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True Energy Trust Announces Second Quarter 2008 Financial Results Aug 7, 2008 5:25:00 PM
TSX: TUI.UN CALGARY, Aug. 7 /CNW/ - (TSX: TUI.UN) During the first half of 2008, True successfully implemented its new strategic direction. Focused on improving balance sheet strength while providing a consistent monthly distribution, the Trust is now positioned to efficiently execute a second half 2008 capital program of 28 net wells. Accomplishments during the first half of 2008 include:
<<
- In the first six months of 2008 True reduced its net debt by
approximately $62 million and the debt to funds flow from
operations* ratio to 1.8 times.
- As of June 30, 2008, True renewed its $152 million credit facility,
which extends to June 26, 2009.
- The Board announced a third quarter distribution policy of $0.04 per
unit per month consistent with the first and second quarter
distribution policy.
- For the six month period ended June 30, 2008 sales volumes averaged
12,737 boe/d. Second quarter 2008 sales volumes averaged 11,922 boe/d
with full year guidance remaining at 12,000 to 12,500 boe/d.
- True closed first half 2008 dispositions totalling $44.3 million of
net proceeds after adjustments and costs.
Highlights from the second quarter include:
- True's total net debt as at June 30, 2008, excluding commodity
contract liabilities, future income taxes and asset retirement
obligations, was $189.4 million. During the six month period ended
June 30, 2008, True has reduced its net debt by approximately
$62 million. As at June 30, 2008, the debt to funds flow from
operations* ratio, calculated based upon annualized second quarter
2008 funds flow from operations*, is 1.8 times.
- During the second quarter of 2008, True participated in 1 (0.4 net)
successful working interest natural gas well. True's planned second
half drilling program is underway with 4 gross (2.9 net) gas wells
drilled thus far in the third quarter of 2008. A further 25 net wells
are planned through the remainder of the year.
- During the second quarter of 2008, True closed on the sale of its
Dodsland-Stranraer property for net proceeds of $38.5 million, after
closing adjustments and costs.
- In the second quarter of 2008, monthly distributions of $0.04 per
unit were declared and paid on May 15, 2008, June 16, 2008 and
July 15, 2008. The Board has announced it has set a distribution
policy for the third quarter of 2008 at a monthly rate of $0.04 per
unit, subject to monthly confirmation, based on current commodity
prices, hedging program, anticipated production volumes and market
conditions. True anticipates its $0.04 per unit monthly distributions
to be sustainable in the current gas price, foreign exchange rate and
cost environment.
- True generated average sales volumes for the second quarter of 2008
of 11,922 boe/d as compared to 17,122 boe/d for the second quarter of
2007. For the six month period ended June 30, 2008, sales volumes
averaged 12,737 boe/d as compared to 17,788 boe/d for the same period
in 2007. Dispositions totalling approximately 1,000 boe/d were closed
during the first half of 2008. In addition to natural production
decline, field production was impacted approximately 150 boe/d by
third party maintenance and severe thunderstorm activity in the
second quarter of 2008. Full year 2008 field production guidance
remains at 12,000 to 12,500 boe/d.
- Funds flow from operations* for the second quarter of 2008 was
$26.3 million on gross sales of $82.1 million compared to funds flow
from operations of $34.2 million on gross sales of $75 million for
the same period in 2007. The decrease in funds flow for the 2008
second quarter was primarily the result of lower sales volumes and
higher realized hedging losses, partially offset by higher overall
commodity prices and operating netbacks for the period. Funds flow
from operations for the second quarter of 2008 increased 1% from
first quarter 2008 funds flow from operations of $24.3 million,
primarily reflecting further improved commodity prices.
- True maintains a commodity price risk management program to provide a
measure of stability to cash distributions and capital expenditures.
Unrealized mark-to-market gains or losses are non-cash adjustments to
the current fair market value of the contract over its entire term
and are included in the calculation of net income (loss).
- A net loss of $21.4 million for the second quarter of 2008 compared
to a net income of $1.7 million for the second quarter of 2007 was
primarily due to higher unrealized mark-to-market, non-cash, losses
on commodity price risk management contracts of $25.6 million. The
net loss for the six month period ended June 30, 2008 was
$40.0 million compared to $6.8 million for the same period in 2007.
- As of June 30, 2008, the credit facility was renewed and consists of
a $15 million demand operating facility provided by one Canadian bank
and a $137 million extendible revolving credit facility syndicated by
two Canadian chartered banks, a Canadian financial institution, one
institutional lender and a U.S. bank. The revolving period on the
revolving term credit facility ends on June 26, 2009, unless extended
for a further 364 day period. Should the facilities not be renewed
they convert to 366 day non-revolving facilities on the renewal date.
The borrowing base was renewed effective June 27, 2008 and is
currently scheduled for renewal on September 30, 2008. As at
June 30, 2008, there was approximately $26.0 million undrawn, net of
$0.5 million of prepaid interest, under these facilities.
* Refer to note (2) in the highlights section of the second quarter
report in respect of the term "funds flow from operations", which is
also commonly referred to as "cash flow from operations".
True's second quarter report is presented below.
HIGHLIGHTS
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
-------------------------------------------------------------------------
FINANCIAL (unaudited)
(CDN$000s except unit
and per unit amounts)
Revenue (before
royalties and
hedging(1)) 82,074 74,991 152,107 146,187
Funds flow from
operations(2) 26,304 34,192 50,537 64,180
Per basic trust
unit $ 0.33 $ 0.47 $ 0.64 $ 0.89
Per diluted trust
unit(5) $ 0.33 $ 0.45 $ 0.64 $ 0.88
Net income (loss) (21,374) 1,741 (39,995) (6,830)
Per basic trust
unit $ (0.27) $ 0.02 $ (0.50) $ (0.10)
Per diluted trust
unit (5) $ (0.27) $ 0.02 $ (0.50) $ (0.09)
Distributions
declared 9,505 18,376 19,012 35,242
Per unit $ 0.12 $ 0.24 $ 0.24 $ 0.48
-------------------------------------------------------------------------
Exploration and
development 3,654 15,116 12,107 60,769
Corporate and
property
acquisitions 426 649 623 1,354
-------------------------------------------------------------------------
Capital expenditures
- cash 4,080 15,765 12,730 62,123
Property dispositions
- cash (38,530) (9,026) (44,318) (27,469)
Corporate
acquisitions
and other
- non-cash (2,521) 311 (2,714) (313)
-------------------------------------------------------------------------
Total capital
expenditures - net (36,971) 7,050 (34,302) 34,341
-------------------------------------------------------------------------
Long-term debt 125,458 142,153 125,458 142,153
Convertible debentures 80,253 78,636 80,253 78,636
Working capital
deficiency (excess) (16,357) 256 (16,357) 256
-------------------------------------------------------------------------
Total net debt(3) 189,354 221,045 189,354 221,045
-------------------------------------------------------------------------
Total assets 793,883 941,122 793,883 941,122
Unitholders' equity 404,062 520,326 404,062 520,326
-------------------------------------------------------------------------
OPERATING
Daily sales volumes
Crude oil,
condensate
and NGLs (bbls/d) 4,170 5,546 4,506 6,007
Natural
gas (mcf/d) 46,515 69,455 49,383 70,686
Total oil
equivalent (boe/d) 11,922 17,122 12,737 17,788
Average prices
Crude oil,
condensate
and NGLs ($/bbl) 103.14 50.90 86.19 45.74
Crude oil,
condensate
and NGLs
(including
hedging(1)) ($/bbl) 82.56 50.14 71.50 46.71
Natural gas ($/mcf) 9.94 7.60 8.90 7.43
Natural gas
(including
hedging(1)) ($/mcf) 8.80 7.65 8.37 7.58
Total oil
equivalent ($/boe) 74.85 47.33 64.99 44.96
Total oil
equivalent
(including
hedging(1)) ($/boe) 63.22 47.25 57.76 45.90
Statistics
Operating
netback ($/boe) 42.66 26.79 35.54 25.53
Operating
netback
(including
hedging(1)) ($/boe) 31.01 26.71 28.30 26.47
Transpor-
tation ($/boe) 2.28 1.56 1.43 0.97
Production
expenses ($/boe) 14.90 12.69 14.31 10.79
General &
adminis-
trative ($/boe) 4.14 2.78 3.56 2.87
Royalties
as a % of
sales after
transpor-
tation 21% 14% 22% 17%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
-------------------------------------------------------------------------
TRUST UNITS
Trust units
outstanding 79,095,460 79,709,119 79,095,460 79,709,119
Trust unit incentive
rights outstanding 5,006,079 6,687,499 5,006,079 6,687,499
Units issuable for
exchangeable shares 347,254 309,216 347,254 309,216
Units issuable for
convertible
debentures 5,390,625 5,390,625 5,390,625 5,390,625
-------------------------------------------------------------------------
Diluted trust units
outstanding 89,839,418 92,296,459 89,839,418 92,296,459
Diluted weighted
average trust
units(5) 79,203,976 75,810,961 79,213,532 71,891,887
-------------------------------------------------------------------------
TRUST UNIT TRADING STATISTICS
(CDN$, except volumes) based
on intra-day trading
High 4.69 6.83 4.69 7.47
Low 3.54 5.71 2.94 4.87
Close 4.40 5.75 4.40 5.75
Average daily volume 266,304 438,393 261,833 520,700
-------------------------------------------------------------------------
(1) The Trust has entered into various commodity risk management
contracts which are considered to be economic hedges. Per unit
metrics after hedging includes only the realized portion of gains or
losses on commodity contracts.
Effective January 1, 2007 on adoption of CICA handbook sections 3855
and 3865, the Trust no longer applies hedge accounting to these
contracts. As such, these contracts are revalued to fair value at the
end of each reporting date. This results in recognition of unrealized
gains or losses over the term of these contracts which is reflected
each reporting period until these contracts are settled, at which
time realized gains or losses are recorded. These unrealized gains or
losses on commodity contracts are not included for purposes of per
unit metrics calculations disclosed.
(2) The highlights section contains the term "funds flow from
operations" (or as commonly referred to as "cash flow from
operations"), which should not be considered an alternative to, or
more meaningful than cash flow from operating activities as
determined in accordance with Canadian generally accepted accounting
principles ("GAAP") as an indicator of the Trust's performance.
Therefore reference to diluted funds flow from operations or funds
flow from operations per trust unit may not be comparable with the
calculation of similar measures for other entities. Management uses
funds flow from operations to analyze operating performance and
leverage and considers funds flow from operations to be a key measure
as it demonstrates the Trust's ability to generate the cash necessary
to fund future capital investments and to repay debt. The
reconciliation between funds flow from operations and cash flow from
operating activities can be found in the Management Discussion and
Analysis ("MD&A"). Funds flow from operations per trust unit is
calculated using the weighted average number of trust units for the
period.
(3) Net debt includes the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities and short-term
future income tax assets. Total net debt also includes the liability
component of convertible debentures and excludes asset retirement
obligations and the future income tax liability.
(4) Operating netbacks are calculated by subtracting royalties,
transportation, and operating costs from revenues.
(5) In computing weighted average diluted earnings per trust unit for the
three month period ended June 30, 2008 nil (2007: 2,320,716) trust
incentive units were added to the 79,203,976 (2007: 73,490,245)
weighted average number of trust units outstanding during the period
for the dilutive effect of exchangeable shares and convertible
debentures. A total of 5,006,079 (2007: 4,875,999) trust incentive
units, 347,254 (2007: nil) exchangeable shares and 5,390,625
(2007: 5,390,625) trust units issuable pursuant to the conversion of
convertible debentures were excluded from the calculation for the
three month period ended June 30, 2008 as they were not dilutive. To
calculate weighted average diluted funds flow from operations for the
three month period ended June 30, 2007, a total of $2.0 million for
interest accretion expense was added to the numerator and 5,390,625
trust units were added to the denominator for units issuable on
conversion of convertible debentures, resulting in diluted weighted
average trust units of 81,201,586 and funds flow from operations per
diluted unit of $0.45 under this calculation.
In computing weighted average diluted earnings per trust unit for the
six month period ended June 30, 2008 5,006,079 (2007: 6,887,499)
trust incentive units, 347,254 (2007: 309,216) exchangeable shares
and 5,390,625 (2007: 5,390,625) trust units issuable pursuant to the
conversion of convertible debentures were excluded from the
calculation for the six month period ended June 30, 2008 as they were
not dilutive. To calculate weighted average diluted funds flow from
operations for the six month period ended June 30, 2007, a total of
$4.0 million for interest accretion expense was added to the
numerator and 5,390,625 trust units were added to the denominator for
units issuable on conversion of convertible debentures, resulting in
diluted weighted average trust units of 77,591,728 and funds flow
from operations per diluted unit of $0.88 under this calculation.
REPORT TO UNITHOLDERS
>>
Improved commodity prices in the second quarter combined with the proceeds of our property disposition program have been utilized to reduce True's bank indebtedness and increase the Trust's financial flexibility. After concentrating on debt reduction in the first half of 2008, our focus for remainder of the year now shifts to the efficient execution of the capital program. Drilling has begun in West Central Alberta and True will soon move onto exciting projects such as the Viking Horizontal program in Kindersley and further exploration drilling with a view to expand our reserve and production base. Accomplishments for the second quarter ended June 30, 2008 include: Distributions In the second quarter of 2008, monthly distributions of $0.04 per unit were declared and paid on May 15, 2008, June 16, 2008 and July 15, 2008. On July 15, 2008, the Trust announced that the Board has set the distribution policy for the third quarter of 2008 at a monthly distribution rate of $0.04 per unit, subject to monthly confirmation by the Board of Directors, based on current commodity prices, hedging program, anticipated production volumes and market conditions. True anticipates its $0.04 per unit monthly distributions to be sustainable in the current gas price, foreign exchange rate and cost environment. Production 2008 second quarter sales volumes averaged 11,922 boe/d as compared to 17,122 boe/d for the same period in 2007. For the six month period ended June 30, 2008, sales volumes averaged 12,737 boe/d compared to 17,788 boe/d for the same period in 2008. Dispositions totalling approximately 1,000 boe/d were closed during the first half of 2008. In addition to natural production decline, field production was impacted approximately 150 boe/d by third party maintenance and severe thunderstorm activity in the second quarter of 2008. Full year 2008 field production guidance remains at 12,000 to 12,500 boe/d. Drilling During the second quarter of 2008, True participated in 1 (0.4 net) successful working interest natural gas well. True's planned second half drilling program is underway with 4 gross (2.9 net) gas wells drilled thus far in the third quarter of 2008. A further 25 net wells are planned through the remainder of the year including at least 3 horizontal Viking light oil wells in the Kindersley area, 1.5 vertical heavy oil wells at Mantario, and 18.5 natural gas wells in Alberta. A further 2 exploration wells are also scheduled. Kerrobert The Kerrobert SAGD project was adversely impacted by severe thunderstorm and lightning activity in June and July 2008. Electrical equipment issues impacted steam generation. Oil production rates were subsequently reduced to retain the steam chamber and ensure uniform heating and conformance. Repairs are largely complete and response to the ongoing reservoir heating continues to improve with temperatures of up to 200 degrees Celsius observed in 2 of the 4 new thermal producing wells as compared to initial reservoir temperatures of approximately 30 degrees Celsius. Financial Funds flow from operations for the second quarter of 2008 was $26.3 million on gross sales of $82.1 million compared to funds flow from operations of $34.2 million on gross sales of $75.0 million for the same period in 2007. The decrease in funds flow for the 2008 second quarter was primarily the result of lower sales volumes and higher realized hedging losses, offset significantly by improved commodity pricing and operating netbacks for 2008. Funds flow from operations for the second quarter of 2008 increased 1% from first quarter 2008 funds flow from operations of $24.3 million, primarily reflecting further improved commodity prices. Funds flow from operations for the six month period ended June 30, 2008 was $50.5 million on gross sales of $152.1 million compared to funds flow from operations of $64.2 million on gross sales of $146.2 million for the same period in 2007. True maintains a commodity price risk management program to provide a measure of stability to cash distributions and capital expenditures. Unrealized mark-to-market gains or losses are non-cash adjustments to the current fair market value of the contract over its entire term and are included in the calculation of net income (loss). A net loss of $21.4 million for the second quarter of 2008 compared to a net income of $1.7 million for the second quarter of 2007 was primarily due to higher unrealized mark-to-market, non-cash, losses on commodity price risk management contracts of $25.6 million. The net loss for the six month period ended June 30, 2008 was $40.0 million compared to $6.8 million for the same period in 2007. Dispositions On December 17, 2007, True announced its intention to divest of its Saskatchewan assets and reduce the distribution level as part of a new strategic direction for the Trust. Proceeds from the proposed divestiture would be utilized to reduce True's bank indebtedness and the reduced distribution level ensured additional financial resources. The additional cash flow generated through improved pricing has eased debt concerns and allowed the Trust to modify the path of the new strategic direction. On April 30, 2008 True announced that the sale of the Dodsland-Stranraer asset, one of five asset packages comprising the Saskatchewan divestiture program, had been successfully completed for net proceeds after adjustments and closing costs of $38.5 million. True further announced its decision to not pursue further Saskatchewan asset disposition options at this time. The Trust feels that the goal of increased financial flexibility is sufficiently achieved through the combination of improved commodity prices, receipt of the Dodsland-Stranraer sale proceeds, and a continued distribution level of $0.04 per unit per month, while retaining a larger asset and production base. Combined with the sale of the Thorhild property in Northern Alberta which closed at the end of the first quarter of 2008 for net proceeds of $5.8 million, after closing adjustments and costs, and other minor property dispositions, total net proceeds from the sale of properties for the first six months of 2008 were $44.3 million. The net proceeds from these dispositions were used to pay down debt. The Trust continuously reviews and optimizes its portfolio, divesting of non-core and high cost properties. Liquidity True's net debt, excluding unrealized commodity contract assets and liabilities, future income taxes and asset retirement obligations, as at June 30, 2008 was $189.4 million, representing $125.5 million outstanding on the credit facility, $80.3 million in convertible debentures (liability component) and the net balance of working capital. Combined funding requirements for distributions declared and True's capital expenditures represented 51.6% and 62.8% of funds flow from operations in the three and six months ended June 30, 2008, respectively. The excess funds flow from operations was applied to the repayment of net debt. As of June 30, 2008, the credit facility was renewed and consists of a $15 million demand operating facility provided by one Canadian bank and a $137 million extendible revolving credit facility syndicated by two Canadian chartered banks, a Canadian financial institution, one institutional lender and a U.S. bank. The revolving period on the revolving term credit facility ends on June 26, 2009, unless extended for a further 364 day period. Should the facilities not be renewed they convert to 366 day non-revolving facilities on the renewal date. The borrowing base was renewed effective June 27, 2008 and is currently scheduled for renewal on September 30, 2008. Further details of the credit facilities are disclosed in note 6 of the consolidated financial statements. As at June 30, 2008, there was approximately $26.0 million, net of $0.5 million of prepaid interest, not drawn under these facilities. True does not hold any Asset-Backed Commercial Paper investments. As a non-operating working interest owner, True has a minor exposure of approximately $70,000 from oil sales marketed through In August 2007, True received True maintains an active commodity price risk management program. Approximately 50% of current natural gas production is hedged through the remainder of 2008 with approximately 23% hedged through the first half of 2009. Approximately 40% of current liquids production is hedged through the remainder of 2008. No liquids are currently hedged subsequent to December 31, 2008. The Trust will continue its hedging strategies focusing on maintaining sufficient cash flow to fund True's unitholder distributions and the capital program. 2008 True Capex Budget True's capital program for the first six months of 2008 of approximately $12.7 million compares to a front end loaded 2007 capital program of approximately $62.1 million in the six month period ended June 30, 2007. True plans to continue to take a balanced approach to the priority use of cash flow between level of distributions and size of its 2008 capital program. True's 2008 capital expenditure program is currently planned at $40 to $45 million. True plans to focus on increasing its farm-out activity in non-core areas and may look to increase its capital spending in the latter part of 2008 dependant upon available cash flow. Wayne M. Chorney, P. Eng. President, CEO and COO August 7, 2008
<<
MANAGEMENT'S DISCUSSION AND ANALYSIS
>>
August 7, 2008 - The following Management's Discussion and Analysis of financial results as provided by the management of CONVERSION: The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/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. All boe conversions in this report are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. NON-GAAP MEASURES: This Management's Discussion and Analysis contains the term "funds flow from operations" (or also commonly referred to as "cash flow from operations"), which should not be considered an alternative to, or more meaningful than "cash flow from operating activities" as determined in accordance with Canadian GAAP as an indicator of the Trust's performance. Therefore reference to funds flow from operations or funds flow from operations per unit may not be comparable with the calculation of similar measures for other entities. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Trust's ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between funds flow from operations and cash flow from operating activities can be found in the Management's Discussion and Analysis. Funds flow from operations per unit is calculated using the weighted average number of units for the period. This Management's Discussion and Analysis also contains other terms such as net debt and operating netbacks, which are not recognized measures under Canadian GAAP. Management believes these measures are useful supplemental measures of firstly, the total amount of current and long-term debt and secondly, the amount of revenues received after transportation, royalties and operating costs. Readers are cautioned, however, that these measures should not be construed as an alternative to other terms such as current and long-term debt or net income determined in accordance with GAAP as measures of performance. True's method of calculating these measures may differ from other entities, and accordingly, may not be comparable to measures used by other trusts or companies. Additional information relating to the Trust, including the Trust's Annual Information Form, is available on SEDAR at www.sedar.com. FORWARD LOOKING STATEMENTS: Certain information contained herein may contain forward looking statements including management's assessment of future plans and operations, drilling plans and the timing thereof, expected production increases from certain projects and the timing thereof, the effect of government announcements, proposals and legislation, plans regarding wells to be drilled, expected or anticipated production rates, hedging strategies, expected exchange rates, distributions and method of funding thereof, proportion of distributions anticipated to be taxable and non-taxable, maintenance of productive capacity and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof, may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and reserve estimates of True's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of True. In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Trust believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Trust can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Trust operates; the timely receipt of any required regulatory approvals; the ability of the Trust to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Trust has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Trust to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Trust to secure adequate product transportation; future commodity gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Trust operates; and the ability of the Trust to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could effect True's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at True's website (www.trueenergytrust.com). Furthermore, the forward-looking statements contained herein are made as at the date hereof and True does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes. Net Income (Loss) and Funds Flow from Operations True generated funds flow from operations of $26.3 million ($0.33 per diluted unit) for the three months ended June 30, 2008, down 23% from $34.2 million ($0.45 per diluted unit) from the second quarter of 2007. The decrease in funds flow from operations for the 2008 period was primarily the result of lower sales volumes and higher realized hedging losses, offset significantly by improved commodity prices and operating netbacks for 2008. Funds flow from operations for the first quarter of 2008 increased 25% from fourth quarter 2007 funds flow from operations of $19.5 million. Funds flow from operations for the six month period ended June 30, 2008 was $50.5 million ($0.64 per diluted unit), down from the $64.2 million ($0.88 per diluted unit) for the same period in 2007. True maintains a commodity price risk management program to provide a measure of stability to cash distributions and capital expenditures. Unrealized mark-to-market gains or losses are non-cash adjustments to the current fair market value of the contract over its entire term and are included in the calculation of net income (loss). True generated a net loss of $21.4 million ($(0.27) per diluted unit) in the second quarter of 2008 primarily due to higher unrealized mark-to-market, non-cash, losses on commodity risk management contracts of $25.6 million. This compares to net income of $1.7 million ($0.02 per diluted unit) for the same period in 2007. The net loss for the six months ended June 30, 2008 was $40.0 million compared to a net loss of $6.8 million for the same period in 2007. Funds Flow From Operations and Net Income (Loss)
<<
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
per unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Funds flow from
operations 26,304 34,192 50,537 64,180
Basic ($/unit) 0.33 0.47 0.64 0.89
Diluted ($/unit) 0.33 0.45 0.64 0.88
Net income (loss) (21,374) 1,741 (39,995) (6,830)
Basic ($/unit) (0.27) 0.02 (0.50) (0.10)
Diluted ($/unit) (0.27) 0.02 (0.50) (0.09)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Reconciliation of Funds Flow from Operations and Cash Flow from Operating
Activities
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
per unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Funds flow from
operations 26,304 34,192 50,537 64,180
Asset retirement
costs incurred (123) (387) (712) (575)
Change in non-cash
working capital (6,289) (29,403) (12,090) (19,244)
-------------------------------------------------------------------------
Cash flow from
operating
activities 19,892 4,402 37,735 44,361
-------------------------------------------------------------------------
>>
Sales Volumes Sales volumes for the three months ended June 30, 2008 averaged 11,922 boe/d as compared to 17,122 boe/d for the same period in 2007, representing a 30% decrease. Sales volumes for the six months ended June 30, 2008 averaged 12,737 boe/d as compared to 17,788 boe/d for the same period in 2007, representing a 28% decrease. In comparison, sales volumes for the first quarter of 2008 averaged 13,552 boe/d. Dispositions totalling approximately 1,000 boe/d were closed during the first half of 2008. In addition to natural production decline, field production was impacted approximately 150 boe/d by third party maintenance and severe thunderstorm activity in the second quarter of 2008. Full year 2008 field production guidance remains at 12,000 to 12,500 boe/d. The disposition of the Dodsland/Stranraer property, consisting of primarily natural gas reserves, on April 30, 2008 reduced average sales volumes for the second quarter by approximately 500 boe/d as compared to the first quarter of 2008.
<<
Sales Volumes
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
-------------------------------------------------------------------------
Natural gas (mcf/d) 46,515 69,455 49,383 70,686
-------------------------------------------------------------------------
Heavy oil (bbls/d) 2,721 3,058 2,773 3,703
Light oil and
condensate (bbls/d) 1,116 1,743 1,253 1,632
NGLs (bbls/d) 333 745 480 672
-------------------------------------------------------------------------
Total crude
oil and NGLs (bbls/d) 4,170 5,546 4,506 6,007
-------------------------------------------------------------------------
Total boe/d (6:1) 11,922 17,122 12,737 17,788
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
During the second quarter of 2008, True participated in 1 (0.4 net) successful working interest gas well. True's planned second half drilling program is underway with 4 gross (2.9 net) gas wells drilled thus far in the third quarter of 2008. A further 25 net wells are planned through the remainder of the year including at least 3 horizontal Viking light oil wells in the Kindersley area, 1.5 vertical heavy oil wells at Mantario, and 18.5 natural gas wells in Alberta. A further 2 exploration wells are also scheduled. The Kerrobert SAGD project was adversely impacted by severe thunderstorm and lightning activity in June and July 2008. Electrical equipment issues impacted steam generation. Oil production rates were subsequently reduced to retain the steam chamber and ensure uniform heating and conformance. Repairs are largely complete and response to the ongoing reservoir heating continues to improve with temperatures of up to 200 degrees Celsius observed in 2 of the 4 new thermal producing wells as compared to initial reservoir temperatures of approximately 30 degrees Celsius. For the three months ended June 30, 2008, the weighting towards natural gas sales averaged 65% compared to 68% in the same period in 2007. For the six month period ended June 30, 2008, the weighting towards natural gas averaged 65% compared to 66% for the same period in 2007. Heavy oil sales made up 23% of total production for the 2008 second quarter compared to 18% in the 2007 second quarter. In comparison, heavy oil sales made up 21% of total production in the first quarter of 2008. Sales of natural gas averaged 46.5 mmcf/d for the second quarter of 2008, compared to 69.5 mmcf/d in the same period of 2007, a decrease of 33%. Crude oil and NGL sales for the second quarter of 2008 averaged 4,170 bbls/d, compared to 2007 second quarter average sales of 5,546 bbls/d. Commodity Prices
<<
Average Commodity Prices
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
% %
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Exchange rate (US$/Cdn$) 1.0000 0.9108 10% 0.9989 0.8810 13%
Natural gas:
NYMEX (US$/mmbtu) 11.47 7.66 50% 9.99 7.41 35%
Alberta spot ($/mcf) 10.20 7.07 44% 9.09 7.23 26%
True's average price
($/mcf) 9.94 7.60 31% 8.90 7.43 20%
True's average price
(including hedging(1))
($/mcf) 8.80 7.65 15% 8.37 7.58 10%
Crude oil:
WTI (US$/bbl) 123.80 65.02 90% 109.92 61.67 78%
Edmonton par - light oil
($/bbl) 126.37 72.66 74% 112.30 70.21 60%
Bow River - medium/heavy
oil ($/bbl) 103.98 50.69 105% 90.74 50.24 81%
Hardisty Heavy - heavy
oil ($/bbl) 96.34 42.95 124% 83.20 42.82 94%
True's average prices
($/bbl)
Light crude oil,
condensate, and NGLs 110.23 60.59 82% 95.92 56.10 71%
Heavy crude oil 99.37 43.01 131% 80.11 39.28 104%
Total crude oil and
NGLs 103.14 50.90 103% 86.19 45.74 88%
Total crude oil and
NGLs (including
hedging(1)) 43.82 50.14 (13%) 71.50 46.71 53%
-------------------------------------------------------------------------
(1) Per unit metrics including hedging include realized gains or losses
on commodity contracts and exclude unrealized gains or losses on
commodity contracts.
>>
True's natural gas is primarily sold on the daily spot market. During the second quarter of 2008, the AECO Spot reference price increased by 44% compared to the same period in 2007. True's average sales price before hedging for the second quarter of 2008 increased by 31% compared to the same period in 2007. In comparison, True's second quarter 2008 natural gas price before hedging was 25% higher than the first quarter 2008 price of $7.97/mcf. True's natural gas price after including hedging for the second quarter of 2008 was $8.80/mcf compared to $7.65/mcf for the same period in 2007. For heavy crude oil, True received an average price before transportation of $99.37/bbl for the second quarter of 2008, an increase of 131% over prices in the 2007 period. The Bow River reference price increased by 105% and the Hardisty Heavy reference price increased by 124% over the same period. The majority of True's heavy crude oil density ranges between 11 and 16 degrees API consistent with the Hardisty Heavy reference price. During 2008, the blend costs for condensate were lower and a certain portion of our heavy oil sales have been sold through the Bow River pipeline which has also contributed to higher pricing received. In comparison, True's second quarter 2008 heavy oil price was 62% higher than the first quarter of 2008 price of $61.55/bbl. For light oil, condensate and NGLs, True recorded an average $110.23/bbl before hedging during the second quarter of 2008, 82% higher than the average price received in the same period of 2007. The Edmonton par price increased by 74% over the same period. The average WTI crude oil US dollar based price increased 90% from the second quarter of 2007 to that in 2008. In comparison, True's realized price for the second quarter of 2008 increased 29% from the first quarter 2008 average price of $85.65/bbl, whereas the Edmonton par price also increased by 29%. True's realized price after including hedging was $50.99/bbl for the second quarter of 2008 compared to $58.90/bbl for the same period in 2007. Revenue Revenue before other income and hedging for the three months ended June 30, 2008 was $81.2 million, 10% higher than the $73.7 million in the same period in 2007. The higher revenue for the 2008 period was the result of significantly higher commodity prices, despite lower sales volumes.
<<
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($000s) 2008 2007 2008 2007
-------------------------------------------------------------------------
Light crude oil,
condensate and NGLs 14,528 13,719 30,262 23,394
Heavy oil 24,608 11,967 40,426 26,329
-------------------------------------------------------------------------
Crude oil and NGLs 39,136 25,686 70,688 49,723
Natural gas 42,067 48,058 79,961 95,040
-------------------------------------------------------------------------
Total revenue before
other 81,203 73,744 150,649 144,763
Other (1) 871 1,247 1,458 1,424
-------------------------------------------------------------------------
Total revenue before
royalties and hedging 82,074 74,991 152,107 146,187
-------------------------------------------------------------------------
(1) Other revenue primarily consists of processing and other third party
income.
>>
Financial Instruments The Trust has a formal risk management policy which permits management to use specified price risk management strategies for up to 50% of crude oil, natural gas and NGL production including fixed price contracts, collars and the purchase of floor price options and other derivative financial instruments to reduce the impact of price volatility and ensure minimum prices for a maximum of eighteen months beyond the current date. The program is designed to provide price protection on a portion of the Trust's future production in the event of adverse commodity price movement, while retaining significant exposure to upside price movements. By doing this, the Trust seeks to provide a measure of stability to cash distributions, as well as, to ensure True realizes positive economic returns from its capital developments and acquisition activities. The Trust will continue its hedging strategies focusing on maintaining sufficient cash flow to fund True's unitholder distributions and capital program. A summary of the hedge volumes and average prices by quarter currently outstanding as of August 7, 2008 is shown in the following tables (see Note 16 to the consolidated financial statements for a detailed disclosure of all commodity contracts in place as at August 7, 2008):
<<
Crude oil and liquids Average Volumes (bbls/d)
-------------------------------------------------------------------------
Q3 2008 Q4 2008 Q1 2009 Q2 2009
-------------------------------------------------------------------------
Collars 2,000 2,000 - -
-------------------------------------------------------------------------
Total bbls/d 2,000 2,000 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average Price (US$/bbl WTI)
-------------------------------------------------------------------------
Q3 2008 Q4 2008 Q1 2009 Q2 2009
-------------------------------------------------------------------------
Collar ceiling price 82.00 82.00 - -
Collar floor price 65.00 65.00 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural gas Average Volumes (GJ/d)
-------------------------------------------------------------------------
Q3 2008 Q4 2008 Q1 2009 Q2 2009
-------------------------------------------------------------------------
Collars - - - -
Fixed 24,326 24,326 10,550 10,550
-------------------------------------------------------------------------
Total GJ/d 24,326 24,326 10,550 10,550
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average Price ($/GJ AECO C)
-------------------------------------------------------------------------
Q3 2008 Q4 2008 Q1 2009 Q2 2009
-------------------------------------------------------------------------
Collar ceiling price - - - -
Collar floor price - - - -
Fixed 6.68 6.89 7.74 7.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
As of June 30, 2008, the fair value of True's outstanding commodity contracts is an unrealized liability of $53.6 million as reflected in the financial statements. The following is a summary of the gain (loss) on commodity contracts for the three and six month periods ended June 30, 2008 and 2007:
<<
Commodity contracts
-------------------------------------------------------------------------
Crude Oil Natural Q2 2008 Q2 2007
($000s) & Liquids Gas Total Total
-------------------------------------------------------------------------
Realized cash gain
(loss) on contracts(1) (7,807) (4,812) (12,619) (118)
Unrealized gain (loss)
on contracts(2) (14,700) (10,850) (25,550) 5,953
-------------------------------------------------------------------------
Total gain (loss) on
commodity contracts (22,507) (15,662) (38,169) 5,835
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Crude Oil Natural YTD 2008 YTD 2007
($000s) & Liquids Gas Total Total
-------------------------------------------------------------------------
Realized cash gain
(loss) on contracts(1) (12,046) (4,715) (16,761) 3,026
Unrealized gain (loss)
on contracts(2) (13,802) (29,435) (43,237) 3,488
-------------------------------------------------------------------------
Total gain (loss) on
commodity contracts (25,848) (34,150) (59,998) 6,514
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes the crude oil and natural gas commodity contract premium
expenses in the 2007 period and the amortization of prior year crude
oil and natural gas commodity contract premiums of a total
$1.0 million and $3.4 million, respectively, for the three and
six months ended June 30, 2007.
(2) Unrealized gain (loss) commodity contracts represent non-cash
adjustments for changes in the fair value of these contracts during
the period.
>>
Royalties For the three months ended June 30, 2008, total royalties were $16.3 million, compared to $9.8 million incurred in the same period in 2007. Overall royalties as a percentage of revenue (after transportation costs) in the second quarter of 2008 were 21%, compared with 14% in the same period in 2007. Royalties for the 2007 second quarter included the impact of the reversal of certain over accruals of light and heavy crude oil royalties from periods prior to 2007 of approximately $5.3 million; excluding that adjustment, the average royalty rate for the second quarter of 2007 would have been 22%. Royalties for the six months ended June 30, 2008 were $31.8 million compared to $24.7 million for the same period in 2007.
<<
-------------------------------------------------------------------------
Royalties by
Commodity Type
($000s, except Three months ended June 30, Six months ended June 30,
where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Light crude oil,
condensate and NGLs 2,897 3,657 6,663 4,537
$/bbl 21.98 16.15 21.12 10.88
Average light crude
oil, condensate and
NGLs royalty rate (%) 20 26 23 19
Heavy Oil 5,341 1,416 7,632 2,936
$/bbl 21.57 5.08 15.12 4.38
Average heavy oil
royalty rate (%) 23 13 20 12
Natural Gas 8,051 4,728 17,494 17,222
$/mcf 1.90 0.74 1.95 1.35
Average natural gas
royalty rate (%) 20 10 22 18
-------------------------------------------------------------------------
Total 16,289 9,801 31,789 24,695
-------------------------------------------------------------------------
$/boe 15.01 6.29 13.71 7.67
-------------------------------------------------------------------------
Average total
royalty rate (%) 21 14 22 17
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Royalties, by Type
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($000s) 2008 2007 2008 2007
-------------------------------------------------------------------------
Crown royalties 9,587 6,229 18,543 13,234
Indian Oil and Gas
Canada royalties 1,854 762 3,535 3,311
Freehold & GORR 4,848 2,810 9,711 8,150
-------------------------------------------------------------------------
Total 16,289 9,801 31,789 24,695
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Expenses
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($000s) 2008 2007 2008 2007
-------------------------------------------------------------------------
Production 16,170 19,778 33,166 34,750
Transportation 2,478 2,431 3,321 3,120
General and
administrative 4,492 4,332 8,262 9,236
Interest and
financing charges 3,487 4,573 8,003 9,120
Unit-based compensation 160 1,275 429 2,387
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Expenses per boe
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($ per boe) 2008 2007 2008 2007
-------------------------------------------------------------------------
Production 14.90 12.69 14.31 10.79
Transportation 2.28 1.56 1.43 0.97
General and
administrative 4.14 2.78 3.56 2.87
Interest and
financing charges 3.21 2.93 3.45 2.83
Unit-based compensation 0.15 0.82 0.19 0.74
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Production Expenses For the three months ended June 30, 2008, production expenses totaled $16.2 million, compared to $19.8 million recorded in the same period in 2007. During the second quarter of 2008, production expenses averaged $14.90/boe, compared to $12.69/boe over the same period in 2007. Production expenses are increased as additional natural gas input costs are required to operate the Kerrobert SAGD facility after startup in late 2007; this adds approximately $2.80/boe to production expenses in the second quarter of 2008. The increase in 2008 costs on a boe basis was also due to a significant fixed component of production expenses in combination with substantially reduced production volumes. For the six months ended June 30, 2008, production expenses totaled $33.2 million, compared to $34.8 million for the same period in 2007.
<<
Production Expenses, by Commodity Type
-------------------------------------------------------------------------
($000s, except Three months ended June 30, Six months ended June 30,
where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Light crude oil,
condensate and NGLs 2,193 2,251 5,274 4,768
$/bbl 16.64 9.94 16.71 11.43
Heavy oil 5,808 5,612 10,843 11,017
$/bbl 23.45 20.17 21.49 16.44
Natural gas 8,169 11,915 17,049 18,965
$/mcf 1.93 1.89 1.90 1.48
-------------------------------------------------------------------------
Total 16,170 19,778 33,166 34,750
-------------------------------------------------------------------------
$/boe 14.90 12.69 14.31 10.79
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 16,170 19,778 33,166 34,750
-------------------------------------------------------------------------
Processing and other
third party income(1) (871) (1,247) (1,458) (1,424)
-------------------------------------------------------------------------
Total after deducting
processing and other
third party income 15,299 18,531 31,708 33,326
-------------------------------------------------------------------------
$/boe 14.10 11.90 13.68 10.35
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Processing and other third party income is included within petroleum
and natural gas sales on the statement of income.
>>
Transportation Transportation expenses are expected to be approximately 2% to 3% of gross revenues for the 2008 year. For the three and six months ended June 30, 2008, transportation expenses averaged approximately 3% and 2%, respectively. Higher transportation expenses on a percentage basis in the second quarter of 2008, as compared to the first quarter of 2008, reflect certain accrual revisions in respective periods. Operating Netback For the second quarter of 2008, corporate field operating netback (before hedging) was $42.66/boe compared to $26.79/boe in the same period in 2007. This was the result of increased overall commodity prices, partially offset by higher royalties and operating costs experienced in the 2008 period. By comparison, corporate field operating netback (before hedging) for the first quarter of 2008 was $29.28/boe. After including hedging activities, the corporate field operating netback for the second quarter of 2008 was $31.01/boe compared to $26.71/boe in the same period in 2007.
<<
Field Operating Netback - Corporate (before hedging)
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($/boe) 2008 2007 2008 2007
-------------------------------------------------------------------------
Sales 74.85 47.33 64.99 44.96
Transportation (2.28) (1.56) (1.43) (0.97)
Royalties (15.01) (6.29) (13.71) (7.67)
Production expense (14.90) (12.69) (14.31) (10.79)
-------------------------------------------------------------------------
Field operating netback 42.66 26.79 35.54 25.53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Field operating netback for natural gas for the second quarter of 2008
increased 23% to $5.77/mcf, compared to $4.68/mcf for the same period in 2007,
reflecting stronger natural gas prices experienced, the effects of which were
partially offset by higher royalties and production expenses. After including
hedging activities, field operating netback for natural gas for the second
quarter of 2008 was $4.62/mcf compared to $4.73/mcf in the same period in
2007.
Field Operating Netback - Natural Gas (before hedging)
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($/mcf) 2008 2007 2008 2007
-------------------------------------------------------------------------
Sales 9.94 7.60 8.90 7.43
Transportation (0.34) (0.29) (0.11) (0.22)
Royalties (1.90) (0.74) (1.95) (1.35)
Production expense (1.93) (1.89) (1.90) (1.48)
-------------------------------------------------------------------------
Field operating netback 5.77 4.68 4.94 4.38
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Field operating netback for crude oil, condensate and NGLs averaged
$57.65/bbl for the second quarter of 2008, up 140% compared to $24.03/bbl for
the same period in 2007. This compares to a 103% increase in the crude oil,
condensate and NGLs sales price combined with a lower corresponding increase
in overall expenses over the same period. After including hedging activities,
field operating netback for crude oil and NGLs for the second quarter of 2008
was $37.08/boe compared to $23.27/boe in the same period in 2007.
Field Operating Netback - Crude Oil, Condensate and NGLs (before
hedging)
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($/bbl) 2008 2007 2008 2007
-------------------------------------------------------------------------
Sales 103.14 50.90 86.19 45.74
Transportation (2.69) (1.23) (2.83) (0.30)
Royalties (21.71) (10.06) (17.43) (6.87)
Production expense (21.09) (15.58) (19.65) (14.52)
-------------------------------------------------------------------------
Field operating netback 57.65 24.03 46.28 24.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
General and Administrative Net general and administrative ("G&A") expenses for the three and six months ended June 30, 2008 were $4.5 million and $8.3 million, respectively, compared to $4.3 million and $9.2 million, respectively, for the same period in 2007. The decrease in the G&A expense for the six month period ended June 30, 2008 from the same period in 2007 reflects a reduction of the number of salaried personnel on staff and other efforts to reduce costs. The reduction in amounts of capitalized G&A for 2008 is consistent with a lower capital program. On a per boe basis, G&A expenses for the three and six months ended June 30, 2008 were $4.14/boe and $3.56/boe, respectively compared to $2.78/boe and $2.87/boe, respectively for the same period in 2007. The increase in G&A on a per boe basis is consistent with reduced sales volumes experienced in the first and second quarters of 2008 compared to 2007.
<<
General and Administrative Expenses
-------------------------------------------------------------------------
($000s, except Three months ended June 30, Six months ended June 30,
where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Gross expenses 5,508 5,872 10,387 12,282
Capitalized (692) (1,121) (1,199) (1,814)
Recoveries (324) (419) (926) (1,232)
-------------------------------------------------------------------------
Net expenses 4,492 4,332 8,262 9,236
-------------------------------------------------------------------------
Net expenses,
per unit ($/boe) 4.14 2.78 3.56 2.87
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest and Financing Charges
True recorded $3.5 million of interest and financing charges for the three
months ended June 30, 2008 compared to $4.6 million in the same period in
2007. For the six months ended June 30, 2008, interest and financing charges
totaled $8.0 million compared to $9.1 million for the same period in 2007.
True's net debt at June 30, 2008 of $189.4 million includes the $80.3 million
liability portion of convertible debentures, $125.5 million of bank debt and
the net balance of working capital.
Interest and Financing Charges
-------------------------------------------------------------------------
($000s, except Three months ended June 30, Six months ended June 30,
where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Interest and financing
charges 3,487 4,573 8,003 9,120
Interest and financing
charges ($/boe) 3.21 2.93 3.45 2.83
Net debt(1) including
convertible debentures
at quarter end 189,354 221,045 189,354 221,045
Debt to periods funds
flow from operations
ratio annualized(2) 1.8x 1.6x 1.9x 1.7x
Net debt excluding
convertible debentures
at quarter end 109,101 142,409 109,101 142,409
Debt to periods funds
flow from operations
ratio annualized(2) 1.1x 1.0x 1.1x 1.1x
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net debt includes the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities and short-term
future tax assets. Total net debt also includes the liability
component of convertible debentures and excludes asset retirement
obligations and the future income tax liability.
(2) Debt to funds flow from operations ratio is calculated based upon
annualizing of funds flow from operations for the three and six month
periods ended June 30, 2008, respectively.
>>
Unit-Based Compensation Non-cash unit-based compensation expense for the three and six month period ended June 30, 2008 was $0.2 million and $0.4 million, respectively, compared to $1.3 million and $2.4 million in 2007, respectively. The decrease in the expense for the six months ended June 30, 2008 reflects a reduction in the estimated weighted average fair value of incentive rights granted for more recent options, a reduction to the 2008 expense of $0.4 million for a reversal of prior year unit-based compensation expense for 2008 forfeitures of unvested incentive rights and reduced incentive rights being granted in 2008 compared to the 2007 period. Capital Expenditures True invested $3.7 million on exploration and development activities during the second quarter of 2008, compared to $15.5 million in the same period in 2007. For the six months ended June 30, 2008, the Trust invested $12.1 million on exploration and development activities compared to $60.8 million for the same period in 2007. During the second quarter of 2008, True participated in 1 (0.4 net) successful working interest natural gas well.
<<
Capital Expenditures(1)
-------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($000s) 2008 2007 2008 2007
-------------------------------------------------------------------------
Lease acquisitions
and retention 415 711 965 1,502
Geological and geophysical (55) (3,455) 12 3,464
Drilling and completion
costs 2,560 15,274 9,504 48,345
Facilities and equipment 734 2,586 1,626 7,458
-------------------------------------------------------------------------
Exploration and
development 3,654 15,116 12,107 60,769
Corporate and property
acquisitions 426 649 623 1,354
-------------------------------------------------------------------------
Total capital
expenditures - cash 4,080 15,765 12,730 62,123
Property dispositions
- cash (38,530) (9,026) (44,318) (27,469)
-------------------------------------------------------------------------
Total net capital
expenditures - cash (34,450) 6,739 (31,588) 34,654
-------------------------------------------------------------------------
Other - non-cash(2) (2,521) 311 (2,714) (313)
-------------------------------------------------------------------------
Total capital
expenditures (36,971) 7,050 (34,302) 34,341
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligation
expenditures incurred during the year.
(2) Other includes current period's asset retirement obligations and unit
based compensation capitalized
>>
The $12.7 million capital program for the first six months of 2008 was financed entirely with funds flow from operations compared to 81% in the same period in 2007. True plans to continue to take a balanced approach to the priority use of cash flow between level of distributions and size of its 2008 capital program. True's 2008 capital expenditure program is currently planned at $40 to $45 million. True plans to focus on increasing its farm-out activity in non-core areas and may look to increase its capital spending in the latter part of 2008 dependant upon available cash flow. True holds an extensive land base. At June 30, 2008, True had approximately 399,661 net undeveloped acres of land of its total developed and undeveloped net acreage position of 705,524 net acres in Saskatchewan, Alberta, and British Columbia. Dispositions during the second quarter of 2008 consisted principally of the divestiture of the Dodsland-Stranrear property in Saskatchewan for net proceeds after adjustments and closing costs of $38.5 million. Combined with the sale of the Thorhild property in Northern Alberta which closed at the end of the first quarter of 2008 for net proceeds of $5.8 million, after closing adjustments and costs, and other minor property dispositions, total net proceeds on sale of properties for the first six months of 2008 were $44.3 million. At the end of the second quarter of 2008, the Trust had committed to drill a total of 2 wells in Alberta pursuant to various farm-in agreements with oil and gas companies. True expects to satisfy these various drilling commitments at an estimated cost for True's interest of approximately $2.8 million. These wells were drilled in July 2008. Depletion, Depreciation and Accretion Depletion, depreciation and accretion expense for the second quarter of 2008 was $33.2 million ($30.61/boe), compared to the $45.3 million ($29.11/boe) in the same period of 2007, which reflects lower production volumes combined with reduced carrying costs in the 2008 period as compared to 2007. For the three month period ended June 30, 2008, True has included $53.5 million for future development costs in the depletion calculation and excluded from the depletion calculation $34.7 million for undeveloped land and $43.5 million for estimated salvage.
<<
Depletion, Depreciation and Accretion Costs
-------------------------------------------------------------------------
($000s, except Three months ended June 30, Six months ended June 30,
where noted) 2008 2007 2008 2007
-------------------------------------------------------------------------
Depletion and
Depreciation 32,696 44,822 68,444 91,769
Accretion 513 527 1,068 1,038
-------------------------------------------------------------------------
Total 33,209 45,349 69,512 92,807
-------------------------------------------------------------------------
Per unit ($/boe) 30.61 29.11 29.99 28.33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Ceiling Test The Trust calculates a ceiling test quarterly and annually to place a limit on the aggregate carrying value of its capitalized costs, which may be amortized against revenues of future periods. The ceiling test is performed in accordance with the requirements of the The Trust performed a ceiling test calculation at June 30, 2008 resulting in undiscounted cash flows from proved reserves and the undeveloped properties exceeding the carrying value of oil and gas assets. Consequently, no impairment in oil and gas assets was identified as at June 30, 2008. The ceiling test calculation will be updated during the remainder of 2008 on a quarterly and annual basis based upon the latest available data, including but not limited to an updated annual external reserve engineering report which incorporates a full evaluation of reserves or internal reserve updates at quarterly periods, and the latest commodity pricing deck. Estimating reserves is very complex, requiring many judgments based on available geological, geophysical, engineering and economic data. Changes in these judgments could have a material impact on the estimated reserves. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available and as the economic environment changes. Asset Retirement Obligations As at June 30, 2008, the Trust has recorded an Asset Retirement Obligation ("ARO") of $26.3 million, compared to $27.1 million at June 30, 2007, for future abandonment and reclamation of the Trust's properties. For the six months ended June 30, 2008, the ARO decreased by $2.0 million total as a result of accretion expense of $1.1 million, and $0.04 million net changes in estimates and liabilities incurred on development activities, offset by $2.4 million of liabilities released on dispositions and $0.7 million of liabilities settled during the year. Income Taxes For the six months ended June 30, 2008, the Trust has recorded capital tax expense of $1.1 million compared to $1.1 million expensed in the same period of 2007. Capital taxes are based on debt and equity levels of the Trust at the end of the year in addition to a resource surcharge component of provincial taxes calculated as a percentage of revenues. Future income taxes arise from differences between the accounting and tax bases of the Trust's assets and liabilities. For the six months ended June 30, 2008, the Trust recognized a future income tax recovery of $23.3 million compared to a recovery of $21.5 million in the same period in 2007. Under our current structure, the operating entities make interest and royalty payments to the Trust, which transfers taxable income to the Trust to eliminate income subject to corporate and other income taxes in the operating entities. With the SIFT legislation (as referred to below), such amounts transferred to the Trust could be taxable beginning in 2011 as distributions will no longer be deductible for income tax purposes. At that time, True could claim tax pools in its operating companies, reduce the income transferred to the Trust, and pay all or a portion of distributions as a return of capital. Until 2011, under the terms of its trust indenture, the Trust is required to distribute amounts equal to at least its taxable income. In the event that the Trust has undistributed taxable income in a taxation year (prior to 2011), an additional special taxable distribution, subject to certain withholding taxes, would be required by the terms of its trust indenture. The SIFT legislation is not expected to directly affect our cash flow levels and distribution policies until 2011 at the earliest. Enactment of the Tax on Income Trusts On June 12, 2007, the legislation implementing a new tax (the "SIFT tax") on publicly traded income trusts and limited partnerships, referred to as "Specified investment flow-through" ("SIFTs") entities (Bill C-52) received third reading in the House of Commons and on June 22, 2007, Bill C-52 received Royal assent. As a result, the SIFT tax was considered to be enacted for accounting purposes in June 2007, which resulted in a $1.2 million future income tax recovery amount being recorded to reflect current temporary differences between the book and tax basis of assets and liabilities expected to be remaining in the Trust in 2011. The SIFT tax announcement and the related future income tax recovery did not affect cash flow or distributions and is not expected to affect distribution policies until 2011 at the earliest. SIFTs are certain publicly traded income and royalty trusts and limited partnerships including True. For SIFTs in existence on October 31, 2006 the SIFT tax will be effective in 2011, unless certain rules related to "undue expansion" are not adhered to. Under the guidance provided, True can increase its equity by approximately $737 million between now and 2011 without prematurely triggering the SIFT tax. In June 2008, Bill C-50, which contains legislation to adjust the deemed provincial component on the tax rate on distributions from income and royalty trusts expected to apply to the Trust commencing in 2011, passed third reading in the House of Commons. Under this legislation, instead of basing the provincial component of the SIFT tax on a flat rate of 13%, the provincial component will instead be based on the general provincial corporate income tax rate in each province in which the SIFT has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable income allocation formula will be used. Specifically, the Trust's taxable distributions will be allocated to provinces by taking half of the aggregate of:
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- that proportion of the Trust's taxable distributions for the year
that the Trust's wages and salaries in the province are of its total
wages and salaries in Canada; and
- that proportion of the Trust's taxable distributions for the year
that the Trust's gross revenues in the province are of its total
gross revenues in Canada.
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Under the Bill C-50 legislation, the Trust would be considered to have a permanent establishment only in Alberta, where the provincial tax rate in 2011 is expected to be 10%. For accounting purposes, however, the adjustment to the provincial component of the tax is not considered substantively enacted as the income tax regulations for the adjustment have not been finalized. If the proposal becomes enacted, we expect to record a future income tax recovery based on temporary differences at that time. On July 14, 2008, the The True Board of Directors and Management continue to review the impact of this tax on business strategy as well as the Conversion Rules in considering alternatives available. At the present time, True believes some or all of the following actions will or could result due to the enactment of the SIFT tax:
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- If structural or other similar changes are not made, the
distribution yield net of the SIFT tax in 2011 and beyond to taxable
Canadian investors will remain approximately the same; however, the
distribution yield to tax-deferred Canadian investors (RRSPs, RRIFs,
pension plans, etc.) would fall by an estimated 26.5 percent in 2011
and 25.0 percent in 2012 and beyond. For U.S. investors, the
distribution yield net of the SIFT and withholding taxes would fall
by an estimated 25.3 percent in 2011 and 25.1 percent in 2012 and
beyond;
- A portion of True's cash flow could be allocated to the payment of
the SIFT tax, or other forms of tax, and would not be available for
distribution or re-investment;
- True could convert to a corporate structure to facilitate investing
a higher proportion or all of its cash flow in exploration and
development projects. Such a conversion and change to capital
programs could result in a significant reduction to or elimination
of distributions and/or dividends;
- True might determine that it is more economic to remain in the trust
structure, at least for a period of time, and shelter its taxable
income using tax pools and pay all or a portion of its distributions
on a return of capital basis, likely at a lower payout ratio.
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The Trust is reviewing all organizational structures and alternatives to minimize the impact of the SIFT tax on our unitholders. While there can be no assurance that the negative effect of the tax can be minimized or eliminated, True and its advisors will continue to work diligently on these issues. As at June 30, 2008, the operating subsidiaries and the Trust itself have a total net future income tax liability balance of $41.0 million. Canadian GAAP requires that a future income tax liability be recorded when the book value of assets exceeds the balance of tax pools. At June 30, 2008, the Trust and operating subsidiaries of the Trust had approximately $469 million in tax pools available for deduction against future income as follows:
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Operating
($000s) Trust subsidiaries Total
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Intangible resource pools 15,000 296,000 311,000
Undepreciated capital cost - 138,000 138,000
Loss carryforwards (expire through 2027) - 14,000 14,000
Unit issue costs 3,000 3,000 6,000
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18,000 451,000 469,000
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Distributions
Trust unitholders who held their trust units throughout the first six
months of 2008 received distributions of $0.24 per unit. For the six months
ended June 30, 2008 the Trust declared distributions as follows:
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($000s, except per unit amount) Distribution
Six months ended June 30, 2008 Per Unit Total
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Distributions declared $ 0.24 $ 19,012
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Distribution Paid History(1)
Distributions comprise a taxable portion and a return of capital portion
(tax deferred). The return of capital component reduces the cost basis of the
trust units held, as described below. For additional information, please see
our website at www.trueenergytrust.com.
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Distributions Taxable Return of
Calendar Year per unit Portion Capital
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2005 (two months)(2) $ 0.480 $ 0.456 $ 0.024
2006 $ 2.640 $ 2.033 $ 0.607
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Cumulative to Dec. 31, 2006 $ 3.120 $ 2.489 $ 0.631
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2007 year $ 0.960 $ 0.960 -
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Cumulative to Dec. 31, 2007 $ 4.080 $ 3.449 $ 0.631
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2008 year to date ( six months)(3) $ 0.240
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Cumulative to June 30, 2008 $ 4.320
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(1) Applies to unitholders who are residents of Canada and hold their
trust units as capital property.
(2) Based upon the distributions paid in the 2005 calendar year, after
the November 2, 2005 Arrangement with During 2008, to date distributions have been funded from funds flow from operations. Foreign Ownership Update Based on information from Trust records and information provided by intermediaries holding Trust units for others, the Trust estimates that, as of July 18, 2008 approximately 27 percent of unitholders are non-Canadian residents with the remaining 73 percent being Canadian residents. Liquidity and Capital Resources True's net debt as at June 30, 2008 was $189.4 million, representing $125.5 million outstanding on the credit facility, $80.3 million in convertible debentures (liability component) and the net balance of working capital. Our calculation of net debt includes the net working capital before short-term commodity contract assets and liabilities and short-term future income tax assets. Total net debt also includes the liability component of convertible debentures and excludes asset retirement obligations and long-term future income taxes. During the six month period ended June 30, 2008, the Trust has reduced its net debt by approximately $61.8 million. Combined funding requirements for distributions declared and True's capital expenditures represented 51.6% and 62.8% of funds flow from operations in the three and six months ended June 30, 2008, respectively. The excess funds flow from operations was applied to the repayment of net debt. As of June 30, 2008, the credit facility was renewed and consists of a $15 million demand operating facility provided by one Canadian bank and a $137 million extendible revolving credit facility syndicated by two Canadian chartered banks, a Canadian financial institution, one institutional lender and a U.S. bank. The revolving period on the revolving term credit facility ends on June 26, 2009, unless extended for a further 364 day period. Should the facilities not be renewed they convert to 366 day non-revolving facilities on the renewal date. The borrowing base was renewed effective June 27, 2008 and is currently scheduled for renewal on September 30, 2008. Further details of the credit facilities are disclosed in note 6 of the consolidated financial statements. As at June 30, 2008, there was approximately $26.0 million, net of $0.5 million of prepaid interest, not drawn under these facilities. The Trust does not hold any Asset-Backed Commercial Paper investments. As a non-operating working interest owner, True has a minor exposure of approximately $70,000 from oil sales marketed through On June 15, 2006 the Trust completed a bought deal public offering of 86,250 7.5% convertible unsecured subordinated debentures at a price of $1,000 per debenture for aggregate gross proceeds of $86,250,000. The debentures have a face value of $1,000 per debenture and a maturity date of June 30, 2011. The debentures bear interest at an annual rate of 7.50% payable semi-annually on June 30 and December 31 in each year commencing December 31, 2006. The debentures are convertible at anytime at the option of the holders into trust units of the Trust at a conversion price of $16.00 per trust unit. The Trust will have the right to redeem all or a portion of the debentures at a price of $1,050 per debenture after June 30, 2009 and on or before June 30, 2010 and at a price of $1,025 per debenture after June 30, 2010 and before the maturity date. Upon maturity or redemption of the debentures, the Trust may, subject to notice and regulatory approval, pay the outstanding principal and premium (if any) on the debentures in cash or through the issue of additional trust units at 95% of the weighted average trading price of the trust units. As at July 31, 2008, the Trust had outstanding a total of 2,670,499 incentive units exercisable at an average exercise price of $4.43 per unit, 373,311 exchangeable shares (convertible, as at July 31, 2008 into an aggregate of 349,960 trust units, subject to further adjustments based on distributions made on trust units), $86.25 million principal amount of debentures convertible into trust units (at a conversion price of $16.00 per trust unit) and 79,031,932 trust units. Commitments As at June 30, 2008, the Trust had committed to drill a total of 2 wells in Alberta pursuant to various farm-in agreements with oil and gas companies. True expects to satisfy these various drilling commitments at an estimated cost of approximately $2.8 million. These wells were drilled in July 2008. Off-Balance Sheet Arrangements The Trust has certain lease agreements, including primarily office space leases, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of June 30, 2008. Business Prospects and 2008 Outlook The Trust continues to develop its core assets and conduct some exploration programs utilizing its large inventory of geological prospects. In addition, the Trust will continue to explore potential acquisition opportunities. Currently, the Trust's producing properties are located in Saskatchewan, Alberta and British Columbia. True has budgeted the US$/Cdn.$ exchange rate to average 1.00 through the 2008 year. The Trust continues to maintain a large undeveloped land base of approximately 635,541 (399,361 net) acres containing a significant multi-year drilling inventory. True's capital program for the first six months of 2008 of approximately $12.7 million compares to a front end loaded 2007 capital program of approximately $62.1 million in first and second quarters of 2007. True plans to continue to take a balanced approach to the priority use of cash flow between level of distributions and size of its 2008 capital program. True's 2008 capital expenditure program is currently planned at $40 to $45 million. True plans to focus on increasing its farm-out activity in non-core areas and may look to increase its capital spending in the latter part of 2008 dependant upon available cash flow. True's planned second half drilling program is underway with 4 gross (2.9 net) gas wells drilled thus far in the third quarter of 2008. A further 25 net wells are planned through the remainder of the year including at least 3 horizontal Viking light oil wells in the Kindersley area, 1.5 vertical heavy oil wells at Mantario, and 18.5 natural gas wells in Alberta. A further 2 exploration wells are also scheduled. Full year 2008 field production guidance remains at 12,000 to 12,500 boe/d. Financial Reporting Update Capital disclosures The CICA issued a new accounting standard, Section 1535 "Capital Disclosures", which requires the disclosure of both qualitative and quantitative information that provides users of financial statements with information to evaluate the entity's objective, policies and processes for managing capital. This new section is effective for the Trust beginning January 1, 2008. Refer to note 15 of the financial statements for additional disclosure for this new section. Financial instruments Two new accounting standards were issued by the CICA, Section 3862 "Financial Instruments - Disclosures", and Section 3863 "Financial Instruments - Presentation". These sections will replace Section 3861 "Financial Instruments - Disclosure and Presentation" once adopted. The objective of Section 3862 is to provide users with information to evaluate the significance of the financial instruments on the entity's financial position and performance, the nature and extent of risks arising from financial instruments, and how the entity manages those risks. The provisions of Section 3863 deal with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These new sections are effective for the Trust beginning January 1, 2008. The additional disclosures required under these sections are included in note 15 of the financial statements. Goodwill and intangible assets In February 2008, the CICA issued a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and Other Intangible Assets, and Section 3450 - Research and Development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The section is effective for the Trust beginning January 1, 2009. Application of the new section is not currently expected to have any impact on the Trust's financial statements. International Financial Reporting Standards ("IFRS") On February 13, 2008 the CICA Accounting Standards Board announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards ("IFRS"), which will replace Canadian generally accepted accounting principles ("GAAP") for years beginning on or after January 1, 2011. True is monitoring industry discussion regarding the replacement of the CICA's Accounting Guideline 16, which is expected to have major implications for True's current full cost accounting policies. Currently, we are assessing the effects of adoption and developing a plan accordingly. We will continue to monitor any changes in the adoption of IFRS and will update plans as necessary. Business Risks and Uncertainties The reader is advised that True continues to be subject to various types of business risks and uncertainties as described in the Management Discussion and Analysis for the year ended December 31, 2007 or the Trust's Annual Information Form. In addition, the Trust is also subject to the following business risks and uncertainties: Environmental Regulations and Risks All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. The Federal government has introduced legislation aimed at reducing greenhouse gas emissions using a "intensity based" approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or as otherwise determined could have a material impact on the nature of oil and natural gas operations, including those of the Trust. In Alberta, the reduction emission guidelines outlined the Climate Change and Emissions Management Amendment Act (the "Act") came into effect July 1, 2007. Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12 per cent. Industries have three options to choose from in order to meet the reduction requirements outlined in the Act, and these are: (a) by making improvement to operations that result in reductions; (b) by purchasing emission credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emissions; or (c) by contributing to the In January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta's projected 400 million tonnes of emissions in half by 2050. This plan is based on three areas: (i) carbon capture and storage, which will be mandatory for in situ oil sand facilities that use heavy fuels for steam generation; (ii) energy conservation and efficiency; and (iii) greening production through increased investment in clean energy technology, including supporting research on new oil sands extraction processes, as well as the funding of projects that reduce the cost of separating CO(2) from other emissions supporting carbon capture and storage. The Government of Canada and the Province of Alberta released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and targeting research to lower the cost of technology. On March 10, 2008, the Government of Canada released "Turning the Corner - Taking Action to Fight Climate Change" (the "Updated Action Plan") which provides some additional guidance with respect to the Government's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. Details of the Updated Action Plan are provided in the Trust's Annual Information Form for the year ended December 31, 2007. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on the Trust and its operations and financial condition. Alberta Royalty Regime On October 25, 2007, the Alberta Government announced its intent to increase royalty rates commencing on January 1, 2009. As of December 31, 2007, the province had not introduced the enabling legislation nor had they provided enough clarity on a number of issues for the Trust's independent reserves evaluator, Since the foregoing sensitivity was prepared, the Alberta Government has announced new royalty incentives for deep, high-cost drilling. The incentives will apply to oil exploration wells and to both development and exploration gas wells. This initiative provides some relief to the recently introduced NRF. On the oil side, a royalty credit of up to $1 million will pertain to exploration wells drilled below 2,000m. Gas wells drilled below 2,500m qualify for credits with no distinction for development versus exploration wells drilled from 2,500m-4,000m. Overall, the deep royalty credits are a modest positive for the industry with a more significant impact for producers that target deep and prolific gas wells at a depth greater than 4,000m. The impact of these new incentives is not expected to be significant to True. The majority of True's current Alberta wells are in the 500m to 1,000m depth range and typically produce at lower rates. The overall impact of the NRF, as currently announced, is mitigated by the Trust's current Saskatchewan properties and the lower shallow gas Alberta natural gas rate royalty production in True's Alberta conventional oil and gas production portfolio. The NRF will impact future drilling decisions in order for the Trust to maintain acceptable rates of return on its capital deployed. Critical Accounting Estimates The reader is advised that the critical accounting estimates, policies, and practices as described in the Management Discussion and Analysis for the year ended December 31, 2007 continue to be critical in determining True's unaudited financial results as at June 30, 2008. Except as described in note 3 of the attached unaudited interim consolidated financial statement, there were no changes in accounting policies for the six month period ended June 30, 2008 Legal, Environmental Remediation and Other Contingent Matters The Trust reviews legal, environmental remediation and other contingent matters to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. The Trust's management monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by the circumstances. Controls and Procedures Disclosure Controls and Procedures Disclosure controls and procedures have been designed to provide reasonable assurance that material information relating to the Trust, including its consolidated subsidiaries, is made known to the Trust's Chief Executive Officer and Chief Financial Officer by others within those entities, particularly during the period in which the annual and interim filings are being prepared. Internal Controls over Financial Reporting The Trust's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements for external purposes in accordance with the Canadian GAAP. The Trust's Chief Executive Officer and Chief Financial Officer are required to cause the Trust to disclose herein any change in the Trust's internal control over financial reporting that occurred during the Trust's most recent interim period that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. No material changes in the Trust's internal control over financial reporting were identified during the three months ended June 30, 2008, that has materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting. It should be noted that a control system, including the Trust's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. Standardized Distributable Cash The Canadian Securities Administrators revised and re-issued in July 2007 National Policy 41-201 "Income Trusts and Other Indirect Offerings", which includes disclosures regarding distributable cash for Income Trusts. Further, the |
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