TSX: TUI.UN
CALGARY, Aug. 6 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True,"
"Company" or the "Trust") announces its financial and operating results for
the three and six months ended June 30, 2009.HIGHLIGHTS
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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
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FINANCIAL (unaudited)
(CDN$000s except unit
and per unit amounts)
Revenue (before
royalties and
hedging(1)) 29,805 82,074 61,150 152,107
Funds flow from
operations(2) 10,765 26,304 17,254 50,537
Per basic trust
unit $ 0.14 $ 0.33 $ 0.22 $ 0.64
Per diluted trust
unit(7) $ 0.14 $ 0.33 $ 0.22 $ 0.64
Net loss (99,715) (21,374) (108,771) (39,995)
Per basic trust
unit $ (1.27) $ (0.27) $ (1.39) $ (0.50)
Per diluted trust
unit(7) $ (1.27) $ (0.27) $ (1.39) $ (0.50)
Distributions declared - 9,505 1,570 19,012
Per unit - $ 0.12 $ 0.02 $ 0.24
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Exploration and
development 1,028 3,475 3,556 11,759
Corporate and property
acquisitions 123 605 351 971
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Capital expenditures
- cash 1,151 4,080 3,907 12,730
Property dispositions
- cash (8,289) (38,530) (8,281) (44,318)
Other - non-cash (1,107) (2,521) (1,221) (2,714)
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Total capital
expenditures - net (8,245) (36,971) (5,595) (34,302)
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Long-term debt 120,205 125,458 120,205 125,458
Convertible debentures(3) 82,075 80,253 82,075 80,253
Working capital excess (5,563) (16,357) (5,563) (16,357)
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Total net debt(3) 196,717 189,354 196,717 189,354
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Pro-forma total net
debt after
Divestiture(4) 111,717 N/A 111,717 N/A
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Total assets 562,854 793,883 562,854 793,883
Unitholders' equity 296,443 404,062 296,443 404,062
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OPERATING
Daily sales volumes
Crude oil,
condensate
and NGLs (bbls/d) 3,816 4,170 3,821 4,506
Natural gas (mcf/d) 35,703 46,515 36,312 49,383
Total oil
equivalent (boe/d) 9,767 11,922 9,873 12,737
Average prices
Crude oil,
condensate
and NGLs ($/bbl) 53.55 103.14 45.16 86.19
Crude oil,
condensate
and NGLs
(including
hedging(1)) ($/bbl) 53.55 82.56 45.16 71.50
Natural gas ($/mcf) 3.40 9.94 4.42 8.90
Natural gas
(including
hedging(1)) ($/mcf) 5.18 8.80 5.70 8.37
Total oil
equivalent ($/boe) 33.34 74.85 33.72 64.99
Total oil
equivalent
(including
hedging(1)) ($/boe) 39.85 63.22 38.43 57.76
Statistics
Operating
netback(5) ($/boe) 12.52 42.66 11.16 35.54
Operating
netback(5)
(including
hedging(1)) ($/boe) 19.03 31.01 15.87 28.30
Transportation ($/boe) 1.42 2.28 1.58 1.43
Production
expenses ($/boe) 13.41 14.90 14.47 14.31
General &
administrative ($/boe) 2.90 4.14 3.03 3.56
Royalties as a
% of sales after
Transportation 19% 21% 20% 22%
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TRUST UNITS
Trust units
outstanding 78,496,581 79,095,460 78,496,581 79,095,460
Trust unit incentive
rights outstanding 4,234,632 5,006,079 4,234,632 5,006,079
Units issuable for
exchangeable shares 312,467 347,254 312,467 347,254
Units issuable for
convertible
debentures(6) 5,390,625 5,390,625 5,390,625 5,390,625
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Diluted trust units
outstanding 88,434,305 89,839,418 88,434,305 89,839,418
Diluted weighted
average trust
units(7) 78,496,581 79,203,976 78,496,581 79,213,532
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TRUST UNIT TRADING STATISTICS
(CDN$, except volumes) based
on intra-day trading
High 1.08 4.69 1.56 4.69
Low 0.66 3.54 0.48 2.94
Close 0.77 4.40 0.77 4.40
Average daily volume 123,853 266,304 147,289 261,833
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(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.
The Trust does not apply 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 cash flow from operating activities and funds
flow from operations 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, current portion
of long-term debt and short-term future income tax assets and
liabilities. Total net debt also includes the liability component of
convertible debentures and excludes asset retirement obligations and
the future income tax liability.
(4) Pro-forma total net debt after Divestiture is calculated as total net
debt as of June 30, 2009, reduced by $85 million of net proceeds,
after purchase adjustments and estimated closing costs, received from
the divestiture of properties in Saskatchewan and others as disclosed
further herein.
(5) Operating netbacks are calculated by subtracting royalties,
transportation, and operating costs from revenues.
(6) Units issuable for convertible debentures are calculated as the
$86.25 million principal amount of the convertible debentures
divided by the conversion price of $16.00 per unit available to
debenture holders.
(7) In computing weighted average diluted earnings per trust unit and
weighted average diluted funds flow from operations for both the
three and six month periods ended June 30, 2009 a total of 4,234,632
(2008: 5,006,079) trust incentive units, 312,467 (2008: 347,254)
exchangeable shares and 5,390,625 (2008: 5,390,625) trust units
issuable pursuant to the conversion of convertible debentures were
excluded from the calculation of diluted earnings per trust unit
and weighted average diluted funds flow from operations as they were
not dilutive.
REPORT TO UNITHOLDERSTrue is pleased to announce that significant progress had been
accomplished in the restructuring of the Trust through the first half of 2009.
The Trust now has a proven team of top tier professional management in all key
operational areas of the organization. The new team has over 175 years of
combined successful experience providing organic growth through full cycle
exploration, exploitation and development.
The cost control strategy implemented at the start of Q1 2009 is on
target through the second quarter with both operating expenses and G&A
expenses meeting budgets, which represent cuts in excess of 30% from 2008
levels. Production levels have been maintained by diligent field optimization
programs designed to arrest decline. Sales volumes averaged 9,767 boe/d in the
second quarter in spite of plant turnarounds in late May and June and a one
time negative accounting adjustment of 261 boe/d. For the first half of 2009
sales volumes averaged 9,873 boe/d.
As of June 30, 2009, year to date capital expenditures totalled $3.9
million. True will maintain its $15 million capital budget for 2009 with the
drilling program to be initiated in August. Capital constraints will remain in
place until improved commodity pricing is demonstrated.
The highly leveraged balance sheet has been addressed through a series of
asset transactions designed to reduce bank indebtedness, thereby providing
True with the ability to move forward with substantially improved financial
flexibility. These efforts include:- On July 8, 2009, True announced the divestiture of a majority of its
oil and natural gas assets in Saskatchewan for gross proceeds of
$93 million effective May 1, 2009 (the "Divestiture"). On July 30,
2009 True closed the Divestiture for net proceeds, after purchase
adjustments, of approximately $86 million. The purchase adjustments
of approximately $7 million include net operating income, prepaid and
other items for the interim period from May 1, 2009 to July 30, 2009.
The Divestiture excludes the Saskatchewan properties of Cypress and
Mantario. True's interest to the base Belly River in three sections
in the Ferrier area of West Central Alberta were also disposed of in
the transaction. The assets sold include production estimated to
average 3,000 boe/d in Q3 and Q4 in 2009, including 5.3 mmcf/d of
natural, 128 km(2) of 3D proprietary seismic with 389.7 km of 2D
proprietary seismic, subject to a royalty free license on the seismic
in favor of True, and 63,333 net acres of undeveloped mineral leases.
- In a separate transaction, on June 30, 2009, True sold 145 boe/d,
including 0.63 mmcf/d of natural gas, in the Penhold Area of Central
Alberta for $4.7 million, after purchase adjustments and estimated
closing costs. In addition, in June 2009, True closed on the
disposition of certain royalty interests for approximately
$3.7 million, after purchase adjustments and estimated closing costs
to undisclosed buyers. The proceeds from these two dispositions were
also used to reduce True's bank indebtedness.
- True's total net debt as of July 31, 2009 after completion of the
dispositions, excluding an unrealized commodity contract asset of
$13.8 million, future income taxes and asset retirement obligations
is approximately $110 million, being approximately $28 million in net
debt outstanding on the credit facility including working capital
adjustments and $82 million in convertible debentures (liability
component).
- After completion of the divestitures, True's production is forecast
to be approximately 6,500 boe/d, comprised of 31.7 mmcf/d of natural
gas and 1,230 bbls/d of light/medium oil. True is forecasting a 2009
average production rate of 8,100 boe/d and a 2009 production exit
rate of 7,000 boe/d based on normal decline rates and risked
production adds from True's capital program.
- Upon completion of the divestitures, 65% of True's natural gas
production for Q3 - Q4 2009 is forward sold for an average of
$7.26 CAD/mcf and 21.5% of Q1 - Q2 2010 natural gas production hedged
at an average of $7.96 CAD/mcf. In addition, 500 bbl/d of oil for
Q3 - Q4 is hedged by way of a costless collar of $52.30 CAD x $80.70
CAD. As a result of these hedges, on a go forward basis True has
approximately 61% of total 2009 production protected through the
remainder of 2009.
- On July 30, 2009, in conjunction with completion of the Divestiture,
True negotiated a new banking syndicate commitment to replace the
existing facility, subject to finalization and execution of a
mutually acceptable credit agreement, that will provide True with a
credit facility of $85 million. The facility will consist of a
$10 million demand operating facility provided by one Canadian bank
and a $75 million extendible revolving term credit facility
syndicated by one Canadian chartered bank and one Canadian financial
institution. As of July 31, 2009 there was approximately $28 million
drawn on True's existing facility.
The second quarter of 2009 featured continued erosion of natural gas
pricing primarily as a result of the supply demand imbalance associated with
the persistent global economic recession. Second quarter financial results
include:
- Funds flow from operations for the second quarter of 2009 was
$10.8 million on gross sales of $29.8 million compared to funds flow
from operations for the first quarter of 2009 of $6.5 million on
gross sales of $31.3 million.
- The net loss for the second quarter of 2009 was $99.7 million
compared to a net loss of $21.4 million for the same period in 2008
and a net loss of $9.1 million in the first quarter of 2009. The net
loss for Q2 2009 was primarily the result of a non-cash accounting
loss on petroleum and natural gas properties held for sale of
$114.2 million. This amount was calculated as the excess of the
historical net book value allocated to Saskatchewan oil and gas
property assets sold as compared to the expected total net proceeds
received on closing subsequent to quarter-end.
- True's total net debt including the liability component of its
convertible debentures, excluding unrealized commodity contract
assets and liabilities, future income taxes and asset retirement
obligations, as at June 30, 2009 was $196.7 million, as compared to
$213.9 million as at March 31, 2009. After completion of the
Saskatchewan asset divestiture on July 30, 2009, True's total net
debt has reduced to approximately $110.0 million.
- 2009 second quarter sales volumes averaged 9,767 boe/d compared to
9,981 boe/d in the first quarter of 2009. True initiated a production
optimization and maintenance program at the beginning of the year.
This program has not only arrested True's production decline through
the first and second quarters, but also increased overall
deliverability without drilling or recompleting wells.
- True's natural gas price for the second quarter of 2009, after
including hedging, was $5.18/mcf compared to $8.80/mcf for the same
period in 2008.
- Capital expenditures for the second quarter of 2009 were $1.2 million
which were funded by available cash flow.
- Following the receipt of net proceeds from the Divestiture closing on
July 30, 2009, the Trust and operating subsidiaries of the Trust are
anticipated to have approximately $391 million in tax pools for
deduction against future income.True's latest forecast for 2009, as updated for June 30, 2009 year to
date results, recent disposition activity and further assumptions including
production volumes of 6,500 boe/d for August to December 2009, a CAD$/US$
exchange rate of $0.90, and a WTI oil price of US$70.00 and AECO natural gas
price of CAD$4.50/mcf for the third and fourth quarters of 2009, generates
estimated cash flow from operations for fiscal 2009 of $38 million.
True's drilling program for the third and fourth quarters has commenced
with plans to participate in up to 20 wells operated by True to take advantage
of the Alberta Government Royalty incentive program. True's drilling program
is targeting oil in Mantario, Saskatchewan and natural gas in Alberta
including up to three Notikewan horizontal well tests in West Central Alberta.
True's total capital expenditure program for the 3rd and 4th quarters is
anticipated to be approximately $11.1 million.
Upon closing of the recent dispositions, True continues to have
approximately 274,000 net acres of undeveloped land with 320 exploitation
drilling opportunities identified representing over 5 years of drilling
inventory. With the Trust's improved financial flexibility, True plans to move
forward with an organic growth model coupled with an M&A mandate to seek
opportunities to consolidate assets that complement its focused asset base
either through geographic fit, technical expertise or future development
potential.Raymond G. Smith, P. Eng.
President and CEO
August 6, 2009
MANAGEMENT'S DISCUSSION AND ANALYSISAugust 6, 2009 - The following Management's Discussion and Analysis of
financial results as provided by the management of True Energy Trust ("True"
or the "Trust") should be read in conjunction with the unaudited interim
consolidated financial statements and selected notes for the three and six
months ended June 30, 2009 and the audited consolidated financial statements
of the Trust for the years ended December 31, 2008 and 2007 and the related
Management's Discussion and Analysis of financial results. This commentary is
based on information available to, and is dated as of, August 6, 2009. The
financial data presented is in accordance with Canadian generally accepted
accounting principles ("GAAP") in Canadian dollars, except where indicated
otherwise.
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 cash flow from operating activities and funds
flow from operations 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 total net debt and operating netbacks, which are not recognized measures
under Canadian GAAP. Total net debt is calculated as long-term debt plus the
liability component of the convertible debentures and the net working capital
deficiency (excess) before short-term commodity contract assets and
liabilities, current portion of long-term debt and short-term future income
tax assets and liabilities. Operating netbacks are calculated by subtracting
royalties, transportation, and operating expenses from revenues. 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 expenses. 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 and tie-in plans and the timing thereof, plans
regarding wells to be drilled, expected or anticipated average and exit
production rates, hedging strategies, anticipated liquidity of the Trust and
various matters that may impact such liquidity, planned reductions in
operating expenses in 2009 and expected operating expenses, expected
production and transportation expenses and general and administrative
expenses, expected levels of revenues and operating expenses and operating
netbacks in 2009 compared to 2008, the expected effect of dispositions on debt
to funds flow ratios, the effect of the SIFT tax on cash flow levels, the use
of forecast funds flow from operations, the proportion of distributions
anticipated to be 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. Included herein is an estimate of True's cash flow from operations
in 2009 and the percentage that 2009 assumed distributions and its planned
capital budget will be of such estimated funds flow from operations. Such
recent financial outlook was approved by management of the Trust on July 8,
2009 and such financial outlook is included herein to provide an assessment of
the ability of the Trust to generate the cash necessary to fund future capital
investments after assumed distributions and to repay debt. 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.
Overview and Description of the Business
True Energy Trust is a Canadian trust, formed in 2005 via the reverse
takeover of TKE Energy Trust. The Trust is involved in the exploration,
development and production of petroleum and natural gas in western Canada. The
Trust has a significant multi-year drilling inventory of locations in Alberta,
Saskatchewan and British Columbia.
True's Trust units and convertible debentures are listed on the Toronto
Stock Exchange under the symbols TUI.UN and TUI.DB, respectively.
Second Quarter 2009 Financial and Operational Results
Dispositions
The Trust's focus in 2009 has been on the restructuring and strengthening
of its balance sheet. The Trust had two minor dispositions in the quarter and
has successfully completed the divestiture of the majority of its petroleum
and natural gas properties in Saskatchewan subsequent to quarter end. Net
proceeds from the dispositions were used to reduce the Trust's bank
indebtedness; these strategic accomplishments will allow the Trust to progress
forward with substantially improved financial flexibility.
On June 30, 2009, True sold 145 boe/d, including 0.63 mmcf/d of natural
gas, in the Penhold Area of Central Alberta for $4.7 million, after purchase
adjustments and closing costs. In addition, in June 2009, True completed a
disposition of certain royalty interests for approximately $3.7 million, after
purchase adjustments and closing costs. The proceeds from these two
dispositions were used to reduce True's bank indebtedness.
On July 8, 2009, True announced the divestiture of a majority of its
petroleum and natural gas properties in Saskatchewan (the "Saskatchewan
Divestiture") for gross proceeds of $93 million effective May 1, 2009. The
Saskatchewan Divestiture excludes the Saskatchewan properties of Mantario and
Cypress. True's interest to the base Belly River in three sections in the
Ferrier area of West Central Alberta were also included in the divestiture
package. The transaction was successfully closed on July 30, 2009.
The assets subject to the Saskatchewan Divestiture have been classified
as held for sale under CICA handbook section 3475 - "Disposal of Long-lived
Assets and Discontinued Operations" as at June 30, 2009 and accounted for
under the guidance of Accounting Guideline 16 - "Oil and Gas Accounting - Full
Cost". Under full cost accounting, if crediting the proceeds from disposition
to costs results in a change of 20 percent or more to the DD&A rate then a
gain or loss should be recognized. When a gain or loss is to be recognized the
total net book value of capitalized costs should be allocated between the
properties sold and the properties retained. The assets held for sale as of
June 30, 2009 are an allocation of the Trust's historical full cost pool based
on a pro-rata ratio of future cash flows of proved reserves associated with
the assets held for sale, discounted at 10%, as compared to all oil and gas
assets. The Trust has recorded a $114.2 million non-cash loss on the assets
held for sale for the excess of the allocated net book value to these assets,
compared to the total estimated net proceeds, after purchase adjustments and
estimated closing costs, of $85 million. The purchase adjustments of
approximately $7 million include net operating income, prepaid and other items
for the interim period from May 1, 2009 to July 30, 2009.
Sales Volumes
Sales volumes for the three months ended June 30, 2009 averaged 9,767
boe/d compared to 11,922 boe/d for the same period in 2008, representing a 18%
decrease. In comparison, sales volumes for the first quarter of 2009 averaged
9,981 boe/d. Sales volumes for the six months ended June 30, 2009 averaged
9,873 boe/d as compared to 12,737 boe/d for the same period in 2008,
representing a 22% decrease.
The decrease in average sales volumes from second quarter 2008 to 2009 is
a result of natural production decline, minimal 2009 capital spending,
dispositions in the second quarter totaling approximately 145 boe/d and
dispositions totaling approximately 1,000 boe/d that were closed during the
second quarter of 2008, partially offset by tuck-in acquisitions completed in
the fourth quarter of 2008 that added approximately 250 boe/d. During the
first quarter of 2009, True implemented a full scale field optimization and
maintenance program throughout True's operated properties. The field
optimization programs were designed to arrest production declines and increase
overall deliverability without drilling or recompleting wells; which is
evidenced by the second quarter average production volumes of 9,767 boe/d in
spite of plant turnarounds in late May and June.Sales Volumes
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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
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Natural gas (mcf/d) 35,703 46,515 36,312 49,383
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Heavy oil (bbls/d) 2,771 2,721 2,646 2,773
Light oil and
condensate (bbls/d) 680 1,116 818 1,253
NGLs (bbls/d) 365 333 357 480
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Total crude
oil and NGLs (bbls/d) 3,816 4,170 3,821 4,506
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Total boe/d (6:1) 9,767 11,922 9,873 12,737
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-------------------------------------------------------------------------During the second quarter of 2009, True did not participate in any
drilling.
For the three months ended June 30, 2009, the weighting towards natural
gas sales averaged 61% compared to 65% in the same period in 2008. Similarly,
for the six month period ended June 30, 2009, the weighting towards natural
gas sales averaged 61% compared to 65% for the same period in 2008. Heavy oil
sales made up 28% of total production for the 2009 second quarter compared to
23% in the 2008 second quarter. In comparison, heavy oil sales made up 25% of
total production for the 2009 first quarter.
Sales of natural gas averaged 35.7 Mmcf/d for the second quarter of 2009,
compared to 46.5 Mmcf/d in the same 2008 period, a decrease of 23%. Crude oil
and NGL sales for the 2009 second quarter decreased 8% averaging 3,816 bbls/d
compared to 2008 average sales of 4,170 bbls/d.
For August to December 2009, following completion of the Saskatchewan
Divestiture, production volumes are anticipated to average approximately 6,500
boe/d and a 2009 production exit rate of 7,000 boe/d. The forecast of 2009
production volumes has been updated from the 10,000 boe/d forecast previously
reported to include the recent disposition activity. The forecast is based on
a number of assumptions, including normal production declines and expenditures
under the current planned capital budget of $15 million.Commodity Prices
Average Commodity Prices
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Three months ended Six months ended
June 30, June 30,
% %
2009 2008 Change 2009 2008 Change
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Exchange rate (US$/Cdn$) 0.8570 1.0000 (14) 0.8291 0.9989 (17)
Natural gas:
NYMEX (US$/mmbtu) 3.81 11.47 (67) 4.13 9.99 (59)
AECO daily index
(CDN$/Mcf) 3.45 10.20 (66) 4.18 9.09 (54)
AECO monthly index
(CDN$/Mcf) 3.47 9.35 (63) 4.64 8.24 (44)
True's average price
($/mcf) 3.40 9.94 (66) 4.42 8.90 (50)
True's average price
(including hedging(1))
($/mcf) 5.18 8.80 (41) 5.70 8.37 (32)
Crude oil:
WTI (US$/bbl) 43.31 123.80 (65) 43.31 109.92 (61)
Edmonton par - light
oil ($/bbl) 66.16 126.37 (48) 58.16 112.30 (48)
Bow River - medium/heavy
oil ($/bbl) 61.69 103.98 (41) 52.73 90.74 (42)
Hardisty Heavy - heavy
oil ($/bbl) 58.07 96.34 (40) 48.72 83.20 (41)
True's average prices
($/bbl)
Light crude oil,
condensate, and NGLs 47.83 110.23 (57) 44.88 95.92 (53)
Heavy crude oil 55.71 99.37 (44) 45.29 80.11 (44)
Total crude oil and
NGLs 53.55 103.14 (48) 45.16 86.19 (48)
Total crude oil and
NGLs (including
hedging(1)) 53.55 82.56 (35) 45.16 71.50 (37)
-------------------------------------------------------------------------
(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 sales are priced with reference to the daily or
monthly AECO indices. During the 2009 second quarter, the AECO daily and
monthly reference price decreased by 66% and 63%, respectively, compared to
the same period in 2008. Similarly, True's average sales price before hedging
for the 2009 second quarter decreased by 66% compared to the same period in
2008. True's natural gas price after including hedging for the second quarter
of 2009 was $5.18/mcf compared to $8.80/mcf for the same period in 2008.
The Trust has entered into a natural gas physical delivery sales contract
to sell 5,275 GJ/day at a fixed price of $7.29/GJ and $7.90/GJ for the third
and fourth quarter of 2009, respectively.
For heavy crude oil, True received an average price before transportation
of $55.71/bbl in the 2009 second quarter, a decrease of 44% over prices in the
same period in 2008. The Bow River reference price and the Hardisty Heavy
reference price both decreased approximately 40% from the 2008 second quarter
to the 2009 second quarter. The majority of True's heavy crude oil density
ranges between 11 and 16 degrees API consistent with the Hardisty Heavy
reference price, although all of True's heavy oil production is sold at
Saskatchewan delivery points.
For light oil, condensate and NGLs, True recorded an average $47.83/bbl
before hedging in the 2009 second quarter, 57% lower than the average price of
$110.23/bbl received in the same period in 2008. In comparison, the Edmonton
par price decreased by 48% over the same period. The average WTI crude oil US
dollar based price decreased 65% from the second quarter of 2008 to that in
2009. The average US$/Cdn$ foreign exchange rate was 0.86 for the 2009 second
quarter compared to 1.0 during the same period in 2008. The negative
correlation between the Canadian dollar and U.S. dollar denominated WTI oil
prices has softened the impact on the Trust.
WTI crude oil prices varied greatly throughout 2008, increasing
significantly to a high of US$147/bbl in July and dramatically falling during
the fourth quarter of 2008 with December 2008 prices of under US$40/bbl and
averaging over US$40/bbl for the first and second quarters of 2009. The
pricing outlook in 2009 for crude oil and natural gas remains uncertain given
the current global economic environment.
Revenue
Revenue before other income and hedging for the three month period ended
June 30, 2009 was $29.6 million, 64% lower than the $81.2 million in the same
period in 2008. The decrease in revenue for the 2009 period was the result of
lower sales volumes in conjunction with significantly lower commodity prices.-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
Light crude oil,
condensate and NGLs 4,550 14,528 9,548 30,262
Heavy oil 14,046 24,608 21,689 40,426
-------------------------------------------------------------------------
Crude oil and NGLs 18,596 39,136 31,237 70,688
Natural gas 11,033 42,067 29,026 79,961
-------------------------------------------------------------------------
Total revenue before
other 29,629 81,203 60,263 150,649
Other(1) 176 871 887 1,458
-------------------------------------------------------------------------
Total revenue before
royalties and hedging 29,805 82,074 61,150 152,107
-------------------------------------------------------------------------
(1) Other revenue primarily consists of processing and other third party
income.Revenues for the remainder of 2009 are currently expected to be lower
than 2008 due to lower commodity prices and average estimated 2009 year
production of approximately 8,100 boe/d, after adjusting for divestitures
closed during the year.
Commodity Price Risk Management
The Trust has a formal risk management policy which permits management to
use specified price risk management strategies as determined by the board of
directors including fixed price contracts, collars and the purchase of floor
price options and other derivative financial instruments and physical delivery
sales contracts 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 funds flow from operations, 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
operations. Any remaining unhedged production is realized at market prices.
A summary of the financial hedge volumes and average prices by quarter
currently outstanding as of August 6, 2009 is shown in the following tables:Natural gas
Average Volumes (GJ/d)
-------------------------------------------------------------------------
Q3 2009 Q4 2009
-------------------------------------------------------------------------
Fixed 19,500 15,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q1 2010 Q2 2010 Q3 2010 Q4 2010
-------------------------------------------------------------------------
Fixed 10,000 5,000 - -
Call option (ceiling
price) 5,000 5,000 5,000 5,000
-------------------------------------------------------------------------
Total GJ/d 15,000 10,000 5,000 5,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average Price ($/GJ AECO C)
-------------------------------------------------------------------------
Q3 2009 Q4 2009
-------------------------------------------------------------------------
Fixed 5.97 6.75
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Q1 2010 Q2 2010 Q3 2010 Q4 2010
-------------------------------------------------------------------------
Fixed 7.58 6.59 - -
Call option (ceiling
price) 8.05 8.05 8.05 8.05
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Crude oil and liquids
Average Volumes (bbls/d)
-------------------------------------------------------------------------
Q3 2009 Q4 2009
-------------------------------------------------------------------------
Costless collars 500 500
-------------------------------------------------------------------------
Total bbls/d 500 500
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Average Price (CDN$/bbl WTI)
-------------------------------------------------------------------------
Q3 2009 Q4 2009
-------------------------------------------------------------------------
Collar ceiling price 80.70 80.70
Collar floor price 52.30 52.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------Included in the above natural gas table is a fixed price contract of
$5.90/GJ at 5,000 GJ/d from the second quarter 2009 to fourth quarter 2009
periods which was funded by selling a call option of 5,000 GJ/d at $8.05 for
the 2010 year.
As of June 30, 2009, the fair value of True's outstanding commodity
contracts is a net unrealized asset of $8.9 million as reflected in the
financial statements. The fair value or mark-to-market value of these
contracts is based on the estimated amount that would have been received or
paid to settle the contracts as at June 30, 2009 and may be different from
what will eventually be realized. Changes in the fair value of the commodity
contracts are recognized in the Consolidated Statements of Loss within the
financial statements.
The following is a summary of the gain (loss) on commodity contracts for
the three and six months ended June 30, 2009 and 2008 as reflected in the
Consolidated Statements of Loss in the financial statements:Commodity contracts
-------------------------------------------------------------------------
Crude Oil Natural Q2 2009 Q2 2008
($000s) & Liquids Gas Total Total
-------------------------------------------------------------------------
Realized cash gain
(loss) on contracts - 5,789 5,789 (12,619)
Unrealized gain (loss)
on contracts(1) (433) (2,271) (2,704) (25,550)
-------------------------------------------------------------------------
Total gain (loss) on
commodity contracts (433) 3,518 3,085 (38,169)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Crude Oil Natural YTD 2009 YTD 2008
($000s) & Liquids Gas Total Total
-------------------------------------------------------------------------
Realized cash gain
(loss) on contracts - 8,420 8,420 (16,761)
Unrealized gain (loss)
on contracts(1) (705) 5,845 5,140 (43,237)
-------------------------------------------------------------------------
Total gain (loss) on
commodity contracts (705) 14,265 13,560 (59,998)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 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, 2009, total royalties were $5.3
million, compared to $16.3 million incurred in the same period in 2008.
Overall royalties as a percentage of revenue (after transportation costs) in
the second quarter of 2009 were 19%, compared with 21% over the same period in
2008. Royalties for the six months ended June 30, 2009 were $11.6 million
compared to $31.8 million for the same period in 2008.-------------------------------------------------------------------------
Royalties by
Commodity Type Three months ended Six months ended
($000s, except June 30, June 30,
where noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
Light crude oil,
condensate and NGLs 1,222 2,897 2,583 6,663
$/bbl 12.84 21.98 12.14 21.12
Average light crude
oil, condensate and
NGLs royalty rate (%) 24 20 24 23
Heavy Oil 2,645 5,341 4,494 7,632
$/bbl 10.49 21.57 9.38 15.12
Average heavy oil
royalty rate (%) 20 23 22 20
Natural Gas 1,457 8,051 4,555 17,494
$/mcf 0.45 1.90 0.69 1.95
Average natural gas
royalty rate (%) 14 20 16 22
-------------------------------------------------------------------------
Total 5,324 16,289 11,632 31,789
-------------------------------------------------------------------------
$/boe 5.99 15.01 6.51 13.71
-------------------------------------------------------------------------
Average total royalty
rate (%) 19 21 20 22
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Royalties, by Type
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
Crown royalties 3,018 9,587 6,091 18,543
Freehold & GORR 1,230 4,848 3,078 9,711
Indian Oil and Gas
Canada royalties 784 1,854 1,973 3,535
Saskatchewan resource
surcharge 292 - 490 -
-------------------------------------------------------------------------
Total 5,324 16,289 11,632 31,789
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Expenses
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
Production 11,916 16,170 25,862 33,166
Transportation 1,267 2,478 2,830 3,321
General and
administrative 2,581 4,492 5,423 8,262
Interest and financing
charges 4,218 3,487 7,520 8,003
Unit-based compensation 243 160 (360) 429
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Expenses per boe
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($ per boe) 2009 2008 2009 2008
-------------------------------------------------------------------------
Production 13.41 14.90 14.47 14.31
Transportation 1.42 2.28 1.58 1.43
General and
administrative 2.90 4.14 3.03 3.56
Interest and financing
charges 4.75 3.21 4.21 3.45
Unit-based compensation 0.27 0.15 (0.20) 0.19
-------------------------------------------------------------------------Production Expenses
For the three months ended June 30, 2009, production expenses totaled
$11.9 million ($13.41/boe), compared to $16.2 million ($14.90/boe) recorded in
the same 2008 period. In comparison, production expenses were $13.9 million
($15.53/boe) in the first quarter of 2009 and $66.6 million ($15.33/boe) for
the 2008 annual period. For the six month period ended June 30, 2009,
production expenses totaled $25.9 million ($14.47/boe) compared to $33.2
million ($14.31/boe) for the same period in 2008.
True is targeting operating costs of approximately $39.6 million
($12.74/boe) in 2009 which based on assumptions of estimated 2009 annualized
production of approximately 8,100 boe/d, after considering completed
divestitures, planned cost reductions, and cost reductions due to disposition
of high operating cost properties. Forecasted cost reductions are on track
through to the second quarter of 2009.Production Expenses, by Commodity Type
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
where noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
Light crude oil,
condensate and NGLs 2,350 2,193 4,627 5,274
$/bbl 24.70 16.64 21.75 16.71
Heavy oil 3,412 5,808 8,148 10,843
$/bbl 13.53 23.45 17.01 21.49
Natural gas 6,154 8,169 13,087 17,049
$/mcf 1.89 1.93 1.99 1.90
-------------------------------------------------------------------------
Total 11,916 16,170 25,862 33,166
-------------------------------------------------------------------------
$/boe 13.41 14.90 14.47 14.31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total 11,916 16,170 25,862 33,166
-------------------------------------------------------------------------
Processing and other
third party income(1) (176) (871) (887) (1,458)
-------------------------------------------------------------------------
Total after deducting
processing and other
third party income 11,740 15,299 24,975 31,708
-------------------------------------------------------------------------
$/boe 13.21 14.10 13.98 13.68
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Processing and other third party income is included within petroleum
and natural gas sales on the statement of income.Transportation
Transportation expenses for the three month period ended June 30, 2009
were $1.3 million ($1.42/boe) compared to $2.5 million ($2.28/boe) in the same
2008 period. In comparison, transportation was $1.74/boe in the first quarter
of 2009 and $1.62/boe 2008 annual periods, respectively.
Operating Netback
For the second quarter of 2009, corporate field operating netback (before
hedging) was $12.52/boe compared to $42.66/boe in the same period in 2008.
This was the result of decreased overall commodity prices, offset somewhat by
lower transportation, royalties and operating expenses. By comparison,
corporate field operating netback (before hedging) for the first quarter of
2009 was $9.81/boe. After including hedging activities, the corporate field
operating netback for the second quarter of 2009 was $19.03/boe compared to
$31.01/boe in the same 2008 period.Field Operating Netback - Corporate (before hedging)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($/boe) 2009 2008 2009 2008
-------------------------------------------------------------------------
Sales 33.34 74.85 33.72 64.99
Transportation (1.42) (2.28) (1.58) (1.43)
Royalties (5.99) (15.01) (6.51) (13.71)
Production expense (13.41) (14.90) (14.47) (14.31)
-------------------------------------------------------------------------
Field operating netback 12.52 42.66 11.16 35.54
-------------------------------------------------------------------------
-------------------------------------------------------------------------Overall, corporate operating netbacks for 2009 are currently expected to
be lower than 2008 due to anticipated lower commodity prices.
Field operating netback for natural gas in the second quarter of 2009
decreased 85% to $0.85/mcf, compared to $5.77/mcf in the same 2008 period,
primarily reflecting weakening natural gas prices experienced. After including
hedging activities, field operating netback for natural gas in the three
months ended June 30, 2009 was $2.63/mcf compared to $4.62/mcf in the same
period in 2008.Field Operating Netback - Natural Gas (before hedging)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($/mcf) 2009 2008 2009 2008
-------------------------------------------------------------------------
Sales 3.40 9.94 4.42 8.90
Transportation (0.21) (0.34) (0.20) (0.11)
Royalties (0.45) (1.90) (0.69) (1.95)
Production expense (1.89) (1.93) (1.99) (1.90)
-------------------------------------------------------------------------
Field operating netback 0.85 5.77 1.54 4.94
-------------------------------------------------------------------------
-------------------------------------------------------------------------Field operating netback for crude oil, condensate and NGLs averaged
$24.11/bbl in the second quarter of 2009, representing a 58% decrease from the
second quarter 2008 operating netback of $57.65/bbl. This compares to a 48%
decrease in the crude oil, condensate and NGLs sales price. After including
hedging activities, field operating netback for crude oil and NGLs in the 2009
second quarter was $24.11/boe compared to $37.08/boe in the same period in
2008.Field Operating Netback - Crude Oil, Condensate and NGLs (before hedging)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($/bbl) 2009 2008 2009 2008
-------------------------------------------------------------------------
Sales 53.55 103.14 45.16 86.19
Transportation (1.72) (2.69) (2.15) (2.83)
Royalties (11.13) (21.71) (10.23) (17.43)
Production expense (16.59) (21.09) (18.47) (19.65)
-------------------------------------------------------------------------
Field operating netback 24.11 57.65 14.31 46.28
-------------------------------------------------------------------------
-------------------------------------------------------------------------General and Administrative
Net general and administrative ("G&A") expenses for the three and six
months ended June 30, 2009 were $2.6 million and $5.4 million, respectively,
compared to $4.5 million and $8.3 million, respectively for the same period in
2008. The decrease in the G&A expense for the 2009 periods compared to the
2008 periods is primarily due to targeted G&A reductions completed in January
2009. True streamlined its operations and reduced head office staffing levels
by one third in January 2009. The reduction in amounts of capitalized G&A for
the 2009 first and second quarter is consistent with a lower capital program.
On a per boe basis, G&A expenses for the three and six months ended June 30,
2009 were $2.90/boe and $3.03/boe, respectively, compared to $4.14/boe and
$3.56/boe, respectively, for the same period in 2008. In comparison, G&A
expenses were $2.8 million or $3.16/boe for the first quarter of 2009.General and Administrative Expenses
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
where noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
Gross expenses 3,178 5,508 6,564 10,387
Capitalized (106) (692) (212) (1,199)
Recoveries (491) (324) (929) (926)
-------------------------------------------------------------------------
Net G&A expenses 2,581 4,492 5,423 8,262
-------------------------------------------------------------------------
Net G&A expenses,
per unit ($/boe) 2.90 4.14 3.03 3.56
-------------------------------------------------------------------------
-------------------------------------------------------------------------Interest and Financing Charges
True recorded $4.2 million of interest and financing charges for the
three months ended June 30, 2009 compared to $3.5 million in the same period
in 2008. For the six months ended June 30, 2009, interest and financing
charges totaled $7.5 million compared to $8.0 million for the same period in
2008. True's total net debt at June 30, 2009 of $196.7 million includes the
$82.1 million liability portion of convertible debentures, $120.2 million of
bank debt and the net balance of a working capital surplus. The convertible
debentures have a maturity date of June 30, 2011.Interest and Financing Charges
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
where noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
Interest and financing
charges 4,218 3,487 7,520 8,003
Interest and financing
charges ($/boe) 4.75 3.21 4.21 3.45
Debt to funds flow
from operations ratio
(annualized)(2)
Total net debt(1) at
quarter end 196,717 189,354 196,717 189,354
Total net debt to
periods funds flow
from operations ratio
(annualized) 4.6x 1.8x 5.7x 1.9x
Net debt(1) (excluding
convertible debentures)
at quarter end 114,642 109,101 114,642 109,101
Net debt to periods
funds flow from
operations ratio
(annualized)(2) 2.7x 1.1x 3.3x 1.1x
Debt to funds flow
from operations
ratio (trailing)(3)
Total net debt to
periods funds flow
from operations ratio
(trailing) 3.2x 2.2x 3.2x 2.2x
Net debt to periods
funds flow from
operations ratio
(trailing) 1.8x 2.0x 1.8x 2.0x
-------------------------------------------------------------------------
(1) Net debt includes the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities, current portion
of long-term debt and short-term future tax assets and liabilities.
Total net debt also includes the liability component of convertible
debentures and excludes asset retirement obligations and the future
income tax liability.
(2) Total net debt and net debt to periods funds flow from operations
ratio (annualized) is calculated based upon annualizing funds flow
from operations for the three and six month periods ended June 30,
2009, respectively.
(3) Trailing periods funds flow from operations is based on the trailing
twelve month period ended June 30, 2009 and 2008.These ratios for the remainder of 2009 are expected to be lower following
reduction to bank indebtedness associated with the Saskatchewan Divestiture
closing on July 30, 2009.
Unit-Based Compensation
Non-cash unit-based compensation expense for the six month period ended
June 30, 2009 was a recovery of $0.4 million compared to expense of $0.4
million in 2008. The decrease in the expense for the six month period ended
June 30, 2009 reflects a reduction in the estimated weighted average fair
value of incentive rights granted for more recent options, and a reduction to
the 2009 expense of $0.7 million for a reversal of prior year unit-based
compensation expense for 2009 forfeitures of unvested incentive rights.
Depletion, Depreciation and Accretion
Depletion, depreciation and accretion expense for the three months ended
June 30, 2009 was $27.4 million ($30.80/boe), compared to the $33.2 million
($30.61/boe) in the same period in 2008, which reflects lower production
volumes combined with reduced carrying costs in the 2009 period as compared to
2008.
For the three months ended June 30, 2009, True has included $62.5 million
for future development costs in the depletion calculation and excluded from
the depletion calculation $26.6 million for undeveloped land and $37.9 million
for estimated salvage.Depletion, Depreciation and Accretion Costs
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
where noted) 2009 2008 2009 2008
-------------------------------------------------------------------------
Depletion and
Depreciation 26,714 32,696 53,307 68,444
Accretion 660 513 1,322 1,068
-------------------------------------------------------------------------
Total 27,374 33,209 54,629 69,512
-------------------------------------------------------------------------
Per unit ($/boe) 30.80 30.61 30.57 29.99
-------------------------------------------------------------------------
-------------------------------------------------------------------------Income Taxes
For the six months ended June 30, 2009, the Trust has recorded no capital
tax expense compared to $1.1 million expensed in the same period in 2008.
Prior to January 1, 2009, capital taxes were based on a combination of debt
and equity levels of the Trust at the end of the year in addition to a
resource surcharge component of Saskatchewan provincial taxes calculated as a
percentage of revenues. Effective for True's 2009 taxation year, this
Saskatchewan tax has been changed such that it is calculated solely as a
percentage of revenues. Accordingly, this Saskatchewan tax is grouped with
royalties on a prospective basis.
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,
2009, the Trust recognized a future income tax recovery of $38.3 million
compared to a recovery of $23.3 million in the same period in 2008.
Under our current structure, the operating entities may 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. Alternatively, the Trust's operating company may claim discretionary
tax deductions to reduce taxable income. Under the SIFT tax (as defined and
referred to below), 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 discretionary tax deductions 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 at
least equal to 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 for
non-resident holders, would be required under the trust indenture.
The SIFT tax 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 22, 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
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 in 2007 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 2006 and 2011 without
prematurely triggering the SIFT tax.
In June 2008, Bill C-50, which contained legislation to adjust the deemed
provincial component of the SIFT tax on distributions from SIFTs expected to
apply to the Trust commencing in 2011, received Royal Assent. Under
regulations now enacted, 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 the pro rata of:- 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.Under the regulations, 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%. As of March 4, 2009, the regulations are substantively
enacted.
On July 14, 2008, the Department of Finance released proposed amendments
(the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the
conversion of existing SIFTs into corporations. In general, the proposed
amendments will permit a conversion to be tax deferred for both the
unitholders and the SIFT if completed before 2013. These rules were
subsequently revised and introduced as part of Bill C-10 as part of the Budget
Implementation Act, 2009 on February 6, 2009 and received Royal Assent on
March 12, 2009.
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:- If structural or other similar changes are not made if and to the
extent that the Trust makes distributions to unitholders, 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;
- If and to the extent that the Trust makes distributions to
unitholders, 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 continued 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 discretionary tax deductions and, if and to the extent
that it reinstates the payments of distributions, pay all or a
portion of its distributions (if any) on a return of capital basis,
likely at a lower payout ratio.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 review these issues.
As at June 30, 2009, the operating subsidiaries and the Trust itself have
a total net future income tax liability balance of $5.7 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, 2009, the Trust and operating subsidiaries of the Trust had
approximately $476 million in tax pools available for deduction against future
income as follows:-------------------------------------------------------------------------
Operating
($000s) Trust subsidiaries Total
-------------------------------------------------------------------------
Intangible resource pools 15,000 306,000 321,000
Undepreciated capital cost - 123,000 123,000
Loss carryforwards (expire through 2027) - 30,000 30,000
Unit issue costs 2,000 - 2,000
-------------------------------------------------------------------------
17,000 459,000 476,000
-------------------------------------------------------------------------Following the receipt of net proceeds from the Divestiture closing on
July 30, 2009, the Trust and operating subsidiaries of the Trust are
anticipated to have approximately $391 million in tax pools for deduction
against future income.
Net Loss and Funds Flow from Operations
True generated funds flow from operations of $10.8 million ($0.14 per
diluted unit) for the three month period ended June 30, 2009, down 59% from
$26.3 million ($0.33 per diluted unit) for the second quarter of 2008. The
decrease in funds flow for the 2009 period compared to the same period in 2008
was primarily the result of a significant decrease in commodity prices, in
combination with lower sales volumes. Funds flow from operations for the
second quarter of 2009 increased 66% from first quarter 2009 funds flow from
operations of $6.5 million. Funds flow from operations for the six month
period ended June 30, 2009 was $17.3 million ($0.22 per diluted unit), down
from the $50.5 million ($0.64 per diluted unit) for the same period in 2008.
True maintains a commodity price risk management program to provide a
measure of stability to funds flow from operations. 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
loss.
True generated a net loss of $99.7 million ($1.27 per diluted unit) in
the second quarter of 2009 compared to a net loss of $21.4 million ($0.27 per
diluted unit) in 2008. The increase in the net loss is primarily a result of
the $114.2 million non-cash accounting loss recorded on the assets held for
sale.Funds Flow From Operations and Net Loss
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except per June 30, June 30,
unit amounts) 2009 2008 2009 2008
-------------------------------------------------------------------------
Funds flow from
operations 10,765 26,304 17,254 50,537
Basic ($/unit) 0.14 0.33 0.22 0.64
Diluted ($/unit) 0.14 0.33 0.22 0.64
Net loss (99,715) (21,374) (108,771) (39,995)
Basic ($/unit) (1.27) (0.27) (1.39) (0.50)
Diluted ($/unit) (1.27) (0.27) (1.39) (0.50)
-------------------------------------------------------------------------
Reconciliation of Cash Flow from Operating Activities and Funds Flow from
Operations
-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except per June 30, June 30,
unit amounts) 2009 2008 2009 2008
-------------------------------------------------------------------------
Cash flow from
operating activities 6,467 19,892 15,778 37,735
Asset retirement costs
incurred 313 123 1,051 712
Change in non-cash
working capital 3,985 6,289 425 12,090
-------------------------------------------------------------------------
Funds flow from
operations 10,765 26,304 17,254 50,537
-------------------------------------------------------------------------
Capital Expenditures
True planned for a very modest capital program for the first half of 2009.
Second quarter 2009 capital spending was $1.2 million, as compared to $4.1
million for the same period in 2008.
Capital Expenditures
-------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
Lease acquisitions
and retention 225 415 308 965
Geological and
geophysical 40 (55) 51 12
Drilling and completion
costs 141 2,382 1,447 9,157
Facilities and
equipment 622 734 1,750 1,626
-------------------------------------------------------------------------
Exploration and
development(1) 1,028 3,475 3,556 11,759
Corporate and property
acquisitions 123 605 351 971
-------------------------------------------------------------------------
Total capital
expenditures - cash 1,151 4,080 3,907 12,730
Property dispositions
- cash (8,289) (38,530) (8,281) (44,318)
-------------------------------------------------------------------------
Total net capital
expenditures - cash (7,138) (34,450) (4,374) (31,588)
-------------------------------------------------------------------------
Other - non-cash(2) (1,107) (2,521) (1,221) (2,714)
-------------------------------------------------------------------------
Total net capital
expenditures(1) (8,245) (36,971) (5,595) (34,302)
-------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligation
expenditures incurred during the year.
(2) Other includes non-cash adjustments for current period's asset
retirement obligations and unit based compensation capitalized.The $1.2 million capital program for the three months ended June 30,
2009, was financed entirely with funds flow from operations.
Based on the current economic conditions and True's operating forecast
for the remainder of 2009, the Trust has budgeted a 2009 capital program of
$15 million and is anticipating capital expenditures of approximately $11.1
million for the remainder of 2009. True's drilling program for the third and
fourth quarters has commenced with plans to participate in up to 20 wells
operated by True to take advantage of the Alberta Government Royalty incentive
program. True's drilling program is targeting oil in Mantario, Saskatchewan
and natural gas in Alberta including up to three Notikewan horizontal well
tests in West Central Alberta.
Land
True's net mineral leases in Alberta, British Columbia and Saskatchewan
as of June 30, 2009 decreased to approximately 338,000 net acres from 358,000
net acres established on March 31,2009. Upon closing of the recent
dispositions, True continues to have approximately 274,000 net acres of
undeveloped land with 320 exploitation drilling opportunities identified
representing over 5 years of drilling inventory.
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 Canadian Institute of Chartered
Accountants ("CICA") AcG-16 "Oil and Gas Accounting - Full Cost", a two step
process.
The Trust performed a ceiling test calculation at June 30, 2009 resulting
in undiscounted cash flows from proved reserves and the undeveloped properties
not exceeding the carrying value of oil and gas assets. Consequently, True
performed stage two of the ceiling test assessing whether discounted future
cash flows from production of proved plus probable reserves plus the carrying
cost of undeveloped properties, net of any impairment allowance, exceeds the
carrying value of its petroleum and natural gas properties. No impairment in
oil and gas assets was identified as at June 30, 2009.
The ceiling test calculation will be updated in 2009 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, 2009, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $33.7 million, compared to $26.3 million at June 30,
2008 for future abandonment and reclamation of the Trust's properties. For the
six months ended June 30, 2009, the overall ARO balance remained approximately
the same as a result of accretion expense of $1.3 million, $1.0 million net
changes in estimates and liabilities incurred on development activities,
offset by $1.3 million of liabilities released on dispositions and $1.0
million of liabilities settled. The asset retirement obligation associated
with the Saskatchewan Divestiture of $9.6 million has been classified as a
current liability.
Distributions
For the six months ended June 30, 2009 Trust declared distributions as
follows:-------------------------------------------------------------------------
($000s, except per unit amount) Distribution
Six months ended June 30, 2009 Per Unit Total
-------------------------------------------------------------------------
Distributions declared $ 0.02 $ 1,570
-------------------------------------------------------------------------
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.
-------------------------------------------------------------------------
Distributions Taxable Return of
Calendar Year per unit Portion Capital
-------------------------------------------------------------------------
2005 (two months)(2) $ 0.480 $ 0.456 $ 0.024
2006 $ 2.640 $ 2.033 $ 0.607
-------------------------------------------------------------------------
Cumulative to Dec. 31, 2006 $ 3.120 $ 2.489 $ 0.631
-------------------------------------------------------------------------
2007 year $ 0.960 $ 0.960 -
-------------------------------------------------------------------------
Cumulative to Dec. 31, 2007 $ 4.080 $ 3.449 $ 0.631
-------------------------------------------------------------------------
2008 year $ 0.460 $ 0.460 -
-------------------------------------------------------------------------
Cumulative to December 31, 2008 $ 4.540 $ 3.909 $ 0.631
-------------------------------------------------------------------------
2009 year to date (one month)(3) $ 0.020
-----------------------------------------------
Cumulative to June 30, 2009 $ 4.560
-----------------------------------------------
(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 TKE Energy Trust.
(3) It is currently estimated that the approximate taxable portion of the
January 2009 distribution to Canadian unitholders will be 100%.
In consultation with its U.S. tax advisors, True believes that its
Trust units should be "qualified dividends" for U.S. federal
purposes. As such, the portion of distributions made during 2009 that
are considered dividends for U.S. federal purposes should qualify for
the reduced rate of tax applicable to long-term capital gains.
Unitholders or potential unitholders should consult their own legal
or tax advisors as to their particular income tax consequences of
holding True units. Please review our February 19, 2009 press release
addressing this.
Monthly Distributions
Actual distributions paid and declared per Trust unit along with relevant
payment dates for 2009 to date are as follows:
-------------------------------------------------------------------------
Distribution
Ex-distribution Date Record Date Payment Date per unit
-------------------------------------------------------------------------
December 29, 2008 December 31, 2008 January 15, 2009 0.02
January 28, 2009 January 30, 2009 February 17, 2009 0.02
-------------------------------------------------------------------------During the first six months of 2009, funding requirements for
distributions declared was 9% of funds flow from operations.
As announced on March 17, 2009, due to the continued deterioration in
economic conditions, including the significant decline in crude oil and
natural gas prices, a weakening outlook for natural gas demand and heightened
risk in the credit markets, True has deemed it prudent to suspend
distributions, until further notice, to maintain corporate liquidity during
the current financial turmoil and prevailing commodity price environment.
Distributions remain suspended until such time as the Board of Directors
determines otherwise. Pursuant to True's credit facility, distributions to
unitholders (other than by way of the issuance of Trust units) require the
approval of True's lenders if the funds to pay such distributions are received
from True Energy Inc. ("True Energy").
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 20, 2009 approximately 25 percent of unitholders are non-Canadian
residents with the remaining 75 percent being Canadian residents.
In order that the Trust maintains its status as a "mutual fund trust"
under the Income Tax Act (Canada), certain provisions of the Income Tax Act
(Canada) require that the trust not be established or maintained primarily for
the benefit of non-residents of Canada ("non-residents"). The trust indenture
for the Trust provides that if the Trust or its administrator becomes aware
that the activities of the Trust and ownership of Trust units by non-residents
may threaten the status of the Trust under the Income Tax Act (Canada) as a
"unit trust" or "mutual fund trust", the Trust is authorized to take action as
may be necessary to maintain the status of the Trust as a unit trust and a
mutual fund trust, including the imposition or restrictions on the issuance by
the Trust, or the transfer by any unitholder, of Trust units to a
non-resident.
Liquidity and Capital Resources
As an oil and gas business, the Trust has a declining asset base and
therefore relies on ongoing development and acquisitions to replace production
and add additional reserves. Future oil and natural gas production and
reserves are highly dependent on the success of exploiting the Trust's
existing asset base and in acquiring additional reserves. To the extent the
Trust is successful or unsuccessful in these activities; funds flow could be
increased or reduced.
Global financial markets continued to remain fragile during the first and
second quarters of 2009. The economic crisis continues to put a strain on
credit and equity markets as characterized by a decline in liquidity and
higher borrowing costs. Access to capital markets has become constrained and
significantly more expensive for the Trust along with other oil and gas
entities. The current global economic environment has continued to create
volatility in commodity prices, tempered somewhat by the growing US to
Canadian dollar exchange rate. Given the continuing uncertain economic
conditions, the Trust has maintained a 2009 capital budget of $15 million and
has suspended distributions until further notice. The Trust continues to
monitor forecasted debt levels to manage its operations within forecasted cash
flow. In addition, the Trust will continue to monitor developments within the
global economic environment to consider the impacts on current or future
lending arrangements.
Liquidity risk is the risk that the Trust will not be able to meet its
financial obligations as they fall due. The Trust actively manages its
liquidity through daily and longer-term cash, debt and equity management
strategies. Such strategies encompass, among other factors: having adequate
sources of financing available through its bank credit facilities, estimating
future cash generated from operations based on reasonable production and
pricing assumptions, analysis of economic hedging opportunities, and
maintaining sufficient cash flows for compliance with debt covenants. The
Trust is fully compliant with all of its debt covenants.
The Trust generally relies on operating cash flows and its credit
facilities to fund capital requirements and provide liquidity. Future
liquidity depends primarily on cash flow generated from operations, existing
credit facilities and the ability to access debt and equity markets. From time
to time, the Trust accesses capital markets to meet its additional financing
needs and to maintain flexibility in funding its capital programs. There can
be no assurance that debt or equity financing, or cash generated by operations
will be available or sufficient to meet these requirements or for other
corporate purposes or, if debt or equity financing is available, that it will
be on terms acceptable to the Trust. The inability of the Trust to access
sufficient capital for its operations could have a material adverse effect on
the Trust's business financial condition, results of operations and prospects.
Credit risk is the risk of financial loss to the Trust if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Trust's trade receivables from
joint venture partners, petroleum and natural gas marketers, and financial
derivative counterparties.
A substantial portion of the Trust's accounts receivable are with
customers and joint interest partners in the petroleum and natural gas
industry and are subject to normal industry credit risks. The Trust sells
substantially all of its production to eight primary purchasers under standard
industry sale and payment terms. Purchasers of the Trust's natural gas, crude
oil and natural gas liquids are subject to a periodic internal credit review
to minimize the risk of non-payment. The Trust has continued to closely
monitor and reassess the creditworthiness of its counterparties, including
financial institutions. This has resulted in the Trust reducing or mitigating
its exposures to certain counterparties where it is deemed warranted and
permitted under contractual terms.
The Trust may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture partners,
marketers of its petroleum and natural gas production and other parties. In
the event such entities fail to meet their contractual obligations to the
Trust, such failures may have a material adverse effect on the Trust's
business, financial condition, results of operations and prospects. In
addition, poor credit conditions in the industry and of joint venture partners
may impact a joint venture partner's willingness to participate in the Trust's
ongoing capital program, potentially delaying the program and the results of
such program until the Trust finds a suitable alternative partner.
During 2009, the Trust has been executing several strategies for dealing
with these uncertain times.
True's corporate thrust in 2009 is to continue to improve the Trust's
balance sheet by reducing total outstanding debt and streamlining its
operating cost structure. In 2009, True has limited its capital program to $15
million in an effort to maintain production and increase financial flexibility
to fund operations. This compares to the $43 million capital program employed
in 2008. As a consequence of a reduced capital program and strategic
divestitures completed in 2008 and 2009, total net debt levels decreased by
$42.7 million from $239.4 million at March 31, 2008 to $196.7 million at June
30, 2009. Total net debt excludes unrealized commodity contract assets and
liabilities, future income taxes and asset retirement obligations.
On July 30, 2009, the Trust successfully completed the divestiture of the
majority of its Saskatchewan assets for net proceeds, after purchase
adjustments of $86 million. These proceeds have been used to reduce the
Trust's bank indebtedness. On July 30, 2009, in conjunction with completion of
the Saskatchewan Divestiture, True negotiated a new banking syndicate
commitment to replace the existing bank facility, subject to finalization and
execution of a mutually acceptable credit agreement, that will provide True
with a credit facility of $85 million. The facility will consist of a $10
million demand operating facility provided by one Canadian bank and a $75
million extendible revolving term credit facility syndicated by one Canadian
chartered bank and one Canadian financial institution. The revolving period on
the revolving term credit facility will end on June 30, 2010, unless extended
for a further 364 day period. Should the facilities not be renewed they will
convert to 366 day non-revolving term facilities on the renewal date. The
borrowing base will be subject to renewal on March 31, 2010.
The strategic dispositions accomplished in the year allow the Trust to
progress forward with substantially improved financial flexibility.
Combined funding requirements for the January distribution declared and
True's capital expenditures represented 11% and 32% of funds flow from
operations in the three and six months ended June 30, 2009, respectively.
As a result of the continued deterioration in economic conditions,
including the significant decline in crude oil prices seen earlier in 2009, a
weakening outlook for natural gas demand and a heightened risk in the credit
markets, True has deemed it prudent to suspend distributions to maintain
corporate liquidity during the current financial turmoil and prevailing
commodity price environment. Distributions remain suspended until such time as
the Board of Directors determines otherwise. Pursuant to True's credit
facility, distributions to unitholders (other than by way of the issuance of
Trust units) generally require the approval of True's lenders if the funds to
pay such distributions are received from True Energy.
True continues to tighten its cost structure in the current economically
challenging climate with forecasted cuts from 2008 levels of 30% to total
operating expenses which includes G&A and lease operating costs in 2009. The
results through the first half of 2009 are on track.
True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate
of $0.90, a WTI oil price of US$70.00/bbl, AECO natural gas price of
CAD$4.50/GJ ($4.95/mcf) and production volumes of 6,500 boe/d for August to
December 2009, generates cash flow from operations of $38 million. Based on
the foregoing assumptions and assuming 2009 distributions of $1.6 million
coupled with the planned capital budget of $15 million the Trust would utilize
approximately 44% of the Trust's forecasted funds flow from operations.
As an added layer of protection of its cash flow forecast, upon
completion of the divestitures, True's hedging represents approximately 65% of
its estimated natural gas production for the third and fourth quarter of 2009
at an average price of $6.60 CAD per GJ ($7.26/mcf) and 21.5% of the first
quarter of 2010 through to the second quarter of 2010 at an average of $7.25
CAD per GJ ($7.96/mcf). In addition, 500 bbl/d of oil for the third and fourth
quarter of 2009 are hedged by way of a costless collar of $52.30 CAD x $80.70
CAD. True maintains an active commodity price risk management program focused
on maintaining sufficient cash flow to fund its operations.
Pursuant to True's existing credit facility, distributions from True
Energy to the Trust during the remaining term of the facilities is restricted
other than: (i) distributions by True Energy to the Trust to permit the
regular semi-annual interest payments by the Trust on June 30, 2009, December
31, 2009 and June 30, 2010 in respect of the convertible debentures issued by
the Trust on or before April 1, 2009; and (ii) distributions from True Energy
to the Trust to permit cash distributions in respect of Trust unit
redemptions, if and only if and to the extent that the total cash amount
payable in respect of all unit redemptions in a month does not exceed
$250,000; provided in each case that the foregoing distributions shall not be
permitted if a borrowing base shortfall has occurred and is continuing, a
demand for payment has been made and remains outstanding, a default or an
event of default is then in existence or could reasonably be expected to
result from such distribution, or the distribution could impair the ability of
True Energy to satisfy its covenants and obligations to the lenders under the
credit facility.
There are currently no commitments, other than those associated with the
Trust's credit facilities outlined above, its 2009 capital program of $11.1
million for the remaining second half of 2009, and the off-balance sheet
arrangements outlined below. The Trust continually monitors its capital
spending program in light of the recent volatility with respect to commodity
prices and Canadian dollar exchange rates with the aim of ensuring the Trust
will be able to meet future anticipated obligations incurred from normal
ongoing operations with funds flow from operations and draws on the Trust's
syndicated facility, as necessary. As announced on March 17, 2009, Trust unit
distributions have been suspended until further notice.
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 22, 2009, the Trust had outstanding a total of 4,377,132
incentive units exercisable at an average exercise price of $2.36 per unit,
294,026 exchangeable shares (convertible, as at July 22, 2009 into an
aggregate of 312,467 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 78,496,581 Trust units.Commitments
Off-Balance Sheet ArrangementsThe 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, 2009.
Business Prospects and 2009 Year 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.
Upon closing of the recent dispositions, True continues to have
approximately 274,000 net acres of undeveloped land with 320 exploitation
drilling opportunities identified representing over 5 years of drilling
inventory.
True continues to monitor its cost structure in the current economically
challenging climate and as a result, completed G&A reductions in January 2009.
True streamlined its operations and reduced head office staffing levels by one
third compared to 2008 levels. True's capital program for 2009 remains at $15
million. Production volumes are estimated to average 6,500 boe/d through
August to December 2009 as a result of recent dispositions, with an expected
2009 average production rate of 7,000 boe/d.
As an added layer of protection of its cash flow forecast, upon
completion of divestitures, True's hedging represents approximately 65% of its
estimated natural gas production for the third and fourth quarter of 2009 at a
combined fixed price of $6.60 CAD per GJ ($7.26/mcf ) and 21.5% of the first
quarter of 2010 through to the second quarter of 2010 at an average of $7.25
CAD per GJ ($7.96/mcf). In addition, 500 bbl/d of oil for the third and fourth
quarter of 2009 are hedged by way of a costless collar of $52.30 CAD x $80.70
CAD.
True's operating forecast for 2009 which assumes a CAD$/US$ exchange rate
of $0.90, a WTI oil price of US$70.00/bbl, AECO natural gas price of
CAD$4.50/GJ ($4.95/mcf) and production volumes of 6,500 boe/d for August to
December 2009, generates cash flow from operations of $38 million. Based on
the foregoing assumptions and assuming 2009 distributions of $1.6 million
coupled with the planned capital budget of $15 million the Trust would utilize
approximately 44% of the Trust's forecasted funds flow from operations.
True's 2009 capital program is not expected to exceed $15 million and
will limit the second half 2009 capital program to $11.1 million. Given the
nature of True's lands and their inherent advantage of year round access, True
currently plans to spread its 2009 capital program evenly through the full
year of 2009 to take advantage of reduced service costs during non-peak times.
True will continue to focus on opportunities to increase its farm-out activity
in non-core areas. If the 2009 outlook for commodity prices improves, True
would plan to increase its capital spending later in 2009 dependant upon cash
flow.
On July 30, 2009 True announced that it has negotiated a new banking
syndicate commitment to replace its existing bank facility, subject to
finalization and execution of a mutually acceptable credit agreement, with a
revolving period of June 30, 2010 and a maturity date of June 2011. The next
borrowing base review under the new facility will be scheduled for March 31,
2010.Financial Reporting Update
Goodwill and intangible assetsIn 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 was effective for
the Trust beginning January 1, 2009. Application of the new section does not
currently 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. The transition date of January 1, 2011 will
require restatement for comparative purposes, of amounts reported by the Trust
for its year ended December 31, 2010, and of the opening balance sheet as at
January 1, 2010. An internal project team has been set up to manage this
transition and to ensure successful implementation within the required time
frame. Current economic conditions may require re-allocation of resources
available for the IFRS conversion project. The Trust has completed a high
level analysis to determine the areas impacted by the conversion and is
assessing the financial reporting impacts on the adoption of IFRS and, at this
time, the impact on future financial position and results of operations has
not yet been determined. On July 23, 2009 the IASB published amendments to
IFRS 1 - "First-time Adoption of International Financial Reporting Standards"
which will allow an election to measure oil and gas assets at the date of
transition to IFRS at the amount determined under Canadian GAAP. The Trust
anticipates a significant increase in disclosures resulting from the adoption
of IFRS and is continuing to assess the level of this disclosure required and
any necessary systems changes to gather and process the information. 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, 2008 and the Trust's Annual
Information Form for the year ended December 31, 2008.
Critical Accounting Estimates
The reader is advised that the critical accounting estimates, policies,
and practices as described in the Trust's Management's Discussion and Analysis
for the year ended December 31, 2008 continue to be critical in determining
True's unaudited financial results as at June 30, 2009. There were no changes
in accounting policies for the six month period ended June 30, 2009, except
for the adoption of a new accounting standard, Section 3064 - Goodwill and
Intangible Assets, which does not have any impact on the Trust's financial
statements.
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 ProceduresThe Trust's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, disclosure
controls and procedures to provide reasonable assurance that: (i) material
information relating to the Trust is made known to the Trust's Chief Executive
Officer and Chief Financial Officer by others, particularly during the period
in which the annual and interim filings are being prepared; and (ii)
information required to be disclosed by the Trust in its annual filings,
interim filings or other reports filed or submitted by it under securities
legislation is recorded, processed, summarized and reported within the time
period specified in securities legislation.
Internal Control over Financial Reporting
The Trust's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, internal control
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 is required to disclose herein any change in the Trust's
internal control over financial reporting that occurred during the period
beginning on April 1, 2009 and ended on June 30, 2009 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 such period, 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 Canadian Institute of Chartered Accountants ("CICA") issued the
Interpretive Release "Standardized Distributable Cash in Income Trusts and
Other Flow-Through Entities: Guidance on Preparation and Disclosure" (the
"Release"). In this guidance, sustainability concepts are discussed and
standardized distributable cash is defined as cash flow from operating
activities less adjustments for productive capacity maintenance, long-term
unfunded contractual obligations and the effect of any foreseeable financing
matters, related to debt covenants, which could impair True's ability to pay
distributions or maintain productive capacity. This Management Discussion and
Analysis is in all material respects in accordance with the recommendations
provided in CICA's Release and NP 41-201.-------------------------------------------------------------------------
Three months ended Six months ended
($000s, except per unit June 30, June 30,
amounts and ratios) 2009 2008 2009 2008
-------------------------------------------------------------------------
Net loss (99,715) (21,374) (108,771) (39,995)
-------------------------------------------------------------------------
Cash flow from operating
activities 6,467 19,892 15,778 37,735
Productive capacity
maintenance(1) (1,028) (3,654) (3,556) (12,107)
-------------------------------------------------------------------------
Standardized distributable
cash 5,439 16,238 12,222 25,628
Proceeds on sale of
property, plant and
equipment 8,289 38,530 8,281 44,318
Corporate and property
acquisition and other
capital expenditures (123) (426) (351) (623)
Repurchase of trust units
under normal course
issuer bid - (596) - (596)
Bank borrowings (debt
repayment) and working
capital changes and
other (13,605) (44,241) (18,582) (49,715)
-------------------------------------------------------------------------
Cash Distributions
declared - 9,505 1,570 19,012
Accumulated distributions,
beginning of period 253,071 224,674 251,501 215,167
-------------------------------------------------------------------------
Accumulated distributions,
end of period 253,071 234,179 253,071 234,179
-------------------------------------------------------------------------
Standardized distributable
cash per unit - basic $0.09 $0.21 $0.16 $0.32
Standardized distributable
cash per unit - diluted $0.09 $0.21 $0.16 $0.32
-------------------------------------------------------------------------
Standardized distributable
cash payout ratio(2) N/A 0.59 0.13 0.74
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Distributions declared per
unit for outstanding units
in the period - $0.12 $0.02 $0.24
Accumulated distributions
per unit, beginning of
period 4.56 4.20 4.54 4.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated distributions
per unit, end of period $4.56 $4.32 $4.56 $4.32
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Excess (shortfall) of net
income over cash
distributions declared (99,715) (30,879) (110,341) (59,007)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Excess of cash flow from
operating activities over
cash distributions
declared 6,467 10,387 14,208 18,723
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Please refer to the discussion of productive capacity maintenance
below
(2) Represents cash distributions declared divided by standardized
distributable cashTrue strives to fund both distributions (if any) and maintenance capital
primarily from funds flow from operations.
Productive capacity is the amount of capital funds required in a period
for an enterprise to maintain its ability to generate future cash flow from
operating activities at a constant level. As commodity prices can be volatile
and short-term variations in production levels are often experienced in the
oil and gas industry, True defines production capacity as production on a
barrel of oil equivalent basis. A quantifiable measure for these short-term
variations is not objectively determinable or verifiable due to various
factors including the inability to distinguish natural production declines
from the effect of production additions resulting from capital and
optimization programs, and the effect of temporary production interruptions.
As a result, the adjustment for productive capacity maintenance in True's
calculation of standardized distributable cash is True's capital expenditures
excluding the cost of any asset acquisition, corporate asset acquisitions or
proceeds of any asset disposition. True believes that its capital programs
based on 40% to 60% of forecasted funds flow including its current view of
True's assets and opportunities and True's outlook for commodity prices and
industry conditions in the medium term, should be sufficient to maintain
True's productive capacity in the medium term. True sets its hurdle rates for
evaluating potential development and optimization projects according to these
parameters. Due to the risks inherent in the oil and natural gas industry,
particularly True's exploration and development activities and inherent
variations in commodity prices, there can be no assurance that capital
programs, whether limited to excess of cash flow over distributions or not,
will be sufficient to maintain or increase True's production levels or cash
flow from operating activities. True's capital expenditures and production can
be impacted by the timing of the capital program and spring break up
associated with certain operating areas of its properties. As True strives to
maintain sufficient credit facilities and appropriate levels of bank debt,
this seasonality is not expected to influence True's distribution policies.
True's calculation of standardized distributable cash has no adjustment
for long-term unfunded contractual obligations. True's only material long-term
unfunded contractual obligation at this time is for asset retirement
obligations. True's abandonment obligations are being funded on an annual
basis with cash flow from operating activities. Cash flow from operating
activities, used in our standardized distributable cash calculation, includes
a deduction for abandonment expenditures incurred in the year. True regularly
monitors its current forecast debt levels to ensure debt covenants are not
exceeded.
Distributions, if paid, typically exceed net income as a result of
non-cash items such as unit-based compensation, depletion, depreciation and
accretion, unrealized loss (gain) on commodity contracts, and future income
tax expense (recovery). These non-cash items generally result in a reduction
to net income, with no impact to cash flow from operating activities.
Therefore, distributions, if paid, will exceed net income in most periods. In
the event distributions exceed cash flow from operating activities and the
requirements of True's capital program, the shortfall would typically be
funded by a combination of available bank facilities, equity or debt issues,
or the sale proceeds from non-core assets.
The Board of Directors and management regularly review the level of
distributions. The board considers a number of factors, including expectations
of future current commodity prices, hedge positions, production volumes,
capital expenditure requirements, market conditions, the availability of debt
and equity capital and other factors. As announced on March 17, 2009, as a
result of the continued deterioration in economic conditions, including the
significant decline in crude oil and natural gas prices and heightened risk in
the credit markets, the Trust has suspended its distributions until further
notice. Pursuant to True's existing credit facility, distributions to
unitholders (other than by way of the issuance of Trust units) generally
require the approval of True's lenders if the funds to pay such distributions
are received from True Energy. It is expected that these restrictions will
continue to exist under the new credit facility.-------------------------------------------------------------------------
($000s, except ratios) To June 30, 2009
-------------------------------------------------------------------------
Cumulative distributable cash from operations(1) 78,655
Proceeds on sale of property, plant and equipment 108,943
Corporate and property acquisitions and other capital
expenditures (26,537)
Net proceeds from issue of trust units 54,375
Proceeds from issue of convertible debentures, net of issue
costs 82,261
Repurchase of trust units under normal course issuer bid (4,194)
Funding from DRIP 42,909
Bank borrowings (debt repayment) and working capital changes
and other (83,341)
-------------------------------------------------------------------------
Cumulative cash distributions declared(1) 253,071
-------------------------------------------------------------------------
Standardized distributable cash payout ratio(2) 3.22
-------------------------------------------------------------------------
(1) Subsequent to the November 2, 2005 reverse takeover of TKE Energy
Trust
(2) Represents cumulative distributions declared divided by cumulative
standardized distributable cashSensitivity Analysis
The table below shows sensitivities to funds flow as a result of product
price and operational changes. This is based on actual average prices received
for the second quarter of 2009 and average production volumes of 9,767 boe/d
during that period, as well as the same level of debt outstanding at June 30,
2009. Diluted weighted average Trust units is based upon the second quarter of
2009. These sensitivities are approximations only, and not necessarily valid
under other significantly different production levels or product mixes.
Hedging activities can significantly affect these sensitivities. Changes in
any of these parameters will affect funds flow as shown in the table below:-------------------------------------------------------------------------
Funds
Funds Flow from
Flow from Operations
Operations Per Diluted
(annualized) Unit
-------------------------------------------------------------------------
Sensitivity Analysis ($000s) ($)
-------------------------------------------------------------------------
Change of US $1/bbl WTI 1,300 0.02
Change of $0.10/mcf 1,100 0.01
Change of US $0.01 Cdn/US exchange rate 700 0.01
Change in prime of 1% 1,200 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected Quarterly Consolidated Information
The following table sets forth selected consolidated financial information
of the Trust for the most recently completed quarters ending at June 30, 2009.
-------------------------------------------------------------------------
2009 - Quarter ended
(unaudited) ($000s,
except per unit
amounts) March 31 June 30
-------------------------------------------------------------------------
Revenues before
royalties and hedging 31,345 29,805
Funds flow from
operations(1) 6,489 10,765
Funds flow from
operations per unit(1)
Basic $0.08 $0.14
Diluted $0.08 $0.14
Net income (loss) (9,056) (99,715)
Net income (loss) per unit
Basic $(0.12) $(1.27)
Diluted $(0.12) $(1.27)
Net capital expenditures
(cash) 2,764 (7,138)
Distributions declared 1,570 -
Distributions per unit $0.02 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2008 - Quarter ended
(unaudited) ($000s,
except per unit
amounts) March 31 June 30 Sept. 30 Dec. 31
-------------------------------------------------------------------------
Revenues before
royalties and hedging 70,033 82,074 72,225 41,053
Funds flow from
operations(1) 24,233 26,304 21,491 5,865
Funds flow from
operations per unit(1)
Basic $0.31 $0.33 $0.27 $0.07
Diluted $0.30 $0.33 $0.27 $0.07
Net income (loss) (18,621) (21,374) 29,939 (9,534)
Net income (loss) per unit
Basic $(0.24) $(0.27) $0.38 $(0.12)
Diluted $(0.24) $(0.27) $0.38 $(0.12)
Net capital expenditures
(cash) 2,862 (34,450) 13,779 16,471
Distributions declared 9,507 9,505 9,474 7,848
Distributions per unit $0.12 $0.12 $0.12 $0.10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 - Quarter ended
(unaudited) ($000s,
except per unit
amounts) March 31 June 30 Sept. 30 Dec. 31
-------------------------------------------------------------------------
Revenues before
royalties and hedging 71,196 74,991 50,547 61,756
Funds flow from
operations(1) 29,988 34,192 17,478 19,514
Funds flow from
operations per unit(1)
Basic $0.43 $0.47 $0.22 $0.25
Diluted $0.42 $0.45 $0.22 $0.25
Net income (loss) (8,571) 1,741 (17,003) (434)
Net income (loss) per unit
Basic $(0.12) $0.02 $(0.21) $(0.01)
Diluted $(0.12) $0.02 $(0.21) $(0.01)
Net capital expenditures
(cash) 27,915 6,739 7,562 14,828
Distributions declared 16,866 18,376 19,132 19,077
Distributions per unit $0.24 $0.24 $0.24 $0.24
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Refer to "Non-GAAP Measures" in respect of the term "funds flow from
operations" and "funds flow from operations per unit".
TRUE ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
As at June 30 and December 31 (unaudited)
-------------------------------------------------------------------------
($000s) 2009 2008
-------------------------------------------------------------------------
ASSETS
Current assets
Accounts receivable $ 22,787 $ 28,119
Marketable securities (note 4) - 120
Deposits and prepaid expenses 4,345 5,969
Commodity contract asset (note 15) 9,571 3,726
Petroleum and natural gas properties held for
sale (note 5) 94,578 -
--------------------------
131,281 37,934
Property, plant and equipment (note 5) 431,573 698,183
--------------------------
Total assets $ 562,854 $ 736,117
--------------------------
--------------------------
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ 21,569 $ 34,128
Distribution payable to unitholders - 1,570
Commodity contract liability (note 15) 705 -
Future income taxes (note 13) 2,610 1,100
Bank debt (note 6) 120,205 -
Asset retirement obligations related to
petroleum and natural gas properties held
for sale (note 5) 9,578 -
--------------------------
154,667 36,798
Long-term debt (note 6) - 132,388
Convertible debentures (note 7) 82,075 81,124
Asset retirement obligations (note 8) 24,141 33,682
Future income taxes (note 13) 3,076 42,777
--------------------------
Total liabilities 263,959 326,769
--------------------------
NON-CONTROLLING INTEREST
Exchangeable shares of subsidiary (note 9) 2,452 2,887
UNITHOLDERS' EQUITY
Unitholders' capital (note 10) 917,012 917,012
Equity component of convertible debentures 5,119 5,119
Contributed surplus (note 11) 27,943 28,240
Accumulated other comprehensive income - (620)
Deficit (653,631) (543,290)
--------------------------
(653,631) (543,910)
--------------------------
--------------------------
Total unitholders' equity 296,443 406,461
--------------------------
Total liabilities and unitholders' equity $ 562,854 $ 736,117
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying selected notes to the consolidated financial statements.
TRUE ENERGY TRUST
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
For the three and six months ended June 30 (unaudited)
Three months ended June 30, Six months ended June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
REVENUES
Petroleum and natural
gas sales $ 29,805 $ 82,074 $ 61,150 $ 152,107
Royalties (5,324) (16,289) (11,632) (31,789)
Gain (loss) on
commodity contracts
(note 15) 3,085 (38,169) 13,560 (59,998)
----------------------------------------------------
27,566 27,616 63,078 60,320
EXPENSES
Production 11,916 16,170 25,862 33,166
Transportation 1,267 2,478 2,830 3,321
General and
administrative 2,581 4,492 5,423 8,262
Interest and
financing charges 4,218 3,487 7,520 8,003
Unit-based
compensation
(recovery)
(notes 10 and 11) 243 160 (360) 429
Depletion,
depreciation and
accretion 27,374 33,209 54,629 69,512
Loss on sale of
marketable
securities (note 4) 501 - 501 -
Loss on petroleum
and natural gas
properties held
for sale (note 5) 114,182 - 114,182 -
----------------------------------------------------
162,282 59,996 210,587 122,693
LOSS BEFORE TAXES (134,716) (32,380) (147,509) (62,373)
TAXES
Capital taxes - 651 - 1,114
Future income tax
recovery (note 13) (34,602) (11,562) (38,303) (23,316)
----------------------------------------------------
(34,602) (10,911) (38,303) (22,202)
NET LOSS BEFORE
NON-CONTROLLING
INTEREST (100,114) (21,469) (109,206) (40,171)
Non-controlling
interest (399) (95) (435) (176)
----------------------------------------------------
NET LOSS (99,715) (21,374) (108,771) (39,995)
Realized loss on
available for
sale marketable
securities 509 - 620 -
----------------------------------------------------
COMPREHENSIVE LOSS $ (99,206) $ (21,374) $ (108,151) $ (39,995)
----------------------------------------------------
Net loss per trust
unit
Basic $ (1.27) $ (0.27) $ (1.39) $ (0.50)
Diluted $ (1.27) $ (0.27) $ (1.39) $ (0.50)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying selected notes to the consolidated financial statements.
TRUE ENERGY TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
For the three and six months ended June 30 (unaudited)
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
UNITHOLDERS' CAPITAL
Balance, beginning
of period $ 917,012 $ 925,735 $ 917,012 $ 925,573
Repurchased under
normal course issuer
bid - (1,577) - (1,577)
Exchangeable shares
converted - - - 162
----------------------------------------------------
Balance, end of
period 917,012 924,158 917,012 924,158
----------------------------------------------------
EQUITY COMPONENT OF
CONVERTIBLE DEBENTURES
----------------------------------------------------
Balance, beginning
and end of period 5,119 5,119 5,119 5,119
----------------------------------------------------
CONTRIBUTED SURPLUS
Balance, beginning
of period 27,670 19,872 28,240 19,454
Unit-based
compensation
expense
(note 10 and 11) 175 562 390 1,165
Adjustment of prior
period unit-based
compensation expense
for forfeitures of
unvested incentive
units 98 (257) (687) (442)
Adjustment for
repurchase of units
under normal course
Issuer bid - 981 - 981
----------------------------------------------------
Balance, end of
period 27,943 21,158 27,943 21,158
----------------------------------------------------
DEFICIT
Balance, beginning
of period (553,916) (515,494) (543,290) (487,366)
Net loss (99,715) (21,374) (108,771) (39,995)
Distributions
declared - (9,505) (1,570) (19,012)
----------------------------------------------------
Balance, end of
period (653,631) (546,373) (653,631) (546,373)
----------------------------------------------------
ACCUMULATED OTHER
COMPREHENSIVE INCOME
Balance, beginning
of period (509) - (620) -
Realized loss on
sale of marketable
securities (note 4) 509 - 620 -
----------------------------------------------------
Balance, end of
period - - - -
----------------------------------------------------
-------------------------------------------------------------------------
TOTAL UNITHOLDERS'
EQUITY $ 296,443 $ 404,062 $ 296,443 $ 404,062
-------------------------------------------------------------------------
See accompanying selected notes to the consolidated financial statements.
TRUE ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and six months ended June 30 (unaudited)
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
-------------------------------------------------------------------------
Cash provided by (used
in):
CASH FLOW FROM
OPERATING ACTIVITIES
Net loss $ (99,715) $ (21,374) $ (108,771) $ (39,995)
Items not involving
cash:
Non-controlling
interest (note 9) (399) (95) (435) (176)
Depletion,
depreciation and
accretion 27,374 33,209 54,629 69,512
Unit-based
compensation
(recovery)
(notes 10 and 11) 243 160 (360) 429
Unrealized loss
(gain) on commodity
contracts (note 15) 2,704 25,550 (5,140) 43,237
Accretion on
convertible
debentures 477 416 951 846
Future income tax
recovery (note 13) (34,602) (11,562) (38,303) (23,316)
Loss on sale of
marketable securities
(note 4) 501 - 501 -
Loss on petroleum
and natural gas
properties held for
sale (note 5) 114,182 - 114,182 -
Asset retirement
costs incurred
(note 8) (313) (123) (1,051) (712)
Change in non-cash
working capital
(note 12) (3,985) (6,289) (425) (12,090)
----------------------------------------------------
6,467 19,892 15,778 37,735
CASH FLOW FROM (USED IN)
FINANCING ACTIVITIES
Decrease in bank debt (11,417) (46,392) (12,183) (43,017)
Repurchase of trust
units under normal
course issuer bid - (596) - (596)
Distributions
declared - (9,505) (1,570) (19,012)
----------------------------------------------------
(11,417) (56,493) (13,753) (62,625)
Change in non-cash
working capital
(note 12) 709 50 (809) (3,110)
----------------------------------------------------
(10,708) (56,443) (14,562) (65,735)
CASH FLOW FROM (USED IN)
INVESTING ACTIVITIES
Additions to property,
plant and equipment (1,151) (4,080) (3,907) (12,730)
Proceeds on sale of
property, plant and
equipment 8,289 38,530 8,281 44,318
Proceeds on sale of
marketable
securities 349 - 349 -
----------------------------------------------------
7,487 34,450 4,723 31,588
Change in non-cash
working capital
(note 12) (3,246) 2,101 (5,939) (3,588)
----------------------------------------------------
4,241 36,551 (1,216) 28,000
Change in cash - - - -
Cash, beginning
of period - - - -
-------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying selected notes to the consolidated financial statements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
-------------------------------------------------------------------------
1. STRUCTURE OF THE TRUST
True Energy Trust ("True" or the "Trust") is an open-ended,
unincorporated investment trust governed by the laws of the Province
of Alberta.
The purpose of the Trust is to indirectly explore for, develop and
hold interests in petroleum and natural gas properties, through
investments in securities of subsidiaries and net profits interests
in oil and natural gas properties. The business of the Trust is
carried on by True Energy Inc. and its indirect wholly owned
subsidiary True Energy Peru S.A.C. The Trust owns, directly and
indirectly, 100% of the common shares, (excluding the exchangeable
shares - see note 9) of True Energy Inc. and True Energy Peru S.A.C.
The activities of True Energy Inc. are financed through interest
bearing notes from the Trust and third party debt.
2. SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements of the Trust have been
prepared by management in accordance with generally accepted
accounting policies in Canada. The unaudited interim consolidated
financial statements have been prepared following the same accounting
policies and methods of computation as the consolidated financial
statements for the fiscal year ended December 31, 2008, except as
described in note 3. The interim consolidated financial statement
note disclosures do not include all of those required by Canadian
generally accepted accounting principles ("GAAP") applicable for
annual financial statements. Accordingly, the interim consolidated
financial statements should be read in conjunction with the
consolidated financial statements and the notes thereto as at and for
the year ended December 31, 2008.
3. RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2009, the Trust adopted the following new
accounting standard:
Goodwill and intangible assets
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. Application of the new section does not 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 for
years beginning on or after January 1, 2011. 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.
4. MARKETABLE SECURITIES
The Trust's investment in Veraz Petroleum Ltd. was sold in May 2009
for proceeds of $0.3 million and a realized loss on sale of
$0.5 million was recognized in the second quarter.
5. PROPERTY, PLANT AND EQUIPMENT
($000s)
---------------------------------------------------------------------
Accumulated
depletion and Net book
June 30, 2009 Cost depreciation value
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 1,370,748 $ 846,482 $ 524,266
Less: Petroleum and natural gas
properties held for sale (434,933) (340,355) (94,578)
---------------------------------------------------------------------
935,815 506,127 429,688
Office furniture and equipment 3,994 2,109 1,885
---------------------------------------------------------------------
$ 939,809 $ 508,236 $ 431,573
---------------------------------------------------------------------
December 31, 2008
---------------------------------------------------------------------
Petroleum and natural gas
properties $ 1,375,331 $ 679,196 $ 696,135
Office furniture and equipment 3,955 1,907 2,048
---------------------------------------------------------------------
$ 1,379,286 $ 681,103 $ 698,183
---------------------------------------------------------------------
---------------------------------------------------------------------
The Trust has included $62.5 million (December 31, 2008:
$62.8 million) for future development costs and excluded
$26.6 million (December 31, 2008: $31.3 million) for undeveloped land
and $37.9 million (December 31, 2008: $42.5 million) for estimated
salvage from the depletion calculation during the six month period
ended June 30, 2009.
For the six month period ended June 30, 2009, the Trust capitalized
$0.2 million of general and administrative expenses and $0.06 million
of unit-based compensation expense directly related to exploration
activities.
Petroleum and Natural Gas Properties Held for Sale
The Trust entered into an agreement for the divestiture of the
majority of its petroleum and natural gas properties in Saskatchewan
(the "Saskatchewan Divestiture") for gross proceeds of $93 million,
subject to closing adjustments, effective May 1, 2009. This
disposition closed on July 30, 2009. The disposition meets the
criteria under CICA handbook section 3475 - "Disposal of Long-lived
Assets and Discontinued Operations" and Accounting Guideline 16 -
"Oil and Gas Accounting - Full Cost", and as a result, the Trust has
classified the group of assets as assets held for sale. Under full
cost accounting, if crediting the proceeds from disposition to costs
results in a change of 20 percent or more to the DD&A rate then a
gain or loss should be recognized. When a gain or loss is to be
recognized the total net book value of capitalized costs should be
allocated between the properties sold and the properties retained.
The assets held for sale as of June 30, 2009 are an allocation of the
Trust's historical full cost pool based on a pro-rata ratio of future
cash flows of proved reserves associated with the assets held for
sale, discounted at 10%, as compared to all oil and gas assets. The
Trust has recorded a $114.2 million loss on the assets held for sale
for the excess of the allocated net book value to the these assets,
compared to the total estimated net proceeds, after purchase
adjustments and closing costs, of $85 million. The associated asset
retirement obligation for these properties of $9.6 million has been
classified as a current liability.
6. Bank Debt
---------------------------------------------------------------------
June 30, December 31,
2009 2008
---------------------------------------------------------------------
($000s)
---------------------------------------------------------------------
Operating facility $ 3,696 $ 7,388
Revolving term facility 116,509 125,000
---------------------------------------------------------------------
Balance, end of period $ 120,205 $ 132,388
Pro-forma bank debt after Saskatchewan Divestiture as of June 30,
2009, was reduced by approximately $86 million of net proceeds, after
purchase adjustments. The bank facility outstanding at June 30, 2009
had a borrowing base of $134 million and matures on June 30, 2010.
Pursuant to True's existing credit facility, distributions to
unitholders (other than by way of the issuance of Trust units)
generally require the approval of True's lenders if the funds to pay
such distributions are received from True Energy Inc.
In conjunction with completion of the Saskatchewan Divestiture on
July 30, 2009, True has negotiated a new banking syndicate commitment
to replace the existing bank facility, subject to finalization and
execution of a mutually acceptable credit agreement, that will
provide True with a credit facility of $85 million. The facility will
consist of a $10 million demand operating facility provided by one
Canadian bank and a $75 million extendible revolving term credit
facility syndicated by one Canadian chartered bank and one Canadian
financial institution. The revolving period on the new revolving term
credit facility will end on June 30, 2010, unless extended for a
further 364 day period. Should the facilities not be renewed they
will convert to 366 day non-revolving term facilities on the renewal
date. The borrowing base will be subject to renewal on March 31,
2010.
7. CONVERTIBLE DEBENTURES
The following table shows the convertible debenture activities for
the six month period ended June 30, 2009 and the year ended December
31, 2008:
---------------------------------------------------------------------
Debt Equity
Number of Component Component
Debentures ($000s) ($000s)
---------------------------------------------------------------------
Balance, December 31, 2007 86,250 $ 79,407 $ 5,119
Accretion - 1,717 -
---------------------------------------------------------------------
Balance, December 31, 2008 86,250 $ 81,124 $ 5,119
---------------------------------------------------------------------
Accretion - 951 -
---------------------------------------------------------------------
Balance, June 30, 2009 86,250 $ 82,075 $ 5,119
---------------------------------------------------------------------
In November 2008, the Trust received Toronto Stock Exchange approval
for its normal course issuer bid program ("NCIB") to repurchase up to
10% of the issued and outstanding 7.50% convertible unsecured
subordinated debentures of the Trust from December 1, 2008 to
November 30, 2009. As of June 30, 2009 there have been no repurchases
of convertible debentures under the NCIB. Commencing April 1, 2009,
repurchase of convertible debentures requires the consent of the
lenders of the long-term debt.
8. ASSET RETIREMENT OBLIGATIONS
The Trust's asset retirement obligations result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Trust estimates the
total undiscounted amount of cash flows required to settle its asset
retirement obligations is approximately $75.6 million which will be
incurred between 2009 and 2053. Approximately $13.4 million of
undiscounted cash flows required for the settlement of asset
retirement obligations will be disposed of as part of the
Saskatchewan Divestiture. A credit-adjusted risk-free rate of 8
percent and an inflation rate of 2.4 percent were used to calculate
the fair value of the asset retirement obligation.
---------------------------------------------------------------------
June 30, December 31,
($000s) 2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 33,682 $ 28,373
Liabilities incurred on development activities 30 784
Changes in prior period estimates 995 8,302
Liabilities released on dispositions (1,259) (3,333)
Liabilities settled during the period (1,051) (2,603)
Accretion expense 1,322 2,159
---------------------------------------------------------------------
Sub-total 33,719 33,682
---------------------------------------------------------------------
Obligations related to petroleum and natural
gas assets held for sale (note 5) (9,578) -
---------------------------------------------------------------------
Balance, end of period $ 24,141 $ 33,682
---------------------------------------------------------------------
---------------------------------------------------------------------
9. EXCHANGEABLE SHARES OF SUBSIDIARY/NON-CONTROLLING INTEREST
---------------------------------------------------------------------
June 30, 2009 December 31, 2008
Number Amount Number Amount
($000s) ($000s)
---------------------------------------------------------------------
Balance, beginning
of period 294,026 $ 2,887 390,276 $ 3,922
Non-controlling
interest recovery - (435) - (83)
Exchanged for trust
units - - (96,250) (952)
---------------------------------------------------------------------
Balance, end of
period 294,026 $ 2,452 294,026 $ 2,887
---------------------------------------------------------------------
---------------------------------------------------------------------
The exchange ratio is calculated monthly based on the five day
weighted average trust unit trading price preceding the monthly
effective date. The exchangeable shares are not eligible for cash
distributions; however cash distributions will increase the exchange
ratio. As at June 30, 2009, the exchange ratio was 1.0627 (2008:
1.0218).
10. UNITHOLDERS' CAPITAL
a. Trust Units
---------------------------------------------------------------------
June 30, 2009 December 31, 2008
Number Amount Number Amount
($000s) ($000s)
---------------------------------------------------------------------
Balance, beginning
of period 78,496,581 $ 917,012 79,216,046 $ 925,573
Repurchased under
normal course
issuer bid - - (814,300) (9,513)
Exchangeable shares
converted - - 94,835 952
---------------------------------------------------------------------
Balance, end of
period 78,496,581 $ 917,012 78,496,581 $ 917,012
---------------------------------------------------------------------
In August 2008, the Trust announced approval of the renewal of its
normal course issuer bid ("NCIB") program to repurchase up to
7.8 million of its outstanding trust units during the period August
28, 2008 through August 27, 2009, subject to certain restrictions. As
of June 30, 2009, the Trust has purchased 615,100 trust units at a
weighted average price of $2.74 per trust unit under the NCIB renewed
on August 28, 2008. No repurchases have taken place in the six month
period ended June 30, 2009. Commencing April 1, 2009, repurchase of
trust units requires the consent of the lenders of the long-term
debt.
b. Trust Unit Incentive Plan
The following tables summarize information regarding trust unit
incentive rights for the six month period ended June 30, 2009:
Unit Rights Continuity
---------------------------------------------------------------------
Weighted Average
Exercise Price(a) Number
---------------------------------------------------------------------
Balance, December 31, 2008 $ 3.97 2,700,500
Granted $ 1.48 2,546,800
Forfeited $ 4.34 (1,012,668)
---------------------------------------------------------------------
Balance, June 30, 2009 $ 2.38 4,234,632
---------------------------------------------------------------------
(a) Exercise prices reflect grant prices less reduction in exercise
prices.
Unit Rights Outstanding, June 30, 2009
-------------------------------------------------------------------------
Outstanding Exercisable
Weighted
Average Weighted
Exercise Average Exercise
Exercise Price Remaining Price
Price At Net of Contrac- At Net of
Net of June 30, Price tual June 30, Price
Reductions 2009 Reductions Life 2009 Reductions
-------------------------------------------------------------------------
$ 0.65 1,327,881 $ 1.10 4.7 - -
- $ 1.50
$ 1.64 2,002,585 $ 2.05 4.3 181,986 $ 2.47
- $ 2.47
$ 2.58 227,000 $ 3.60 3.9 49,832 $ 3.66
- $ 4.29
$ 4.23 652,166 $ 5.03 2.9 424,484 $ 5.05
- $ 5.57
$16.95 25,000 $16.95 1.4 25,000 $16.95
- $16.95
-------------------------------------------------------------------------
-------------------------------------------------------------------------
$ 0.65 4,234,632 $ 2.38 4.2 681,302 $ 4.69
- $16.95
-------------------------------------------------------------------------
-------------------------------------------------------------------------
c. Employee Trust Unit Savings Plan
Effective October 1, 2006, the Trust introduced an employee trust
unit savings plan for the benefit of all employees. Under the savings
plan, employees may elect to contribute up to 10 percent of their
salary and contributions are used to fund the acquisition of trust
units. The Trust matches employee contributions at a rate of $1.00
for each $1.00 contributed. Trust units are purchased in the open
market by the plan administrator, an investment firm, on behalf of
the participants in the plan. For the six month period ended June 30,
2009, the Trust matched $0.1 million (2008 - $0.2 million) under the
plan. Effective for March 2009, the Trust suspended matching
contributions under the plan until further notice.
11. CONTRIBUTED SURPLUS
---------------------------------------------------------------------
June 30, December 31,
($000s) 2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 28,240 $ 19,454
Unit-based compensation expense 390 1,869
Incentive units voluntarily surrendered - 466
Adjustment of prior period unit-based
compensation expense for forfeitures of
unvested incentive units (687) (526)
Adjustment for repurchase of units under NCIB - 6,977
---------------------------------------------------------------------
Balance, end of period $ 27,943 $ 28,240
---------------------------------------------------------------------
---------------------------------------------------------------------
Unit-based Compensation Expense
During the six months ended June 30, 2009, the Trust granted
2,546,800 unit incentive rights to employees, directors and officers.
Of the 2,546,800 unit incentive rights granted during the period,
2,054,520 unit incentive rights have an exercise price that is higher
than the Trust's unit market price on the grant date. The unit
incentive rights for which the exercise price is higher than the
Trust's unit market price on the grant date have a weighted average
fair value of $0.25 per unit and an average exercise price of $1.69.
The remaining unit incentive rights have a weighted average fair
value of $0.39 per unit. During the six month period ended June 30,
2009, the Trust recorded unit-based compensation of $0.4 million, of
which $0.1 million was capitalized to property, plant and equipment.
The fair values of all incentive rights granted are estimated on the
date of grant using the Black-Scholes option-pricing model. The
weighted average fair market value of incentive rights granted during
the six month period ended June 30, 2009 and the assumptions used in
their determination are as noted below:
---------------------------------------------------------------------
2009
---------------------------------------------------------------------
Assumptions:
Risk free interest rate (%) 2
Expected life (years) 5
Expected volatility (%) 69-71
---------------------------------------------------------------------
Results:
Weighted average fair value of each incentive right
granted $ 0.27
---------------------------------------------------------------------
---------------------------------------------------------------------
12. SUPPLEMENTAL CASH FLOW INFORMATION
Cash Interest and Taxes Paid
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($000s) 2009 2008 2009 2008
---------------------------------------------------------------------
Cash paid:
Interest $ 4,280 $ 5,580 $ 5,174 $ 8,085
Taxes (net of
refunds) 1 $ 246 $ (273) $ 531
---------------------------------------------------------------------
Change in Non-cash Working Capital
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($000s) 2009 2008 2009 2008
---------------------------------------------------------------------
Changes in non-cash
working capital
items:
Accounts
receivable $ 2,787 $ 4,352 $ 5,332 $ (4,822)
Deposits and
prepaid expenses 1,722 1,446 1,624 1,065
Accounts payable
and accrued
liabilities (11,031) (9,935) (12,559) (11,862)
Distribution
payable to
unitholders - (1) (1,570) (3,169)
---------------------------------------------------------------------
$ (6,522) $ (4,138) $ (7,173) $ (18,788)
---------------------------------------------------------------------
Changes related to:
Operating
activities $ (3,985) $ (6,289) $ (425) $ (12,090)
Financing
activities 709 50 (809) (3,110)
Investing
activities (3,246) 2,101 (5,939) (3,588)
---------------------------------------------------------------------
---------------------------------------------------------------------
$ (6,522) $ (4,138) $ (7,173) $ (18,788)
---------------------------------------------------------------------
---------------------------------------------------------------------
13. INCOME TAXES
The Trust is a mutual fund trust as defined under the Income Tax Act
(Canada). All taxable income earned by the Trust has been allocated
to unitholders and such allocations are deducted for income tax
purposes.
In June 2007, the government legislation implementing the new tax
(the "SIFT tax") on publicly traded income trust and limited
partnerships (Bill C-52) received third reading in the House of
Commons and Royal Assent. For existing income trusts and limited
partnerships, the SIFT tax will be effective in 2011 unless certain
rules related to "undue expansion" are not adhered to. As such, the
Trust would not be subject to the new measures until the 2011
taxation year provided the Trust continues to meet certain
requirements.
As at June 30, 2009, the total "temporary difference" (tax basis
exceeds accounting basis) in the Trust is $8.7 million. As at June
30, 2009, the Trust's subsidiaries have a tax basis of approximately
$459 million that is available to shelter future taxable income.
Included in this tax basis are estimated non-capital loss carry
forwards of approximately $30 million that expire in years through
2027. In addition, the Trust itself has approximately $17 million of
tax basis.
14. PER TRUST UNIT AMOUNTS
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
2009 2008 2009 2008
---------------------------------------------------------------------
Basic trust units
outstanding 78,496,581 79,095,460 78,496,581 79,095,460
Dilutive effect of:
Trust unit
incentive rights
outstanding 4,234,632 5,006,079 4,234,632 5,006,079
Units issuable for
exchangeable
shares 312,467 347,254 312,467 347,254
Units issuable for
convertible
debentures 5,390,625 5,390,625 5,390,625 5,390,625
---------------------------------------------------------------------
Diluted trust units
outstanding 88,434,305 89,839,418 88,434,305 89,839,418
---------------------------------------------------------------------
Weighted average
trust units
outstanding 78,496,581 79,203,976 78,496,581 79,213,532
Dilutive effect of
exchangeable shares,
trust unit
incentive plan and
convertible
debentures(1) - - - -
---------------------------------------------------------------------
Diluted weighted
average trust units
outstanding 78,496,581 79,203,976 78,496,581 79,213,532
---------------------------------------------------------------------
(1) A total of 4,234,632 (2008: 5,006,079) trust incentive units,
312,467 (2008: 347,254) exchangeable shares and 5,390,625 (2008:
5,390,625) trust units issuable pursuant to the conversion of
convertible debentures were excluded from the calculation for the
three and six month period ended June 30, 2009 as they were not
dilutive.
15. FINANCIAL RISK MANAGEMENT
a. Credit risk
As at June 30, 2009, accounts receivable was comprised of the
following:
---------------------------------------------------------------------
($000s)
---------------------------------------------------------------------
Trade accounts receivable 5,014
Accrued and other accounts receivable 17,773
---------------------------------------------------------------------
22,787
---------------------------------------------------------------------
The carrying amount of accounts receivable and derivative assets
represents the maximum credit exposure. The Trust has an allowance
for doubtful accounts as at June 30, 2009 of $0.6 million.
As at June 30, 2009 the Trust estimates its trade accounts
receivables to be aged as follows:
---------------------------------------------------------------------
Aging ($000s)
---------------------------------------------------------------------
Not past due (less than 90 days) 1,896
Past due (90 or more days) 3,118
---------------------------------------------------------------------
Total 5,014
---------------------------------------------------------------------
---------------------------------------------------------------------
After considering June 30, 2009 trade accounts payable from the same
companies and cash receipts received subsequent to June 30, 2009, the
Trust's trade receivables aged 90 or more days of approximately
$3.1 million are reduced to a net balance of approximately
$1.7 million.
Included in accrued and other accounts receivable are approximately
$4.7 million of amounts aged 90 or more days.
b. Liquidity risk
The following are the contractual maturities of financial liabilities
as at June 30, 2009:
---------------------------------------------------------------------
Financial (less than)
liability ($000s) 1 Year 1-2 Years 2-5 Years Thereafter
---------------------------------------------------------------------
Accounts payable and
accrued liabilities 21,569 - - -
Distribution payable
to unitholders - - - -
Bank debt -
principal(1) 120,205 - - -
Convertible
debentures -
principal - - 86,250 -
---------------------------------------------------------------------
Total 141,774 - 86,250 -
---------------------------------------------------------------------
(1) The current facility is due on June 30, 2010. Refer to note 6 for
further details.
The Trust's convertible debentures outstanding at June 30, 2009 bear
interest at a coupon rate of 7.5%, which currently requires total
annual interest payments of $6.5 million. Interest due on the bank
credit facility is calculated based upon floating rates.
c. Commodity price risk
Commodity price risk is the risk that the fair value or future cash
flows will fluctuate as a result of changes in commodity prices.
Commodity prices for petroleum and natural gas are impacted by not
only the relationship between the Canadian and United States dollar,
as outlined above, but also world economic events that dictate the
levels of supply and demand.
The Trust utilizes both financial derivatives and physical delivery
sales contracts to manage commodity price risks. All such
transactions are conducted in accordance with the risk management
policy that has been approved by the Board of Directors.
The Trust's formal risk management policy permits management to use
specified price risk management strategies including fixed price
contracts, costless collars and the purchase of floor price options,
other derivative financial instruments, and physical delivery sales
contracts 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 funds flows from operations, as well as, to ensure True
realizes positive economic returns from its capital developments and
acquisition activities.
As at June 30, 2009, the Trust had entered into commodity price risk
management arrangements as follows:
-------------------------------------------------------------------------
Price Price
Type Period Volume Floor Ceiling Index
-------------------------------------------------------------------------
Natural Gas March 1, 2009 to 4,500 GJ/day $ 5.00 CDN $ 5.00 CDN AECO
fixed Sept. 30, 2009
Natural Gas March 1, 2009 to 5,000 GJ/day $ 5.90 CDN $ 5.90 CDN AECO
fixed Dec. 31, 2009
Natural Gas July 1, 2009 to 5,000 GJ/day $ 5.41 CDN $ 5.41 CDN AECO
fixed Sept. 30, 2009
Natural Gas July 1, 2009 to 5,000 GJ/day $ 7.49 CDN $ 7.49 CDN AECO
fixed Sept. 30, 2009
Natural Gas Oct. 1, 2009 to 5,000 GJ/day $ 8.09 CDN $ 8.09 CDN AECO
fixed Dec. 31, 2009
Natural Gas Oct. 1, 2009 to 5,000 GJ/day $ 6.26 CDN $ 6.26 CDN AECO
fixed Dec. 31, 2009
Natural Gas Jan. 1, 2010 to 5,000 GJ/day $ 7.16 CDN $ 7.16 CDN AECO
fixed March 31, 2010
Natural Gas Jan. 1, 2010 to 5,000 GJ/day $ 8.00 CDN $ 8.00 CDN AECO
fixed March 31, 2010
Natural Gas Jan. 1, 2010 to 5,000 GJ/day - $ 8.05 CDN AECO
call option Dec. 31, 2010
Natural Gas April 1, 2010 to 5,000 GJ/day $ 6.59 CDN $ 6.59 CDN AECO
fixed June 30, 2010
Oil collar March 1, 2009 to 500 bbl/d $52.30 CDN $80.70 CDN WTI
Dec. 31, 2009
-------------------------------------------------------------------------
For the three and six months ended June 30, 2009 and 2008, the gain
(loss) on commodity contracts was comprised of the following:
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
($000s) 2009 2008 2009 2008
---------------------------------------------------------------------
Gain (loss) on
commodity
contracts
Realized(1) $ 5,789 $ (12,619) $ 8,420 $ (16,761)
Unrealized(2) (2,704) (25,550) 5,140 (43,237)
---------------------------------------------------------------------
$ 3,085 $ (38,169) $ 13,560 $ (59,998)
---------------------------------------------------------------------
(1) Realized gains and losses on commodity contracts represent actual
cash settlements and other amounts paid under these contracts.
(2) Unrealized gains and losses on commodity contracts represent non-
cash adjustments for changes in the fair value of these contracts
during the period.
The Trust has entered into a natural gas physical delivery sales
contract to sell 5,275 GJ/day at a fixed price of $7.29/GJ and
$7.90/GJ for the third and fourth quarter of 2009, respectively.
d. Interest rate risk
The Trust had no interest rate swap or financial contracts in place
during the three and six months period ended June 30, 2009.
e. Capital management
The Trust's policy is to maintain a strong capital base so as to
maintain investor, creditor and market confidence and to sustain the
future development of the business. The Trust manages its capital
structure and makes adjustments to it in the light of changes in
economic conditions and the risk characteristics of the underlying
petroleum and natural gas assets. The Trust considers its capital
structure to include unitholders' equity, bank debt, convertible
debentures and working capital. In order to maintain or adjust the
capital structure, the Trust may from time to time issue trust units,
adjust its capital spending, and/or dispose of certain assets to
manage current and projected debt levels.
The Trust monitors capital based on the ratio of total net debt to
annualized funds flow (the "ratio"). This ratio is calculated as
total net debt, defined as outstanding bank debt, plus the liability
component of convertible debentures, plus or minus working capital
(excluding commodity contract assets and liabilities, current portion
of long-term debt and future income tax assets or liabilities),
divided by funds flow from operations (cash flow from operating
activities before changes in non-cash working capital and deductions
for asset retirement costs) for the most recent calendar quarter,
annualized (multiplied by four). The total net debt to annualized
funds flow ratio may increase at certain times as a result of
acquisitions, fluctuations in commodity prices, timing of capital
expenditures and other factors. In order to facilitate the management
of this ratio, the Trust prepares annual capital expenditure budgets
and sets unitholder distributions on a monthly basis. Capital
expenditure budgets and levels of monthly unitholder distributions
are reviewed and updated as necessary depending on varying factors
including current and forecast prices, successful capital deployment
and general industry conditions. The annual and updated budgets and
monthly unitholder distributions are approved by the Board of
Directors.
Given the continuing uncertain economic conditions, the Trust has
suspended unit distributions in order to maintain financial
flexibility. The Trust plans to continue to monitor forecasted debt
levels to manage its operations within forecasted funds flow. The
Trust expects the total net debt to annualized funds flow ratio to
reflect the economic burdens experienced as a result of the recent
downturn in the global economic environment. The Trust will continue
to monitor developments within the global economic environment to
consider the impacts on the current or future lending arrangements.
The Trust's long-term strategy, under a more stable economic
environment, is to target a total net debt to annualized funds flow
ratio of 2.0 times. As at June 30, 2009, the Trust's ratio of total
net debt to annualized funds flow based on second quarter results was
4.6 times. The total net debt to annualized funds flow ratio as at
June 30, 2009 decreased from that at December 31, 2008 of 9.2 times
due to higher funds flow from operations in the second quarter in
addition to lower total net debt. The Trust expects this ratio to
decrease in the third quarter of 2009 as total net debt levels are
reduced by the estimated net proceeds of $85 million from the closing
of the Saskatchewan Divestiture on July 30, 2009; True continues to
take a balanced approach to the priority use of funds flows. The
Debentures have a maturity date of June 30, 2011. Upon maturity, the
Trust may settle the principal in cash or issuance of additional
Trust units. Excluding Debentures, net debt to annualized funds flow
based on second quarter results was 2.7 times.
The calculation of total net debt and total net debt to cash flow is
as follows:
---------------------------------------------------------------------
Three months ended Six months ended
($000s, except June 30, June 30,
where noted) 2009 2008 2009 2008
---------------------------------------------------------------------
Long-term debt 120,205 125,458 120,205 125,458
Convertible
debentures (liability
component) 82,075 80,253 82,075 80,253
Working capital
excess (5,563) (16,357) (5,563) (16,357)
---------------------------------------------------------------------
Total net debt(1) at
year end 196,717 189,354 196,717 189,354
Debt to funds flow
from operations ratio
(annualized)(2)
Funds flow from
operations
(annualized) 43,060 105,216 34,508 105,216
Total net debt(1)
to periods funds
flow from
operations ratio
(annualized) 4.6x 1.8x 5.7x 1.8x
Net debt(1)
excluding
convertible
debentures) at
quarter end 114,642 109,101 114,642 109,101
Net debt to
periods funds flow
from operations
ratio (annualized) 2.7x 1.1x 3.3x 1.1x
Debt to funds flow
from operations
ratio (trailing)(3)
Total net debt to
periods funds flow
from operations ratio
(trailing) 3.2x 2.2x 3.2x 2.2x
Net debt to periods
funds flow from
operations ratio
(trailing) 1.8x 2.0x 1.8x 2.0x
---------------------------------------------------------------------
(1) Net debt includes the net working capital deficiency (excess)
before short-term commodity contract assets and liabilities,
current portion of long-term debt and short-term future income
tax assets and liabilities. 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 (annualized) is
calculated based upon second quarter funds flow from operations
annualized.
(3) Trailing periods funds flow from operations is based on the
trailing twelve-months period ended June 30, 2009 and 2008.
The Trust's credit facility is based on petroleum and natural gas
reserves (see note 6). The credit facility outlines limitations on
percentages of forecasted production, from external reserve engineer
data, which may be hedged through financial commodity risk management
contracts and limitations on property dispositions without prior
consent of the lenders. The Trust also has outstanding normal course
issuer bids for its convertible debentures and trust units, as
detailed in note 7 and 10, respectively.
f. Fair value of financial instruments
The Trust's financial instruments as at June 30, 2009 include
accounts receivable, deposits, marketable securities, commodity
contract liability, accounts payable and accrued liabilities,
distributions payable, long-term debt and convertible debentures. The
fair value of accounts receivable, accounts payable and accrued
liabilities and distributions payable approximate their carrying
amounts due to their short-terms to maturity.
The fair value of commodity contracts is determined by discounting
the difference between the contracted price and published forward
price curves as at the balance sheet date, using the remaining
contracted petroleum and natural gas volumes.
Long-term bank debt bears interest at a floating market rate and
accordingly the fair market value approximates the carrying value.
The fair value of the convertible debentures of $65.1 million is
based on exchange traded values.True Energy Trust is a Calgary-based oil and natural gas trust. True is
an open-ended, incorporated investment trust governed by the laws of the
Province of Alberta. The purpose of the Trust is to indirectly explore for,
develop and hold interests in petroleum and natural gas properties, through
investments in securities of subsidiaries and net profits interests. The trust
structure allows individual unitholders to participate in the cash flow of the
business. Cash flow is realized from the Trust's subsidiaries' ownership of
natural gas and petroleum properties and related facilities. Trust units and
convertible debentures of True trade on the Toronto Stock Exchange ("TSX")
under the symbols TUI.UN and TUI.DB, respectively.
