quarter rose to $49.7 million or $0.70 per unit, compared with $28.4 million or $0.55 per unit for the same three-month period in 2004. A 23 percent rise in oil equivalent commodity pricing, combined with a 38 percent increase in production, drove the year-over-year increase. Distributions declared per unit increased by $0.03 from $0.45 to $0.48 per unit, an increase of 7 percent. Weighted average units outstanding increased by 38 percent, primarily due to the Addison acquisition.
For the six-month period ended June 30, 2005, funds available for distribution were $93.1 million, an increase of 70 percent over the similar period in 2004. This increase in funds available drove higher distributable income per unit, which increased by 30 percent to $1.39 per unit versus $1.07 per unit in the previous year.
Unitholders' Distributions
(thousands of dollars, except per unit amounts) (unaudited)
------------------------------------------------
3 Months 3 Months 6 Months 6 Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
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Funds from operations $50,237 $28,789 $94,258 $55,440
Deduct:
Contributions to
reclamation reserve (157) (94) (254) (221)
Actual abandonment
costs (356) (308) (888) (548)
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Funds available for
distribution before: 49,724 28,387 93,116 54,671
Funds applied to
debt repayment
and capital (15,462) (5,086) (27,828) (8,464)
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Distributions declared $34,262 $23,301 $65,288 $46,207
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Distributable
income per unit(1) $ 0.70 $ 0.55 $ 1.39 $ 1.07
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Distributions
declared per unit $ 0.48 $ 0.45 $ 0.96 $ 0.90
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Weighted average
units outstanding 71,187,715 51,638,256 66,952,822 51,215,861
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(1) Based on weighted average units outstanding
Production
During the second quarter, the Trust's output averaged 18,349 boed, up from 13,259 boed recorded in the second quarter of 2004 and up 5 percent from 17,457 boed in the prior quarter. The increase is primarily in natural gas production and is a result of the February 2005 acquisition of Addison Energy Inc. Natural declines and a high level of plant maintenance turnaround activity partially offset the production gains from development activity during the quarter. Turnarounds at Brent, Joffre, Westward Ho, Nottingham, Weyburn and Morpeth reduced average production during the quarter by approximately 600 boed. Wet weather conditions in Central Alberta and Southeast Saskatchewan impacted production by delaying drilling and tie-in activities.
For the six months ended June 30, 2005 production trends are consistent with Q2 results, with daily production higher by 34 percent.
Daily Production Volumes
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Oil (bbl/d) 9,197 8,205 12 9,202 8,254 11
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Natural gas
(Mcf/d) 43,254 26,254 65 42,419 26,563 60
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NGL (bbl/d) 1,943 678 186 1,635 716 128
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Oil equivalent
(boed) 18,349 13,259 38 17,906 13,397 34
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Commodity Prices
Crude Oil and Natural Gas Liquids (NGLs)
----------------------------------------
Throughout the second quarter, world oil prices remained strong. WTI benchmark crude averaged US$53.18/bbl during this period, up 39 percent from US$38.33 a year ago and 7 percent higher than US$49.90 in the first quarter of 2005. NAL's oil price per barrel averaged $57.94, up 33 percent from the prior year period and 4 percent higher than the previous quarter. A 9 percent increase in the Canadian dollar partially offset the rise in year-over-year oil pricing. Hedging contracts in place during the three months ended June 30, 2005 negatively affected NAL's second quarter realized crude price by $(0.95)/bbl or $(0.8) million in aggregate.
Year-over-year, the price per barrel of Natural Gas Liquids rose by 33 percent to $45.84/bbl compared to $34.44 in the second quarter, 2004. Compared to the first quarter of 2005, the Natural Gas Liquids price increased by 14 percent.
For the six-month period ended June 30, 2005 the average oil price of $56.77/bbl was 35 percent higher than the $41.98/bbl price realized a year earlier. The aggregate hedging impact for the six months is the same as outlined in Q2, 2005 as there were no hedges in place in Q1, 2005.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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NAL average oil
(Cdn$/bbl) 57.94 43.48 33 56.77 41.98 35
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NAL average
natural gas
(Cdn$/Mcf) 7.99 7.12 12 7.47 6.86 9
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NGL (Cdn$/bbl) 45.84 34.44 33 43.60 34.23 27
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Oil equivalent
(Cdn$/boe) 52.67 43.15 22 50.87 41.62 22
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Natural Gas
-----------
Western Canadian average natural gas prices were 16 percent higher compared to the same quarter in 2004. The AECO reference price averaged $7.32/Mcf in the second quarter of 2005, compared with $6.80/Mcf in the comparable period of 2004. Second quarter 2005 natural gas prices were up 16 percent versus the first quarter of 2005, when the AECO monthly index price averaged $6.69/Mcf.
Natural gas from our Lake Erie production was sold at $9.14/Mcf in the second quarter, up from $8.50/Mcf a year ago and up 8 percent from the first 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 second quarter natural gas price, net of transportation costs, of $7.99/Mcf, up 12 percent from the $7.12/Mcf reported in the same period last year and up 15 percent compared to the first quarter, 2005. Hedging contracts in place during the three months ended June 30, 2005 negatively affected the realized natural gas price by $(0.02)/Mcf or $(0.1) million in aggregate.
For the six-month period ended June 30, 2005 the overall natural gas price realized was $7.47/Mcf, a 9 percent increase over the $6.86/Mcf price a year earlier. The aggregate hedging effect for the six-month period is the same as outlined in Q2, 2005 as there were no hedges in place for Q1, 2005.
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 at the time of the Addison acquisition when higher than normal bank debt was put in place. 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 50
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Natural
2005 Apr - Oct Gas Financial 17,000 GJ Cdn$6.95/GJ 50
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The estimated fair value of the pricing contracts in place at June 30, 2005 was an unrealized loss of $5.5 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 June 30, 2005. To date, NAL has no hedges in place for 2006.
Revenue and Funds from Operations
Gross revenue, net of transportation charges(1), from oil, natural gas and natural gas liquids sales totaled $88 million in the three months ended June 30, 2005 - a 69 percent increase over the same period last year. A 38 percent rise in quarterly production driven primarily by the Addison Acquisition and a 22 percent increase in oil equivalent pricing were the major contributing factors. Funds from operations tracked revenues, up 70 percent over last year's second quarter and 2005 year-to-date cash flows exceeded 2004 totals by 68 percent.
For the six-month period ended June 30, 2005, similar increases in
revenues (62 percent) and funds from operations (75 percent) were experienced.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Revenue(1)
($000s) 88,090 52,060 69 164,858 101,480 62
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$/boe 52.76 43.15 22 50.87 41.62 22
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(1) Oil, natural gas and liquids sales less transportation costs and
hedging
Net Income
Net income for the three months ended June 30, 2005 was $20.8 million, $9.9 million higher than the $10.9 million recorded in the second quarter of 2004. This higher net income was driven by higher production and commodity prices, partially offset by somewhat higher royalties, depletion, operating costs, and a provision for future income taxes.
Net income for the six months ended June 30, 2005 increased by 82 percent, based on similar drivers.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Net income
($000s) 20,804 10,871 91 36,051 19,834 82
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As % of
revenue(1) 23.6 20.9 13 21.9 19.5 12
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$/boe 12.46 9.01 38 11.12 8.13 36
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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 $18.7 million for the three months ended June 30, 2005. Expressed as a percentage of gross sales, before hedging and transportation costs, the net royalty rate was 20.8 percent for the quarter. Overall royalty rates continued to benefit from favorable royalty treatment on certain Saskatchewan production.
Similar trends in royalties were experienced in the six-month period ended June 30, 2005.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Net royalties
($000s) 18,651 11,926 56 35,878 23,228 54
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As % of
revenue(1) 20.8 21.5 (3) 21.5 21.7 0
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$/boe 11.17 9.88 13 11.07 9.53 16
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(1) Oil, natural gas, and liquids sales
Operating Costs
Production expenses per boe for the second quarter of 2005 were up 23 percent over the second quarter of 2004, averaging $7.14 compared with $5.79 in Q2 2004. Approximately $0.40 - 0.45 per barrel were attributed to the higher operating costs of the gas focused Addison acquisition. As compared to the first quarter, operating costs increased due to the high level of turnaround activity (facility maintenance), driving expenses higher and curtailing production, and a full quarter of higher cost Addison production. Strong demand for services and equipment due to industry activity levels also exerted upward pressure on field operating costs when comparing year-over-year results. Overall, for the six months ended June 30, operating costs were $6.91 which compares favorably to other Industry players.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Operating costs
($000s) 11,917 6,985 71 22,404 14,064 59
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As % of revenue 13.5 13.3 2 13.6 13.8 (1)
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$/boe 7.14 5.79 23 6.91 5.77 20
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Operating Netback
NAL's operating netback for the second quarter was $34.45 per boe, up 25 percent from the $27.48 recorded in the same period a year ago. Record high crude oil pricing led to a 22 percent increase in oil equivalent pricing. This increase was partially offset by higher operating costs. In addition, the benefit of higher crude prices was moderated by the strengthening Canadian dollar, which on average was 9 percent higher in the second quarter of 2005.
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($/boe) 3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Revenue,
net of
transportation
costs 53.27 45.72 17 51.13 43.59 17
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Hedging effect (0.51) (2.57) (80) (0.27) (1.97) 86
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Royalties, net (11.17) (9.88) (13) (11.07) (9.53) (16)
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Operating
expenses (7.14) (5.79) 23 (6.91) (5.77) 20
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Operating
netback 34.45 27.48 25 32.88 26.32 25
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General & Administrative (G&A)
G&A costs for the three months ended June 30, 2005 averaged $2.31 per boe, up from $1.48 per boe recorded in the same period last year and up considerably from the $1.51 per boe charged in the prior quarter. The first quarter 2005 G&A costs were lower than normal as a result of the reversal of an over-accrual of G&A costs attributable to 2004. For the second quarter, the higher year-over-year G&A costs per boe reflect the increased costs resulting from higher staffing levels as well as greater regulatory governance, control, and public company compliance requirements. Also contributing to increased G&A costs are higher costs for consulting and other support services that are in great demand in the current energy industry environment.
For the six-month period ended June 30, 2005 G&A costs averaged $1.92 per boe, up 32 percent compared to the equivalent period in 2004.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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G&A costs
($000s) 3,850 1,785 116 6,216 3,538 76
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As % of revenue 4.4 3.4 29 3.8 3.5 9
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$/boe 2.31 1.48 56 1.92 1.45 32
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Per Trust
unit ($) 0.05 0.03 67 0.09 0.07 29
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Management Fees
Base management fees for the three months ended June 30, 2005 amounted to $2.0 million, comparable to the same period last year. These 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 second quarter performance, which did not exceed that of its peers based on the S&P/TSX Capped Energy Trust Index (the "Index"). NAL's total return for the three months ended June 30, 2005 was 6.7 percent compared with an 8.6 percent return for the Index. Total year-to-date management fees were $3.5 million or $1.08 per boe in 2005, compared with $3.8 million or $1.57 per boe for the same period in 2004.
For the six-month period ended June 30, 2005, management fees are down 8 percent due primarily to no performance fee being payable during the period.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Management
fees ($000s) 1,958 1,972 (1) 3,512 3,830 (8)
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As % of revenue 2.2 3.8 (42) 2.1 3.7 (43)
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$/boe 1.17 1.63 (28) 1.08 1.57 31
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Per trust
unit ($) 0.03 0.04 (25) 0.05 0.07 28
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Interest
Interest expense for the quarter ended June 30, 2005 was $2.8 million. Year-over-year second quarter interest charges increased by $1.8 million due to a higher average debt load after the February 10, 2005 Addison acquisition.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Interest
($000s) 2,790 968 188 4,898 2,082 135
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Depletion, Depreciation and Accretion
In the second 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. Second quarter depletion and accretion charges amounted to $29.4 million in 2005 compared with $17.7 million for 2004. Per boe, depletion rose 20 percent to $17.63 in the second quarter from $14.68 a year ago.
For the six months ended June 30, 2005 depletion and accretion expenses were $56.9 million compared to $35.6 million for the same period in 2004. On per barrel basis, depletion and accretion rose 19% to $17.55 compared to $14.70 in the previous 6 month period, primarily due to Addison acquisition.
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3 Months Ended June 30 6 Months Ended June 30
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2005 2004 % Change 2005 2004 % Change
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Depletion and
accretion
($000s) 29,445 17,708 66 56,891 35,649 60
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Capital Resources and Liquidity
The capital structure of the Trust is comprised of trust units and debt.
As at June 30, 2005 NAL had 71,784,825 units outstanding - 18,720,685 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: As at August 8, 2005, there were 72,179,972 units outstanding(1). The DRIP generated net proceeds of $15.9 million in the second quarter. The proceeds were used to fund existing capital programs and to reduce debt.
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.
(1) Includes July DRIP
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($000s) June 30, December 31, June 30,
2005 2004 2004
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Trust unit equity 475,198 261,037 274,238
Long-term debt 250,100 93,700 97,500
Debt to equity 0.53 0.36 0.36
Net debt(1) 229,005 96,864 86,767
Net debt to trailing
12-month cash flow(2) 1.20 0.84 0.78
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(1) Net debt is long-term debt net of working capital.
(2) Determination of second quarter 2005 ratio based on an annualized
June 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:
($000s)
2005 2006 2007 2008 2009
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Office lease(1) 1,088 2,238 1,765 - -
Transportation Agreement(2) 441 49 - - -
(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 $1.8 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 second quarter of 2005 amounted to $10.5 million compared with $7.0 million a year ago. In the second quarter, NAL spent $6 million on development drilling, $4 million on facilities and equipment, and $0.5 million on geological and geophysical and other corporate assets. In addition, in the three months ended June 30, 2005 NAL made no expenditures on the purchase of minor land interests compared to $0.4 million in 2004.
Effective February 10, 2005 NAL completed a corporate acquisition of Addison Energy Inc. resulting in the acquisition of assets in Alberta for $385 million dollars after purchase-price adjustments. For further details of the Addison transaction see Note 1 to the financial statements.
For the six months ended June 30, 2005 capital expenditures totaled $18.1 million allocated - $11.5 million to development drilling, $5.2 million to facilities and equipment, and $1.4 million to geological and geophysical and other assets.
Other than some delay in our drilling and tie in activities, we continue to generate results as anticipated for our overall program and remain positive about the operations acquired in the Addison transaction.
Development Activities
During the second quarter, the Trust participated in a total of 34 (12.12 net) wells with a 97 percent success rate (96% net).
A total of 10 wells (4.02 net) were drilled in Southeast Saskatchewan during the quarter. At Alida, two (0.90 net) horizontal oil wells were brought on production late in the quarter. At Elswick, one (0.13 net) well was drilled and five (1.00 net) horizontal oil wells, drilled during the previous quarter, were brought on production. At Browning, two (1.00 net) horizontal oil wells are on production and one (0.5 net) horizontal oil well is on production at both Lost Horse Hills and Steelman.
In Central Alberta, activity commenced on the land acquired from Addison Energy by drilling ten (4.57 net) wells. Of these wells, two (0.97 net) marked the kick-off of an 18 (9.2 net) well Horseshoe Canyon coalbed methane project in the Nevis area. Six wells (2.30 net) targeted gas from the Edmonton Sands. Two (1.34 net) of these wells are on production at Wilson Creek and the remaining wells have been tested and are awaiting tie-in. Two (1.40 net) wells were drilled and cased for oil from the Buck Sandstone at Wilson Creek.
In East-Central Alberta, one (1.0 net) well was drilled and cased for Viking gas and two (1.10 net) gas wells, drilled during the previous quarter, were tied-in and are now producing from multiple horizons.
At Lake Erie, thirteen (2.54 net) gas wells were drilled during the quarter. Four (0.81 net) are on production and the remainder are currently being tested and tied-in.
Quarterly Information
---------------
Financial 2005 2004 2003
---------------------------------------------------------------
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
---------------------------------------------------------------
Revenue,
net of
royalties
and
transpor-
tation 70,797 60,617 43,110 43,989 40,674 38,540 37,697 33,378
Per unit 0.99 0.97 0.81 0.84 0.79 0.76 0.75 0.79
Funds
from
oper-
ations 50,237 44,021 29,633 30,809 28,789 26,651 24,413 23,615
Per unit 0.71 0.69 0.56 0.59 0.56 0.52 0.48 0.56
Distri-
butions
declared,
per unit 0.48 0.48 0.48 0.47 0.45 0.45 0.45 0.45
Net
income 20,804 15,247 11,754 13,279 10,871 8,963 3,252 8,701
Per unit 0.29 0.24 0.22 0.25 0.21 0.18 0.06 0.21
---------------------------------------------------------------
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 six months ended June 30, 2005.
Dated August 8, 2005
Consolidated Balance Sheets
(thousands of dollars)
------------------------
As at As at
June 30, December 31,
2005 2004
(unaudited) (audited)
------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $7,142 $1,111
Accounts receivable and other 45,495 19,709
------------------------------------------------------------------
52,637 20,820
Reclamation reserve 3,688 3,434
Future income tax asset 3,360 4,676
Property, plant and equipment, net
(Notes 1 and 2) 757,834 386,715
------------------------------------------------------------------
$817,519 $415,645
------------------------------------------------------------------
------------------------------------------------------------------
Liabilities and
Unitholders' Equity
Current liabilities
Accounts payable and accrued liabilities $20,056 $15,494
Distributions payable to Unitholders 11,486 8,490
Current portion of long-term debt - 23,425
------------------------------------------------------------------
31,542 47,409
Long-term debt (Note 4) 250,100 70,275
Asset retirement obligations (Note 3) 60,679 36,924
------------------------------------------------------------------
342,321 154,608
------------------------------------------------------------------
Unitholders' equity
Unitholders' capital (Note 5) 720,018 476,620
Accumulated income 211,309 175,258
Accumulated distributions (456,129) (390,841)
------------------------------------------------------------------
475,198 261,037
------------------------------------------------------------------
Commitments (Note 7)
------------------------------------------------------------------
------------------------------------------------------------------
$817,519 $415,645
------------------------------------------------------------------
------------------------------------------------------------------
Units outstanding 71,784,825 53,064,140
------------------------------------------------------------------
------------------------------------------------------------------
See accompanying notes
Consolidated Statements of Income and Accumulated Income
(thousands of dollars, except per unit amounts) (unaudited)
------------------------------------------------
Quarter Quarter 6 Months 6 Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
-------------------------------------------------------------------------
Revenue
Oil, natural gas
and liquids sales(1) $88,775 $52,389 $166,194 $102,147
Transportation costs (685) (329) (1,336) (667)
Royalty and other income 1,358 540 2,434 962
Crown royalties,
net of ARTC (13,842) (9,627) (26,572) (18,365)
Freehold and other
royalties (4,809) (2,299) (9,306) (4,863)
-------------------------------------------------------------------------
70,797 40,674 131,414 79,214
-------------------------------------------------------------------------
Expenses
Operating 11,917 6,985 22,404 14,064
General and administrative 3,850 1,785 6,216 3,538
Management fees 1,958 1,972 3,512 3,830
Interest on long-term debt 2,790 968 4,898 2,082
Depletion, depreciation
and amortization 28,267 17,007 54,690 34,250
Accretion on asset
retirement obligations 1,178 701 2,201 1,399
-------------------------------------------------------------------------
49,960 29,418 93,921 59,163
-------------------------------------------------------------------------
Income before taxes 20,837 11,256 37,493 20,051
Income and capital taxes (45) (175) (126) (260)
Future income tax
recovery (provision) 12 (210) (1,316) 43
-------------------------------------------------------------------------
Net income 20,804 10,871 36,051 19,834
Accumulated income,
beginning of period 190,505 139,354 175,258 130,391
-------------------------------------------------------------------------
Accumulated income,
end of period $211,309 $150,225 $211,309 $150,225
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net income per Trust unit $0.29 $0.21 $0.54 $0.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted average
units outstanding 71,187,715 51,638,256 66,952,822 51,215,861
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net of hedging
See accompanying notes
Consolidated Statements of Cash Flows
(thousands of dollars) (unaudited)
------------------------------------------------
Quarter Quarter 6 Months 6 Months
Ended Ended Ended Ended
June 30, June 30, June 30, June 30,
2005 2004 2005 2004
-------------------------------------------------------------------------
Operating activities
Net income $20,804 $10,871 $36,051 $19,834
Items not involving cash:
Depletion, depreciation
and amortization 28,267 17,007 54,690 34,250
Accretion on asset
retirement obligations 1,178 701 2,201 1,399
Future income tax
provision (recovery) (12) 210 1,316 (43)
-------------------------------------------------------------------------
Funds from operations 50,237 28,789 94,258 55,440
Abandonment and
environmental expenditures (356) (308) (888) (548)
Decrease (increase) in
non-cash working capital (8,609) (5,962) (15,871) 3,257
-------------------------------------------------------------------------
41,272 22,519 77,499 58,149
-------------------------------------------------------------------------
Financing Activities
Distributions to
Unitholders (34,068) (23,175) (62,292) (45,982)
Issue of Trust units,
net of issue costs 15,897 9,190 243,398 15,985
Advances from (repayment of)
long-term debt (9,500) (1,000) 156,400 (6,000)
Increase in non-cash
working capital (160) - - -
-------------------------------------------------------------------------
(27,831) (14,985) 337,506 (35,997)
-------------------------------------------------------------------------
Investing Activities
Business acquisition (1,837) (352) (384,984) (907)
Investment in property,
plant and equipment (10,624) (6,990) (18,116) (14,278)
Proceeds from dispositions - 88 - 1,008
Reclamation reserve (157) (94) (254) (221)
Decrease (increase) in
non-cash working capital 4,061 10 (5,610) (7,225)
-------------------------------------------------------------------------
(8,557) (7,338) (408,974) (21,623)
Increase in cash
and cash equivalents 4,884 196 6,031 529
Cash and cash equivalents,
beginning of period 2,258 907 1,111 574
-------------------------------------------------------------------------
Cash and cash equivalents,
end of period $7,142 $1,103 $7,142 $1,103
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary disclosure
of cash flow information:
Cash paid during the
period for:
Interest $2,771 $944 $4,867 $2,027
Taxes $45 $175 $126 $260
-------------------------------------------------------------------------
See accompanying notes
Notes to Interim Consolidated Financial Statements
Three and Six Months Ended June 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:
June 30, December 31,
2005 2004
---------------------------------------------------------------------
Oil and natural gas properties, at cost $1,111,543 $685,737
Less: Accumulated depletion and depreciation (353,709) (299,022)
---------------------------------------------------------------------
$757,834 $386,715
---------------------------------------------------------------------
---------------------------------------------------------------------
During the six months ended June 30, 2005 the Trust capitalized
$0.8 million (2004 - $0.4 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 $158.5 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:
---------------------------------------------------------------------
June 30, December 31, June 30,
2005 2004 2004
---------------------------------------------------------------------
Balance, beginning of period $36,924 $34,914 $34,914
Accretion expense 2,201 2,821 1,399
Liabilities incurred 22,442 887 170
Liabilities settled (888) (1,698) (548)
---------------------------------------------------------------------
Balance, end of period $60,679 $36,924 $35,935
---------------------------------------------------------------------
---------------------------------------------------------------------
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 June 30,
2005 was approximately 4.45 percent.
5. Trust Units
-----------
Issued at:
June 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 - (12,254)
Issued from Distribution
Reinvestment Plan 1,721 22,752 2,499 27,937
---------------------------------------------------------------------
Balance, end of period 71,785 $720,018 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 June 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
June 30, 2005 was an unrealized loss of $5.5 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 June 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:
($000s) 2005 2006 2007 2008 2009
---------------------------------------------------------------------
Office lease(1) 1,088 2,238 1,765 - -
Transportation Agreement(2) 441 49 - - -
(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 $1.8 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 there from.
Trading Performance
For the
Quarter Ended 30-Jun-05 31-Mar-05 31-Dec-04 30-Sep-04 30-Jun-04
-------------------------------------------------------------------------
PRICE
High $14.98 $14.69 $15.29 $14.29 $12.05
Low $13.13 $12.82 $12.60 $11.68 $11.05
Close $14.25 $13.80 $13.55 $14.29 $11.73
Volume 36,182,149 23,391,175 15,265,465 9,359,852 11,283,206
Contact Information:
NAL Oil & Gas Trust
Andrew B. Wiswell
President and CEO
(403) 294-3636
NAL Oil & Gas Trust
Kelsey Finley
(403) 294-3637 or Toll Free: (888) 223-8792
(403) 294-3699,
Email: Investor.Relations@nal.ca ,
Website: www.nal.ca
